Prepared by the Baker Botts Hydrogen Practice Group, including Barbara de Marigny, Michael Bresson, Mona Dajani, George Fibbe, Ellen Friedman, Elias Hinckley, Tom Holmberg, Steven Marcus, Renn Neilson, Shailesh Sahay, Katie McEvilly, and Jared Meier

On January 3, 2025, the Internal Revenue Service (“IRS”) and the Department of the Treasury (“Treasury”) released long-awaited final regulations regarding the clean hydrogen production tax credit under section 45V of the Internal Revenue Code, which were published in the Federal Register on January 10, 2025.  The credit, enacted by the Inflation Reduction Act of 2022, is a key component of the Biden Administration’s clean energy initiative and is the primary tax incentive for the production of clean hydrogen.

Simultaneously, the Department of Energy (“DOE”) released a White Paper that supports Treasury’s analysis and describes how to assess lifecycle greenhouse gas emissions associated with electricity used to produce hydrogen.  DOE also released on January 13, 2025, a new version of its model (“45VH2-GREET (Rev. January 2025)”) for determining the lifecycle greenhouse gas emissions of hydrogen production through a variety of pathways, along with a manual as to use of the model, available here and a change log itemizing the changes in the model from its November 2024 version, available here.

The IRS and Treasury had previously released proposed regulations in December 2023, discussed by us here.  The proposed regulations generated a flood of critical comments and testimony at the subsequent IRS hearing, focusing on the restrictions in the regulations which would make access to the credit difficult for the hydrogen industry. A link to the tool we prepared for finding the comment letters by name of filer is here. 

Highlights:

Key features of the final regulations are as follows, with detail regarding each point developed further below.  

• Three Pillars: In the final regulations, Treasury has retained the requirements referred to as the “three pillars” of clean power and has not provided for any general grandfathering exception for facilities based on the date of beginning construction or placing in service, although each pillar has been liberalized in certain respects. 
• Additionality/Incrementality:  The first “pillar” – the requirement that renewable power used to produce hydrogen must be from sources that are additional to existing sources – has been retained, however, exceptions to the requirement will be available for nuclear facilities that are at risk of being shut down and renewable power sources in states which have mandated that new power sources be renewable (citing California and Washington State specifically).  A carbon capture and sequestration (“CCS”) retrofit rule has been added so that power from a facility that has been in operation more than 36 months may be considered incremental if the facility has added CCS.     
• Temporal Matching:  The second “pillar” – the requirement that renewable power be generated close in time to its use – has been retained but the final regulations have pushed out the deadline by which hydrogen production must be matched hourly with renewable power generation by two years to January 1, 2030.  
• Geographic Matching or Deliverability:  The third “pillar” – the requirement that renewable power generation be sourced from a power producer in the same geographic region as the hydrogen production facility – has been retained but the final regulations offer some flexibility allowing electricity transfers between regions under certain circumstances. 
• Hourly Accounting:  The final regulations clarify that hydrogen producers may determine 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, thereby allowing hydrogen producers to obtain at least partial credit value for those periods when emissions are sufficiently low.  
• Renewable Natural Gas:  The final regulations did not incorporate a “first productive use” requirement that had been threatened in the preamble to the proposed regulations.  Instead, the reduction in emissions from the use of renewable natural gas (“RNG”) or fugitive sources of methane (such as from coal mine operations) is to be determined based on the assumed alternative fate of such gas, as stipulated by Treasury.  
• GREET Model Certainty:  The final regulations allow hydrogen producers to rely, for the duration of the 10-year credit period, on the version of the GREET model in effect at the time that the hydrogen production facility began construction. 

Background

The amount of the section 45V credit varies depending upon the carbon intensity of the hydrogen production process: the lower the amount of greenhouse gases (“GHGs”), such as carbon dioxide, that are released during the hydrogen production process, including in the generation of electricity used to produce the hydrogen or in the production of its feedstock, the higher the amount of the section 45V credit.  

Section 45V, as enacted, did not specify in detail the methodology to be applied to determine the GHG emissions of hydrogen production methods, specifying only that the emissions were to be determined “well-to-gate” using the Greenhouse gases, Regulated Emissions, and Energy use in Transportation  (“GREET”) Model developed by the Argonne National Laboratory, and charging the IRS with developing the specifics and, in particular, rules for determining the GHG emissions associated with electricity used to produce hydrogen.  

