Most POWER readers are probably familiar with levelized cost of energy (LCOE) and levelized value of energy (LVOE) as metrics used to help evaluate potential power plant investment options.

LCOE measures the average net present cost of electricity generation over a facility’s lifetime. It includes capital costs, fuel costs, operation and maintenance (O&M) costs, financing costs, expected capacity factor, and project lifetime. Meanwhile, LVOE goes beyond LCOE by considering the actual value the power provides to the grid, including time of generation (peak vs. off-peak), location value, grid integration costs and benefits, contributions to system reliability, environmental attributes, and capacity value.

Some of the key differences stem from the perspective and market context each provides. LCOE, for example, focuses on pure cost comparison between technologies, while LVOE evaluates actual worth to the power system. Notably, LCOE ignores when and where power is generated; whereas, LVOE accounts for temporal and locational value variations. Concerning system integration, LCOE treats all generation as equally valuable, while LVOE considers grid integration costs and system needs.

“Things like levelized cost of energy or capacity factors are probably the wrong measure to use in many of these markets,” Karl Meeusen, director of Markets, Legislative, and Regulatory Policy with Wärtsilä North America, said as a guest on The POWER Podcast. “Instead, I think one of the better metrics to start looking at and using more deeply is what we call the levelized value of energy, and that’s really looking at what the prices at the location where you’re trying to build that resource are going to be.”

Wärtsilä is a company headquartered in Finland that provides innovative technologies and lifecycle solutions for the marine and energy markets. Among its main offerings are reciprocating engines that can operate on a variety of fuels for use in electric power generating plants. Wärtsilä has modeled different power systems in almost 200 markets around the world. It says the data consistently shows that a small number of grid-balancing gas engines in a system can provide the balancing and flexibility to enable renewables to flourish—all while maintaining reliable, resilient, and affordable electricity.

Meeusen noted that a lot of the models find engines offer greater value than other technologies on the system because of their flexibility, even though they may operate at lower capacity factors. Having the ability to turn on and off allows owners to capture high price intervals, where prices spike because of scarcity or ramp shortages, while avoiding negative prices by turning off as prices start to dip and drop lower. “That levelized value is one of the things that we think is really important going forward,” he said.

“I think what a lot of models and planning scenarios miss when they look at something like LCOE—and they’re looking at a single resource added into the system—is how it fits within the system, and what does it do to the value of the rest of their portfolio?” Meeusen explained. “I call this: thinking about the cannibalistic costs. If I look at an LCOE with a capacity factor for a combined cycle resource, and don’t consider how that might impact or increase the curtailment of renewable energy—no cost renewable energy—I don’t really necessarily see the true cost of some of those larger, inflexible generators on the system. And, so, when we think about that, we really want to make sure that what we’re covering and capturing is the true value that a generator has in a portfolio, not just as a standalone resource.”

Steam is used for a wide variety of critical processes across many industrial sectors. For example, pulp and paper facilities use steam to power paper machines, dry paper and wood products, and provide heat for chemical recovery processes. Steam is used by metal and mining companies, as well as in the food and beverage industry, petroleum refining, pharmaceutical manufacturing, textile production, and many other industrial processes.

“About 20% of global carbon emissions come from the industrial heat sector, and virtually all of that industrial heat today is produced by burning hydrocarbons—coal and natural gas—and emitting carbon into the atmosphere,” Clay Sell, CEO of X-energy, said as a guest on The POWER Podcast. “With our technology, we have the opportunity to replace hydrocarbons and use nuclear-generated carbon-free steam to dramatically decarbonize these so-called hard-to-decarbonize sectors.”

X-energy is a nuclear reactor and fuel design engineering company. It is developing Generation-IV high-temperature gas-cooled nuclear reactors and what’s known as TRISO-X fuel to power them.

The company’s Xe-100 small modular reactor (SMR) is an 80-MWe reactor that can be scaled into a four-pack (320-MWe power plant) that can grow even larger as needed. “The most significant advantages that we have over large-scale traditional nuclear power plants is the evolution of our technology, our safety case, and the smaller, more simplified designs that can be built with much less time and much less money,” Sell said. “We’re a high-temperature gas-cooled reactor using a TRISO fuel form—that’s ceramic, encapsulated fuel in a round pebble that flows through the reactor like gumballs through a gumball machine.”

