In one of the Biden administration’s final acts to advance decarbonization, and after more than two years of deliberation and heated debate, the Treasury Department issued the final requirements governing eligibility for the clean hydrogen tax credit on Friday.
At up to $3 per kilogram of clean hydrogen produced, this was the most generous subsidy in the 2022 Inflation Reduction Act, and it came with significant risks if the Treasury did not get the rules right. Hydrogen could be an important tool to help decarbonize the economy. But without adequate guardrails, the tax credit could turn it into a shovel that digs the U.S. deeper into a warming hole by paying out billions of dollars to projects that increase emissions rather than reducing them.
In the final guidelines, the Biden administration recognized the severity of this risk. It maintained key safeguards from the rules proposed in 2023, while also making a number of changes, exceptions, and other “flexibilities” — in the preferred parlance of the Treasury Department — that sacrifice rigorous emissions accounting in favor of making the program easier to administer and take advantage of.
For example, it kept a set of requirements for hydrogen made from water and electricity known as the “three pillars.” Broadly, they compel producers to match every hour of their operation with simultaneous clean energy generation, buy this energy from newly built sources, and ensure those sources are in the same general region as the hydrogen plant. Hydrogen production is extremely energy-intensive, and the pillars were designed to ensure that it doesn’t end up causing coal and natural gas plants to run more. But the final rules are less strict than the proposal. For example, the hourly matching requirement doesn’t apply until 2030, and existing nuclear plants count as new zero-emissions energy if they are considered to be at risk of retirement.
Finding a balance between limiting emissions and ensuring that the tax credit unlocks development of this entirely new industry was a monumental challenge. The Treasury Department received more than 30,000 comments on the proposed rule, compared to about 2,000 for the clean electricity tax credit, and just 89 for the electric vehicle tax credit. Senior administration officials told me this may have been the most complicated of all of the provisions in the IRA. In October, the department assured me that the rules would be finished by the end of the year.
Energy experts, environmental groups, and industry are still digesting the rule, and I’ll be looking out for future analyses of the department’s attempt at compromise. But initial reactions have been cautiously optimistic.
On the environmental side, Dan Esposito from the research nonprofit Energy Innovation told me his first impression was that the final rule was “a clear win for the climate” and illustrated “overwhelming, irrefutable evidence” in favor of the three pillars approach, though he did have concerns about a few specific elements that I’ll get to in a moment. Likewise, Conrad Schneider, the U.S. senior director at the Clean Air Task Force, told me that with the exception of a few caveats, “we want to give this final rule a thumbs up.”
Princeton University researcher Jesse Jenkins, a co-host of Heatmap’s Shift Key podcast and a vocal advocate for the three pillars approach, told me by email that, “Overall, Treasury’s final rules represent a reasonable compromise between competing priorities and will provide much-needed certainty and a solid foundation for the growth of a domestic clean hydrogen industry.”
On the industry side, the Fuel Cell and Hydrogen Energy Association put out a somewhat cryptic statement. CEO Frank Wolak applauded the administration for making “significant improvements” but warned that the rules were “still extremely complex” and contain several open-ended parts that will be subject to interpretation by the incoming Trump-Vance administration.
“This issuance of Final Rules closes a long chapter, and now the industry can look forward to conversations with the new Congress and new Administration regarding how federal tax and energy policy can most effectively advance the development of hydrogen in the U.S.,” Wolak said.
Constellation Energy, the country’s biggest supplier of nuclear power, was among the most vocal critics of the proposed rule and had threatened to sue the government if it did not create a pathway for hydrogen plants that are powered by existing nuclear plants to claim the credit. In response to the final rule, CEO and President Joe Dominguez said he was “pleased” that the Treasury changed course on this and that the final rule was “an important step in the right direction.”
The California governor’s office, which had criticized the proposed rule, was also swayed. “The final rules create the certainty needed for developers to invest in and build clean, renewable hydrogen production projects in states like California,” Dee Dee Myers, the director of the Governor’s Office of Business and Economic Development, said in a statement. The state has plans to build a $12.6 billion hub for producing and using clean hydrogen.
