The POWER Podcast

There are many reasons to be excited about the U.S. nuclear power industry and its potential for growth. For activists focused on climate change, its carbon-free attribute makes it a viable long-term power resource. Additionally, its around-the-clock generating capability makes it a vital option in a world increasingly filled with intermittent renewables. Furthermore, new technology that incorporates passive safety features lessen the dangers associated with reactors, making units appealing even to companies outside of the power generating sector, such as chemical producer Dow Inc. and steel manufacturer Nucor Corp. Yet, there are numerous challenges facing the industry that could thwart the growth predicted by optimistic observers. John Kotek, senior vice president for Policy and Public Affairs with the Nuclear Energy Institute (NEI), the trade association for the nuclear energy technologies industry, outlined a handful of major obstacles that must be overcome to ensure future success of the nuclear industry. “The cost and schedule challenges associated with firsts-of-a-kinds of new reactor technologies is very high on our list,” Kotek said as a guest on The POWER Podcast. Kotek acknowledged that the Plant Vogtle expansion, a Southern Company project being undertaken in Georgia where two new AP1000 reactors are being added to the existing two-unit facility, has taken longer and cost more than originally expected. Nonetheless, he implied these cost and schedule issues can be overcome. Kotek also suggested the Nuclear Regulatory Commission’s (NRC’s) licensing review and approval process could be improved. “We’re really focused on the Nuclear Regulatory Commission,” he said. “They do a really good job of overseeing a safe industry here in the U.S., but it’s our view that they need to modernize their approaches to regulation as the technology is modernized. We need to see greater efficiency and timeliness and lower cost in NRC licensing reviews.” “Finally, we’re going to need to see investments in our export support,” said Kotek. “When we export a nuclear reactor and nuclear technology to another country, we need to have an agreement in place with that country that ensures that non-proliferation requirements are met. We need to see more of those agreements put in place. Right now, the U.S. only has such agreements in place with about a quarter of the nations in the world, and so, as the global market expands, we’re going to need to expand the number of those agreements.” Another aspect of export support involves leveling the playing field in the global marketplace. “When our companies are competing in this global marketplace, they’re competing against countries—competing against the state-owned enterprises in Russia and China, for example,” explained Kotek. “Those nations can offer very attractive financing packages, for example. So, we need organizations like our Export-Import Bank to be given the tools they need to enable our exporters to look attractive and succeed in those markets.” Kotek acknowledged that the Bipartisan Infrastructure Law and Inflation Reduction Act were highly beneficial to the nuclear industry, but he said it would remain important to see those tax credits and other incentives retained well into the future. Kotek suggested policies could also be enhanced in many states. Specifically, he said for states interested in decarbonizing their power grids, renewable portfolio standards should be broadened to clean energy standards. “Seeing more states move in that direction will create more demand for nuclear, because the more you’re focused on getting to 100% carbon-free, the more the value of nuclear really comes through,” he said. “Policymakers are coming to understand that the lowest-cost carbon-free energy systems include nuclear power.”

