The POWER Podcast: Recent Episodes
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The POWER Podcast provides listeners with insight into the latest news and technology that is poised to affect the power industry. POWER’s Executive Editor Aaron Larson conducts interviews with leading industry experts and gets updates from insiders at power-related conferences and events held around the world.
; and the structural headwinds—permitting delays, an aging workforce, supply chain strain, and cybersecurity—that determine what utilities can build and how fast.Corwin closes with what he most wants policymakers to understand about community-owned utilities, and the value of 2,000 diverse communities speaking with one voice on affordability and reliability.Listen to the full conversation to hear how public power is navigating one of the most dynamic periods the industry has faced in years.
A's St. Louis shop: the first 7FA.03 rotor purchased specifically for the seed rotor program to complete the full production cycle, with newly manufactured wheels stacking perfectly alongside original serviceable components. And we discuss the 2026 delivery of a life-extended 7FA.03 rotor to a leading U.S. power producer—a vote of confidence from a famously risk-averse industry.Whether you're a utility planner staring down rotor end-of-life on your 7FA fleet, an asset manager weighing OEM dependence against supply chain risk, or an industry watcher tracking how independents are reshaping heavy-duty gas turbine services, this episode lays out where the bottlenecks are, what's been done about them, and why the window to act is narrowing fast.
• The mechanical reality of an uprate: increased thermal megawatt ratings, more highly enriched fuel, and the secondary-side components — feedwater heaters, moisture separator reheaters, large pumps and motors — that have to be replaced to accommodate the change.• Duke Energy's decision-making framework for new nuclear, tentatively reflected in the integrated resource plan in 2037, and why economics, not technology choice, is the gating factor.• Career advice for engineers considering nuclear, from someone who has held more than 10 different roles across his own engineering career.Capps grew up about 10 miles from Oconee Nuclear Station, earned a mechanical engineering degree at Clemson, and joined Duke Energy after graduation. Twenty years at Oconee, a decade at McGuire, and most recently roles in Duke Energy's corporate organization have shaped his view of where the fleet — and the industry — go from here.
Nuclear energy is back — and this time, the momentum may be here to stay. In this episode of The POWER Podcast, Executive Editor Aaron Larson sits down with Dagmar Thien, who manages conventional island equipment for nuclear power plants at Siemens Energy, to explore what's driving the industry's renewed optimism and how the company is positioning itself at the center of the action.Thien, a physicist with two decades at Siemens Energy, breaks down the forces fueling the nuclear resurgence: surging global electricity demand, the need for reliable baseload power to back up intermittent renewables, and nuclear's strong climate credentials as a low-lifecycle-emission energy source. The explosive growth of data centers, which require uninterrupted power around the clock, has added particular urgency.The conversation spans the full spectrum of reactor technology — from gigawatt-scale plants that benefit from economies of scale, to small modular reactors (SMRs) promising faster, cheaper deployment through factory standardization, to Generation IV designs like high-temperature gas-cooled and molten salt reactors that could unlock industrial heat applications beyond electricity.Thien explains how Siemens Energy's broad turbine portfolio allows it to support virtually any reactor type. She highlights the value of whole-system optimization — collaborating with reactor developers to find the best overall plant performance rather than optimizing each side independently.The episode also covers the critical but often overlooked work of lifetime extension and modernization. With some U.S. plants pursuing 80-year operating licenses, upgrading turbines, generators, and control systems is essential. Thien discusses the Palisades Nuclear Generating Station — a landmark example of a decommissioned plant being brought back online — and the complex process of managing obsolescence in safety-qualified instrumentation and control systems used in roughly 23% of the world's reactors.Regulatory challenges, international harmonization efforts between the U.S., UK, and Canada, and the growing role of nuclear heat for industrial decarbonization round out a wide-ranging discussion on where the industry is headed next.
market, and how hybrid deals combining firm capacity with clean energy attributes are changing PPA structures• The rise of flexibility as a corporate procurement category, including demand-side management, on-site storage, and virtual power plants• How rising tariffs and supply chain inflation are squeezing solar, wind, and gas project economics• Powell's top policy ask: fundamental, legislatively codified reform of federal permitting and transmission planningA candid look at where the corporate clean energy market stands today—and what it will take to keep pace with the AI era.
After decades of flat electricity demand, the U.S. power sector is suddenly racing to keep up—and rural electric cooperatives are on the front lines. In this episode of The POWER Podcast, Jim Matheson, CEO of the National Rural Electric Cooperative Association (NRECA), joins executive editor Aaron Larson to discuss how roughly 900 co-ops serving 42 million people across 48 states are navigating surging data center load, supply chain pressures, and a shifting regulatory landscape.Matheson explains what makes the co-op model distinctive—not-for-profit, consumer-owned, and locally governed—and why affordability isn't a talking point but an operational imperative for utilities that serve 92% of America's persistent poverty counties. He then digs into the generation debate, drawing a key distinction between always-available sources like coal, gas, and nuclear, and intermittent resources like wind and solar, and makes the case for local flexibility over federal one-size-fits-all mandates.Other topics covered in the conversation include:• Why Matheson believes viable power plants shouldn't be retired before replacement capacity is in place.• The long-term outlook for nuclear, the status of small modular reactors, and a notable Michigan plant restart driven by two co-ops.• Where energy storage fits today—and what a true long-duration breakthrough would unlock.• How global supply chain pressures and tariffs are driving up costs on everything from turbines to meters.• NRECA's 2026 policy priorities, including EPA rule rollbacks, permitting reform, raising the USDA Rural Utilities Service lending cap, and FEMA reform.• The contractual and operational complexity of onboarding hyperscale data center loads, and why existing consumers shouldn't subsidize them.• How roughly 200 co-ops are now bringing broadband to underserved rural areas—a modern echo of 1930s rural electrification.Whether you're tracking the AI-driven load boom, policy developments in Washington, or the unique role cooperatives play in the U.S. electric sector, this conversation offers a clear-eyed view from someone who represents member-owned utilities covering 54% of the nation's land mass.
for a company of its size and age. On this episode of The POWER Podcast, DeLine sits down with executive editor Aaron Larson to explain how Linea got there and where it's headed next.At the core of Linea's approach is a commitment to better information, earlier. Most developers don't get detailed site data, such as wetland boundaries, topography, and transmission characteristics, until after leases are signed and field teams are deployed. Linea has built proprietary simulations to surface that information before a single landowner conversation takes place, giving its team a sharper picture of risk before committing capital.That discipline extends to how the company handles offtake. Unlike most developers, Linea is comfortable advancing projects without a power purchase agreement (PPA) locked in. DeLine explains why signing a PPA too early can actually create risk, particularly in a market where tariff volatility and shifting capital costs have burned developers who fixed the revenue side before they had certainty on expenses.The conversation also covers Linea's growing role in the data center space. The company is doing bespoke energy development for data center operators and, in some cases, developing the data center itself. But DeLine is candid about the engineering challenges: artificial intelligence (AI) inference workloads cause demand to swing on a microsecond basis, which is fundamentally different from what the grid was built to handle. Linea has developed battery-and-inverter solutions to smooth those rapid fluctuations, guided by a simple principle: the lights have to stay on.DeLine shares her perspective on battery storage as a grid resource, the maturing but still incomplete renewable energy capital markets, the interconnection queue bottleneck, and what it means to commit to communities for a 40-year ownership horizon. She also discusses why Linea is evaluating small modular reactor technology—not because the economics work today, but because projects started now won't come online until the 2030s, and she wants to be ready for where the market is heading.Whether you're in development, finance, policy, or just following the energy transition, this is a conversation worth hearing.
After 22 years at IBM, where he rose to senior vice president and director of IBM Research, Dr. Dario Gil now leads one of the most ambitious science and technology initiatives in a generation. As the Department of Energy's (DOE's) Under Secretary for Science and director of the Genesis Mission, Gil is orchestrating a convergence of high-performance computing, artificial intelligence (AI), and quantum computing aimed at transforming how America does science and engineering.The Genesis Mission rests on a straightforward premise: a computing revolution is underway, and the U.S. should harness it to double the productivity of its trillion-dollar-a-year research and development engine within a decade. The initiative is built on three pillars: a platform for accelerating discovery anchored in high-performance computing, AI supercomputing, and quantum computing; a portfolio of national challenges in energy, physical sciences, and national security; and a university engagement effort to rethink how future scientists and engineers are educated in the age of AI.Gil offered fusion energy as a prime example of how AI can compress timelines. By training neural networks on validated simulation data, researchers can build surrogate models that run thousands to tens of thousands of times faster, allowing engineers to iterate on reactor designs in hours rather than months. AI is also being applied to real-time plasma control through collaborative work involving Google DeepMind and Commonwealth Fusion Systems.On the grid, Gil shared two striking examples. The DOE's Office of Electricity is developing AI agents to help developers fix deficient interconnection applications—which account for 80% to 90% of submissions—potentially accelerating studies by up to a year. Meanwhile, Brookhaven National Laboratory's Grid FM emulator can speed power flow calculations by 100x, compressing what would be 20 years of conventional analysis of the Texas transmission grid into roughly two months.Gil was candid about the tension between AI as an energy solution and AI as a source of surging electricity demand, noting that planned data centers now reach gigawatt scale. The path forward, he said, involves optimizing the existing grid, accelerating nuclear energy, investing in fusion, and driving major efficiency gains in AI hardware.New supercomputing infrastructure is already being built through the Genesis Consortium, a partnership of 27 industrial players. Argonne and Oak Ridge National Laboratories are each standing up large GPU clusters this year, with a 100,000-GPU system planned for Argonne in 2027—the largest science-oriented cluster in the world.Asked what success looks like, Gil pointed to the AlphaFold story: 50 years of work produced 200,000 protein structures, then AI predicted 200 million in two years. Success, he said, will mean 50 to 100 comparable breakthroughs across all domains of science within three to five years.
equipment—purchasing materials early to lock in expiring tax credit incentives. Smaller developers are being forced to sell projects or abandon them, driving capital toward established brands.Nagarajan also suggested natural gas is no longer a bridge fuel. Given demand for gas turbines from hyperscalers and the signals from manufacturers like GE Vernova and Siemens Energy, gas is firmly embedded in the energy mix. The consequence, he argued, is that emissions will rise, driving significant demand for high-integrity carbon credits—a space he is personally bullish on.His overarching message is one of disciplined optimism. The energy sector is experiencing a rare convergence of rising demand, constrained supply, and deep pools of capital. But the winners will be those who resist underwriting to today's enthusiasm and instead back businesses that can thrive regardless of which way the policy winds blow.
The power industry's workforce crisis is well documented — an aging labor force, too few new recruits, and a surge of infrastructure investment that's only widening the gap. But on this episode of The POWER Podcast, two guests offer a practical blueprint for closing it.Derek O'Connor, Workforce Development Manager in the Office for Research and Innovation at Stony Brook University, and Rosalie Drago, Vice President for External Affairs and Strategic Engagement at Haugland Group, discuss the suite of workforce programs they've built together — from a paid summer experience for high school students called Taste of the Trades, to drone piloting certification, HVDC power systems training, an energy cybersecurity program, and EmpowerHER, a program designed to bring young women into the construction trades.Their model is built on a simple but powerful insight: many high school students need to earn income over the summer, which steers them toward retail and food-service jobs instead of career-building experiences. By braiding together government youth employment funding, industry sponsorship, and university research expertise, the Stony Brook–Haugland partnership pays students to explore energy and infrastructure careers — and then offers them a clear pathway from that first exposure all the way through college and into the workforce.O'Connor and Drago share real student success stories, explain how they've adapted their curriculum to a shifting energy landscape, and make the case that every community in the country already has the building blocks to replicate what they've done. They also discuss why investing in teacher training and community education delivers returns that go well beyond filling open positions.
A outlook, and public-private partnerships• New directions and critical changes in policy, impacting every energy industry.Be a part of the conversations shaping the future of power markets.Learn more and register at: https://bit.ly/POWERPOD. Use the code POWERPOD at checkout to get a 10% discount on registration.
A’s Gas Turbine Program Manager, experienced the original boom firsthand as a GE field engineer specializing in 7F and 9F units from 1996 to 2001. He sees important differences between then and now.“There seems to be a lot more concrete reasons and a much stronger foundation for this current bubble than the previous one that took place two and a half decades ago,” Fernandes said. “There are a lot of things that are all stacking up at the same time that put more of an emphasis on getting out in front of extending the life of your current assets now, probably more than ever.”Supply chains have become particularly challenging. The specialized superalloy forgings required for turbine wheels are produced by a limited number of facilities worldwide, and those forging houses are simultaneously serving aerospace, military, and new power generation equipment markets.“You’re going to be competing with those new unit sales across various industries in an attempt to get in line with what is perceived from some angles as higher priorities,” Fernandes explained. “That further complicates the scenario that the customer base is facing when they’re trying to extend the rotor life of their existing assets.”
Rayburn Electric Cooperative faced three years of power costs in five days during the 2021 storm. The experience transformed the organization’s approach to risk, generation assets, and long-term planning.When Winter Storm Uri swept across Texas in February 2021, Rayburn Electric Cooperative found itself staring down a crisis that would reshape the organization’s entire operational philosophy. The generation and transmission cooperative, which serves approximately 625,000 Texans across 16 counties northeast of Dallas, incurred three years’ worth of power costs in just five days.“Bankruptcy was certainly one of the options on the table,” David Naylor, president and CEO of Rayburn Electric Cooperative, said as a guest on The POWER Podcast. “We were thankful we didn’t have to go that route. We were able to come up with a solution where we paid everything we owed—and then we took a hard look in the mirror and asked ourselves what we needed to do differently.”That self-evaluation led to strategic decisions that fundamentally shifted Rayburn’s power supply operations, transforming the cooperative from an organization with minimal owned generation resources into one that now owns and operates a major power plant—with another under construction.From Crisis to AcquisitionWithin two years of Uri, Rayburn acquired the Panda Sherman Power Plant, a 758-MW natural gas–fired combined cycle facility located just outside the cooperative’s service territory. The acquisition doubled Rayburn’s balance sheet, but Naylor said the plant checked critical boxes that emerged from the cooperative’s post-Uri analysis.“When we looked at who benefited from Uri—or at least came out of it in a solid situation—it was the people who owned generation assets, and whose units ran,” Naylor explained. “The Panda Sherman plant performed great during Winter Storm Uri. It had room for additional capacity if we wanted to expand in the future. And for someone that was staring bankruptcy in the face a couple years earlier, winning that auction over several private equity companies was a tremendous success.”Building for GrowthOne concern Rayburn had when acquiring the Panda Sherman plant—now called Rayburn Energy Station (RES)—was its size. Leadership initially projected the cooperative wouldn’t grow into the plant’s capacity until 2030 or later. That timeline proved wildly optimistic.“We’re projecting 25% growth over the next 10 years, and that’s not counting any data centers or large loads—just normal organic growth,” Naylor said. “We grew into Rayburn Energy Station a lot faster than we anticipated.”That rapid growth prompted Rayburn to begin construction on a second gas plant at the same site. The cooperative secured turbines and transformers under contract in late 2024, with a commercial operation date targeted for June 2028. According to Naylor, the timing proved fortuitous: suppliers indicated that waiting just a couple more months would have resulted in significantly higher costs and delivery dates pushed out by three to four years.The project is supported in part by the Texas Energy Fund, a $10 billion pool of low-cost loans created by the Texas Legislature after Uri to incentivize new dispatchable generation. Of more than 125 initial applicants, only 17 were selected to advance—and Rayburn is the only cooperative among them.
E) and Dominion Energy, mid-size utilities like Entergy, and cooperatives such as Umatilla Electric Cooperative in the Pacific Northwest.“The simple answer is that Amazon data centers are not being subsidized by other utility customers,” Ulrich said. The study projects that Amazon’s data centers will generate $33,500/MW of surplus value in 2025, increasing to $60,650/MW by 2030.For a typical 100-MW Amazon data center, that translates to $3.4 million in surplus revenues in 2025 and approximately $6.1 million by 2030. These surplus funds—revenues above the utility’s regulated rate of return—can be used by utilities to modernize grid infrastructure, improving reliability for all customers.Grid Investment Benefits All CustomersThe study found that Amazon data centers are driving investments in grid infrastructure that support not just their own operations but also local residential and commercial growth. Ulrich pointed to Entergy Mississippi as a prime example, where the utility is using investments from Amazon and other large customers to fund a $300 million “Superpower Mississippi” grid reliability campaign—at no cost to residential customers—targeting a 50% reduction in outages within five years.Innovative Rate Structures Prevent Cost-ShiftingWhile the E3 study validates that existing rate policies have been effective in preventing cross-subsidization, Ulrich emphasized that AWS continues to work with utilities on innovative approaches to ensure large industrial customers pay their fair share.She highlighted a Northern Indiana Public Service Co. (NIPSCO) project as a “groundbreaking model.” Under this first-of-its-kind agreement, Amazon is investing in 3 GW of electrical capacity, with 2.4 GW dedicated to data center operations and 600 MW reserved specifically to support grid reliability for all NIPSCO customers.The structure creates a separate generation company (GenCo) that operates under a “commercial contract term,” Ulrich explained. By operating as a separate entity, GenCo isolates the cost of new growth to data centers. “The data center companies that drive new demand for electricity will fund the generation and transmission infrastructure they require, ensuring that regular customers don’t shoulder those costs, even if the customer leaves before contract completion,” NIPSCO said in a Nov. 24 press release.“NIPSCO’s existing customers will have no financial responsibility for powering Amazon data centers,” Ulrich said. NIPSCO said, “This structure is expected to provide value to customers by generating approximately $1 billion in cost savings that will be returned to current NIPSCO customers as credits on monthly electric bills over the project’s 15-year duration.”
As the global demand for clean energy intensifies, nuclear power is enjoying a resurgence not seen in decades. However, this renewed interest has exposed a critical vulnerability in the U.S. energy sector: a massive disconnect between uranium consumption and domestic production. As a guest on The POWER Podcast, Thomas Lamb, president and CEO of Myriad Uranium, discussed some of the complexities of the nuclear fuel cycle and how junior exploration companies are racing to secure America’s energy future.The Great American Supply DeficitTo understand the urgency of the current uranium market, one must first grasp the sheer scale of consumption. A single large-scale nuclear reactor consumes approximately 400,000 to 500,000 pounds of uranium oxide concentrate (U3O8) annually, depending on design, capacity, and operating efficiency. The U.S. operates 94 commercial reactors today, resulting in a national consumption of roughly 37 million to 47 million pounds of U3O8 per year.The domestic production figures, however, paint a starkly contrasting picture. “The United States consumes, for very round numbers, 50 million pounds of uranium per year, and produces a million pounds of uranium per year,” Lamb explained. To be more specific, the U.S. Energy Information Administration reported that domestic production of U3O8 was 677,000 pounds in 2024, and it’s been much lower than that in the not-too-distant past.This imbalance creates a precarious reliance on foreign imports. Lamb noted that Kazakhstan alone produces more than 40% of the world’s uranium. More concerning for U.S. national security is the country’s reliance on Russia, where a surprisingly high percentage of U.S. reactor fuel bundles are sourced.“You have a worldwide supply deficit, and then you have an enormous domestic production deficit in the United States relative to consumption. That makes the U.S. vulnerable,” Lamb said. “What if Kazakhstan, China, [and] Russia kind of work together? What if they cut off the United States? What if some other things happen? The U.S. could be short of uranium.”Revitalizing History: The Copper Mountain ProjectMyriad Uranium is positioning itself to fill this gap by revitalizing past assets rather than starting from scratch. The company’s flagship asset, the Copper Mountain Uranium Project in Wyoming, was a focal point of Union Pacific’s energy subsidiary in the 1970s.Union Pacific invested approximately CA$117 million (in 2024 dollars, US$84.7 million) into the site, planning a large-scale mine to fuel reactors in Southern California that were ultimately never built due to the post-1979 nuclear freeze. Because the project was abandoned due to external market forces rather than a lack of resources, it represents a “brownfield” opportunity.“In our case, we already know it’s there because a lot of the work was done,” Lamb said. “Now, we just have to … bring the information current,” he added.
The power industry is experiencing unprecedented demand growth, driven largely by data centers and artificial intelligence (AI) applications. This surge is creating both opportunities and challenges for utilities, equipment manufacturers, and the broader power generation ecosystem.As a guest on The POWER Podcast, Seth Harris, growth director for Emerson’s Power business in North America, discussed how the company is helping the industry navigate this transformative period. With 20 years at Emerson across various roles, Harris brings a comprehensive perspective on the evolving needs of power generation facilities.The Data Center EffectThe conversation around power generation has fundamentally shifted. Data centers are forcing utilities to rethink everything. “I’m focused on the power markets, but I can’t tell you the last time I was able to have a conversation about power without somehow referencing the data center aspect of it,” Harris said.This demand is affecting multiple stakeholders simultaneously. Manufacturers of turbines, heat recovery steam generators, control systems, valves, and instruments are all facing unprecedented orders. The challenge extends beyond simply meeting demand. Companies must rapidly scale up manufacturing capabilities and engineering resources that have been stagnant for years.Extending Plant LifespansAmong the things that must be rethought are decisions on existing plant operations. In some cases, power plants that were previously scheduled for retirement are now being extended. “The ability to deliver power as quickly as possible is certainly top of mind as this kind of race to deliver on the technology promises coming from AI and the various use cases for data centers has really put those existing assets in a place where they have to focus on driving the most efficiency and reliability they possibly can,” said Harris.However, many owners haven’t been investing in these plants beyond the necessities, which means upgrades are often needed to keep the plants operating efficiently. “The technology has come a long way since those facilities were originally built,” Harris explained. Furthermore, operational expectations are changing. Rather than operating as baseload units, these legacy facilities may now only be called on to provide peaking or backup power, which means control systems may need upgrades to accommodate for that as well. Harris said retrofitting existing plants “has been a bit of a boom from an Emerson standpoint.”
Energy security represents one of Taiwan’s most pressing challenges. With virtually no domestic fossil fuel resources and limited renewable energy potential relative to its needs, the island imports approximately 98% of its energy. The semiconductor fabrication plants that drive the economy are particularly energy-intensive, requiring uninterrupted power supplies to maintain their precision manufacturing processes. Any disruption in electricity can halt production lines worth billions of dollars, making grid stability and efficient power generation not merely infrastructure concerns but fundamental pillars of Taiwan’s economic competitiveness. This reality has driven the island to pursue cutting-edge power generation technologies, including advanced combined cycle plants that can deliver maximum efficiency from imported natural gas. One such plant, the Sun Ba II facility, entered commercial operation in May 2025. It was recently recognized as a 2025 POWER Top Plant award winner.“That this project got recognized with your power plant award, I think this is really a nice story and a nice finish I would never have expected when I came here,” Thomas Ringmann, director of Business Development with Siemens Energy, said as a guest on The POWER Podcast.Sun Ba II is a 2 x 1 multi-shaft configuration, which means there are two gas turbines and two heat recovery steam generators (HRSGs) serving one steam turbine. The gas turbines and the steam turbine each have their own generators. “We have used in this project our latest and biggest gas turbine—the SGT-9000HL,” Ringmann explained. “The steam turbine is a SST-5000, so that’s a triple-pressure steam turbine with a combined HP [high-pressure] and IP [intermediate-pressure] turbine, and a dual-flow LP [low-pressure] turbine. Also, we had an air-cooled condenser, condensing the steam from that steam turbine, and we had a three-pressure reheat HRSG, which was of Benson-type technology.”The project began at the peak of the COVID pandemic, which presented a large challenge. “Every project meeting, every design meeting, every coordination meeting were all done online,” Andy Chang, project manager with Siemens Energy, said. “Everything was done online, because nobody can travel. We just had to figure this out.”Effective collaboration among project partners was a key to success. “The collaboration is not only with our consortium partner—CTCI, an EPC [engineering, procurement, and construction] company—but actually with also the customer, Sun Ba Power,” Ewen Chi, sales manager with Siemens Energy, said. “Everybody has the same target, which is to bring power on grid as soon as possible. So, with this same-boat mentality—everybody sitting in the same boat and rowing toward the target—actually helped the project to be successful and to overcome many challenges.” Chang agreed that on-time completion was only possible with all parties maintaining a collaborative spirit.“This power plant right now is predominantly running on baseload operation,” Ringmann reported. “So, given that high grade of operations along with a high gas price, the efficiency of our turbines actually is a key contributor to an economic value of the customer.”Meanwhile, the lessons learned from this first deployment of HL technology in Taiwan are being applied to a new project. Siemens Energy and CTCI are now collaborating on the Kuo Kuang II power plant, which is under construction in Taoyuan, northern Taiwan. “Because we have this momentum and this mentality from Sun Ba II execution, now each side, they decided that they will keep their core team member from both sides, and they will continue to cherish this partnership with the next project,” Chang reported.
Public power utilities are community-owned, not-for-profit electric utilities that deliver reliable, low-cost electricity to about 2,000 communities serving more than 55 million Americans. Among the cities served by public power utilities are Austin, Texas; Nashville, Tennessee; Los Angeles, California; Jacksonville, Florida; and Seattle, Washington.The Large Public Power Council (LPPC) is the voice of large public power in Washington, D.C. It advocates for policies that enable members to build critical energy infrastructure, power the growth of the economy, and provide affordable and reliable electricity to millions of Americans. The LPPC’s members are 29 of the largest public power systems in the nation. Together, they serve 30.5 million consumers across 23 states and territories.Tom Falcone, president of the LPPC, noted that all power companies, whether publicly owned, cooperatives, or investor-owned utilities (IOUs), are in the same business, that is, to reliably deliver electricity to customers. The big difference is that public power companies are accountable at home. “We’re publicly owned. We are not-for-profit. We are community oriented. We’re mission oriented. And so, our real goal, and only goal in life, is reliable, affordable power—sustainable power—back home at the least cost to customers,” Falcone said as a guest on The POWER Podcast. “So, we’re not necessarily looking to grow loads or grow earnings, unless that’s favorable to our community, unless we’re meeting the needs of our community or lowering costs for them.”Public power companies face many of the same concerns as co-ops and IOUs. One of the biggest challenges today is rapid load growth, driven by data centers, artificial intelligence (AI), and the increasing electrification of manufacturing and transportation. “The biggest thing is that the load is arriving faster and lumpier, and in a more concentrated fashion, than it has in the past,” explained Falcone. “Historically, when somebody new came to town, they wanted, you know, 5 MW, or maybe they were really large and they wanted 100 MW,” said Falcone. “But what we have today is folks who come to town and they want a GW, which is enough to power probably 600,000 homes, depending on what part of the country you’re in.”Falcone said about half of LPPC’s members are seeing this very, very rapid growth. “They could double over the next 10 years,” he said. While the demand for the energy is very immediate, utilities’ ability to build infrastructure is not. “We have to go through the same permitting and public processes, and construction and supply chain, and it just doesn’t allow us to build quite that fast,” Falcone reported.
Despite nuclear power’s unmatched ability to produce reliable, carbon-free energy at scale, it is often dismissed by clean energy advocates in favor of renewable resources like wind and solar. Cost arguments and public misconceptions around safety and radioactive waste have kept it out of many mainstream climate strategies. But as Tim Gregory argues in his new book Going Nuclear: How Atomic Energy Will Save the World, this exclusion may be the greatest obstacle to achieving net zero goals. In fact, Gregory says in his book “net zero is impossible without nuclear power.”“Claiming renewables on their own are enough to replace fossil fuels is underestimating the challenge of achieving net zero,” Gregory said as a guest on The POWER Podcast. “Fossil fuels have basically defined the world order for the last couple of centuries, and to think that we can replace them with wind power and solar power, which are fundamentally tied to the whims of the weather, and the rotation of the planet in the case of solar, is really underestimating the scale of the challenge,” he said.“We need power that comes in enormous quantities exactly where we need it and when we need it,” Gregory continued. “I don’t want to live in a world without solar panels or wind turbines, but to think that they can do it on their own, I think, is honestly naive. We need something that’s reliable to compensate for the intermittence of renewables, and nuclear power would be absolutely perfect for that.”Notably, innovative companies and many government leaders around the world are backing nuclear power projects. “Big tech in North America has really cottoned on to these small modular reactors,” said Gregory. “Meta, Google, Microsoft, and Amazon are all going to be using small modular reactors to power their data centers. … This isn’t just a pipe dream—this is actually happening now in real time. … It’s been very, very encouraging watching that unfold.”Public perceptions on nuclear power are also trending in a positive direction, and the movement seems to be bipartisan. “It’s very, very encouraging that more than half of people in the UK either strongly support or tend to support nuclear power. Strong opposition to nuclear power, according to the latest poll, is actually below 10%,” Gregory reported. “As such, the two major political parties in the UK—that’s the Labor Party, which is kind of our left leaning party, and the Conservative Party, which is our right leaning party—they both support the massive expansion of nuclear power, which is really, really nice actually. It’s maybe something that both sides of the political spectrum can agree on.”The same is true in the U.S., where both Democrats and Republicans have gotten behind nuclear power. A case in point is the Accelerating Deployment of Versatile, Advanced Nuclear for Clean Energy (ADVANCE) Act, which was signed into law in July 2024. It passed with overwhelming bipartisan support in the Senate with a vote of 88–2, and in the House of Representatives with a vote of 393–13.“If your politics has you more concerned with environmental stewardship, and climate change, and phasing out fossil fuels, and getting rid of oil from the energy system, then nuclear power is for you. But then at the same time, if your politics has you perhaps more leaning towards economic growth, and the economy, and prosperity, and all that kind of thing, then nuclear power is for you as well, because it provides the energy that enables that economic growth,” Gregory said. “And so, it’s actually very, very encouraging to see that, at least in most countries, nuclear power is not a partisan issue, which is all too rare in the world these days.”
More than 100 of the world’s largest energy companies are betting that artificial intelligence (AI) will revolutionize how electricity gets made, moved, and managed. But they’re not waiting for Silicon Valley to build it for them—they’ve taken matters into their own hands through an EPRI-led consortium.That initiative is the Open Power AI Consortium, which EPRI launched in March 2025 to drive the development and deployment of an open AI model tailored for the power sector. According to its mission statement, the Open Power AI Consortium “aims to evolve the electric sector by leveraging advanced AI technologies to innovate the way electricity is made, moved, and used by customers. By fostering collaboration among industry leaders, researchers, and technology providers, the consortium will drive the development and deployment of cutting-edge AI solutions tailored to enhance operational efficiencies, increase resiliency and reliability, deploy emerging and sustainable technologies, and reduce costs while improving the customer experience.”“We’re really looking at building an ecosystem to accelerate the development and deployment, and recognizing that, while AI is advancing rapidly, the energy industry has its own unique needs, especially around reliability, safety, regulatory compliance, and so forth. So, the consortium provides a collaborative platform to develop and maintain domain-specific AI models—think a ChatGPT tailored to the energy industry—as well as sharing best practices, testing innovative solutions in a secure environment, and long term, we believe this will help modernize the grid, improve customer experiences, and support global safe, affordable, and reliable energy for everyone,” Jeremy Renshaw, executive director for AI and Quantum with EPRI, said as a guest on The POWER Podcast.Among the consortium’s members are some of the largest energy companies in the world, including Constellation, Con Edison, Duke Energy, EDF, Korea Electric Power Corp. (KEPCO), New York Power Authority (NYPA), Pacific Gas and Electric Co. (PG&E), Saudi Electricity Co., Southern Company, Southern California Edison, Taiwan Power Co., and Tennessee Valley Authority (TVA). It also includes entities like Amazon Web Servies (AWS), Burns and McDonnell, GE Vernova, Google, Gulf Cooperation Council (GCC) Interconnection Authority, Korea Hydro and Nuclear Power (KHNP), Khalifa University, Microsoft, Midcontinent Independent System Operator (MISO), PJM, Rolls-Royce SMR, and Westinghouse Electric Co.“For many years, the power industry has been somewhat siloed, and there were not many touch points or communication between global utilities, technology companies, universities, and so forth. So, this consortium aims to facilitate making new connections between these important and impactful organizations to increase collaboration and information sharing that will benefit everyone,” Renshaw explained.EPRI, together with Articul8 and NVIDIA, has already developed the first set of domain-specific generative AI models for electric and power systems aimed at advancing the energy transformation. Although the technology has not been released publicly, it will be made available soon as an NVIDIA NIM microservice for early access. This development sets the foundation for more to come.
In a special edition of The POWER Podcast, released in collaboration with the McCrary Institute’s Cyber Focus podcast, POWER’s executive editor, Aaron Larson, and Frank Cilluffo, director of the McCrary Institute for Cyber and Critical Infrastructure Security and Professor of Practice at Auburn University, discuss the evolving power grid and cybersecurity challenges. Specifically, they highlight the shift taking place from centralized power stations to more distributed energy resources, including solar farms and wind turbines. The conversation touches on the importance of a reliable power grid and the need to protect critical infrastructure.“From a national security standpoint, from an economic standpoint, from a public safety standpoint, if you don’t have power, all these other systems are somewhat irrelevant,” Cilluffo said. “There’s no infrastructure more critical than power.”Cilluffo noted that artificial intelligence (AI) is requiring increasingly more power, which can’t be ignored. “If we want to be AI dominant, we can’t do that if we’re not energy dominant,” said Cilluffo. “The two are in inextricably interwoven—hand in glove. And if you start looking at where the country wants to be technologically, if we want to lead, we really need to continue to double down, triple down, and look at all sorts of sources of energy as well.”While renewables are clearly leading when it comes to new generation being added to the grid today, emerging technologies including small modular reactors, fusion power, deep dry-rock geothermal, and space-based solar power, are on the horizon, promising potentially game-changing energy options. “And not to put a fine point on it, but you mentioned so many different forms of energy, and I’m reminded of the old test, the A, B, C, or D, all of the above. This sounds like it is clearly an all of the above,” Cilluffo proposed.Meanwhile, the enormous energy buildout in China was discussed. China is not just leading, but truly dominating the world in the construction of wind, solar, nuclear, coal, and energy storage projects in 2025, both in terms of capacity and projects under development. This leadership is evident across all five sectors, frequently accounting for the majority, or at least a plurality, of new global construction and installation.“China is a primary focus of a lot of our [Cyber Focus] podcast discussion, but it’s a race we cannot afford to lose, whether it’s around AI, quantum. And, I think you’re spot on; to get there, they recognize the need to really quadruple down on energy,” said Cilluffo. “I still think that we [the U.S.] want to be at the vanguard driving all of this.”And while it’s widely known that cybersecurity is critically important to energy systems, it’s often not prioritized the way it should be. “Everyone needs to be cyber aware, cyber informed,” Cilluffo said. “These are issues that we have to invest in. It can’t be an afterthought. It has to be something that everyone thinks through. And the reality is, don’t think it’s someone else’s problem: a) it’s all of our problems, and b) don’t think that it can be looked at after the balloon goes up—you need to be thinking all of this well in advance.”
The name Mike Richter is well-known among hockey fans. Richter spent 15 years in the National Hockey League as a goalie for the New York Rangers, including in 1994 when he was a fixture in the net during the team’s Stanley Cup winning season. Richter was also recognized as the most valuable player for the U.S.’s 1996 gold medal winning World Cup team, as well as a member of three U.S. Olympic teams, including in 2002 when the team won the silver medal. Richter was inducted into the U.S. Hockey Hall of Fame in 2008.But what is likely lesser known is that Richter is the current president of Brightcore Energy, a leading provider of integrated, end-to-end clean energy solutions to the commercial, institutional, and government markets. The Armonk, New York–headquartered company’s services include high-efficiency geothermal-based heating and cooling systems for both new construction and existing building retrofits, among other things. Brightcore’s turnkey, single-point solution encompasses all project development phases including preliminary modeling, feasibility and design, incentive and policy guidance, construction and implementation, and system performance monitoring.As a guest on The POWER Podcast, Richter noted that heating, ventilation, and air conditioning (HVAC) systems for commercial, industrial, and municipal buildings consume an enormous amount of energy in a place like New York City. Furthermore, the emissions associated with these systems can be significant. “If you can address that, you’re doing something important, and that’s really where our focus has been, particularly the last few years,” he said.Geothermal Heating and Cooling SystemsTraditional geothermal often requires significant open space for the geothermal borefield and can have material time implications in project development. Brightcore says its exclusive UrbanGeo solution combines proprietary geothermal drilling technology and techniques that increase the feasibility of geothermal heating and cooling applicability while reducing construction development timelines.“We typically go between 500 and 1,000 feet down,” Richter explained. “The ambient temperature of the ground about four feet down below our feet here in New York is 55 degrees [Fahrenheit] year-round.” The constant and stable underground temperature is the key to geothermal heating and cooling systems. Even when the air above ground is extremely hot or freezing cold, the earth’s steady temperature provides a valuable heating or cooling resource. A geothermal system has pipes buried underground that fluid is circulated through, and a heat pump inside the building. In winter, the fluid in the pipes absorbs warmth from the earth and brings it inside. There, the heat pump “compresses” this heat, raising its temperature so it can warm the building air comfortably—even when it’s icy cold outside.In summer, the system works in reverse. The heat pump pulls heat out of the building’s air, sending it through the same underground pipes. Since the earth is cooler than the hot summer air, it acts like a giant heat sponge, soaking up unwanted heat from the building. This process cools the living space easily and efficiently, using a lot less energy than a regular air conditioner because the ground is always cooler than the hot outdoor air.So, whether it’s heating or cooling, a geothermal system can keep buildings comfortable by moving heat between the building and the earth. “[It’s] pretty straightforward and very, very efficient and effective, particularly—and this is key—at the extremes,” said Richter. “Air source heat pumps are excellent and they continue to get better,” he added.
In the proverbial shadow of the Naughton Power Plant, a station in Kemmerer, Wyoming, that will stop burning coal at the end of this year, TerraPower is constructing what it calls “the only advanced, non-light-water reactor in the Western Hemisphere being built today.” The project represents more than just a new power source—it’s a symbolic passing of the torch from fossil fuels to next-generation nuclear technology.“We call it the Natrium reactor because it is in a class of reactors we call sodium fast reactors,” Eric Williams, Chief Operating Officer for TerraPower, said as a guest on The POWER Podcast. The Natrium design is a Generation IV reactor type, which is the most advanced class of reactors being developed today. “These designs have a greatly increased level of safety, performance, and economics,” Williams explained.Williams said the use of liquid metal coolant enhances safety. “Liquid metals are so excellent at transferring heat away from the reactor, both to exchange that heat into other systems to go generate the electricity or to remove the heat in an emergency situation,” he said. “For the Natrium reactor, we can do that heat removal directly to air if we want to, so that provides a very robust safety case for the reactor.”The design is also safer because it can run at low pressure. “The primary system is at atmospheric pressure; whereas, current pressurized water reactors have to pressurize the system to keep the liquid from boiling—to keep it in a liquid state,” Williams explained. “Liquid metal sodium doesn’t boil until about 800 to 900 degrees Celsius, and the reactor operates down at 500 degrees Celsius, so that can remain a liquid and still be at a very high temperature without having to pressurize it.”The liquid metal coolant also provides performance benefits. “One of those is the ability to store the energy in the form of molten salt heat coming out of the nuclear island,” said Williams. “That is really giving us the ability to provide basically a grid-scale energy storage solution, and it really matches up well with the current needs of the modern electricity grid.”Meanwhile, the energy storage aspect also allows decoupling the electricity generation side of the plant—the energy island—from the reactor side of the plant, that is, the nuclear island. That allows the energy island to be classified as “non-safety-related” in the eyes of the U.S. Nuclear Regulatory Commission (NRC). “That side of the plant has nothing to do with keeping the reactor safe, and that means the NRC oversight doesn’t have to apply to the energy island side of the plant, so all of that equipment can be built to lower cost and different codes and standards,” Williams explained.Notably, this also permits the grid operator to dispatch electricity without changing anything on the nuclear island. “That allows a different kind of integrating with the grid for a nuclear plant that hasn’t been achieved yet in the U.S.,” Williams said. “We’re very excited about that—the safety, the performance, and economics—and it really gives us the ability to have a predictable schedule, and construction will be complete in 2030.”While there is clearly a lot that needs to be done, and first-of-a-kind projects rarely go off without a hitch, Williams seemed pleased with how the project was progressing. “We’re really excited to be working in the state of Wyoming. It is just an outstanding state for developing any kind of energy project, including nuclear energy. The people in the community are really welcoming to us. The state legislators are always looking for ways to remove any obstacles and just explain to us how to get the permits we need and everything. So, the project has been going really well from that standpoint,” he said. In the end, Williams appeared confident that TerraPower would hit its current target for completion in 2030.
The world’s electricity grids are facing unprecedented strain as demand surges from electrification, data centers, and renewable energy integration, while aging infrastructure struggles to keep pace. Traditional approaches to grid expansion—building new transmission lines and substations—face mounting challenges including sometimes decade-long permitting processes, escalating costs that can reach billions per project, and growing public resistance to new infrastructure. This mounting pressure has created an urgent need for innovative solutions that can unlock the hidden capacity already embedded within existing transmission networks.What Are GETs and What Do They Do?Grid enhancing technologies (GETs) represent a transformative approach to this challenge, offering utilities the ability to safely increase power flows on existing transmission lines by up to 40% in some cases without the need for new construction. These advanced technologies—including dynamic line ratings (DLR) that adjust capacity based on real-time weather conditions, high-temperature advanced conductors that can carry significantly more current, and sophisticated power flow controllers that optimize electricity routing—work by maximizing the utilization of current infrastructure. Rather than building around bottlenecks, GETs eliminate them through smarter, more responsive grid management.On an episode of The POWER Podcast, Anna Lafoyiannis, program lead for the integration of renewables and co-lead of the GET SET (Grid Enhancing Technologies for a Smart Energy Transition) initiative with EPRI, explained that GETs can be either hardware or software solutions. “Their purpose is to increase the capacity, efficiency, reliability, or safety of transmission lines. So, think of these as adders to your transmission lines to make them even better,” Lafoyiannis said.“Typically, they reduce congestion costs. They improve the integration of renewables. They increase capacity. They can provide grid service applications. So, they’re really multifaceted—very helpful for the grid,” she said. “At EPRI, we think of them as kind of like a tool in a toolbox.”The economic and environmental implications are profound. Deploying GETs can defer or eliminate the need for costly new transmission projects while accelerating the integration of renewable energy resources that are often stranded due to transmission constraints. As utilities worldwide grapple with the dual pressures of modernizing their grids and meeting ambitious clean energy targets, GETs offer a compelling path forward that leverages innovation over infrastructure expansion to create a more resilient, efficient, and sustainable electricity system.
As the world transitions toward renewable energy sources, geothermal power has emerged as one of the most promising, yet underutilized, options in the clean energy portfolio. Unlike solar and wind, geothermal offers consistent baseload power generation capacity without intermittency challenges, making it an increasingly attractive component in the renewable energy mix.The geothermal sector has shown increasing potential in recent years, with technological innovations expanding its possible applications beyond traditional volcanic regions. These advances are creating opportunities to tap into moderate-temperature resources that were previously considered uneconomical, potentially unlocking gigawatts of clean, renewable power across the globe.It's within this expanding landscape that companies like Gradient Geothermal are pioneering new approaches. As a guest on The POWER Podcast, Ben Burke, CEO of Gradient Geothermal, outlined his company’s innovative approach to geothermal energy extraction that could transform how we think about energy recovery from oil and gas operations.Modular and Mobile Geothermal SolutionsGradient Geothermal differentiates itself in the geothermal marketplace through its focus on modular, portable equipment designed specifically for oil field operations, geothermal operators, and potentially data centers. Unlike traditional geothermal installations that require permanent infrastructure, Gradient’s equipment can be moved every six to 18 months as needed, allowing clients to adjust their thermal capacity by adding or removing units as requirements change.“The advantage of mobility and modularity is really important to oil and gas operators,” Burke said. The company’s solution consists of two main components: an off-the-shelf organic Rankine cycle (ORC) unit and a primary heat exchanger loop. This system can handle various ratios of oil, gas, and water—even “dirty” water containing sand, brines, and minerals—and convert that heat into usable power.One of the most compelling aspects of Gradient’s technology is its ease of installation. “Installation takes one day,” Burke explained. “It’s two pipes and three wires, and it’s able to sit on a gravel pad or sit on trailers.” This quick setup contrasts sharply with traditional geothermal plants that can take years to construct.The units come in three sizes: 75 kW, 150 kW, and 300 kW. The modular nature allows for flexible configurations, with units able to be connected in series or parallel to handle varying water volumes and temperatures.
U.S. President Donald Trump was sworn into office for the second time on Jan. 20, 2025. That means April 30 marks his 100th day back in office. A lot has happened during that relatively short period of time. The Trump administration has implemented sweeping changes to U.S. energy policy, primarily focused on promoting fossil fuels while curtailing renewable energy development. The administration declared a “national energy emergency” to expedite approvals for fossil fuel infrastructure and lifted regulations on coal plants, exempting nearly 70 facilities from toxic pollutant rules. Coal was officially designated a “critical mineral,” with the Department of Justice directed to investigate regulatory bias against the industry. Additionally, the administration ended the Biden-era pause on approvals for new liquefied natural gas (LNG) export facilities, signaling strong support for natural gas expansion.On the environmental front, U.S. Environmental Protection Agency (EPA) Administrator Lee Zeldin announced 31 deregulatory actions designed in part to “unleash American energy.” The administration is also challenging the 2009 EPA finding that greenhouse gases endanger public health—a foundational element of climate regulation. President Trump announced the U.S.’s withdrawal from the Paris Climate Agreement, effective in early 2026, and terminated involvement in all climate-related international agreements, effectively eliminating previous emissions reduction commitments.Renewable energy has faced significant obstacles under the new administration. A six-month pause was imposed on offshore wind lease sales and permitting in federal waters, with specific projects targeted for cancellation. The administration issued a temporary freeze on certain Inflation Reduction Act (IRA) and Bipartisan Infrastructure Law (BIL) funds designated for clean energy projects. Policies were implemented to weaken federal clean car standards, potentially eliminate electric vehicle (EV) tax credits, and halt funding for EV charging networks—indirectly affecting power generation by potentially reducing electricity demand from EVs.Yet, the administration’s tariff policy may end up impacting the power industry more than anything else it has done. “One thing in particular that I think would be hard to argue is not the most impactful, and that’s the current status of tariffs and a potential trade war,” Greg Lavigne, a partner with the global law firm Sidley Austin, said as a guest on The POWER Podcast.In April, President Trump declared a national emergency to address trade deficits, imposing a 10% tariff on all countries and higher tariffs on nations with large trade deficits with the U.S. These tariffs particularly affect solar panels and components from China, potentially increasing costs for renewable energy projects and disrupting supply chains.Meanwhile, the offshore wind energy industry has also taken a hard hit under the Trump administration. “My second-biggest impact in the first 100 days would certainly be the proclamations pausing evaluation of permitting of renewable projects, but particularly wind projects, on federal lands,” said Lavigne. “That is having real-world impacts today on the offshore wind market off the eastern seaboard of the United States.” Despite the focus on traditional energy sources, the Trump administration has expressed support for nuclear energy as a tool for energy dominance and global competitiveness against Russian and Chinese nuclear exports. Key appointees, including Energy Secretary Chris Wright, have signaled a favorable stance toward nuclear power development, including small modular reactors.All these actions remain subject to ongoing legal and political developments, with their full impact on the power generation industry yet to unfold.