Part of the reason the Treasury needed to find a Goldilocks compromise that pleased as many stakeholders as possible was to protect the rule from future lawsuits and lobbying. But not everyone got what they wanted. For example, the energy developer NextEra, pushed the administration to get rid of the hourly matching provision, which though delayed remained essentially untouched. NextEra did not respond to a request for comment.
Companies that fall on the wrong side of the final rules may still decide to challenge them in court. The next Congress could also make revisions to the underlying tax code, or the incoming Trump administration could change the rules to perhaps make them more favorable to hydrogen made from fossil fuels. But all of this would take time — a rule change, for example, would trigger a whole new notice and comment process. Though the one thing I’ve heard over and over is that the industry wants certainty, which the final rule provides, it’s not yet clear whether that will outweigh any remaining gripes.
In the meantime, it's off to the races for the nascent clean hydrogen industry. Between having clarity on the tax credit, the Department of Energy’s $7 billion hydrogen hubs grant program, and additional federal grants to drive down the cost of clean hydrogen, companies now have numerous incentives to start building the hydrogen economy that has received much hype but has yet to prove its viability. The biggest question now is whether producers will find any buyers for their clean hydrogen.
Below is a more extensive accounting of where the Treasury landed in the final rules.
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What exactly happened to the “three pillars”?
On “deliverability,” or the requirement to procure clean energy from the same region, the rules are largely unchanged, although they do allow for some flexibility on regional boundaries.
As I explained above, the Treasury Department also kept the hourly matching requirement, but delayed it by two years until 2030 to give the market more time to set up systems to achieve it — a change Schneider said was “really disappointing” due to the potential emissions consequences. Until then, companies only have to match their operations with clean energy on an annual basis, which is a common practice today. The new deadline is strict, and those that start operations before 2030 will not be grandfathered in — that is, they’ll have to switch to hourly matching once that extended clock runs out. In spite of that, the final rules also ensure that producers won’t be penalized if they are not able to procure clean energy for every single hour their plant operates, an update several groups applauded.
On the requirement to procure clean power from newly built sources, also known as “incrementality,” the department made much bigger changes. It kept an overarching definition that “incremental” generators are those built within three years of the hydrogen plant coming into service, but added three major exceptions:
1. If the hydrogen facility buys power from an existing nuclear plant that’s at risk of retirement.
2. If the hydrogen facility is in a state that has both a robust clean electricity standard and a broad, binding, greenhouse gas cap, such as a cap and trade system. Currently, only California and Washington pass this test.
3. If the hydrogen facility buys power from an existing natural gas or coal plant that has added new carbon capture and storage capacity within three years of the hydrogen project coming into service.
What does this mean for nuclear plants?
The hydrogen tax credit is so lucrative that environmental groups and energy analysts were concerned it would drive companies like Constellation to start selling all their nuclear power to hydrogen plants instead of to regular energy consumers, which could drive up prices and induce more fossil fuel emissions.
The final rules try to limit this possibility by only allowing existing reactors that are at risk of retirement to qualify. But the definition of “at risk of retirement” is loose. It includes “merchant” nuclear power plants — those that sell at least half their power on the wholesale electricity market rather than to regulated utilities — as well as plants that have just a single reactor, which the rules note have lower or more uncertain revenue and higher operational costs. Looking at the Nuclear Energy Institute’s list of plants, merchant plants make up roughly 40% of the total. All of Constellation Energy’s plants are merchant plants.
There are additional tests — the plant has to have had average annual gross receipts of less than 4.375 cents per kilowatt hour for at least two calendar years between 2017 and 2021. It also has to obtain a minimum 10-year power purchase agreement with the hydrogen company. Beyond that, the reactors that meet this definition are limited to selling no more than 200 megawatts to hydrogen companies, which is roughly 20% for the average reactor.