There has been intense lobbying and public debate, especially with respect to the extent to which hydrogen producers will be allowed to rely on the use of renewable power to reduce their carbon intensity.  Proponents of stricter rules advocate limiting the ability of the hydrogen industry to use existing renewable power sources to produce clean hydrogen out of a concern that such use would stimulate the production of more GHG-emitting fossil-based power to backfill the renewable power used by hydrogen.  Proponents of more permissive rules want to foster development of the fledgling clean hydrogen industry and are concerned that strict standards will make clean hydrogen expensive to produce and hinder the growth of the industry the credit was intended to incentivize.  

The proposed regulations reflected a policy decision from the Biden Administration to adhere to the stricter view embodied in the so-called “three pillars” of clean power by requiring that any power source used to produce hydrogen satisfy requirements of: (1) additionality (or “incrementality” in the language of the regulations), (2) temporal matching and (3) geographic correlation (or “deliverability” in the language of the proposed regulations).  The final regulations now reflect an easing of some of these requirements, as described further below.      

Section 45V Credit Amounts

Section 45V provides a tax credit that is a dollar amount per kilogram of clean hydrogen produced during a 10-year time period beginning on the date the hydrogen production facility is placed in service.  The credit does not mandate the technology or feedstock that must be used to produce the hydrogen.  Rather, the amount of the credit turns on the lifecycle GHG emissions of the production process and whether the construction of the facility complies with certain prevailing wage and apprenticeship requirements (discussed by us here).  The “cleanest” hydrogen receives a credit of $3.00 per kilogram if the lifecycle GHG emissions are less than 0.45 kilograms of CO2e (CO2 equivalent) per kilogram of hydrogen produced.  Hydrogen that has lifecycle GHG emissions in excess of 4 kilograms of CO2e per kilogram of hydrogen cannot receive a credit.  The table below presents each tier of credit value for the section 45V credit:  
 

Emissions Intensity (kg of CO2e per kg of H2)	Maximum credit ($/kgH2, assuming prevailing wage and apprenticeship requirements are met)
0 - .45kg	$3.00
.45 – 1.5kg	$1.00
1.5 – 2.5kg	$0.75
2.5 – 4kg	$0.60

Hydrogen Production Methods 

By industry custom, the various methods for producing hydrogen are categorized by a designated color for ease of reference.  The most common method of producing hydrogen, the reformation of natural gas, produces significant carbon dioxide emissions and is categorized as “gray” hydrogen. “Green” hydrogen is produced by an electrolyzer that uses electric power to split water (H2O) into its components (hydrogen and oxygen).  If the electric power input for the electrolysis is from a zero-emission source, such as wind or solar power, the production of green hydrogen will have very low or zero emissions. “Blue” hydrogen is produced by the reformation of natural gas or other hydrocarbons, with the associated carbon dioxide by-product being captured and sequestered rather than allowing it to escape into the atmosphere.

How to Determine Greenhouse Gas Emissions?

Because the amount of the credit depends upon the carbon intensity of the production process, there has been considerable focus on the rules that would be applied to determine the lifecycle GHG emissions for the hydrogen production method used.  Section 45V is “technology-agnostic” in that it does not specify the nature of the technology that must be used to produce the clean hydrogen, requiring only that lifecycle GHG emissions be measured “well-to-gate” as determined under the GREET Model.  

Determining an Emission Rate with DOE’s GREET Model

The regulations require that taxpayers use DOE’s 45VH2-GREET model to determine lifecycle GHG emissions of a hydrogen production process.  The GREET model assesses and applies the emissions associated with feedstock growth, extraction, processing and delivery to the hydrogen production facility, together with emissions associated with the power used by the hydrogen production facility, and any capture and sequestration of carbon dioxide generated by the hydrogen production facility.

DOE’s 45VH2-GREET as released in January 2024 included modeling methodology for eight hydrogen production pathways:  steam methane reforming (SMR), with potential carbon capture and sequestration (CCS), autothermal reforming (ATR) of natural gas, with potential CCS, SMR of landfill gas with potential CCS, ATR of landfill gas with potential CCS, coal gasification with potential CCS, biomass gasification with corn stover and logging residue, and low-temperature and high-temperature water electrolysis.  The January 2025 version of GREET has retained these pathways but removed logging residue as an input, pending ongoing national laboratory analysis.   