The power industry supply chain is facing unprecedented strain as utilities race to upgrade aging infrastructure against a backdrop of lengthening lead times and increasing project complexity. This supply chain gridlock arrives precisely when utilities face mounting pressure to modernize systems. As the industry confronts this growing crisis, innovations in procurement, manufacturing, and strategic planning are essential.“Utilities can optimize their supply chain for grid modernization projects by taking a collaborative approach between the services themselves and how they can support the projects, as well as having a partner to be able to leverage their sourcing capabilities and have the relationships with the right manufacturers,” Ian Rice, senior director of Programs and Services for Grid Services at Wesco, explained as a guest on The POWER Podcast. “At the end of the day, it’s how can the logistical needs be accounted for and taken care of by the partnered firm to minimize the overall delays that are going to naturally come and mitigate the risks,” he said.Headquartered in Pittsburgh, Pennsylvania, Wesco is a leading global supply chain solutions provider. Rice explained that through Wesco, utilities gain access to a one-stop solution for program services, project site services, and asset management. The company claims its tailored approach “ensures cost reduction, risk mitigation, and operational efficiencies, allowing utilities to deliver better outcomes for their customers.”“We take a really comprehensive approach to this,” said Rice. “In the utility market, we believe pricing should be very transparent.” To promote a high level of transparency, Wesco builds out special recovery models for its clients.“What this looks like is: we take a complete cradle-to-grave approach on the lifecycle of the said project or program, and typically, it could be up to nine figures—very, very large programs,” Rice explained. “It all starts with building that model and understanding the complexity. What are the inputs, what are the outputs, and what constraints are there in the short term as well as the long term? And, really, what’s the goal of that overall program?” The answers to those questions are accounted for in the construction of the model. “It all starts with demand management, which closely leads to a sourcing and procurement strategy,” Rice said. “From there, we can incorporate inventory control, and set up SOPs [standard operating procedures] of how we want to deal with the contractors and all the other stakeholders within that program or project. And that really ties into what’s going to be the project management approach, as well in setting up all the different processes, or even the returns and reclamation program. We’re really covering everything minute to minute, day to day, the entire duration of that project, and tying that into a singular model.”But that’s not all. Rice said another thing that sets Wesco apart from others in the market is when it takes this program or project approach, depending on the scale of it, the company remains agnostic when it comes to suppliers. “We’re doing procurement on behalf of our customers,” he said. “So, if they have direct relationships, we can facilitate that. If they’re working with other distributors, we can also manage that. The whole idea here is: what’s in the best interest of the customer to provide the most value.”
As the presidential inauguration loomed on the horizon in January this year, the U.S. Department of Energy’s (DOE’s) Loan Programs Office (LPO) published a “year-in-review” article, highlighting accomplishments from 2024 and looking ahead to the future. It noted that the previous four years had been the most productive in the LPO’s history.“Under the Biden-Harris Administration, the Office has announced 53 deals totaling approximately $107.57 billion in committed project investment––approximately $46.95 billion for 28 active conditional commitments and approximately $60.62 billion for 25 closed loans and loan guarantees,” it said.Much of the funding for these investments came through the passing of the Bipartisan Infrastructure Law (BIL) and the Inflation Reduction Act (IRA). The LPO reported that U.S. clean energy investment more than doubled from $111 billion in 2020 to $236 billion in 2023, creating more than 400,000 clean energy jobs. The private sector notably led the way, enabled by U.S. government policy and partnerships.“There were 55 deals that we got across the finish line,” Jigar Shah, director of the LPO from March 2021 to January 2025, said as a guest on The POWER Podcast, while noting there were possibly 200 more projects that were nearly supported. “They needed to do more work on their end to improve their business,” he explained. That might have meant they needed to de-risk their feedstock agreement or their off-take agreement, for example, or get better quality contractors to do the construction of their project.“It was a lot of education work,” Shah said, “but I’m really proud of that work, because I think a lot of those companies, regardless of whether they used our office or not, were better for the interactions that they had with us.”A Framework for SuccessWhen asked about doling out funds, Shah viewed the term somewhat negatively. “As somebody who’s been an investor in my career, you don’t dole out money, because that’s how you lose money,” he explained. “What you do is you create a framework. And you tell people, ‘Hey, if you meet this framework, then we’ve got a loan for you, and if you don’t meet this framework, then we don’t have a loan for you.” Shah noted that the vast majority of the 400 to 500 companies that the LPO worked closely with during his tenure didn’t quite meet the framework.Still, most of those that did have progressed smoothly. “Everything that started construction is still under construction, and so, they’re all going to be completed,” said Shah. “I think all in all, the thesis worked. Certainly, there are many people who had a hard time raising equity or had a hard time getting to the finish line and final investment decision, but for those folks who got to final investment decision and started construction, I think they’re doing very well.”Notable ProjectsWhen asked which projects he was most excited about, Shah said, “All of them are equally exciting to me. I mean, that’s the beauty of the work I do.” He did, however, go on to mention several that stood out to him. Specifically, he pointed to the Wabash, Montana Renewables, EVgo, and Holtec Palisades projects, which were all supported under the LPO’s Title 17 Clean Energy Financing Program, as particularly noteworthy.Perhaps the most important of the projects Shah mentioned from a power industry perspective, was the Holtec Palisades endeavor. Valued at $1.52 billion, the loan guarantee will allow upgrading and repowering of the Palisades nuclear plant in Covert, Michigan, a first in U.S. history, which has spurred others to bring retired nuclear plants back online. “[It’s] super exciting to see our first nuclear plant being restarted, and as a result, the Constellation folks have decided to restart a nuclear reactor in Pennsylvania, and NextEra has decided to restart a nuclear reactor in Iowa. So, it’s great to have that catalytic impact,” said Shah.
The Tennessee Valley Authority (TVA) has for many years been evaluating emerging nuclear technologies, including small modular reactors, as part of technology innovation efforts aimed at developing the energy system of the future. TVA—the largest public power provider in the U.S., serving more than 10 million people in parts of seven states—currently operates seven reactors at three nuclear power plants: Browns Ferry, Sequoyah, and Watts Bar. Meanwhile, it’s also been investing in the exploration of new nuclear technology by pursuing small modular reactors (SMRs) at the Clinch River Nuclear (CRN) site in Tennessee.“TVA does have a very diverse energy portfolio, including the third-largest nuclear fleet [in the U.S.],” Greg Boerschig, TVA’s vice president for the Clinch River project, said as a guest on The POWER Podcast. “Our nuclear power plants provide about 40% of our electricity generated at TVA. So, this Clinch River project and our new nuclear program is building on a long history of excellence in nuclear at the Tennessee Valley.”TVA completed an extensive site selection process before choosing the CRN site as the preferred location for its first SMR. The CRN site was originally the site of the Clinch River Breeder Reactor project in the early 1980s. Extensive grading and excavation disturbed approximately 240 acres on the project site before the project was terminated. Upon termination of the project, the site was redressed and returned to an environmentally acceptable condition.The CRN property is approximately 1,200 acres of land located on the northern bank of the Clinch River arm of the Watts Bar Reservoir in Oak Ridge, Roane County, Tennessee. The CRN site has a number of significant advantages, which include two existing power lines that cross the site, easy access off of Tennessee State Route 58, and the fact that it is a brownfield site previously disturbed and characterized as a part of the Clinch River Breeder Reactor project. The Oak Ridge area is also noted to have a skilled local workforce, including many people familiar with the complexities of nuclear work. “The community acceptance here is really just phenomenal,” said Boerschig. “The community is very educated and very well informed.”TVA began exploring advanced nuclear technologies in 2010. In 2016, it submitted an application to the Nuclear Regulatory Commission (NRC) for an Early Site Permit for one or more SMRs with a total combined generating capacity not to exceed 800 MW of electricity for the CRN site. In December 2019, TVA became the first utility in the nation to successfully obtain approval for an Early Site Permit from the NRC to potentially construct and operate SMRs at the site. While the decision to potentially build SMRs is an ongoing discussion as part of the asset strategy for TVA’s future generation portfolio, significant investments have been made in the Clinch River project with the goal of moving it forward.OPG has a BWRX-300 project well underway at its Darlington New Nuclear Project site in Clarington, Ontario, with construction expected to be complete by the end of 2028. While OPG is developing its project in parallel with the design process, TVA expects to wait for more design maturity before launching its CRN project. “As far as the standard design is concerned, we’re at the same pace, but overall, their project is about two years in front of ours,” said Boerschig. “And that’s by design—they are the lead plant for this effort.” In the meantime, there are two primary items on TVA’s to-do list. “Right now, the two biggest things that we have on our list are completing the standard design work, and then the construction permit application,” Boerschig said, noting the standard design is “somewhere north of 75% complete” and that TVA’s plan is to submit the construction permit application “sometime around mid-year of this year.”
A virtual power plant (VPP) is a network of decentralized, small- to medium-scale power generating units, flexible power consumers, and storage systems that are aggregated and operated as a single entity through sophisticated software and control systems. Unlike a traditional power plant that exists in a single physical location, a VPP is distributed across multiple locations but functions as a unified resource.VPPs are important to power grid operations because they provide grid flexibility. VPPs help balance supply and demand on the grid by coordinating many smaller assets to respond quickly to fluctuations. This becomes increasingly important as more intermittent renewable energy sources—wind and solar—are added to the grid.“A virtual power plant is essentially an aggregation of lots of different resources or assets from the grid,” Sally Jacquemin, vice president and general manager of Power & Utilities with AspenTech, said as a guest on The POWER Podcast. “As a whole, they have a bigger impact on the grid than any individual asset would have on its own. And so, you aggregate all these distributed energy resources and assets together to create a virtual power plant that can be dispatched to help balance the overall system supply to demand.”VPPs provide a way to effectively integrate and manage distributed energy resources such as rooftop solar, small wind turbines, battery storage systems, electric vehicles, and demand response programs. VPPs can reduce strain on the grid during peak demand periods by strategically reducing consumption or increasing generation from distributed sources, helping to avoid blackouts and reducing the need for expensive peaker plants.Other benefits provided by VPPs include enhancing grid resilience, enabling smaller energy resources to participate in electricity markets that would otherwise be inaccessible to them individually, and reducing infrastructure costs by making better use of existing assets and reducing peak demand. VPPs enable consumers to become “prosumers,” that is, both producers and consumers of energy, giving them more control over their energy use and potentially reducing their costs.“Virtual power plants are becoming important, not only for utilities, but also in the private sector,” Jacquemin explained. “Because of the commercial value of electricity rising and the market system rates, it’s now profitable for these virtual power plants in many markets due to the value of power that they can supply during these periods of low supply.”AspenTech is a leading industrial software partner, with more than 60 locations worldwide. The company’s solutions address complex environments where it is critical to optimize the asset design, operation, and maintenance lifecycle. AspenTech says its Digital Grid Management solutions “enable the resilient, sustainable, and intelligent utility of the future.”“At AspenTech Digital Grid Management, our software is in control rooms of utilities around the world,” said Jacquemin. “All utilities know they need to be investing in their digital solutions and modernizing their control room technology in order to meet the demands of the energy transition. So, utilities need to be focusing more time and more money to ensure that their software and their systems are capable of enabling that utility of the future.”
Net-demand energy forecasts are critical for competitive market participants, such as in the Electric Reliability Council of Texas (ERCOT) and similar markets, for several key reasons. For example, accurate forecasting helps predict when supply-demand imbalances will create price spikes or crashes, allowing traders and generators to optimize their bidding strategies. It’s also important for asset optimization. Power generators need to know when to commit resources to the market and at what price levels. Poor forecasting can lead to missed profit opportunities or operating assets when prices don’t cover costs.Fortunately, artificial intelligence (AI) is now capable of producing highly accurate forecasts from the growing amount of meter and weather data that is available. The complex and robust calculations performed by these machine-learning algorithms is well beyond what human analysts are capable of, making advance forecasting systems essential to utilities. Plus, they are increasingly valuable to independent power producers (IPPs) and other energy traders making decisions about their positions in the wholesale markets.Sean Kelly, co-founder and CEO of Amperon, a company that provides AI-powered forecasting solutions, said using an Excel spreadsheet as a forecasting tool was fine back in 2005 when he got started in the business as a power trader, but that type of system no longer works adequately today. “Now, we’re literally running at Amperon four to six models behind the scenes, with five different weather vendors that are running an ensemble each time,” Kelly said as a guest on The POWER Podcast. “So, as it gets more confusing, we’ve got to stay on top of that, and that’s where machine learning really kicks in.”The consequences of being ill-prepared can be dire. Having early and accurate forecasts can mean the difference between a business surviving or failing. Effects from Winter Storm Uri offer a case in point.Normally, ERCOT wholesale prices fluctuate from about $20/MWh to $50/MWh. During Winter Storm Uri (Feb. 13–17, 2021), ERCOT set the wholesale electricity price at its cap of $9,000/MWh due to extreme demand and widespread generation failures caused by the storm. This price remained in effect for approximately 4.5 days (108 hours). This 180-fold price increase had devastating financial impacts across the Texas electricity market.The financial fallout was severe. Several retail electricity providers went bankrupt, most notably Griddy Energy, which passed the wholesale prices directly to customers, resulting in some receiving bills of more than $10,000 for just a few days of power. “Our clients were very appreciative of the work we had at Amperon,” Kelly recalled. “We probably had a dozen or so clients at that time, and we told them on February 2 that this was coming,” he said.With that early warning, Kelly said Amperon’s clients were able to get out in front of the price swing and buy power at much lower rates. “Our forecasts go out 15 days, ERCOT’s forecasts only go out seven,” Kelly explained. “So, we told everyone, ‘Alert! Alert! This is coming!’ Dr. Mark Shipham, our in-house meteorologist, was screaming it from the rooftops. So, we had a lot of clients who bought $60 power per megawatt. So, think about buying 60s, and then your opportunity is 9,000. So, a lot of traders made money,” he said. “All LSEs—load serving entities—still got hit extremely bad, but they got hit a lot less bad,” Kelly continued. “I remember one client saying: ‘I bought power at 60, then I bought it at 90, then I bought it at 130, then I bought it at 250, because you kept telling me that load was going up and that this was getting bad.’ And they’re like, ‘That is the best expensive power I’ve ever bought. I was able to keep my company as a retail energy provider.’ And, so, those are just some of the ways that these forecasts are extremely helpful.”
When you think of innovative advancements in nuclear power technology, places like the Idaho National Laboratory and the Massachusetts Institute of Technology probably come to mind. But today, some very exciting nuclear power development work is being done in West Texas, specifically, at Abilene Christian University (ACU). That’s where Natura Resources is working to construct a molten salt–cooled, liquid-fueled reactor (MSR).“We are in the process of building, most likely, the country’s first advanced nuclear reactor,” Doug Robison, founder and CEO of Natura Resources, said as a guest on The POWER Podcast. Natura has taken an iterative, milestone-based approach to advanced reactor development and deployment, focused on efficiency and performance. This started in 2020 when the company brought together ACU’s NEXT Lab with Texas A&M University; the University of Texas, Austin; and the Georgia Institute of Technology to form the Natura Resources Research Alliance. In only four years, Natura and its partners developed a unique nuclear power system and successfully licensed the design. The U.S. Nuclear Regulatory Commission (NRC) issued a construction permit for deployment of the system at ACU last September.Called the MSR-1, ACU’s unit will be a 1-MWth molten salt research reactor (MSRR). It is expected to provide valuable operational data to support Natura’s 100-MWe systems. It will also serve as a “world-class research tool” to train advanced reactor operators and educate students, the company said.Natura is not only focused on its ACU project, but it is also moving forward on commercial reactor projects. In February, the company announced the deployment of two advanced nuclear projects, which are also in Texas. These deployments, located in the Permian Basin and at Texas A&M University’s RELLIS Campus, represent significant strides in addressing energy and water needs in the state.“Our first was a deployment of a Natura commercial reactor in the Permian Basin, which is where I spent my career. We’re partnering with a Texas produced-water consortium that was created by the legislature in 2021,” said Robison. One of the things that can be done with the high process heat from an MSR is desalinization. “So, we’re going to be desalinating produced water and providing power—clean power—to the oil and gas industry for their operations in the Permian Basin,” said Robison.Meanwhile, at Texas A&M’s RELLIS Campus, which is located about eight miles northwest of the university’s main campus in College Station, Texas, a Natura MSR-100 reactor will be deployed. The initiative is part of a broader project known as “The Energy Proving Ground,” which involves multiple nuclear reactor companies. The project aims to bring commercial-ready small modular reactors (SMRs) to the site, providing a reliable source of clean energy for the Electric Reliability Council of Texas (ERCOT).
Geothermal energy has been utilized by humans for millennia. While the first-ever use may be a mystery, we do know the Romans tapped into it in the first century for hot baths at Aquae Sulis (modern-day Bath, England). Since then, many other people and cultures have found ways to use the Earth’s underground heat to their benefit.Geothermal resources were used for district heating in France as far back as 1332. In 1904, Larderello, Italy, was home to the world’s first experiment in geothermal electricity generation, when five lightbulbs were lit. By 1913, the first commercial geothermal power plant was built there, which expanded to power the local railway system and nearby villages.However, one perhaps lesser-known geothermal concept revolves around energy storage. “It’s very much like pumped-storage hydropower, where you pump a lake up a mountain, but instead of going up a mountain, we’re putting that lake deep in the earth,” Cindy Taff, CEO of Sage Geosystems, explained as a guest on The POWER Podcast.Sage Geosystems’ technology utilizes knowledge gleaned from the oil and gas industry, where Taff spent more than 35 years as a Shell employee. “What we do is we drill a well. We’re targeting a very low-permeability formation, which is the opposite of what oil and gas is looking for, and quite frankly, it’s the opposite of what most geothermal technologies are looking for. That low permeability then allows you to place a fracture in that formation, and then operate that fracture like a balloon or like your lungs,” Taff explained. “When the demand is low, we use electricity to power an electric pump. We pump water into the fracture. We balloon that fracture open and store the water under pressure until a time of day that power demand peaks. Then, you open a valve at surface. That fracture is naturally going to close. It drives the water to surface. You put it through a Pelton turbine, which looks like a kid’s pinwheel. You spin the turbine, which spins the generator, and you generate electricity.”Unlike more traditional geothermal power generation systems that use hot water or steam extracted from underground geothermal reservoirs, Sage’s design uses what’s known as hot dry rock technology. To reach hot dry rock, drillers may have to go deeper to find desired formations, but these formations are much more common and less difficult to identify, which greatly reduces exploration risks. Taff said traditional geothermal energy developers face difficulties because they need to find three things underground: heat, water, and high-permeability formations. “The challenge is the exploration risk, or in other words, finding the resource where you’ve got the heat, the large body of water deep in the earth, as well as the permeability,” she said. “In hot dry rock geothermal, which is what we’re targeting, you’re looking only for that heat. We want a low-permeability formation, but again, that’s very prevalent.” Sage is now in the process of commissioning its first commercial energy storage project in Texas. “We’re testing the piping, and we’re function testing the generator and the Pelton turbine, so we’ll be operating that facility here in the next few weeks,” Taff said. Meanwhile, the company has also signed an agreement with the California Resources Corporation to establish a collaborative framework for pursuing commercial projects and joint funding opportunities related to subsurface energy storage and geothermal power generation in California. It also has ongoing district heating projects in Lithuania and Romania, and Taff said the U.S. Department of Defense has shown a lot of interest in the company’s geothermal technology. Additionally, Meta signed a contract for a 150-MW geothermal power generation system to supply one of its data centers.
Imagine a field of solar panels floating silently in the endless day of Earth’s orbit. Unlike their terrestrial cousins, this space-based solar array never faces nighttime, clouds, or atmospheric interference. Instead, they bathe in constant, intense sunlight, converting this endless stream of energy into electricity with remarkable efficiency.But the true innovation lies in how this power is transmitted to power grids on Earth. The electricity generated in space is converted into invisible beams of microwaves or laser light that pierce through the atmosphere with minimal losses. These beams are precisely aimed at receiving stations on Earth—collections of antennas or receivers known as “rectennas” that capture and reconvert the energy back into electricity that can be supplied to the power grid.This isn’t science fiction—it’s space-based solar power (SBSP), a technology that could revolutionize how clean energy is generated and distributed. While conventional solar panels on Earth can only produce power during daylight hours and are at the mercy of weather conditions, orbital solar arrays could beam massive amounts of clean energy to Earth 24 hours a day, 365 days a year, potentially transforming the global energy landscape.
Power grids operate like an intricate ballet of energy generation and consumption that must remain perfectly balanced at all times. The grid maintains a steady frequency (60 Hz in North America and 50 Hz in many other regions) by matching power generation to demand in real-time. Traditional power plants with large rotating turbines and generators play a crucial role in this balance through their mechanical inertia—the natural tendency of these massive spinning machines to resist changes in their rotational speed.This inertia acts as a natural stabilizer for the grid. When there’s a sudden change in power demand or generation, such as a large factory turning on or a generator failing, the rotational energy stored in these spinning masses automatically helps cushion the impact. The machines momentarily speed up or slow down slightly, giving grid operators precious seconds to respond and adjust other power sources.However, as we transition to renewable energy sources like solar and wind that don’t have this natural mechanical inertia, maintaining grid stability becomes more challenging. This is why grid operators are increasingly focusing on technologies like synthetic inertia from wind turbines, battery storage systems, and advanced control systems to replicate the stabilizing effects traditionally provided by conventional power plants.Alex Boyd, CEO of PSC, a global specialist consulting firm working in the areas of power systems and control systems engineering, believes the importance of inertia will lessen, and probably sooner than most people think. In fact, he suggested stability based on physical inertia will soon be the least-preferred approach. Boyd recognizes that his view, which was expressed while he was a guest on The POWER Podcast, is potentially controversial, but there is a sound basis behind his prediction.Power electronics-based systems utilize inverter-based resources, such as wind, solar, and batteries. These systems can detect and respond to frequency deviations almost instantaneously using fast frequency response mechanisms. This actually allows for much faster stabilization compared to mechanical inertia.Power electronics reduce the need for traditional inertia by enabling precise control of grid parameters like frequency and voltage. While they decrease the available physical inertia, they also decrease the amount of inertia required for stability through advanced control strategies. Virtual synchronous generators and advanced inverters can emulate inertia dynamically, offering tunable responses that adapt to grid conditions. For example, adaptive inertia schemes provide high initial inertia to absorb faults but reduce it over time to prevent oscillations.Power electronic systems address stability issues across a wide range of frequencies and timescales, including harmonic stability and voltage regulation. This is achieved through multi-timescale modeling and control techniques that are not possible with purely mechanical systems. Inverter-based resources allow for distributed coordination of grid services, such as frequency regulation and voltage support, enabling more decentralized grid operation compared to centralized inertia-centric systems. Power electronic systems are essential for grids with a high penetration of renewable energy sources, which lack inherent mechanical inertia. These systems ensure stability while facilitating the transition to low-carbon energy by emulating or replacing traditional generator functions.“I do foresee a time in the not-too-distant future where we’ll be thinking about how do we actually design a system so that we don’t need to be impacted so much by the physical inertia, because it’s preventing us from doing what we want to do,” said Boyd. “I think that time is coming. There will be a lot of challenges to overcome, and there’ll be a lot of learning that needs to be done, but I do think the time is coming.”
The rapid rise of data centers has put many power industry demand forecasters on edge. Some predict the power-hungry nature of the facilities will quickly create problems for utilities and the grid. ICIS, a data analytics provider, calculates that in 2024, demand from data centers in Europe accounted for 96 TWh, or 3.1% of total power demand. “Now, you could say it’s not a lot—3%—it’s just a marginal size, but I’m going to spice it up a bit with two additional layers,” Matteo Mazzoni, director of Energy Analytics at ICIS, said as a guest on The POWER Podcast. “One is: that power demand is very consolidated in just a small subset of countries. So, five countries account of over 60% of that European power demand. And within those five countries, which are the usual suspects in terms of Germany, France, the UK, Ireland, and Netherlands, half of that consumption is located in the FLAP-D market, which sounds like a fancy new coffee, but in reality is just five big cities: Frankfurt, London, Amsterdam, Paris, and Dublin.”Predicting where and how data center demand will grow in the future is challenging, however, especially when looking out more than a few years. “What we’ve tried to do with our research is to divide it into two main time frames,” Mazzoni explained. “The next three to five years, where we see our forecast being relatively accurate because we looked at the development of new data centers, where they are being built, and all the information that are currently available. And, then, what might happen past 2030, which is a little bit more uncertain given how fast technology is developing and all that is happening on the AI [artificial intelligence] front.”Based on its research, ICIS expects European data center power demand to grow 75% by 2030, to 168 TWh. “It’s going to be a lot of the same,” Mazzoni predicted. “So, those big centers—those big cities—are still set to attract most of the additional data center consumption, but we see the emergence of also new interesting markets, like the Nordics and to a certain extent also southern Europe with Iberia [especially Spain] being an interesting market.”Yet, there is still a fair amount of uncertainty around demand projections. Advances in liquid cooling methods will likely reduce data center power usage. That’s because liquid cooling offers more efficient heat dissipation, which translates directly into lower electricity consumption.Additionally, there are opportunities for further improvement in power usage effectiveness (PUE), which is a widely used data center energy efficiency metric. At the global level, the average PUE has decreased from 2.5 in 2007 to a current average of 1.56, according to the ICIS report. However, new facilities consistently achieve a PUE of 1.3 and sometimes much better. Google, which has many state-of-the-art and highly efficient data centers, reported a global average PUE of 1.09 for its facilities over the last year.Said Mazzoni, “An expert in the field told us when we were doing our research, when tech moves out of the equation and you have energy engineers stepping in, you start to see that a lot of efficiency improvements will come, and demand will inevitably fall.”Thus, data center load growth projections should be taken with a grain of salt. “The forecast that we have beyond 2030 will need to be revised,” Mazzoni predicted. “If we look at the history of the past 20 years—all analysts and all forecasts around load growth—they all overshoot what eventually happened. The first time it happened when the internet arrived—there was obviously great expectations—and then EVs, electric vehicles, and then heat pumps. But if we look at, for example, last year—2024—European power demand was up by 1.3%, U.S. power demand was up by 1.8%, and probably weather was the main driver behind that growth.”
District energy systems employ a centralized facility to supply heating, cooling, and sometimes electricity for multiple buildings in an area through a largely underground, mostly unseen network of pipes. When district energy systems are utilized, individual buildings do not need their own boilers, chillers, and cooling towers. This offers a number of benefits to building owners and tenants. Among them are:•Energy Efficiency. Centralized heating/cooling is more efficient than individual building systems, reducing energy use by 30% to 50% in some cases.•Cost Savings. Lower operations and maintenance costs through economies of scale and reduced equipment needs per building.•Reduced Environmental Impacts. Emissions are lessened and renewable energy resources can often be more easily integrated.•Reliability. A more resilient energy supply is often provided, with redundant systems and professional operation.•Space Optimization. Buildings need less mechanical equipment, freeing up valuable space.The concept is far from new. In fact, Birdsill Holly is credited with deploying the U.S.’s first district energy system in Lockport, New York, in 1877, and many other cities incorporated district systems into their infrastructure soon thereafter. While district energy systems are particularly effective in dense urban areas, they’re also widely used at hospitals and at other large campuses around the world.“There’s over 600 operating district energy systems in the U.S., and that’s in cities, also on college and university campuses, healthcare, military bases, airports, pharma, even our sort of newer industries like Meta, Apple, Google, their campuses are utilizing district energy, because, frankly, there’s economies of scale,” Rob Thornton, president and CEO of the International District Energy Association (IDEA), said as a guest on The POWER Podcast.“District energy is actually quite ubiquitous,” said Thornton, noting that systems are common in Canada, throughout Europe, in the Middle East, and many other parts of the world. “But, you know, not that well-known. We’re not visible. Basically, the assets are largely underground, and so we don’t necessarily have the visibility opportunity of like wind turbines or solar panels,” he said. “So, we quietly do our work. But, I would guess that for the listeners of this podcast, if they went to a college or university in North America, I bet, eight out of 10 lived in a dorm that was supplied by a district heating system. So, it’s really a lot more common than people realize,” said Thornton.
Most POWER readers are probably familiar with levelized cost of energy (LCOE) and levelized value of energy (LVOE) as metrics used to help evaluate potential power plant investment options. LCOE measures the average net present cost of electricity generation over a facility’s lifetime. It includes capital costs, fuel costs, operation and maintenance (O&M) costs, financing costs, expected capacity factor, and project lifetime. Meanwhile, LVOE goes beyond LCOE by considering the actual value the power provides to the grid, including time of generation (peak vs. off-peak), location value, grid integration costs and benefits, contributions to system reliability, environmental attributes, and capacity value.Some of the key differences stem from the perspective and market context each provides. LCOE, for example, focuses on pure cost comparison between technologies, while LVOE evaluates actual worth to the power system. Notably, LCOE ignores when and where power is generated; whereas, LVOE accounts for temporal and locational value variations. Concerning system integration, LCOE treats all generation as equally valuable, while LVOE considers grid integration costs and system needs.“Things like levelized cost of energy or capacity factors are probably the wrong measure to use in many of these markets,” Karl Meeusen, director of Markets, Legislative, and Regulatory Policy with Wärtsilä North America, said as a guest on The POWER Podcast. “Instead, I think one of the better metrics to start looking at and using more deeply is what we call the levelized value of energy, and that’s really looking at what the prices at the location where you’re trying to build that resource are going to be.”Wärtsilä is a company headquartered in Finland that provides innovative technologies and lifecycle solutions for the marine and energy markets. Among its main offerings are reciprocating engines that can operate on a variety of fuels for use in electric power generating plants. Wärtsilä has modeled different power systems in almost 200 markets around the world. It says the data consistently shows that a small number of grid-balancing gas engines in a system can provide the balancing and flexibility to enable renewables to flourish—all while maintaining reliable, resilient, and affordable electricity. Meeusen noted that a lot of the models find engines offer greater value than other technologies on the system because of their flexibility, even though they may operate at lower capacity factors. Having the ability to turn on and off allows owners to capture high price intervals, where prices spike because of scarcity or ramp shortages, while avoiding negative prices by turning off as prices start to dip and drop lower. “That levelized value is one of the things that we think is really important going forward,” he said.“I think what a lot of models and planning scenarios miss when they look at something like LCOE—and they’re looking at a single resource added into the system—is how it fits within the system, and what does it do to the value of the rest of their portfolio?” Meeusen explained. “I call this: thinking about the cannibalistic costs. If I look at an LCOE with a capacity factor for a combined cycle resource, and don’t consider how that might impact or increase the curtailment of renewable energy—no cost renewable energy—I don’t really necessarily see the true cost of some of those larger, inflexible generators on the system. And, so, when we think about that, we really want to make sure that what we’re covering and capturing is the true value that a generator has in a portfolio, not just as a standalone resource.”
Steam is used for a wide variety of critical processes across many industrial sectors. For example, pulp and paper facilities use steam to power paper machines, dry paper and wood products, and provide heat for chemical recovery processes. Steam is used by metal and mining companies, as well as in the food and beverage industry, petroleum refining, pharmaceutical manufacturing, textile production, and many other industrial processes.“About 20% of global carbon emissions come from the industrial heat sector, and virtually all of that industrial heat today is produced by burning hydrocarbons—coal and natural gas—and emitting carbon into the atmosphere,” Clay Sell, CEO of X-energy, said as a guest on The POWER Podcast. “With our technology, we have the opportunity to replace hydrocarbons and use nuclear-generated carbon-free steam to dramatically decarbonize these so-called hard-to-decarbonize sectors.”X-energy is a nuclear reactor and fuel design engineering company. It is developing Generation-IV high-temperature gas-cooled nuclear reactors and what’s known as TRISO-X fuel to power them. The company’s Xe-100 small modular reactor (SMR) is an 80-MWe reactor that can be scaled into a four-pack (320-MWe power plant) that can grow even larger as needed. “The most significant advantages that we have over large-scale traditional nuclear power plants is the evolution of our technology, our safety case, and the smaller, more simplified designs that can be built with much less time and much less money,” Sell said. “We’re a high-temperature gas-cooled reactor using a TRISO fuel form—that’s ceramic, encapsulated fuel in a round pebble that flows through the reactor like gumballs through a gumball machine.”The Xe-100 design’s intrinsic safety makes it especially unique. “This is a plant that cannot melt down under any scenario that one could imagine affecting the plant. So, that extraordinary safety case allows us to operate on a very small footprint,” said Sell. The simplified design has fewer subsystems and components, less concrete, less steel, and less equipment than traditional nuclear power plants. As noted previously, X-energy’s SMR is capable of producing high-quality steam, which is especially attractive for use in industrial processes. As such, Dow Inc., one of the world’s leading materials science companies, has agreed to deploy the first Xe-100 unit at its Union Carbide Corp. Seadrift Operations, a sprawling chemical materials manufacturing site in Seadrift, Calhoun County, Texas. “Our first project is going to be deployed in a public-private partnership with the U.S. government and Dow Inc., the large chemical manufacturer, at a site southwest of Houston, Texas, that will come online around the end of this decade,” Sell reported.Currently, X-energy is in the final stages of its design effort. Once complete, the next step will be to submit a construction permit application to the Nuclear Regulatory Commission (NRC). If all goes according to plan, the application should be approved by the NRC in early 2027, which would allow construction to start around that time. “We anticipate construction on the plant to be about a three- to three-and-a-half-year process, which will then bring it online in the early 2030s,” Sell explained.Beyond that, X-energy has an agreement to supply Amazon with 5 GW of new SMR projects (64 units) by 2039, starting with an initial four-unit 320-MWe Xe-100 plant with regional utility Energy Northwest in central Washington. Sell believes the deal positions X-energy to quickly apply lessons learned from its first-of-a-kind project with Dow, replicate and repeat the effort to achieve scale, and reach a favorable nth-of-a-kind cost structure faster than anyone else in the SMR market today.Said Sell, “When we imagine a future of a decarbonized economy with reliable power supporting dramatic growth at a reasonable cost, I believe X-energy is going to be a central technology to that future.”
Hydrogen is becoming increasingly important to the electric power generation industry for several reasons.One is that hydrogen offers a promising pathway to decarbonize the power sector. When used in fuel cells or burned for electricity generation, hydrogen produces only water vapor as a byproduct, making it a zero-emission energy source. This is crucial for meeting global climate change mitigation goals and reducing greenhouse gas emissions from power generation.Hydrogen also provides a potential energy storage solution, which is critical for integrating solar and wind energy into the power grid. These renewable resources are intermittent—sometimes they produce more energy than is needed by the grid, while at other times, they may completely go away. Hydrogen can be produced through electrolysis during periods of excess renewable energy production, then stored and used to generate electricity when needed. This helps address the challenge of matching energy supply with demand.Hydrogen is a flexible and versatile fuel that can be used in fuel cells, gas turbines, or internal combustion engines. It can also be blended with natural gas to accommodate existing equipment limitations. The wide range of options make hydrogen a great backup fuel for microgrids and other systems that require excellent reliability.“We’ve actually seen quite a bit of interest in that,” Tim Lebrecht, industry manager for Energy Transition and the Chemicals Process Industries with Air Products, said as a guest on The POWER Podcast. Lebrecht noted that hydrogen can be a primary use in microgrids, or used as a source of backup or supplement.“Think of a peaking unit that as temperature goes up during the day, your pricing for power could also be going up,” Lebrecht explained. “At a point, hydrogen may be a peak shave–type situation, where you then maximize the power from the grid, but then you’re using hydrogen as a supplement during that time period.”Another hydrogen use case revolves around data centers. “Data centers, specifically, have been really interested in: ‘How do we use hydrogen as a backup type material?’ ” Lebrecht said. Air Products is the world’s leading supplier of hydrogen with more than 65 years of experience in hydrogen production, storage, distribution, and dispensing. Lebrecht noted that his team regularly works with original equipment manufacturers (OEMs); engineering, procurement, and construction (EPC) companies; and other firms to collaborate on solutions involving hydrogen. “We’ve got a great history,” he said. “My team has a great amount of experience.”
Power plant construction and retrofit projects come in all shapes and sizes, but they all generally have at least one thing in common: complexity. There are usually a lot of moving pieces that must be managed. This can include sourcing the right materials and components, getting equipment delivered to the site at the right time, finding qualified contractors, and overseeing handoffs between working groups. Getting a job done on time and on budget is not as easy as some people might think.“It absolutely can be difficult and a lot of things to consider,” Kevin Slepicka, vice president of Sales for Heat Recovery Boilers at Rentech Boiler Systems, said as a guest on The POWER Podcast. “You’ve got to make sure that communication is ongoing between your suppliers and the end user.”Rentech is a leading manufacturer of boiler systems including package boilers, waste heat boilers, and heat recovery steam generators (HRSGs). Rentech’s fabrication facilities are in Abilene, Texas. “We have three shops,” Slepicka explained. “There’s 197,000 square feet of manufacturing space under roof. We’ve got over 100 tons of lift capability with cranes, and we can bring in other cranes for our heavier lifts. Our properties are located on 72 acres, so we have a lot of room for staging equipment, storing equipment, if customers aren’t ready to take delivery at the time the units are done.”Moving large boilers from Texas to sites around the country and other parts of the world can be difficult, which is another reason why good communication is imperative. “Shipping is a major consideration on how the unit is constructed, how much is going to be built in the facility, and how large we can ship. So, it really goes hand in hand with the design of the boiler,” Slepicka said. “It really is important that we work with our logistics people and work with our partner companies that do our transportation for us.”Communication with customers on potential future needs is also important. Slepicka said knowing that a retrofit may be required down the road to account for a new environmental regulation, for example, could allow a boiler system to be designed with space to accommodate changes. This could save a lot of money and headaches in the long run. “That’s where you’ve got to be able to work with the customer—make sure you understand the space available and make sure that the unit’s going to work properly,” he said.Slepicka said Rentech had a customer recently that faced new formaldehyde restrictions and needed its HRSG system modified. “Luckily, we had the space in the unit where that catalyst could be installed in the right location to address the concern they had, so it was a relatively easy retrofit for them to make.” If the prospect had not been considered up front, the cost and complexity could have been much greater.
On Dec. 22, 2008, a major dike failure occurred on the north slopes of the ash pond at the Tennessee Valley Authority’s (TVA’s) Kingston Fossil Plant. The failure resulted in the release of approximately 5.4 million cubic yards of coal ash spilling onto adjacent land and into the Emory River.The Kingston spill is considered one of the most significant and costly events in TVA history. In a project completion fact sheet issued jointly by the U.S. Environmental Protection Agency (EPA) and the TVA in December 2014, it says the cleanup took about six years, required a total of 6.7 million man-hours, and cost $1.178 billion. TVA hired various contractors to perform the post-spill cleanup, removal, and recovery of fly ash at the Kingston site. Perhaps most notable among them was Jacobs Engineering. TVA hired Jacobs in 2009 specifically to provide program management services to assist with the cleanup.Jacobs claims to have “a strong track record of safely managing some of the world’s most complex engineering and environmental challenges.” It has noted that TVA and the EPA’s on-scene coordinator oversaw the worker safety programs for the Kingston cleanup, approving all actions in consultation with the Tennessee Department of Environment and Conservation. Jacobs said TVA maintained rigorous safety standards throughout the cleanup, and that it worked closely with TVA in following and supporting those standards.Jared Sullivan, author of Valley So Low: One Lawyer’s Fight for Justice in the Wake of America’s Great Coal Catastrophe, studied the Kingston cleanup and followed some of the plaintiffs for more than five years while writing his book. As a guest on The POWER Podcast, Sullivan suggested many of the workers felt fortunate to be employed on the Kingston cleanup. The U.S. economy was not thriving at the time; housing and stock markets were in a funk, and unemployment was relatively high.“These workers—these 900 men and women—this disaster is kind of a godsend for them as far as their employment goes, you know. A lot of them needed work. Many of them were very, very pleased to get this call,” Sullivan explained. “The trouble is that after a year or so of working on this job site—of scooping up and hauling off this coal ash muck from the landscape, also from the river—they start feeling really, really terribly,” he said.“At first they kind of write off their symptoms as overworking themselves. In many cases, these workers were working 14-hour shifts and just pushing themselves really, really hard because there’s a lot of overtime opportunities. So, that was good for them—that they could work so much, that this mess was so big,” Sullivan continued. But after a while, some workers start blacking out in their cars, having nosebleeds, start coughing up black mucous, and it becomes clear to them that the coal ash is the cause.Jacobs reports several contractors’ workers at the Kingston site filed workers compensation claims against their employer in 2013. These workers alleged that conditions at the site caused them to experience various health issues that were a result of excessive exposure to coal ash. Jacobs said many of these claims were found to be unsubstantiated and were rejected. Then, many of the same workers filed lawsuits against Jacobs, even though they may not have been Jacobs employees. Jacobs says it stands by its safety record, and that it did not cause any injuries to the workers.“The case resolved early last year, after almost 10 years of litigation,” Sullivan said. “Jacobs Engineering and the plaintiffs—230 of them—finally settled the case. $77.5 million dollars for 230 plaintiffs. So, it works out to a couple hundred thousand dollars each for the plaintiffs after the lawyers take their fees—so, not tons of money.” In a statement, Jacobs said, “To avoid further litigation, the parties chose to enter into an agreement to resolve the cases.”
You don’t need me to tell you how artificial intelligence (AI) is impacting the power grid; you can just ask AI. Claude, an AI assistant created by Anthropic, told POWER, “AI training and inference are driving unprecedented demand for data center capacity, particularly due to large language models and other compute-intensive AI workloads.” It also said, “AI servers, especially those with multiple GPUs [graphics processing units], require significantly more power per rack than traditional servers—often 2–4x higher power density.”So, what does that mean for power grid operators and electricity suppliers? Claude said there could be several effects, including local grid strain in AI hub regions, the need for upgraded transmission infrastructure, higher baseline power consumption, and potential grid stability issues in peak usage periods. Notably, it said AI data centers tend to cluster in specific regions with favorable power costs and regulations, creating “hotspots” of extreme power demand.Sheldon Kimber, founder and CEO of Intersect Power, a clean energy company that develops, owns, and operates a base portfolio of 2.2 GW of operating solar PV and 2.4 GWh of storage in operation or construction, understands the challenges data centers present for the grid. As a guest on The POWER Podcast, Kimber suggested the only way to meet the massive increase in power demand coming from data centers is with scalable behind-the-meter solutions.“These assets may still touch the grid—they may still have some reliance on the grid—but they’re going to have to bring with them an enormous amount of behind-the-meter generation and storage and other things to make sure that they are flexible enough that the grid can integrate them without creating such a strain on the grid, on rate payers, and on the utilities that service them,” Kimber said.Yet, data center developers have not traditionally kept power top-of-mind. “The data center market to date has been more of a real estate development game,” Kimber explained. “How close to a labor pool are you? What does it look like on the fiber side? What does the land look like?” He said electric power service was certainly part of the equation, but it was more like part of a “balanced breakfast of real estate criteria,” rather than a top priority for siting a data center. In today’s environment, that needs to change. Kimber said Intersect Power has been talking to data center companies for at least three years, pitching them on the idea of siting data centers behind-the-meter at some of his projects. The response has been lukewarm at best. Most of the companies want to keep their data centers in already well-established hubs, such as in northern Virginia; Santa Clara, California; or the Columbia River Gorge region in Oregon, for example. Kimber’s comeback has been, “Tell us when you’re ready to site for ‘Power First.’ ”What “Power First” means is simple. Start with power, and the availability of power, as the first criteria, and screen out all the sites that don’t have power. “To date, data center development that was not ‘Power First’ has really been focused on: ‘What does the plug look like?’ ” Kimber said. In other words: How is the developer connecting the data center to the power grid—or plugging in? The developers basically assumed that if they could get connected to the grid, the local utility would find a way to supply the electricity needed. However, it’s getting harder and harder for utilities to provide what developers are asking for. “The realization that the grid just isn’t going to be able to provide power in most of the places that people want it is now causing a lot of data center customers to re-evaluate the need to move from where they are. And when they’re making those moves, obviously, the first thing that’s coming to mind is: ‘Well, if I’m going to have to move anyway, I might as well move to where the binding constraint, which is power, is no longer a constraint,’ ” he said.
