Treasury Finalizes Rules for Clean Hydrogen Production Tax Credit (Section 45V) | Foley Hoag LLP

Over a year since Treasury released proposed rules—after thousands of public comments and various hearings, think pieces, whitepapers, Op-Eds, and, yes, even TV commercials—on January 3, 2025, Treasury finalized rules for implementing the IRA’s Clean Hydrogen Production Tax Credit, otherwise known by its Tax Code designation, Section 45V. The hydrogen credit is meant, along with other federal policies, to jumpstart a still-nascent clean hydrogen industry in the United States. It gives lucrative tax credits—up to $3 per kilogram of hydrogen—to hydrogen producers whose processes significantly reduce lifecycle greenhouse gas (GHG) emissions. The credit goes hand-in-hand with $7 billion in additional federal funding the Department of Energy (DOE) is planning to award to seven regional hydrogen hubs per the 2021 Bipartisan Infrastructure Law (BIL) and another $1 billion DOE has allocated for demand-side hydrogen initiatives.

The hydrogen rules have drawn significant interest. Nearly 30,000 comments were submitted in response to Treasury’s proposed rules. The final rules tweak the proposed rules in several ways, but largely leave their overarching frameworks in place. Overall, the tweaks could make it easier for hydrogen producers across a range of technologies to comply with the rules. 

We still don’t know what, if anything, the incoming Trump administration might do with the rules (or federal hydrogen incentives generally). This alert analyzes possible ways the incoming administration may affect the rules, though we may not learn much more about the administration’s plans until after Trump takes office on January 20, 2025.

Key Takeaways:

• The rules keep the “three pillars” requirements for matching low-emitting electric power generation to hydrogen production—incrementality, temporal matching, and deliverability. But the rules relax the requirements in several ways: (1) they provide a pathway for existing nuclear plants to power hydrogen production; (2) they exempt from the incrementality requirement hydrogen producers sourcing clean energy in certain “Qualifying States” (for the moment, just California and Washington); (3) they extend the deadline from 2028 to 2030 for hourly matching of clean power generation to hydrogen production; and (4) they allow certain cross-regional deliveries of power to meet the deliverability requirement.
• The rules clarify key requirements for how lifecycle GHG emissions will be determined using the 45VH2-GREET model. While the model will continue to be updated (at least annually), hydrogen producers may choose to lock in an emissions rate for the 10-year duration of their credit calculated using the version of the model in effect when they begin construction of their hydrogen facility. The final rules also clarify that, once hourly matching begins in 2030, hydrogen producers can claim the credit for hydrogen produced during specific hours in which they can show matched low-emitting electric power, even if they cannot match electric power on an hourly basis at times when that power isn’t available. Importantly, however, the rules still require those producers to establish an annual emissions rate of no more than 4 kg CO2e per kg H2 for all hydrogen produced in the relevant taxable year.
• The rules establish pathways to produce creditable hydrogen from biogas, renewable natural gas (RNG), and fugitive methane. They do not adopt the “first productive use” requirement Treasury had initially proposed–meaning that facilities currently producing biogas, RNG, or fugitive methane for other purposes may switch to supplying producers of clean hydrogen. The rules also allow book-and-claim accounting for RNG and coal mine methane feedstocks, though not until at least 2027, to give time for credit registries to develop electronic tracking methods that comply with the rules. Until then, hydrogen producers using RNG or coal mine methane feedstocks will need to show exclusive, physical delivery of those feedstocks to their facilities.
• The Trump administration could seek to rescind or modify the rules, though it’s still too soon to tell what actions it might take. The administration would have a few options, each of which would implicate different procedural hurdles. Treasury under Trump could try to rescind or modify the rules, but the agency would likely need to engage in another notice-and-comment rulemaking process. The Congressional Review Act could also be used to invalidate the rules, though that would require majorities in the House and Senate, which could be difficult given the thin Republican Congressional majorities and bipartisan support for the hydrogen credit.

Hydrogen Tax Credit Basics

The Three Pillars

Incrementality

Temporal Matching

Deliverability

Lifecycle Emissions and 45VH2-GREET

RNG/Biogas/Fugitive Methane

Provisional Emissions Rate (PER) Process

Impacts of the Incoming Trump Administration

Conclusion
            
Hydrogen Tax Credit Basics
A detailed description of the hydrogen credit and the proposed rules is available in our previous publication. Below is a chart showing the credit amounts hydrogen producers may qualify for, provided they meet applicable requirements, including the prevailing wage and apprenticeship requirements. 