One fuel source that may not immediately come to mind when thinking about charging EVs is propane. However, there are innovative vehicle-charging options available using propane, and it is a relatively low-carbon fuel source, especially when “renewable propane” is available. Jim Bunsey, director of commercial business development with the Propane Education & Research Council (PERC), shared details on a portable propane-fueled EV charging unit that is available today. “It takes up about a parking space,” he explained as a guest on The POWER Podcast. “It’s a trailer that weighs under 10,000 pounds—so, it’s a non-commercial load—and they have about 100 to 120 gallons of storage onboard.” During the Advanced Clean Transportation Expo (ACT Expo) held May 1–4, 2023, in Anaheim, California, PERC put the portable charging station to the test. The expo included a “Ride & Drive Event,” which allowed attendees to take dozens of the latest advanced clean vehicles for a test run. What the event needed was a way to charge the electric vehicles during the show. The portable trailer fit the bill. “Now, the fun part is, we hooked up with a large propane retailer in the area, and they actually had renewable propane available to us. So, we were charging the electric vehicles—a zero-emission tailpipe—we were charging them with a carbon-intensity score, with a blend that we had, less than 20,” Bunsey said. He noted that the carbon-intensity score for the California grid is right around 79 to 80, and that non-renewable domestic propane typically runs around 79 to 80 as well. “So, we’re equal to the grid in that area—depends on how we look at carbon intensities—but since we had the blends that were available to us, we were charging with a carbon intensity of 20, which was amazing that we were there. So, it was very successful,” he said. Bunsey said the original equipment manufacturers (OEMs) demonstrating their vehicles at the ACT Expo became very excited about the possibility of charging vehicles with propane. “We were charging these over-the-road electric vehicles at 700 volts with nice, quiet, clean-burning propane that was reliable, and it opened the OEM’s eyes. They’re like, ‘Hey, we want to do this.’ And luckily, we’re starting to pair with OEMs to help them electrify the future,” said Bunsey. Using the AFDC calculator, annual CO2 equivalent emissions for an all-electric vehicle charged in California was 1,473 pounds in 2021. If we assume renewable propane offers a carbon intensity of about one-quarter that of the California grid, the CO2 equivalent emissions using renewable propane would even be close to half what was estimated earlier in the Washington state example. For fleet owners that are just getting started with EVs and may not have the infrastructure and transformers in place to charge at 700 V, the propane-fueled portable trailers could make sense. The systems could be scaled up as fleets expand, then, once permanent, grid-connected charging stations are installed, propane could be phased out or continue to act as a backup. It frankly provides a lot of options.

For more than four decades, POWER magazine has honored the top performers in the electricity-generating industry with annual power plant awards. Award winners are selected by the editors of POWER based on nominations submitted by industry insiders, including suppliers, designers, constructors, and operators of power plants. Winning POWER’s highest honor—the Plant of the Year—in 2023 is Estrella del Mar III, a first-of-its-kind floating combined cycle gas turbine power barge that Sonal Patel, senior associate editor for POWER, said fulfills a remarkable assortment of modern power system demands. “Nearly fully built in Singapore by an international team that delicately integrated shipbuilding and power engineering, the pioneering SeaFloat plant sailed more than 10,000 miles for final commissioning in Santo Domingo, capital of the Dominican Republic. The innovative 148-MW project exemplifies an efficient, ecological, economical, and resilient power solution that triumphs over land and cost constraints,” she wrote in the cover story for the July issue of POWER. “This is actually the highest form of modularization, bringing a fully equipped power plant to the heart of the capital without requirements of precious land,” Hamed Hossain, business owner of Siemens Energy’s SeaFloat segment, said as a guest on The POWER Podcast. Hossain explained that with SeaFloat on the menu, Siemens Energy customers can choose to build power plants either on land or on a floating device. “This opens entirely new possibilities for customers,” he said. Constructing SeaFloat plants in a shipyard rather than on-site offers a number of benefits. Hossain noted that an experienced workforce is typically readily available in the shipyard environment. Furthermore, the impact on the local community during the construction phase of the power plant is minimized. Hossain said building the power barge directly in the heart of Santo Domingo would surely have affected residents, for example, with possible traffic restrictions and other complications. Estrella del Mar III is a state-of-the-art combined cycle power plant. It is equipped with two SGT-800 gas turbines (GTs) built in a Siemens Energy factory in Sweden, and an SST-600 steam turbine manufactured in Görlitz, Germany. “We have ensured to bring typical land-based plant efficiency to the heart of the beautiful island, Dominican Republic, Santo Domingo, on a floating device,” Hossain said. Notably, the SGT-800 gas turbines are capable of operating currently on a blend of 75% hydrogen, and Siemens Energy has a pathway to 100% hydrogen by the end of the decade or sooner. This is an important development as countries move to decarbonize their power supplies. “We need to find the best way for a net-zero future,” said Hossain. “We are not there yet, but the capability to run the GTs with hydrogen is a huge step in that direction.”