Microreactors are a class of very small modular reactors targeted for non-conventional nuclear markets. The U.S. Department of Energy (DOE) supports a variety of advanced reactor designs, including gas, liquid-metal, molten-salt, and heat-pipe-cooled concepts. In the U.S., microreactor developers are currently focused on designs that could be deployed as early as the mid-2020s.The key features of microreactors that distinguish them from other reactor types mainly revolve around their size. Microreactors typically produce less than 20 MW of thermal output. The size obviously allows a much smaller footprint than traditional nuclear power reactors. It also allows for factory fabrication and easier transportability. Among other unique aspects are their self-regulating capability, which could enable remote and semi-autonomous microreactor operation. Their rapid deployability (weeks or months rather than many years) is a huge benefit, too, allowing units to be used in emergency response and other time-sensitive situations. Furthermore, some designs are expected to operate for up to 10 years or more without refueling or significant maintenance, which could be a big benefit in remote locations.A lot of microreactor development work is being done at the Idaho National Laboratory (INL). John H. Jackson, National Technical Director for the DOE’s Office of Nuclear Energy Microreactor program at INL, was a recent guest on The POWER Podcast. On the show, he noted some of the programs and facilities INL has available to assist in proving microreactor concepts.“I like to say it starts with my program, because I’m overtly focused on enabling and accelerating commercial development and deployment of microreactor technology,” Jackson said. “But there are certainly the entities like the National Reactor Innovation Center, or NRIC, which is heavily focused on deployment and enabling deployment of microreactor technology, as well as small modular reactor technology.”POWER has reported extensively on the Pele and MARVEL microreactor projects. Project Pele is a Department of Defense (DOD) project that recently broke ground at INL. Meanwhile, MARVEL, which stands for Microreactor Applications Research Validation and EvaLuation, is funded through the DOE by the Office of Nuclear Energy’s Microreactor program.Project Pele aims to build and demonstrate a high-temperature gas-cooled mobile microreactor manufactured by Lynchburg, Virginia–headquartered BWXT Advanced Technologies. Fueled with TRI-structural ISOtropic particle fuel, Project Pele will produce 1 MWe to 5 MWe for INL’s Critical Infrastructure Test Range Complex (CITRC) electrical test grid. The DOD noted last month that assembly of the final Pele reactor is scheduled to begin in February 2025, and the current plan is to transport the fully assembled reactor to INL in 2026.The MARVEL design is a sodium-potassium-cooled microreactor that will be built inside the Transient Reactor Test (TREAT) facility at INL. It will generate 85 kW of thermal energy and about 20 kW of electrical output. It is not intended to be a commercial design, but the experience of constructing and operating the unit could be crucial for future microreactor developers and microgrid designers, as future plans are to connect it to a microgrid.“The MARVEL reactor is one of the top priorities, if not the top priority, at the Idaho National Laboratory, along with the project Pele,” Jackson said. “One or the other—Pele or MARVEL—will be the first reactor built at Idaho National Laboratory in over 50 years.”Still, Jackson was cautious when it came to predicting when the first microreactor might begin operation. “I cringe sometimes when people get a little ahead of themselves and start making bold declarations, like, ‘We’re going to have a microreactor next year,’ for instance. I think it’s important to be excited, but it’s also important to stay realistic with respect to timeframes for deployment,” he said.
The domestic content bonus credit is available to taxpayers that certify their qualified facility, energy project, or energy storage technology was built with certain percentages of steel, iron, or manufactured products that were mined, produced, or manufactured in the U.S.“What we’ve seen happen is just a proliferation of investments into U.S. domestic manufacturing,” Mike Hall, CEO of Anza Renewables, said as a guest on The POWER Podcast. Hall said U.S. manufacturers started with the easiest and probably lowest-risk investment in the supply chain, which is module assembly. “You could count on one hand the number of U.S. module options just a couple of years ago,” he said. “Today, I was actually looking at our database, and if you were looking to take delivery in late-2025, there are 17 different manufacturers that are willing to sign POs [purchase orders] today to supply domestically made modules.”Hall suggested most developers that are looking to utilize domestic supplies are trying to solve one or two problems. “Either they’re trying to mitigate trade risk—AD/CVD [anti-dumping and countervailing duty] risk—from the various petitions, or risk around detainment by customs due to concerns around UFLPA [Uyghur Forced Labor Prevention Act] violations,” explained Hall. “So, that’s one potential problem that customers are trying to solve, and a domestically made module may really help solve that problem,” he said. “The other thing, though, that we increasingly see developers looking to do is to try and access the extra 10% tax credit that you can get if you meet certain minimum standards for domestically manufactured content,” Hall continued. For solar projects, that generally means a domestically manufactured solar cell is needed. “A few years ago, again, there were one, maybe two options for that,” Hall noted. “There’s still only a few—we see those options growing over time—but if you’re looking at late-2025 deliveries, there’s four to five viable options of companies that will actually issue POs today for domestically manufactured cells. So, overall, we’re definitely seeing more and more options come to the market, and that’s really exciting.”Yet, aside from domestic content, the options available on the market have never been greater than today. “There are more manufacturers selling into the market,” said Hall. “On Anza, we have coverage of 95% of the U.S. supply, and that requires us to have relationships—partnerships in the data pipeline—with over 33 different suppliers. So, if you’re doing a mid- or large-scale project, there’s over 120 different products that you should be considering. And, so, navigating that, and finding the module or the handful of modules that are actually going to deliver an optimal financial outcome is a big challenge.”Hall suggested maximizing project economics requires having a sound view of the market. Then, developers must compare products, accounting for cost to install, predicted energy production, the value of the energy, and particular project risks and priorities. “One of the things we help developers do is really understand: what is the value in dollars per watt of efficiency and the value for their particular project,” explained Hall. “And that value differs. If you’ve got a community solar project with a really high priced PPA [power purchase agreement], then efficiency is worth a whole lot. If you’ve got a really low dollar-per-megawatt-hour utility-scale PPA, then efficiency is still worth something, but it might be worth less.”Projecting the longevity of products can be difficult, but Anza tries to factor that in using warranty information. If different manufacturers warranty their equipment for different lengths of time, that can be incorporated into financial models and will impact outcomes.
A new U.S. president will be inaugurated in less than five months. Polls show the race between Donald Trump and Kamala Harris to be very close, with potentially only a few swing states deciding the election. While energy policy may not be a deciding factor for many Americans in choosing who they will vote for, it is very important to power industry professionals.With that in mind, Mary Anne Sullivan, senior counsel with the law firm Hogan Lovells, and Megan Ridley-Kaye, a partner with Hogan Lovells, were interviewed as guests on The POWER Podcast to discuss how the candidates might differ in their areas of focus after the election. Among the most pronounced differences is the rhetoric the two might espouse.“A Trump administration, I think, would talk a lot more about energy security, energy independence, and the need to be friendly to American-made fossil fuels,” Sullivan said. “A Harris administration, I assume, will follow in the footsteps of the Biden administration and focus on the need to respond to climate change and build on what have truly been unprecedented accomplishments under the Infrastructure Investment and Jobs Act and the IRA [Inflation Reduction Act],” she said.Although a Trump administration might seek to repeal all or at least parts of the IRA, Sullivan thought that would be hard to achieve. “I think recent indications are that it [the IRA] has now a fair bit of support in Congress,” she said. Ridley-Kaye agreed. “Obviously, key to what happens there [the fate of the IRA] is what happens in Congress,” she said. “It seems increasingly unlikely that it will be repealed.”And, while the government has made major investments that support energy and power projects, private parties have invested a lot of money too. At this point in the cycle, however, Ridley-Kaye suggested some of her clients are beginning to take a wait-and-see approach, especially if project economics are not viable without tax credits. Still, many other investors are unworried about the possibility of policy changes. “We do have a large group of clients that would say, ‘The train has left the station. Corporate America expects the tax credits. There’s no way that they would be taken away,’ ” Ridley-Kaye said.Meanwhile, there are some areas where the candidates may see eye to eye. “No matter which of them is elected, I think they will both recognize the need for more power transmission and more power generation,” said Sullivan. “Although the Biden administration has talked a good game about greening power generation, they have also very much pursued an all-of-the-above approach to generation resources. And I would expect that to continue in a Harris administration, just because there are so many new demands for electricity—the data centers, AI [artificial intelligence], vehicle electrification, the sort of ‘electrify everything’ movement that some people talk about,” she said.Two other areas where Trump and Harris might support similar policies are on nuclear power, and carbon capture and storage. “The two administrations might have different motivations for pursuing that, but I think either one will support further technology development there,” Sullivan supposed.Sullivan would expect a more light-handed approach to regulation under a Trump administration, specifically, as applied to permitting energy infrastructure projects. “But that more light-handed regulation on permitting helps the carbon-free power projects as much as the carbon-intensive power projects. It cuts both ways,” she said.Depending on how the election plays out, the energy and power landscape could change very quickly. “Trump’s team seems much more ready to move on policy than it did when he ran the last time. I think they’re thinking about it in advance. They’re building a desired set of policies,” Sullivan said. “I do expect them to be more ready to move on their policy objectives.”
Fuel cells are not some novel new technology. In fact, most history books credit the invention of the fuel cell to Welsh chemist and physicist William Grove, who, in the late 1830s and early 1840s, conducted experiments proving that electric current could be produced from an electrochemical reaction between hydrogen and oxygen over a platinum catalyst.Yet, fuel cells never really took off as a mainstream source of power. Why is that? “I think the real reason is, historically, we’ve been comfortable with less-clean, lower-efficient but less-expensive technologies, because we haven’t been as focused on air quality and on decarbonization as we currently are,” Tony Leo, executive vice president and Chief Technology Officer with FuelCell Energy, said as a guest on The POWER Podcast. However, as people have become more focused on air quality and climate change, Leo suggested fuel cells are now poised to take off. “That’s why you’re seeing such an acceleration in the deployment of fuel cells and that’s why you’re hearing more and more about them these days,” he said.A fuel cell is a device that makes electricity from fuel and air. Instead of burning the fuel to make heat to drive a mechanical generator, fuel cells react the fuel and air electrochemically, without combustion. The electrochemical approach avoids pollutants that are created by high flame temperatures, and it is a more direct and efficient way to make power from a fuel.Reacting fuel and air electrochemically involves delivering fuel to a set of negative electrodes (called anodes) and delivering air to a set of positive electrodes (called cathodes). The electrochemical reaction of fuel produces electrons. The electrochemical reaction of oxygen in air consumes electrons. Connecting the two produces the current of usable electrical power.Fuel cells are configured in stacks of individual cells connected in a series. FuelCell Energy’s carbonate stacks have up to 400 cells per stack and produce between 250 kW and 400 kW of power. FuelCell Energy’s standard MW-scale module contains four stacks, nets about 1.4 MW of power, and can make electricity for sites such as universities, hospitals, and data centers. The modular design of fuel cell plants allows them to scale up to a specific site’s energy needs.“One big advantage is they’re quiet,” said Leo. “Since they don’t have a big spinning machine and this big spinning generator, they’re quiet compared to traditional power generation, so you can site them in population centers. We have a 15-MW fuel cell right in the middle of downtown Bridgeport, Connecticut, for example, and that just makes a really good neighbor.” The lack of harmful emissions is also a benefit. Another advantage is that while fuel cells are making electricity, they’re also making heat that can be used to produce hot water or steam, or to drive chilling operations. “That further enhances the sustainability because you get to avoid burning fuel in a boiler, for example, if you can use the heat coming off the fuel cell,” said Leo.Additionally, fuel cells don’t require a lot of maintenance or a large operations staff. “They’re unmanned—we monitor them remotely—and so, they take care of themselves and just generate value,” Leo explained.
Former U.S. Sen. Mary Landrieu (D-La.), who is now a senior policy advisor for the law firm Van Ness Feldman and co-chair of the Natural Allies Leadership Council, is keen on natural gas and believes it is part of the solution to reaching both domestic and global climate goals.“Natural gas in America is not the enemy,” Landrieu said as a guest on The POWER Podcast. “The majority of the emissions reductions of the United States in the last 10 years are directly attributed to more natural gas being used and less coal,” she said.Yet, that doesn’t mean Landrieu is opposed to renewable energy. She believes in an “all-of-the-above” strategy. “As natural gas has replaced coal as the number one producer of electricity in this country, our emissions have been reduced substantially, that is, in addition and in collaboration with—in partnership with—the increase in wind [and] the increase in solar,” said Landrieu.There are many reasons to support natural gas, according to Landrieu. For one, America has a lot of it. “We have over a hundred-year supply,” she claimed. “Number two: we have an amazing pipeline infrastructure that can move gas from where we find it to the people that need it,” she added. “But also, what’s so important is natural gas, because it’s relatively inexpensive, we can keep the cost of electricity lower. So, it’s available, it’s plentiful, it’s affordable, and when connected with wind and solar, we can really build a modern and low-emissions electric grid for the country.”Landrieu has a sound basis for her views, having served three terms in the U.S. Senate (1997–2015) where she chaired the prominent Senate Energy and Natural Resources Committee and she advocated for her home state of Louisiana, which is America’s fourth-largest energy-producing state. Still, Landrieu pushes back when people suggest she only promotes natural gas because Louisiana produces it. “No, I promote natural gas because we produce it, but we also use a lot of it. So, my goal is to keep it plentiful [and] keep the price low and stable,” she said.Another form of energy that Landrieu supports is nuclear power. “Although our coalition doesn’t promote nuclear, we recognize the power of nuclear power. We want to see more nuclear power in this country,” she said. “Nuclear provides about 18% of our electricity—it was about 20—if we could get that up to 25 or even 30%, it would really help. Natural gas can provide a lot, more wind, more solar, and as batteries come along, that’s going to be, I think, the combination we’re looking for.”The Natural Allies Leadership Council calls itself “a coalition of interested stakeholders that recognize the vital role natural gas and its infrastructure must play in the energy mix.” The group says natural gas partnered with renewable energy “can accelerate our path to a clean energy future—ensuring affordability and reliability while reducing carbon emissions domestically and internationally.” Landrieu co-chairs the group with Kendrick Meek (D-Fla.), who served southern Florida in Congress from 2002 to 2010; Michael Nutter, who served as Philadelphia’s 98th Mayor from 2008 to 2016; and Tim Ryan (D-Ohio), who served 10 terms in Congress from 2003 to 2023. “We’re talking to Democrats—we’re happy always to talk with Republicans as well—but we’re talking to Democratic leaders and saying, ‘If you want prices low, if you want your people employed, if you want jobs in your community, natural gas is for you.’ And we’re happy to partner with renewables, nuclear, batteries, and let’s build a future together,” said Landrieu.
In 2018, Cooperative Energy, a generation and transmission co-op headquartered in Hattiesburg, Mississippi, had an issue to deal with. Several years earlier, it had joined the Midcontinent Independent System Operator (MISO), giving the power provider access to a competitive market. However, Cooperative Energy’s R.D. Morrow Sr. Generating Station, a 400-MW two-unit coal-fired facility that had opened about 40 years earlier, was not being dispatched as the co-op would have liked. In fact, the facility’s capacity factor in those days was running at only about 3%.“We could not compete in the MISO market due to the cost of the unit, the lack of flexibility, [and] startup time—when you’re bidding the unit into a day-ahead market, a 42-hour startup time is not a good place to be,” Mark Smith, senior vice president of Power Generation with Cooperative Energy, explained as a guest on The POWER Podcast. Smith continued: “We had high transportation costs. Our coal came in by rail and the route from the mine to the plant was roughly 440 miles one way. So, the transportation cost was excessive. Environmental regulations—the goal post seems to keep moving and things keep ratcheting down—we didn’t know where we were heading. At the point that we did decommission, we were well within compliance, but the future was uncertain. It was going to require a lot of capital investment in the coal unit.”With that as a backdrop, Cooperative Energy made the decision to build a new gas-fired unit to take the place of the coal units. Cooperative Energy took a somewhat unconventional approach for the project, utilizing many of its own people to manage the job, rather than opting for a turnkey EPC (engineering, procurement, and construction) contractor. “There were several reasons for us to choose what we call the multi-contract approach, as opposed to utilizing an EPC contractor,” Trey Cannon, director of Generation Projects with Cooperative Energy, said on the podcast. “Probably the one that was most important to us is just having that full transparency and full control of the entire project, including technology selections and equipment procurement, selection of construction contractors, and things of that nature,” Cannon explained. There was also a cost savings involved. “We estimated that we probably saved at least 15% on the total budget by utilizing the self-build self-manage approach,” said Cannon. The results were phenomenal. The project finished well ahead of schedule and well under budget. Yet, Cannon admitted that a lot of the savings was due to circumstances. “The market conditions and the timing of the project couldn’t have been better,” he said.The market for power plants in 2018 was down, so Cooperative Energy was able to get very competitive pricing on the gas turbine and a lot of other equipment. As construction work kicked into full swing in 2020, the market took another dip with COVID and other factors pushing projects to the back burner. Cooperative Energy, however, pressed on and was able to cherry pick the best contractors and the best workers. To underscore how the project benefited from the quality of personnel it was able to attract, Smith noted, “The weld rejection rate for our mechanical contractor was 0.41%, which was remarkable.”Today, the repowered Morrow plant is the heavy-load-carrying unit in Cooperative Energy’s fleet. “Since we went commercial, I think we’re carrying a 90-plus-percent capacity factor on the unit,” said Cannon.“If it’s not the most-efficient plant in MISO South, it’s very close,” added Smith. “And, needless to say, if the unit is available—we’re not in a planned outage—it’s operating and it’s typically baseloaded. In MISO, the name of the game is flexibility, efficiency, and reliability. The Morrow repower has checked all of those boxes for us and has Cooperative Energy in a great position for many years to come.”
Nuclear power has consistently provided about 19% to 20% of total annual U.S. electricity generation since 1990. It provides significant amounts of electricity in many other countries as well. According to data from The World Nuclear Industry Status Report (WNISR), a total of 414 reactors were operating in 32 countries, as of July 1, 2024. Preliminary data says China generated the second-most electricity from nuclear power in 2023 (behind the U.S.), while France came in third and had the highest percentage share of national power generation from nuclear power at 65%.Many power industry experts and environmental activists consider nuclear power an important component in the world’s transition to carbon-free energy. Yet, Mycle Schneider, an independent international analyst on energy and nuclear policy, and coordinator, editor, and publisher of the annual WNISR, said, “in [new] capacity terms, the nuclear industry, from what is going on, on the ground, is totally irrelevant.”Schneider was speaking as a guest on The POWER Podcast and prefaced his statement by comparing nuclear power additions to solar power additions in recent years. “Let’s look at China, because China is the only country that has been massively building nuclear power plants over the past 20 years,” he said. “China connected one reactor to the grid in 2023—one gigawatt. In the same year, they connected, and the numbers vary, but over 200 gigawatts of solar alone. Solar power generates more electricity in China than nuclear power since 2022. And, of course, wind power generates more than nuclear power in China for a decade already,” Schneider said. Furthermore, he noted, the disparity has gone “completely unnoticed by the general public or even within the energy professionals that are in Europe or often also in North America.”Schneider said the media often gives the impression that the nuclear industry is booming, but the facts suggest otherwise. “Over the past 20 years—2004 to 2023—104 reactors were closed down and 102 started up,” Schneider said. “But here is important that almost half, 49 of those new reactors started, were in China [where none closed], so the balance outside China is minus 51.”Some nuclear advocates might suggest that things are changing. They might argue that small modular reactors (SMRs) or other advanced designs are poised to reinvigorate the industry. But Schneider disagrees. He noted that since the construction start of the second unit at Hinkley Point C in the UK in 2019—almost five years ago—there have been 35 nuclear project construction starts in the world. Twenty-two of those were in China and the other 13 were all implemented by the Russian nuclear industry in a few different countries. “Nothing else. Not an SMR here or an SMR there, or a large reactor here or a large reactor there by any other player,” reported Schneider.Schneider noted that the vast majority of new capacity being added to the grid is from solar and wind energy. “These guys are building tens of thousands of wind turbines, and literally hundreds of millions of solar cells, so the learning effect is just absolutely stunning,” he said. “On the nuclear side, we’re talking about a handful. That’s very difficult. Very, very difficult—very challenging—to have a learning effect with so few units.”Schneider said the nuclear discussion in general needs a “really thorough reality check.” He suggested the possibilities and feasibilities must be investigated. “Then, choices can be made on a solid basis,” he said.
The U.S. Energy Information Administration (EIA) reports SAIDI and SAIFI values in its Electric Power Annual report, which is regularly released in October each year. In the most recent report, the U.S. distribution system’s average SAIDI value including all events was 335.5 minutes per customer in 2022. If major event days were excluded, which is often a worthwhile exercise to get accurate long-term trends because hurricanes and severe winter storms, for example, can skew the numbers quite dramatically in a given year, the figure dropped to 125.7 minutes per customer. Notably, this the highest SAIDI value tallied in the past decade and it continued what has effectively been a steady year-over-year decline in performance from 2013 through 2022. (2017 saw a brief improvement over 2016, but every year before and since has been worse than the previous year during the timespan covered by the report.) For comparison, in 2013, the SAIDI value was 106.1 minutes per customer.SAIFI values do not vary as noticeably as SAIDI, but still have been worsening. In 2022, the U.S. distribution system’s average SAIFI value including all events was 1.4 power interruptions per customer. With major events excluded, SAIFI was 1.1 interruptions per customer in the U.S. While this was not substantially worse than values reported in other years over the past decade (every year from 2013 onward has been 1.0, except for 2016 when the value was also 1.1), it seems to confirm that the system hasn’t been improving.Yet, Mike Edmonds, Chief Operating Officer for S&C Electric Company, said several things can be done to improve the reliability and resiliency of the power distribution system. “The grid looks different depending on what state you’re in,” Edmonds said as a guest on The POWER Podcast. “We’ve got great experience with Florida Power & Light [FPL],” he said. “We’ve helped them create a resilient grid. So, that’s not only a grid that is reliable, but a grid that can actually weather the storms and all the challenges thrown at the grid.”Notably, FPL reported in March that it had provided “the most reliable electric service in company history in 2023.” Over the past two decades, FPL said its customers have realized a remarkable 45% improvement in reliability. In NextEra Energy’s (the parent company of FPL) Sustainability Report 2023, the company reported FPL’s SAIDI was 47.1 and SAIFI was 0.85, confirming markedly better results than the U.S. averages noted earlier. Furthermore, FPL said this is the ninth time in the past 10 years that it achieved “its best-ever reliability rating.”To better understand some of the innovative new equipment S&C Electric Company offers, Edmonds provided an example. “We have some technology that does something called ‘pulse finding,’ and what Florida Power & Light does, it just lets our equipment do what it does best. If there’s a problem, it’ll pulse to see if the problem is there or not on the grid, if it’s not, it reenergizes,” he said. “This technology is available to really change how the grid operates.”Edmonds said S&C Electric Company invented the fuse 115 years ago, and he noted fuses have served the industry well since that time. However, today there is better technology available that doesn’t require a lineworker to respond to an outage to replace a fuse. “Let’s take fuses off the grid and have a fuseless grid, and have much more intelligent devices that can actually re-energize,” Edmonds decreed.
FBI Director Christopher Wray, while speaking at the Vanderbilt Summit on Modern Conflict and Emerging Threats in Nashville, Tennessee, in April, warned that U.S. critical infrastructure is a prime target of the Chinese government.“The fact is, the PRC’s [People’s Republic of China’s] targeting of our critical infrastructure is both broad and unrelenting,” he said. Wray also noted that the immense size and expanding nature of the Chinese Communist Party’s hacking program isn’t just aimed at stealing American intellectual property. “It’s using that mass, those numbers, to give itself the ability to physically wreak havoc on our critical infrastructure at a time of its choosing,” he said.Wray noted that during the FBI’s recent Volt Typhoon investigation, the Bureau found that the Chinese government had gained illicit access to networks within America’s “critical telecommunications, energy, water, and other infrastructure sectors.” Some cybersecurity experts have likened this activity to an act of war, although NATO hasn’t defined it as such just yet. In any case, it is a serious threat to national security.“In this country, critical infrastructure is operated by the private sector, most of which are publicly traded companies,” said Alex Santos, CEO of Fortress Information Security, a company that specializes in cyber supply chain security for organizations that operate critical infrastructure including utilities and government agencies. Santos was speaking as a guest on The POWER Podcast. “Somehow, the private sector has taken on the responsibility to defend these acts of war, which I was always taught is the responsibility of the government,” he said.“I think what’s really the point here is that the government is asking us to do more. We’re being attacked more by the adversaries. Regulations are coming in. It’s becoming more and more complicated with technology change. And, our budgets are being cut,” said Santos. Thus, while Wray can be commended for pointing out the national security problem Chinese hackers present to critical infrastructure, his words fall flat if the government doesn’t put its money where its mouth is, Santos suggested.That’s not to say money isn’t being spent by the U.S. government. “The government is spending a lot on cybersecurity to help companies, but it’s going to research and universities,” Santos said. “How many research studies do we need to tell us that cybersecurity is a problem? How many research studies do we need to tell us that we don’t have enough cybersecurity workers? How much research do we need to give us 10 recommendations for how to increase the capability of our cybersecurity workforce? At some point, we need to actually do the work.”Santos suggested money could be better spent helping companies repair vulnerabilities or by getting small businesses to install basic security precautions like endpoint protection and network monitoring. “Does the government study how to build a tank or do they build tanks?” Santos asked rhetorically. “The government builds tanks and they buy bullets,” he answered.“So, think of it that way. We need to buy more tanks and bullets, and less research studies on which tanks, how many tanks, what kind of tanks—tanks with wheels, tanks with tracks—you know, let’s buy some tanks,” he said.
The power industry has long been lamenting its aging workforce. While turnover has been happening for years, there remains a large percentage of power professionals on the verge of retirement. Furthermore, the U.S. Bureau of Labor Statistics predicts faster than average job growth for engineering occupations. That means experienced workers with the skills needed by the power industry are in high demand and can be choosy when looking for new opportunities. They can also demand higher compensation to make a change. Meanwhile, relative youngsters coming out of college and trade schools, while often having the fundamental knowledge to do power jobs, don’t usually have the experience needed to add immediate value to an organization. The situation is forcing companies to implement workforce development strategies.Mechanical Dynamics & Analysis (MD&A) is a company that offers a full-service alternative to original equipment manufacturer services, parts, and repairs for steam, gas, and industrial turbines and generators. Like other power industry companies, MD&A has found it challenging to recruit experienced engineers. “When we started out back in the early 80s, we started out as a company who tended to hire engineers who were very experienced. And back around 2009, we started to realize that those people were becoming a little harder to find,” Charles Monestere, general manager for Technical Services with MD&A, said as a guest on The POWER Podcast.“So, we started hiring a few engineers a year—some years one person, some years two or three people, maybe even a little bit more—and we developed an in-house program where we would bring in generally recent graduates, within a year or two or three out of school, and put them through some classroom training, but then a structured on-the-job training where we would have weekly meetings reviewing the activities on the job sites,” he explained. “And we’d put the young engineers with very experienced project managers and technical directors that are at the sites—the field engineers who have been doing this for many years.”Called the Engineers in Training (EIT) program, the instruction tasked learners with becoming proficient at and gaining knowledge on many different technical aspects of the job. “A good part of the work is on the job sites; however, there is some structured classroom training, which is integrated into it,” Monestere said. In recent years, finding experienced people has become even more difficult, leading MD&A to increase its hiring into the EIT program. “We’re actually targeting about 10 people a year now,” said Monestere. “We’re just hiring in five more this summer, and then, probably another five or so at the end of the year. So, that’s the direction we’re heading.”Colin Baker, one of MD&A’s newest field engineers, participated in the program and found it very worthwhile. “Working with all these really great and really smart engineers, you get all of their experience firsthand, and you learn what’s right and what’s wrong,” he said. “Also, with all these classes that you’re put through, you use all of that knowledge and you learn where to apply it when you’re actually out in the field.”Meanwhile, Baker said the program also offered him an opportunity to network within the industry and in the company. Baker said he now has multiple experts he can contact when he runs into problems. “Especially with MD&A, you can always reach out to anyone for help. Everyone is pretty much readily available for any kind of questions or something of that matter,” he said. “I’m still very new in the industry and I’m not going to know everything. I know people who do know most things, so it’s good to get these kinds of resources.”
Wildfires have had a devastating impact on California and on the state’s largest utility company, Pacific Gas and Electric (PG&E).Potential wildfire liabilities exceeding $30 billion led PG&E to file for bankruptcy in January 2019. The company emerged from bankruptcy on July 1, 2020, with a renewed focus on mitigating wildfires within its 70,000-square-mile service territory in northern and central California.“A lot has changed,” Andy Abranches, senior director of Wildfire Preparedness and Operations with PG&E, said as a guest on The POWER Podcast. “We really saw the devastation that could occur from these wildfires, and so, that was the point that PG&E started really making a big pivot to addressing the wildfire risk. The way we address the wildfire risk is really through what we consider our layers of protection. We started initially learning as much as we could from San Diego Gas and Electric [SDG&E], and put in place the public safety power shutoff program.”High-fire-threat district maps were important in understanding risks. About half of PG&E’s service territory falls in high-fire-threat areas. “We have 25,000 distribution miles that run through the high-fire-threat districts and 5,000 transmission miles,” said Abranches. Vegetation plays a critical role in the risk, and while precisely quantifying the number of trees in and around those risky transmission and distribution lines is difficult, Abranches estimated it’s in the range of eight to 10 million.With such a large area and so many trees to monitor, PG&E turned to Planet Labs, a San Francisco-based provider of global, daily satellite imagery and geospatial solutions, for help. Planet’s satellite-derived data on vegetation, including canopy height, cover, and proximity to electric-system infrastructure, is used by PG&E to prioritize the mitigation of vegetation-associated risks.Quantifying Threats and ConsequencesAbranches explained PG&E’s risk characterization process by likening it to a bowtie. “The first part of your risk bowtie is: ‘How do you quantify and in a probabilistic way build a risk model to predict ignitions are going to happen?’ ” He noted that the biggest source of ignitions is through contact with vegetation, such as a tree falling on a line or a branch coming into contact with a line on a windy day, but birds and other animals can also cause ignitions.“The second half of the bowtie is the consequence,” said Abranches. “If an ignition occurs at a particular location, if the vegetation around it is just not there, that ignition will never spread.” The fire triangle requires heat (or a spark), oxygen, and fuel. The fuel is the vegetation bed around the line where the ignition event occurs. If there happens to be a lot of dry fuel, that’s when an ignition becomes a wildfire. Depending on the oxygen, which can be heavily influenced by wind conditions, it could become a catastrophic fire, Abranches explained.“As we built our risk models, you needed to understand the vegetation dimension on two levels. One level is for probability of ignitions: ‘How do we get better at predicting where we expect vegetation ignitions to occur?’ And the data that we’re able to get from Planet every year helps improve and keeps those models updated,” said Abranches. “The second piece of it is the consequence of the ignition—understanding the fuel layer. That also—data from Planet—helps inform and continually refreshes that information to make sure it’s most current. So, the risk model actually uses the Planet data on both sides of the bowtie, because it’s probability of ignition times the consequence of ignition gives you the risk event.”
It’s no secret that the U.S. electric power system has undergone a remarkable transition that continues today. Coal-fired generation, which was the leading source of power generation during the 20th century, often providing more than half of the country’s electricity supply, fell to about 16.2% of the mix in 2023. Meanwhile, the U.S. solar market installed 32.4 GWdc of electricity-generation capacity last year, a 51% increase from 2022, and the industry’s biggest year by far, exceeding the 30-GWdc threshold for the first time. Solar accounted for 53% of all new electricity-generating capacity added to the U.S. grid in 2023, far greater than natural gas and wind, which were second and third on the list, accounting for 18% and 13% of new additions, respectively.But, how is the shift in resources affecting power system reliability? Some experts say it’s not good. “We’ve got a lot of warning lights that appear to be flashing today,” Todd Snitchler, president and CEO of the Electric Power Supply Association (EPSA), said as a guest on The POWER Podcast. “I say that not just from our perspective, but from NERC [the North American Electric Reliability Corp.]—the reliability coordinator—or from FERC [the Federal Energy Regulatory Commission], who has also expressed concerns, and all of the grid operators around the country have raised concerns about the pace of the energy transition.”EPSA is the national trade association representing America’s competitive power suppliers. It believes strongly in the value of competition and the benefits competitive markets provide to power customers. “Our members have every incentive to be the least-cost, most-reliable option that’s available, because if you are that resource, you’re going to be the resource that’s selected to run,” said Snitchler.Yet, not all markets are providing a level playing field, according to Snitchler. “The challenge we’re seeing is that there are a number of resources that are either having regulatory burdens that are placed on them that make them less competitive in comparison to resources that are not facing the same challenges, or there are resources that are highly subsidized, and as a result of those subsidies, it creates an economic disadvantage to unsubsidized resources, and that puts economic pressure on units that would otherwise be able to run and would earn a sufficient amount of revenue to remain on the system,” he explained. “We’re also seeing a pretty significant acceleration in retirements off of the system of dispatchable resources,” Snitchler continued. “What does that mean? So, of course, it means the coal plants that have been on the system for decades, as a result of economics and environmental policies, are retiring and moving off of the system. You’re seeing some of the older gas units experience the same kind of financial and regulatory pressures, and that is forcing some of them off of the system. And we’re seeing a large penetration of new renewable resources come onto the system that, frankly, are good energy resources, but don’t have the same performance characteristics that the dispatchable resources have. “And so, we’re having to fill a gap, or as I call it, the delta between aspirational policy goals and operational realities of the system, because too much retirement of dispatchable resources without sufficient resources that can replicate or deliver the same types of services that those dispatchable resources can provide, creates reliability concerns,” said Snitchler.
It’s no secret that power grids around the world need to expand to accommodate more renewable energy and the so-called “electrification of everything.” The latter, of course, refers to the growing trend of using electricity to power various sectors and applications that have traditionally relied on fossil fuels, such as natural gas or petroleum-based products. The electrification of everything includes the push toward electric vehicles; the transition from fossil fuel–based heating and cooling systems to electric alternatives, as well as the adoption of electric appliances; and the shift to more electric motors, furnaces, and other electric-powered equipment in manufacturing processes. Add to that the expected power needed to supply data centers and the growth of artificial intelligence-related computing, and current estimates of 50% load growth by 2050 could be vastly understated.Yet, getting new transmission lines planned, approved, and constructed is a daunting task, often taking a decade or longer to complete. So, how can the world more quickly add transmission capacity to the system without investing enormous time and money in the process? The answer: grid enhancing technologies, or GETs.“GETs are exciting to us because they are technologies that help us unlock quickly the additional headroom or additional capability of the grid to carry energy across the system,” Alexina Jackson, vice president of Strategic Development with AES Corp., said as a guest on The POWER Podcast. “This is something that is very important, because today, we are not making the fullest use of the electricity system as it’s built.”The system is operated below its maximum capacity for very good reasons, specifically, to maintain reliability, but by implementing GETs, it can be operated closer to its true limits without risk of failure. “Once we have these technologies, such as dynamic line rating, which helps us visualize the dynamic and full headroom of the electrical grid, and then technologies like storage as transmission, advanced power flow control, topology optimization—they all allow us to operate the grid in its dynamic capability. By doing both these things—visualization and operation dynamically—we’re able to start making fuller use of that carrying capacity for energy, which will allow us to add additional energy more quickly, serve our customer needs more efficiently, and ultimately decarbonize faster,” Jackson said.To read AES's white paper, visit: https://www.aes.com/sites/aes.com/files/2024-04/Smarter-Use-of-the-Dynamic-Grid-Whitepaper.pdf
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.”
There are many reasons to be excited about the U.S. nuclear power industry and its potential for growth. For activists focused on climate change, its carbon-free attribute makes it a viable long-term power resource. Additionally, its around-the-clock generating capability makes it a vital option in a world increasingly filled with intermittent renewables. Furthermore, new technology that incorporates passive safety features lessen the dangers associated with reactors, making units appealing even to companies outside of the power generating sector, such as chemical producer Dow Inc. and steel manufacturer Nucor Corp. Yet, there are numerous challenges facing the industry that could thwart the growth predicted by optimistic observers. John Kotek, senior vice president for Policy and Public Affairs with the Nuclear Energy Institute (NEI), the trade association for the nuclear energy technologies industry, outlined a handful of major obstacles that must be overcome to ensure future success of the nuclear industry. “The cost and schedule challenges associated with firsts-of-a-kinds of new reactor technologies is very high on our list,” Kotek said as a guest on The POWER Podcast. Kotek acknowledged that the Plant Vogtle expansion, a Southern Company project being undertaken in Georgia where two new AP1000 reactors are being added to the existing two-unit facility, has taken longer and cost more than originally expected. Nonetheless, he implied these cost and schedule issues can be overcome. Kotek also suggested the Nuclear Regulatory Commission’s (NRC’s) licensing review and approval process could be improved. “We’re really focused on the Nuclear Regulatory Commission,” he said. “They do a really good job of overseeing a safe industry here in the U.S., but it’s our view that they need to modernize their approaches to regulation as the technology is modernized. We need to see greater efficiency and timeliness and lower cost in NRC licensing reviews.” “Finally, we’re going to need to see investments in our export support,” said Kotek. “When we export a nuclear reactor and nuclear technology to another country, we need to have an agreement in place with that country that ensures that non-proliferation requirements are met. We need to see more of those agreements put in place. Right now, the U.S. only has such agreements in place with about a quarter of the nations in the world, and so, as the global market expands, we’re going to need to expand the number of those agreements.” Another aspect of export support involves leveling the playing field in the global marketplace. “When our companies are competing in this global marketplace, they’re competing against countries—competing against the state-owned enterprises in Russia and China, for example,” explained Kotek. “Those nations can offer very attractive financing packages, for example. So, we need organizations like our Export-Import Bank to be given the tools they need to enable our exporters to look attractive and succeed in those markets.” Kotek acknowledged that the Bipartisan Infrastructure Law and Inflation Reduction Act were highly beneficial to the nuclear industry, but he said it would remain important to see those tax credits and other incentives retained well into the future. Kotek suggested policies could also be enhanced in many states. Specifically, he said for states interested in decarbonizing their power grids, renewable portfolio standards should be broadened to clean energy standards. “Seeing more states move in that direction will create more demand for nuclear, because the more you’re focused on getting to 100% carbon-free, the more the value of nuclear really comes through,” he said. “Policymakers are coming to understand that the lowest-cost carbon-free energy systems include nuclear power.”
One fuel source that may not immediately come to mind when thinking about charging EVs is propane. However, there are innovative vehicle-charging options available using propane, and it is a relatively low-carbon fuel source, especially when “renewable propane” is available. Jim Bunsey, director of commercial business development with the Propane Education & Research Council (PERC), shared details on a portable propane-fueled EV charging unit that is available today. “It takes up about a parking space,” he explained as a guest on The POWER Podcast. “It’s a trailer that weighs under 10,000 pounds—so, it’s a non-commercial load—and they have about 100 to 120 gallons of storage onboard.” During the Advanced Clean Transportation Expo (ACT Expo) held May 1–4, 2023, in Anaheim, California, PERC put the portable charging station to the test. The expo included a “Ride & Drive Event,” which allowed attendees to take dozens of the latest advanced clean vehicles for a test run. What the event needed was a way to charge the electric vehicles during the show. The portable trailer fit the bill. “Now, the fun part is, we hooked up with a large propane retailer in the area, and they actually had renewable propane available to us. So, we were charging the electric vehicles—a zero-emission tailpipe—we were charging them with a carbon-intensity score, with a blend that we had, less than 20,” Bunsey said. He noted that the carbon-intensity score for the California grid is right around 79 to 80, and that non-renewable domestic propane typically runs around 79 to 80 as well. “So, we’re equal to the grid in that area—depends on how we look at carbon intensities—but since we had the blends that were available to us, we were charging with a carbon intensity of 20, which was amazing that we were there. So, it was very successful,” he said. Bunsey said the original equipment manufacturers (OEMs) demonstrating their vehicles at the ACT Expo became very excited about the possibility of charging vehicles with propane. “We were charging these over-the-road electric vehicles at 700 volts with nice, quiet, clean-burning propane that was reliable, and it opened the OEM’s eyes. They’re like, ‘Hey, we want to do this.’ And luckily, we’re starting to pair with OEMs to help them electrify the future,” said Bunsey. Using the AFDC calculator, annual CO2 equivalent emissions for an all-electric vehicle charged in California was 1,473 pounds in 2021. If we assume renewable propane offers a carbon intensity of about one-quarter that of the California grid, the CO2 equivalent emissions using renewable propane would even be close to half what was estimated earlier in the Washington state example. For fleet owners that are just getting started with EVs and may not have the infrastructure and transformers in place to charge at 700 V, the propane-fueled portable trailers could make sense. The systems could be scaled up as fleets expand, then, once permanent, grid-connected charging stations are installed, propane could be phased out or continue to act as a backup. It frankly provides a lot of options.
For more than four decades, POWER magazine has honored the top performers in the electricity-generating industry with annual power plant awards. Award winners are selected by the editors of POWER based on nominations submitted by industry insiders, including suppliers, designers, constructors, and operators of power plants. Winning POWER’s highest honor—the Plant of the Year—in 2023 is Estrella del Mar III, a first-of-its-kind floating combined cycle gas turbine power barge that Sonal Patel, senior associate editor for POWER, said fulfills a remarkable assortment of modern power system demands. “Nearly fully built in Singapore by an international team that delicately integrated shipbuilding and power engineering, the pioneering SeaFloat plant sailed more than 10,000 miles for final commissioning in Santo Domingo, capital of the Dominican Republic. The innovative 148-MW project exemplifies an efficient, ecological, economical, and resilient power solution that triumphs over land and cost constraints,” she wrote in the cover story for the July issue of POWER. “This is actually the highest form of modularization, bringing a fully equipped power plant to the heart of the capital without requirements of precious land,” Hamed Hossain, business owner of Siemens Energy’s SeaFloat segment, said as a guest on The POWER Podcast. Hossain explained that with SeaFloat on the menu, Siemens Energy customers can choose to build power plants either on land or on a floating device. “This opens entirely new possibilities for customers,” he said. Constructing SeaFloat plants in a shipyard rather than on-site offers a number of benefits. Hossain noted that an experienced workforce is typically readily available in the shipyard environment. Furthermore, the impact on the local community during the construction phase of the power plant is minimized. Hossain said building the power barge directly in the heart of Santo Domingo would surely have affected residents, for example, with possible traffic restrictions and other complications. Estrella del Mar III is a state-of-the-art combined cycle power plant. It is equipped with two SGT-800 gas turbines (GTs) built in a Siemens Energy factory in Sweden, and an SST-600 steam turbine manufactured in Görlitz, Germany. “We have ensured to bring typical land-based plant efficiency to the heart of the beautiful island, Dominican Republic, Santo Domingo, on a floating device,” Hossain said. Notably, the SGT-800 gas turbines are capable of operating currently on a blend of 75% hydrogen, and Siemens Energy has a pathway to 100% hydrogen by the end of the decade or sooner. This is an important development as countries move to decarbonize their power supplies. “We need to find the best way for a net-zero future,” said Hossain. “We are not there yet, but the capability to run the GTs with hydrogen is a huge step in that direction.”
- Subsequent License Renewal: Extending Nuclear Power Reactors to 80 Years of Operation by POWER
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.
Some cybersecurity experts believe hackers pose a greater threat than ever to power plants and electric grids. Much of the operational technology (OT) used in power stations and throughout the grid was installed at a time when cybersecurity was more of an afterthought than a focal point in the design process. Furthermore, the pool of bad actors has grown increasingly large and complex, including nation states, activist groups, organized crime syndicates, malicious company insiders, thrill seekers, and a bevy of other folks with a variety of untoward motivations. Hackers are found in all parts of the world, meaning unscrupulous activity is occurring around the clock. The troublemakers aren’t always looking to deploy cyber warfare strategies on the spot, but rather, they often want to gain access to systems so they can cause chaos when the action would be most beneficial to their cause and/or most inconvenient for the system. People in the power sector haven’t been oblivious to the threat. A skilled group of professionals has been assembled to monitor systems and develop countermeasures to thwart possible attacks. Still, the vectors and tactics utilized by hackers are constantly evolving, which makes the task of protecting OT systems challenging. “What worries me right now about the threat landscape overall is that I see it accelerating, in particular, in the OT or the industrial cybersecurity environment,” Ian Bramson, global head of Industrial Cybersecurity at ABS Consulting, said as a guest on The POWER Podcast. It’s not only the frequency of attacks that has changed, but also the kinds of attacks, what’s being targeted, how systems are being hit, the goals of the instigators, and the people responsible for the offenses have all shifted, he said. Bramson believes the conflict in Ukraine has increased cyber risks. “It’s what I call a multi-player game now,” he said. As an example, he mentioned a hacker group that goes by the name “Anonymous.” Days after the war in Ukraine began, Bramson said the group announced it had “declared war” on Russia. Anonymous is not based in Ukraine or affiliated with the country in any known way, it simply decided to take a stand against Russia in response to the country’s aggression. While that in itself doesn’t seem to pose a great threat to U.S. systems, it increases cyber activity overall and could presumably encourage pro-Russian hackers to seek revenge, taking aim at Western targets in response. Furthermore, Bramson suggested much of the cyber activity that’s being undertaken by Russia and its supporters is politically motivated. Attacks are one way, for example, that Russia could try to fight back against sanctions enacted by European countries and the U.S. without firing missiles and starting a physical war with the West. “All that is increasing the pace of attack. So, I think it absolutely is increasing the threat environment for anyone here,” Bramson said. “And it brings that battle—that war—into our systems, into our devices, into our operations of our power and energy plants. That’s where a lot of these conflicts are going to be playing out and that’s what we have to be on guard for.”
Uninterruptible power supply (UPS) systems are often installed to protect critical equipment and loads from power outages, and other voltage and current problems. Many UPS systems continuously regulate the input power, thereby maintaining a constant and uniform supply of electricity. UPS systems are typically used on computer hardware or other equipment where an unexpected power disruption could cause fatalities, serious business disruption, or data loss, such as at data centers, telecommunication facilities, hospitals, and power plants. While UPS systems have batteries and obviously store energy, they are not synonymous with standard battery energy storage systems that are commonly being added to the power grid these days. In fact, UPS systems are often not allowed to export power to the grid. However, that doesn’t mean they can’t serve a useful purpose in lowering energy bills and providing a return on investment to owners. “Historically, UPSs are sitting there waiting for something bad to happen—they were kind of insurance devices,” Yaron Binder, vice president of Product Management with SolarEdge Critical Power, said as a guest on The POWER Podcast. “But I think there’s a growing understanding that these could also double as an energy storage system, and actually create some kind of benefit, let’s say, revenue for the customer, apart from just sitting there waiting for the power to go out.” In the past, many UPS systems used lead-acid batteries, which were not a good fit for cycling operations. Today, however, many UPSs have lithium-ion batteries, which are much better suited to regular cycling. Therefore, there is less downside to using a UPS for more than just emergencies. Binder said there are many clever ways to utilize UPSs. “One of the things you can do, for example, is use the UPS as a demand response component,” he said. Although, as previously mentioned, owners may not be able to export power directly to the grid, they can reduce their power demand when electricity prices spike by using their UPS to power in-house needs. This will save money when prices are high and the UPS can be recharged when power prices have returned to a lower rate. Of course, a minimum charge level must be maintained to support the UPSs main function, which is to provide power to critical equipment during an emergency. Another innovative solution that can save owners money is to basically levelize power demand spikes using the UPS. “Sometimes you can use that battery to defer an increase in the site infrastructure,” Binder said. He referenced a hospital that he worked with where this was done. The hospital had two medical scanners that consumed a lot of energy when they were powered up. However, the demand was much lower while patients were actually being tested by the machines. “We had a case where putting in those two scanners was drawing more power than what the distribution panel was able to do, but upgrading that distribution panel was very, very expensive,” explained Binder. To solve the problem, the UPS was used during startup, and then as the load lessened during the test, the UPS returned to its normal standby role. “That way, we were able to use that battery and defer that infrastructure upgrade. So, that was another nice use for a UPS,” said Binder.