The credit expires on January 1, 2033. Before the expiration date, hydrogen producers can claim the credit for a 10-year period starting the year in which their hydrogen production facilities are placed in service. Unlike other IRA tax credits, which allow for elective pay only for certain tax-exempt and governmental entities, the hydrogen credit allows for elective pay (direct payments instead of a reduction in tax liability) for for-profit entities for the first five years of the 10-year credit period. This gives non-tax-exempt hydrogen producers another way to monetize the credit, in addition to tax credit transfer and tax equity transactions.

The Three Pillars
Perhaps no other feature of the rules has been more hotly debated than the so-called “three pillars.” The three pillars—incrementality, temporal matching, and deliverability—are requirements meant to link hydrogen production to specific sources of zero- or low-emitting electric power for purposes of determining lifecycle GHG emissions, and, thus, the applicable amount of the hydrogen credit. 

Under the rules, hydrogen producers must obtain and retire Energy Attribute Certificates (EACs), such as renewable energy certificates (RECs), that meet these three requirements in order to show that their hydrogen was produced using electricity from specific sources of clean power generation. All hydrogen producers seeking to establish a link between their processes and specific generators must acquire and retire EACs that meet these requirements, even if the generator is directly connected (behind-the-meter) to the hydrogen facility.

The three pillars are particularly important for electrolytic hydrogen, that is, hydrogen produced using electricity to split water into hydrogen and oxygen (otherwise known as “green” hydrogen, if the electric power comes from renewables, or “pink” hydrogen, if from nuclear). Electrolysis can be energy intensive. To meet emissions requirements, electrolytic hydrogen producers must rely on renewable energy or other zero- or low-emitting energy sources.

Incrementality
Incrementality refers to sourcing power from new clean power generators. The rules keep the proposed 36-month “lookback” period for incrementality. Hydrogen producers will need to obtain and retire EACs from clean power generators with commercial operations dates no more than 36 months before the hydrogen producer’s facility is placed in service. Treasury declined to adopt a longer lookback period, but it did add alternatives and exceptions to the incrementality requirement, as follows.

Nuclear Pathway. The 36-month lookback period, as initially proposed, would have largely prevented hydrogen producers from relying on existing nuclear power plants to claim the credit. The final rules now provide a pathway for certain “qualifying nuclear reactor[s]” even if those reactors began commercial operations outside the 36-month window:

• Qualifying nuclear reactors must be merchant facilities or single-unit plants (i.e., not co-located with another operating reactor). A merchant reactor is one that participates in a competitive electricity market and for which over 50 percent of the reactor and its electricity production does not receive “cost recovery through rate regulation or public ownership with related retail rate recovery.”
• Qualifying nuclear reactors must meet a “financial test” that “the average annual gross receipts (as defined under section 45U [the separate tax credit for nuclear power production]) of the reactor were less than 4.375 cents per kilowatt hour for any two of the calendar years from 2017 through 2021.”
• Qualifying nuclear reactors must either (A) be directly connected (behind-the-meter) to the hydrogen production facility; or (B) contract with the hydrogen production facility to acquire and retire EACs for a fixed term of at least 10 years, among other requirements.

Qualifying nuclear reactors are further limited to supplying only up to 200 MWh of electricity per operating hour per qualifying nuclear reactor. Additional power from those reactors is not considered incremental under the rules. The rules state that, for integrated reactors—that is, multiple qualifying nuclear reactors with integrated operations—the aggregate limit will equal 200 MWh per operating hour multiplied by the number of qualifying nuclear reactors.

The nuclear pathway addresses several concerns raised by commenters, including that it takes a long time to permit and build new nuclear plants to comply with the 36-month lookback period, and that many existing plants are at risk of retirement. Allowing existing plants to power creditable clean hydrogen production could extend their operations. Additionally, the BIL specifically requires that, to the maximum extent practicable, at least one Hydrogen Hub produce hydrogen from nuclear energy. The Mid-Atlantic Hub, for example, plans to rely on both renewable and nuclear power. This pathway could help support those plans.

Qualifying States. The final rules exempt from the incrementality requirement clean power generated in certain “Qualifying States.” Qualifying States must have two key characteristics: (1) a Qualifying Decarbonization Standard; and (2) a Qualifying GHG Cap Program. The rules set out several specific requirements for each. So far, Treasury has identified only two states that meet those requirements: California and Washington. Other states will not be considered “Qualifying States” until Treasury determines that they comply with the rules.