The Xe-100 design’s intrinsic safety makes it especially unique. “This is a plant that cannot melt down under any scenario that one could imagine affecting the plant. So, that extraordinary safety case allows us to operate on a very small footprint,” said Sell. The simplified design has fewer subsystems and components, less concrete, less steel, and less equipment than traditional nuclear power plants.

As noted previously, X-energy’s SMR is capable of producing high-quality steam, which is especially attractive for use in industrial processes. As such, Dow Inc., one of the world’s leading materials science companies, has agreed to deploy the first Xe-100 unit at its Union Carbide Corp. Seadrift Operations, a sprawling chemical materials manufacturing site in Seadrift, Calhoun County, Texas. “Our first project is going to be deployed in a public-private partnership with the U.S. government and Dow Inc., the large chemical manufacturer, at a site southwest of Houston, Texas, that will come online around the end of this decade,” Sell reported.

Currently, X-energy is in the final stages of its design effort. Once complete, the next step will be to submit a construction permit application to the Nuclear Regulatory Commission (NRC). If all goes according to plan, the application should be approved by the NRC in early 2027, which would allow construction to start around that time. “We anticipate construction on the plant to be about a three- to three-and-a-half-year process, which will then bring it online in the early 2030s,” Sell explained.

Beyond that, X-energy has an agreement to supply Amazon with 5 GW of new SMR projects (64 units) by 2039, starting with an initial four-unit 320-MWe Xe-100 plant with regional utility Energy Northwest in central Washington. Sell believes the deal positions X-energy to quickly apply lessons learned from its first-of-a-kind project with Dow, replicate and repeat the effort to achieve scale, and reach a favorable nth-of-a-kind cost structure faster than anyone else in the SMR market today.

Said Sell, “When we imagine a future of a decarbonized economy with reliable power supporting dramatic growth at a reasonable cost, I believe X-energy is going to be a central technology to that future.”

Hydrogen is becoming increasingly important to the electric power generation industry for several reasons.

One is that hydrogen offers a promising pathway to decarbonize the power sector. When used in fuel cells or burned for electricity generation, hydrogen produces only water vapor as a byproduct, making it a zero-emission energy source. This is crucial for meeting global climate change mitigation goals and reducing greenhouse gas emissions from power generation.

Hydrogen also provides a potential energy storage solution, which is critical for integrating solar and wind energy into the power grid. These renewable resources are intermittent—sometimes they produce more energy than is needed by the grid, while at other times, they may completely go away. Hydrogen can be produced through electrolysis during periods of excess renewable energy production, then stored and used to generate electricity when needed. This helps address the challenge of matching energy supply with demand.

Hydrogen is a flexible and versatile fuel that can be used in fuel cells, gas turbines, or internal combustion engines. It can also be blended with natural gas to accommodate existing equipment limitations. The wide range of options make hydrogen a great backup fuel for microgrids and other systems that require excellent reliability.

“We’ve actually seen quite a bit of interest in that,” Tim Lebrecht, industry manager for Energy Transition and the Chemicals Process Industries with Air Products, said as a guest on The POWER Podcast. Lebrecht noted that hydrogen can be a primary use in microgrids, or used as a source of backup or supplement.

“Think of a peaking unit that as temperature goes up during the day, your pricing for power could also be going up,” Lebrecht explained. “At a point, hydrogen may be a peak shave–type situation, where you then maximize the power from the grid, but then you’re using hydrogen as a supplement during that time period.”

Another hydrogen use case revolves around data centers. “Data centers, specifically, have been really interested in: ‘How do we use hydrogen as a backup type material?’ ” Lebrecht said.

Air Products is the world’s leading supplier of hydrogen with more than 65 years of experience in hydrogen production, storage, distribution, and dispensing. Lebrecht noted that his team regularly works with original equipment manufacturers (OEMs); engineering, procurement, and construction (EPC) companies; and other firms to collaborate on solutions involving hydrogen. “We’ve got a great history,” he said. “My team has a great amount of experience.”