Hydrogen is widely seen as a vital component in efforts to decarbonize the world’s power supply. One example of this is a strategy being piloted by at least a couple of major gas turbine manufacturers, which involves storing “green hydrogen” produced through electrolysis using excess wind or solar power when renewable energy supplies exceed grid demand. Then, when the tables turn and demand exceeds renewable energy supplies, the carbon-free green hydrogen is burned in combustion turbines to provide sustainable clean energy to the grid. It’s not a perfectly efficient energy conversion, but it is a method that can be used essentially as a renewable energy storage mechanism, reducing demand for fossil fuels. The movement of hydrogen is not so simple though. Today, hydrogen is transported from the point of production to the point of use via pipeline and over the road in cryogenic liquid tanker trucks or gaseous tube trailers. Because hydrogen has a relatively low volumetric energy density, its transportation, storage, and final delivery to the point of use comprise a significant cost and result in some of the energy inefficiencies associated with using it as an energy carrier. However, ammonia offers one possible solution for the hydrogen transport problem. The chemical formula for ammonia is NH3. Like hydrogen, ammonia can be combusted in gas turbines and reciprocating engines. Unlike hydrogen, however, ammonia can be more easily transported and stored in liquid form, something fertilizer companies have been doing for decades. “Hydrogen is really being looked at as a key means of transporting energy around the world and fueling the world in an environment where carbon emissions aren’t acceptable,” Erik Mayer, vice president of Clean Energy Solutions with CF Industries, said as a guest on The POWER Podcast. “We convert large quantities of hydrogen into ammonia, currently for the fertilizer market but ultimately that same ammonia molecule is being looked at as an efficient way of being able to move hydrogen molecules around the world, whether they’re sourced from natural gas or whether they’re sourced from electrolysis.” Mayer said the advantage ammonia offers over hydrogen is that it is a liquid at moderately low temperatures and can be stored as liquid under relatively low pressure, similar to how liquefied petroleum gas (LPG) is stored. Concerning how the ammonia is used, Mayer said there are two possible ways: ammonia can be burned directly or it can be “cracked,” that is, decomposed over a catalyst, back to hydrogen. Because there are no carbon atoms in ammonia, there is no CO2 released when it is burned in either case. A downside of burning ammonia is that it produces relatively high NOx emissions. Mayer said those can be somewhat managed through combustion controls, but ultimately, there are proven technologies such as selective catalytic reduction (SCR) systems that can be used to keep NOx emissions within required limits. One big application that CF Industries sees as a growth opportunity for ammonia is as a marine fuel. “The marine industry uses large quantities of bunker fuel to do these transoceanic voyages, and the amount of energy required makes it impossible for them to convert to something like batteries,” Mayer said. “Some of the larger marine engine manufacturers are planning to be able to inject ammonia in replacement of carbon-based fuels, almost to 100%, and they think that technology will be fully developed in the next couple of years.”
Tuesday, March 8, was International Women’s Day, a global day celebrating the social, economic, cultural, and political achievements of women. One woman who has achieved great success is Amani al Hosani, a nuclear engineer in the United Arab Emirates (UAE). “I was born and raised in Abu Dhabi, the capital of the United Arab Emirates. I got my bachelor in science in chemical engineering from UAE University, and then worked in the oil and gas industry—ADNOC Onshore—for almost two years as a process engineer,” Hosani said as a guest on The POWER Podcast. “Then, I was awarded a scholarship to pursue my education in nuclear engineering, and I graduated in 2012 with a Master’s in nuclear engineering and was hired by the Emirates Nuclear Energy Corporation [ENEC] as a simulator engineer. Currently, I work as the Unit 3 shift supervisor at Barakah nuclear power plant.” The Barakah nuclear plant is a four-unit station being constructed in the Al Dhafra region of the Emirate of Abu Dhabi on the Arabian Gulf, approximately 53 kilometers west-southwest of the city of Ruwais. Barakah Unit 1 entered commercial operation on April 1, 2021. Unit 2 was connected to the UAE grid in August 2021, and commercial operation is expected in the coming months. Construction of Unit 3 was completed in November 2021 and that unit is currently undergoing operational readiness preparations, while Unit 4 is in the final stages of commissioning with construction completion standing at 92%. Hosani has seen the Barakah project spring to life before her very eyes. In 2009, ENEC CEO Mohamed Al Hammadi invited her class, which was the first class of nuclear engineering graduates in the UAE, to visit the site. “They drove us two and a half hours from Abu Dhabi into the middle of the desert—in the middle of nowhere,” Hosani recalled on the podcast. “All that we were able to see was four signs standing there with numbers 1, 2, 3, and 4. And then, His Excellency, Mohamed Al Hammadi, was leaning toward me and telling me, ‘You see those signs? Here is where we are going to build Units 1, 2, 3, and 4.’ There was nothing there.” Fast forward to today, and the site looks very different (Figure 1). Now, the plants have been constructed and Unit 1 is in commercial operation. “It was a wonderful journey,” said Hosani. “I really feel so proud that I’m part of this organization and this major historical project in this region.” Hosani hasn’t been the only woman involved in the project. Women have made up a larger percentage of ENEC’s workforce than is typical in the nuclear industry. Sheikha Lubna bint Khalid Al Qasimi, noted in November 2017 that 23% of professionals working at ENEC at the time were women and that approximately 10% of employees at the Barakah plant were female. “Here in the UAE, we strongly believe in the equality of men and women, both in society and in professional development,” she said during a presentation. “From the very beginning of the UAE Peaceful Nuclear Energy Program, we emphasized strongly the need to bring more women into the nuclear industry and into what is generally considered a male-dominated sector around the world.” While the percentage of women in the ENEC workforce has decreased to about 20% today, as the workforce has grown significantly and the percentage of women added has not quite kept pace, Hosani said women still play an important role in the UAE’s nuclear power sector. “You can see women confidently and competently leading their teams in either non-technical supportive roles or in technical specialized roles,” she said. “For a relatively young organization, I’m proud looking around me and seeing women working as local operators, reactor operators, shift supervisors, radiation protection, chemistry, engineering, maintenance, you name it, and every single person is very well trained and qualified to assume their role. So, they are adding great value to the organization.”
Many power companies have been facing challenges when trying to attract high-quality recruits in the increasingly competitive labor market for engineers and other workers with technical backgrounds This podcast touches on one place qualified candidates can be found to fill some of those high-tech positions—the military. This episode includes input from William Newell, a 20-year veteran of the U.S. Air Force. Will recently transitioned from the military to a job in the power sector. Will’s story is unique and provides details about what worked for him. It offers an inside look at the job search process and shows how military experience prepares people to step right in and take charge of projects in the civilian world. Amy West, recruiting team leader with Orion Talent, the nation’s largest military recruitment firm, said, “The biggest skillset that we’re asked to find is technical talent. The military offers the best technical training program, in my opinion, in the world. Nothing prepares you like the military does to work on technical systems.” West would know, having herself been a gas turbine electrician in the U.S. Navy. Yet, even with his significant training and formal education, as well as the hands-on experience he had, Newell felt the anxiety many people experience when leaving the military. “I was extremely nervous,” Newell recalled. He had “a great support system of friends and family,” all of whom were assuring him that there were jobs available and he was “desired by the industry,” but that didn’t instantly calm his fears. What helped, however, was speaking with his brother-in-law, who had transitioned from the U.S. Army to the civilian world. In the process of his employment search, Newell’s brother-in-law had attended a job fair where he connected with Orion. Although he felt somewhat out of place initially, because all the other candidates in the room were officers in the military while he was enlisted, Orion’s staff made Newell’s brother-in-law feel welcome and “treated him really well.” In the end, Orion helped get him a job that he really liked, and he has since been promoted. His brother-in-law’s experience convinced Newell to seek Orion’s help too. One thing Newell wasn’t sure of, though, was how his experience would translate to a job outside of the military. He knew he could work on airplanes, of course, but he was ready for a change, so the question was, what else could he do. “In my head, I had never made the correlation to the job that I’m currently working,” he said. “I didn’t know that data centers, power plants, and everyone had these large battery backup systems that require constant maintenance and such heavy support that there is a need for a technician like myself to come service them all the time.” That’s where Orion really provided value. “We usually start when a new candidate comes into our system with an initial screening call,” West explained. “We get to know the candidate. We learn about what they did in the military—how they’re looking to leverage those skills in the private sector. And then from there, we try to make suggestions and present opportunities based on a combination of skillset and interest, and we use a lot of different techniques to narrow it down.”
Many experts believe hydrogen holds great promise as a clean energy resource that can help nations achieve carbon-free goals. Green hydrogen, which is made from water through electrolysis powered by renewable energy, could be used to decarbonize a wide range of hard-to-abate industries, including petrochemical, cement, and steel, which often require high temperatures and combustion that cannot be achieved with standard wind and solar power. Hydrogen can also be used in mobility applications and as an energy storage medium, among other things, so the future looks very bright for this up-and-coming energy sector. “Looking at this large, growing market; the projects that we see emerging so fastly; the transport and the pipeline tasks in front of us—the infrastructure; and the industry use sectors just starting to be developed, it looks like we are all climbing the Himalaya and we have just left the base camp, but we are very motivated to go further,” Dr. Hans Dieter Hermes, vice president Clean Hydrogen with Worley, said as a guest on The POWER Podcast. Hermes is “very excited” about the hydrogen market. Worley, an engineering company headquartered in Australia with a worldwide team of about 48,000 consultants, engineers, construction workers, and data scientists, is currently implementing more than 120 hydrogen projects worldwide, he said. While that number may seem large from a historical perspective, the growth in hydrogen projects required to decarbonize even a few of the sectors mentioned above is mindboggling. For example, Hermes, who is based in Berlin, said if Germany’s heavy-truck fleet were to be powered from hydrogen instead of fossil fuels, the country would need to ramp up today’s production of hydrogen by a factor of 100. “And I’m not talking about buses, not talking about trains, not even talking about fertilizer industry, chemical industry, or steel, or heating the houses, just only the heavy-truck fleet,” he said. As another example, Hermes pointed to household heating. To supply all German households with hydrogen heating fuel, existing production would need to be increased by a factor of 830. “This gives us an idea of the size of the task that is in front of us,” he said. While many companies are investing in green hydrogen technology, high production costs currently pose a barrier to widespread adoption. Today, most hydrogen is produced from natural gas, which is typically considered grey hydrogen, or blue hydrogen when carbon capture technology is utilized. For green hydrogen production costs to come down, facilities will need an accessible and abundant renewable energy supply, and, perhaps even more importantly, further advancement and scale-up of electrolyzer technology. Still, Hermes expects that to happen fairly quickly based on cost curves observed in other developing power sectors. Specifically, he pointed to the offshore wind industry as an example. He said 10 or 20 years ago, every offshore foundation was a pilot project and costs were very high. Nowadays, the industry is very mature and costs have come down dramatically. “I expect that the same will happen with the hydrogen sector. We already see a very steep cost reduction,” he said. Cost reductions to date have come by integrating lessons learned from earlier projects and also through new developments that have been triggered by a growing market demand. Looking ahead to 2050, Hermes sees several “boosts and barriers” along the way. “On the positive side, I could already mention technology development, the market development, and cooperation,” he said. “On the barrier side, the regulatory frameworks, and the infrastructure, and how to get finance into that sector.”
In February 2021, a severe cold weather event, known as Winter Storm Uri, caused numerous power outages, derates, or failures to start at electric generating plants scattered across Texas and the south-central U.S. The Electric Reliability Council of Texas (ERCOT), which manages the power supply for about 90% of the load in Texas, ordered a total of 20,000 MW of rolling blackouts in an effort to prevent grid collapse. According to the Federal Energy Regulatory Commission (FERC), this was “the largest manually controlled load shedding event in U.S. history.” More than 4.5 million people in Texas lost power—some for as long as four days. The National Oceanic and Atmospheric Administration’s National Centers for Environmental Information reported that the event resulted in 226 deaths nationwide and cost an estimated $24 billion. There has been a lot of finger pointing surrounding the blackouts that occurred. Several studies have been done into the causes, including one spearheaded by FERC, the North American Electric Reliability Corp. (NERC), and NERC’s regional entities. The key finding from the FERC/NERC report was that a critical need exists “for stronger mandatory electric reliability standards, particularly with respect to generator cold weather-critical components and systems.” The study found that a combination of freezing issues (44.2%) and fuel issues (31.4%) caused 75.6% of the unplanned generating unit outages, derates, and failures to start. But Bernard McNamee, a former FERC commissioner, and current partner with the law firm McGuireWoods and a senior advisor at McGuireWoods Consulting, suggested the study missed the real cause of the problem. Speaking as a guest on The POWER Podcast, McNamee said, “I think the reality is, is that there was a market design problem in Texas, and that was that, as you had more subsidized resources driving down the overall cost of power, you’re not providing enough financial incentive for other dispatchable resources to harden their systems—winterize their systems—to be available when the wind wasn’t blowing or the sun wasn’t shining.” McNamee didn’t blame power generators for being ill-prepared. He suggested they simply made decisions based on cost-benefit analysis. “Why would you [spend money on weatherization] if you’re a natural gas company or generator and you think you’re going to make most of your money, you know, five to 10 days in the summer? You’re not expecting to operate in the winter and make money, [so] why would you spend the capital that you’re not going to be able to recover?” McNamee asked. “I think that the market design is something that has not been talked about enough [and] was one of the leading causes of what happened,” McNamee said. “I think what happened in the winter storm in Texas, and what happened in August of 2020 in California, were really warning signs for the rest of the country about how we really need to pay attention to market design, and maybe costs that aren’t being priced into the market but that are necessary for reliability.” However, McNamee also doesn’t blame the growth of renewable resources for the problem. “It doesn't mean that wind and solar are bad. They provide some great benefits,” he said. “It’s not that one resource is good or bad. It’s thinking about how does the system all work together, so it’s there when you need it 24/7. And it can’t be, ‘Well, on average, the power will be available.’ It’s got to be available every moment.”
There are countless risks associated with power plant operations. For example, the risk of equipment failure is present in virtually every power plant system. In some cases, the risk is very low and could even be inconsequential. In others, it’s much higher and could be catastrophic, not only to plant operation, but also to the health and safety of workers. Understanding where the greatest risks lie and acting to reduce the likelihood of an unwanted incident should be high on every plant manager’s to-do list. Digital technology has made the task of managing risk much easier. Tools are available today that can organize data and help users evaluate where the most probable and/or consequential failures are likely to occur. For example, risk-based asset integrity management (AIM) software, which often uses data imported from a plant historian or other legacy software systems, can sort and prioritize data to identify areas of concern and provide insight for decision-makers. There are several companies that offer AIM products. One is Antea, a company founded in Italy more than 30 years ago. Antea’s platform features a number of different modules that can be configured to meet the needs of clients in the oil & gas, power generation, and chemical process industries. Among the most important of these modules is IDMS (inspection data management system). “IDMS is the key,” Floyd Baker, vice president for Antea North America, said as a guest on The POWER Podcast. Baker explained that inspection data, such as from ultrasonic, radiographic, or other testing, can be collected and stored in the IDMS. This allows users to do a number of things, such as monitor and trend corrosion, schedule follow-up inspections, and perhaps most importantly, plan repairs. “We can forecast the useful life of that asset so that one can either make repairs beforehand or plan replacements,” said Baker. Antea’s platform also includes an RBI (risk-based inspection) module. The company claims the most effective way to prevent unplanned downtime is with RBI. It determines inspection frequency according to an asset’s individual risk level, which can dramatically reduce spending and focus resources on the most critical equipment. Baker explained: “You wouldn’t want to be spending millions of maintenance dollars out inspecting a water tank, when in fact those dollars could be focused more on say, high-pressure piping or something that could cause a real catastrophic event. So, this methodology takes into account the real risk—how it’s going to affect them from a safety perspective, from a financial perspective, even from an environmental perspective—takes all of this stuff into several algorithms and calculates the risk that you assume on any given asset. When you look at that risk, say on a matrix, then you can actually figure out where you need to focus your maintenance dollars in order to reduce that risk.” Risk is assessed in multiple ways. In some cases, including at some power plants, it’s done using a qualitative risk assessment model. “The end user—the plant operators—would actually provide input on what risk looks like to them,” Baker said. In other cases, such as at many refineries and chemical plants, risk is assessed quantitatively. That’s done using recommendations developed by the American Petroleum Institute (API), and published in its “Risk-based Inspection” API Recommended Practice (RP) 580 and “Risk-Based Inspection Methodology” API RP 581. One of the benefits of utilizing digital technology is the transparency these tools provide. “It creates total transparency, especially for the C-suite level,” Baker said. “Using a platform like this actually creates the transparency that all people—up, down, and across the organization—can actually have access to key performance indicators and dashboards to understand better where that risk is at and what their teams are doing to mitigate that risk.”
Environmental, social, and governance (ESG) efforts are factoring into merger and acquisition (M&A) deal activity within the power and utilities sector across North America, according to a report issued by PwC, a professional services firm serving the “Trust Solutions and Consulting Solutions” segments. “As policies are clarified and ESG strategies are strengthened, broad investor interest should continue to grow” in 2022, the report says. The power and utilities industry saw increases in both deal volume and value during the 12 months ending on Nov. 15, 2021, the report says, “with significant contributions from both financial and inbound investors, as well as those focused on renewables.” While deal activity slowed after midyear, the rebound to pre-pandemic levels stayed steady in 2021, with the sector seeing 55 deals, up from 42 in 2020 and 52 in 2019. On a value basis, total deal value increased to $49.9 billion, up from $48.4 billion in 2020 and $42.9 billion in 2019, PwC reported. “We saw volumes, as we defined deals in the space, hold pretty consistent over the last several years, including last year,” Jeremy Fago, PwC U.S.’s Power & Utilities Deals leader, said as a guest on The POWER Podcast. However, Fago noted that the size of deals has changed, with fewer mega-deals being done. “That was an expectation that we put out there several years ago when we looked at the types of deals that were being done at that time, and as a result, we expected a bit of a dearth in mega-deals as we moved into this period of time, including 2021 and 2022,” he said. PwC’s report says, “ESG became a noted driver of deal activity as major power and utilities players focus on ESG investment and goals.” Fago agreed that ESG initiatives are part of the narrative underpinning some deals. “A lot of the companies in this space—in fact, most of them—have set some type of goal out there, particularly on the environmental side around carbon reduction, in some cases a net-zero target, you know, 10, 15, 20 years down the road,” he said. “I think it’s become table stakes at this point,” suggesting that having sound ESG policies in place is a minimum requirement in any M&A discussion. Fago said he expects the focus on ESG to continue. However, he also said now that most companies have ESG initiatives in place, attention has turned to executing on strategies. In some cases, that means selling pieces of the business or buying new assets. “We expect some portfolio reshuffling as a result of this, where perhaps there are businesses within larger companies that don’t necessarily fit those ESG goals bespoke to that company and divesture of those platforms to recycle that capital into potential opportunities that do fit that profile,” he said. “It’s going to be very dependent on not only the existing portfolio, but also what are the opportunities in your particular area and in your particular footprint to be able to do that,” said Fago. “We’ve seen it as certainly a reason for some of the deals that have been done, but again, it’s going to be very dependent on what the opportunity is for a particular company and how quickly that capital can be deployed.”
New distributed energy resources (DERs) are being added to the power grid every day. However, DERs don’t automatically provide owners with the greatest value possible. In many cases, that requires the help of an aggregator, that is, a company that specializes in managing DERs owned by a pool of clients and optimizing performance of the overall system based on real-time signals coming from the wholesale power markets. “Wholesale electricity markets need grid services from distributed energy resources. We connect those underutilized distributed energy resources—typically behind customer meters—to those wholesale power markets to orchestrate and monetize those resources to deliver reliable, cost-effective, and clean energy,” Gregg Dixon, co-founder and CEO of Voltus, said as a guest on The POWER Podcast. Voltus’ customers and grid services partners generate cash by allowing Voltus to maximize the market value of their flexible load, distributed generation, energy storage, energy efficiency, and electric vehicle resources. “Voltus is to the electricity industry what Airbnb is to the real estate market in the sense that Airbnb connects under-utilized apartments or homes to buyers who want to make use of those under-utilized assets, and Voltus does that for the electricity grid,” Dixon explained. Dixon said the core of Voltus’ business tends to be commercial and industrial energy consumers—large energy users that have various types of DERs installed at their facilities. “They could have solar plus storage at a facility. They could have on-site generation at a facility, like perhaps a data center or a hospital. They could have the ability to curtail electricity for certain periods of time—otherwise known as demand response—like, say, a cold storage facility. They could have electric vehicle charging where they can either inject that power back into the grid, say, with public transit fleets, or simply curtailing charging at various locations. We can essentially aggregate anything, whether it’s an electric vehicle in a homeowner’s garage or it’s a steel mill at an industrial campus,” he said. “We essentially operate a virtual power plant, aggregating the various forms of distributed energy resources,” said Dixon. Notably, Voltus’ software platform is unique, according to Dixon, in that it is integrated fully into all nine U.S. and Canadian wholesale power markets. In the end, it all comes down to economics. “The market is the final arbiter,” he said. Every technology has different operating constraints, including the economics by which they are dispatched. Battery storage, thermal storage, solar panels, wind turbines, demand response, and on-site backup generators all provide certain benefits, but they also have limitations. “Each of those DERs has operating constraints that are best addressed through a software platform that can orchestrate it all,” Dixon said. Still, everybody wins when DERs are optimized. “We’re driving the economics of the grid down while driving resilience up and making the grid cleaner. It’s the proverbial win, win, win,” said Dixon.
What is a microreactor and why would you want one? The definition could be debated, but nuclear reactors in the 1 MW to 20 MW range generally fit the bill, and there are countless possible applications for the technology. “This could be used for disaster relief. This could be used for mines, remote communities—on a 24/7 basis. It can be used for data centers, industrial plants—anyone that wants to be off the grid, even though maybe they’re on the grid now, but they want to be off the grid—so, military bases. The opportunities here are just endless,” David Durham, president of Energy Systems with Westinghouse Electric Co., said as a guest on The POWER Podcast. Westinghouse is developing a microreactor called eVinci. It’s a next-generation, small nuclear energy generator intended for decentralized generation markets. The eVinci design is very different from commercial light water reactor plants currently in service around the world. “The differences are substantial. There’s no water. There’s no moving parts. Literally, there’s hot air that transfers through the tubes into the power conversion container, and then, that generates electricity,” Durham explained. “So, it’s simply a hot air transfer system,” he added. “What’s interesting about this technology is it’s totally self-contained in three containers, and these containers fit on the back of an 18-wheel truck,” said Durham. “So, this isn’t your image of building a big power station with constructors and cranes and everything else. It’s basically three CONEX boxes that are then taken to a site, which requires very little work—a concrete basemat, that’s it—and then they’re plug and play together, so that within just about three months, you’ve got electricity at that site.” Westinghouse claims the reactor core “can easily run for more than 10 years without the need for refueling.” Furthermore, units can be controlled and monitored remotely with literally no personnel onsite. It remains unclear, however, if regulators will allow that type of operation. “If there are staff onsite, it’ll be a very minimal number. There’s really very little maintenance to be done. This thing is sealed and operates for five years autonomously,” said Durham. “Quite frankly, if there are operators onsite, they’re basically just going to be monitoring—there’s nothing really for them to do.” Durham suggested the eVinci design could eliminate the need for diesel-fueled power generation in remote locations. He noted that diesel is “one of the dirtiest fossil fuels out there,” and an “extremely expensive way to generate electricity, particularly when you need to ship it into remote areas.” Westinghouse conducted a feasibility study in partnership with Bruce Power, a Canadian private-sector nuclear generator that produces about 30% of Ontario’s power annually. The study found that a single eVinci microreactor could be “between 14% and 44% more economic than a diesel generator, depending upon the price of diesel fuel and the price for carbon,” according to a Westinghouse-issued statement. “The feasibility study determined that there are at least 100 communities in Canada—up in the north—where this could be a game-changing technology to eliminate almost 100 million liters of diesel fuel being burned per year,” Durham said. Additionally, in mining scenarios, Westinghouse said that the eVinci microreactor unit with diesel backup “could reduce carbon emissions by about 90% in Canada.” So, when can we expect to see the first eVinci unit enter commercial operation? “We’re still in the process of scaling it up,” Durham explained. “And then, of course, we have to go through the licensing process," he said. “We definitely see this being commercialized by the end of this decade,” said Durham, who sees a bright future for nuclear power. “I think that we’ll definitely see a significant growth in nuclear power at large. I think it’ll include eVinci, certainly, in a big way.”
The optimal grease to use in power plant equipment is rarely contemplated by people other than truly dedicated operations and maintenance managers, and the workers on their teams who feel the pain when a piece of equipment breaks down due to inadequate lubrication. Yet, for those individuals, the choice of which grease to use in a component is an important decision. Selecting the right option could not only save energy, but also extend the maintenance interval and reduce the likelihood of equipment failure. “We spent a lot of years looking at: ‘Can you make a difference from an efficiency perspective based on the product that you choose?’ And the answer is, unequivocally, yes,” Greg Morris, product application specialist for greases at Shell Americas, said as a guest on The POWER Podcast. Morris suggested that synthetic greases are far superior to standard mineral-based formulations. “How do you get to a place where you have longer service intervals— you touch the equipment less often,” Morris asked. “You can go to a synthetic,” he said. “That changes everything.” If an original equipment manufacturer recommends relubrication every 1,500 hours using a mineral-grade grease, for example, you may be able to double that interval to 3,000 hours with a synthetic grease. “Using synthetics, you’ve gained something,” Morris said. “You’re gaining oxidative stability. A lot of times there’s mechanical stability that comes along with that. And, you also have thicker film at higher temperatures.” Extending preventive maintenance intervals also reduces the risk of human error. The less often workers have to touch a piece of equipment, the fewer chances there are for personnel to make a mistake, such as lubricating with the wrong grease, for example. “We don’t have as many people working in the facility as we used to dedicated to doing just lubrication. So, you’re doing more [work] with fewer people,” explained Morris. “If you can reduce the tasks that those folks have to do to maintain reliability, then you’re helping yourself out as well.” Efficiency gains can be significant. Morris said 8% to 12% improvements in efficiency are common using synthetic greases. “Where does that show up? It shows up in temperature in the bearing,” Morris said. “If you go from a mineral grade to a synthetic, you can see a drop in temperature in the bearing, and nothing else has changed—you haven’t changed the load, you haven’t changed the speed, you haven’t done anything else—what you see is, the lubricant is having that much of an impact.”
There is a common misperception that “green energy” appeals mostly to liberals. However, at least some of the facts don’t support that view. A case in point can be found in the rooftop solar sector. “It’s not Republican or Democratic. It’s really American. It’s free enterprise,” Jayson Waller, founder and CEO of POWERHOME SOLAR, said as a guest on The POWER Podcast. POWERHOME SOLAR does business in 15 states—some red and some blue—so Waller has fairly good insight on the types of people who are installing solar systems. “Both sides of the aisle are liking solar,” he said. In fact, POWERHOME SOLAR surveyed customers and found more than 60% were Republicans. Waller suggested that part of the misunderstanding is a result of the climate change debate. Yet, he doesn’t necessarily see rooftop solar as part of an environmental agenda; he implied that economics were driving growth. “What we see is more Republicans come across and understand what solar is—it’s the largest job growth the last two years in a row. They understand that it’s energy independence, and they get it.” The data seems to back Waller's view. The U.S. surpassed 3 million solar installations across all market segments during the second quarter (Q2) of 2021, according to a report issued in September by the Solar Energy Industries Association (SEIA). More than half of all new U.S. electric capacity additions in the first half of 2021 were from solar. Residential solar was up 46% from Q2 2020 when installations were hit hardest by the COVID-19 pandemic. The commercial and community solar segments also saw a substantial uptick in activity in Q2, increasing 31% and 16%, respectively, compared to the same quarter last year. Meanwhile, utility-scale solar set a new record for installations with 4.2 GWdc added, nearly three quarters of it in Texas, Arizona, and Florida. “I see all states really continuing to grow rooftop solar,” Waller said. “You’re seeing a lot more companies go public with it. You’re seeing a lot more loan and finance companies know that this is good paper to invest in.” Perhaps Waller’s biggest revelation, however, was that energy storage has become synonymous with rooftop solar. “We’re huge advocates of battery storage. We’re at 98% attachment rate for battery storage. So, if we install 1,000 customers this month, we’re going to install 980 batteries,” he said. “It’s our belief that every customer deserves battery storage.” While casual observers might think solar systems are more valuable in states with a lot of sunshine, such as Florida, Texas, and Arizona, Waller said that may also be a misconception. “Michigan is our largest state,” he said. The reason a state like Michigan is such a good candidate for solar is that the cost of power is high in the state compared to places like Florida, Texas, and Arizona. Yet, the production from a photovoltaic system in Michigan is only about 15% less than in North Carolina (where Waller’s company is based). Therefore, if you balance the cost of power, which is 60% higher in Michigan, against the lower production, you still end up with a better return on the investment. “Solar works in gray, it works in snow, it just doesn’t work at night—that’s why you have battery storage—but it still works on a gray day. That’s why Connecticut and New York have a ton of solar,” said Waller.
Fusion occurs when two atoms slam together to form a heavier atom, such as when two hydrogen atoms fuse to form one helium atom. A tremendous amount of energy is released in the process. This is the same process that powers the sun. In the sun's core, where temperatures reach 15,000,000C, hydrogen atoms are in a constant state of agitation. As they collide at very high speeds, the natural electrostatic repulsion that exists between the positive charges of their nuclei is overcome and the atoms fuse. Without fusion, there would be no life on Earth. Significant research has been done to better understand the fusion process since the concept was first theorized in the 1920s. Scientists have answered most of the key physics questions behind fusion. Today, in southern France, 35 nations are collaborating to build the world's largest tokamak—a magnetic fusion device designed to prove the feasibility of fusion as a large-scale and carbon-free source of energy. The ITER project, as it is known, is expected to be the first fusion device to produce “net energy,” which is the term used when the total power produced during a fusion plasma pulse surpasses the thermal power injected to heat the plasma. ITER could be the first fusion device to maintain fusion for long periods of time, and it is expected to be the first fusion device to test the integrated technologies, materials, and physics regimes necessary for the commercial production of fusion-based electricity. “I’m optimistic. I think in 10 to 15 years, we could have a commercial fusion energy plant producing electricity on the grid,” Chuck Goodnight, lead partner in the U.S. on U.S. Nuclear Energy as part of Arthur D. Little’s Global Energy & Utilities practice, said as a guest on The POWER Podcast. If Goodnight’s prediction is correct, the entire landscape of power generation could be transformed not only in the U.S., but also around the world. “In the 1950s, we had very few nuclear power plants, and then in the U.S. within 35 years or so we had 100,” Goodnight said. “I can envision that same future for small modular reactors and fusion—and that could be global in my vision. And at that point, hopefully, there’s renewables, there’s fission, there’s fusion, and there ultimately would be no carbon-based fuel systems running. And people could look around the planet and look back with gratitude to the people of today that have spent time and money and energy and sweat to make these technologies viable and to get them to market and to get them into a grid that is sustainable,” he said. “So, I'm optimistic because we’ve got a lot of smart people and quite a bit of funding now behind these ideas to get these things going, and the government’s behind them and the private equity behind them and private funding and innovative people that are clearly a big part of this. I think there’s a lot of reasons to be optimistic about our future,” said Goodnight.
Nuclear power opponents often point to radioactive waste as one of their main concerns. However, most people don’t realize that problems associated with long-lived waste can actually be solved in an economic way with technology that’s already well-proven. Long-lived actinides can be “burned” in a thorium molten salt reactor (MSR), or a breeder reactor. They do not burn fast, but in this way, it is possible to convert the most problematic part of the waste from something that needs to be stored safely for tens of thousands of years to fission products that only need to be stored safely for about 300 years.
“Breeding is where you actually convert what’s called a fertile fuel—and thorium is one of these fertile fuels—you convert that into something which you can fission, and then you have to make sure that that process actually doesn't stop—that it continues to create more and more new fuel,” Thomas Jam Pedersen, co-founder of Copenhagen Atomics, said as a guest on The POWER Podcast. “That’s what Copenhagen Atomics is trying to prove to the world—that it’s not merely something that you can show from physics that it’s possible, but you could actually also build it and make it work.”
The concept is not new. MSRs—a class of reactors that use liquid salt, usually fluoride- or chloride-based, as either a coolant with a solid fuel or as a combined coolant and fuel with the fuel dissolved in a carrier salt—underwent significant testing in the 1950s and 1960s at the Oak Ridge National Laboratory (ORNL) in Tennessee. Subsequent design studies in the 1970s focusing on thermal-spectrum thorium-fueled systems established reference concepts for two major design variants, one of which was a molten salt breeder reactor with multiple configurations that could breed additional fissile material or maintain self-sustaining operation.
One reason the testing stopped was because thorium is not well-suited for making nuclear weapons, so the military was not interested in investing in the technology. “It was, from the very get-go, far behind the investments in the uranium fuel cycle, and therefore, most people were educated in the uranium fuel cycle,” Pedersen said.
In the late 2000s, that changed, because documents from the ORNL testing were released to the public. “People started to discover, ‘Oh, there’s actually something here that is quite exciting.’ Because thorium is the only element where you can make breeder cycle, or breeder reactor, in thermal spectrum, and thermal spectrum is sort of, you can say, the easy reactors to build,” Pedersen explained.
Copenhagen Atomics’ goal is to have a 100-MWth (roughly 45-MWe) reactor unit available commercially by 2028. Units are expected to be built in a factory, using an assembly-line process, and will be roughly the size of a standard shipping container, which will allow them to be delivered easily to plant construction sites around the world. Customers would be able to install multiple units at a site to effectively create almost any size plant.
The company expects to have a non-fission prototype unit ready for operation next year. “We will be able to test it—it’s a one-to-one scale model of the reactor—we will not be able to run fission inside, but we can start it up and we can pump the salt around and we can test all the systems—see that it’s working,” Pedersen said. Copenhagen Atomics is targeting 2025 to have a fully functioning demonstration reactor in operation.
The cost? “I think it’ll be a much cheaper energy form than classical nuclear reactors, and I think we can even compete with some of the cheapest forms of wind power or solar power,” said Pedersen. Furthermore, the thorium-fueled units will be dispatchable. “We can supply energy 24/7, and therefore, the value of our energy source is higher in the grid than it would be if you buy the same electricity from solar.”
Experts claim power grid infrastructure needs to be upgraded to accommodate the vast amount of renewable energy expected to be added to the system in coming decades. That could require billions of dollars in investments, millions of hours of planning and permitting work, and years of construction in the field. Another option that could help is to optimize existing grid components. While increasing the capacity of present power lines may not preclude the need for upgrades down the road, it could reduce the urgency and eliminate some of the congestion on the system in the near term. One way to maximize line capacity is through closer monitoring of conductors. “LineVision is a grid technology company that is working with leading utilities around the world to solve some of the most critical challenges they’re facing,” Hudson Gilmer, CEO of LineVision, said as a guest on The POWER Podcast. “What we have developed is a platform that uses advanced sensors and analytics to increase the capacity, the resilience, and safety of our electric grid.” “What may be surprising to many of your listeners is that these high-voltage lines—these transmission lines and even distribution lines—that really form the backbone of our electric grid are not monitored today. Utilities have invested a lot in technologies that monitor equipment within their substations, but one of the last frontiers where they don’t monitor the condition of their grid is the overhead lines,” Gilmer said. It may not be obvious to the casual observer, but power lines do move quite a bit. The difference in the sag of a typical transmission line can be several meters. “A hot conductor will sag more than a cool conductor will,” Gilmer explained. “What we’re doing with these sensors is taking advantage of the fact that even a modest amount of wind cooling the line allows utilities to safely put much more power through them than they would if they weren’t monitored and they had to make essentially worst-case, very-conservative assumptions about the conductor’s temperature,” said Gilmer. “So, this allows us to unlock up to 40% additional capacity on existing lines, and that really addresses one of the most important obstacles to a clean energy transition, and that is, increasing capacity on the grid.” LineVision has collaborated on projects with several utilities, as well as with the Electric Power Research Institute (EPRI) and the U.S. Department of Energy (DOE). “We did one recently that was DOE-funded together with Xcel Energy out in Colorado. And we’re really fortunate to have a number of great utility clients and utilities that are really recognized as leaders in the industry. That includes National Grid, includes Dominion, includes Xcel, that includes Duquesne energy in the Pittsburgh area, Sacramento Municipal Utility District,” noted Gilmer. He said LineVision is also working with several other clients that he’s not at liberty to mention at the present time. The technology is not only in demand in the U.S., but also around the world. On Oct. 6, the company announced that Marubeni Corp. would integrate LineVision’s power line monitoring solutions onto the Japanese electric grid. Today, the company announced that a large power utility in Northern Ireland will install its sensors to monitor 33-kV overhead lines in that region. Gilmer said LineVision has also done work in New Zealand, Austria, Slovenia, Greece, Hungary, and Germany, among others. “The reality is that this is a need worldwide as utilities try to connect more renewables to their grid,” said Gilmer. “Traditionally, the only way to expand grid capacity was by very capital-intensive, costly projects—that take five to 10-plus years—to build new lines or upgrade existing lines, and what we represent here is really a new model for how to expand grid capacity by deploying advanced sensors and analytics to get more out of the existing wires,” he explained.
Insiders have long been talking about the energy transition taking place within the power industry. Most of the chatter has revolved around renewable energy, specifically wind and solar power, and the shift from coal- to gas-fired generation in the U.S. However, one expert from the Electric Power Research Institute (EPRI) told POWER that carbon capture and hydrogen are the “most exciting” technologies he sees impacting the energy sector between now and 2050. “The potential of carbon capture in this transition is going to be phenomenal. We have to figure this out. We have to deploy it,” Neil Wilmshurst, senior vice president of Energy System Resources with EPRI, said as a guest on The POWER Podcast. Wilmshurst suggested regulators are the biggest hurdle standing in the way of carbon capture projects, and that it will likely take the work of an organization such as EPRI to overcome the obstacles. He said a group like his “going to the regulators and saying, ‘What are you worried about? What would stop you permitting carbon storage in your area?’ and doing the research to help enable those regulators to make an informed decision” could be a difference-maker in getting projects off the ground. However, the costs associated with adding carbon capture to existing fossil-fueled power plants adds another layer of complexity. When asked about that aspect, Wilmshurst responded, “If you have coal assets or gas assets, they still produce CO2 despite all the improvements being made to them. If we’re going to have those assets actually returning their return on investment out beyond 2030, we need to address carbon capture. So, from my mind, one of the arguments for carbon capture is: we’ve already got some costs and infrastructure—the added cost of carbon capture—weigh those against the cost of shutting an asset down before its end of life. And that is maybe a discussion that isn’t actually thought about sometimes, that it’s not just the cost of the capture, it’s the stranded asset costs if we walk away from some of these gas plants.” Furthermore, Wilmshurst suggested it would be very difficult to meet carbon reduction targets without utilizing carbon capture technology. “When you look at the infrastructure we have today and the options we have to get to 2050, it is a real challenge to see how the U.S. gets to 2050 [goals] without leaning in hard on carbon capture.” Wilmshurst also expressed excitement around the prospects for hydrogen. “As you look at 2050, we cannot get to that zero-carbon target just by removing CO2 from the electric industry, we’ve got to actually remove CO2 from industrial processes, from domestic processes, and hydrogen and other alternative fuels like ammonia—they have a tremendous appeal in that discussion,” he said. EPRI has a Low-Carbon Resources Initiative designed to accelerate development and demonstration of low- and zero-carbon energy technologies. One thing to watch coming out of that initiative is what energy carriers, or energy vectors, are going to become most prominent by 2050. “It’s not going to be the same as it is now,” he said. “What are ships going to be powered by? What are aircraft going to be powered by? What are industrial complexes going to be powered by?” Wilmshurst asked. “We’re seeing people talking about building new nuclear power stations. Traditionally, you talk about new nuclear power stations, they're going to be connected to the grid, they’re going to generate 100% power 24 hours a day, and that’s their role. Now, we’re hearing people talk about producing hydrogen from a nuclear power plant and actually supplying that to industrial hubs. So, this whole change in the role of the energy sector in the next 20, 30 years is probably the most exciting thing out there.”
Is America Ready to Take a ‘Baby Step’ Toward Carbon Pricing? Most people recognize that carbon dioxide (CO2) is a greenhouse gas (GHG), and while not everyone agrees, a majority of climate scientists believe increasing GHG concentrations in the Earth’s atmosphere are causing climate change. Carbon pricing is a market-based strategy for reducing CO2 emissions. The goal of carbon pricing schemes is to place a value on carbon emissions so that the costs can be passed on to GHG emitters, thereby creating financial incentives to reduce emissions. However, enacting a carbon pricing strategy in the U.S. has been difficult. Some observers blame the fossil fuel industry, such as coal mining and oil drilling companies, for lobbying in Washington to halt carbon pricing efforts. Yet, even some fossil-focused groups are getting behind the idea. In March this year, the American Petroleum Institute (API), an advocacy group representing all segments of America’s natural gas and oil industry, endorsed “a Carbon Price Policy to drive economy-wide, market-based solutions.” Another strong proponent of carbon pricing is Neil Chatterjee, a former commissioner and chairman with the Federal Energy Regulatory Commission (FERC), who recently joined Hogan Lovells as a senior advisor in the firm’s Energy Regulatory practice group. As a guest on The POWER Podcast, Chatterjee said, “As someone who had a front row seat to the challenges within competitive power markets in the U.S., I have really come to the conclusion that pricing the externality—putting a price on carbon—is a vastly superior approach to carbon mitigation than subsidies or mandates or over-reaching burdensome regulations. I just think that given those choices—I saw it firsthand—a carbon price is a far more effective and efficient market-based approach to carbon mitigation.” Chatterjee spearheaded an effort to provide clarity for regional transmission organizations (RTOs) and independent system operators (ISOs), which resulted in a FERC policy statement on carbon pricing. Chatterjee said a FERC policy statement is not like a rulemaking, but rather, it provides a roadmap to stakeholders for how to engage with the commission. “I wanted to make clear that: A) the commission didn’t have the ability to unilaterally impose, collect, and administer a price on carbon but, B) that should a state implement a price on carbon that got incorporated into an RTO or ISO tariff, that there was a roadmap whereby the commission could make a determination of whether such a tariff change was just and reasonable,” he explained. “And the reason I think it’s important is I do think you have a couple of RTOs and ISOs who are looking at the possibility of incorporating a carbon price. And some people will say, ‘Well, that’s just a baby step.’ Well, I say, let’s take the baby step. “We’ve had economists across the political spectrum say that this is an effective market-based way to decarbonize,” Chatterjee said. “Let’s take a baby step. Let’s see if an RTO or an ISO can implement a price on carbon, if this iteration of FERC can make the determination that such a price on carbon is just unreasonable, and then let’s see if it works. And perhaps, if we have that successful model within the U.S. power market, and we take that baby step successfully, then maybe other grid operators will take note of that, and you could see further utilization of this market-based tool.”
3D printing is a process used to create an object by sequentially adding build material in successive cross-sections, one stacked upon another. It is a form of additive manufacturing. Once considered more of a novelty, 3D printing has evolved into an incredibly valuable production method used to create very intricate designs, including gas turbine components such as combustors. “We see a lot of activity and creative designs in the combustion section of gas turbines,” Scott Green, principal solutions leader with 3D Systems Inc., said as a guest on The POWER Podcast. “If you look in the combustion can, there’s a lot of really interesting designs for fuel injectors or mixers,” Green said. “It lends itself well to additive manufacturing because everything inside the combustion can is going to fit inside most mid-frame 3D direct-metal printers. They’re not massive components. They’re relatively shoebox-size things that are a part of a bigger system. Now, those are relatively easy for engineers to graph. They can dump a ton of time into making the highest possible efficiency fuel injector, you know, with capillaries, and efficient swirling and mixing structures that are internal, really eliminating tons of braising operations. So, we see a lot of great designs in the combustion can—in the combustion components.” In addition to combustor parts, 3D printing is also used to manufacture stator vanes, impellers, and casings and ducting components for power industry applications. One of the reasons for this is that consolidating multiple-part assemblies into a single part increases manufacturing yield and component reliability, while the integration of highly efficient cooling channels improves thermal performance. Furthermore, new levels of machinery performance can be unlocked using additive manufacturing by improving design features and leveraging extreme temperature-resistant materials. All of this can be accomplished while reducing manufacturing costs and eliminating the need for expensive, long-lead-time tooling and five-axis machining. Many other industries have found 3D printing solutions to be of value too. 3D Systems works extensively with the automotive, aerospace, defense, semiconductor, and healthcare sectors, among others. Figuring out whether 3D printing is right for a specific application comes down to a six-step process, according to Green. He said not every customer will go through all of the stages, but the progression has led to success for many companies. “What we want to do is engage with the customer on their application. We want to learn more about what you do, why you’re interested in 3D printing, and get down to what’s the subject part,” he said. If a customer has a specific problem to solve and a goal in mind, such as improving efficiency by 10% or increasing speed by 10%, the team will work to achieve that outcome. They will consider which parts are suitable for additive manufacturing and which aren’t. “For the ones that are a good fit, let’s help you develop how to make them. So, we’ll recommend which machine will even do the build setup process, the material selection—alloy selection with you—testing and validation, and proving that the process actually works. And then, at that point in time, we can take over to do bridge production, which means we work with you to find the right cost, and the right volume and schedule to make the parts for you,” Green explained. “What we want to do is help deliver a plan to make the thing that solves the problem you have to whoever’s going to utilize the equipment.”
