Newly Issued Final Regulations for Clean Hydrogen: Key Takeaways

By Carl F. Staiger, with specific insights from James O'Toole, Heather Hurst, Candace Quinn, Alan Seltzer, John Povilaitis, and Sean Moran

On January 3, 2025, the Treasury Department and Internal Revenue Service (IRS) issued final regulations regarding the clean hydrogen production credit (PTC) under §45V of the Internal Revenue Code (IRC), added by the Inflation Reduction Act (IRA), and the election to treat clean hydrogen production facilities as energy property for purposes of the IRC §48 investment tax credit (ITC). In addition, the Department of Energy (DOE) intends to release a new version of the 45VH2-GREET model and accompanying user manual to assess lifecycle greenhouse gas emissions associated with the production of hydrogen.

Although various concerns raised in the approximately 30,000 comments submitted in response to the proposed regulations issued in December of 2023 were not addressed, the Treasury and IRS have, by the final regulations, made important modifications intended to provide flexibility in certain key areas. Notably, the final regulations provide additional rules by which electricity produced from certain pre-existing nuclear facilities can satisfy the incrementality rules.  

Summary of Credit

Calculation of the PTC

Under IRC §45V, the PTC for any taxable year is an amount equal to the product of:

• The kilograms of “qualified clean hydrogen” produced by the taxpayer after 2022 at a “qualified clean hydrogen production facility” during the 10-year period beginning on the date such facility was “originally placed in service,” and
• A “base credit rate” of up to $0.60 per kilogram or a “full credit rate” of up to $3.00 per kilogram if certain prevailing wage and apprenticeship requirements are satisfied. The “base credit rate” or “full credit rate,” as applicable, gradually increases as the lifecycle greenhouse gas (GHG) emission rate attributable to the production pathway decreases, within four separate tiers, as follows:

Qualified Clean Hydrogen

Under IRC §45V, “qualified clean hydrogen” is produced through a process that results in a lifecycle GHG emissions rate of not greater than 4 kilograms of CO2e per kilogram of hydrogen, and such hydrogen is:

• Produced (i) in the United or a United States territory, (ii) in the ordinary course of a trade or business of the taxpayer, and (iii) for sale or use; and
•  An unrelated party verifies the production and sale or use of such hydrogen.

IRC §45V expressly provides that “lifecycle greenhouse gas emissions” include emissions only through the point of production (“Well-to-Gate”) as determined by the “most recent GREET Model” developed by Argonne National Laboratory “or a successor model (as determined by the Secretary).”

Coordination with IRC §45Q

No PTC credit is allowed with respect to any qualified clean hydrogen produced at a facility that includes carbon capture equipment for which a credit is allowed to any taxpayer as determined under IRC §45Q (Carbon Oxide Sequestration Credit) for the taxable year or any prior taxable year.

Election to Treat Clean Hydrogen Production Facilities as Energy Property under IRC §48

IRC §48(a)(15) provides that in the case of any qualified property that is part of a specified clean hydrogen production facility, such property is treated as “energy property,” and a taxpayer may make an irrevocable election to claim the ITC under IRC §48 with respect to such property. IRC §48(a)(15)(A)(ii) provides that the energy percentage for a facility that is designed and reasonably expected to produce qualified clean hydrogen with a lifecycle GHG emissions rate that is within the four tiers (described above), is 1.2%, 1.5%, 2% and 6% respectively. Note: The election is irrevocable and is in lieu of any production credit under §45V and §45Q relative to the energy property (i.e., clean hydrogen production facility) for which an election is made.

Final Regulations - Key Takeaways

Below is a high-level summary of certain key provisions in the final regulations.

