This is the second in a three-part series Utility Dive is publishing this week looking at the emerging business and policy landscape for hydrogen in the United States. The first part examined regulatory challenges around hydrogen while the third will focus on potential competition and collaboration between gas and electric utilities.
To the Los Angeles Department of Water and Power, the future of hydrogen is both clear and bright. As the city moves with increasing speed toward its 100% renewable energy target, hydrogen will fill an important gap by providing a form of long-term storage for when the city's growing network of wind and solar resources are offline.
"We view green hydrogen as the path forward to full decarbonization, and full decarbonization in a way that is reliable," said Jason Rondou, director of resource planning, development and programs at LADWP.
Across the country, Southern Company also views hydrogen as a critical technology required for full decarbonization, but the company's own research led to a different vision: rather than using hydrogen as a generation asset, Southern Company believes the alternative fuel will, at least at first, help the company pay for renewable energy and needed grid expansion by creating a marketable byproduct of renewable hydrogen gas to be sold to industrial customers who currently lack carbon-free alternatives.
"We see hydrogen as a great vector to bring zero carbon fuels to customers," said Nick Irvin, director of advanced energy systems R&D for Southern Company.
"We see hydrogen as a great vector to bring zero carbon fuels to customers."
Nick Irvin
Director of Advanced Energy Systems R&D, Southern Company
While the hydrogen sector is still dominated by petrochemical companies and oil majors such as BP, large utilities have recently begun to move into the market as well, according to Mona Dajani, a partner at Pillsbury Winthrop Shaw Pittman, where she heads the firm's renewable energy and hydrogen practice. But depending on the utility's specific circumstances, such as the resources they have access to and their approach to decarbonization, hydrogen can represent something different from one utility to the next, Dajani said. Where some, such as LADWP, see the potential to retrofit existing generation assets, others see a host of new business opportunities on the horizon.
"We think hydrogen is a little further out there than maybe some of the [other] solutions, but it's probably an important one," said Joe Hoagland, vice president of enterprise relations and innovation at the Tennessee Valley Authority (TVA). "What we haven't figured out is how does it come into play."
Hydrogen for the offtaking
The TVA feels confident about the next decade or so of its decarbonization plans; by 2035, Hoagland said, the utility should be able to reduce its emissions by 70-80% using existing technologies. What happens after that is less certain, Hoagland said.
Hydrogen, he said, is one strategy TVA has considered for eliminating the final 20% of generation emissions by 2050. However, the development of alternative fuels is somewhat behind other technologies such as advanced nuclear and carbon capture, so hydrogen-powered turbines may be some decades off for the TVA, Hoagland said.
But he does see near-term potential for hydrogen as a fuel — and as a byproduct of electrical generation. While most hydrogen produced today is extracted from natural gas to create so-called "blue" hydrogen, "green" hydrogen could be produced by using clean electricity to split water into oxygen and hydrogen.
"It's obviously important that we get our emissions down, but the whole mission of TVA is to make lives better for the whole valley," Hoagland said. "Can we take our electricity and make things that allow our whole valley to decarbonize?"
Southern Company, similarly, does not plan to use hydrogen to generate power any time soon. There simply isn't enough cost-effective green hydrogen available to fire a gas turbine yet, Irvin said.
"If I want to make the move toward [burning hydrogen in gas turbines], it seems logical to target applications that can afford a premium fuel," Irvin said, "and use those applications to grow the scale of manufacturing to get down the cost curve as quickly as possible, and then go back to the applications that require large scale like combustion turbines."
What hydrogen can do in the near-term, Irvin said, is "create more space for renewables" by driving electrolysis with energy that would otherwise be curtailed. The hydrogen could then be sold into industries already using it as a fuel or feedstock, including fertilizers, oil refining and some synthetic materials, which would in turn make overbuilding renewable energy a more cost-effective strategy for utilities looking to decarbonize rapidly, Irvin said.
This strategy is also attractive to the TVA, which envisions using excess nuclear power to drive electrolysis, helping to pay for the cost of nuclear energy by supplementing the utility's income with sales of hydrogen.
"The question I don't think is solved yet," Hoagland said, "is should I produce hydrogen and use that hydrogen somewhere else, or should I use that electricity where I electrify something else in the economy."