If you’ve flown on a commercial airplane, you’ve likely sat within a hundred feet of an operating gas turbine engine. Gas turbines have been used to power aircraft since the 1940s. But gas turbines like those on airplanes are also used for generating electricity. These designs are known as aero-derivative gas turbines and occupy a special place in the power market. Aero-derivative gas turbines are popular because of their reliability, efficiency, and flexibility. They are significantly lighter, respond faster, and have a smaller footprint than their heavy-duty counterparts, which makes them much easier to utilize for temporary purposes and in applications that require mobility. “If you look at the high-level goal for the industry in terms of decarbonization, grid resilience, resource adequacy, and affordability, the aero-derivatives fit perfectly in all those categories,” Harsh Shah, vice president of sales and business development with Mitsubishi Power Aero, said as a guest on The POWER Podcast. “We provide solutions that generate power from 30 MW to 140 MW, and we see a very strong demand for these products across the globe—everywhere—in developed nations, developing nations, whether it’s industrial, utilities, independent power producers, and even captive power producers.” Shah said the main reason for the demand is that when customers require fast-track power solutions, and can’t wait years between signing a contract and having the power come online, aero-derivatives are often the best option. “When time is an important factor, the aero-derivative solution is very important,” he said. Shah offered a recent example to demonstrate how quickly aero-derivative gas turbines can be deployed. Mitsubishi Power Aero (previously PW Power Systems, the company underwent a rebranding on April 1) worked with Mexico’s state-owned power utility, Comisión Federal de Electricidad (CFE), to add 150 MW of generation to help meet summer demand in the Mexicali, Baja California region. Negotiations began in January this year, and the capacity was available to the grid less than four months after the contract was signed. “We supplied five MOBILEPAC units. These are trailer-mounted, very-mobile, very-compact units—don’t require any site preparation, in terms of, you don’t need a concrete foundation, minimal work required at the site,” said Shah. “From the time we signed the contract, within 110 days we had power up and running.” Time plays into another benefit of aero-derivative gas turbines in that they can go from completely cold to full power very quickly. “Our aero-derivatives offer a very unique value proposition to our customers, whereby, we would be fully up and running in less than 10 minutes, and we’re pushing that envelope to lower and lower times—five minutes and such,” Shah said. Flexibility is also an important feature. “This is flexibility from different perspectives. You could have flexibility in terms of the ramp rates—how quickly you can go up and down. And this is especially important as across the globe you have more and more renewables on the grid. You need solutions that can cover when the sun is covered or the wind power drops off. So, the ramp up, ramp down, and fast responsiveness gives the very-much-required flexibility,” Shah said. “In addition to that, we get flexibility because of multifuel capability—whether you are using gas or liquid fuel. You also have flexibility for dual frequency in 50 or 60 Hz. And then the last aspect of flexibility that I will touch is very high power density. … Optimal use of land is very important, and the high power density of our solutions is creating a lot of demand.”
It’s not unusual for species to go extinct; it happens all the time. In fact, scientists estimate that at least 99.9% of all species of plants and animals that have ever lived on Earth are now extinct. That’s pretty amazing, considering how many species still exist—up to 8.7 million, according to some experts. Mass extinction events, however, are not so common. A mass extinction event is when more than half of all species living at a given time go extinct over a relatively short period. The American Museum of Natural History found five significant mass extinction events in the Earth’s history that it thought were worth highlighting on the museum’s website. The largest of these happened about 250 million years ago, when up to 95% of existing species died out. Another that people may find particularly noteworthy occurred 65 million years ago. That one took out the dinosaurs, marking a major turning point in history. What hasn’t happened in the past is a mass extinction event caused by humans. However, Richard Heinberg, author of the soon-to-be-released book titled Power: Limits and Prospects for Human Survival, thinks that may be coming, and some of the reasons are detailed in his 416-page book. “The book is a ‘big picture’ book, and I address three huge questions in it. One is: How did we—just one species—come to overpower the rest of nature to the point where we’re changing the climate and triggering what looks like it may be a mass extinction event? The second question is: How have we come to oppress one another in so many and so brutal ways? And the third is: Is there any way we can come to terms with power in such a way as to turn things around?” Heinberg said as a guest on The POWER Podcast. Heinberg said people around the world must switch from fossil fuels to alternative energy sources to limit climate change, but he was pessimistic about the prospects for doing so quickly enough to make a difference in the long term. “It’s going to be very, very difficult to do that in fact, and for a number of reasons,” said Heinberg. “One, of course, is just the fact that solar and wind, which are our main candidates for replacing fossil fuels, they produce electricity, but electricity is only about 20% of global energy usage. So, the other 80%, we use solid, liquid, and gaseous fuels for agriculture and transportation, and industrial processes like smelting metals, and making cement for concrete, and on, and on, and on—a lot of high-heat industrial processes. Those things are going to be hard to electrify.” The only way to “get to the other side,” according to Heinberg, is for people in industrial countries such as the U.S. to reduce their overall energy usage pretty substantially. “That sounds really daunting, but it certainly is possible to do,” he said. “Europeans use half the energy that Americans do, and yet their quality of life is quite acceptable by anybody’s standards. So, we’re going to have to find ways of providing basic human needs in ways that use the least amount of energy, and then supply renewable energy for those purposes.” “I speak frequently to experts, not just in climate science, but in other environmental fields and social fields and so on. And everyone that I talk to is really, really concerned about where all of this is headed. So, if you’re worried, you’re not alone, the experts are worried too. But, we really have to start talking honestly with each other about all of this and getting our heads out of the sand because it’s just too easy to live in denial,” Heinberg said. “We’re going to have to step up to the plate and really show that we’re a species that deserves to survive.”
Decarbonizing the Power Grid with Hydrogen and Advanced Technology Many leaders around the world are focused on decarbonizing their countries’ energy supplies. For most, that means adding renewable energy resources to their electricity mix, and developing a path aimed at retiring coal and other fossil-fueled power plants. Yet, these are not the only decarbonization options. Research and development (R&D) efforts are also ongoing to expand the use of hydrogen and energy storage, and advance new technologies, such as carbon capture and artificial intelligence, in an effort to reduce carbon emissions. “I think there is a clear sign right now that the world has made the choice, and the choice is clearly the zero-CO2 emission,” Karim Amin, executive vice president of Generation with Siemens Energy, said as a guest on The POWER Podcast. “So, that's a given, and we are all working towards achieving this target.” Siemens Energy sees hydrogen as an important piece of the decarbonization puzzle. The company is working to bring the cost of hydrogen down through advances in its electrolyzer technology. Siemens Energy also has a very clear roadmap to make its advanced heavy-duty gas turbines capable of operating on 100% hydrogen before 2030. “Two years ago, we were barely at 30% of hydrogen co-firing. Today, our HL gas turbine is up to 50%, and some of our decentral gas turbines [are] up to 75%,” Amin said. “We are confident to be able to develop the technology, which is mainly around the combustion system in the gas turbine, to be able to handle 100% of hydrogen.” Most of the hydrogen produced around the world today comes from natural gas, which is often called “gray” hydrogen. In order to decarbonize the energy supply, it’s important for “green” hydrogen, which is produced from renewable energy resources, to replace the gray hydrogen. However, gray hydrogen is currently much cheaper than green hydrogen. “The cost right now to produce green hydrogen is rather expensive,” Amin said. “The technology is still not there to bring the cost of the hydrogen to affordable levels, and that’s what we are working on, and other players also in the industry [are] working on, to bring the cost of hydrogen down to levels that can be also sustainable in the future.” Amin made it clear, however, that hydrogen isn’t the only piece of the decarbonization puzzle. “Hydrogen is only one part. There are technologies around carbon capture—technologies, which we are also working on. There are technologies around storage, as I said. There are technologies around upgrading existing fleets. There is even a big part to be played by artificial intelligence, algorithms, and digitalization,” he said. “There [are] new horizons for the industry to explore and to take us to the next level, and that’s what we are investing in and working upon, besides all the other things that we talked about,” Amin concluded.
Leveling the Market Playing Field for Hybrid Power Plants The Federal Energy Regulatory Commission (FERC) is an independent agency that, among other things, regulates the interstate transmission of electricity. Its ultimate mission is to “Assist consumers in obtaining economically efficient, safe, reliable, and secure energy services at a reasonable cost through appropriate regulatory and market means, and collaborative efforts.” In the past, FERC has issued important orders, including 841 and 2222, which have helped clear the way for more energy storage to be added to the U.S. power grid. However, Chip Cannon, a partner with Akin Gump Strauss Hauer & Feld LLP, who heads the firm’s energy regulation, markets, and enforcements practice, believes the playing field requires further leveling for hybrid plants, that is, facilities pairing solar or wind farms with battery storage. Cannon said few hybrid plants existed on the grid a few years ago, but that is changing quickly. In fact, he said there are 102 GW of solar plus storage and 11 GW of wind plus storage capacity in the interconnection queue at the present time. “We have battery storage resources, typically paired with renewables, that are entering the interconnection queue at a very, very fast clip,” Cannon said as a guest on The POWER Podcast. That has created some challenges for the market. “The queue process has not really been set up for accommodating these hybrid resources, and we really don’t have very much experience for them in the market,” said Cannon. Hybrid plants offer a number of physical and operational traits that benefit the power grid. Solar and wind resources are obviously intermittent, meaning they only produce power when the sun shines and the wind blows. When paired with energy storage, which can be used to either add or remove energy to and from the grid, intermittency problems can be alleviated. The pairing also improves reliability, flexibility, and resiliency, and can help lower costs for consumers. Cannon explained that all of the regional transmission organizations (RTOs) and independent system operators (ISOs), such as PJM, CAISO, and NYISO, establish the “rules of the road” for generators to participate in their energy capacity and ancillary services markets. “But those market rules were not designed to reflect resources that can both take in energy as well as put energy on the grid. So, the concern here right now is that the market designs were simply not set up to accommodate energy storage resources,” Cannon said. While FERC doesn’t have the authority to establish rules that promote energy storage, it can look at the existing market rules to see if they are unduly hindering the ability of certain classes of resources to participate and compete in those markets. Cannon said FERC has held a technical conference regarding hybrid resources, which allowed various stakeholders to provide input. It also directed RTOs and ISOs earlier this year to submit information on how their markets are setup to accommodate hybrid resources. Cannon suggested it will be interesting to see how FERC ultimately addresses the issue. “We’re definitely at an inflection point in the power sector. I think the power sector has been going through an evolution for a couple of decades since FERC started going down the path of competition, and now we’ve got this radically new resource mix,” Cannon said. “I’m of the view, though, that the evolution is really turning into a revolution of the power sector with the speed of technological changes and falling prices. So, there’s a lot of really good stuff out there.”
Brazil is blessed with a wealth of natural resources. It gets almost two-thirds of its electricity from hydropower facilities, and it also has enormous potential for wind, solar, and natural gas-fired power. Yet, the country is saddled with higher than average electricity prices compared to most developed nations. A study conducted by McKinsey & Company analysts found that Brazil’s electric power rates for captive industrial consumers were 65% higher than rates in the U.S. in 2019, and 35% greater than Canada’s, which has a similar reliance on hydropower. “The price of energy in Brazil only goes one way, and that’s up,” Lisarb Energy Chairman Jamie MacDonald-Murray said as a guest on The POWER Podcast. “It's driven by inflation, but largely, it’s also driven by the fact that the grid operators are having to reinvest in the infrastructure. They’re having to renew the grids. They’re having to add capacity and modernize the grid, and that cost they’re passing on to the consumer.” Lisarb Energy is focused on developing large-scale solar projects in Brazil. These include distributed energy solar parks for the corporate power purchase agreement (PPA) market, as well as high-yielding utility-scale solar parks for the free market and government auctions. The company was established in 2017, and has already become one of Brazil’s fastest growing solar developers. “We’ve been very successful,” MacDonald-Murray said. The ability to lock in power prices through a PPA is one of the key incentives for Lisarb Energy’s corporate clients, according to MacDonald-Murray. “We now have over 200 MW of PPAs signed with some of Brazil's largest companies, and we have another 700 MW in various stages of negotiation that I think will close out 2021 with just over 1 GW of corporate PPAs signed,” he said. The fact that legislation will be enacted next year requiring solar generators in Brazil to contribute money toward distribution costs has incentivized PPA agreements in the near term. “The price that we can offer won’t be as attractive [in 2022] because obviously, if we’re going to have to start contributing to distribution costs, then, obviously, we’re not going to be able to offer such a competitive price to our off-takers,” said MacDonald-Murray. Still, Lisarb Energy believes solar power’s growth potential in Brazil is enormous. The company cited a forecast by the Brazilian Solar Photovoltaic Energy Association, ABSOLAR, which says “solar will take the largest share (38%) of the Brazilian electricity matrix, producing 125 GW by 2050.” Brazil’s government recently exempted various types of solar equipment from a 12% import duty, which Lisarb Energy said shows that officials recognize “the strategic importance of the solar market.” Lisarb Energy has already secured land for 3 GW of solar PV development in Brazil. The majority of the company’s existing projects are smaller in size (about 2.5 MW), but it is currently working with a mining company on a 250 MW system. “That one’s slightly different,” said MacDonald-Murray. “We’re working with a partner to provide a battery system to obviously increase the usability of the energy that’s generated.”
According to a report released in 2019 by the U.S. Department of Energy, geothermal electricity generation could increase more than 26-fold by 2050—reaching 60 GW of installed capacity. That may seem like a pipe dream to some power observers, but if new well-drilling techniques allow enhanced geothermal systems to become economical, the reality could be much greater. In fact, Quaise Energy, a company working to develop enabling technologies needed to expand geothermal on a global scale, claims as much as 30 TW of geothermal energy could be added around the world by 2050. Most of the geothermal systems that supply power to the grid today utilize hydrothermal resources. These tap into naturally occurring conditions in the Earth that include heat, groundwater, and rock characteristics (such as open fractures that allow fluid flow) for the recovery of heat energy, usually through produced hot water or steam. Enhanced geothermal systems contain heat similar to conventional hydrothermal resources but lack the necessary groundwater and/or rock characteristics to enable energy extraction without innovative subsurface engineering and transformation. The technology that Quaise Energy is working on would allow drilling down as far as 20 kilometers (12.4 miles) to utilize heat from dry rock formations, which are much hotter and available in almost all parts of the world. “The key thing is we’re going for hotter rock, because we want the water to get hotter,” Carlos Araque, CEO of Quaise Energy, said as a guest on The POWER Podcast. “We want it even to be supercritical, which is the fourth phase of water—when it goes above a certain temperature and pressure—that’s what we’re looking for.” But drilling to those depths is difficult. “It really boils down to temperature,” Araque said. “The state-of-the-art of drilling technologies is in the 200C neighborhood, and the reason for that is electronics that go with the drilling systems. Making higher-temperature electronics is a very, very difficult task.” Another problem is the hotter the rock gets, the faster drill bits wear out. “So, if you imagine drilling at five kilometers below the surface of the earth, your drill bit will only last a few hours, because the rock is so hot and so hard,” said Araque. He explained that pulling the drill string out of a five-kilometer-deep hole so that the drill bit can be changed, and then pushing it back into the hole can take a significant amount of time. “So, a week to pull out of the hole, a few hours to change the drill bit, a week to push down into the hole to drill a few more hours. It becomes exponentially impossible to do that,” he said. “That’s where the drilling technology that we’re proposing comes into play. We’re basically trying to do directed-energy drilling with millimeter waves,” Araque said. “Imagine a microwave source on the surface, it’s called a gyrotron. We beam this energy through a pipe into the hole. Together with this energy, we push a gas—could be nitrogen, could be air, could be argon, if necessary—and at the bottom of that pipe, this energy comes out, evaporates the rock, and the gas picks up the vapor of that rock and pulls it back out. What comes out of the hole looks like volcanic ash, and the hole actually burns its way down, you know, five, six, 10, 15, 20 kilometers, as needed, to get to the temperatures we’re looking at.”
Open-Source Technology Benefits Transmission and Distribution Operators The term “open source" is well-recognized in the technology world, but may not be as widely understood in other sectors. What open source means is that the software code is publicly available so that anyone can contribute to the code base and create add-on extensions. This enables the growth of a market of providers that can offer hosting and add-on functionalities that can be utilized by all users. In the energy sector, LF Energy has taken a leading role in facilitating the development of open-source technology. LF Energy is part of The Linux Foundation, which is the umbrella organization for more than 425 open-source projects. Among LF Energy’s projects are platforms that help automate demand response; assist electricity, water, and other utility operators in managing systems; monitor and control microgrids and other distribution assets; and perform dynamic power flow simulations, among other things. Arjan Stam, director of System Operations with Alliander (a distribution system operator [DSO] in the Netherlands), and Lucian Balea, research and development program director and open-source manager with RTE (a transmission system operator [TSO] in France), were guests on The POWER Podcast and explained how open-source technology is being used by their companies. “We are talking about applications that would help assist the grid operators in operational control rooms to manage the power system in real time. We are talking about applications that help us to simulate the behavior of the power system to make sure that we can operate under safe conditions. We are talking about application that would increase the automation of the power grid so that the grid can react automatically in an optimized manner,” Balea, who is also the board chair for LF Energy, said. Stam, who is also an LF Energy governing board member, said DSOs are less experienced than TSOs when it comes to managing energy flows on the grid. He suggested it’s hard to start from scratch in developing greater power management capabilities. “It's really helpful if you can find an example that you can use to build this new capability,” said Stam. With open source, that’s what Alliander found. “We needed also new applications, and also the knowledge you need, and standardization you need, and interoperability you need,” said Stam. “The best way to build that and to create it is with other parties that have the same challenges. And that’s what we found in working with open source. So, it delivered us quite a lot.” Stam suggested open-source technology can also help speed the transition to renewable energy. In order to increase the level of renewable energy in the system, he said, “we need quite specialized applications that are not yet really available in the market.” However, by teaming up with other companies that have the same needs, development of the technology can happen more quickly. “And that’s actually what’s happening in open source,” Stam said. “Open source has to be seen as an accelerator. That’s the lesson that we learned from the experience of other industries,” Balea said, specifically mentioning cloud services as an example. He said by relying on open-source collaboration, cloud services technology was built and scaled very quickly. “In LF Energy, we apply this open-source acceleration lever to a great cause, that is, the energy transition,” Balea said. “If we look at the projects that we have, they are all guided by the need to adapt to a future energy system that will have to cope with a high share of distributed renewable energy resources.”
The Benefits of Flow Batteries Over Lithium Ion Lithium-ion (Li-ion) is the most commonly talked about battery storage technology on the market these days, and for good reason. Li-ion batteries have a high energy density, and they are the preferred option when mobility is a concern, such as for cell phones, laptop computers, and electric vehicles. But there are different energy storage technologies that make more sense in other use cases. For example, iron flow batteries may be a better option for utility-scale power grid storage. An iron flow battery is built with three pretty simple ingredients: iron, salt, and water. “A flow battery has a tank with an electrolyte—think of it as salt water to be simple—and it puts it through a process that allows it to store energy in the iron, and then discharge that energy over an extended period of time,” Eric Dresselhuys, CEO of ESS Inc., a manufacturer of iron flow batteries for commercial and utility-scale energy storage applications, explained as a guest on The POWER Podcast. Iron flow batteries have an advantage over utility-scale Li-ion storage systems in the following areas: • Longer duration. Up to 12 hours versus a typical duration of no more than 4 hours for large-scale Li-ion systems. • Increased safety. Iron flow batteries are non-flammable, non-toxic, and have no explosion risk. The same is not true for Li-ion. • Longer asset life. Iron flow batteries offer unlimited cycle life and no capacity degradation over a 25-year operating life. Li-ion batteries typically provide about 7,000 cycles and a 7- to 10-year lifespan. • Less concern with ambient temperatures. Iron flow batteries can operate in ambient conditions from –10C to 60C (14F to 140F) without the need for heating or air conditioning. Ventilation systems are almost always required for utility-scale Li-ion systems. • Lower levelized cost of storage. Because iron flow batteries offer a 25-year life, have a capital expense cost similar to Li-ion, and operating expenses that are much lower than Li-on, the cost of ownership can be up to 40% less. “People have been really interested in flow batteries for a lot of reasons, but the most common one that you’ll hear about is the long duration,” said Dresselhuys. So, why haven’t iron flow batteries overtaken Li-ion batteries in the power grid storage market? “I think lithium has had an advantage for a couple of reasons historically,” Dresselhuys said. “The first is that it’s been more broadly available.” Dresselhuys explained that even though Li-ion batteries weren’t specifically developed for grid applications, the fact that they are well-suited for cars and other uses, where the energy density that lithium provides has real advantages, allowed manufacturing efficiencies to develop. That, in turn, has brought costs for Li-ion down and accelerated growth. Therefore, it’s taken some time for other technologies to catch up. Still, there are companies implementing iron flow battery projects. ESS announced in April that it had contracted with a Chilean utility to provide a flow battery system for use in the environmentally pristine Patagonia area. ESS’s 300-kW/2-MWh Energy Warehouse system will be integrated with renewable resources in a local microgrid with the aim of eliminating about 75% of the diesel-fueled generation previously used to power the area. “The project there was actually originally designed and spec'd out to be a lithium project, because, of course, that’s what people thought was available,” said Dresselhuys. ESS’s team of experts talked to the owners about the advantages of the iron flow battery system and came away with the order.
Looking for Carbon-Free Energy Resources? Don’t Forget Nuclear Power As leaders around the world take steps to decarbonize energy supplies, many people have focused their attention specifically on wind and solar power. What they may fail to recognize is that nuclear power provides more electricity in the U.S. than all other carbon-free sources combined. This is true in some other countries, such as France, Sweden, and Ukraine, as well. “I think it’s a really exciting time to be in [the nuclear power] industry, not only because of all the technology that is starting to really be leveraged and come all together into a system to deploy a new reactor concept, for example, but the fact that our product has always been a clean energy source,” Dr. Rita Baranwal, former head of the U.S. Department of Energy’s (DOE’s) Office of Nuclear Energy, who now serves as vice president of Nuclear Energy and Chief Nuclear Officer with the Electric Power Research Institute (EPRI), said as a guest on The POWER Podcast. “It can be a solution to decarbonization, not only for states and countries, but the world as a whole. And so, to me, it’s a very exciting time and a great time to be in the business,” she said. EPRI is an independent nonprofit organization that conducts research, development, and demonstration projects in collaboration with the electricity sector and its stakeholders. It focuses mainly on electricity generation, delivery, and use, with a goal of benefiting the public, and the organization’s U.S. and international members. EPRI has many programs designed to support the nuclear industry including in the areas of materials management, fuels and chemistry, plant performance, and strategic initiatives. “Some of the things that we’re working on are deployment of small modular reactors—SMRs—and other advanced technology. We at EPRI have partnerships in this area with Kairos, NuScale, and LucidCatalyst. That’s one area. The other is around workforce opportunities and development. EPRI does a lot of work in developing training and delivering that kind of training,” Baranwal said. While most of the world’s existing reactors are large units with capacities as high as 1,000 MW and greater, advanced designs, such as the SMRs Baranwal mentioned, may open up opportunities to use nuclear power in new applications. For example, microreactors with capacities under 10 MW may be suitable for use in very remote areas or on islands. They could also be important for Department of Defense installations. “Let’s talk about Alaska,” said Baranwal. “Right now, they rely on extensive diesel to be driven in to help generate electricity for them. If you can envision a microreactor instead, you are reducing the reliance on that fossil fuel and also creating small communities that can have a microgrid and a microreactor, and be very self-sustained.” She suggested a similar arrangement could be used in places like Puerto Rico. Baranwal said what keeps her enamored with the nuclear industry is its clean-energy attributes. “I want to leave our environment as good or better than what we are experiencing today, and I know that nuclear—it being a clean energy source—will absolutely have a vital role to play in the decarbonization efforts that we’re all experiencing and trying to accomplish,” she said.
How Artificial Intelligence Is Improving the Energy Efficiency of Buildings. A lot of energy is consumed by buildings. In fact, the Alliance to Save Energy, a nonprofit energy efficiency advocacy group, says buildings account for about 40% of all U.S. energy consumption and a similar proportion of greenhouse gas emissions. Some estimates suggest about 45% of the energy used in commercial buildings is consumed by heating, ventilation, and air conditioning (HVAC) systems, of which, as much as 30% is often wasted. Most power companies these days have energy efficiency programs that help customers identify waste and implement energy-saving measures, but there are also non-utility providers working on solutions. Montreal, Canada–based BrainBox AI is one of them. It’s using artificial intelligence (AI) to significantly reduce energy consumption in buildings. “We’ve developed an autonomous artificial intelligence technology that applies to commercial buildings in order to render their heating and cooling needs, which is typically the single largest consumer of energy in a building, and to make those much more efficient and certainly much more flexible to outside demands and occupant demands,” Sam Ramadori, president of BrainBox AI, said as a guest on The POWER Podcast. The company’s autonomous AI HVAC technology studies how a building operates and analyses the external factors affecting it. It identifies potential improvement opportunities and then acts to optimize the building’s system. It requires no human intervention and reacts to changes in the built environment immediately to maintain the highest tenant comfort and energy efficiency at all times. “What’s exciting is you don’t have to picture a room full of dozens of engineers managing and monitoring these buildings. It’s truly the AI optimizing the building in real time without human intervention,” Ramadori said. Surprisingly, the BrainBox technology does not require any changes to be made to most buildings’ HVAC systems. It simply connects to what’s already installed and utilizes existing sensors and data, along with third-party resources such as weather forecasts and occupancy information, to drive decision-making. It’s easy to imagine how a building’s HVAC needs change through the course of a day. For example, east-facing offices may require more cooling in earlier parts of the day as the sun rises, while west-facing offices may require more cooling later in the day as the sun shines through windows in the afternoon. The BrainBox technology accounts for those sorts of changes and adjusts dampers to keep each zone optimally heated or cooled. But it doesn’t end there, the AI is constantly learning and evolving. Ramadori explained how changes in a building’s surroundings would also be picked up and accounted for by the technology. “What happens if across the street on the south-facing side, right now there’s a parking lot, and then in a year, they build up a tower right next to it? Well, what happens, that tower is now throwing shade onto part of your building for a part of the day. So suddenly, the behavior of those rooms has changed,” Ramadori said. “What’s exciting is no one has to tell the AI that there’s a building that just went up next door, it will just learn that ‘Wait a second, those rooms that used to get hot at noon, you know, for the bottom half of my building, no longer are getting that hot anymore.’ It doesn’t know why, but it doesn't matter. It just knows. It’ll relearn—by itself without a human reprogramming it—it’ll relearn the new behavior caused by that building built next door.” “We’re cutting energy consumption in a building typically by 20 to 25%—so, it’s a large reduction—and we do so without turning one screw, which makes it super exciting and powerful,” said Ramadori.
Serious Power Transmission without Wires Is Closer Than You Think Most people are aware that wireless charging technology is available today for small electronic devices, such as cell phones and watches, but when it comes to larger-scale power systems, the concept of wireless transmission of electricity probably seems like science fiction. The truth, however, is that systems have been developed and are being tested that could result in kilowatts of power being transmitted over distances of kilometers very soon. “We are looking to have these sort of higher-power, kilowatt-class devices at kilometer-scale distances out for early customer testing and use in the next couple of years,” Tom Nugent, co-founder and CTO of PowerLight Technologies, said as a guest on The POWER Podcast. Unlike most wireless cell phone chargers, which produce a magnetic field that a small coil in the device receives and harvests energy from to charge the battery, PowerLight uses optical power beaming technology, which converts electricity into high-intensity light. PowerLight’s system then shapes, directs, and beams the light to a specialized solar cell receiver that converts the light back to direct-current power. Through the beam, the company says “power can travel over long distances, at high altitudes, and in the deep sea—maintaining uptime, from near and far.” The innovative beam-shaping design “optimizes the energy of the beam at the start, to minimize losses across the transfer medium and maximize power in the end.” “This is a way to take energy from somewhere where it’s easy to generate or access, whether that’s a generator or an electrical outlet, and we convert that electricity into light, and then project it either through the air or through optical fibers to some remote location where it may be very difficult to get power to,” Nugent said. “What this really is, is a wireless extension cord.” PowerLight has already conducted demonstrations in which it delivered as much as a kilowatt of continual power. “One of the advantages of using near-infrared light, as we do, is that it allows you to go very long distances—kilometers or even more,” said Nugent. In fact, the company has delivered power over distances of one kilometer in demonstrations. Currently, PowerLight is focused on providing solutions for the telecommunications and construction industries, and for the military. Some of the applications that seem particularly promising include powering communication nodes, security sensors, and drones. However, as the technology evolves, Nugent envisions scenarios where megawatts of power could be delivered over hundreds of kilometers to remote military bases or small islands—places where it would be impractical to run wires. Nugent said PowerLight is getting very close to releasing some new products to the market. “It’s something that many people haven’t heard of, or don’t realize where the technology is, and it’s actually much, much closer to reality than a lot of people may have thought,” he said.
What’s Been Holding Hydrogen Fuel Cells Back, and How to Change That The technology used in modern hydrogen fuel cells is not new. In fact, NASA used fuel cells for its manned space missions in the 1960s. But fuel cells have not really “taken off” (pardon the pun) in earthly applications since that time. Some industry insiders believe that will change very soon. “We’ve been sort of monitoring hydrogen for a number of years and doing some research in it, and it became clear to us over the past few years that hydrogen can play a huge role in fighting the climate crisis and decarbonizing hard to decarbonize sectors,” Amy Adams, vice president of Fuel Cell and Hydrogen Technologies with Cummins, said as a guest on The POWER Podcast. Among the ways Adams envisions hydrogen being utilized is in fuel cells powering such things as trucks, buses, trains, and ships. There are also stationary applications, including for electric power generation, that could be a good fit. So, what’s been hindering deployment of fuels cells to date? Adams suggested there were four main things holding back widespread adoption of the technology. “First of all is just technical readiness,” said Adams. However, she noted that fuel cell technology has been evolving, and advancements have led to longer-lasting, better-performing, more-efficient, and larger-scale fuel cell systems. “They’re now ready for primetime, if you will, in several applications.” Another barrier has been infrastructure readiness. “That’s got two pieces,” Adams said. “One is the availability of hydrogen, so having hydrogen refueling stations, and then the cost of the hydrogen at the pump.” Adams noted that Cummins has been involved in a number of refueling station projects that use electrolyzers to produce hydrogen. The company has also partnered with ETC in a joint venture called NPROXX, which is based in Europe and will provide customers with hydrogen products for both on-highway and rail applications. Adams said many companies within the industry are working to address the infrastructure challenge, so she expects that to build out over time. A third obstacle has been regulation, but policymakers around the world are beginning to help on that front too. “We continue to see a lot of government activity to accelerate the role of adoption, both through mandates and incentives, tax credits, carbon taxes, etc. So, that’s going to help accelerate investment in both innovation and R&D [research and development], as well as larger-scale deployments,” she said. Lastly, in the past, total cost of ownership has not been where it needed to be. “With any technology adoption, it has to make sense for the customer from a business perspective,” said Adams. But that is also changing. “The costs have come down significantly, and will continue to go down as we go throughout this decade,” she said. According to Cummins’ total cost of ownership analysis, fuel cells will reach parity with diesel engines in heavy-duty truck applications by 2030 or sooner. “We’ve seen positive progress in all of those areas, which is why we see increased interest now and what we believe will be increased adoption over the next few years,” Adams said. One country that has already seen significant growth in fuel cell usage is South Korea. POWER reported on three new electricity generating facilities based on fuel cell technology that were deployed in South Korea last summer: a 50-MW power plant placed in service by Hanwha Energy at its Daesan Industrial Complex in Seosan, a 19.8-MW installation in Hwasung, and an 8.1-MW facility in Paju. “Part of the magic that we’re seeing in Korea as it relates to stationary power using fuel cells is incentives,” said Joe Cargnelli, director of engineering for Cummins’ Fuel Cell and Hydrogen Technologies division. “So, they have incentives that promote the deployment of stationary fuel cells and [they’ve been] highly successful, and I think it’s a great strategy.”
Solar Energy in the Sunshine State: FPL Leads the Way Florida is known as “The Sunshine State,” so it’s no surprise that solar energy is growing rampantly across the state. Among the utilities adding solar resources to their energy mixes is Florida Power and Light Co. (FPL). FPL claims to be the largest energy company in the U.S. as measured by retail electricity produced and sold. The company serves more than 5.6 million customer accounts supporting more than 11 million residents across Florida. FPL—a subsidiary of Juno Beach, Florida-based NextEra Energy—says it operates “one of the cleanest power generation fleets in the U.S.” “We are big fans of solar energy, and we’ve been working to advance solar in the state for more than a decade,” Jill Dvareckas, senior director of development with FPL, said as a guest on The POWER Podcast. “We currently have 37 solar energy centers in operation, with seven more under construction, which makes FPL the largest producer of solar power in Florida.” FPL stuck its proverbial “toe in the water” back in 1984 when it constructed a 10-kW PV facility in Miami, but it didn’t really get serious about solar until 2009 when it built a 25-MW solar energy center in DeSoto County. Since then, 35 similarly sized installations (74.5 MW each) have been added. “Our commitment to clean energy is evidenced by our groundbreaking ’30-by-30’ goal to install 30 million solar panels by the year 2030,” Dvareckas said. If the company succeeds in reaching that target, solar energy will make up about 20% of FPL’s power capacity at the turn of the decade. In her position, Dvareckas is also responsible for the deployment of other cutting-edge technology, including electric vehicle (EV) and battery storage programs. “There’s no doubt that the electric transportation revolution is underway already,” she said. “FPL has been investing in clean transportation for over a decade. We were the first electric company in America to place the hybrid electric bucket truck into service in 2006.” Today, the company has one of the largest “green” fleets in the nation, with nearly 1,800 vehicles that are either biodiesel-fueled, plug-in hybrids, or EVs. FPL also has an EV charging infrastructure pilot program, called FPL EVolution. “Our goal with the program is to install 1,000 charging ports in 100 locations in our service area across the state to increase the availability of universal EV charging by 50%,” Dvareckas said. Ultimately, more chargers means less range anxiety for EV owners, which many consumers cite as a reason for not wanting to purchase an EV. “From our perspective, this is a pilot program that is really enabling us to learn as the utility ahead of mass adoption to ensure that the infrastructure upgrades and placement that we’re making in the future is done in a thoughtful manner that benefits all of our customers,” said Dvareckas.
Understanding Energy Crises of the 1970s and Avoiding Problems Today. If you were alive and living in the U.S. during the 1970s, you probably remember waiting in long lines to fill your car with fuel. Yet, gasoline wasn’t the only item in short supply during the “Me Decade”—natural gas was seemingly running out and electricity demand was growing so much that new power plants were going up all over the country. “I would argue, and I think a lot of historians would agree with me, that the 1970s was the most important decade in U.S. energy history, and I say that because of the gasoline interruptions. We had three big crises in the Middle East that reduced our supplies of oil, and that got so bad that at one point, in some states, less than 50% of the stations had any gasoline to sell at all,” Jay Hakes, author of the forthcoming book Energy Crises: Nixon, Ford, Carter, and Hard Choices in the 1970s, said as a guest on The POWER Podcast. “It was also a time where electric demand was expanding at a very rapid rate. There was a lot of optimism that nuclear would fill most of that void,” Hakes said. However, as fate would have it, the Three Mile Island (TMI) accident in 1979 pretty much put an end to the nuclear power construction heyday. In addition to writing books, Hakes has served as the administrator of the U.S. Energy Information Administration during the Clinton administration and as director for Research and Policy for President Obama’s BP Deepwater Horizon Oil Spill Commission. He was also the director of the Jimmy Carter Presidential Library for 13 years, and he has had access to some of President Carter’s personal diaries, giving him unique insight into the events that occurred during Carter’s presidency. “Jimmy Carter worked for Admiral Rickover when they developed the first nuclear submarine,” Hakes pointed out. “So, he actually knew the technology of nuclear reactors—obviously better than any president and better than some of the people that worked at the Atomic Energy Commission.” Carter had also spent time on recovery efforts after the world’s first nuclear accident, which was at the Chalk River site in Ontario, Canada, in 1952. Carter was part of a group that was sent into the containment vessel to clean it up. “So, he would be the best president you’d want to have if there was a nuclear accident.” Hakes noted that reports being sent to the president during the first couple of days after the TMI accident were mostly positive. However, on the third day, Carter decided he needed someone with technical expertise at the site to provide him with better details, so he had a direct phone line set up with Harold Denton, who was onsite following the situation as the head of nuclear reactors for the Nuclear Regulatory Commission. “The short story is the coolant system, which keeps the core from melting, broke down, but the containment vessel—that four-feet thick concrete structure that is around the reactor—did its job, and so, very little contamination reached the public,” Hakes said. Following the incident, Carter formed a commission to investigate and recommend reforms for the nuclear industry. “I think that commission did an excellent job,” said Hakes, noting that many improvements were made based on the lessons learned. “The industry and the government both did a good job of fixing those safety problems. So, you know, in that sense, it’s a good model for dealing with energy crises.” Hakes explained some of the policies, not only of Carter’s administration, but also of Nixon’s, that exacerbated the energy crises of the 1970s, and he shared his insight on how President Biden’s agenda could affect the energy industry going forward. He noted that Biden has put a pause on leasing on federal lands, but said he doesn’t expect that to affect production, at least for several years.
Is It Safe to Invest in Mexican Energy Projects? In late 2013, Mexico embarked on a path to transform its energy markets. Then-President Enrique Peña-Nieto oversaw constitutional reforms that ended state-run monopolies, and opened Mexico’s power market to competition and investment from foreign and private companies. By most accounts, the policies were highly effective in spurring investments in renewable energy and efficient natural gas-fired power projects. A great deal of money has been funneled into Mexico by investors from as many as 45 countries since the law was enacted. “The result of that was dramatically successful. I mean, you have millions and millions of dollars that were sunk into the power sector bringing in modern equipment, environmentally friendly, because there were a lot of renewable projects that went online. You see how the percentage of renewables changed in the last 10 years—you can see that it has been successful,” Roberto Aguirre Luzi, a partner with King & Spalding, said as a guest on The POWER Podcast. However, Peña-Nieto is no longer in office, and President Andrés Manuel López Obrador wants state-owned power company Federal Electricity Commission (CFE) to get special treatment in the market. Under the previously enacted reform measures, dispatch priority was based on price, with the lowest-cost generation being delivered first. Earlier this month, Mexican policymakers passed legislation that would change the order in which electricity is dispatched, giving priority to CFE at the expense of private operators. “There were a wave of amparos to challenge this law,” said Fernando Rodriguez-Cortina, senior associate with King & Spalding. An amparo is a protection provided for under Mexico’s constitutional law. It may be filed in federal court by Mexicans and by foreigners in an attempt to guarantee protection of the claimant’s constitutional rights. “The judge granted the amparo with general effects, and now the law is stayed,” said Rodriguez-Cortina. “With general effects” means the stay applies to everyone affected by the law, rather than simply to the amparo filer. President López Obrador is not standing idly by, however. He asked the Mexican Supreme Court to open an investigation into the judge’s conduct, claiming that the judge, who was appointed under the previous administration, acted inappropriately. “This is obviously a political maneuver, because this is not how you initiate a proceeding. I mean, if you want the judge to be investigated, you follow a different route. You don’t go to the Supreme Court,” said Rodriguez-Cortina. The chief justice ultimately referred the case to the proper court for resolution. Aguirre Luzi suggested the actions taken by Mexico’s policymakers should be very concerning to all stakeholders and will have wide-ranging implications on future investments. He said when you have two branches of government making important energy policy changes with the intention of helping two state-owned entities—CFE and PEMEX, which is the fuel supplier to many of CFE’s power plants—it’s going to have long-term effects. “It’s a 180-degree change,” said Aguirre Luzi. “How do you come back from that?” Only time will tell. Rodriguez-Cortina suggested court proceedings could go on for a while. “It usually takes around six months for the amparo to be resolved,” he said, and appeals could take the dispute all the way to the Supreme Court. “So, this is going to be a process that is going to take years to see the actual outcomes,” said Aguirre Luzi.
Are 1-in-10-Year Events Really 1-in-10-Year Events Anymore? When evaluating resource adequacy requirements, many power companies and grid operators have used a methodology that originated more than 70 years ago. This probabilistic reliability approach has generally performed adequately through the years. It has generally evaluated loss-of-load events occurring at frequencies of one-day-in-10-years (1-in-10) to be acceptable in terms of system reliability. However, it’s not without risk, as incidents in Texas, California, and other parts of the country and world have demonstrated in recent history. In light of these events, it’s worth asking: have risks changed? It could be that the method used to evaluate what constitutes a 1-in-10 event is no longer sound. “When you have 1-in-a-5 or 1-in-a-10-year event that’s happening every year, most likely those are not 1-in-a-10 or 1-in-100-year events,” Electric Power Research Institute (EPRI) CEO Arshad Mansoor said as a guest on The POWER Podcast. “Really, what we need to go is beyond that. We need to look forward to a future, and not really just back-cast, but forecast. What is the resiliency of the grid that we need when maybe societal dependence on electricity has doubled because of electrification, where extreme weather is becoming frequency, and severity is becoming a norm? And, our resource mix is changing pretty rapidly, and these changes are profound. So, taking all those three trends into consideration, we just need to step back—and resource adequacy is one part of the planning process,” Mansoor said. In rather prescient timing, EPRI published a technical update (or white paper) on Jan. 28—about two weeks before uncharacteristically cold weather caused widespread blackouts all across Texas. “That timing was not by design,” Mansoor said, noting that EPRI has long been working on ways to enhance grid design, planning, and operation to help navigate the energy transition. According to the abstract, “This white paper focuses on planning for resource adequacy given a world in which supply disruptions are correlated and no longer limited to the outage of independent units and may be due to widespread or long-duration events with significant economic impacts on consumers.” The 72-page paper highlights several attributes of planning for resource adequacy in an environment of increasing numbers of extreme events. Among the items addressed are: • Supply disruptions that are common-mode events caused by weather, cyber and/or physical attacks, natural gas constraints, or combinations of factors. • The occurrence of an event (zero/one), consideration of its physical impacts (the amount of unserved energy, breadth of customer base impacted, and duration), and its economic costs to consumers. • The need for the definition of probabilistic metrics and methodologies that over time can be used to incorporate consideration of common-mode and high-impact supply disruptions. The paper concludes with an identification of strategies that individual utilities and independent system operators/regional transmission organizations (ISOs/RTOs) could follow based on their unique situations. “I would encourage all of your audience to go to our website www.epri.com and you should be able to download the paper—we have made it available to all,” Mansoor said (see https://www.epri.com/research/products/000000003002019300).
Battery Technology Used in Outer Space Could Be a Gamechanger on Earth Lithium-ion has become the dominant battery technology used in energy storage applications around the world, but that doesn’t mean it’s the only, or even the best, technology available. Many companies are working on different battery chemistries that could provide safer, longer-lasting, and ultimately more cost-effective options. One alternative that has gotten little exposure until now is a battery chemistry with a 30-plus-year history of successful operation. It’s a metal-hydrogen battery, which has been used by NASA on space missions, including in the Hubble Space Telescope, the Mars Curiosity rover, and the International Space Station. “[The battery was] designed for a use case where these aerospace satellites and so forth needed a battery that would withstand the harsh climate of outer space, meaning super high temperatures, super low temperatures, and then have basically an infinite cycle life and require no maintenance,” Jorg Heinemann, CEO of EnerVenue, said as a guest on The POWER Podcast. “They worked very successfully with over 30,000 cycles—30,000 cycles is like charging the battery and discharging it three times per day for 30 years,” he said. For the sake of comparison, Heinemann said the longest lasting lithium-ion batteries can handle about 3,000 cycles, about one-tenth the cycle life. The metal-hydrogen battery contains no toxic materials, and unlike lithium-ion technology, it has no fire risk. “There are no safety issues. It’s a really safe device. There’s no thermal runaway risk, which is the primary concern with lithium-ion. Our battery operates in a very broad—what I call a ‘happy’—temperature range,” Heinemann said. Specifically, EnerVenue’s battery has been proven to operate reliably in ambient temperatures from –40F to +140F. That means, whether in artic or desert conditions, it doesn’t require large-scale heating and air conditioning systems, which can be expensive and maintenance-intensive. Cost has been the main reason metal-hydrogen chemistry has not been more fully developed for use on Earth. The batteries used in space were very expensive, costing as much as $20,000/kWh, according to Heinemann. However, about two years ago, EnerVenue’s founder, Yi Cui, a professor at Stanford University who was leading a research lab focused on materials innovations for sustainability, came up with a new set of materials to replace the high-cost elements. “It uses Earth-abundant materials—nothing but—there’s nothing that is either rare or problematic. There’s no lithium, no cobalt, no platinum-group metals. It’s just Earth-abundant stuff that you can find virtually on every continent,” Heinemann said. Which means, the cost has come way down, and the kicker is, it even performs better. “We believe that we can match the cost trajectory for lithium-ion battery packs, which is going to continue to go down over time based on the scale effects,” he said. “We can match their CAPEX [capital expenditure expense], and then, we can give the customer a significantly better value proposition in terms of the capabilities of the battery, especially the high temperature range, the durability, the flexibility, and a very significant economic savings because of the fact that there’s no maintenance costs associated with this battery. It’s basically an install-and-forget battery.” Metal-hydrogen batteries are not particularly well-suited for mobile applications, such as electric vehicles or cellphones, so for now, EnerVenue’s target market is the utility-scale energy storage sector. “Our battery is really good for a super broad range of stationary uses,” he said.
Hydrogen and the Energy Transition Power systems around the world are changing. Renewable energy, mainly in the form of wind and solar generation, is being added everywhere, while more traditional forms of power, such as coal-fired and nuclear generation, are being retired from the grid. Meanwhile, natural gas-fired generation has taken the lead role in facilitating the transition by providing relatively quick ramping capability and stable baseload power to backup intermittent renewables. However, there is a lot of research and development work underway that could eventually push natural gas out of the mix. The reason is that gas, like other fossil fuels, releases CO2 and other emissions to the atmosphere, albeit at lower quantities than coal, fuel oil, and diesel on a per-kWh-generated basis. One of the potential supplements or replacements for natural gas could be hydrogen. The concept of a hydrogen economy is not new. It was first contemplated at least as far back as the 1970s, but the economics associated with producing hydrogen at the time made it impractical. That is changing as countries around the world implement decarbonization goals and the share of renewable energy in the power mix increases. Going forward, there are likely to be situations in which the supply of solar and wind power is high, but demand for the electricity is low. Rather than curtailing production, the surplus energy could be used to produce “green hydrogen” through electrolysis at a very reasonable cost. “There’s no CO2 emissions associated with [green hydrogen],” Megan Reusser, hydrogen development lead at Burns & McDonnell, said as a guest on The POWER Podcast. “So, bringing hydrogen to the forefront as a potential way to meet decarbonization goals, coupled with other types of renewable energy such as solar or wind, that’s what’s really giving [hydrogen] kind of a new life and a really big interest currently in the market.” Seeing the writing on the wall, the major gas turbine original equipment manufacturers (OEMs) have jumped aboard the hydrogen bandwagon. Siemens, GE, and Mitsubishi Power all have programs underway to make their combustion turbines 100% hydrogen capable. Their intentions are really designed to “future proof” investments in new power plants. “All the major OEMs have advanced-class gas turbines that are available and can blend up to 30% hydrogen. Where it gets interesting is you see and hear about the concept of hydrogen-ready for the future, and 100% hydrogen capable for the future,” Joey Mashek, business development manager at Burns & McDonnell, said on the podcast. “The plan to develop those technologies to get near 100%, or 100%, is still about 10 years. And I think all the OEMs will say they can do that and will do that, but it’ll be market driven.” Reusser said Burns & McDonnell has seen a lot of interest in hydrogen pilot projects. “By that I mean small-scale applications where people are just trying to understand how all this is going to come together,” she said. One example that she mentioned was a system installed by the Orlando Utilities Commission. “They are developing a pilot facility that has a little bit of everything. It’s got [an] electrolyzer, some storage, and a fuel cell. So, they’re kind of doing the whole spectrum of generating their hydrogen, storing their hydrogen, and then converting it back to power,” said Reusser. “Only thing I can say is, it’s exciting, really exciting time in the energy industry,” Mashek said.