Hydrogen producers in California and Washington will need to meet other requirements, including those for temporal matching and deliverability. However, assuming they can do so, they should be able to source EACs from any clean power generator in California or Washington regardless of when the generator began commercial operations. This could include allowing hydrogen producers in both California and Washington to source power from Washington’s existing, abundant hydropower facilities. 

The exemption could spur other states to seek Qualifying State status, such as New York or Massachusetts. Those states have renewable portfolio standards. Both also participate in the Regional Greenhouse Gas Initiative, a regional power-sector cap-and-trade program in which 11 states participate. Massachusetts also has its own cap and allowance trading program for large fossil plants, and New York is in the process of developing a cap-and-invest program. Obtaining Qualifying State status could bolster clean hydrogen production in those states.

The Qualifying State framework does not offer a complete solution to some who were hoping for additional leniency on incrementality. Treasury had initially proposed an across-the-board exemption from incrementality for renewables, hydropower, and other zero- or low-emitting generators, equal to five percent of their hourly generation. This was intended to serve as a proxy for periods of curtailment, retirement risk, and other difficult-to-determine factors that might reduce the risk of induced grid emissions from hydrogen production. But no such exemption is included in the final rules. Nor do the rules offer a pathway specifically for hydropower facilities. Treasury determined that those facilities do not face the same retirement risks as nuclear plants. It also determined that hydropower producers could qualify in other ways: for instance, if they are located in Qualifying States, or if those facilities undergo an “uprate,” as described below.

Uprates. The final rules allow “uprates” at pre-existing facilities, provided the uprate occurs within the 36-month lookback period. The rules account for uprates in both nameplate and “specified” capacity, that is, “the actual productive capacity of the facility.” The rules include specific standards for determining uprates in “specified capacity.” 

The uprate rules also account for “restarted facilities.” Facilities that have been decommissioned or are in the process of decommissioning can be restarted to support clean hydrogen production and meet the incrementality requirement. Such facilities must be shutdown for at least one calendar year in which federal regulators did not permit them to operate and must meet other specified requirements.

Carbon Capture Retrofits. The rules also allow fossil power plants that install carbon capture equipment to meet the incrementality requirement, provided the carbon capture equipment is placed in service no more than 36 months before the hydrogen production facility is also placed in service. The retrofitted facility is considered incremental only if carbon is captured and disposed of in secure geological storage or utilized as prescribed under the separate carbon capture tax credit, Section 45Q.

Temporal Matching
Temporal matching refers to linking hydrogen production to times when clean power is being simultaneously generated. The rules provide for two matching regimes: annual and hourly. Annual matching allows hydrogen producers to obtain and retire EACs created in the same calendar year in which qualifying clean hydrogen was produced. Hourly matching is more granular. It requires matching power generation to hydrogen production on an hour-by-hour basis.

The rules allow for annual matching until January 1, 2030. After that, all hydrogen producers, regardless of when they began producing hydrogen, will need to switch to hourly matching. This extends the January 1, 2028 hourly matching deadline in the proposed rules by two years. Treasury declined to include any legacy or grandfathering rules for annual matching for first-moving hydrogen producers.

Hydrogen producers raised several concerns with hourly matching. Many plan to run electrolyzers 24 hours a day, but clean energy from wind or solar facilities may not be available during each of those hours: for instance, at night or when the wind isn’t blowing. In these circumstances, the proposed rules would have required hydrogen producers to calculate carbon intensity on an annualized basis, meaning that matched hours would be averaged with unmatched hours, thereby raising the carbon intensity of hydrogen production potentially to levels that would render it ineligible for the credit.

The rules address this specific issue by allowing hydrogen producers to determine emissions on an hourly basis, provided the producer elects to determine all emissions from the facility’s use of electricity for the taxable year on an hourly basis. This means that producers can claim the credit for hydrogen produced during matched hours. During unmatched hours, the rules require applying the “default electricity emissions intensity within the [relevant] regional electricity grid.” However, the rules impose an important condition: facilities that choose this option must still achieve an annual lifecycle emissions rate of no greater than 4 kg CO2e per kg H2, the upper limit of lifecycle emissions for qualifying clean hydrogen under Section 45V. Otherwise, according to Treasury, the hourly rule might encourage hydrogen production that does not meet Section 45V’s emissions requirements.