Final Treasury regulations sections 1.45V-4(b)(1) and 1.45V-1(a)(9) generally require that taxpayers determine lifecycle GHG emissions on a year-by-year basis under “the most recent” GREET model, which the final regulations define as the latest version that is publicly available on the first day of the taxable year during which the qualified clean hydrogen for which the taxpayer is claiming the section 45V credit was produced. 

The GREET model is subject to change, and hydrogen producers have been concerned that the model could change between the initial development of a project and the end of its 10-year production period, causing a project developed when the model indicated credit availability to no longer qualify under the changed model. The final regulations address this concern by adding an elective safe harbor that allows hydrogen producers to rely on the version of the GREET model in effect at the time that the hydrogen production facility began construction for the duration of the 10-year credit period. Thus, even if the model is subsequently changed in such a manner that the hydrogen producer’s credit otherwise would be reduced or it would no longer qualify, the change would not impact a hydrogen producer that began construction relying on the credit outcome under the model in effect at that time.  

The final regulations also offer an alternative process pursuant to which a hydrogen producer may petition for a provisional emissions rate (“PER”) if the hydrogen production technology or feedstock used by a taxpayer is not included in the DOE’s 45VH2-GREET model.  A taxpayer who receives a PER before starting construction can rely upon the provisional emissions rate for its entire credit period.  The final regulations have also relaxed the requirements for a PER, now calling for submission of only a Class 3 front-end engineering and design (“FEED”) study which is not as detailed (and expensive) to prepare as a Class 5 study.    

Energy Attribute Certificates (“EACs”) Must Be Purchased to Claim Emissions Reduction

A key question for application of the GHG emissions calculation has been the circumstances in which the purchase of renewable power or the purchase of grid power while purchasing certificates for renewable energy use (“RECs”) could be used to reduce the carbon intensity of a hydrogen production process for purposes of section 45V.  

The section 45V regulations have introduced a new term, “Energy Attribute Certificates” (“EACs”), defined as tradeable contractual instruments, issued through a qualified EAC registry or accounting system that represents the energy attributes of a specific unit of energy produced.  The regulations provide that a REC is a form of EAC.  The DOE has explained that EACs are legal instruments that represent an exclusive claim to the attributes of an energy unit and that, while RECs relate exclusively to renewable power, EACs can be used for energy sources other than renewable power such as, for example, RNG or nuclear power.  

An eligible EAC with respect to electricity must provide information regarding the generating facility and technology and its feedstock, the amount of electricity, the commercial operation date of the facility, and the year (pre-2030) or the date and hour (2030 and later) that the electricity was generated.  The qualified EAC registry or accounting system must assign a unique identification number to each EAC, enable verification that only one EAC is associated with each unit of electricity, verify that each EAC is claimed or retired only once, identify the owner of each EAC, and provide a publicly accessible view of currently registered generators.   

EACs are the mechanism by which the section 45V regulations will track and determine the low-emission power or feedstock to be associated with the production of a hydrogen producer for purposes of determining its GHG emissions.    

The final regulations provide that the EAC requirement applies not just to purchases of power or feedstock from third parties but also applies equally to situations in which the hydrogen producer has its own captive and dedicated power source or feedstock that is co-located with the hydrogen production facility.  Although such facilities should easily meet the three pillars requirements, Treasury has determined that EACs are still needed in such “behind-the-meter” cases because they could create induced emissions if they were previously connected to the grid or used for a purpose other than hydrogen production.   

Three “Pillars” of Clean Power  

The debate over what sources of zero-carbon power may be used for purposes of calculating the section 45V credit has centered on three “pillars” of clean power: (1) incrementality (also known as additionality), (2) temporal matching and (3) deliverability (also known as geographic correlation). The regulations provide that EACs for power having these characteristics (discussed further below) may be counted for purposes of determining the emissions rate of clean hydrogen production:    

Incrementality (also known as additionality).  “Incrementality” means that the hydrogen producer would have to use power from new renewables projects, so that it does not utilize existing clean electricity facilities that would otherwise help decarbonize the power grid.  The final regulations require strict incrementality, i.e., that the power counted for determining the lifecycle GHG emissions of a clean hydrogen production facility must be from a facility that is new or that had a commercial operation date no earlier than 36 months prior to the date the hydrogen production facility was placed in service.  The incrementality requirement is applied without grandfathering for any projects currently or previously developed.  