Dirty Electricity, but Not the Kind You Think When most people hear the term “dirty electricity,” they probably think of power generated from sources considered more-polluting, such as coal, natural gas, or other fossil fuels. However, Satic Inc., an electronics manufacturer and professional engineering firm based in Missoula, Montana, says electricity in homes and businesses is filled with “electrical pollution” that is not necessarily associated with dirty fuels. In fact, the company claims solar power is one of the main sources of dirty electricity. “Dirty electricity specifically comes from three different main culprit places. Number one, it’s delivered to our panel. Number two, we make it with our electronics—our solar inverters, our LED lighting, our DC devices. And, the wiring in our home—maybe half a mile of high-quality copper wiring—acts as a super antenna. So, that’s how we get dirty electricity into our house. What defines it specifically is, it’s electricity that has distortion or interference, low power factor, etcetera, on it,” B.D. Erickson, Satic’s CEO, said as a guest on The POWER Podcast. Dirty electricity may affect more than just electrical devices. Some people claim to have a hypersensitivity to electromagnetic fields (EMFs), and they report symptoms such as fatigue, dizziness, headaches, problems with concentration and memory, and sleep disturbances as a result of exposure to dirty electricity. While studies on the effects of exposure to EMFs have in some cases been conflicting, Erickson said his son experienced symptoms when the family moved into a home located near large power transmission lines, which is what led him to research the topic. “Electricity has eight attributes that need to be within an acceptable realm, and if they’re not within that acceptable realm, they are considered dirty,” Erickson said. He explained the eight attributes are volts, amps, watts, electromagnetic fields, total harmonic distortion, interference, ohms law of resistance, and frequency. Erickson said when electricity leaves a power plant, it’s properly regulated and is typically within an acceptable range for all eight attributes. But as it flows out to customers, it can degrade or get distorted, usually as a result of the devices everyone uses. “We live in an alternating current world [but] half the stuff we plug in nowadays isn’t alternating current. Anything with [a] battery is DC,” he said. In today’s world, cell phones, computers, tablets, and some other electronic devices are often powered by batteries. Furthermore, lighting has changed from incandescent bulbs, which were essentially resistors that used to act as “energy cleaners,” to compact fluorescent bulbs, and now, LED lighting, which adds electrical pollution. Lastly, Erickson said solar power, and specifically solar inverters, create a lot of dirty electricity. What Erickson and his team of engineers came up with is a product that provides system-wide power conditioning, robust surge protection, and power factor correction with advanced EMF, interference, and harmonics filtration. The system is easy to install in homes and businesses, and the effects are immediate. “You don't have to wait a month like with solar to see your bill. You can see it, you can feel it, you can hear it in real time. The amp draws—your air conditioner might go from five amps to two, and running better and running quieter,” he said. Erickson said the cost savings on electric bills will usually pay for the device in about two years, and there are other benefits, such as robust surge protection, less heat generation, and longer operating lives for appliances and devices, not to mention possibly improving the health of people with EMF sensitivities.
Is Nuclear Power Poised for a Resurgence? Since 1990, nuclear power has consistently supplied about 19% to 20% of the electricity used in the U.S. However, very few nuclear plants have been added to the U.S. fleet over that time. Currently, the only nuclear project in the U.S. is Southern Company’s Plant Vogtle expansion, which is expected to add two new reactors to the grid by the end of next year. Still, there are 50 reactors under construction around the world—12 of them in China—and several countries are considering adding more. “There has been a fundamental shift in the thinking around the world. As climate change has become front and center as the number one issue globally—environmental issue and societal issue—the recognition that nuclear can and should play a part in helping us overcome the climate change problems has shifted a lot of thinking in governments that I talk to around the world, but also even with people that are environmental-minded—people that have been, in the past, anti-nuclear—and start seeing that nuclear now is and should be part of the solution. So, it’s a very exciting time,” George Borovas, head of Hunton Andrews Kurth’s nuclear practice and managing partner of the firm’s Tokyo office, said as a guest on The POWER Podcast. In the future, Borovas said he expects China to continue building nuclear plants at least on the scale it is today, and perhaps at an even greater rate. “I think it’s going to be very easy for them to keep replicating, especially because they have such tremendous needs for energy,” he said. Nuclear power’s emissions-free aspect also provides a huge benefit for the Chinese, which has had air quality problems in a lot of its industrialized cities. “So, I do think that China is going to continue with its new build program very aggressively, and we're starting to see also China becoming more of an exporting nation for nuclear technology and services around the world.” Schedule delays and cost overruns have long been issues for the nuclear industry, but Borovas suggested some of those nagging problems could be remedied through repetition, especially now that first-of-a-kind units have been successfully commissioned. He noted that EPR and AP1000 units are operating in China, and effectively provide a template for future success. Borovas was also optimistic about advanced technology, such as small modular reactors. “The small modular reactors—the SMRs—are very exciting,” he said. “You have some wonderful technologies that are designed to operate in a different environment. They have much more passive systems, they have walkaway safety scenarios, and they’re using technologies that have been around for a long time in the sense, but they’re packaging them in a way that makes more sense for the evolving world that we live in. I think they hold a lot of promise.” Concerning the long-term future of nuclear power, Borovas said he believes it has a place in the world and offers sustainable development. He suggested nuclear energy can help bring people out of poverty in places such as Africa, and its zero-carbon emissions provide a great alternative to fossil fuels. “I think nuclear has a very, very compelling and exciting story to tell, and the more people see that—the more people understand that—I think the more supporters of nuclear we’re going to have around the world,” he concluded.
Bigelow Tea Enhances Sustainability with a Vehicle-to-Grid System Sustainability is a buzzword that’s being bantered about up and down Wall Street, and corporate leaders have taken notice. Many companies have adopted environmental, social, and governance (ESG) initiatives, which are often tied to sustainability goals. In some cases, the pressure to do so has come from customers and/or investors, but in others, CEOs and boards are simply choosing to “do the right thing” to help save the planet. “A lot of companies are really recognizing, we need to use our money to make a difference, we need to use our money to make this world a better place,” Cindi Bigelow, president and CEO of Bigelow Tea, said as a guest on The POWER Podcast. Bigelow Tea, which is 100% family owned and operated, has implemented several measures to enhance the company’s sustainability. In addition to obtaining all of its electric power from renewable energy sources, Bigelow Tea also has a waste reduction, recycling, and composting program, which has resulted in all three of its facilities achieving zero-waste-to-landfill status. The company’s most recent sustainability initiative involved installing a vehicle-to-grid (V2G) system in collaboration with Fermata Energy. The V2G system includes a bidirectional charger connected to a Nissan LEAF electric vehicle (EV). “What those two elements are doing is they’re operating behind the building’s electric load, and they are managing the building’s electric load in such a way that when the load starts to peak during the billing cycle, we dispatch energy out of the vehicle into the building load behind the meter. And what that does is it reduces the utility costs—the energy costs—for the building by however much dispatchable energy we were able to put into that load. So, we save the customer money,” David Slutzky, founder and CEO of Fermata Energy, said on the podcast. “It’s a customer bill management application.” “Yes, it’s reducing your utility bills,” Bigelow said, but the program accomplishes much more than that. In fact, she suggested there were three clear benefits. One is that the V2G system allows Bigelow Tea to identify when it is operating during peak-load periods, which lets the company make changes within its operational system to reduce load, which is important in the long term. Secondly, if more companies incorporate V2G systems, the total peak demand on the grid will be lessened, which benefits everyone. The third benefit is in Bigelow Tea’s ability to utilize the EV for transportation purposes, which reduces emissions, because, as previously noted, the company gets all of its electric power from renewable sources. “So, there’s many facets to why this program is so important and beneficial for our company,” Bigelow said. In the end, Bigelow suggested all CEOs need to spend time developing and implementing sustainability initiatives. She acknowledged that companies must focus on their core products and services, and turn a profit. “But at the same time, we have to remember, we can make a difference both for our employees, for the community, and the environment, and this is a very important part of what we do,” Bigelow said.
Is a Microgrid Right for You? A microgrid is a discrete energy system consisting of distributed energy resources, such as solar panels, wind turbines, backup generators, and battery storage systems, and loads capable of operating in parallel with, or independently from, the main power grid. A microgrid generally operates while connected to the grid, but importantly, it can break off and operate on its own using local energy resources in times of crisis, such as during storms or power outages, or for other reasons. Microgrids are all the rage these days, but would adding one to your power system provide enough benefit to justify the cost? Answering that question requires a detailed understanding not only of the technology involved, but also the energy landscape in your local area. “People look at [microgrids] because they are a sustainable solution. They’re generally cleaner than [the electricity] you’re buying from the utility—your source of power is cleaner,” Mike Byrnes, executive vice president and Chief Operating Officer of SourceOne, a Veolia company, said as a guest on The POWER Podcast. “What gets them across the finish line is it adds resiliency, and typically, the lifecycle cost is less than your business-as-usual case.” SourceOne is an energy consulting firm that provides highly specialized energy management, engineering, and owner’s representative services for commercial, industrial, and municipal energy concerns. It has been crafting innovative solutions that help customers ensure sustainable, reliable, and cost-effective utility operations for more than 20 years, so Byrnes has a long history with microgrid technology. “We love sustainability. We love reducing greenhouse gases. We love building resiliency for people with microgrids,” said Byrnes. But, a microgrid requires a serious commitment from the organization doing the project, and Byrnes said you don’t usually get that unless there is a financial benefit. “Those are the ones that are getting built—the ones that have really solid paybacks for people,” he explained. Byrnes noted that decreasing prices for solar power and battery storage systems are making those resources very attractive for many customers. “The price point for renewables has come down so far that it's become in everybody's reach,” he said. “Every project we work on right now, instead of just having CHP [combined heat and power]—which you still need because you need the heat component out of it—typically, will have a solar and a battery storage component, or at least to start everybody wants it, and they make great sense. It gives you so much more flexibility in the market, and your ability to actively manage your electric usage is huge.”
Enhancing Operations and Maintenance with an EAM System Enterprise asset management (EAM) involves a combination of software, systems, and services that are used to maintain and control operational assets and equipment. The aim is to optimize the quality and utilization of assets throughout their lifecycle, increase uptime, and reduce costs. EAM involves work management; asset maintenance; planning and scheduling; supply chain management; and environmental, health, and safety initiatives. “Maximo is an enterprise asset management system. It’s a tool, if you will, a software tool, that’s used to manage and maintain expensive assets, primarily, and power has been a big part of the Maximo portfolio for as long as I can remember,” Steve Richmond, CEO of Projetech, a Maximo-as-a-Service provider, said as a guest on The POWER Podcast. “It’s good for managing equipment and the people that work on it. So, if you’re tracking labor or certifications, compliance issues, all that detail-oriented data collection, it’s a perfect repository for it.” EAM is often associated with a computerized maintenance management system (CMMS), but it’s different. While a CMMS can be one aspect of EAM, it focuses on centralizing information to facilitate and automate maintenance management processes. EAM, on the other hand, provides an approach for managing the entire asset lifecycle, supporting asset performance from acquisition to disposal. “Maximo-as-a-Service is essentially what it says,” Richmond said. Unlike 30 years ago, when a company would have had to buy a CMMS or EAM software product, and then purchase and install servers, operating systems, databases, and all the related technology that goes along with owning and operating a system, today, providers such as Projetech offer a “no-hassle, login, and simply use-the-product concept,” he explained. While the solution has long been used at conventional power plants, such as coal, nuclear, and gas-fired facilities, Richmond said it is also suitable for wind and solar farms. “It’s been the largest growth area of my business for over five years now. We are a perfect fit for renewables,” he said. The reason is that many solar and wind farms are located in remote areas. “The ability to look at your entire farm, or many farms in the aggregate, and make decisions about what’s the best way to schedule and plan your maintenance, makes this remote connectivity a perfect fit for them,” Richmond explained. “And the ability to be able to connect anywhere, again, from the cab of a pickup truck to a phone on top of a tower—everybody’s connected and they all have the same information available to them at any time.”
Improving Asset Inspections with Drones and AI The U.S. bulk electric system consists of more than 360,000 miles of transmission lines, including approximately 180,000 miles of high-voltage lines, according to the U.S. Department of Energy. That means power companies have a lot on their plates when it comes to inspecting and maintaining those assets. Furthermore, the stakes are high. As wildfires in California and elsewhere have shown, billions of dollars can quickly go up in smoke when equipment fails. San Francisco-based Pacific Gas and Electric (PG&E), for example, faced as much as $30 billion in potential liabilities for the role its equipment played in causing wildfires in 2017 and 2018. PG&E filed for Chapter 11 bankruptcy in January 2019, at least partly as a result. Therefore, finding and fixing problems before components fail is worth the effort. “For the most part, utilities are inspecting somewhere between 10% and 12% of their assets each year,” Chris Beaufait, CEO of Sharper Shape, said as a guest on The POWER Podcast. “They’re always trying to figure out how to prioritize in the best way, but then they also run into human resource issues, and just how much they can accomplish in a single year.” That’s where automated drone technology and artificial intelligence (AI) algorithms can help. “We can do detailed inspection of various assets using drones, and we actually have specific software packages that allow parts of that to be automated so the utility can get a repeatable process on their inspection,” Beaufait said. “Then, we basically process all that data. If we do a LIDAR [light detection and ranging] data collection, as an example, we can create data assets of everything that they have in the physical world, and then we can use AI algorithms and human intelligence to really come up with actions that they can do around that so they prioritize what they're going to do in the field, around maintenance, around vegetation management, around asset replacement, or asset improvements,” he explained. Utilizing drones and AI technology allows a much larger area to be covered in a shorter amount of time. “We're talking tens of thousands of miles, and using this combination of artificial intelligence, we can tell them where they may have risks,” said Beaufait. The inspections generate an enormous amount of data. According to Beaufait, Sharper Shape has completed more than 35,000 miles of collection, which includes more than 800,000 different structures and assets, equating to about 5 petabytes of data (5,000,000 GB). It would be impossible for a human to thoroughly process all the information in that amount of data, but computers with AI algorithms can look for anomalies and prioritize the problems identified. And while the inspection capabilities available today are remarkable, the technology is constantly improving, which means future asset assessments could be even more advanced.
Engineering Technicians and Technologists Are an Important Industry Pillar According to Cheryl Farrow, CEO of the Ontario Association of Certified Engineering Technicians and Technologists (OACETT), there are three basic pillars that make up the engineering field. They are licensed engineers, technicians and technologists, and skilled trades. “We can't be successful without all three of these pillars working together effectively,” Farrow said as a guest on The POWER Podcast. “That's why, from our perspective, you need certified technicians and technologists, who have proven to be at the highest level of technical, ethical, and professional performance.” OACETT’s mission is to act as Ontario's independent certifying body for Engineering and Applied Science technicians and technologists. “We provide member certifications, career-long educational opportunities, and professional support for the benefit of our members, for the benefit of the province’s economy, and for the development of safe and secure communities,” said Farrow. There are a number of things OACETT does to raise awareness of opportunities in the engineering field. One major activity is the group’s participation in Canada’s National Engineering Month in March. The event will take place virtually in 2021. “That is our opportunity to create some general awareness about this field of practice,” said Farrow. The organization also works closely with employers. Farrow explained: “That's where you really do start to see job postings where the certifications that OACETT offers will either be required, or they will be preferred, or they will create an advantage for hiring. And we have also just launched what we're calling our 360 Partnership Program, which is to help us connect even more with the employer community, get this message out there, and help them to understand the value of hiring certified technicians and technologists.” In 2021, OACETT plans to launch a government relations strategy. It intends to target specific ministries, and let them know the kind of expertise leaders could draw on from among OACETT’s membership when creating policy. The education community is another area of focus for the group. “We work very closely with all of Ontario's community colleges on outreach to their students,” Farrow said. “We even go so far as to embed our exam programs in some of these college curriculums so they sort of have a leg up even into the certification once they finish school and start working. And then we work together with the colleges so that we can start to get the word out, even in high school, to encourage students to explore these fields of study.”
A Hopeful Narrative for the Nuclear Industry Although there is only one nuclear power plant construction project in progress today in the U.S., that doesn’t mean the nuclear industry has gone dormant. A lot of research and development are ongoing, and the federal government is putting millions of dollars behind some of the efforts. The Advanced Reactor Demonstration Program “The Department of Energy’s [DOE’s] Advanced Reactor Demonstration Program [ARDP] is a real gamechanger for the industry,” Marc Nichol, senior director of new reactors with the Nuclear Energy Institute (NEI), a policy organization of the nuclear technologies industry, said as a recent guest on The POWER Podcast. “It offers an opportunity for DOE to directly cost-share with different companies developing technologies to help accelerate technology development.” In October, the DOE awarded TerraPower and X-energy $80 million each in initial funding under the ARDP to build two advanced nuclear reactors that can be operational within seven years. The DOE plans to invest a total of $3.2 billion over the next seven years, with industry partners providing matching funds. For its part, TerraPower plans to demonstrate its Natrium reactor, a sodium-cooled fast reactor that supposedly leverages decades of development and design work undertaken by TerraPower and its partner GE Hitachi Nuclear Energy. The high-operating temperature of the Natrium reactor, coupled with thermal energy storage, will reportedly allow the plant to provide flexible electricity output that complements variable renewable generation such as wind and solar. X-energy is expected to deliver a commercial four-unit nuclear power plant based on its Xe-100 reactor design. The Xe-100 is a high-temperature gas-cooled reactor that is said to be ideally suited to provide flexible electricity output as well as process heat for a wide range of industrial heat applications, such as desalination and hydrogen production. “There’s a lot of new and innovative things that these types of reactors can do,” Nichol said, referring to the ARDP-funded designs. Microreactors Among other designs that Nichol spoke about were microreactors (units with power output ranging from 1 MW to 10 MW). “The best way I can describe it is a microreactor would be able to fit on the back of a flatbed semi-truck. The building itself would be about the size of an average home. The size of the site itself would be about the size of a suburban lot. And, so, that gives a visual perspective of how small these things are—you can put them just about anywhere,” he said. Commercial interest for microreactors is coming largely from remote areas, such as in Alaska and northern Canada. Nichol said microreactors can operate 24/7 for years at a time without refueling, and at prices cheaper than what diesel generators can do today. Mobile reactor designs are also being developed. Although there is little interest for mobile rectors from a commercial perspective, the Department of Defense (DOD) sees a use for these types of units. In March, the DOD awarded three teams—BWX Technologies Inc., Westinghouse Government Services, and X-energy—contracts to each begin design work on a mobile nuclear reactor prototype under a Strategic Capabilities Office initiative called Project Pele. “That design effort should conclude sometime next year, in 2021, maybe early 2022,” Nichol said. “From there, they'll move into the manufacturing and operations to test that.”
Could Geothermal Energy Become the ‘Sexy’ Renewable? Geothermal is an often-overlooked and even disregarded renewable energy resource. While new wind and solar energy projects garner headlines nearly every day, geothermal is rarely sighted in news feeds. However, that could change in the future. One company that has made progress on new geothermal technology is GreenFire Energy. In June, the company completed the world’s first field-scale demonstration of closed-loop geothermal energy production. The demonstration was performed using an inactive well at the Coso geothermal field in Coso, California. The project was funded by a $1.48 million grant from the California Energy Commission, with additional support from Shell Oil, the Electric Power Research Institute (EPRI), and J-POWER—a large Japanese utility and EPRI member. Scherer explained what was done: “At our Coso demo, we were able to insert a tube-in-tube heat exchanger 1,000 feet long into an existing geothermal well that couldn't be used due to the high concentration of non-condensable gases, and we made over 1 MW of power, even though the project wasn’t really at full commercial scale. And with these results, we were able to validate the modeling we use to predict the performance of our various closed-loop solutions and a variety of geothermal resources.” Scherer said another application that shows promise for GreenFire Energy’s technology is in hydrogen production. The company was asked by an oil and gas super major to investigate whether using geothermal heat down bore in its GreenLoop system could make “green” hydrogen more efficiently. “And happily, the answer is yes,” said Scherer. He explained: “Since green hydrogen production is more efficient at high temperatures—and often benefits from high pressure—and since high temperatures and high pressures are free deep down in a geothermal resource, we can indeed substantially improve the efficiency of hydrogen production.” Furthermore, in order to be transported, hydrogen typically requires compression, which is expensive. However, when hydrogen is produced down bore at high pressure, it doesn’t require as much compression, which is an additional money-saving advantage. The hydrogen production technology hasn’t been commercialized yet, but GreenFire Energy has the support to do so and expects that to be accomplished in the next two years. “Geothermal isn’t traditionally regarded as sexy, but hydrogen is. So, our plans to make hydrogen with geothermal energy makes GreenFire and geothermal sexy, right?” Scherer joked.
Clean Energy Tech Company Offers Customers Renewable Options There is a growing trend toward clean energy around the world. A number of high-profile companies, including Google, Apple, Walmart, and more than 260 others, have set 100% renewable electricity goals, and power companies, too, have joined in the movement, with many targeting net-zero emissions in coming decades. However, most consumers have found it more difficult to source 100% renewable energy to power their homes. That is, until now. Inspire, a clean energy technology company headquartered in Santa Monica, California, and Philadelphia, Pennsylvania, announced on Nov. 9 the availability of its digital energy experience in New Jersey, Pennsylvania, and Southern California. It claims to provide consumers with the first and only personalized flat-rate, monthly subscription with unlimited access to 100% clean energy. “What we do is we're building a completely digital energy experience that makes it insanely easy for consumers to adopt clean energy and clean energy technologies by providing them as a simple subscription service,” Patrick Maloney, CEO of Inspire, said as a recent guest on The POWER Podcast. Maloney said Inspire did a lot of research and found that many power customers were confused about their bills and didn’t understand the tiers that were often incorporated into their rates. Furthermore, some people had an underlying feeling of guilt because they knew most of their power was generated by fossil fuels, which many believe is harming the planet. “So, what we focused on was entering into those markets where we could really build a technology platform that would effectively almost sit on top of the grid, and allow us to then revolutionize the business model into a subscription model—almost like a Netflix like subscription for clean energy,” Maloney said. “We're at the place where we're now beginning to take the model we pioneered there, and now bring it to a national basis.” According to Inpsire, people can make the switch to access 100% clean energy in minutes. Customers connect their current utility account (giving Inspire access authorization) and Inspire calculates a custom flat price for each customers’ entire monthly utility bill, based on factors such as historic consumption. No matter the usage or season, customers can anticipate the same price month over month, mitigating concerns over large energy bills during extreme weather seasons, for example. The company says there’s no hidden fees or price fluctuations, and it’s risk-free—customers can cancel at any time. Customers pay Inspire using their preferred payment method and Inspire pays their utility bill in full on their behalf every month, while matching home electricity usage to 100% clean energy. Inspire’s impact dashboard lets customers easily track their path to a net-zero lifestyle through easy-to-understand visuals, and practical tips to save energy and reduce CO2 emissions. Maloney said one year with Inspire can have a greater impact in reducing a consumer’s carbon footprint than 10 years of recycling.
Developments in Offshore Wind Technology By some estimates, offshore wind energy has the potential to deliver 18 times the current global electricity demand. The International Energy Agency (IEA) has said offshore wind power could develop into a $1 trillion industry over the next two decades, so there’s obviously a lot of growth potential around the world. While the cost for offshore wind projects is currently higher than onshore systems, John Olav Giæver Tande, Norwegian Chief Scientist at SINTEF Energy Research, said the difference is less than most people realize. “Offshore wind is maybe cheaper than you think,” Tande said as a guest on The POWER Podcast. “Bottom-fixed offshore wind farms, they are today built without any subsidies—so, simply competing on electricity price at the best locations.” Tande offered the Dogger Bank Wind Farm as a case in point. The site is being developed in three phases off the northeast coast of England. Each phase will have an installed generation capacity of up to 1.2 GW. When finished, the 3.6-GW development will be the largest wind farm in the world. “It’s competitive with the cost of electricity in the UK without any subsidies,” Tande said. Floating platforms could provide a great new opportunity for wind power developers too. About 80% of the ocean is deep water, which means it’s not suitable for bottom-fixed wind farms. However, with floating wind turbines, the situation changes. “You have a much larger area to locate your floating wind farms, and they can be located at more ideal positions related to wind resource. But also, related to impact to other interest or an environmental impact or grid connection or fisheries or what have you,” Tande said. To make floating technology more competitive, Tande said two things still need to happen: the design and operation of floating wind turbines need to be optimized through research and innovation, and the supply chain needs to be developed. “These two things will make floating wind cost-competitive within the next decade or so,” he said. Among the technology SINTEF has helped develop over recent years are remote maintenance and surveillance systems, optimized boring systems, new generator concepts, and greatly improved methods and tools for designing floating and fixed offshore wind turbines. “The one innovation that has had the highest value were actually these models to optimize the constructions,” said Tande. “You can’t say that is a game-changer, but it has huge impact on the cost of electricity from an offshore wind farm. If you can reduce the amount of steel [by] maybe 5%, then you have an automatic cost reduction.” Tande said his group is currently working on ways to operate wind farms using a more holistic approach. Historically, each wind turbine was operated to maximize individual output—the effect each turbine had on the operation of other surrounding turbines was not really considered. Now, researchers are investigating ways to maximize a farm’s overall output, which could mean curtailing operation of some turbines to improve the operation of others. “We are working hard to develop methods that we—in real time—are able to predict how the wind speed inside a wind farm is going to change depending on how we are controlling the individual turbines,” Tande said. An offshore wind-filled power system does present some challenges for the grid. Europe is planning to have 450 GW of offshore wind by 2050, and some ambitious estimates suggest there could be 1,400 GW of offshore wind installed worldwide by that time. “With these kinds of massive amounts of offshore wind, it's really a challenge of how to develop the grid to bring the power to shore and the technology to do that,” said Tande.
Fusion Power May Be Closer Than You Think Fusion research and development have been ongoing for decades, and many people probably believe a fusion power system will remain out of reach for decades longer. But the truth is that more than 100 tokamaks have been constructed and the science behind fusion is well-understood. What has been elusive is generating net energy from a fusion reaction, that is, getting more energy out than goes in to heat the plasma. One company that believes it is on the cusp of a breakthrough is Cambridge, Massachusetts-based Commonwealth Fusion Systems (CFS). Bob Mumgaard, the company’s CEO, was a guest on The POWER Podcast and explained why he’s excited about the future. One big reason is that a groundbreaking series of seven papers were recently published and peer reviewed in a special edition of the Journal of Plasma Physics, validating CFS’s approach to commercial fusion energy. The papers, written in collaboration with the Massachusetts Institute of Technology’s (MIT’s) Plasma Science and Fusion Center, are the first peer-reviewed publications from any private commercial fusion company that verify a compact fusion device will achieve net energy. Mumgaard acknowledged that his company, which is only about two years old, has capitalized on much of the previous research conducted by the U.S. Department of Energy (DOE), universities, national labs, and other countries, to get to where it is today. In fact, CFS spun out from MIT and gained a lot of knowledge from the Alcator C-Mod project—a compact, high-magnetic field tokamak that the DOE funded at the university. In 2016, C-Mod broke its own record for plasma pressure in a magnetically confined device, an important measurement for fusion. “It’s a really interesting story of the long history of fusion and all these stepwise improvements that have been done. And, you know, most of these have all been towards making a machine, basically a fusion machine, that can create the conditions that are necessary inside of it, which is namely having a very, very small amount of fuel, like a grain of rice worth of fuel, that is at very hot temperatures—like 100 million degrees, so hotter than the center of the sun—and at densities where you get enough reactions, and insulated well enough so that it doesn't cool itself off, to the point where you can make more power from fusion than it took to heat it up. That's called breakeven or net-energy,” Mumgaard explained. CFS is now developing and testing new high-temperature superconductor (HTS) magnets, which will allow for smaller, faster, and less-expensive tokamaks using the science developed on Alcator C-Mod and other devices. “We’re now starting to assemble a full-scale first-of-a-kind, 20-Tesla, multi-ton magnet that will really push this technology way beyond what anyone has done before,” said Mumgaard. “That’s at the parameter range that you need to build these high-field compact fusion tokamaks.” Once the HTS magnets are finalized, CFS will utilize them in a demonstration unit called SPARC, which could be the world’s first fusion device to produce more energy than it consumes. Mumgaard expects construction on that machine to commence next summer. Once that system is complete, “You’ll be able to show up, push a button, and make a whole bunch of excess energy—more energy than it took to run the fusion plasma for the very first time. And that feels kind of like the Wright Brothers moment for fusion,” Mumgaard said.
Developing a Safer Lithium-Ion Battery. Most consumers know that lithium-ion (Li-ion) batteries can get hot. People experience the phenomenon in devices such as cell phones and laptop computers. In extreme circumstances, the heat can cause fires with catastrophic consequences. One company that is working to remedy the problem is Burlington, Washington-headquartered LAVLE. The company’s COO Morten Pedersen and CTO Ben Gully were guests on The POWER Podcast. They explained how LAVLE is making Li-ion batteries safer. “The foundation of safety in the lithium-ion battery really comes from a good and effective thermal management system,” Gully said. “Another really critical component for safety actually ends up being the battery management system—the BMS. That’s kind of the electrical computer brains of the battery,” he said. LAVLE has put a lot of emphasis on incorporating reliable and redundant protection into its designs “that give the whole system a very high level of safety.” Heat is generated in Li-ion batteries due to the chemical reaction that takes place in the process, as well as from inefficiencies or losses. As battery systems become larger, operate at higher power levels, and are asked to charge and discharge at faster rates, additional heat is generated, making effective management systems even more important. “That’s really one of the key aspects of the lithium-ion batteries, especially of today, is managing that heat and getting them to make sure they operate in a safe and comfortable temperature range,” Gully said. LAVLE has made great strides in improving battery cooling systems. It has tested various materials and cell arrangements to figure out the most efficient and effective way to remove heat from each individual cell in the quickest way possible, using every accessible surface. The company has also experimented with different working fluids and heat exchange mechanisms. Still, Gully suggested more improvements could be made in a number of areas to make Li-ion batteries safer. LAVLE sees the marine sector as a prime market for Li-ion batteries, and its products in particular. Pedersen noted that the marine sector transfers much of the world’s cargo and releases between 2% and 3% of the world’s greenhouse gas emissions. Incorporating batteries into the shipping industry could lessen that greatly. Nonetheless, much of the progress the company has made on battery technology also translates to other sectors. “As new power generating technologies come to market, the battery is probably a very good enabler to make those work efficiently as well, because many of the technologies we see are not very good at big peaks in power consumption,” said Pedersen. “So, the battery can kind of be the buffer that takes the big hits and the big changes in load. And then, those stable power generating technologies can help.”
Taking Lithium-Ion Batteries to the Next Level. Although the first lithium-ion (Li-ion) battery was conceived more than 50 years ago, the technology continues to be refined and improved today. Scientists and engineers are constantly modifying and testing electrolytes, anodes, and cathodes in an effort to make Li-ion batteries more energy-efficient, cost-effective, and safer. Chicago, Illinois-based NanoGraf Technologies is one company working to improve the technology. The company has demonstrated a novel high-energy-density silicon-based anode material that has the long-term potential to replace graphite-based anodes in Li-ion batteries. By some estimates, NanoGraf’s formulation may be able to increase the energy density of current Li-ion batteries by 20% to 40%, while also improving the usable life of batteries. Chip Breitenkamp, vice president of business development with NanoGraf, was a guest on The POWER Podcast and talked about progress being made by the company. He said NanoGraf has been working in collaboration with researchers at Northwestern University and Argonne National Laboratory to develop, optimize, and patent its proprietary technology. According to NanoGraf, current graphite-based anodes offer a capacity of about 372 milliamp-hours per gram (mAh/g). NanoGraf’s silicon alloy-graphene material architecture can be customized to achieve capacities from 1,000 mAh/g to more than 2,500 mAh/g, delivering higher cell-level energy density and best-in-class rate capabilities for high-discharge applications. “NanoGraf has been working on [overcoming] the challenges that are associated with silicon for about eight years now,” Breitenkamp said. “Those challenges are: as lithium is taken into silicon particles during charge and discharge cycles of the battery, it swells, it cracks, and it sort of falls apart. And what the co-founders of NanoGraf [Cary Hayner and Josh Lau] have been working on is a way to utilize graphene and other coating treatments to allow those particles to swell and contract, but hold them together. Graphene is a huge part of that.” Breitenkamp said some competitors rely on vapor deposition-based systems in their manufacturing processes, but NanoGraf utilizes a wet-chemistry process that is highly scalable, cheaper, and less complex. The company has already proven the process at a pilot manufacturing line in Japan, where it is producing at a 10-ton scale. Breitenkamp said the company expects to ramp that up in the near future. “We can get to cost-parity with graphite at only a 500-ton scale, which is where we’re getting to very soon. Once we get to that thousand-ton scale, we actually become cheaper than graphite on a kilowatt-hour basis,” said Breitenkamp.
Leaders in the Smart City Movement What is a “Smart City”? According to one definition, it’s an urban area that uses different types of electronic methods and sensors to collect data, with insights gained from that data used to manage assets, resources, and services efficiently. Clint Vince, chair of Dentons’ U.S. Energy Practice and co-chair of Dentons’ Global Energy Sector, was a guest on The POWER Podcast. Vince created the firm’s groundbreaking Smart Cities and Connected Communities Initiative and Think Tank, and he is one of the industry’s leaders on the subject. “We have been deeply involved with cities and communities around the country and around the world for decades,” Vince said. “My initial introduction in the Smart Cities concept was really through grid modernization for cities. But we quickly realized that the Smart Cities approach requires integration with many other sectors and subject areas.” Dentons system of working with power companies and other utilities to implement Smart City technology is quite innovative for a legal practice. “I think that our approach to Smart Cities is unique. I don't know of any other law firm with a think tank,” said Vince. “Our clients like it when we focus not just on legal issues, but on business and policy issues, and try to integrate all of those together.” Dentons’ Smart City Think Tank has 16 pillars, including every major sector in the law firm, such as cyber, transportation, communications, intellectual property, and so on. More than 500 thought-leaders from around the globe are involved, which allows insightful sharing of best practices from the various regions. The group feels creating a Smart City requires more than just harnessing technology, it involves modernizing infrastructure. Vince offered CPS Energy, the municipal electric and gas utility serving San Antonio, Texas, as an example of a company making great strides forward in the Smart City area. He said Dentons has helped CPS Energy develop innovation zones, modernize its grid, identify dark fiber in its networks to be used for advanced telecommunications, address cyber-related issues, and team with the joint military base in San Antonio for further collaboration. CPS Energy has invested heavily in renewable energy and on energy efficiency initiatives. “We would identify them as a real rising star,” Vince said. As a global firm, Dentons works with cities all over the world. Vince suggested many other countries are well ahead of the U.S. in Smart City adoption. “Singapore often is singled out as sort of the lead Smart City in the world,” he said. “They really are extremely advanced.” Vince said Singapore invested more than $1 billion into its Smart Cities approach in 2019. Some specific infrastructure and social advancements that Vince thought were notable included Singapore’s ubiquitous very-high-speed internet, which supports other initiatives. “They’ve got online voting down. They have an online system where any citizen can report into the city for maintenance repairs that are needed,” Vince said. Singapore’s pandemic response was also a model for the world, not just in terms of policies for limiting exposure, but also its testing and tracing methods. Vince also noted that Singapore has advanced beyond pilot projects for autonomous vehicles. “They are using autonomous vehicles in portions of their city very, very effectively. They have a government technology agency, which is allowing them to be one of the leaders on sensor technology and integration with the Internet of Things. So, they are of a scale and economic dimension that they can really teach a lot of other cities some impressive things,” Vince said.
Is Carbon Capture Technology a Viable Solution? Carbon capture utilization and storage (CCUS) is widely viewed as a necessary technology to facilitate the continued use of fossil fuels in light of climate change concerns around the world. One company that has been highly focused on CCUS research and development, as well as deployment of the technology, is Mitsubishi Heavy Industries (MHI). Tiffany Wu, business development manager for MHI America, was a guest on The POWER Podcast, and talked about the technology and its future prospects. Wu has a degree in chemical engineering and began her career working intimately on CCUS projects, including at Alabama Power’s Plant Barry facility and on the Petra Nova project—POWER’s Plant of the Year in 2017. “I think that carbon capture is going to become an increasingly important part of the energy portfolio,” Wu said. “In the absence of any regulatory pressure in the U.S., what matters to the industry is whether or not these carbon capture facilities are going to be economic or not. So, our customers are trying to come up with not only environmentally friendly projects, but also economic projects.” Wu said there are reasons for optimism. “In the U.S., we have a really great environment for [viable projects], because one, we have all of this history with enhanced oil recovery [EOR]. And so, there’s a lot of infrastructure in place that they can build off of. And then the other thing is that there have been a lot of federal incentives such as the 45Q tax credit that can help bolster the technology and these projects.” Section 45Q provides a tax credit on a per-ton basis for CO2 that is sequestered. Beginning in 2008, an incentive of $20 per metric ton for CO2 geologic storage and $10 per metric ton for CO2 used for EOR or enhanced natural gas recovery was available. In February 2018, the credit increased to $35 per metric ton for EOR and $50 per metric ton for geologic storage by 2026. The $35 tax credit is also available for non-EOR CO2 utilization and direct air capture projects. MHI’s carbon capture process is known as Kansai Mitsubishi Carbon Dioxide Recovery (KM CDR). It has been installed on at least 13 commercial plants around the world. Wu explained how the KM CDR process works. “It’s very similar to other amine-based processes,” she said. “Flue gas is introduced into the system, and in one of the initial towers, which we call the absorber, we also introduce a solvent. known as an amine, and the CO2 attaches itself to the amine. So, through that process, we’re able to capture 90%—and in some cases, we can capture up to 95%—of the CO2 from the flue gas.” The process is a closed loop system, and the amine is reused. Wu continued, “We introduce the amine that’s rich in CO2 into another tower we call a regeneration tower, and in that tower, steam is introduced and the amine is heated up so that the CO2 separates itself from the amine.” The CO2 is compressed and the amine is sent back to the front of the process. This sort of technology is used by various industrial sectors, including for acid gas treatment. In each case, there may be different flue gas constituents, but the process is essentially the same.
Sustainable Building at Heart of Collaborative Project. The South Landing project in Spokane, Washington, has been called “the five smartest city blocks in the world.” The development is said to feature “the most sustainable large building in North America.” Known as the Catalyst Building, it is intended to anchor a planned “innovation hub.” The five-story, 150,000-square-foot building features two wings around a light-filled collaborative atrium. Catalyst will host dry labs, offices, classrooms, and common study areas. The Catalyst design team reportedly emphasized sustainability as a core value. The building features cross-laminated timber (CLT)—a mass timber building material made of laminated wood panels—for major structural elements. The design reduces the buildings environmental footprint by reducing energy use and prolonging the expected lifespan of the building. The Catalyst Building connects to Spokane’s growing University District by way of the Gateway Bridge, designed to accommodate pedestrians and cyclists. The South Landing project is a joint development of Avista Development and South Landing Investors LLC. Other stakeholders include Katerra (maker of the CLT), Eastern Washington University, McKinstry, and Michael Green Architecture. The sustainable features include an energy-efficient radiant heating and cooling system throughout the building, heat recovery of all exhaust air, high-performing building envelope design, LED lighting, sun shading in the lobby, and a smart building management system to maximize building operations efficiency. Heather Rosentrater, senior vice president of Energy Delivery and Shared Services with Avista Utilities, and Ash Awad, Chief Market Officer from McKinstry, were guests on The POWER Podcast. They explained why the project is important for the community and the many ways all the stakeholders collaborated to make it a success. “As a utility, we recognize that a healthy community creates a healthy utility,” Rosentrater said. “And so, that’s at the core of being involved in this kind of a development is recognizing the value that it can bring to the community in terms of attracting businesses and just providing economic development in this area. So, that’s a big piece of why we’re involved.” “Typically, when a development is happening, the developer and the general contractor and the architect are really working from a top down perspective,” Awad said. However, the South Landing stakeholders worked together in atypical ways. He said Avista and McKinstry collaborated “to think differently about how energy moves.” The two also worked closely with Katerra to bring CLT strategies into the building. “But then, we actually worked with the community, and we thought a lot about ‘What does this southern part of the University District need?’ and working quite closely with the higher ed community and the greater Spokane area to think about some of those elements,” Awad said.
How to Find the Lowest-Cost Option for Electricity in Competitive Markets. How electricity is delivered to customers in the U.S. is complicated. Consumers in some states have no choice who supplies their power; state commissions regulate utilities as vertically integrated electricity providers. Other states utilize a competitive model in which power producers can openly access transmission infrastructure and participate in wholesale electricity markets. Yet, there isn’t complete consistency among states within the two general models. The entire system is a complex mechanism where different technologies, jurisdictions, and regulatory designs must interact. Free-market proponents will tell you that having competition is the preferable alternative, but that is debatable if you look at power prices in different areas. According to a study published by the American Public Power Association, the average revenue per kWh in regulated states has been less than in deregulated states. Currently, 15 states and the District of Columbia have deregulated electricity markets. The states are Connecticut, Delaware, Illinois, Maine, Maryland, Massachusetts, Michigan, New Hampshire, New Jersey, New York, Ohio, Pennsylvania, Rhode Island, Texas, and Virginia. But for consumers, understanding and choosing the best option to meet their needs can be difficult. That’s where a company like WattBuy comes in. WattBuy is an online electricity marketplace that helps customers save on electricity costs by identifying the best option and switching users to the cheapest electricity provider. “So, the way that we work is we have an algorithm that looks at how your home uses electricity down to 15-minute increments, and we take into account all sorts of data,” Naman Trivedi, co-founder and CEO of WattBuy, said as a guest on The POWER Podcast. Among the things WattBuy considers are a home’s square footage, number of bedrooms, number of bathrooms, and historic usage data. It also compares a customer’s data to that of other consumers in the same area. With the information, “We can get pretty accurate at predicting what your home's electricity usage will look like,” Trivedi said. Understanding usage is only the first piece of the puzzle. Then, WattBuy looks at plans offered by power companies to see which one fits best for the customer in question. That includes evaluating tier-pricing options, which comes into play when a different rate applies to different usage thresholds. For example, rates could differ from 0–500 kWh, 500–1,000 kWh, and greater than 1,000 kWh. Other things that may need to be considered include available rebates, promotional incentives, loyalty plans, time-of-day usage, and renewable energy preferences of the consumer. There’s obviously a lot to consider, but Trivedi said WattBuy can save customers as much as 40% on their electric bills. “We have that machine learning model that assures that we’re going to be very accurate,” he said. “The best part about it is that it continues to improve over time.” Trivedi has an interesting background. He was included on the 2020 Forbes “30 Under 30” list in the Energy category. On the podcast episode, Trivedi told about some of the past projects he’s been involved in, which include working with the Silicon Valley Leadership Group promoting a policy initiative for community choice aggregation, working for the White House Office of Science and Technology under the Obama administration, and working on renewable energy projects in Haiti and Paraguay.
Amicarella ‘Demystifies’ the Role of CEO for Women. The power generation industry has historically been a male-dominated industry, but today there are a number of women who have risen through the ranks to positions of leadership. Ana Amicarella, CEO of EthosEnergy, is one of them. EthosEnergy is a leading independent service provider of rotating equipment services and solutions to the power, oil and gas, and industrial markets. Amicarella was appointed CEO last December after spending 22 years with GE and eight with Aggreko, where she was managing director for its Latin America business prior to taking on her latest role. Speaking as a guest on The POWER Podcast, Amicarella explained how her career evolved. “I started in engineering. I moved to sales. I did strategy. Then I did operations roles,” Amicarella said. “For the past 18 years, I’ve been running different businesses, which is what I love to do and likely will continue to do,” she said. Amicarella’s first seven months at the helm of EthosEnergy have been interesting to say the least. In December, COVID-19 was not yet a major concern to most people around the world, but that quickly changed. Amicarella was forced to deal with the situation. “We reacted swiftly and decisively,” she said. “We built a plan—a strategic plan that we developed as a team—and we just accelerated the execution of the plan, and adapted to the new environment and the different working rules that we had to face.” EthosEnergy has 20 facilities scattered throughout the world, and the company was able to keep them all open, even during the height of the pandemic. Amicarella said keeping people safe was a top priority, so new protocols were created and workplace adjustments were made. “We essentially sent our office personnel home, but we were already users of virtual technology, so our IT team made sure that we had the proper infrastructure to support remote workers,” she said. Concerning women in the workforce, Amicarella said, “All the companies I've work for, I think they valued women, and I think they really tried to do the best they could to retain and develop women.” Still, she suggested there’s a lot more work to be done. “We need definitely more diversity in our industry,” Amicarella said. “I think a lot of it starts at home. We have to encourage girls to do more problem-solving, more involvement in sports to develop that competitive spirit, and then take it into schools and encourage girls to get into math and sciences. Make it fun—hands-on—demystify things,” she said. “When you start seeing that women are in powerful positions then it demystifies the role,” said Amicarella. It allows other women to say, “If she can do it, I probably can do it!” When recruiting personnel, Amicarella looks for the combination of diversity and talent. She suggested the key is to have a diverse slate, and then pick the top candidate. “My leadership team from seven months ago to today is a very diverse leadership team, and it’s not by accident,” she said.