The rules will also allow hydrogen producers to use stored clean power to meet hourly matching requirements at times when clean power isn’t simultaneously being generated. The rules are clear, however, that the ability to rely on battery storage will require EAC registries to develop sufficient tracking mechanisms. The rules set out the following requirements:

• The power must be discharged from the storage system in the same hour that the taxpayer produces hydrogen.
• The storage system must be located in same region as the clean power generation facility and hydrogen production facility.
• The clean power generation facility, but not the storage system, must meet the incrementality requirements.
• EACs reflecting stored energy must be retired in a registry that sufficiently protects against double-counting, accounts for storage-related efficiency losses, and develops frameworks that address storage comprehensively and estimates the temporal profile of stored and discharged electricity, including when the storage system is charged by multiple generators.

The rules for temporal matching rely heavily on the independent development of credit registries that meet these and other requirements. But the rules do not mandate that registries establish such mechanisms. 

Deliverability
Deliverability, also known as “regionality,” requires hydrogen facilities to be located in the same region as the power generators they rely on. The rules for deliverability changed little between the proposed and final rules. Treasury is still relying on the October 30, 2023 DOE Transmission Needs Study to establish the regions for the deliverability requirement:

Source: DOE Transmission Needs Study, at iii (Oct. 2023)

The rules further clarify the deliverability requirement by adding a table of balancing authorities and the regions to which they belong. To meet the deliverability requirement, the power generation facility and the hydrogen producer must be interconnected to balancing authorities within the same region. 

The rules allow for cross-regional deliveries in certain circumstances. The electricity generator must have transmission rights from its location to the region where the hydrogen producer operates. The generation must be delivered to (scheduled and then dispatched and settled in) the hydrogen producer’s region and meet other tracking requirements. Imports from Mexico or Canada must also include a generator attestation that the attributes represented by its EACs aren’t being used for other purposes.

Lifecycle Emissions and 45VH2-GREET
Treasury fielded several comments about the model DOE released for hydrogen producers to use when determining their hydrogen’s lifecycle emissions for purposes of Section 45V, the 45VH2-GREET model. 45VH2-GREET is a variant of DOE’s research and development GREET model (GREET stands for Greenhouse gases, Regulated Emissions, and Energy use in Technologies). Commenters had questioned the need for a 45V-specific model. They pointed to Section 45V’s text, which refers to DOE’s R&D GREET model. Yet the rules keep 45VH2-GREET. According to Treasury, the R&D GREET model, while valuable in other settings, lacks the “degree of precision and certainty” necessary for purposes of the hydrogen tax credit.

The current 45VH2-GREET model contains eight pathways for producing hydrogen. The rules identify a forthcoming update to the model in January 2025, which as of this writing, has not yet been released. The eight modeled pathways for producing hydrogen are:

1. Steam methane reforming (SMR) of natural gas, with potential carbon capture and sequestration (CCS);
2. Autothermal reforming (ATR) of natural gas, with potential CCS;
3. SMR of landfill gas with potential CCS;
4. ATR of landfill gas with potential CCS;
5. Coal gasification with potential CCS;
6. Biomass gasification with corn stover and logging residue with no significant market value with potential CCS;
7. Low-temperature water electrolysis using electricity; and
8. High-temperature water electrolysis using electricity and potential heat from nuclear power plants.

Producers who use feedstocks or production processes that differ from the listed pathways cannot use 45VH2-GREET to determine their lifecycle emissions. They must instead request an individualized Provisional Emissions Rate (PER) via a separate process, addressed in more detail below. Pathways excluded from 45VH2-GREET include methane pyrolysis and extracting geologic hydrogen, among others.

The rules make other changes that producers may favor. For instance, the rules will allow producers to lock in an emissions rate for the 10-year duration of their credit based on the version of the 45VH2-GREET model in effect at the time they start construction. Because 45VH2-GREET will be periodically updated, producers were concerned that their hydrogen might qualify under one version of the model but not another, or qualify for different credit amounts year-to-year, making it difficult to predict what they’ll be able to claim in any given year. This change addresses that concern.