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

Building a nuclear power plant is a difficult job. It takes years of planning and sometimes more than a decade to complete. The risk of schedule delays is great, especially on first-of-a-kind projects, and the financial implications of such setbacks can ruin a company. Yet, the Tennessee Valley Authority’s (TVA’s) president and CEO, Jeff Lyash, suggested the risk is worth taking, that is, if lessons learned from one project can be parlayed into success in future projects. That’s why TVA is studying the addition of a small modular reactor (SMR) at its Clinch River site. Lyash envisions using that first unit as a template to eventually make Clinch River a four-unit site, and then replicating that design in at least four other locations within TVA’s service territory. “I’ve said very vocally, I [want] nothing to do with building one reactor, unless I can build 20—and 20 is the low estimate—and so, this is what Clinch River is about,” Lyash said as a guest on The POWER Podcast. While TVA continues to support and examine all of the various SMR designs being proposed, and it is also following the development of Generation IV advanced nuclear technology, it has selected GE-Hitachi’s (GEH’s) BWRX-300 design for its Clinch River site. “We picked the BWRX-300 technology because the X stands for the 10th generation. We know this fuel works. We know this technology works,” Lyash said. Lyash noted that there are 50 years’ worth of experience behind the GEH design. He said engineers have applied modularization processes and advanced manufacturing techniques to advance the design, but the technology behind it all is well-established. “This allows us to focus on what I think the risk is that’s yet to be proven, and that is, can we finish a first-of-a-kind on schedule and on budget, and can we demonstrate the movement to nth-of-a-kind rapidly, and can we turn that into a fleet?” Lyash said. “We intend Clinch River to be a four-unit site,” Lyash explained. “There’s an optimum way to build four units. It includes a lot of overlap—supply chain, labor, etc. That’s what we want to develop, but we’re going to ‘unlap’ the first unit so that we can learn all those lessons, identify all those risks, and make units two and three and four look significantly better and different, so that when we build site two, three, and four, we’ve got that,” he said. TVA is a wholly owned U.S. government corporation created by Congress in 1933. It is the largest public power company in the country, providing electricity for 153 local power companies serving 10 million people in Tennessee and parts of six surrounding states, as well as directly to 58 large industrial customers and federal installations. Because of TVA’s unique position as an entity of the federal government, Lyash believes it should be a leader for the power industry. “Because of TVA’s special role, we’re really doing it to support the nation, because what we’d really love to happen is fast followers,” he said. In other words, he hopes once TVA proves that an SMR can be constructed on time and on budget, other power companies will jump on the new nuclear construction bandwagon. Still, nuclear is not the only new generation TVA is pursuing. It also has plans to add at least 10,000 MW of new solar, as well as battery and pumped-hydro energy storage, and even some natural gas–fired generation to help bridge the gap as it phases out its coal generation by 2035. “We at TVA are very outcome focused, so we spend a lot of time talking about: ‘At the end of this trail, where is it we want to arrive at?’ ” Lyash said. “It’s about affordable energy that’s reliable and resilient, and low-carbon.” To reach the desired outcome, Lyash said it would take renewables, nuclear, storage, demand-side management, and energy efficiency all in the right mix.

New technology is regularly being developed and enhanced to improve power delivery and incorporate more renewable energy into systems. ABB Energy Industries is among the companies investing large sums of money in research and development (R&D) programs to make future power systems better. Among its current projects are subsea power distribution and conversion concepts, which could benefit the offshore wind industry, and a Power-to-Ammonia pilot project. “We have a lot of experience—over 20 years—with this subsea equipment,” Asmund Maland, head of subsea and offshore power at ABB Energy Industries, said as a guest on The POWER Podcast. “Our intention is to put on the seabed what we call the ‘services substation and collector systems,’” he explained. Maland said the subsea equipment could replace or act as an alternative to a floating substation, which he expects will be more needed as the offshore wind industry moves to deeper waters. ABB has already tested these systems for the oil and gas (O&G) industry with great early success. Nearly a decade ago, the company initiated a $100 million Joint Industrial Project with Equinor (formerly Statoil), Total, and Chevron with support from the Research Council of Norway. As part of that project, ABB completed the development of an electrification system for transmission, distribution, and conversion of power, to subsea pumps and gas compressors, at a peak capacity of 100 MW, to water depths up to 3,000 meters, with transmission distances up to 600 kilometers, and with little or no