Using Autonomous Drones in the Power Sector. Drones, or unmanned aerial vehicles (UAVs), have been dabbled with throughout the power industry for years. POWER featured a drone on its cover in April 2014, and it has published many articles on drone technology since then. Yet, the technology has been used more as a novelty in the power sector up to this point. As a guest on The POWER Podcast, Reese Mozer, CEO and co-founder of American Robotics, suggested that could change in the very near future. “We’ve all been talking about this for a very long time—you know, a decade plus—and despite all that, we really are not even scratching the surface yet of the scale that drones will be implemented and the value that will come from them,” he said. “But we are about to enter a very different generation of drone technology—and really robotics in general—and, you know, I think the next decade is going to look quite a bit different.” According to Mozer, American Robotics has developed the next generation of drone technology. The company offers a fully automated drone system that’s capable of continuous unattended operation. Mozer explained that the autonomous drones work in conjunction with automated base stations to capture, process, analyze, and transfer data remotely to a user. The base stations charge and house the drones to prepare them for their next flight. He said this level of automation is key to finally unlocking drones as a viable tool for the energy sector. “The reality is that until we can remove the human from the loop, drones will not be able to scale to the levels that everybody has imagined,” Mozer said. “Once we can, [that] changes the economics of working with a drone. That changes the logistics. Not only does it make it affordable and practical to actually scale, it actually unlocks a whole different type of data collection, and thus, analysis that we can do on that data.” There are still some challenges to overcome, however, such as getting Federal Aviation Administration (FAA) regulations updated to allow autonomous operation. “That is the primary hurdle stopping this technology from taking off,” Mozer said. “American Robotics has developed the technology, the automation, the machine vision, the AI [artificial intelligence] that’s required to actually conduct these automated operations reliably in the real world. And the last step for us, and for the rest of the industry, is to overcome FAA regulations. “Beyond line of sight is probably the most key. There’s also a list of other ones that would prohibit this kind of automated operation,” he said. “And that's one of the reasons that we don't see drones flying all over the place right now.” There is reason for optimism. “We expect it in the near future,” Mozer said. “This topic is something that has been debated over and worked on from both a technology perspective and a policy perspective for really the past decade, and we think that that change is coming quite soon.”
What Is DERMS and How Can It Help Utilities? A distributed energy resource management system, or DERMS, is a software platform used to manage a group of distributed energy resource (DER) assets—such as rooftop photovoltaic solar panels, behind-the-meter batteries, or a fleet of electric vehicles—to deliver vital grid services and balance demand with supply to help utilities achieve mission-critical outcomes. As a guest on The POWER Podcast, Seth Frader-Thompson, CEO of the DERMS provider EnergyHub, said aggregating DERs can offer a number of benefits to power companies. For example, they may be used to support frequency or voltage on the grid, shift load, or provide emergency demand response. Although many utilities manage DERs through a relatively manual process today, Frader-Thompson said some companies are shifting to a more automated framework, in which computers are identifying issues in the system, proactively forecasting how DERs could be manipulated to mitigate the problem, and executing the strategy. “The utility grid operator does not want to think about a million individual batteries, rooftop solar systems, electric vehicles, smart thermostats, industrial process controllers, etc. They essentially want a virtual power plant and sort of a virtual knob for that plant that they can operate,” Frader-Thompson said. EnergyHub’s Mercury DERMS uses advanced machine learning-based artificial intelligence to manage resources. “We have invested many millions of dollars in a bunch of artificial intelligence that allows the system to take 100,000 resources that happen to be clustered around a certain city and stitch them together in a closed-loop way into something that allows the utility to sort of specify exactly the outcome they want,” said Frader-Thompson. “The DERMS is basically built to allow them to do either something very specific, or something very general, and kind of dial it into exactly what works for them.” In addition to complicating grid operation, the growth in DERs would seem to pose a business challenge for utilities too. For example, if more customers are generating their own power, that means the local electric company is selling less. But Frader-Thompson suggested DERMS could provide new revenue streams for power companies to tap into. “There are other ways to make money and the concept of a DERMS creating grid services from a big group of aggregated DERs is in and of itself another revenue opportunity for utilities,” he said. “Increasingly, you’re seeing regulators say, ‘You know what? This is really valuable to the grid. In many ways, this is preferable to ratepayers—to the community—over a traditional, capital-intensive infrastructure upgrade.’ And you're seeing those regulators say, ‘You—the utility—are able to make a regulated rate of return on that.’ ”
The Importance of a Resilient Power System. It’s hurricane season in the U.S., which runs from June 1 through the end of November, and there have already been three named storms. The most recent was Tropical Storm Christobal, which was the earliest third-named Atlantic storm on record when it formed on June 2. It made landfall in the U.S. along the northern Gulf Coast on June 7, with heavy rain, a storm surge of almost six feet, and a few tornadoes. “Irrespective of which part of the world you belong to, we are seeing the impact of severe weather across the globe,” Amol Sabnis, global lead for Transmission and Distribution with Accenture, said as a guest on The POWER Podcast. “One thing is clear—that the severe weather events are becoming a recurring global event.” Accenture recently released a report titled “From Reliability to Resilience: Confronting the Challenges of Extreme Weather,” which included insight gleaned from a survey of more than 200 C-suite and senior vice president-level executives at electric utilities spread across 28 countries. “We conducted this research to better understand the risks posed by increased frequency of extreme weather and how we can help our clients navigate these challenges by building a more resilient network,” Sabnis said. The findings from the study are eye-opening. Nearly nine out of 10 executives surveyed said extreme weather events had grown in frequency, severity, or duration over the past 10 years. Furthermore, more than nine out of 10 expect extreme weather events to increase over the next 10 years. Yet, less than a quarter of the executives felt well-prepared to manage the challenges of extreme weather events. “One of the things that we found in our research is that nearly every utility considers resilience as a matter of focus,” said Jason Teckenbrock, North American lead for Transmission and Distribution with Accenture, who was also a guest on podcast. “So, even if they’re not fully prepared, they know they need to focus on it.” Teckenbrock suggested that there are three steps utilities can take to improve resiliency. They can harden their networks, improve restoration effectiveness, and/or develop greater system flexibility. However, network hardening is costly, and improving restoration effectiveness takes time to implement and can require significant procedural changes. Therefore, the most cost-effective approach for enhancing resilience in many scenarios is developing greater system flexibility. Some ways flexibility can be improved include creating automated self-healing grids and incorporating artificial intelligence (AI) to help route electricity in a more appropriate manner. AI can also be used to conduct vegetation management assessments and to identify other risks. “We’ve seen lots of utilities starting to work on this,” Teckenbrock said. “We believe that taking a metric-based approach is important here.”
Tips for Check Valve Selection and Installation. Check valves are installed in many piping systems. Their purpose is to allow flow in only one direction, which can be critical for plant safety and to protect equipment from damage. There are a few different check valve designs, including swing check valves and spring-loaded poppet-style check valves. Understanding which type is best for a given application and ensuring valves are properly installed is vital to success. Noah Miller, applications/engineered sales manager with Check-All Valve Manufacturing Co., and Brian Strait, business development and marketing manager with Check-All Valve, explained the differences between check valve designs, and offered installation and sizing tips as guests on The POWER Podcast. Check-All Valve is a West Des Moines, Iowa-based manufacturer of industrial spring-loaded poppet-style check valves. Miller explained that piston poppet check valves have two main advantages over swing check valves. The first concerns water hammer, which is hydraulic shock caused when water stops or changes direction suddenly. “Once that wave gets to the swing check, it'll push that clapper closed and actually slam it shut, which will promote that water hammering effect,” Miller said. However, the spring inside a piston poppet-style check valve helps minimize, and may even eliminate, water hammer, because it closes the valve before the pressure way arrives. “The secondary aspect or advantage of the piston poppet over a swing check is installation orientation,” Miller said. “A swing check is only supposed to be installed in a horizontal-flow position. Whereas, a spring-loaded piston check can be vertical-flow up, vertical-flow down, 45 degrees, 37 degrees, you can kind of pick and choose with that spring, because it allows it to still close in a static condition in the piping system.” Another consideration when installing check valves concerns the run of piping. Miller noted, “Ideally, you'd like to have a minimum of 10 pipe diameters of straight pipe on the upstream side of the check valve.” The reason is to ensure the flow through the valve is laminar in nature, that is, fluid particles following in smooth layers, with little or no mixing. Miller said that would maximize the effective valve life. Getting a valve sized correctly for the application is also important. The goal is for a check valve to always be either fully open or fully closed. “Pressure and flow together create pressure drop across the given check valve,” Miller said. “You can have enough of one, but not enough of the other.” Miller presented an example of a system with 300 psi of pressure, but only 0.005 gpm of flow. He said, “You’re not fully opening any check valve, it doesn't matter what style it is, because you’ve got enough pressure, but you don’t have enough flow, and that pressure and flow together create that pressure drop to fully open the valve.” Listen to The POWER Podcast to hear the complete interview.
Understanding the Dangers of Hydrogen Sulfide Gas. Hydrogen sulfide (H2S) gas is produced as a result of the microbial breakdown of organic materials in the absence of oxygen. It can be found in tanks, vaults, voids, and other confined spaces at industrial facilities including power plants. Besides being flammable and corrosive, H2S is also colorless and toxic, even in relatively low concentrations, so it is extremely hazardous to workers. In fact, it is the second-most-common cause of workplace inhalation fatalities behind carbon monoxide. H2S is noticeable initially by its rotten egg smell, but the gas can deaden senses making it difficult for workers to detect without a gas monitor. Veriforce CEO Colby Lane and Chris Detillier, senior safety analyst with Veriforce, were guests on The POWER Podcast. Veriforce is a leading provider of software and services that enhance workforce and community safety. Among its offerings is a training course called H2S Clear, which provides students with life-saving information while meeting the compliance requirements of ANSI/ASSP standards. “It's extremely toxic. As little as 700 parts per million can cause someone to immediately collapse, and they can die from it,” Detillier said. “So, it is very important to have a good training program in place.” Lane explained that Veriforce’s training model essentially credentials and accredits instructors. Then, those instructors provide the training to actual workers. Detillier said he’s received a lot of positive feedback every time he’s taught a “train-the-trainer” class for H2S Clear. “We've had guys that have been in the industry for years—some of them who have previously been through H2S training—and after class would tell me how much that they learned from the class and appreciate the content that we have in there.”
Solar Power Is Cheap and Getting Cheaper. In many locations, solar power is already the lowest-cost renewable energy alternative available. Some of the advantage stems from advancements made in manufacturing processes and economies of scale that solar companies have captured. Operating costs also factor into the equation—solar’s operating costs are minimal while operating expenses for wind power are more substantial. Still, Brendan Duval, CEO of the Glenfarne Group, suggested the gap between wind and solar costs could widen. “The cost curve for solar has probably got some room to run. Wind is sort of, you know, plateauing out now,” he said as a guest on The POWER Podcast. The Glenfarne Group is a New York-based energy and infrastructure assets owner that develops, constructs, and operates projects across the investment-grade Americas, including in Chile, Panama, and Columbia. Duval said the Glenfarne Group has two distinct business units: a power unit, and a midstream oil and gas unit. Each of the business units are also separated into two different segments. The legs of the midstream unit are divided between a gas gathering business and a liquefied natural gas (LNG) export development project in Texas. On the power side, there is a renewables arm and a backup power arm. “Backup power plants—we think—are really important in the energy transition process,” Duval said. “As more and more renewables come online, having [a] well-run, well-put-together backup power plant network in any country is really important. And we've got a long-term vision for that,” he said. But the Glenfarne Group isn’t just backing up renewable energy projects, it’s also investing in them. Duval said his team focuses on run-of-river hydro projects rather than dam hydro because they are generally smaller and face fewer hurdles during the development process. There is often political pressure surrounding dams, and navigating interactions with the local community, government agencies, agricultural entities, and environmental groups can be daunting. In run-of-river projects, the water is taken out of the river for a kilometer or two, and then it’s returned to the stream, so the disruption is much less extreme. “The run-of-river hydro is just [an] easier asset for us to manage within the community,” Duval said. Duval noted that run-of-river hydro development has really slowed down in Latin America for a number of reasons. For one, the best sites have already been taken. The permitting process has also become more difficult. And finally, power prices have decreased significantly. “When governments are now looking for renewable opportunities, they're looking for a lower price point. And they can achieve that lower price point with renewable sources by looking at solar and to some extent wind,” said Duval. “So, if you look at the dollars per megawatt invested, solar is the most cost-effective, then wind, and then run-of-river hydro. And the cutoff point now is really in that capital cost between wind and run-of-river hydro.”
Technology for Managing Distributed Energy Resources. With the growth of distributed energy resources, including rooftop solar, wind turbines, battery energy storage systems, electric vehicles, and demand response technology, distributed energy resource management systems (DERMS) are becoming increasingly important for utilities. Brad Williams, vice president of Industry Strategy with Oracle Utilities was a guest on The POWER Podcast. He touched on a number of topics, including how DERMS are helping power companies, how electric vehicles are challenging the industry, and how utilities are dealing with the proliferation of edge devices and data. Williams said managing the variety of resources that exist will be a key to meeting renewable energy standards in the future. “Being able to manage these resources—whether they’re distributed energy resources or electric vehicle charging equipment—being able to manage those and forecast—predict—what their operation will be is going to be critical for utilities to be able to fully embrace these renewables standards, because by nature renewable energy is intermittent, which means utilities will have to do more to manage the demand side.”
What Does It Take to Develop Utility-Scale Solar Projects? Constructing a utility-scale solar project requires more than simply buying PV panels and mounting them in a field. It can take years to find the right location, conduct feasibility studies, obtain permits, and align the proverbial stars. A couple of experts, who have managed multiple projects through the process, were guests on The POWER Podcast. Carl Jackson and Charles Silio, two of the three partners who founded Glidepath Ventures, a company focused on solar project development in PJM and other fast-growing solar markets in North America, provided a high-level overview of the development process and explained what drew them to the PJM market. “There’s an old saying in solar that every project that actually gets built dies a thousand deaths, and that’s probably accurate,” Jackson said. “A lot of that has to do with all the things that you deal with at the beginning stages of development.” Jackson earned his stripes by leading project origination and business development for Cypress Creek Renewables, where he worked on solar energy projects in a variety of states. Some of that experience helped inform the partners’ decision to focus on the PJM market, and Pennsylvania in particular. “One of the reasons we picked Pennsylvania was it’s very close to a lot of load in the competitive PJM market. There are multiple opportunities for corporate or municipal offtake, and a lot of companies, municipalities, and universities—even within the state of Pennsylvania—that have sustainability goals, who are actively looking for renewable power. In addition, it being PJM, you can sell via contract for differences to corporates or other buyers anywhere within PJM. And failing that, if you really want to run a plant merchant, there’s a fairly liquid market for power and for other ancillary services and capacity,” Silio said. Most people probably don’t think of Pennsylvania as a solar power hotbed, but in some ways that works to Glidepath Ventures’ advantage. There is less competition from other developers, and land is reasonably priced. However, most landowners aren’t particularly well-versed in the benefits that solar power projects can offer. “You may get some inbound calls from a landowner because their neighbors or friends in that community have had success with a project, but a lot of the areas that we’re targeting, we’re one of the first phones calls that they’re receiving or the first phone call that they’re receiving,” Jackson said. “Most of the time, we’re proactively reaching out to landowners, educating them exactly on what solar is, what the actual economic impact could be for them, and then getting them onboard.” But there is a fair amount of work done behind the scenes before a landowner is contacted. “We canvas areas to make sure that we have what we anticipate as at least a reasonable opportunity from an electrical perspective to interconnect the type of projects that we actually want to interconnect there. Then, we reach out to landowners,” said Jackson. “We ultimately get a lease option or some sort of lease agreement with those landowners, and then begin the process of entering into PJM, getting an interconnection feasibility study completed, and then working our way through all the studies through PJM, as well as starting the process of getting the requisite entitlements needed to deliver that project.” Jackson said those steps can take anywhere from 18 to 24 months for projects connecting at 69 kV or higher. For projects connecting at the distribution level (less than 69 kV), the timeline for getting the interconnection agreement from the utility and PJM can be shortened to about 12 months or so. Then, it can take another six months to a year to satisfy all the state and local regulatory requirements before the project is ready to begin construction.
PLM, ERP, EAM, Digital Twin: What Do They All Mean? The power industry and technology worlds are filled with acronyms. It’s often hard to know what they all mean. Mark Reisig, director of Product Marketing at Aras, was a guest on The POWER Podcast. He explained how digital technology is being utilized to bring products to market and track assets throughout their lifecycle. The process often starts in a product lifecycle management (PLM) system. Reisig said when a product is created for the first time, things like the engineering bill of materials (BOM) and computer-aided design (CAD) drawings can be linked to the component in a PLM system. In all, he said there are about 20 key attributes documented in the system. They typically revolve around the form, fit, and function of the product, including its description, revision, unit of measure, part number, and more. The PLM information feeds into an enterprise resource planning (ERP) system. ERP is a transactional system. It coordinates how everything is put together. It tracks what is made and what is bought—including financial data—and allows the product to be manufactured and assembled. ERP systems often include 150 to 175 different attributes. When complete, the ERP provides an as-shipped BOM. At that point, an enterprise asset management (EAM) system becomes important. It is used to track and manage the physical asset through its lifecycle. This basically covers construction, commissioning, operations, and maintenance, all the way to decommissioning and replacement. As an enterprise tool, it goes beyond a single plant to include all the assets an owner manages. The idea is to track all the changes to all the physical assets, which is what Reisig called an “as-maintained” or “as-running” BOM. The EAM system also facilitates planning and execution of the work required to keep everything running. “The real value of the three systems that I just mentioned is that you can connect across them in a digital thread,” Reisig said. “The person looking into the enterprise asset management, when they click on a digital twin, if they want to go back and see what the actual requirement was, they can actually do so. So, the real value is when you can cut across all of these pillar systems—EAM, ERP, and PLM.” What is a digital twin? Reisig said most vendors position digital twins as models. The models are typically created during the engineering phase, which means they are a representation of what was designed. However, they don’t always reflect what was actually made during the manufacturing or construction process. “Right there, you’ve got a problem, and that’s because many things happen to products when they go through production,” Reisig said. “We believe the digital twin is first available after it’s been manufactured, and even after it’s shipped, during the as-built stage.” By creating the digital twin in the as-built phase, much more detailed and accurate information can be captured. In this way, physical part BOMs and related simulation data can be linked to the digital twin. Things like CAD drawings, service bulletins, work order history, electronics wiring schematics, and more, can be connected using a digital thread back to where that information is stored. “Our definition is: the digital twin is the individual configuration of that physical product or a system of assets, and that creates the context you need to create value across the lifecycle,” Reisig said.
Are Traditional Power Companies Being Disintermediated? How will the electric grid change as the world transitions to a power system with more renewable energy resources? Some experts foresee a shift from today’s grid-type architecture to a system of systems—from the current centralized design to a distributed energy scheme. While it’s hard to know exactly what the future holds, it’s commonly believed that change is inevitable. Shuli Goodman, executive director of LF Energy, was a recent guest on The POWER Podcast. LF Energy is an open-source initiative, overseen and hosted at The Linux Foundation. On the podcast, Goodman said power companies need to think of themselves more like network operators rather than as conventional utilities; otherwise, they may become irrelevant within 10 or 15 years. “I think that any utility on the planet—particularly playing at the distribution level or an investor-owned utility—if they are not thinking of themselves as a network operator, they’re going to be disintermediated. And in the U.S., I think they’re going to be disintermediated by the Google’s, Amazon’s, and Apple’s for sure, because those companies are going to own their customers,” she said. Goodman said two main factors are driving the change: decarbonization and electric mobility. “We have to get to 100% decarbonization in 20 years. But I think that we have to be able to show tremendous progress in 10 years,” Goodman said. “I think that the easier part of the equation is onboarding the generation assets at scale from a utility-scale perspective. I think the more complicated problems that we’re trying to solve for—and will need to solve for—are what happens behind the meter.” Goodman suggested consensus among European Commission members is helping Europe move quickly toward a clean energy future. In the U.S., however, she said the government is sending mixed signals. “Recently, [the Department of Energy] said that they were making a $64 million investment in coal,” said Goodman. “That kind of confusion in the marketplace from a signaling perspective is going to be extremely damaging to the economy of the United States. I have no doubt about it that we are going to suffer tremendously from that.” Goodman said the economics are clear. “Right now, renewable energy is on par with any other kind of traditional energy or it is now becoming cheaper,” she said. “What’s going to happen is a level of innovation that’s going to occur in Europe in which actually the cost of energy is going to get less, and less, and less, and less.” The reason that’s important is because energy equates to productivity or production. “There’s a very tight integration between economics or economies and energy,” Goodman said.
Why Do People Choose Careers in Engineering? Do you want to solve important problems, contribute to society, and help people? Well, then, you may want to become an engineer. At least that’s why some successful engineers have said they entered and persist in the occupation, according to a recent study published by DiscoverE, an engineering outreach organization based in Alexandria, Virginia. The research was conducted by DiscoverE in partnership with the Concord Evaluation Group. It specifically sought to answer the question: What are the common factors that motivate girls to pursue—and then persist—in engineering education and careers? Thea Sahr, director of Communications and Programs with DiscoverE, discussed some of the findings as a guest on The POWER Podcast. “We’re finding that the women who are staying in engineering have a really strong support network, whether that’s family or friends or they have role models, that network is super important,” said Sahr. “They can draw on past obstacles. They have the cultural and social capital to get through the tough times—that resiliency, that grit that we hear is so important for all of us—and a sense of belonging. The women who feel a sense of belonging, either in their university or at their place of employment, have a better chance of staying.” So, do men have other reasons for getting into the engineering field? Not really. Sahr said DiscoverE has done additional surveys asking people what attracted them to the profession, and across the board, women and men said solving critical problems was the main reason they liked engineering. But many kids don’t get the opportunity to really understand what an engineer does. That’s why DiscoverE’s work is so important. The group helps get the word out in schools and through other events throughout the year. In fact, DiscoverE is the backbone organization behind Engineers Week, which was established in 1951. The week begins this year on Feb. 16 with the theme “Engineers: Pioneers of Progress.” Learn more about it at DiscoverE.org. Sahr suggested the outreach is vital. She said DiscoverE has conducted surveys of 11- and 12-year-old kids, and it found that 92% of those surveyed were thinking about their future careers, even at that early age. “It’s not just when Grandma asks at Thanksgiving, they’re thinking about this pretty seriously,” Sahr said. Another DiscoverE-sponsored program begins on March 11 and runs on Wednesdays through April 8. Called “Global Marathon,” it will be a five-part series with stories from inspiring women in the engineering and technology fields. It’s a free web-based event designed to provide actionable career advice and connect women around the globe.
How Utilities Can Manage Supplier Risk. Power companies are turning to external suppliers and contractors now more than ever. Utilities are getting help with tasks ranging from the relatively simple, such as vegetation management and the handling of customer calls, to the complex, including turbine repair and large infrastructure projects. Although the benefits of utilizing contractors are often obvious, the dangers, which include cyber, reputational, financial, legal, and regulatory risks, may not be as easy to assess. Two Boston Consulting Group (BCG) experts, Mike Lewis and João Maciel, were recent guests on The POWER Podcast. Both men are managing directors and partners with BCG based in Houston, Texas. Lewis leads the firm’s Houston office, while Maciel specializes in green energy, energy efficiency, and the environment. The pair helped author a paper on supplier risk management best practices and shared some tips during an interview for the podcast. Maciel noted that outsourcing amplifies three main risks that utilities are typically already exposed to in their businesses. Those are operational risk, reputational risk, and cyber risk. For example, if a contractor fails to follow suitable health and safety practices, then a utility could be operationally affected by the consequences. Additionally, power companies may be held accountable by the community or media when a contractor makes a mistake, which places the utility’s reputation at risk. Lastly, even though a utility may have excellent internal protocols designed to protect digital plant systems, when suppliers are given access to perform work, the utility’s risk increases. Suppliers also bring new risk exposure, such as fourth-party risk, which arises when a supplier uses subcontractors. Another added risk is contractual risk, which may limit a utility’s ability to monitor a contractor’s work. Concentration risk is also a potential problem. If a utility becomes too dependent on a supplier, it could lose bargaining power and internal expertise, which could lead to the last risk Maciel discussed: financial risk. That threat can be realized when a supplier falls into financial distress. If a power company can’t quickly replace the supplier, the utility’s operations could be adversely affected, which could have financial implications. On the podcast, Maciel presents a method to manage the risks. “One of the principles of the approach is that the complexity and the hard work and the really detailed design happens in a center of excellence in the corporate center,” Lewis explained. “It is very tailored to the needs and very, very user-friendly for people at the front lines.” Lewis said a lot of the setup and screening is done as vendors go through the procurement and contracting process, well before a job is scheduled to take place. “When things are the most complex, when the timing is tight, when deadlines are short, when a lot of people are onsite, that’s when a lot of the potential incidents could happen,” Lewis said. That’s why it’s important for utilities to manage risks appropriately in advance.
Good Water Treatment Systems Need Both Equipment and Chemistry. Proper water treatment is vital to successful power plant operation. The water treatment system must be designed appropriately, implementing a suitable water chemistry program, and operated and monitored correctly. Having adequate training and utilizing the services of a knowledgeable partner can be invaluable. Three water industry experts from U.S. Water, a Kurita company, were recent guests on The POWER Podcast. Kevin Milici, vice president of Marketing and Technology; Nathan Bach, vice president of Engineering Services and Equipment, and Joe Tirreno, vice president of Strategic Corporate Accounts shared insight from their years of experience helping customers develop sound water treatment solutions. Bach noted that many older power plants are shifting from primary ion exchange, that is, cation-anion mixed beds, to membrane treatment systems for their demineralized water needs. Meanwhile, some that may have had older-generation membrane treatment systems, such as reverse osmosis (RO) and electrodeionization (EDI) systems, have been upgrading to include ultrafilters ahead of the RO to reduce fouling and extend membrane life or utilizing two-pass RO units to reduce the loading on EDIs. A lot of things must be studied when designing a water treatment system for a power plant. Bach said boiler operating pressure is one of the first considerations, but the raw water source is also very important. “A plant that operates on well water will have different challenges than one that operates on surface water or maybe even a plant that has multi-source—maybe they have a blend of surface and well water or multiple wells of different depths blending into a common feed point into the plant,” Bach said. “Knowing where the water comes from really helps us determine how we might need to treat it.” Tirreno said two of the most important items in a power plant are steam quality and condenser cleanliness. He noted that most plants spend significant amounts of money to monitor steam quality, but they don’t always do the same on the condenser side. He said monitoring equipment is available today that allows biofilm and corrosion to be more instantaneously scrutinized. “The steam side is important,” Tirreno said, “but don’t forget the condenser side as equally as important to ensuring efficiency of electricity generation.” “The takeaway is that we can’t just think of it in terms of chemistry or equipment, we have to think of the combination of those things,” Milici said. “Every situation can be unique. It’s a function of the customer’s assets, their design, the water qualities that they’re working with, the other challenges they might be confronted with, for example, water scarcity or the discharge of conventional phosphate-bearing treatments and having to minimize those and look for alternative chemistries. So, my takeaway would be that it’s not one or the other, it’s the ability to be able to look at both of those levers in looking at the total solution and put them together in the right proportions to deliver the best and most cost-effective result.”
Recruiting the New Power Workforce. It’s a time of great transition in the power industry. Not only are generation resources changing, but so are the work skills needed to operate and maintain those resources. Meanwhile, a large number of workers are reaching retirement age, leaving open positions that had long been filled by highly experienced staff. And the talent pool to fill those positions is not as large as many employers would like. Robin Schawe, vice president and global workforce solutions leader with Kelly Services, discussed some of the challenges as a guest on The POWER Podcast. She offered insight into some of the trends Kelly Services is seeing in the power industry. “Our research shows that up to 30% of the overall industry will be ready to retire within the next 10 years, with 10% being ready to retire now, 11% within the next one to five years, and 10% over the next six to 10 years,” she said. “While these retireants mount, the industry grows younger—22% of utility industry workers are below the age of 34. The concern becomes making sure there are no skills gaps, and we’re seeing a lot of effort in this space.” Schawe suggested transition planning and knowledge transfer is key. Still, filling technical positions can be particularly difficult. “The number of graduating engineers is on the decline and recruiting new workers with the right skillsets for those jobs is becoming more and more difficult each and every year,” Schawe said. However, leading companies are doing innovative things to attract the right people. “What we’re seeing is that power generation companies are starting to engage with those pools of talent very early in a new and exciting way,” she said. “One utility I know does outreach as early as middle school, educating children on what a utility does and the different types of careers available. I see high schools with some amazing apprenticeship programs. For example, my local high school has a four-year welding program. I also see a lot of power generation utility organizations making very strategic commitments and investments into hiring veterans. It’s an exceptional source of talent.”
Is Carbon Pricing the Key to a Clean Energy Future? The New York Independent System Operator (NYISO) has proposed incorporating the social cost of carbon into the wholesale price of electricity. According to an October-released study conducted by the consulting firm Analysis Group, “A carbon price in NYISO’s competitive wholesale power markets can help deliver New York’s clean-energy transition in faster, cheaper, more reliable, more efficient, and more creative ways.” NYISO President and CEO Rich Dewey was a guest on The POWER Podcast. He seemed to agree that carbon pricing is the best way for New York to achieve its clean energy goals. “We just thought that unleashing the power of competitive markets is really the most cost-effective and the most efficient way to do that,” Dewey said. “So, we designed a mechanism by which New York state as the policy-setter could establish a social cost of carbon. We could embed that cost right into the offers that the generators put in for producing power, and using the competitive forces, we could reward those sources of power that are zero or low-emitters and at the same time institute a payment, if you will, for the emitters of carbon dioxide to essentially pay for the pollution that they’re putting into the air. And we thought that by using the competitive market forces and the optimization engine that we have in place that we could more-efficiently and more-effectively achieve those carbon reduction goals from the electric sector.” NYISO is the first ISO/RTO in the U.S. to propose a market-based mechanism for pricing energy-based carbon emissions. It would incorporate a carbon price in the NYISO-administered wholesale energy markets, in dollars per ton of CO2 emissions resulting from power plant operations. The carbon price would be based on the social cost of carbon emissions, which is to be established by the state. Power plant operators would include their expected cost of carbon in their NYISO market offer prices, in dollars per unit of electricity sold. While suppliers of power with zero or low CO2 emissions would benefit from higher net revenues, fossil generators’ payments would reflect a deduction for the carbon charges related to their emissions. Retail electricity suppliers (known as “Load Serving Entities” in the NYISO market) would be charged the locational price for power they need for their consumers, with that price reflecting carbon-related costs. They would also receive a credit to substantially offset the impact of carbon pricing, because consumers would see a portion of the carbon charges collected from generators returned to them. The carbon charge would provide incentives to suppliers of power with low or no carbon emissions, including innovative low-carbon technologies that may not yet be developed or are unable to be commercial in wholesale markets that do not include carbon pricing. Imports of power into New York would include a carbon price to discourage leakage of CO2 emissions from neighboring regions. “We’re sensing that even some of the participants who were skeptical or opposed to it are now recognizing it is the most cost-effective way to achieve these goals,” Dewey said. The Analysis Group found that carbon pricing could save up to $850 million while achieving New York’s aggressive climate targets.
Experts Share Insight on the Industry at Recent Power Event. POWER was at the POWERGEN International exhibition and summit, which was held in New Orleans, Louisiana, Nov. 19–21, 2019. Among the experts we met with at the show were Paul Browning, CEO of Mitsubishi Hitachi Power Systems Americas (MHPSA); Chris Mieckowski, director of global solutions marketing and strategy with Siemens; Robert Yeager, president of Emerson’s Power and Water Solutions business; Britt Burt, vice president of power industry research at Industrial Info Resources (IIR); and Eduardo Almeida, director of innovation with Industrial Specialists By BrandSafway. Here snippets from the interviews on The POWER Podcast. Topics covered include the latest developments in gas turbine and digital technology, energy storage and wind power growth, and innovative power industry solutions.
Using Extreme Visibility to Protect Industrial Control Systems. What does it mean to have “extreme visibility” in an operational technology (OT) environment? According to Claroty, a New York-based company that offers cybersecurity products for industrial control systems, it’s having the ability to see all assets on a network, knowing what they are, and understanding what functions they perform. The company says the more organizations know about their OT network assets, the better equipped they will be to detect and investigate suspicious behavior. “In order to really understand how to protect these networks, you really have to have your finger on the pulse of the threat landscape,” Dave Weinstein, Chief Security Officer with Claroty, said as a guest on The POWER Podcast. “With respect to industrial control systems, nation-state actors continue to monopolize, if you will, the threat landscape. That is to say that the barriers to entry are sufficiently high enough at this point to prevent your average script kiddie or high school hacker from doing serious damage to, for example, the electrical grid,” Weinstein said. “But our observation is that those barriers to entry that I referred to are slowly but surely falling to the point where in the next couple of years we may start to see non-state actors penetrate this threat landscape, which of course is a troubling scenario because it’s much more difficult if not impossible to deter non-state actors.” Weinstein said one of the main factors contributing to increased cyber risk is that OT networks, which have historically been isolated from the internet, are increasingly connected by way of corporate IT networks. “Our assessment is that it’s only going to grow more connected with time, which compels organizations to think really proactively about how to deal with this phenomenon,” Weinstein said. “Quite frankly, the first step is gaining really deep visibility of the assets on the OT side of the house. What once was a trusted network can no longer be trusted,” he said. Most of the traffic on OT networks involves machine-to-machine communications. That can actually be beneficial when it comes to threat detection. “When you’re dealing with industrial control systems, they are communicating in highly predictable ways. It’s repeatable. There are lots of patterns. Deviations from those patterns are typically indicative of either a malicious threat or some sort of operational anomaly,” Weinstein said. “We perform something called deep-packet inspection on all the network’s communications. And by doing that, we’re able to—at a very granular level—understand the communications between all these devices and parse their protocols,” said Weinstein. The result is that end-users get the information needed to better understand security and operational events, so they can perform actions to mitigate risks.
Using Data to Improve Power Plant Operations. Power plants have an abundance of data. Temperatures, pressures, flows, and various other parameters are all monitored constantly to ensure plants are operating properly. However, a lot of data is not used to its fullest extent. With the right tools, data can be more-thoroughly analyzed and findings can be acted upon to improve efficiency and catch asset deterioration before equipment fails. David Thomason, industry principal of Global Power Generation with OSIsoft, was a guest on The POWER Podcast. OSIsoft offers several solutions for the power industry that help utilities ensure reliable and stable system operation. “What we’ve seen is kind of an evolution of what we’re calling layered analytics,” Thomason said. “You really want to be able to monitor the health of your assets in real time. So, it’s kind of a movement from periodic conditioned assessments around equipment and assets, and move to a more online condition monitoring.” Thomason mentioned an innovative solution that has been implemented at the Itaipu dam in Brazil. The facility is using a real-time data system to scrutinize the structural integrity of the dam. He said there are “key blocks within the hydroelectric facility” that were instrumented with sensors that can detect movement. The system allows operators to monitor the health of the entire structure. “It’s such a cool use case that I really wish I could see this expanded across multiple places, of course, multiple hydro dams, but also even things like tunnels and bridges,” he said. In another example, Thomason said several power companies around the world are incorporating parameters such as depth and density of snowfall into water inventory calculations to allow better day-to-day decisions and optimize hydro resources. “This is that whole concept around using data and information in ways people really weren’t planning to use in the past, but being able to have it available to help them to make those types of decisions,” said Thomason.
What Can You Do with a Superconductor? A Lot! [PODCAST] What is a superconductor? One definition says, “a material that can conduct electricity or transport electrons from one atom to another with no resistance.” “At the base physics level, what a superconductor does is it moves a lot more power per unit volume or per unit weight, so you have a very high energy-dense material that can move lots of power,” Daniel McGahn, CEO of American Superconductor (AMSC), explained as a guest on The POWER Podcast. “So, from a very simple standpoint, we can move transmission-level power at distribution voltage simply with the energy density.” AMSC is a global energy solutions provider serving both the power grid and wind industries. “Everything we do revolves around resiliency—either of the grid, infrastructure, or of Navy ships,” McGahn said. “We do a lot of grid interconnection of wind to the grid. We do voltage support within the grid. We do voltage support for large industrial consumers of power, things like mills, mines, and semiconductor fabs—all large instantaneous users of power. We have a solution for them to be able to protect the grid from their operations,” he said. The focus of AMSC’s grid business is really on “trying to move power with a purpose,” McGahn explained. What that means is AMSC technology can interconnect substations on the distribution side to allow them to work as one. This allows a very small conduit to be used under city streets in the urban core. “So, it’s not really a power cable, it’s more like an extension cord or a long bus bar that connect two physical assets that exist,” McGahn said. “When we look at multi-point connections throughout the city, we have the potential to double if not quadruple the overall resiliency of that urban system.” AMCS has done work with Boston, Washington, D.C., San Francisco, Seattle, and Chicago. “What we see are very similar vanes of need. The first one is we need to bring more infrastructure into the urban core. We don’t have access to land. It can be quite expensive to do it. And our idea is, ‘Why don’t we untrap and unleash the trapped capacity that already exists within the system and have it work more like a multi-point network,” said McGahn. “Most of the things we do on the grid really revolve around hardening, bringing more resiliency, bringing more leverage of existing capacity. And we’re trying to do that in a way where we don’t extend the cyber footprint of the system,” he said. AMSC’s technology is also being used on U.S. warships to counter minefield threats. Many mines are activated by sensing a change in magnetism, which can be caused by a ship passing through the water near them. World War II technology utilized copper degaussing coils to reduce magnetic signatures, but a lot has changed since that time. McGahn said ships now go a lot faster. Furthermore, threats today tend to be concentrated in shallower water and sensors have become more sophisticated. The Navy realized new solutions were warranted. “They’ve invested around $30 million of development money. We’ve done full qualification. We’ve done tens of thousands of hours at sea on multiple different ship platforms and we just recently—at the end of last year—converted that into a full order and instruction to deliver a complete system for the first ship. And the second ship, we announced earlier this calendar year,” McGahn said.
Engineering a World-Class Gas Turbine. GE introduced the F-class gas turbine to the power industry nearly 30 years ago. Since that time, more than 1,500 F-class machines have operated for more than 54 million hours. With available outputs ranging from 51 MW for a GE 6F.01 simple cycle unit to more than 1,000 MW for a 3x1 7F.05-based combined cycle plant, the F-class is a versatile workhorse around the world. Don Brandt, former manager of GE gas turbine engineering, has been called the father of the F-class, but he is hesitant to accept all the credit. “I can’t express enough the number of people and the skills—the broad skills—that made that F machine a success,” Brandt said as a guest on The POWER Podcast. “Just the little thing like the rolling of a thread became critical to the success of the F machine, because if that thread broke, you lost the continuity of the rotor, the rotor would vibrate, the machine would shut down, it wouldn’t be a success.” During the interview, the 87-year-old Brandt reminisced about his career with GE. He joined the company in 1963 and quickly found his calling in the gas turbine business. From working with slide rules and computer punch cards to high-tech design using finite element analysis, Brandt has seen it all. Yet, what impresses him the most is the teamwork required to produce revolutionary gas turbines. “It wasn’t me. It was hundreds of people doing really creative things,” Brandt said. “And that’s still true. I went down to Greensville this past spring to see the 9HA.02 prototype. They were gracious enough to bring me down there. And the work that those people are doing down there—the individuals, manufacturing, materials, design, you name it.” Brandt is proud not only of the work he did, but also of the industry he supported. “The gas turbine business has really accomplished a lot to the betterment of society, and I gotta tell ya’, that thrills the livin’ daylights out of me.”
Large Public Power Systems Are Evolving. The power grid is changing across the U.S. More distributed energy resources are being added every day. That brings challenges for power utilities, but also opportunities. John Di Stasio, president of the Large Public Power Council (LPPC), which represents 27 of the largest locally governed and operated not-for-profit electric systems in the U.S., was a guest on The POWER Podcast and discussed how the changes are affecting his organizations members. As large infrastructure developers and asset owners, the LPPC’s members are uniquely affected by certain policies in Washington, D.C. Di Stasio, who previously served as general manager and CEO of the Sacramento Municipal Utility District (SMUD) from June 2008 through April 2014, said his group has been focused on tax, infrastructure, cybersecurity, environmental regulation, electrification, and grid modernization initiatives. Di Stasio noted that the U.S. power grid was originally designed as a central station system with one-way power flow from generators to consumers. “Now, we’re looking at much more distributed generation potentially, and also the fact that two-way power flow provides some additional opportunities and capabilities for consumers, also some additional complexity,” Di Stasio said. He suggested the benefits of digitization should be taken advantage of, which could allow a communications or digital network to be incorporated on top of the grid’s physical network to allow more interoperability. “I think a lot of that’s already underway,” he said. However, “it’s very hard to do something like that on a top-down basis given the fact that the grid is designed and operated differently all over the United States,” Di Stasio said. “My argument would be you should start with the building block of local distribution grids and actually build from the ground up rather than the top down in order to modernize the grid in the most effective and kind of no-regrets fashion, if you will.” DiStasio noted that distributed generation is becoming more prominent not only in states like California and New York, where there have been strong policy pushes to develop distributed resources, but also throughout other regions of the U.S. “The economics warrant that these kind of investments get made all over the country, and I’m seeing that as a significant change than maybe just a decade ago,” he said. Concerning cybersecurity, Di Stasio said, “We need good practices. We need good principles. We also need flexibility and we need significant coordination.” He noted that with more interoperability and more devices on the grid, more surfaces for entry exist, but he suggested advances have been made to protect industrial control systems, and a lot of “best practice sharing” is taking place across industry sectors.
Renewable energy and battery storage are hot topics in the U.S. today. Lawmakers throughout the country debated various new energy policies during the 2019 legislative session. Nevada is among the states leading the way forward. Several new laws were passed in the state that will affect power companies and consumers for years to come. Curt Ledford, a Nevada-based attorney who is a partner with Davison Van Cleve PC, was a guest on The POWER Podcast. Ledford’s practice is focused on utility, administrative, corporate, cooperative, and regulatory law, as well as general matters affecting energy developments, generation facilities, renewable energy, and Nevada’s utilities. On the podcast, Ledford touched on several legal and legislative developments that occurred recently. Among the topics were changes to Nevada’s fundamental utility ratemaking structure and changes to the state’s open access for large customers. He also elaborated on an update to the state’s renewable portfolio standard, which requires 50% of Nevada’s energy to come from renewable sources by 2030. In December, the Nevada Public Utilities Commission approved NV Energy’s proposal for the state’s largest-ever solar energy investment, six new solar energy resources totaling more than 1,000 MW, as well as 100 MW of battery storage capacity. Ledford talked about the company’s commitment to double its renewable energy by 2023.
Nuclear power advocates suggest there are many benefits associated with nuclear energy. They point to high-paying jobs; billions of dollars in economic activity for plant-hosting communities; and secure, reliable, baseload electricity. But the most-important benefit of nuclear power may be that it emits no greenhouse gases, and therefore, does not contribute to climate change. According to Nuclear Matters, a national coalition that works to inform the public and policymakers about the benefits of nuclear energy, nuclear power is playing an essential role in the U.S.’s clean energy future. The group says nuclear power accounted for more than 55% of the country’s clean energy generation in 2018, and phasing nuclear energy out would create devastating environmental impacts for the world. Carol Browner, former U.S. Environmental Protection Agency administrator and former energy and climate change senior advisor to President Obama, was a guest on The POWER Podcast. Browner, who currently serves on the Nuclear Matters Advocacy Council, said, “Air pollution is a major burden to human health, and electricity generation is a major source of air pollution. The burning of fossil fuels contributes to air pollution, obviously, contributes to climate change. Nuclear energy, or nuclear electricity generators, do not emit significant amounts of air pollution, and so, as companies and states look at closing existing nuclear facilities, the likelihood is that those will be replaced, at least in the short term, with fossil fuel-burning facilities, and that means more air pollution and more climate change challenges.” As an environmentalist, Browner has long advocated for renewable energy, and that hasn’t changed. “I support much more wind and solar. I hope to continue to see that industry grow. It has grown significantly and it continues to grow,” she said. But with climate change top of mind, Browner believes nuclear power has a place in the energy mix too. “I also believe that the climate change crisis is real. That we need to act responsibly. We need to act immediately. And taking a source of clean energy, of carbon-free energy—nuclear power—offline and replacing it with fossil fuels simply doesn’t make any sense. There are deaths associated with the fossil fuel burning. There’s the climate crisis. And so, what we need to do is maintain those facilities,” she added. Can climate change be stopped? “I am perpetually optimistic that my generation will not be the first to leave to our children and our grandchildren an environmental problem that they can’t solve. The clock is running. We need to get moving. But I’m also encouraged because I see lots of states stepping up. I see cities stepping up. And just today, we see an announcement from Ford, Honda, Volkswagen, and the BMW company that they have reached an agreement with the state of California on more-efficient cars and cars that produce less greenhouse gas emissions,” Browner said. “So, I think there are reasons to be optimistic.”
Reversing Climate Change with Nuclear Power. According to the Energy Impact Center, a Washington, D.C.-based research institute focused on deep decarbonization, CO2 emissions “must go net-negative by 2040, globally across all energy sectors” to begin countering climate change. The only way it sees to accomplish this is to “produce energy inexpensive enough to make carbon negative fuels that compete with fossil fuels on a global market without tax or subsidy,” and it says nuclear fission is the only energy source that can match cost, deployment, and timeline constraints. Bret Kugelmass, managing director of the Energy Impact Center, was a guest on The POWER Podcast. He elaborated on his group’s thesis and offered a path forward. “I think the problem that often goes unacknowledged is that even if you went net-zero emissions across the globe in every single sector—agriculture, industry, heat, electricity, transportation—that wouldn’t be enough to stop climate change,” Kugelmass said. “The real challenge toward solving climate change is to remove all of the existing emissions as well—get us back to the levels that we had in 1750, under 300 ppm—only then are you going to prevent climate change. “If you look at the problem from that perspective, the only energy source that has a small enough carbon footprint to totally account for its lifecycle emissions is nuclear energy,” said Kugelmass. “The one issue is how do we build them cheap and fast, and how do we create an ecosystem of stakeholders, whether they be construction companies, customers, utilities, governments, whoever it is, that is focused on that one thing?” Kugelmass asked. He said the Energy Impact Center has worked with universities, the Department of Energy, utilities, and think tanks to develop partnerships dedicated to solving the issues.