Power plant construction and retrofit projects come in all shapes and sizes, but they all generally have at least one thing in common: complexity. There are usually a lot of moving pieces that must be managed. This can include sourcing the right materials and components, getting equipment delivered to the site at the right time, finding qualified contractors, and overseeing handoffs between working groups. Getting a job done on time and on budget is not as easy as some people might think.

“It absolutely can be difficult and a lot of things to consider,” Kevin Slepicka, vice president of Sales for Heat Recovery Boilers at Rentech Boiler Systems, said as a guest on The POWER Podcast. “You’ve got to make sure that communication is ongoing between your suppliers and the end user.”

Rentech is a leading manufacturer of boiler systems including package boilers, waste heat boilers, and heat recovery steam generators (HRSGs). Rentech’s fabrication facilities are in Abilene, Texas.

“We have three shops,” Slepicka explained. “There’s 197,000 square feet of manufacturing space under roof. We’ve got over 100 tons of lift capability with cranes, and we can bring in other cranes for our heavier lifts. Our properties are located on 72 acres, so we have a lot of room for staging equipment, storing equipment, if customers aren’t ready to take delivery at the time the units are done.”

Moving large boilers from Texas to sites around the country and other parts of the world can be difficult, which is another reason why good communication is imperative. “Shipping is a major consideration on how the unit is constructed, how much is going to be built in the facility, and how large we can ship. So, it really goes hand in hand with the design of the boiler,” Slepicka said. “It really is important that we work with our logistics people and work with our partner companies that do our transportation for us.”

Communication with customers on potential future needs is also important. Slepicka said knowing that a retrofit may be required down the road to account for a new environmental regulation, for example, could allow a boiler system to be designed with space to accommodate changes. This could save a lot of money and headaches in the long run. “That’s where you’ve got to be able to work with the customer—make sure you understand the space available and make sure that the unit’s going to work properly,” he said.

Slepicka said Rentech had a customer recently that faced new formaldehyde restrictions and needed its HRSG system modified. “Luckily, we had the space in the unit where that catalyst could be installed in the right location to address the concern they had, so it was a relatively easy retrofit for them to make.” If the prospect had not been considered up front, the cost and complexity could have been much greater.

On Dec. 22, 2008, a major dike failure occurred on the north slopes of the ash pond at the Tennessee Valley Authority’s (TVA’s) Kingston Fossil Plant. The failure resulted in the release of approximately 5.4 million cubic yards of coal ash spilling onto adjacent land and into the Emory River.

The Kingston spill is considered one of the most significant and costly events in TVA history. In a project completion fact sheet issued jointly by the U.S. Environmental Protection Agency (EPA) and the TVA in December 2014, it says the cleanup took about six years, required a total of 6.7 million man-hours, and cost $1.178 billion.

TVA hired various contractors to perform the post-spill cleanup, removal, and recovery of fly ash at the Kingston site. Perhaps most notable among them was Jacobs Engineering. TVA hired Jacobs in 2009 specifically to provide program management services to assist with the cleanup.

Jacobs claims to have “a strong track record of safely managing some of the world’s most complex engineering and environmental challenges.” It has noted that TVA and the EPA’s on-scene coordinator oversaw the worker safety programs for the Kingston cleanup, approving all actions in consultation with the Tennessee Department of Environment and Conservation. Jacobs said TVA maintained rigorous safety standards throughout the cleanup, and that it worked closely with TVA in following and supporting those standards.

Jared Sullivan, author of Valley So Low: One Lawyer’s Fight for Justice in the Wake of America’s Great Coal Catastrophe, studied the Kingston cleanup and followed some of the plaintiffs for more than five years while writing his book. As a guest on The POWER Podcast, Sullivan suggested many of the workers felt fortunate to be employed on the Kingston cleanup. The U.S. economy was not thriving at the time; housing and stock markets were in a funk, and unemployment was relatively high.

“These workers—these 900 men and women—this disaster is kind of a godsend for them as far as their employment goes, you know. A lot of them needed work. Many of them were very, very pleased to get this call,” Sullivan explained. “The trouble is that after a year or so of working on this job site—of scooping up and hauling off this coal ash muck from the landscape, also from the river—they start feeling really, really terribly,” he said.