1. Qualified “Facility”

• Included Equipment. The final regulations maintain that a qualified “facility” is a single production line used to produce qualified clean hydrogen, including all property components that function interdependently to produce qualified clean hydrogen. However, to ease the determination of what equipment is included, the definition of “single production line” is modified to include all components that function interdependently “through a process that results in the lifecycle GHG emissions rate used to determine the credit.” This phrase is intended to clarify that all equipment used to produce the qualified clean hydrogen for which the §45V credit is determined, including carbon capture equipment contributing to the lifecycle GHG emissions rate of the process by which the hydrogen for which the credit is determined, is included as part of the facility.   
• Electrolyzers. If there are multiple electrolyzers within the “balance of a plant,” the final regulations clarify that, to the extent each electrolyzer produces qualified clean hydrogen separately from the other electrolyzers (i.e., it does not function interdependently with the other electrolyzers), each such electrolyzer is treated as a separate facility.
• Feedstock Production Equipment. The IRS and Treasury state that the intent of the proposed regulations was to exclude upstream feedstock production and recovery equipment, such as renewable natural gas (RNG) production equipment, from the definition of facility. Accordingly, the final regulations add “feedstock-related equipment, including production, purification, recovery, transportation, or transmission equipment” to the list of items expressly excluded from the definition of facility.

2. Most Recent GREET Model  

• 45VH2-GREET v. R&D GREET. Consistent with the proposed regulations, the final regulations adopt the 45VH2-GREET model as the “most recent GREET model” to determine lifecycle GHG emissions attributable to each process for producing hydrogen. The IRS and Treasury recognize the existence of the R&D GREET Model, but point out that such model does not provide the degree of certainty, structure, and specificity necessary to meet the statutory requirement of reflecting lifecycle GHG emissions as defined by section 211(o)(1)(H) of the Clean Air Act (as in effect on August 16, 2022), nor does it meet the specific objectives of §45V or the Clean Air Act.
• Beginning of Construction Safe Harbor. The final regulations permit a taxpayer, in its discretion, to make an irrevocable election effective for the remaining taxable years within the 10-year eligibility period under §45V(a)(1), to treat the latest version of 45VH2-GREET that was publicly available on the date when construction of the qualified clean hydrogen facility began as the applicable version of the 45VH2-GREET Model.

3. Provisional Emissions Rate (PER) Process

• Limitation on Use of PER Process; Background Data.  The proposed regulations provided that if the feedstock and production technology are already represented in the 45VH2-GREET model, the taxpayer cannot use the PER process. The 45VH2-GREET model includes fixed assumptions called "background data" (which users cannot change) to calculate the emissions intensity of the project (and thus the eligibility for the PTC). These background data inputs include upstream methane leakage for natural gas and other feedstock supply. With this in mind, numerous comments requested that taxpayers be allowed to file a PER petition after challenging background data inputs through the Emissions Value Request Process (EVRP) because using actual values would likely result in a lower and more accurate emissions rate.  Nonetheless, the final regulations do not allow taxpayers to avail themselves of the PER petition process if their hydrogen production pathway (which consists of the combination of production technology and input feedstock materials and sources) is included in the 45VH2-GREET model, regardless of any disagreement with the background assumptions.

Insight: In 2026, operators of applicable natural gas supply chain facilities are required to begin reporting annually their methane emissions occurring during the prior calendar year to the Environmental Protection Agency (EPA) pursuant to the EPA’s Greenhouse Gas Reporting Program (GHGRP) and Subpart W of the EPA’s Methane Emissions Reduction Program (MERP) under Section 136 of the Clean Air Act. Once GHGRP and MERP data is available, the DOE is anticipated to update the 45VH2-GREET model to allow differentiated methane emissions rate reporting. Until such time, however, the DOE has advised the Treasury Department and the IRS that it anticipates keeping the national average upstream methane emissions rate in the 45VH2-GREET model consistent with the value used in the initial 2023 release of the model.

• PER Petition. To scale back the amount of information necessary to attach with the PER Petition, the final regulations modify the filing requirements by stating that a PER petition must only contain (i) the letter received from the DOE stating the emissions value the DOE determined with respect to the facility’s hydrogen production pathway, and (ii) the DOE control number assigned to the emissions value request of the taxpayer.
• EVRP; Class 3 FEED Study. The DOE opened the EVRP to the public on September 30, 2024. Proposed regulations provide that an applicant may request an emissions value from the DOE only after a front-end engineering and design (FEED) study or similar indication of project maturity, such as project specification and cost estimation sufficient to inform a final investment decision, has been completed for the hydrogen production facility. Comments to the regulations questioned the FEED study requirement and suggested various alternatives.  Nonetheless, the final regulations retain the FEED study requirement. However, they clarify that a taxpayer only needs a Class 3 Feed study (typically less detailed or time-consuming than a Class 1 or 2 FEED study) or a similar indication of project maturity to apply.