Lithium-Ion Batteries: Costs Down, Benefits Up [PODCAST] The price of lithium-ion batteries has plummeted over the past decade. Battery pack prices averaged $1,160 per kWh in 2010, according to BloombergNEF, but they dropped to $176 per kWh last year, and experts suggest they could be less than $100 by 2024. Tony Cooper, general manager of Green Cubes Technology’s Motive division, was a guest on The POWER Podcast. He explained why prices have been coming down. “Basically, the production capabilities—the production process—I think that’s the number one driver in bringing down the cost of lithium [batteries], economics of scale. The other thing though, it’s not just the production, it’s also the process of getting the raw materials. So, the production process of mining, the production process of refining those minerals, and then also, of course, the production process of making the cell, even to making the battery pack. I mean, all of these processes are being refined,” Cooper said. “And the quality’s there, because it’s all highly automated—everything is precision measured—so, nowadays, you’ve got great quality of cells coming out at a huge rate,” Cooper added. Although Cooper suggested it’s getting harder and harder to optimize the production process for battery cells, he said there is still room for improvement in systems. “There’s lots of things that can be done to keep improving from a system-level efficiency,” he said. Repurposing lithium battery packs offers value for the power grid. Although electric vehicle (EV) battery packs reach a point in which they are no longer suitable for use in cars, the packs still have great capacity for purposes in which space is not a limitation. Mercedes-Benz Energy, for example, has incorporated EV battery packs into the electric grid at several sites. “Second life is a huge thing for lithium,” Cooper said. “With lithium, you have a very good end of life or cycle life, where it’s very linear. It doesn’t have a waterfall, where just all of a sudden it stops working like lead-acid. It’ll really be very linear. So, a pack that has 50% capacity has a lot of energy that can be put into applications which don’t require small spaces or have room for them.” The benefits of lithium-ion over lead-acid batteries are quite significant too. Cooper noted that one of the biggest benefits revolves around maintenance. Lithium-ion batteries require zero maintenance. “And we really mean zero maintenance,” Cooper said. “Lithium batteries take no special side operations. No one’s needed there to tighten bars down, water, or anything like that. It’s really zero maintenance, so it’s a huge benefit.” Another benefit is energy savings. Cooper said charging lithium-ion batteries can save 20% or more compared to lead-acid, and there’s also greater efficiency during discharge. Lithium technology performs better in cold-temperature operations. Cooper said lead-acid batteries can lose up to 50% of their capacity when temperatures drop to freezing and below, while lithium still operates well. Furthermore, heaters can be effectively placed on lithium-ion batteries, as there is less mass to warm. Another drawback of lead-acid batteries is that they can leak acid and release hydrogen gas, whereas lithium designs are sealed and clean.
How to Monitor and Predict Operational Performance with Digital Analytics. Power plants are capturing operational data in ever-increasing amounts. However, analyzing all the data can be challenging. A number of tools are available that can help. In this episode of The POWER Podcast, two experts from one technology provider explain how big data can be analyzed to identify trends and create actionable information to solve production issues. Their company’s solution allows users to troubleshoot problems, and monitor processes and assets, in real-time, so operators can make better decisions, faster. “We want the user to have a really good springboard to be able to jump into analytics,” said Nick Petrosyan, data analytics engineer with TrendMiner. “If you’re going to be doing some type of analytics or you’re troubleshooting something in your process, it’s usually because one of your KPIs [key performance indicators] are off. So, we would like to have those KPIs somewhere very easy for them to access and see, so that they start doing more analytics in their day-to-day job, and troubleshooting and solving more problems.” Petrosyan said there are more than 30 power plants across the U.S. connected to TrendMiner and the tool is paying dividends. As one example, he mentioned a plant that was experiencing a decrease in efficiency over time, but it had been hard for operators to identify the cause due to the wide range of variables involved. “The first thing we did was we flattened the dataset with regards to ambient temperature, using TrendMiner’s big data searches,” Petrosyan said. “So, finding periods where ambient temperature was relatively stable and wasn’t varying a whole lot—that you’re able to do in TrendMiner in a matter of seconds—and then from there you can start to layer these really stable periods in terms of ambient conditions on top of each other and start performing comparison analytics.” Petrosyan said different plant parameters were then added and compared to see what besides efficiency had changed over time. “The first thing we confirmed was that efficiency was actually changing, and then we were able to find something very, very subtle in their process, a malfunction in their air supply system that was causing this decline in efficiency,” he said. “Once we were able to narrow down and pinpoint the actual root cause of the efficiency decline, they were able to repair it really quickly.” Another thing Petrosyan said TrendMiner has done for customers is “fingerprint what a really good startup looks like.” The company does that by taking multiple startups that were performed well, combining them together, and generating a fingerprint of an ideal sequence. Then, when future plant startups are performed, they can be monitored against the model conditions. “They were able to really reduce the amount of bad startups that they had and reduce the frequency that their heat recovery steam system was experiencing thermal stresses,” Petrosyan said. In the end, engineers developed multiple fingerprints based on the length of time the plant had been offline, and operators could choose the appropriate model for any given situation. Thomas Dhollander, CTO and co-founder of TrendMiner, said there are generally four ways in which customers experience and quantify the return on investment for digital solutions. They are in time savings, solving unsolved cases, avoiding abnormal situations, and knowledge capturing and sharing. “The fourth one is maybe harder to quantify but strategically very important,” Dhollander said.
The natural gas industry is doing quite well and the future looks bright to many observers. “We’re at a really great moment for the natural gas industry in the U.S. Production is growing dramatically. Shale continues to provide tremendous improvements technologically, bringing the cost down and growing the production, extending access to U.S. gas. At the same time, the shift from coal to gas-fired power generation is in full swing and the U.S. is in the midst of a significant boom in LNG [liquefied natural gas] exports and is poised to see a number of approvals for the second wave of U.S. LNG projects coming up,” Alex Dewar, senior manager with the Center for Energy Impact in the Washington, D.C., office of Boston Consulting Group (BCG), said as a guest on The POWER Podcast. But the future may not be as rosy as it seems. “There’s potential actually for a very different outcome, I think, than many expect for natural gas here in the U.S.,” Dewar said. “What we’ve noticed by looking at some of the future trends in technology and policy, and also public opinion and consumer preferences, is that there are some risks to that emerging in the not-so-far-off future.” According to a BCG report that Dewar co-authored, titled Preparing for an Abundance of US Natural Gas, the U.S. will likely experience a peak in gas demand, with consumption growth slowing from the late 2020s and plateauing by 2030. “The U.S. gas market is likely to shift from being limited by the pace of growth in supply to being limited by the level of demand,” the report says. “Our modeling estimates that U.S. gas consumption could be about 20% less in 2040 than the typical modeling suggests by the U.S. Energy Information Administration,” Dewar said. “There are some pretty big implications across the power sector—and the entire energy sector in the U.S.—if that in fact is what shapes up over the coming decades.” One reason is a push toward electrification. “I think we’re going to continue to see a push towards electrification because of both the greenhouse gas and safety issue,” Tom Baker, a partner and managing director in BCG’s San Francisco office, said on the podcast. Baker was also a co-author of the report on natural gas. He suggested that gas utilities serving consumers, especially in markets like California and New York, face significant risks to their businesses going forward and should review long-term strategies.
Power Company Business Models Are Evolving The power industry is changing and power companies must evolve to stay competitive. Many businesses are transitioning from vertically integrated, centralized utility structures to more-distributed models. JEA offers a good case in point. JEA is a not-for-profit, community-owned utility located in Jacksonville, Florida. It serves an estimated 466,000 electric, 348,000 water, 271,000 sewer, and 11,000 reclaimed water customers. Aaron Zahn, managing director and CEO with JEA, was a recent guest on The POWER Podcast. He explained some of the challenges not only facing his company, but also investor-owned utilities (IOUs) and other power providers across the country. “Whether you’re municipally owned or an IOU, ultimately, you’re in competition to make sure you’re providing the best service to the customer, because now there are disruptive providers of solar, and battery, and microturbines, and others, that don’t even fall into either of those two classes,” Zahn said. “For the last 100 to 125 years, those were the only two predominant providers, and that’s just no longer the case.” As a public utility, JEA found it hard to gauge value. It didn’t have a stock price to measure the company’s performance against, so it needed specific metrics that it could use in decision-making processes. To gain some perspective, JEA established its CCEF benchmark, which identified four basic measures of value. The acronym stands for customer, community, environmental, and financial values. “We now tie metrics to each one of them and cascade them throughout the organization and throughout the community to let people know what direction—where we are today—and actually what direction we’re headed and where we expect to be in the future. And I think that’s enabled us to have very deliberate and methodical conversations about our strategies and tactics on how to move forward,” said Zahn. JEA’s power mix has evolved over the years too. In the early 1970s, its power was predominantly produced from oil-fired generation. It shifted more toward solid fuels as the price of oil escalated. It has since added more natural gas-fired generation, and in 2008, it signed an agreement with Municipal Electric Authority of Georgia (MEAG) to purchase nuclear power from the Plant Vogtle expansion. There is pending litigation on the validity of that contract, however; JEA is seeking to void the agreement. One of the underlying reasons is that solar energy is seen as a more-cost-effective solution for its customers. “Today, we’ve executed 250 MW of power purchase agreements for solar at a price almost 20-plus-percent cheaper than our current cost of dispatch of our fleet. And that will be a long-term hedge for us for about 20, 25 years, and completely emission-free,” Zahn said. Zahn talked about several other changes taking place at JEA and touched on some of the company’s recent accomplishments, including a 2019 Best Practices Award in Outage Communications. The company was recognized by Chartwell Inc. for its multi-channel Restoration 1-2-3 process, which goes into effect during major storm events. Restoration 1-2-3 focuses on actions during each phase of storm restoration and acknowledges the key role customers play in efforts to restore power safely and quickly when massive outages occur.
When it comes to gas turbines, size matters. Although the market for large, heavy-duty gas turbines has been challenging in recent years, demand for industrial gas turbines—generally units with output ranging from about 5 MW to 100 MW—has been growing, according to Reed Lengel, product line manager for SCC-800 solutions with Siemens Energy. “When you really dig into it,” Lengel said, speaking as a guest on The POWER Podcast, “there’s actually been pretty significant improvements—or growth in this power band within the portfolio. Where there’s been really a decline over the last four years in the total gas turbine sales—that’s just globally, looking at all gas turbine sales—in that same timeframe, the market share of this 40 to 90 MW power band gas turbine has actually doubled.” For Siemens, its SGT-800 gas turbine fits squarely in that range. Increasing interest in industrial gas turbines has led manufacturers to invest in design improvements. New coatings, advanced cooling technologies, and additive manufacturing have spurred significant efficiency gains. Since 2015, the SGT-800’s efficiency has improved from about 56% to 58.6% in combined cycle mode, which makes it the market leader in efficiency for its power band, according to Lengel. Flexibility has also made these mid-size gas turbines popular. Rather than constructing a single large gas turbine unit, many companies are deciding to install multiple smaller units at sites. “We actually have a six on one that’s actually under construction right now,” Lengel said. (Six on one refers to an arrangement in which six gas turbines and six heat recovery steam generators are joined with one steam turbine in a combined cycle configuration.) “That’s a project that’s down in Panama,” he said. Industrial gas turbines are also good candidates for combined heat and power applications. Lengel mentioned the Holland Energy Park in Holland, Michigan—a POWER Top Plant in 2018—as a shining example of a plant that utilizes SGT-800 gas turbines for more than just generating electricity. That facility also provides heat for a snow-melt system that keeps downtown city walkways ice-free during the winter. Although Lengel said there were only 14 SGT-800 units currently operating in the U.S., it's a well-proven model around the world. “With the changes that are being seen, and I think the desire for more smaller units and distributed generation,” he said, “I think that’s only going to increase.” When asked what sectors would be the biggest buyers of industrial gas turbines going forward, Lengel said, “Looking at some of the numbers, even from the [Energy Information Administration’s] latest energy outlook that they put in just a couple months ago, the bulk chemical [industry] actually is looking to increase pretty significantly in their power needs, and more specifically, on onsite generation. So, that's one specific area that really could see some growth—in the U.S. in particular—for onsite power generation combined heat and power application.”
Control Your Own Destiny with Combined Heat and Power Systems Combined heat and power (CHP), also known as cogeneration, is the concurrent production of electricity or mechanical power and useful thermal energy (heating and/or cooling) from a single source of energy. Although it may not be widely recognized outside of industrial, commercial, institutional, and utility circles, CHP has been providing highly efficient electricity and process heat to some of the most vital industries, urban centers, and campuses in the U.S. for more than a century. In fact, Thomas Edison’s Pearl Street Station was a CHP facility when it opened in 1882—the same year POWER was first published. According to the Department of Energy, most CHP applications can reasonably expect to operate at greater than 65% efficiency, a large improvement over the typical electric-only power plant. President Obama believed so strongly in the benefits that he signed an executive order on August 30, 2012, establishing a national goal of adding 40 GW of new CHP capacity by 2020. However, the country will fall well short of that target; only 2.5 GW was added between 2012 and 2016. Bill Castor, director of business development for Siemens Energy, was a guest on The POWER Podcast. Castor gave a presentation titled “Navigating Through the Challenges of Implementing Successful Onsite Generation Solutions in a Complex Market” on April 25 during the ELECTRIC POWER Conference and Exhibition in Las Vegas, Nevada. He touched on some of the main points from his presentation during the podcast interview. “CHP is an entirely different animal than your typical power plant because it is so intertwined with the end user—the host—as well as impacted by the outside grid,” Castor said. He noted that CHP results in not only reliability gains, efficiency gains, and environmental gains, but it also allows end users to take control of their own destinies. “Controlling your own destiny is one of the phrases that really is attached to CHP as a driver for the potential hosts of those units,” Castor said. “The whole story for CHP has to start though with the end user,” Castor said. “You need to have that thermal host in order to make [CHP] a sensible alternative.” Castor noted that industrial solutions come in a variety of shapes and sizes. Systems range from small to large, and can utilize an assortment of technologies including gas turbines, reciprocating engines, and fuel cells, as well as incorporating control systems, electrical systems, transformers, and more. “Utilities in the past have traditionally resisted CHP coming because it tends to take large customers away from the utility,” Castor said. But that is changing. “Many of the cases that we’re looking at today involve either utility ownership and operation or at least a cooperation between the host and the utility to try to make those work,” he said.
Working with Peers Is Critical to Power System Reliability. When conversations around the power industry turn to computer hacking, more often than not experts say it’s not a question of if, but rather, how systems have been compromised. William Doering, adjunct professor in the John E. Simon School of Business at Maryville University and a director with Guidehouse—a management consulting services provider—said he has participated in various discussions on how to cleanse infection and how to ensure reliability after the fact. Speaking on The POWER Podcast, Doering said the Stuxnet computer worm and the Ukraine power grid cyberattack in 2015 should provide more than enough evidence that systems are vulnerable. “For us to think that something like that hasn’t happened yet [in the U.S.] is definitely on the riskier side of optimistic,” Doering said. “I think the level of sophistication that state-level actors provide is in many cases astounding,” he said. But even more worrisome to Doering is the fact that state-level-actor tools, which are extremely sophisticated, complex, and devastating, have been released and are now in the hands of the broader masses. “The level of disruption is really hard to gauge,” Doering said. “Building microgrids around critical infrastructure where they have the ability to do generation plus storage, and I’m not saying that that’s the only answer but … a combined portfolio of solutions, I think, provides a lot of resilience.” Doering also touched on the risks presented by electromagnetic pulse and geomagnetic disturbance events, suggesting that a combined effort is needed to harden the system. “If you have limited resources on how to prepare, selecting the appropriate level of preparation is crucial,” he said. “I don’t think any utility or even a government actor has the ability to do all of the things [necessary], so I think instead what we do is try to prioritize and understand, ‘Where do our limited resources bear the most fruit?’ ” “For me, the place where I see the most value put in is the information sharing,” Doering said. “Always be learning, always be working with your peers, be working with your vendors, identifying situations where the first thing that we need to do is question our assumptions.”
Trump Ended War on Fossil Fuels, but Focus Needed on CCS. The United States Energy Association (USEA) is an association of public and private energy-related organizations, corporations, and government agencies that helps increase understanding of the world’s energy issues. Barry Worthington has been the executive director of the USEA for more than 30 years. During that time, he has seen the association grow from a two-person, $200,000-a-year operation to an organization with 25 employees and a $10 million budget. Worthington was a guest on The POWER Podcast. He spoke about some of his group’s accomplishments over the years and explained what the USEA is concentrating on currently. “I think right now that the most important technology that we need to focus on where we’re not adequately focusing is carbon capture utilization and storage,” he said. Worthington believes people around the world are going to continue using fossil fuels for many, many years. Even if developed nations such as the U.S. and some European countries cut back on fossil fuels, places like China, India, Vietnam, Indonesia, and many others are going to continue to burn coal, Worthington said. “I feel that we have an obligation to help them do that in a manner that’s using the best technology—low-emission, high-efficiency technologies. If we have any hope of meeting our climate change goals, we need to be deploying CCS [carbon capture and storage] much more rapidly than what we are now,” he said. What’s holding CCS back, according to Worthington, is that the U.S. hasn’t established economic incentives to help support the technology. For perspective, he compared federal spending on renewables to that spent on CCS. “The ratio is 100 to 1,” Worthington said. “For every dollar the federal government spends on CCS, they spend $100 on renewable incentives. And the consequence or outcome of that is you’ve seen a dramatic, dramatic reduction in the cost of wind and the cost of solar, but you haven’t seen anywhere near the dramatic cost reduction in CCS. Yet, the potentials are there.” But Worthington was optimistic about what the government has been doing. He suggested the most important message the Trump administration has delivered to the energy sector is that the war on fossil fuels is over. “We went through eight years where fossil fuels were vilified as opposed to applauded. Fossil fuels have been the cornerstone of economic development all throughout the world ever since the industrial revolution. They continue to provide about 80% of primary energy supply on a global basis and we have unleashed—the administration has unleased—the fossil fuel industry,” he said. Worthington noted that the message is a marked change from the one sent by the Obama administration. “This is just a complete about-face, where you had individuals and departments within the federal government that literally—without exaggeration—literally wouldn’t use the word fossil fuels. It was like they were banned for eight years,” he said. “I think that the Trump administration turning that around and all of the ramifications that fall out of that policy decision are very profound, and I would go so far as to say we’re just now beginning to understand what kind of geopolitical value this about-face can do for the country,” Worthington said. During the interview, Worthington also touched on takeaways from the USEA’s inaugural Energy Efficiency and Supply Forum, the integration of renewables into the grid, the trajectory for electric vehicles, climate change, sustainability, the efficient use of fossil fuels, and more.
How a Major Resort Owner Manages Its Power. MGM Resorts International took a bold step in 2016 when it ended its energy-buying relationship with NV Energy and instead chose to purchase electricity from private providers. The company’s decision was driven by a desire to slash bills and boost renewables. Henry Shields, executive director of finance and analysis in the Corporate Sustainability division of MGM Resorts International, was a guest on The POWER Podcast. Shields will be a keynote presenter at the ELECTRIC POWER Conference and Exhibition, which will be held at The Mirage Events Center in Las Vegas, Nevada, April 23–26, 2019. On the podcast, Shields explained how the changes played out in practice. “Nevada’s not a deregulated state in the purest sense,” Shields said. “However, there’s been a law in Nevada on a very limited path for certain sophisticated commercial customers to do what we did.” “What we did was separate from the utility in terms of the actual procurement of electricity so that we were able to source our power from the wider market. We do remain actively—and will so in the future—very much a customer of NV Energy, but now for local lines and wires, and transmission service only,” Shields said. Concerning renewable energy, MGM Resorts International has really embraced solar power. Even before it broke away from NV Energy, MGM installed more than 26,000 photovoltaic (PV) panels on its Mandalay Bay Convention Center—about 28 acres of rooftop area. Furthermore, in April 2018, the company announced it was partnering with Chicago-based Invenergy, North America’s largest independent renewable energy company, to construct a solar project about 25 miles north of Las Vegas. At full production, the 100-MW solar array is expected to provide up to 90% of the total daytime power needs for MGM Resorts’ 13 Las Vegas Strip locations. Shields said the project would go a long way toward meeting the company’s published goal of reducing its carbon intensity by 50% by 2030.
Royce Peters, senior technical coordinator for the Carpenters International Training Center (ITC) in Las Vegas, Nevada, was a guest on The POWER Podcast. The ITC is the largest and most-comprehensive training facility of its kind in the world. Following the completion of phase six of construction in 2018, the center now has more than 1.2 million square feet under-roof. Peters listed some of the unique training tools available at the facility, including a Frame 7 gas turbine, a 64-MW steam turbine, eight overhead bridge cranes, and a 16,000-gallon underwater-welding dive tank, among other things. The facility is one of the largest publishers of technical training materials in the world, with more than 120 books created and more under development. The Carpenters International Training Fund and its affiliated funds invest more than $200 million a year to develop and deliver training, enhance knowledge and skill sets, and create new opportunities for United Brotherhood of Carpenters and Joiners of America (UBC) members. Outreach programs include Career Connections, which targets high schoolers and inner-city residents, among others, with training leading to a career in the industry, and Helmets to Hardhats, which gives military members the opportunity to transition more easily to the civilian workforce. But people interested in joining the UBC don’t have to go through one of the outreach programs, anyone can apply by contacting their nearest regional council office. There’s a lot of see at the ITC and the ELECTRIC POWER Conference and Exhibition is making it possible by offering a tour of the facility as an option for attendees. To learn more and to register for the event, which will be held April 23–26, 2019, at The Mirage Events Center in Las Vegas, visit: https://2019.electricpowerexpo.com/.
Carol Holahan, counsel in Foley Hoag’s Energy & Cleantech practice, was a guest on The POWER Podcast. Holahan advises large regional generators and other participants in the wholesale and retail competitive electricity markets on policy initiatives, changing environmental regulations, decommissioning and sale of plants, and matters pending before the Federal Energy Regulatory Commission (FERC). During her interview, Holahan explained some of the differences between natural gas pipeline and bulk power system cybersecurity requirements. Currently, the Transportation Security Administration (TSA) is responsible for oversight of the gas pipeline system. Holahan said the U.S. system comprises a 2.7 million-mile network. Yet, according to a letter written by two FERC commissioners last year, TSA has only six employees dedicated to pipeline oversight. Furthermore, TSA has no mandatory compliance or reporting requirements, and relies on companies basically self-reporting, especially with respect to cybersecurity events. Oversight of the U.S. bulk power system is markedly different. It is mandatory and quite complicated, with FERC, the North American Electric Reliability Corp. (NERC), the Department of Homeland Security, and the Department of Energy (DOE) all involved in some aspect of oversight. The disparity between the requirements for gas and electric infrastructure, combined with a computer hacking event last year that affected multiple pipeline companies, led two FERC commissioners—one Democrat and one Republican—to write a joint letter urging the transfer of gas pipeline oversight to the DOE. To date, changes in the oversight structure are still being debated in Washington with no clear resolution in sight. While cybersecurity is easy to neglect, Holahan said a recent $10 million fine issued by NERC against an unnamed power company for alleged cybersecurity violations sent a very clear message to all U.S. utilities subject to NERC requirements: “If you had not been paying attention to cybersecurity to date, you better start.” Holahan touched on the changing landscape of power generation. She noted that Brayton Point—the last big coal-fired power plant in New England—was retired last year and Pilgrim nuclear plant will be shuttered this year, removing hundreds of MW from the grid. What’s coming online is new gas, solar, and wind generation, including the promise of more offshore wind. Pairing battery storage with renewables is allowing intermittent resources to participate in the market as baseload power. While noting that FERC has traditionally operated above the political fray, Holahan said there is some concern that the DOE will continue to exert pressure on the agency to provide relief for certain types of units, especially coal-fired plants. Furthermore, Holahan thinks it will be interesting to see how FERC responds to various state policies that support certain resources, such as nuclear and renewables. “I think it will be well worth watching what models FERC is going to approve that will allow these resources to participate without compromising price formation or market entry and exit signals.” she said.
Prepare for More Distributed Energy Resources. Paul DeCotis, senior director in West Monroe Partners’ Energy and Utilities practice, was a guest on The POWER Podcast. West Monroe, in partnership with Greentech Media, conducted a survey of more than 1,700 utility customers, 140 utility executives and managers, and more than two dozen regulators in major markets across North America. Its findings were released in a report titled Planning for a Distributed Energy Future. Interestingly, 92% of survey respondents said they had distributed energy resources (DERs) on their system, up from 80% when the survey was conducted three years ago. However, DeCotis noted during the podcast that DERs are not yet universally economical throughout the U.S. “Not all states and regulatory jurisdictions handle DERs the same. It’ll be a few years before we see very significant DER penetrations uniformly across the country,” DeCotis said. “DERs still need substantial backup generation because utilities have the obligation to serve load and be the provider of last resort, so the industry will develop cautiously in some parts of the country until regulations become more certain and incentives become more mature,” he added. The report notes that distributed energy resource management system (DERMS) technology is on many utilities’ radar, but more than half of respondents said they had no concrete plans to invest in it. “As the system gets more distributed, [utilities] do need a way to have visibility and to manage that system so that they can be the provider of last resort,” DeCotis said. Therefore, DERMS technology will continue to become more and more important as DERs are added to the grid.
Community Solar Power Offers the ‘Best of Both Worlds.’ Laura Stern, co-founder and president of Nautilus Solar Energy, was a guest on The POWER Podcast. Founded in 2006, Nautilus is a leading acquirer, developer, and operator of community solar projects. During the past five months, the company has acquired community solar projects in Minnesota, Massachusetts, New York, Maryland, and Rhode Island. Community solar refers to local solar facilities shared by multiple community subscribers who receive credit on their electricity bills for their share of the power produced. This solar power model is being rapidly adopted throughout the U.S. According to the Solar Energy Industries Association—the national trade association of the U.S. solar energy industry—there was 1,294 MW of installed community solar capacity at the end of June 2018, with at least one community solar project online in 42 states. Furthermore, the group says the market will add as much as 3 GW over the next several years. Community solar allows homeowners, renters, and businesses to have equal access to the economic and environmental benefits of solar energy generation regardless of the physical attributes or ownership of their homes or businesses. It’s particularly beneficial for low-to-moderate income customers most affected by a lack of access, and it helps build a stronger, more-distributed and -resilient electric grid. “It’s kind of the best of both worlds,” Stern said. “It is the best physical configuration of a solar plant, and it’s the best kind of off-take in terms of diversifying your risk among a number of subscribers, not being captive to an on-site customer, and being able to update that list of customers as your project advances.”
Izzet Bensusan, managing partner and founder of Captona, a North American-focused investment company that specializes in power generation and energy infrastructure, was a guest on The POWER Podcast. He is very bullish on the renewable energy industry for a variety of reasons. For instance, Bensusan said renewable energy is growing at more than 20% around the world because companies behind the technology are making it more efficient, cheaper, and better. He suggested new renewable generation is being added, not because of special incentives or sustainability angles, but rather, because it makes economic sense. When asked about promising opportunities in the renewable sector, Bensusan said the repowering of wind farms makes sense these days because new technology can improve output while using much of the same infrastructure. He was also optimistic about the U.S. offshore wind market in the long-term, but he didn’t expect it to take off in the next three years. Concerning other renewable resources, Bensusan said solar projects are now “mainstream” and financing has become “plain vanilla.” He said, “That means, anyone and everyone can really get capital to build small, medium, or large projects.” Community solar is growing too, and bankers—the people who provide the financing—are becoming comfortable with the investment. Bensusan expects a spike in new solar projects in 2019, mainly because the investment tax credit will have a step-down next year. Nonetheless, he has been in the industry long enough to know that surprises happen regularly. This year, interest rates could provide a shock. When rates go up, the leverage factor in projects could get extremely tight. “It’s going to be very unique to watch when that next step-up happens,” Bensusan said. “I think watching those markets closely is very important for the renewable energy market.”
Optimizing power plant control systems can be challenging, but new tools are available to simplify and improve the process. On this episode of The POWER Podcast, Executive Editor Aaron Larson spoke with Jon Towslee, digital engagement leader for ABB Inc.’s Industrial Automation Power Generation & Water business. Towslee explained how ABB Ability is focused on improving customers’ businesses by optimizing assets and operator effectiveness, and enhancing top-to-bottom performance. Solutions like the company’s loop performance monitor can be used to identify such things as transmitters that are providing bad data, noisy signal lines, and actuators that aren’t working correctly. Once maintenance crews have all equipment functioning properly, technicians can evaluate process control schemes to ensure they are responding appropriately, which then permits loops to be tuned for optimal performance. The loop performance monitor evaluates control loops on 17 different parameters. Once individual loops are optimized, higher-level adjustments can be made. Ultimately, the tools allow plant operators to expand boundaries and operate plants more closely to maximum safe operating limits. This enhances performance and increases profitability.
The Jackson Hole Center for Global Affairs—a bipartisan think tank—will host the “Jackson Hole Global Forum: Climate Solutions, Coal Communities, and Economic Diversification” in Wyoming, November 8–9, 2018. Among the sessions on day one is a panel titled “What Is Coal’s Future?” Charles K. Ebinger, nonresident senior fellow with the Atlantic Council, will be one of the panelists. Ebinger touched on some of the issues facing the coal industry on an episode of The POWER Podcast. He said the question—“What is coal’s future?”—really needed to be answered in two parts: one addressing challenges in the U.S. and the other taking a broader look at coal usage around the world. Although coal faces stiff headwinds in the U.S., demand in Asia is very robust, growing 5% or more per year in some places. The fact is, hundreds of millions of people still do not have electricity in various parts of the world, and hundreds of millions of others don’t have truly reliable sources of power. Furthermore, the industry employs a very large number of people globally and scaling back coal is considered political suicide for government officials in many parts of the world. Ebinger said the U.S. has a major role to play in combatting climate change through the development of carbon capture and sequestration (CCS) technology. He suggested proving CCS technology viable, and exporting it around the world, could offer economic benefits at home, while helping to reduce global carbon emissions. Ebinger said there are challenges, but with the right backing, breakthroughs may be possible. The podcast includes some climate change discussion and briefly touches on the future of nuclear power in the generation mix, including talk about small modular reactors and potential changes needed in the regulatory process. The forum in Jackson Hole offers global perspectives on energy, climate, and economics. A keynote presentation by Han Wenke, former director general for China’s Energy Research Institute of the National Development Reform Commission is sure to be interesting. Other sessions include policy models, climate change and national security, wind and economic diversification, blockchain as an economic growth driver, and more.
It is safe to say that all electricity customers want reliable and resilient power service. One way that some end-users are ensuring they get it is by investing in distributed energy resources and building microgrids. But rather than simply using these systems as emergency backups, more and more owners are finding ways to capture economic benefits from them. Distributed energy resources can help shave peak loads, shift time-of-use, and support ancillary services, which all provide value to owners. Nonetheless, utilities generally set the rules; they establish the rate tariffs. As such, utilities have the ability to alter how the game is played. According to Amy Simpkins, CEO of muGrid, there are a number of ways that utilities can influence how large commercial and industrial customers behave simply by modifying the rules. Simpkins will give a presentation at the Distributed Energy Conference in Golden, Colorado, October 15–17, 2018, during which she will offer a few case studies and show some sensitivity analysis. What would happen if demand charges were increased? What if the look-back period was modified? What if time-of-use rates were shuffled? Simpkins’ presentation—“How to Incentivize Your Utility Customers to Do What You Want”—will focus on the “knobs utilities can turn” to sway customer behavior. Attendees may find that power companies have more control than they realize over what customers choose to do in the end. Furthermore, the solution can be win-win.
Roy Palk, president of New Horizons Consulting, will give a presentation titled "The Rise of Distributed Energy — New Challenges Bring New Opportunities" during the Distributed Energy Conference, which will be held October 15–17, 2018, in Golden, Colorado. In this podcast, Mr. Palk gives a brief preview of his talk. He says the power market is changing and suggest utilities must evolve if they want to continue to be a trusted energy provider for customers.
Nevada law has included net metering provisions for more than 20 years. Net metering is an arrangement that allows energy generated by a customer’s leased or purchased solar system to offset monthly power bills. It also permits excess energy supplied to the grid to earn credits, which are then automatically applied to future billing periods in which more energy is consumed than produced.
Historically, net metering was a one-for-one transaction in Nevada. For every kWh supplied to the grid, a credit was given to the customer for one kWh in the future. The scheme changed in 2015 when the Nevada Public Utilities Commission (PUC) created a laddered approach that ratcheted down the value of customer-generated energy over a period of years to about 2¢/kWh, which was much less than the retail rate of about 11¢/kWh. The change effectively stopped all construction on new residential rooftop solar systems.
Through Assembly Bill 405 (AB 405), the Nevada Legislature modified the net metering rate structure effective June 15, 2017. The bill allows Nevadans who choose to net meter to fall under a rate structure codified in the law. The rate structure applies to renewable energy systems of 25 kW or less, which is typical of a rooftop solar system installed on a home or small business. The net metering rate structure is tiered and will decrease over time as the amount of electricity produced by net metering systems reaches 80-MW benchmarks.
The first tier offers a net metering rate that is 95% of the retail rate. As of April 26, 2018, nearly 20 MW of installed capacity had been applied toward the first 80-MW tier. The net metering rate for the second tier is 88% of the retail rate, with tiers three and four crediting 81% and 75%, respectively.
Furthermore, on March 14, 2018, the PUC approved numerous new time-variant rates pursuant to AB 405. The rates are designed to incentivize the use of battery storage at residential and small commercial sites. Under the new structure, utility customers with battery storage are allowed to shift their grid usage to times when energy is less costly. The result is a reduced load on the system during peak times coupled with energy savings for the customer. The development provides a natural incentive for customers to deploy behind-the-meter battery storage.
Curt Ledford, a Nevada-based attorney with McDonald Carano, who focuses on utility, cooperative, administrative, corporate, and employment law, as well as reliability and general regulatory matters affecting cooperative utilities, spoke in-depth about energy storage, net metering, and other energy matters during an interview for The POWER Podcast. Although Nevada law is his primary expertise, many of the lessons learned in the state can be applied elsewhere.
More and more people are finding distributed energy solutions are the answer for their power resource challenges. Distributed energy comes in many forms. Renewables such as solar and wind are top-of-mind when most people think of distributed resources, but natural gas-fired generation is often a good fit too, because it adds reliability to the system and is a consistent source of backup power.
Energy storage is also a logical piece of the distributed energy puzzle. Wind and solar are obviously dependent on nature. You need the wind to blow and the sun to shine in order to generate power from them. But often, those conditions do not match electricity demand. Frequently, renewables generate power when demand is low and die off when demand is high. That can mean power prices are low or even negative when solar and wind are generating most of their power, and prices are high when they are no longer producing. Batteries or other storage mechanisms can help overcome that problem, charging during low-demand hours and discharging when demand is high.
Combined heat and power (CHP) is another great way to optimize systems. How CHP works is by using the heat that would otherwise be wasted in exhaust gases from fossil combustion systems, such as flue gases from a coal- or biomass-fueled boiler or exhaust from a gas turbine or reciprocating engine, to produce steam and/or hot water for various industrial or commercial needs. The process can increase efficiency of the combined system significantly, which saves money on fuel and reduces overall emissions.
In this episode of the POWER podcast, Dalia El Tawy, director, Thermal Power Solutions Distributed Energy Systems with Siemens Energy, explains some of the work her group is doing to solve customers’ challenges. Born and raised in Egypt, Dalia came to the U.S. in 1999 to finish her education. She knew how disruptive power blackouts could be from her childhood and believed there had to be a way to improve reliability. She found it in distributed energy systems and CHP solutions.
Tennessee Valley Authority (TVA) CEO Bill Johnson in an exclusive interview with POWER suggested that the power industry continues to face an uncertain future. Johnson said that during his 40-year career, he has seen more change in the last five years than in the previous 35 combined. Several indicators imply that will continue going forward. According to Johnson, one thing driving change is declining demand for power, which has resulted from efficiency improvements, a shift toward a more-service-oriented economy, and lower population growth, among other things. Johnson said customers are interested in cleaner, more-flexible sources of power and information. The challenge for utilities is to figure out how to integrate new behind-the-meter resources after having focused for so long on big centralized power stations. Other power industry changes include a shift away from coal-fired generation. Johnson said TVA generated about 60% of its energy from coal 10 years ago, but by the end of the decade that figure will be down to only 20%. TVA has added nuclear capacity and shifted to more gas-fired generation. In addition, solar is now becoming a more viable option for the corporate agency of the federal government. Johnson was one of three “Thought Leaders,” who spoke and answered questions during the opening day of the ELECTRIC POWER Conference and Exhibition, held in Nashville, Tennessee, in late March. Prior to the event, Johnson sat down with POWER Executive Editor Aaron Larson to offer some insight on happenings at TVA.
Joe Grimes, executive vice president of generation with the Tennessee Valley Authority, gave the keynote presentation during the ELECTRIC POWER Conference and Exhibition, which was held March 19–22 in Nashville, Tennessee. His presentation focused on steps TVA is taking to diversify its generation portfolio in order to reduce risks and keep costs as low as possible for customers. TVA was created by Congress in 1933. According to its website, TVA was “charged with a unique mission—to improve the quality of life in the Valley through the integrated management of the region’s resources.” As the nation’s largest government-owned power provider, TVA sold more than 152.3 TWh of electricity in fiscal year 2017. Its generation portfolio is 37% nuclear, 24% coal, 20% natural gas, 9% hydro, 3% wind and solar, and 7% energy efficiency. TVA sells electricity to 154 local power companies and 54 directly served industries and federal facilities. Its power service territory covers 80,000 square miles, including most of Tennessee and parts of Alabama, Georgia, Kentucky, Mississippi, North Carolina, and Virginia. In this POWER Podcast extra, Grimes speaks with Executive Editor Aaron Larson about TVA’s generation mix and what the future holds for its fleet.
The Watts Bar 2 nuclear unit has a lengthy and well-chronicled history. Construction began on the unit in 1973. It was suspended in 1985 due to slower electricity demand growth, rising construction costs due to inflation and new regulatory requirements stemming from the accident at Three Mile Island in 1979, and regulatory concerns throughout the Tennessee Valley Authority’s (TVA’s) nuclear fleet. A study was conducted—beginning in 2006—to evaluate energy needs, schedule, cost, environmental impacts, and financial risks for Unit 2. After serious deliberation, TVA’s board decided to resume construction, which recommenced in 2008. Although more delays ensued, the unit was completed and entered commercial operation on October 19, 2016. In this POWER Podcast extra, Mike Skaggs, executive vice president of operations with TVA, explains the process the organization went through to complete the unit. Skaggs was intimately involved in the project as a member of the Watts Bar Operations and Construction group. When it entered commercial operation, Watts Bar 2 was the first new nuclear unit added to the U.S. fleet in more than 20 years.
Concentric Power, a California-based provider of high-efficiency energy modules for onsite refrigeration and electric power generation, recently launched a $100 million finance program for cogeneration and microgrid projects. "We are excited to create a new path forward in energy infrastructure financing and development," Brian Curtis, founder and CEO of Concentric Power, said in a press release. "The next 20 years will be transformative for how electric power is generated and consumed. Industrial and ag consumers see these shifts coming but would often rather invest capital in their core business rather than in plant utilities. Concentric's technology strategy and finance program enable customers to utilize third-party financing to roll out sustainable infrastructure." Concentric has already developed two significant projects: Taylor Farms in Gonzales, California, and True Leaf Farms in San Juan Bautista, California. Both are large agricultural processing facilities that require several MW of power and refrigeration to operate. Taylor Farms installed solar panels and a wind turbine to supply some of its power needs, but it needed a reliable backup to fill voids when the wind and solar couldn't meet the processing plant's needs. Concentric evaluated the situation and constructed a cogeneration plant to meet the facility's needs. The primary energy comes from a natural gas-fueled Caterpillar internal combustion engine. The heat in the engine's exhaust and water cooling jacket is used by an aqueous ammonia absorption refrigeration unit, which cools the processing plant. An advanced control system governs the operation, matching wind, solar, and engine generation with the plant's overall needs. Curtis spoke to POWER Executive Editor Aaron Larson about his company and the solutions it provides. You can hear their conversation in episode 11 of The POWER Podcast.
Cybersecurity threats have increased dramatically as sophisticated, nation-state developed hacking programs have been leaked to the general public. Now, common criminals have high-tech tools at their disposal with the capability to cause serious damage. As such, the power industry must take precautions and upgrade security to keep systems safe. While regulations provide a minimum security standard, companies that aren't going above and beyond the government's requirements are likely to be setting themselves up as "low-hanging fruit," that is, easy targets for hackers.
In this episode of The POWER Podcast, Chris Grove, director of industrial security with Indegy, offers some tips for keeping bad actors out of power plants. Gaining visibility into systems is an important first step. Once companies understand what risks they're exposed to, getting a broad-based team of both information technology (IT) and operational technology (OT) experts involved to develop solutions to mitigate the risks is a logical subsequent step. Investing in good security can pay dividends in the end.
Amir Adnani, CEO of Uranium Energy Corp., discusses the state of the nuclear industry, highlighting uranium production trends, new construction developments, and the lack of a nuclear vision in the U.S.
Ray Long, vice president of government affairs for NRG Energy, addresses the New Jersey Senate Environment and Energy Committee concerning nuclear subsidies.
PSEG CEO Ralph Izzo addresses the New Jersey Senate Environment and Energy Committee concerning nuclear subsidies.
Hans Maghon, Siemens' program director for HL-class gas turbine development, explains some of the unique features of the HL design and how the company built on proven technology during the development phase.
Earlier this year, GE’s Power Services achieved a significant milestone with its 9EMax gas turbine upgrade solution. The 9EMax completed initial validation testing and was offered commercially to gas turbine customers around the globe. The first 9EMax unit was installed at a customer’s site in Asia. “First fire is a critical test where the gas turbine is switched on and runs on fuel at the site. We completed the ‘first fire’ milestone with the unit successfully reaching full speed at no load, and it proved to deliver significantly more power and efficiency compared to current 9E gas turbine operations,” Eric Gray, general manager of Gas Plant Solutions for GE’s Power Services, said in a press release announcing the occasion. During the tests, over 1,000 pieces of instrumentation were used to collect data and improve the performance of the machine. The sensors collected over 14 terabytes of data. The validation test monitored and mapped the unit’s behavior at typical operating parameters. Some of the conclusions included: • The turbine’s output was increased to 145 MW in simple cycle operation and to 210 MW in a combined cycle configuration. • It achieved up to 37% efficiency in simple cycle and up to 53.5% efficiency in combined cycle opertion. • It delivered maintenance intervals of up to 32,000 hours or 900 starts—equivalent to approximately four years of typical plant operation. • It offset as much as 2% to 3% of normal performance degradation between maintenance intervals in extreme ambient operating conditions. 9EMax can operate at partial loads, making it ideal for power producers looking to add renewables to their energy mix. It also includes an array of digital solutions to boost operational reliability, improve combustion operations, and manage emissions. In this episode of The POWER Podcast, Executive Editor Aaron Larson spoke with Gray about innovations incorporated into the 9EMax gas turbine.
The Connected Plant Conference will be held in Charlotte, N.C., February 26–28, 2018. The forum is designed for professionals in the power generation and chemical process industries who are leading digital adoption at all stages. Sessions are tailored to offer actionable information and strategies to maximize the use of data, analytics, and related technology to drive efficiency improvements, preventive and predictive maintenance programs, and staff safety. Jon Towslee, director of marketing and business development with ABB Inc., is scheduled to give a presentation during the event. He spoke with POWER Executive Editor Aaron Larson on December 6 during a power-industry conference in Las Vegas, Nevada. You can listen to the interview in the following POWER Podcast extra.
In December 2016, Mitsubishi Hitachi Power Systems (MHPS) announced the introduction of its JAC gas turbine—a new air-cooled J-series model. The JAC has flexible ramping capabilities, an impressive 64% efficiency, 99.5% reliability, and a combined cycle output of 575 MW. Furthermore, the design has been thoroughly tested, with more than 14,000 operating hours at T-Point, MHPS’s validation facility.
The combination of those factors led customers in Asia, the U.S., Mexico, and South America to technically select the M501JAC for projects 26 times in the past year, representing more than 14 GW of new power generation. In addition to the JAC technical selections, MHPS has 25 J-series gas turbines already in operation and 31 more units have been ordered. The platform has more operating hours than advanced turbine models offered by MHPS's two largest competitors combined.
“The success of the JAC is no coincidence,” said Paul Browning, president and CEO of Mitsubishi Hitachi Power Systems America (MHPSA). “The company started on a journey in 2004 by setting a goal of 65% efficiency and has methodically pursued that goal."
Browning gave a keynote presentation during a recent power-industry conference in Las Vegas, Nevada, and he spoke to POWER shortly after the session. During the interview, Browning provided highlights from his keynote address and touched on several other topics. Despite restructuring at GE and Siemens, Browning expressed optimism about the future of MHPS.
Exelon has been an early adopter of digital technology throughout its operations. Among the solutions implemented is GE's Predix platform. A group of Exelon leaders spoke in depth about the company's digital transformation.
Two experts from the law offices of Mayer Brown discuss how deregulation has affected the Mexican electricity sector. They explain how the power generation mix is evolving, risks that potential investors should be aware of and tips to mitigate those risks, and they touch on financing.
Eric Gebhardt, vice president of systems and innovation for GE Power, is interviewed about the television special "Droneweek." which will air on the Viceland network beginning Monday, Oct 9, and continuing throughout the week. In the series, drones will be used to produce video footage of several large and interesting power projects.
Most large power plants have continuous vibration monitoring systems installed on turbine generators and other critical equipment. The systems have evolved greatly since the 1970s. In this episode of The POWER Podcast, Steve Sabin, SETPOINT product manager for Brüel & Kjær Vibro, offers some tips to get the most out of these systems. He talks about an important vibration monitoring standard—API 670—and discusses how training has improved with new technology. Sabin gives a little background on consolidation within the industry, including the recent acquisition of SETPOINT by Brüel & Kjær Vibro. He explains how systems can be incorporated into existing power plant software, such as OSI Soft's PI system, and how purpose built vibration data repositories are used.
The UK Supreme Court ruled unanimously in favor of E.ON in a long-running dispute over foundation problems identified at the 174-MW Robin Rigg offshore wind farm located between Scotland and England. The judges said Danish contractor MT Højgaard must bear the approximate €26 million cost of remedying failed grouted connections between monopiles and transition pieces at Robin Rigg.
Rebecca Williams, partner with Watson Farley and Williams LLP, spoke to POWER Executive Editor Aaron Larson, providing background on the case and detailing implications of the decision. Listen to their conversation in the first episode of The POWER Podcast.