maintenance for up to a lifetime of 30 years. “If you replace a floating substation with something on the subsea, you will reduce to one-fifth of the steel. So, by that, there is also then potential capex [capital expenditure] savings of maybe over 30%, and also, the opex [operating expense] savings of the year will also be quite good,” said Maland. ABB expects to be ready to take orders for subsea offshore systems by the end of 2024. On the podcast, Tom Zøllner, head of ABB Energy Industries for Denmark, talked about another innovative project ABB is involved in, which the company calls “the world’s first dynamic green Power-to-Ammonia plant.” ABB is working alongside Danish companies Skovgaard Energy, Vestas, and Haldor Topsoe to demonstrate Power-to-X (PtX) technology in Lemvig, northwest Denmark. The project is also being supported by the Danish government’s Energy Technology Development and Demonstration Programme, which provided about $12 million in assistance. “The reason behind the project is that in Denmark we have for some time been one of the lead countries when it comes to green energy, and it has been more and more clear that we need to figure out how to store all this additional energy that we may not be able to use all the time. Unfortunately, batteries are not strong enough, and therefore, we need to look into alternatives, and Power-to-X has become one of the solutions that we have been looking into for some time,” Zøllner said. The demonstration facility—scheduled to start operating in 2024—will be powered by renewables from 12 MW of existing wind turbines and 50 MW of new solar panels. ABB is responsible for electrical integration and advanced process control of the full Power-to-Ammonia plant operating in highly dynamic mode. The 10-MW plant is expected to operate at full capacity when excess wind and solar power are available, but will gear production down when neither renewable energy source is present, making it adaptable to fluctuations in energy supply and different from other types of PtX plants, which are directly connected to the grid. The pilot plant will produce about 5,000 tons of ammonia per year. While the project is small in the grand scheme of things, Zøllner said it will showcase the technology and should be scalable in the future.

It’s no secret that leaders around the world are searching for ways to decarbonize their electric power grids. While solar panels and wind turbines have been the main options utilized in this effort in recent years, both are intermittent resources. Therefore, backup generation is required to keep power grids reliable. In many situations, that means installing diesel-fueled power generators. In fact, there’s been a significant increase in diesel generator sales as wind and solar capacity have increased. “Right now, 90% of the backup power is diesel-powered,” Jim Bunsey, director of commercial business development with the Propane Education & Research Council (PERC), said as a guest on The POWER Podcast. “It’s been tremendous growth in diesel-powered backup power and that’s where we can really start to bring propane into play,” Bunsey said. Yet, even as propane is used to supplant diesel-fueled backup systems, it can also be used to displace other grid-connected power generators, thereby reducing carbon emissions. “As we look at decarbonization, we look at the carbon intensity, or the full lifecycle of a product, of where it’s generated, how it’s transmitted, and how it gets to its end source where it’s being used,” Bunsey explained. He noted the national average carbon intensity score for the U.S. power grid is 130. Propane, meanwhile, has a carbon intensity score of only 79. “So, right now, from switching from the electric grid to propane-powered power generation, we’ve now moved our carbon intensity score from 130 to 79. That’s a great savings. That’s available today with our infrastructure for developing propane, for storing propane, for moving propane, and gives that carbon intensity score—79 is really good,” he said. “It starts us on the path to zero. So, as we decarbonize, we look at the electric grid, we look at other products, we’re working our way down.” But Bunsey sees a future where propane is even less carbon intensive, and it’s not too far in the distance. “The most exciting thing that’s coming is renewable propane,” he said. “Renewable propane has been being used for about five, six years right now. It’s being delivered.” While quantities are still limited at present, and most of the renewable propane produced today in the U.S. is being shipped to California where carbon credits are making it more affordable, Bunsey expects the volume of renewable propane to increase as major suppliers start to come onboard. “That gives us a clear path to zero. We can step it down,” he said. “There’s renewable propane that’s being delivered today that has at-the-source carbon intensity of about 11. And then, delivered on-site, because that’s where you’ve got to look at the whole lifecycle—what does it take? We’re going to develop this fuel. We’re going to ship it. We’re going to go to the end-use. By the time it gets to the end use in California, they’re at 20.5 today. That was the last quarter. That’s what they’re using right now with renewable propane,” said Bunsey. “There’s a clear path right now for people, for their decarbonization, and we can get our path to zero.”