“At first they kind of write off their symptoms as overworking themselves. In many cases, these workers were working 14-hour shifts and just pushing themselves really, really hard because there’s a lot of overtime opportunities. So, that was good for them—that they could work so much, that this mess was so big,” Sullivan continued. But after a while, some workers start blacking out in their cars, having nosebleeds, start coughing up black mucous, and it becomes clear to them that the coal ash is the cause.

Jacobs reports several contractors’ workers at the Kingston site filed workers compensation claims against their employer in 2013. These workers alleged that conditions at the site caused them to experience various health issues that were a result of excessive exposure to coal ash. Jacobs said many of these claims were found to be unsubstantiated and were rejected. Then, many of the same workers filed lawsuits against Jacobs, even though they may not have been Jacobs employees. Jacobs says it stands by its safety record, and that it did not cause any injuries to the workers.

“The case resolved early last year, after almost 10 years of litigation,” Sullivan said. “Jacobs Engineering and the plaintiffs—230 of them—finally settled the case. $77.5 million dollars for 230 plaintiffs. So, it works out to a couple hundred thousand dollars each for the plaintiffs after the lawyers take their fees—so, not tons of money.”

In a statement, Jacobs said, “To avoid further litigation, the parties chose to enter into an agreement to resolve the cases.”

You don’t need me to tell you how artificial intelligence (AI) is impacting the power grid; you can just ask AI. Claude, an AI assistant created by Anthropic, told POWER, “AI training and inference are driving unprecedented demand for data center capacity, particularly due to large language models and other compute-intensive AI workloads.” It also said, “AI servers, especially those with multiple GPUs [graphics processing units], require significantly more power per rack than traditional servers—often 2–4x higher power density.”

So, what does that mean for power grid operators and electricity suppliers? Claude said there could be several effects, including local grid strain in AI hub regions, the need for upgraded transmission infrastructure, higher baseline power consumption, and potential grid stability issues in peak usage periods. Notably, it said AI data centers tend to cluster in specific regions with favorable power costs and regulations, creating “hotspots” of extreme power demand.

Sheldon Kimber, founder and CEO of Intersect Power, a clean energy company that develops, owns, and operates a base portfolio of 2.2 GW of operating solar PV and 2.4 GWh of storage in operation or construction, understands the challenges data centers present for the grid. As a guest on The POWER Podcast, Kimber suggested the only way to meet the massive increase in power demand coming from data centers is with scalable behind-the-meter solutions.

“These assets may still touch the grid—they may still have some reliance on the grid—but they’re going to have to bring with them an enormous amount of behind-the-meter generation and storage and other things to make sure that they are flexible enough that the grid can integrate them without creating such a strain on the grid, on rate payers, and on the utilities that service them,” Kimber said.

Yet, data center developers have not traditionally kept power top-of-mind. “The data center market to date has been more of a real estate development game,” Kimber explained. “How close to a labor pool are you? What does it look like on the fiber side? What does the land look like?” He said electric power service was certainly part of the equation, but it was more like part of a “balanced breakfast of real estate criteria,” rather than a top priority for siting a data center.

In today’s environment, that needs to change. Kimber said Intersect Power has been talking to data center companies for at least three years, pitching them on the idea of siting data centers behind-the-meter at some of his projects. The response has been lukewarm at best. Most of the companies want to keep their data centers in already well-established hubs, such as in northern Virginia; Santa Clara, California; or the Columbia River Gorge region in Oregon, for example. Kimber’s comeback has been, “Tell us when you’re ready to site for ‘Power First.’ ”

What “Power First” means is simple. Start with power, and the availability of power, as the first criteria, and screen out all the sites that don’t have power. “To date, data center development that was not ‘Power First’ has really been focused on: ‘What does the plug look like?’ ” Kimber said. In other words: How is the developer connecting the data center to the power grid—or plugging in? The developers basically assumed that if they could get connected to the grid, the local utility would find a way to supply the electricity needed.