Other requested changes were not adopted in the final rules: for example, changes to the background assumption in 45VH2-GREET for upstream methane leakage. For hydrogen producers using natural gas feedstock, the model accounts for methane lost during the natural gas recovery process by assuming a methane leakage rate of 0.9 percent of methane consumed by the hydrogen producer, which increases modeled emissions. This assumption is fixed. It cannot be altered in 45VH2-GREET or by use of the PER process. Commenters asked Treasury for more flexibility to establish their own methane leakage rates based on actual data. Treasury rejected that approach, opting instead to rely on future methane leakage data collected in EPA’s Greenhouse Gas Monitoring Program.

DOE will update the model once EPA’s data is available. Treasury states that such an update should allow taxpayers to use a differentiated upstream methane rate based on data from “all relevant parts of” EPA’s program “for all facilities in the taxpayer’s natural gas supply chain that are required to report.” For facilities that are not required to report, Treasury says the model will prescribe “default segment-specific emissions rates,” developed by DOE and EPA. However, if EPA’s monitoring program is changed to become less stringent or is rescinded, Treasury expects that upstream methane emissions rates would need to remain as unalterable background data in the model.

Many commenters also requested that updates to 45VH2-GREET be subject to public comment, similar to proposed regulations. Treasury explained that that the request was outside the scope of the rules, which are limited to Treasury’s designation of the 45VH2-GREET as the operative lifecycle emissions model for purposes of the credit. It’s incumbent on DOE to determine the best way to address comments about future updates to 45VH2-GREET.

RNG/Biogas/Fugitive Methane
Treasury’s December 2023 proposed rules addressed only one modeled biogas-to-hydrogen pathway: landfill gas with a direct physical connection to a hydrogen production facility. Treasury did not propose rules for other biogas or RNG sources or for “fugitive methane” (methane leaked or vented during fossil fuel extraction and production activities). Instead, it solicited comments on a range of topics regarding how the hydrogen credit should apply to those feedstocks. As a result, the rules establish a range of biogas, RNG, and fugitive methane pathways, collectively referred to by Treasury as “natural gas alternatives.”

First Productive Use
The rules do not include a “first productive use” requirement, as Treasury had initially proposed. This means that preexisting facilities collecting biogas or fugitive methane for other productive uses can switch to supplying hydrogen producers. 

Alternative Fates
In lieu of a first productive use requirement, the rules instead look to the alternative uses, or “alternative fates,” of the natural gas alternatives when calculating their lifecycle emissions. Treasury analyzed each feedstock to determine its individualized “alternative fate” lifecycle emission baseline:

Importantly, the alternative fates of these feedstocks will not solely determine the carbon intensity of hydrogen for purposes of the credit. For example, they do not account for emissions associated with other processes, such as upgrading, transporting, or compressing biogas to convert it to RNG. However, the baselines do signal that biogas and coal mine methane sources will receive more favorable treatment in terms of lifecycle emissions compared to fossil feedstocks, such as natural gas. Relying on those sources in lieu of natural gas in processes such as SMR or ATR with carbon capture or methane pyrolysis could reduce emissions rates for crediting purposes. Animal waste biogas feedstocks are the only feedstocks with a negative emissions baseline. 
    
Treasury expects that pathways relying on these natural gas alternatives will be added to 45VH2-GREET this year.

Book-and-Claim Accounting
For RNG and coal mine methane, the rules will allow for book-and-claim accounting, but not until January 1, 2027, at least, to give crediting registries time to develop and adapt to electronic attribute tracking requirements in the rules. The rules introduce the term “gas EACs” to refer to the tradeable attribute certificates hydrogen producers can use to account for RNG and coal mine methane feedstocks used in their production processes.

Regarding the delayed implementation date, Treasury explains that existing registries and book-and-claim accounting methods, such as those for the federal Renewable Fuel Standard and California’s Low Carbon Fuel Standard, are insufficient. 

Book-and-claim accounting won’t begin automatically on January 1, 2027. The rules state that Treasury must determine whether one or more electronic tracking systems meet the applicable requirements on or after that date. Until Treasury makes such a determination, RNG and coal mine methane must be delivered via a direct physical connection to the hydrogen production facility, such as by dedicated pipeline or other physical means of “exclusive” delivery.

Deliverability and Temporal Matching
The rules adopt other requirements for gas EACs. They impose a deliverability requirement. Hydrogen producers in the contiguous United States must obtain and retire gas EACs for gas injected in and withdrawn from pipeline networks in the contiguous United States. Alaska, Hawaii, and the U.S. Territories are treated as separate regions. The rules also require monthly matching. Gas EACs must be time-stamped such that the calendar month of pipeline injection is the same as the calendar month when gas is used to produce hydrogen.