The final regulations have somewhat relaxed the incrementality requirement, however, primarily by offering exceptions for certain nuclear power, for power generated in states in which renewable power is mandated, and for increases in capacity or retrofitting of carbon capture systems, as described below. 

Nuclear Facility Exception to Incrementality.  Nuclear facilities that are at risk of being shut down or retired and that are co-dependent on hydrogen production facilities will be considered incremental to the extent of 200 megawatt hours per reactor, even if they have been in operation longer than 36 months.  The final regulations define the risk of being shut down and co-dependence on a hydrogen production facility as follows:  a “qualified nuclear reactor” is a “merchant nuclear reactor” or a nuclear reactor that is not co-located with any other operating nuclear reactor, that meets the section 45U financial test (described below) for any two of the calendar years between 2017-2021 and either has a behind-the-meter connection with the hydrogen production facility or is the subject of a 10-year contract to sell to the hydrogen production facility.  A “merchant nuclear reactor” is one that competes in a competitive electricity market and for which over 50% of its production does not receive cost recovery through rate regulation.  These requirements define as incremental the reactors that are most exposed to power market price risk through merchant power sales.  However, even cost-of-service nuclear plants will be considered at risk under these rules if they are a single unit.

The section 45U financial test calls for average annual gross receipts as defined under section 45U of the reactor to be less than 4.375 cents per kilowatt hour for any two years between 2017-2021.  Guidance under section 45U provides rules for calculating gross receipts.  The test to demonstrate that the hydrogen production facility is materially contributing to the continued operation of the at-risk reactor is that either there is a behind-the-meter connection between the reactor and the hydrogen production facility or there is a long term 10-year binding written agreement under which the hydrogen production facility agrees to acquire and retire EACs from the nuclear reactor and pursuant to which the seller’s exposure to market price risk is hedged.  

Exception to Incrementality for States with Mandated Renewable Standards.  The final regulations are responsive to comments from those in certain states that asserted that the theory of induced emissions was misplaced for states in which power producers are required to add renewable, rather than fossil fuel, facilities.  In such states, even if hydrogen production facilities demanded all the renewable power, electricity generators could not legally replace such renewable power with fossil-fuel power.  In the final regulations, Treasury has acknowledged that there is not a risk of induced fossil emissions in such states.  Therefore, the incrementality requirement does not apply in such states.  

However, the definition of qualifying states requires that they have both a “qualifying electricity decarbonization standard” and a “qualifying GHG cap program.”  A qualifying electricity decarbonization standard is defined as a standard that: (i) contains a target that 100% of the state’s retail sales of electricity be supplied by renewable, non-emitting, zero-emitting or minimal-emitting sources by 2050,  (ii) applies to the large majority of eligible electricity supplied to the state and (iii) includes policies that would achieve that target or a plan to achieve that standard.  A state renewable portfolio standard (RPS) would be such a standard.  

A qualifying GHG cap program is a legally binding program that creates a cap on the quantity of GHG emissions in the state through issuance of a limited number of allowances or other compliance instruments to covered entities for each compliance period, which requires subject entities to report emissions, includes a cap on GHG emissions that generally declines over time, applies to the large majority of in-state power sector sources of emissions that emit greater than 25,000 metric tons of CO2e in a calendar year, applies to a large majority of out-of-state electricity supplied to the state, generally ensures that the prices of allowances sold in a state-run auction cannot fall below $25/metric ton of CO2e adjusted for inflation and generally ensures that the cap on GHG emissions cannot be exceeded for less than $90/metric ton of CO2e adjusted for inflation. 

In the preamble to the final regulations, Treasury states that it has determined that both California and Washington State meet these requirements.  Presumably, other states will qualify as their programs are developed to meet these requirements.  The final regulations require that the electricity-generating facility and the hydrogen production facility must each be in a state meeting these requirements, although not necessarily the same state. 

