The POWER Podcast

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 Consequences Abranches 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.”

The Nuclear Regulatory Commission (NRC) issues licenses for commercial power reactors to operate for up to 40 years. These licenses can be renewed for an additional 20 years at a time. As of June 15, 2023, 87 of the 92 commercially operating nuclear reactors in the U.S. have had their licenses extended to 60 years. Furthermore, owners can apply for subsequent license renewal (SLR), which would authorize units to operate for another 20 years. Among owners interested in this option is the Tennessee Valley Authority (TVA), which has said it plans to submit SLR applications for its Browns Ferry reactors by December 2023. Manu Sivaraman, site vice president for the Browns Ferry Nuclear Plant, talked about the SLR process as a guest on The POWER Podcast. “There’s a lot of analysis that you do when you’re going to submit for a license renewal, especially a second license renewal,” he said. “So, number one is we benchmarked other sites that have done a 60 to 80 license application, because it’s not like this has been done hundreds of times. There’ve been a few sites that have done it, some similar to ours—a boiling water—so we took all those lessons learned and then built the project plan around: ‘How did everybody else do it?’ ” While a great deal of analysis is required to complete the SLR process, Sivaraman said even more work must be done to ensure the plant can operate reliably for another 20 years. “It’s a living process,” Sivaraman explained. “We’ve got close to 100 major capital projects laid out for the next 20 years. And when we say major, we’re not talking go replace a small pump, we’re talking change the turbine rotor out—all the blades, the rotor, generator change outs, cooling tower replacements for long-term operation.” He suggested having TVA’s backing and commitment to extending the lives of the units, allows planning for prolonged operation and not simply trying to manage stop-gap projects from year to year. “There’s also a whole host of modernization things we’re going to do—main control room modernization, digitalization of different systems, rad monitor change outs,” Sivaraman said, noting that many companies and industry groups, including the Electric Power Research Institute (EPRI), are regularly developing improvements to nuclear plant systems that enhance operations and safety. Meanwhile, having a long-term plan is also good for employee morale and helps in attracting new workers, because people can have confidence in the plant being a steady source of employment for many years to come. “It’s a great opportunity to retain people because they know they’ve got a place to work and what they do matters,” said Sivaraman. Notably, 80 years may not be the end of the line for nuclear plants. “It’s very preliminary, but there are conversations occurring in different pockets like EPRI—even the NRC—that I think have to do with ‘Okay, what does a 100-year extension look like?’ ” said Sivaraman. “It’s at its infancy, probably, right? But the fact that that discussion is happening, we can’t focus on just trying to get to 80, we need to think as though it can go past that.” Sivaraman suggested the long-term planning process is the key to success. “It is not a once and done thing. It’s a living process that needs to have intelligence built into it as you go,” he said.

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.”