Esposito, who has closely analyzed the potential emissions consequences of using existing nuclear plants to power hydrogen production, was not convinced by the safeguards. “I don't love the power price look back,” he told me, “because that's not especially indicative of the future — particularly this high load growth future that we're quickly approaching with data centers and everything. It’s very possible power prices could go up from that, and then all of a sudden, the nuclear plants would have been fine without hydrogen.”
As for the 200 megawatt cap, Esposito said it was better than nothing, but he feels “it's kind of an implicit admission that it's not really, truly clean” to produce hydrogen with the energy from these nuclear plants.
Schneider, on the other hand, said the safeguards for nuclear-powered hydrogen projects were adequate. While a lot of plants are theoretically eligible, not all of their electricity will be eligible, he said.
Are there concerns about the state policy exemption?
The rules assert that in states that meet the two criteria of a clean electricity standard and a binding cap on emissions, “any increased electricity load is highly unlikely to cause induced grid emissions.”
But in a paper published in February, Energy Innovation explored the potential consequences of this exemption in California. It found that hydrogen projects could have ripple effects on the cap and trade market, pushing up the state’s carbon price and triggering the release of extra carbon emission allowances. “In other words, the California program is more of a ‘soft’ cap than a binding one — the emissions budget ‘expands or contracts in response to price bounds set by the legislature and [California Air Resources Board],’” the report says.
Esposito thinks the exemption is a risk, but that it requires further analysis and he’s not sounding the alarm just yet. He said it could come down to other factors, including how economical hydrogen production in California ends up being.
What about hydrogen made from methane?
Producers are also eligible for the tax credit if they make hydrogen the conventional way, by “reforming” natural gas, but capture the emissions released in the process. For this pathway, the Treasury had to clarify several accounting questions.
First, there’s the question of how producers should account for methane leaked into the atmosphere upstream of the hydrogen plant, such as from wells and pipelines. The proposal had suggested using a national average of 0.9%. But researchers found this would wildly underestimate the true warming impact of hydrogen produced from natural gas. It could also underestimate emissions from natural gas producers that have taken steps to reduce methane leakage. “We branded that as one size fits none,” Schneider told me.
The final rules create a path for producers to use more accurate, project-specific methane emissions rates in the future once the Department of Energy updates a lifecycle emissions tool that companies have to use called the “GREET” model. The Environmental Protection Agency recently passed new methane emissions laws that will enable it to collect better data on leakage, which will help the DOE update the model.
Schneider said that’s a step in the right direction, though it will depend on how quickly the GREET model is updated. His bigger concern is if the Trump administration weakens or eliminates the EPA’s methane emissions regulations.
Can producers just buy renewable natural gas certificates?
The Treasury also opened up the potential for companies to produce hydrogen from alternative, cleaner sources of methane, like gas captured from wastewater, animal manure, and coal mines. (The original rule included a pathway for using gas captured from landfills.) In reality, hydrogen plants taking this approach are unlikely to use gas directly from these sources, but rather procure certificates that say they have “booked” this cleaner gas and can “claim” the environmental benefits.
Leading up to the final rule, some climate advocates were concerned that this system would give a boost to methane-based hydrogen production over electricity-based production, as it's cheaper to buy renewable natural gas certificates than it is to split water molecules. Existing markets for these credits also often overestimate their benefits — for example, California’s low carbon fuel system gives biogas captured from dairy farms a negative carbon intensity score, even though these projects don’t literally remove carbon from the atmosphere.
The Treasury tried to improve its emissions estimates for each of these alternative methane sources to make them more accurate, but negative carbon intensity scores are still possible.
The department did make one significant change here, however. It specified that companies can’t just buy a little bit of cleaner methane and then average it with regular fossil-based methane — each must be considered separately for determining tax credit eligibility. Jenkins, of Princeton, told me that without this rule, huge amounts of hydrogen made from regular natural gas could qualify.
Producers also won’t be able to take this “book and claim” approach until markets adapt to the Treasury’s reporting requirements, which isn’t expected until at least 2027.
