Treasury issues final section 45V clean hydrogen production credit rules

Effective Date: These Final Regulations are generally effective for taxable years beginning after December 26, 2023. For earlier taxable years, these regulations generally allow taxpayers to elect to apply the Proposed Regulations or the Final Regulations, as long as the rules applied are followed consistently.

Background:  Internal Revenue Code section 45V (Section 45V) provides a tax credit of up to $3 per kg (indexed to inflation) of clean hydrogen produced at a qualified clean hydrogen production facility for 10 years beginning on the date such facility is/was placed in service.  A qualified facility is one owned by the taxpayer and located in the U.S. (or U.S. possession), the construction of which begins before January 1, 2033. Internal Revenue Code section 48(a)(15) also allows a taxpayer who places such a facility in service to elect, in lieu of claiming any 45V credits for hydrogen production from such facility, to claim a one-time investment tax credit (at a base level of up to 30% of the basis) for the year it is placed in service.

The highest level 45V credit ($3/kg H2) is available (for taxpayers also meeting prevailing wage, apprenticeship requirements for the facility) only for hydrogen produced through a process with a lifecycle greenhouse gas (GHG) emissions rate of less than 0.45kg of CO2e per kg of hydrogen.  Lower credit levels ($1, $0.75 or $0.60) are available for production with higher lifecycle GHG rates of 0.45kg or higher, up to (and not to exceed) 4 kg CO2e/kg H2.

The lifecycle GHG emissions rate for any H2 production process is determined under the most recent Greenhouse gases, Regulated Emissions, and Energy use in Technology model (“GREET model”) developed by the U.S. Department of Energy’s Argonne National Laboratory, or a successor model.  In conjunction with Treasury’s issuance of proposed 45V regulations, the Department of Energy released a new lifecycle GHG emissions model (“45VH2 GREET 2023”) specifically tailored for use with the section 45V tax credit. For hydrogen production for which an emissions rate has not been determined under this model, a taxpayer can file a petition with the Treasury for a provisional emissions rate (PER).

The Final Regulations provide rules for determining emissions rates resulting from hydrogen production processes including those using electricity from various sources, natural gas with carbon capture, renewable natural gas (RNG), and coal mine methane to determine eligibility for the credit; petitioning for provisional emissions rates; verifying production and sale or use of clean hydrogen; modifying or retrofitting existing qualified clean hydrogen production facilities; and electing to treat a specified clean hydrogen production facility instead as property eligible for the section 48 energy credit.

The following provides highlights of key updates in the Final Regulations:

Electrolytic hydrogen. For hydrogen production using zero carbon electricity (including nuclear) the Final Regulations maintain the requirement that taxpayers seeking to use Energy Attribute Certificates (EACs) to attribute electricity use to a specific generator meet certain criteria for temporal matching, deliverability, and incrementality.

However, the final rules differ from the proposed in several respects:

• New clean power (incrementality): As in the proposed rules, the final rules define electricity generation as incremental if the generator begins commercial operations within 36 months of the hydrogen facility being placed in service, or to the extent a plant increases its capacity within that period. The final rules provide additional pathways for demonstrating incrementality, including:
  
  • Nuclear retirement risk. Electricity produced by nuclear plants meeting certain bright-line indications of being at risk of retirement and certain indications of co-dependence on hydrogen investment will be considered incremental, up to 200 MW per qualifying reactor. 
  
  
  • State policies. Electricity generated in states with “robust GHG emissions caps” paired with clean electricity standards or renewable portfolio standards meeting the criteria set forth in the final rules will be considered incremental. Treasury has determined that only the standards of the states of Washington and California currently meet these criteria. 
  
  
  • New Carbon Capture and Sequestration (CCS). Electricity from a generator that has added CCS within a 36-month window before the hydrogen facility is placed in service will be considered incremental. 
  
  
• Temporal matching: The final rules extend the transition allowing annual matching of EACs through the end of 2029 with hourly matching required starting in 2030 for all facilities. 
• Deliverability: The final rules confirm that electricity generated by a facility in the same grid region as the hydrogen facility meets the deliverability requirement, with certain clarifications, including providing a pathway to demonstrate electricity transfers between regions. Grid regions are based on the Department of Energy National Transmission Needs Study.
• Hourly accounting option: Once hourly matching is required, the final rules allow hydrogen producers to determine electricity-related lifecycle emissions on an hour-by-hour basis as long as the annual emissions of the hydrogen production process are under section 45V’s limit of 4 kg of CO2e per kg of hydrogen produced. 

Methane-based Hydrogen

The final regulations provide rules for determining eligibility of hydrogen produced using methane reforming technologies, including with carbon capture and sequestration (“blue” hydrogen), as well as with the use of natural gas alternatives such as RNG or coal mine methane.

The final rules require that upstream methane leakage rates be reflected in determining credit value, first based on default national values in the current version of 45VH2-GREET, and on project-specific upstream methane leakage rates in future 45VH2-GREET releases.

For hydrogen production using natural gas alternatives, the Final Regulations allow for potential credits for a wider range of biogas and fugitive methane than the proposed rules allowed – including wastewater, animal manure, and landfill gas – and for coal mine methane.  The Final Regulations also require, however, that emissions intensities for hydrogen production be determined separately for each natural gas alternative feedstock, so do not allow a negative intensity score of one feedstock (e.g., RNG) to average with a positive score of another (fossil natural gas) such that hydrogen produced from the blended volume of the two feedstocks can all qualify for the credit.

The Final Regulations do not include a first productive use requirement for methane-based hydrogen. The Final Regulations generally make it more difficult to achieve a low emissions score for natural gas alternatives, however, by providing negative emissions credit only for avoided/reduced emissions as compared to an assumed counterfactual practice, i.e. an “alternative fate” of such methane (e.g. in the case of mine methane, flaring.)

The Final Regulations allow for the use of “book-and-claim” systems for natural gas alternatives such as RNG or coal mine methane, but not until 2027 at the earliest. 
We are happy to discuss further the details and implications of the Final Regulations.

Authored by James M. Wicket, Steve Schneider, Megan Ridley-Kaye, and Darcy Bisset.