THE BIG PICTURE: Hydrogen Cofiring at U.S. Gas Power Plants (Infographic)
While natural gas power accounted for 43% of total U.S. power generation in 2023, several state and federal policies aimed at reducing greenhouse gas emissions are bolstering interest in hydrogen cofiring. These policies include the Environmental Protection Agency’s recently finalized Carbon Pollution Standards, federal production tax credits, and the federal hydrogen hub program.
However, only a handful of natural gas plants have begun integrating hydrogen into their fuel streams. Operators are exploring three approaches: testing hydrogen cofiring at existing plants, upgrading turbines to accommodate hydrogen blends, and constructing new plants equipped for hydrogen use. This graphic shows some recent high-profile projects.
Source: POWER/Energy Information Administration.
DeBary Plant (Duke Energy). Duke Energy plans to upgrade one of DeBary’s four 83-MW GE 7E gas turbines, enabling it to combust up to 100% hydrogen (by volume) to cater to periods of peak demand. Project completion is estimated for late 2024.
Scattergood Generation Station (LADWP). The Los Angeles Department of Water and Power is seeking to transition its existing 778-MW Scattergood plant in Los Angeles to a rapid-response 346-MW combined cycle system capable of co-firing 30% hydrogen by December 2029, with future plans to increase that share to 100%.
Intermountain Power Agency Plant (Intermountain Power Agency). The Intermountain Power Project (IPP) Renewed project is installing a new 840-MW combined cycle plant in Utah, comprising two M501JAC gas turbines that will be capable of utilizing a fuel blend of 30% hydrogen by volume when they begin operation in 2025. It plans to transition to 100% hydrogen fuel by 2045 as technology improves.
Magnolia Power Plant (Kindle Energy). Kindle Energy LLC is building the 678-MW Magnolia Power Plant, composed of a GE Vernova 7HA.03 turbine, which is expected to enter service in 2025. Kindle Energy says the plant could co-fire up to 50% hydrogen.
Brentwood Power Plant (New York Power Authority). In September 2022, the New York Power Authority’s Brentwood power plant co-fired a blend of natural gas on a GE Vernova LM6000 PC gas turbine, starting at 5% and reaching 44% hydrogen by volume in its 47-MW peaking unit.
Hillabee Energy Center (Constellation Energy). In May 2023, Constellation Energy’s Hillabee Energy Center, a combined cycle plant in Alabama, tested a blend of up to 38% hydrogen on a Siemens Energy SGT6-6000G gas turbine.
Orange County Advanced Power Station (Entergy). The 1,158-MW Orange County plant in Texas, expected to operate by 2026, will co-fire up to 30% hydrogen using two M501JAC enhanced air-cooled gas turbines.
Jack McDonough Power Plant (Georgia Power). In June 2022, Georgia Power’s Jack McDonough power plant co-fired a fuel blend of up to 20% hydrogen on an M501G gas turbine, one of its 233-MW natural gas turbines.
A.J. Mihm Generating Station (Upper Michigan Energy Resources Company). In March 2023, the Upper Michigan Energy Resources Company conducted a test at its A.J. Mihm Generating Station using 25% hydrogen in one of the station’s three 18.8-MW Wärtsilä 18V50SG reciprocating internal combustion engines.
Long Ridge Energy Generation Project (Long Ridge Energy). This 485-MW plant in Ohio successfully tested 5% hydrogen co-firing in March 2022 using a GE Vernova 7HA.02 gas turbine.
IEEFA Report Casts Doubt on Hydrogen’s Role in Decarbonizing Gas Power
In an August 2024 report, the Institute for Energy Economics and Financial Analysis (IEEFA), a nonpartisan think tank, highlighted several other projects, including at least three that have been recently canceled.
Source: Institute for Energy Economics and Financial Analysis (IEEFA). (2024, August). Hydrogen: Not a solution for gas-fired turbines. Note: POWER has not independently verified the information presented by the IEEFA.
In its report, the IEEFA, which says its mission is to accelerate the transition to a “diverse, sustainable and profitable energy economy” through an “evidence-based approach,” provides a scathing critique of the growing trend among utilities and developers to market new gas-fired power plants as “hydrogen-capable.” The report suggests the label is little more than a marketing tactic designed to obscure the significant challenges that will delay or prevent hydrogen from playing a meaningful role in decarbonizing the power sector for decades to come.
“Utilities and merchant developers have announced ‘hydrogen-ready’ projects in at least 18 states in the past several years, running the gamut from technology demonstrations to large-scale commercial developments. But the reality is that for at least the next 10 years, any ‘hydrogen-capable’ gas-fired power plant is going to operate almost completely, if not completely, using methane,” the report says. “As such, those projects should be evaluated on that basis—not some hoped-for, potentially less environmentally damaging fuel that is years from broad commercial availability.”