Uprating (Increasing Capacity) and CCS Retrofit Can Excuse Lack of Incrementality. The final regulations also provide that if the capacity of an older power facility is increased (“uprated”) within 36 months before the hydrogen production facility is placed in service, then the power may be counted but only to the extent of the increase in capacity.  The test for incrementality is applied once based on the placed-in-service date of the hydrogen production facility and does not require re-testing during the 10-year credit period.  The final regulations also provide that for power production facilities that add CCS to an existing plant, the plant will be deemed to have been newly placed in service for purposes of determining incrementality.  The requisite CCS may consist of either capture and sequestration as described in section 45Q(f)(2) or capture and utilization as described in section 45Q(f)(5).      

Temporal Matching.  “Temporal matching” relates to how tight the correlation must be between the time at which the power covered by the relevant EAC is generated and the time at which power from the grid is consumed by the hydrogen production facility –  hourly, weekly, monthly or annually – and therefore to what extent taxpayers can claim the use of clean power at times when the wind is not blowing or the sun is not shining.

The proposed regulations provided that an EAC may be counted if the electricity represented by the EAC is generated in the same hour that the taxpayer’s hydrogen production facility uses grid electricity to produce hydrogen.  In response to comments that tracking systems to provide hourly tracking are not yet available, Treasury has now extended a transition rule, pursuant to which an EAC that represents electricity generated before January 1, 2030, will be considered generated in the same hour that the hydrogen production facility uses power if the electricity represented by the EAC is generated in the same calendar year that the facility uses the electricity.  In other words, annual matching is permissible under the final regulations until 2030.  

In a change that is responsive to a number of comments, the final regulations also clarify that storage of power, such as through the use of batteries, can be used to shift the temporal profile of clean electricity supply.  However, the ability to claim the use of storage to shift the time of production is contingent on whether and when EAC registries have frameworks that comprehensively address storage, including when stored electricity comes from multiple generators not all of which produce minimal emissions.  Use of storage applies only for on-site storage and does not apply to offsite storage.  

Deliverability (also known as geographic correlation).  “Deliverability” refers to the geographic distance between the hydrogen production facility and the source of the electricity represented by the EAC that is taken into account for purposes of the credit. The proposed regulations provided that an EAC may be counted if the electricity represented by the EAC is generated by a facility that is in the same region as the hydrogen production facility.  “Regions” were defined in the proposed regulations as those identified in the National Transmission Needs Study that was released by the DOE on October 30, 2023, identifying the following regions:

Image Source: National Renewable Energy Laboratory

The final regulations have added a table to define the region of a hydrogen production facility or electricity generating source, as applicable, by the region of the balancing authority to which it is electronically connected.  A hydrogen production facility and electricity generating source will be treated as located in the same region for purposes of the 45V credit if the balancing authorities to which they are electronically connected are located in the same region.  

Importantly, however, the final regulations will allow EACs for electricity produced outside the region of the hydrogen production facility if (i) the electricity generation has transmission rights from the generator location to the region of the hydrogen production facility, that generation is delivered to such facility’s region and can be tracked on an hour-to-hour basis (ii) tracking occurs via the relevant EAC registry and (iii) imports from Canada and Mexico include an attestation from the electricity generator that the attributes are not being used for any other purpose thereby preventing double-counting.  

In sum, with respect to each of the three pillars of clean power generation, the final regulations continue to reflect the Biden Administration’s policy of limiting section 45V credit availability to hydrogen producers even though these limits will significantly increase costs for the clean hydrogen industry.  

Hydrogen Produced Using Natural Gas Alternatives 

The proposed regulations did not provide rules regarding how the use of natural gas alternatives (including biogas, RNG, and fugitive sources of methane) to produce hydrogen would be counted in determining the emissions rate of hydrogen production, although the release of the proposed regulations was accompanied by a request from Treasury for comments on the conditions that should be imposed on the ability to use certificates for RNG and fugitive methane to reduce the hydrogen producer’s emission rate.  The final regulations address the use of such feedstocks in considerable detail.  

No first productive use requirement.  The preamble to the proposed regulations stated that Treasury anticipated that for a natural gas alternative to receive a low emissions value for section 45V purposes it would need to originate from the “first productive use” of the relevant methane. Commenters objected that such a provision was not appropriate for such feedstocks and would be administratively quite difficult to implement.  Accordingly, the first productive use requirement was not implemented in the final regulations.