4. Energy Attribute Certificates (EACs)

• Required Use of EACs. The final regulations adopt the EAC framework set forth in the proposed regulations to prevent double counting the energy and emissions attributes represented by EACs and mitigate the risk of significant indirect emissions. Accordingly, when a taxpayer determines the lifecycle GHG emissions rate for hydrogen produced at a hydrogen production facility, such facility’s use of electricity may only be treated as sourced from a specific electricity generating facility rather than from the regional electricity grid if the taxpayer acquires and retires a qualifying EAC for each unit of electricity that the taxpayer claims from such source.  Such requirements must be met regardless of whether the electricity-generating facility giving rise to the qualifying EAC is grid-connected, directly connected, or co-located with the hydrogen production facility (that is, regardless of whether the underlying source of the qualifying EAC physically supplies electricity through a direct connection to the hydrogen production facility).
• Three Pillars are Retained. The final regulations retain the qualifying EAC requirements for incrementality, temporal matching, and deliverability (known as the “three pillars”), subject to certain modifications (summarized below) intended to provide additional flexibility.

5. Incrementality

• 36 Month COD Lookback Rule. The final regulations retain the general rule that an EAC meets the incrementality requirement if the electricity generating facility that produced the unit of electricity to which the EAC relates has a commercial operations date (COD) that is no more than 36 months before the facility for which the EAC is retired was placed in service.
• Uprates. The final regulations similarly retain the alternative rule that an EAC meets the incrementality requirement for electricity generating facilities that undergo an uprate no more than 36 months before the facility for which the EAC is retired was placed in service and such electricity is part of the facility’s “uprated production”, subject to requirements that the facility’s production be prorated to each hour or year (as applicable) for matching purposes.   
• Additional Pathways to satisfy Incrementality.  The final regulations adopt the following additional ways to satisfy the incrementality requirement:

CCS Retrofit Rule:  the electricity represented by the EAC is produced by an electricity generating facility that uses carbon capture and sequestration (CCS) technology and the carbon capture equipment has a placed in service date that is no more than 36 months before the hydrogen production facility for which the EAC is retired was placed in service (CCS retrofit rule).

Qualifying State: the electricity represented by an EAC is produced by an electricity generating facility that is physically located in a qualifying state and the hydrogen production facility is also located in a qualifying State.  A “Qualifying State” means as a State such as California which, as determined by the IRS, has under its State law or regulations, a “qualifying electricity decarbonization standard” and a “qualifying GHG cap program”, as both terms are defined in the regulations. 

Qualifying Nuclear Reactors: the electricity represented by the EAC is produced by an electricity generating facility that is a “Qualifying Nuclear Reactor”, which generally speaking, means a nuclear reactor which is at risk of retirement. For purposes of this rule, only up to 200 megawatt hours (MWh) of electricity per operating hour per qualifying nuclear reactor may be considered incremental, subject to an integrated operations rule, which offers additional flexibility by providing an aggregate limit of 200 MWh per hour multiplied by the number of integrated nuclear reactors that have not permanently ceased operations.  A “qualifying nuclear reactor” means a nuclear reactor: (i) that is a “merchant nuclear reactor” (i.e., a reactor that competes in a competitive market through the sale of energy and for which more than 50% of the reactor and its electricity production do not receive cost recovery via rate regulation or public ownership) or a nuclear reactor that is not co-located with any other operating nuclear reactor (i.e., a single unit plant); (ii) for which average annual gross receipts within the meaning of IRC §45U(b)(2)(A)(ii)(I)¹ for any two of the calendar years 2017 through 2021 are less than 4.375 cents per kilowatt hour, as determined with respect to any one owner of the reactor; and (iii) either (A) has a behind-the-meter physical electric connection with the hydrogen production facility that acquires and retires the EAC or (B) is the subject of a written binding contract, for a fixed term of at least 10 years beginning on the first date on which qualified EAC are acquired, under which the owner of the hydrogen production facility agrees to acquire and retire EACs from the nuclear reactor, and which manages the qualifying nuclear reactor’s risk of price changes with respect to EACs or electricity.

Insight: The requirements that the facility either have a “behind the meter connection” with a hydrogen production facility or be subject to a “binding written agreement” with a hydrogen production facility is intended to demonstrate that the hydrogen production facility is materially contributing to the continued operation of the at-risk nuclear reactor over the long term.

