The POWER Podcast

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.”