Assumptions regarding emissions prevented (“alternative fate”).  The final regulations provide detail regarding the nature and use of natural gas alternatives.  In order to provide for the emissions prevented by use of methane derived from biogas, RNG, or fugitive methane to produce hydrogen, it is necessary to make an assumption regarding the way such methane would have been used otherwise.  For this purpose, the final regulations provide for the “alternative fate” of methane based on the source of the methane (for example, landfills, wastewater, coal mines, or animal waste).  An assumption that the alternative fate of methane is  venting would have been very favorable since methane releases almost 25 times the GHGs of carbon dioxide.  This would have given hydrogen producers a strong incentive to use natural gas alternatives because of the assumed drop in emissions when the underlying methane is used to produce hydrogen rather than being vented.  On the basis that venting is being increasingly regulated against, however, the final regulations do not assume that venting is an alternative fate.    

The final regulations provide that the alternative fate for methane from landfill sources, methane from wastewater sources, and coal mine methane is flaring.  In flaring, the gas is combusted and the emissions to the atmosphere are of carbon dioxide from such combustion but not methane as such.  For methane from animal waste (manure), the alternative fate is deemed to be that of the sector as a whole that is derived from the national average of all animal waste management practices.  For fugitive methane other than coal mine methane, the alternative fate is stated to be productive use because fossil fuel activities other than coal mining are considered to be overwhelmingly comprised of oil and gas operations.  

“Book and claim" for gas is coming.  Another significant issue for hydrogen producers that reform natural gas to make hydrogen is whether the molecules of natural gas they use in their production must be molecules of alternative natural gas or whether they can use a “book and claim” system under which they receive credit for purchasing alternative natural gas which is placed on the pipeline system but the gas that they take off the system and use in the production of hydrogen consists of molecules of natural gas from other, presumably less “clean,” sources.  The final regulations acknowledge that a book and claim system is in theory permissible for such gas but require that a “gas EAC” be issued through a qualified gas EAC registry or accounting system and restrict use of a book and claim system to after 2026, by which time Treasury expects to be able to determine that an existing registration/tracking system meets the requirements of the regulations.  Until then, there must be a direct pipeline connection between the alternative natural gas producer and the hydrogen producer.  

For purposes of temporal matching with respect to EACs for natural gas alternatives, the final regulations require monthly matching rather than hourly matching; inputs must be time-stamped such that the calendar month of the pipeline injection is the same month in which the gas is used by the hydrogen producer.  With respect to deliverability (geographic matching) for natural gas alternatives, the final regulations will treat the entire continental United States as a single region.       

Hydrogen Must Be “Sold or Used”

Section 45V requires the clean hydrogen to be produced “for sale or use.”  The regulations provide that storage of hydrogen following production does not disqualify such hydrogen from being considered produced for sale or use. The regulations confirm that sale or use may occur outside the United States.

The regulations contain extensive provisions regarding the preparation of a verification report that must be attached to the credit claim form.  The report must be prepared by a qualified verifier who must attest as to the production, the data entered in the GREET model, the lifecycle GHG emissions rate, the amount, the sale or use (excluding use to generate power to produce more hydrogen or venting/flaring of the hydrogen), and the absence of conflict on the part of the verifier as to both the hydrogen producer and the transferee taxpayer in the event of a credit transfer, among others.  A qualified verifier means any individual with accreditation from the American National Standards Institute National Accreditation Board or as a verifier under the California Air Resources Board Low Carbon Fuel Standard program.  

Making Old New Again

Under section 45V(d)(4), if a facility originally placed in service before 2023 that does not produce qualified clean hydrogen is modified to produce qualified clean hydrogen, the facility will be deemed to have been placed in service as of the date the modification property is placed in service.  Final Treasury regulations section 1.45V-6 requires that the modification be made for the purpose of enabling the facility to produce qualified clean hydrogen, which will be considered the purpose if the facility previously could not produce hydrogen with a lifecycle GHG emissions rate of less than 4 kilograms of CO2e per kilogram of hydrogen.  Merely changing fuel inputs to the hydrogen production process, such as switching from conventional natural gas to renewable natural gas, however, would not qualify as a modification for this purpose.  