• Modifications regarding Uprates.

Uprate Definition: the final regulations modify the definition of “uprate” to mean an increase in an electricity generating facility’s rated nameplate capacity (in nameplate megawatts) or its capacity measured by a standard other than nameplate capacity, referred to as “specified capacity”. Similarly, the definitions of “pre-uprate capacity” and “post-uprate capacity” are modified to include specified capacity.

Restarted Electric Generation Facilities. Taking into account comments speaking to decommissioned and restarted nuclear facilities, the final regulations addReg. §1.45V-4(d)(3)(i)(B)(2), providing that an existing facility that is decommissioned or in the process of decommissioning and restarts can be considered to have increased nameplate or specified capacity from a base of zero if: (i) the facility has ceased operations; (ii) the facility has been shut down for a period of at least one calendar year during which it was not authorized to operate by its respective Federal regulatory authority (that is, the Federal Energy Regulatory Commission (FERC) or the Nuclear Regulatory Commission (NRC); (iii) the increased capacity of the restarted facility must be eligible to restart based on an operating license issued by either FERC or NRC; and (iv) the existing facility has not ceased operations for the purpose of qualifying for the special rule for restarted facilities.

Insight: The IRS observed that unless a restarted electricity generation facility has a new COD, the incrementality requirement would not be satisfied, as the facility that produced the unit of electricity to which the EAC relates would have a COD more than 36 months before the hydrogen production facility for which the EAC is retired was placed in service.

6. Temporal Matching

•  The final regulations adopt the hourly matching requirement set forth in the proposed regulations, but extend the transitional rule permitting annual matching by 2 years from January 1, 2028 until January 1, 2030. Accordingly, annual matching will be required through 2029 and hourly matching will be required thereafter.

7. Deliverability (aka “geographic matching”)

• General Framework – Regional Boundaries. The proposed regulations would provide that an EAC meets the deliverability requirement if the electricity represented by the EAC is generated by a facility that is in the same grid region as the hydrogen production facility. The final regulations general framework for drawing the regional boundaries, but clarify the regions by adding a table of balancing authorities and their corresponding regions, which shall be the definitive source for identifying the regions. The regulations further clarify that the electricity generating source and the hydrogen production facility are located in the same region if they are both electrically interconnected to a balancing authority (or balancing authorities) that is located in the same region, as identified in the table.
• Changes to Geographic Regions. To allow for reasonable changes to geographic regions, the Treasury Department and the IRS, in consultation with the DOE, intend to revise the regions in future safe harbor administrative guidance published in the Internal Revenue Bulletin. Updates to geographic regions are expected to occur at most once each year, and likely less frequently.   If, in the future the Treasury Department and the IRS publish a revised table as a safe harbor in the Internal Revenue Bulletin, a clean hydrogen producer would be able to instead employ such regions prospectively, subject to requirements that may be contained in such guidance.
• Cross Regional Delivery.  The final regulations allow an eligible EAC to meet the deliverability requirement in certain instances of actual cross-region delivery where the deliverability of such generation can be tracked and verified, subject to the following 3 requirements:

First, such EACs will only qualify if the underlying electricity generation has transmission rights from the generator location to the region of the clean hydrogen producer and that generation is delivered to (that is, scheduled and then dispatched and settled in) such producer’s region. Such electricity delivery must be demonstrated on an hour-to-hour or more frequent basis, with no direct counterbalancing reverse transactions, and must be verified with NERC E-tags or the equivalent.

Second, tracking of transmission rights and electricity delivery must occur via the relevant EAC registry; if the relevant EAC registry lacks this capability, such cross-region transactions are not allowed.

Third, imports from Canada and Mexico must additionally include an attestation from the generator that the attributes included in the eligible EACs are not being used for any other purpose, with that attestation included as an attachment to the verification report submitted with the taxpayer’s return.

