The POWER Podcast

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.”