Perhaps the most devastating thing that could happen in any developed country would be widespread catastrophic damage to its electric power grid. Nearly everything in an industrialized nation relies on electricity to function. Without it, normal water supplies, sewer systems, and communication services are cut off. Furthermore, things like food and transportation are quickly affected when power is down for extended periods. A severe electromagnetic pulse (EMP) or geomagnetic disturbance (GMD) event could take the power grid down for months, and possibly even for years. An EMP is a very intense pulse of electromagnetic energy, typically caused by the detonation of a nuclear bomb or other high-energy explosive device. A GMD, meanwhile, can be caused when a solar eruption produces a coronal mass ejection (CME) that travels from the sun to the Earth. A direct hit by an extreme CME would cause widespread power blackouts disabling everything that uses electricity. Some experts have suggested that a major EMP or GMD hit could result in the death of up to 90% of the U.S. population. What makes the event so devastating is that the U.S. power grid is not well-protected from such a strike, and the country is not prepared to recover quickly. Dr. William R. Forstchen, author of more than 40 books including the groundbreaking novel One Second After, which has been credited with raising national awareness to the potential threat posed by an EMP strike, explained the situation as a guest on The POWER Podcast. Forstchen noted that the U.S. power grid is vulnerable to such an event for a number of reasons. “The average component in our electrical grid is 40 to 50 years old. We are running our electricity on a 1970s, early-1980s industry. We’re not modernizing it,” he said. A few years ago, the federal government began to address the problem. “The Trump administration finally started taking action about six months before the election in 2020. They mandated DOD [the Department of Defense], DOE [the Department of Energy], all the different agencies to submit a comprehensive analysis of what needs to be done that would then follow by legislative action in the next Congress,” Forstchen explained. However, when Trump lost the election, President Biden immediately killed the initiative, he said. Forstchen said relatively minor investments could vastly improve the situation. He suggested stockpiling key components is an important first step. “A large transformer for a major substation can cost several million dollars. From the time of ordering one until the big truck pulls up and we start to unload it is two or more years,” Forstchen said. Furthermore, he noted that most of the equipment and components that might be needed to repair the grid are now sourced from other countries, mainly China, which means the U.S. may not be able to get supplies, especially if the attack was initiated by one of those countries. “We should be building a strategic reserve of key electrical components,” he said. Additionally, Forstchen said the U.S. should focus on a “lifeline to recovery.” He suggested hardening 10% of the grid could act as an insurance policy for the nation. “Let’s say the rest goes down, but we have those lifelines out there that can be used to start repairing things, bringing supplies, and communicate—big thing, communication and transportation,” said Forstchen. Risks could be substantially reduced with relatively minor investments. “I argue $20 to $30 billion a year would at least start ensuring some responsible response to this problem,” Forstchen said.

The U.S. Gulf Coast offers some of the greatest potential for renewable energy development in the country. According to a National Renewable Energy Laboratory (NREL) study, Florida, Texas, and Louisiana rank second, third, and fourth, respectively, in net technical energy resource potential for offshore wind. The large energy resource in these three southern states is attributed to a large quantity of ocean area that encompass relatively long coastlines and wide continental shelves. Greater New Orleans Inc. (GNO) is the regional economic development nonprofit organization serving the 10-parish region of Southeast Louisiana that includes Jefferson, Orleans, Plaquemines, St. Bernard, St. Charles, St. James, St. John the Baptist, St. Tammany, Tangipahoa, and Washington parishes. GNO is keenly focused on developing a thriving offshore wind industry in its region. Among the initiatives it oversees is the GNOwind Alliance, which is comprised of more than 180 organizations that GNO says “provide the expertise to grow the region and state as an energy leader.” “[The GNOwind Alliance] was really launched with the understanding that there was a lot of activity and a lot of interest in the forthcoming leases in the Gulf of Mexico around wind development, and recognizing that not only do we have this lease potential in the Gulf of Mexico, but we also have this incredible industrial base across south Louisiana to connect some of this green energy to,” Lacy McManus, executive director of Future Energy at GNO Inc., said as a guest on The POWER Podcast. McManus suggested that south Louisiana’s history with the oil and gas industry positions it to quickly adapt and capitalize on the offshore wind potential. She said many of the services that are going to be needed—the labor profiles, the workforce, and even some of the policy and regulatory experience necessary to develop the wind sector—borrow from the oil and gas industry. “We have a lot of that already in our landscape,” said