8. Use of Biogas, RNG and fugitive sources of methane (aka “Natural Gas Alternatives”)

• General Framework. The final regulations adopt a general framework by which the assessment of lifecycle GHG emissions with respect to methane derived from natural gas alternatives such as biogas, RNG and fugitive sources of methane such as coal mine methane (CMM) used in the process of producing hydrogen takes into account not only the assessment of direct and indirect emissions attributable to the production process, but also consideration of the “alternative fate” for a particular natural gas alternative.  See discussion above regarding the most recent GREET model, updates to such model based upon GHGRP data.
• Alternative Fate. The term “Alternative Fate” means a set of informed assumptions (for example, production processes, material outcomes, and market-mediated effects) used to estimate the emissions from the use or disposal of each feedstock were it not for the feedstock’s new use due to the implementation of policy (that is, to produce hydrogen). Rather than provide rules that would specify a single, generic alternative fate for all natural gas alternatives (for example, capture and flaring), the final regulations address different considerations for each major source of natural gas alternatives.  The final regulations clarify that alternative fates would include avoided emissions and alternative productive uses of that methane; the risk that the availability of tax credits creates incentives resulting in the production of additional methane or otherwise induces additional emissions; and observable trends and anticipated changes in waste management and disposal practices over time as they are applicable to methane generation and uses.
• First Production Use Requirement Not Adopted. The IRS and Treasury stated in the proposed regulations that they intended to require that, for natural gas alternatives to receive an emissions value consistent with that gas (and not fossil natural gas), the natural gas alternative used during the hydrogen production process must originate from the first productive use of the relevant methane, known as the “first productive use” requirement. After consideration of numerous comments, the final regulations do not impose the first productive use requirement.
• Certain Waste Streams. The final regulations specifically address the alternative fate considerations for methane from landfill sources, wastewater, coal mine methane, animal waste sources, and fugitive methane other than CMM.
• Use of Gas EACs – RNG and Coal Mine Methane. Similar to the requirements applicable to electricity production facilities, the final regulations provide that if a taxpayer determines a lifecycle GHG emissions rate for hydrogen produced at a hydrogen production facility using the 45VH2-GREET model or the taxpayer obtains a PER, then the taxpayer may treat such hydrogen production facility’s use of RNG or coal mine methane as being from a specific source of such gas rather than fossil natural gas only if the taxpayer acquires and retires “qualifying gas EACs” for each unit of such gas that the taxpayer claims from such source. The final regulations set forth detailed requirements in order for a Gas EAC to be a qualifying gas EAC.

9. Changing the Placed-in-Service Date for an Existing Facility that is Modified or Retrofitted

• Modification to Produce Hydrogen – General Rule. IRC §45V(d)(4) provides that in the case of any facility that was originally placed in service before January 1, 2023 which did not produce qualified clean hydrogen, but after December 31, 2022 (i) is modified to produce qualified clean hydrogen, and (ii) amounts paid or incurred with respect to the modification are properly chargeable to the taxpayer’s capital account, such facility will be deemed to have been originally placed in service as of the date the property required to complete the modification is placed in service.  As noted below, a facility that satisfies these requirements is not also required to satisfy the 80/20 rule in order to obtain a new placed in service date.
• Changing Feedstock Inputs; Feedstock Production Equipment. Changing fuel inputs, without more, would not satisfy this statutory requirement. However, the final regulations clarify that, to the extent new components are installed in the hydrogen production facility in order to enable the facility to consume a different type of fuel that would enable the facility to produce qualified clean hydrogen, and to the extent such components are chargeable to the capital account of the taxpayer, then the installation of such new components would qualify as a modification for these purposes.  The final regulations also clarify that feedstock production equipment is not part of the facility for these purposes.
• Retrofit of Existing Facility (80/20 Rule). Consistent with the proposed regulations, the final regulations provide that an existing facility may establish a new date on which it is considered originally placed in service for purposes of §45V, even though the facility contains some used property, provided the fair market value of the used property is not more than 20 percent of the facility’s total value (i.e., the cost of the new property plus the value of the used property), known as the “80/20 Rule”. However, the regulations clarify that a facility that satisfies the requirements of for a modification under §45V(d)(4) does not also need to meet the 80/20 Rule in order to be deemed to be originally placed in service as of the date that the property required for the modification is placed in service. In addition, the final regulations clarify that 80/20 Rule applies separately to each single production line containing used property.

The final regulations, which consist of almost 400 pages of detailed information, offer long-awaited guidance to taxpayers seeking to qualify for the §45V credit. The attorneys at Buchanan Ingersoll & Rooney PC are uniquely positioned to assist clients, including investors and/or developers of hydrogen projects, in examining these detailed rules.