However, it’s getting harder and harder for utilities to provide what developers are asking for. “The realization that the grid just isn’t going to be able to provide power in most of the places that people want it is now causing a lot of data center customers to re-evaluate the need to move from where they are. And when they’re making those moves, obviously, the first thing that’s coming to mind is: ‘Well, if I’m going to have to move anyway, I might as well move to where the binding constraint, which is power, is no longer a constraint,’ ” he said.

Microreactors are a class of very small modular reactors targeted for non-conventional nuclear markets. The U.S. Department of Energy (DOE) supports a variety of advanced reactor designs, including gas, liquid-metal, molten-salt, and heat-pipe-cooled concepts. In the U.S., microreactor developers are currently focused on designs that could be deployed as early as the mid-2020s.

The key features of microreactors that distinguish them from other reactor types mainly revolve around their size. Microreactors typically produce less than 20 MW of thermal output. The size obviously allows a much smaller footprint than traditional nuclear power reactors. It also allows for factory fabrication and easier transportability.

Among other unique aspects are their self-regulating capability, which could enable remote and semi-autonomous microreactor operation. Their rapid deployability (weeks or months rather than many years) is a huge benefit, too, allowing units to be used in emergency response and other time-sensitive situations. Furthermore, some designs are expected to operate for up to 10 years or more without refueling or significant maintenance, which could be a big benefit in remote locations.

A lot of microreactor development work is being done at the Idaho National Laboratory (INL). John H. Jackson, National Technical Director for the DOE’s Office of Nuclear Energy Microreactor program at INL, was a recent guest on The POWER Podcast. On the show, he noted some of the programs and facilities INL has available to assist in proving microreactor concepts.

“I like to say it starts with my program, because I’m overtly focused on enabling and accelerating commercial development and deployment of microreactor technology,” Jackson said. “But there are certainly the entities like the National Reactor Innovation Center, or NRIC, which is heavily focused on deployment and enabling deployment of microreactor technology, as well as small modular reactor technology.”

POWER has reported extensively on the Pele and MARVEL microreactor projects. Project Pele is a Department of Defense (DOD) project that recently broke ground at INL. Meanwhile, MARVEL, which stands for Microreactor Applications Research Validation and EvaLuation, is funded through the DOE by the Office of Nuclear Energy’s Microreactor program.

Project Pele aims to build and demonstrate a high-temperature gas-cooled mobile microreactor manufactured by Lynchburg, Virginia–headquartered BWXT Advanced Technologies. Fueled with TRI-structural ISOtropic particle fuel, Project Pele will produce 1 MWe to 5 MWe for INL’s Critical Infrastructure Test Range Complex (CITRC) electrical test grid. The DOD noted last month that assembly of the final Pele reactor is scheduled to begin in February 2025, and the current plan is to transport the fully assembled reactor to INL in 2026.

The MARVEL design is a sodium-potassium-cooled microreactor that will be built inside the Transient Reactor Test (TREAT) facility at INL. It will generate 85 kW of thermal energy and about 20 kW of electrical output. It is not intended to be a commercial design, but the experience of constructing and operating the unit could be crucial for future microreactor developers and microgrid designers, as future plans are to connect it to a microgrid.

“The MARVEL reactor is one of the top priorities, if not the top priority, at the Idaho National Laboratory, along with the project Pele,” Jackson said. “One or the other—Pele or MARVEL—will be the first reactor built at Idaho National Laboratory in over 50 years.”

Still, Jackson was cautious when it came to predicting when the first microreactor might begin operation. “I cringe sometimes when people get a little ahead of themselves and start making bold declarations, like, ‘We’re going to have a microreactor next year,’ for instance. I think it’s important to be excited, but it’s also important to stay realistic with respect to timeframes for deployment,” he said.

The domestic content bonus credit is available to taxpayers that certify their qualified facility, energy project, or energy storage technology was built with certain percentages of steel, iron, or manufactured products that were mined, produced, or manufactured in the U.S.