McManus. “It’s where we are fortunate because I think that’s going to really catalyze a lot of our activity, and add to the momentum, and the speed and efficiencies with which we’re able to deliver to companies and industries coming in.” GNOwind Alliance is already supporting workforce programs that train workers to transfer skills from oil and gas to wind energy through a partnership with academic and industry allies. “We work hand in glove with our higher education landscape here in Louisiana, but specifically at GNO Inc., we have a fantastic relationship with both LCTCS, which is the Louisiana Community and Technical College System, as well as with the Board of Regents, who oversees all of our higher education institutions,” McManus said. GNO leadership made the decision about a decade ago to have all of the presidents of the four-year schools in the Greater New Orleans region, and all the chancellors of the two-year community colleges in the region, on its board of directors. “For the last 10-plus years, all of that higher ed leadership has been sitting in the same room with all of the business leadership in the region on a monthly basis at our board meetings. They get the scoop and the understanding, and hear straight from the horse’s mouth on new announcements that we have coming in,” said McManus. Beyond offshore wind, McManus sees opportunity for southeastern Louisiana in the green hydrogen economy. “Louisiana and our industry base actually consumes one-third of the nation’s hydrogen. So, that’s a lot of gray hydrogen that’s currently going into our industrial footprint,” said McManus. “With the opportunity to develop more wind in the Gulf, we have a really unique, in my view, sort of once in a generation chance to shift some of that gray hydrogen that we’re currently using in our industrial footprint over to green hydrogen.”

You may not expect to hear names like Henry Ford and J.P. Morgan mentioned when studying the history of hydropower. You might know that President Franklin Delano Roosevelt signed the Tennessee Valley Authority Act in 1933, establishing the Tennessee Valley Authority (TVA), which has 29 power-generating dams in its power system, but you may not realize how much of a role FDR played in other hydropower projects. It’s frankly an understatement to say all three of these men were hugely important in the development of U.S. hydropower. “I almost guarantee that most people do not realize that Henry Ford was such a significant player. He was a strong proponent of hydropower. He looked at water as free,” Bob Underwood, author of the book DAM IT! Electrifying America and Taming Her Waterways, said as a guest on The POWER Podcast. “He was experimenting with hydropower from the time he was a kid. He went on to develop 30 different hydroelectric facilities—small and large.” Underwood explained that Ford was also part of a major hydropower battle. It involved the Wilson Dam near Muscle Shoals, Alabama, a small town located on the southern bank of the Tennessee River. President Woodrow Wilson had authorized construction of the Wilson Dam in 1916. The hydropower plant was intended to provide electricity for a munitions facility that was supporting the war effort during World War I, but the war ended before the dam was completed. Construction on the project languished after the war while Congress debated what to do with the property. Some senators wanted to sell the dam to a private company while others thought the government should retain public control of the property. Henry Ford made a surprise inspection tour of the Muscle Shoals facilities and the Wilson Dam site in June 1921. A month later, he submitted a bid for all the federal properties associated with the site. “And that’s where he got into it with Senator Norris [from Nebraska], and that went on for four or five years,” said Underwood. Norris was one of the biggest public power advocates around. Although technically a Republican, Norris was fiercely independent and regularly collaborated with FDR, a Democrat. “[Ford] lost, but that sure elevated the view of hydropower in this world,” said Underwood. Although J.P. Morgan passed away a little over a year before World War I began, he played an important role in the history of hydropower during his lifetime. Underwood said even he didn’t realize how influential J.P. Morgan was to the electric power generation industry before he started doing research for his book. He said Morgan was pulling strings behind the scenes, not only in the electrical business, but in everything else that was going on in his day. “He was always trying to build a monopoly in whatever industry it was,” said Underwood. “He manipulated Edison to merge another company of the time—a big competitor, Thomson-Houston—into Edison General Electric to form General Electric, essentially shoving Edison aside and out of his own company. And J.P. Morgan kept having huge influence through the financing of the industry—both the hydroelectric side of it, as well as the coal-fired side of it,” Underwood explained. But when it comes to big hydro projects, FDR gets much of the credit for making them happen. “He changed the industry,” Underwood said on the podcast. “Very influential.” Among FDR’s significant hydropower accomplishments are two projects on the Columbia River: Bonneville and Grand Coulee. Four months after taking office in March 1933, FDR was able to cut through years of conflicts to get construction underway. Underwood wrote in his book, “His actions clearly established federal authority over the waters of the West."