Provisional Emissions Rate (PER) Process
Hydrogen producers planning on using feedstocks and/or production processes that differ from those modeled in 45VH2-GREET must obtain an individualized PER before they can claim the credit. The first step in that process is to obtain an individualized emissions rate from DOE. That DOE process opened in September 2024. We wrote about it in detail here. The rules make few changes to the PER process, though they do clarify a handful of important points.

First, the PER process is available only to taxpayers whose feedstocks and/or production pathways differ from the 45VH2-GREET pathways. Taxpayers using the pathways in 45VH2-GREET cannot use the PER process to obtain a different or more favorable emissions rate. In particular, the PER process cannot be used to obtain an individualized upstream methane leakage rate, different from the fixed 0.9 percent leakage rate assumption discussed above.

Second, Treasury stated explicitly that the PER process applies to geologic hydrogen production. Treasury stated that “newer methods of hydrogen production, such as geologic hydrogen, [are] subject to technical uncertainty,” and that DOE will address those “uncertainties by engaging with applicants during the” emissions rate determination process “and through independent research.” Geologic hydrogen producers, as well as other hydrogen producers using new and innovative technologies and seeking a PER, should be ready to engage with DOE in this process.

Third, Treasury reiterated and clarified certain procedural requirements for obtaining a PER. To request an emissions rate from DOE, applicants must first perform a Class 3 FEED Study or provide similar indication of project maturity. DOE is currently only accepting applications for which a Class 3 FEED Study has been performed. There will be no appeals process for DOE’s emissions rate determinations. DOE also has not developed a method for applicants to unilaterally revise or supplement their application. The rules will allow applicants to reapply if they wish to seek a new emissions value based on new or updated information. PER applicants should be as thorough as possible in their initial applications to avoid the need to redo the process to account for more comprehensive technical data.

Finally, the rules do not impose a time limit on DOE to make emissions rate determinations. DOE expects to give additional details on expected timelines as it continues processing applications.

Impacts of the Incoming Trump Administration
Many are wondering about the fate of these rules under the incoming Trump administration. Although Trump’s team has signaled an intent to roll back many of the Biden administration’s clean energy policies, the incoming administration has offered few details regarding its plans for hydrogen. 

Many factors will bear on how the administration addresses the hydrogen incentives. Unlike other low carbon technologies, hydrogen has garnered support across a range of industries, from cleantech to nuclear to oil and gas. DOE selected regional Hydrogen Hubs that include projects in several red states and swing states. Hydrogen projects planned outside the Hubs are proposed to be located in red states as well. Those factors could influence how the administration addresses the hydrogen incentives, and these rules in particular. 

If the Trump administration seeks to overturn or modify the rules, it would have a handful of options. A Trump-run Treasury could modify or rescind the rules, but doing so would likely require another notice-and-comment process. This means issuing another proposal, engaging in another comment period, and finalizing another set of rules or a rescission of the previous rules. The process would be time-consuming and burdensome, and would likely draw significant scrutiny from stakeholders. 

The rules could also be invalidated under the Congressional Review Act, however, this would require majority votes in both Houses of Congress where Republicans have only thin majorities. 

Conclusion
Early reporting on the rules suggests that stakeholders across a range of industries and interest groups got some things they wanted in the final rules and others they didn’t. Statements by many companies, nonprofits, and other stakeholders express varying degrees of support for the rules, while identifying provisions they continue to disagree with. Few, if any, have suggested that Treasury should go back to the drawing board.

The release of the rules comes at a critical juncture. Stakeholders and, in particular, hydrogen producers will need to decide if they can live with these rules. Getting to this point took years. Any changes, modifications, or rescissions could extend the period of uncertainty regarding how the hydrogen credit applies. There are also potentially other ways that stakeholders can influence the implementation of the rules, short of regulatory changes, for instance, as DOE continues updating the 45VH2-GREET model, or through the PER process for innovative hydrogen technologies.

The Trump administration could throw a wrench in the gears. But hydrogen hasn’t been prominent among the incoming administration’s stated priorities. Its relatively lower profile and broad industry support could mean that the rules remain. It’s still too soon to tell what, if any, action the next administration might take regarding the rules. We’ll be watching closely for developments. As always, please reach out with any questions regarding how the rules might apply to your specific operations.