“What we’ve seen happen is just a proliferation of investments into U.S. domestic manufacturing,” Mike Hall, CEO of Anza Renewables, said as a guest on The POWER Podcast. Hall said U.S. manufacturers started with the easiest and probably lowest-risk investment in the supply chain, which is module assembly. “You could count on one hand the number of U.S. module options just a couple of years ago,” he said. “Today, I was actually looking at our database, and if you were looking to take delivery in late-2025, there are 17 different manufacturers that are willing to sign POs [purchase orders] today to supply domestically made modules.”

Hall suggested most developers that are looking to utilize domestic supplies are trying to solve one or two problems. “Either they’re trying to mitigate trade risk—AD/CVD [anti-dumping and countervailing duty] risk—from the various petitions, or risk around detainment by customs due to concerns around UFLPA [Uyghur Forced Labor Prevention Act] violations,” explained Hall. “So, that’s one potential problem that customers are trying to solve, and a domestically made module may really help solve that problem,” he said.

“The other thing, though, that we increasingly see developers looking to do is to try and access the extra 10% tax credit that you can get if you meet certain minimum standards for domestically manufactured content,” Hall continued. For solar projects, that generally means a domestically manufactured solar cell is needed.

“A few years ago, again, there were one, maybe two options for that,” Hall noted. “There’s still only a few—we see those options growing over time—but if you’re looking at late-2025 deliveries, there’s four to five viable options of companies that will actually issue POs today for domestically manufactured cells. So, overall, we’re definitely seeing more and more options come to the market, and that’s really exciting.”

Yet, aside from domestic content, the options available on the market have never been greater than today. “There are more manufacturers selling into the market,” said Hall. “On Anza, we have coverage of 95% of the U.S. supply, and that requires us to have relationships—partnerships in the data pipeline—with over 33 different suppliers. So, if you’re doing a mid- or large-scale project, there’s over 120 different products that you should be considering. And, so, navigating that, and finding the module or the handful of modules that are actually going to deliver an optimal financial outcome is a big challenge.”

Hall suggested maximizing project economics requires having a sound view of the market. Then, developers must compare products, accounting for cost to install, predicted energy production, the value of the energy, and particular project risks and priorities.

“One of the things we help developers do is really understand: what is the value in dollars per watt of efficiency and the value for their particular project,” explained Hall. “And that value differs. If you’ve got a community solar project with a really high priced PPA [power purchase agreement], then efficiency is worth a whole lot. If you’ve got a really low dollar-per-megawatt-hour utility-scale PPA, then efficiency is still worth something, but it might be worth less.”

Projecting the longevity of products can be difficult, but Anza tries to factor that in using warranty information. If different manufacturers warranty their equipment for different lengths of time, that can be incorporated into financial models and will impact outcomes.

A new U.S. president will be inaugurated in less than five months. Polls show the race between Donald Trump and Kamala Harris to be very close, with potentially only a few swing states deciding the election. While energy policy may not be a deciding factor for many Americans in choosing who they will vote for, it is very important to power industry professionals.

With that in mind, Mary Anne Sullivan, senior counsel with the law firm Hogan Lovells, and Megan Ridley-Kaye, a partner with Hogan Lovells, were interviewed as guests on The POWER Podcast to discuss how the candidates might differ in their areas of focus after the election. Among the most pronounced differences is the rhetoric the two might espouse.

“A Trump administration, I think, would talk a lot more about energy security, energy independence, and the need to be friendly to American-made fossil fuels,” Sullivan said. “A Harris administration, I assume, will follow in the footsteps of the Biden administration and focus on the need to respond to climate change and build on what have truly been unprecedented accomplishments under the Infrastructure Investment and Jobs Act and the IRA [Inflation Reduction Act],” she said.

Although a Trump administration might seek to repeal all or at least parts of the IRA, Sullivan thought that would be hard to achieve. “I think recent indications are that it [the IRA] has now a fair bit of support in Congress,” she said. Ridley-Kaye agreed. “Obviously, key to what happens there [the fate of the IRA] is what happens in Congress,” she said. “It seems increasingly unlikely that it will be repealed.”

And, while the government has made major investments that support energy and power projects, private parties have invested a lot of money too. At this point in the cycle, however, Ridley-Kaye suggested some of her clients are beginning to take a wait-and-see approach, especially if project economics are not viable without tax credits. Still, many other investors are unworried about the possibility of policy changes. “We do have a large group of clients that would say, ‘The train has left the station. Corporate America expects the tax credits. There’s no way that they would be taken away,’ ” Ridley-Kaye said.