The report outlines three significant barriers to hydrogen adoption: lack of supply, lack of pipeline infrastructure, and lack of storage. So far, however, current hydrogen production in the U.S. is largely consumed by industrial sectors like petrochemicals and fertilizers, leaving little room for power generation.
“Any hydrogen blending in the power sector would require new production, and a lot of it,” the report notes. For example, a relatively small gas plant that consumed 24.14 billion cubic feet of methane in 2023 would need approximately 206,073 metric tons of hydrogen to operate—equivalent to more than 2% of the total U.S. hydrogen production that year. To generate that hydrogen cleanly through renewable-powered electrolysis would require 10.3 million MWh of electricity—which is more than 2.5 times the amount of electricity the plant supplied to the grid in the same year, the report says.
If the 19 largest combined cycle gas turbine (CCGT) plants in the U.S. are factored into the calculation, the supply gap widens exponentially. The 19 plants, each with an installed net supper capacity of more than 1.5 GW and a combined capacity of 40 GW would need almost 12 million metric tons of hydrogen annually to run on 100% hydrogen, it says. That’s more than the current annual production in the U.S., it says. “In turn, to produce that hydrogen cleanly would take more than 562 million MWh of electricity, or essentially 100% of the 2023 output of the installed utility-scale wind and solar capacity in the U.S.”
In addition, the report calls into question the long-term viability of such projects, arguing that they will do little to reduce carbon emissions in the near term and will lock in the continued use of methane, a potent greenhouse gas. It also soundly criticizes the lack of transparency in the financial implications of hydrogen-ready projects. Utilities, it argues, may push to pass the cost of future-proofing gas plants for hydrogen onto ratepayers, even though there is little evidence that these plants will ever use hydrogen at a meaningful scale.
If the report highlights a bright spot for hydrogen’s future in the power sector, it suggests hydrogen may have niche applications in the power sector, such as for long-duration storage, where renewable energy can be converted into hydrogen during periods of low demand and stored for later use. The Advanced Clean Energy Storage (ACES Delta) project in Utah, backed by Mitsubishi Power and Chevron, for example, plans to store hydrogen in underground salt caverns to be used as a long-term energy source. However, IEEFA cautions that even these applications could face hurdles, such as to secure reliable sources of renewable energy to power electrolysis.
Ultimately, the report urges regulators to take a more critical stance, ensuring that investments in hydrogen-capable projects are justified, cost-effective, and not a distraction from more viable renewable energy options like wind, solar, and battery storage, which are available and cost-competitive today.
“[I]f it’s ever built, the cost of that infrastructure would certainly run into the billions of dollars and ultimately would be paid by customers,” the report concludes. “Regulators should not be approving supposedly emissions-free ‘hydrogen-capable’ gas turbines today as if they are the least-cost option when compared to renewables and battery storage. The costs of wind, solar, and storage are known today, while the ultimate cost of any ‘hydrogen-capable’ turbine will not be known for years.”
The Potential Value of Flexibility and Future-Proofing
As POWER has reported, however, the industry’s primary motivation for pursuing hydrogen combustion demonstrations has been to explore future flexibility and optionality.
Even with robust, plant-specific financial models, utility executives are grappling with increasingly volatile market conditions—and now a looming demand surge—as the energy transition gains pace. This is posing new complexities for their evaluation of long-term returns on carbon-emitting assets over their 20 to 30-year lifecycles. To enhance the long-term value of their gas plants, utility owners and operators are moving to enhance the long-term value of their gas plants by designing them with future technology integration in mind.
Optimism is also buoyant on government support for hydrogen initiatives. The U.S. Department of Energy (DOE), for example, has made significant strides through its Regional Clean Hydrogen Hubs program, allocating $7 billion to demonstrate the entire hydrogen value chain. While these hubs seek to address the infrastructure and supply challenges, they are also designed to focus on real-world applications and large-scale integration, potentially alleviating technological and financial risks. In addition, federal programs, such as the DOE’s Hydrogen Shot program, are pushing to lower the cost of clean hydrogen to $1 by 2026 and $1 per kilogram by 2031, creating a policy framework that encourages more innovation and investment in hydrogen technology.
More advancement is on the horizon. So far, the DOE’s Hydrogen and Fuel Cell Technologies Office (HFTO) has reported substantial progress, including an 80% reduction in the capital cost of proton exchange membrane (PEM) electrolyzers and a 70% reduction in fuel cell system costs for transportation applications.
In its recently issued Multi-Year Program Plan (MYPP), the office has set ambitious targets for more progress, such achieving 65% electrolyzer efficiency, scaling hydrogen infrastructure, improving fuel cell durability for heavy-duty applications, and expanding U.S. manufacturing capacity for hydrogen technologies.
—Sonal Patel is a POWER senior editor (@sonalcpatel, @POWERmagazine).