As new technologies emerge, utilities could begin to "stack" additional benefits of hydrogen for even greater cost savings and income, Irvin said. Instead of simply selling the hydrogen itself, it might be possible to locate a small electrolyzer near an industrial user, such as a warehouse with hydrogen-powered forklifts. The electrolyzer could be equipped with both a dispenser for the trucks, and a fuel cell, and electric vehicle fast chargers. When there's extra renewable power, the electrolyzer turns on to soak up excess energy and fill the dispenser and fuel cell. When there's less power, the fuel cell charges employee EVs. If the power goes out, the fuel cell itself could serve as a backup generator. Generation, grid resilience and demand management — all tied together in one package that was already paid for with the revenue from selling hydrogen to the forklifts, Irvin said.
"That's a really interesting model," he said. "There ought to be something there for somebody to take advantage of, and we're working to figure out what our role in that is."
Fuel of the future
Xcel Energy has also taken an interest in hydrogen production, and currently has plans in the works to pilot an electrolysis system at its Prairie Island nuclear plant in Minnesota in 2022.
But to eliminate the last 20% of its own emissions, Xcel Energy plans to take a more direct approach, according to a company statement to Utility Dive. New gas-powered generation will have the capacity to use hydrogen as a fuel in the future, according to Xcel, including four natural gas facilities to be built in or near Minnesota.
LADWP also falls squarely into the camp of utilities more focused on using hydrogen to generate electricity and cut emissions than on hydrogen as a byproduct to be sold to other parties, according to Paul Schultz, the utility's director of external generation.
"[W]e're looking for another technology that is ultimately seasonal storage, and we think hydrogen is that solution."
Paul Schultz
Director of external generation, LADWP
As a municipal utility, LADWP is prohibited from selling hydrogen, Schultz said. Their strong interest in the alternative fuel comes from a need identified by the city's LA100 study, completed last March in partnership with the National Renewable Energy Laboratory. While the study determined that the city should be able to achieve 100% renewable energy by 2035, it also found that no matter how the city plans to achieve its goals, it will need significant transmission upgrades and some form of reliable generation located within the city itself.
"We see hydrogen as that piece, to get completely off natural gas," Rondou said. "We view green hydrogen as the path toward full decarboniziation in a way that is reliable."
Hydrogen will fill a niche in LA that no other available resource can, Rondou explained — not baseload generation but something akin to long-term storage. Some days, hydrogen-fueled turbines will act like peaking plants, firing up when high heat begins to stress the grid. Or it might kick in as backup power if an emergency cuts the city off from its remote wind and solar resources. Other days, the city won't use hydrogen at all — possibly for many days in a row.
"As we see more and more renewables and pair them with batteries, the batteries are four-hour duration," Shultz said. "So we're looking for another technology that is ultimately seasonal storage, and we think hydrogen is that solution."
LADWP is currently preparing an RFP to solicit proposals for hydrogen generation within the city, according to Rondou. Outside the region, their first hydrogen-fired power plant is already under construction at the Intermountain Power Project (IPP) in Delta, Utah.
Although the IPP will provide LA with baseload energy and not the backup resource it envisions for the future, it will provide LADWP with its first experience generating power with hydrogen, according to Rondou. The plant will burn a natural gas blend with 30% hydrogen when it first comes online in 2025, and work up to 100% hydrogen as the industry scales. And the IPP is in a perfect location to drive that growth, Schultz said, thanks to the fact that it sits atop a natural salt cavern that can be used to store large amounts of hydrogen, and has access to extensive transmission systems.
"There are so many things that really set it up for phenomenal hydrogen production," Rondou said, noting that dispatching hydrogen will be much more difficult in the city itself. "IPP will give us a head start," he said, "but we're going to have to take those lessons and expertise and try to make that happen within the city."
Rondou said he believes LADWP is, in its own way, also uniquely situated to take advantage of hydrogen — the utility is vertically integrated and has access to excellent transmission resources. Other utilities, he said, will have to consider their own situation when evaluating how hydrogen could fit into their operations, because hydrogen, like any resource, may not be equally valuable in all regions.
"Not all utilities will or won't need hydrogen," he said. "What I would say is they need to look and to do the modeling for their own service area. They need to look at things like resilience, because if they don't it may not become apparent that a resource like hydrogen will be needed."