Meanwhile, there are some areas where the candidates may see eye to eye. “No matter which of them is elected, I think they will both recognize the need for more power transmission and more power generation,” said Sullivan. “Although the Biden administration has talked a good game about greening power generation, they have also very much pursued an all-of-the-above approach to generation resources. And I would expect that to continue in a Harris administration, just because there are so many new demands for electricity—the data centers, AI [artificial intelligence], vehicle electrification, the sort of ‘electrify everything’ movement that some people talk about,” she said.

Two other areas where Trump and Harris might support similar policies are on nuclear power, and carbon capture and storage. “The two administrations might have different motivations for pursuing that, but I think either one will support further technology development there,” Sullivan supposed.

Sullivan would expect a more light-handed approach to regulation under a Trump administration, specifically, as applied to permitting energy infrastructure projects. “But that more light-handed regulation on permitting helps the carbon-free power projects as much as the carbon-intensive power projects. It cuts both ways,” she said.

Depending on how the election plays out, the energy and power landscape could change very quickly. “Trump’s team seems much more ready to move on policy than it did when he ran the last time. I think they’re thinking about it in advance. They’re building a desired set of policies,” Sullivan said. “I do expect them to be more ready to move on their policy objectives.”

Fuel cells are not some novel new technology. In fact, most history books credit the invention of the fuel cell to Welsh chemist and physicist William Grove, who, in the late 1830s and early 1840s, conducted experiments proving that electric current could be produced from an electrochemical reaction between hydrogen and oxygen over a platinum catalyst.

Yet, fuel cells never really took off as a mainstream source of power. Why is that? “I think the real reason is, historically, we’ve been comfortable with less-clean, lower-efficient but less-expensive technologies, because we haven’t been as focused on air quality and on decarbonization as we currently are,” Tony Leo, executive vice president and Chief Technology Officer with FuelCell Energy, said as a guest on The POWER Podcast.

However, as people have become more focused on air quality and climate change, Leo suggested fuel cells are now poised to take off. “That’s why you’re seeing such an acceleration in the deployment of fuel cells and that’s why you’re hearing more and more about them these days,” he said.

A fuel cell is a device that makes electricity from fuel and air. Instead of burning the fuel to make heat to drive a mechanical generator, fuel cells react the fuel and air electrochemically, without combustion. The electrochemical approach avoids pollutants that are created by high flame temperatures, and it is a more direct and efficient way to make power from a fuel.

Reacting fuel and air electrochemically involves delivering fuel to a set of negative electrodes (called anodes) and delivering air to a set of positive electrodes (called cathodes). The electrochemical reaction of fuel produces electrons. The electrochemical reaction of oxygen in air consumes electrons. Connecting the two produces the current of usable electrical power.

Fuel cells are configured in stacks of individual cells connected in a series. FuelCell Energy’s carbonate stacks have up to 400 cells per stack and produce between 250 kW and 400 kW of power. FuelCell Energy’s standard MW-scale module contains four stacks, nets about 1.4 MW of power, and can make electricity for sites such as universities, hospitals, and data centers. The modular design of fuel cell plants allows them to scale up to a specific site’s energy needs.

“One big advantage is they’re quiet,” said Leo. “Since they don’t have a big spinning machine and this big spinning generator, they’re quiet compared to traditional power generation, so you can site them in population centers. We have a 15-MW fuel cell right in the middle of downtown Bridgeport, Connecticut, for example, and that just makes a really good neighbor.” The lack of harmful emissions is also a benefit.

Another advantage is that while fuel cells are making electricity, they’re also making heat that can be used to produce hot water or steam, or to drive chilling operations. “That further enhances the sustainability because you get to avoid burning fuel in a boiler, for example, if you can use the heat coming off the fuel cell,” said Leo.

Additionally, fuel cells don’t require a lot of maintenance or a large operations staff. “They’re unmanned—we monitor them remotely—and so, they take care of themselves and just generate value,” Leo explained.