Final Treasury regulations section 1.45V-6 also provides that any existing facility may establish a new date on which it is considered originally placed in service for purposes of section 45V, thereby starting a new 10-year credit period, by modifying the facility 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 (the “80/20 rule”).  The regulations also provide that the 80/20 rule applies to any existing facility, regardless of whether the facility previously produced qualified clean hydrogen and regardless of when the facility was originally placed in service.  

An Anti-Abuse Rule

Treasury has expressed a concern that, if the cost of producing qualified clean hydrogen is less than the amount of the section 45V credit available, then taxpayers may have an incentive to produce qualified clean hydrogen solely for the purpose of exploiting the section 45V credit in a manner that is inconsistent with the purpose of incentivizing the production of qualified clean hydrogen for productive use.  Therefore, the regulations contain an anti-abuse rule that would make the credit unavailable if the hydrogen is produced in a manner that is wasteful, such as production that the taxpayer knows or has reason to know will be vented or flared.   

Stacking Section 45V and Section 45Q Credits

The production of “blue” hydrogen involves capture and sequestration of the carbon dioxide emitted during the hydrocarbon reformation process.  Such sequestration is generally eligible for the section 45Q tax credit for carbon capture and sequestration.  Section 45V allows no credit with respect to hydrogen produced at a facility that includes carbon capture equipment for which a credit is allowed to any taxpayer under section 45Q for the taxable year or any prior taxable year.  It has been unclear, however, whether mere co-location of carbon capture equipment with a hydrogen production facility prevents a section 45V claim even if the carbon capture is not part of the clean hydrogen production process train.  

Final Treasury regulations section 1.45V-1(a)(7) defines the term “facility” to mean “a single production line that is used to produce qualified clean hydrogen” and states that a single production line “includes all components of property that function interdependently to produce qualified clean hydrogen.”  Further, the regulation provides that the term “facility” does not include “any carbon capture equipment associated with the electricity production process.”  

Therefore, carbon capture equipment that is used to reduce the GHG emissions rate of the hydrogen production process would be included in the definition of the facility and a taxpayer could not claim both a section 45Q and 45V credit with respect to such production.  However, carbon capture equipment that is unrelated to the hydrogen production process is eligible for a section 45Q credit even while a section 45V credit is claimed for the hydrogen production.  Thus, a section 45Q credit could be claimed for a co-located natural gas-fired power plant that captures and sequesters its carbon dioxide emissions even though electricity from the plant is used to produce hydrogen for which a section 45V credit is claimed. 

Effective Date

The final regulations have an effective date that is the date of their publication in the Federal Register (January 10, 2025).   The Administrative Procedure Act prohibits an effective date for regulations that is less than 30 days after publication in the Federal Register.  Treasury may, however, provide that final regulations are effective sooner, if it has good cause to why the earlier date is in the public interest.  The preamble to the final regulations states that the regulations have an immediate effective date and that “the Treasury Department and the IRS find that there would be good cause to make this rule immediately effective upon publication in the Federal Register.”  The good cause referenced in the preamble is the need of the hydrogen industry to have guidance upon which it can rely in order to make investment decisions in clean hydrogen production.

 The Congressional Review Act requires federal agencies to submit their rules to Congress for approval before those rules can take effect.  By joint resolution, Congress may disapprove such rules during a limited time period that begins when the rule is published in the Federal Register and ends after 60 days of continuous session of Congress.  If the President agrees, or if Congress overrides a presidential veto, the rules do not take effect.  The Final Regulations are subject to these review procedures but no disapproving resolution has been filed in Congress at the date of this writing. 

---

Recognized as Band 1 by Chambers in Energy Transition, Baker Botts has significant experience advising a broad range of companies on the intricacies of tax incentives specific to the Inflation Reduction Act and other government-sponsored programs.

The development of hydrogen projects requires a diverse range of complementary legal disciplines and a multidisciplinary approach.  Baker Botts’ Hydrogen Practice Group is at the forefront of this developing industry globally.

If you have any questions about Section 45V or other questions related to tax incentives, we invite you to reach out to any member of the Baker Botts Tax Team. 

ABOUT BAKER BOTTS L.L.P.
Baker Botts is an international law firm whose lawyers practice throughout a network of offices around the globe. Based on our experience and knowledge of our clients' industries, we are recognized as a leading firm in the energy, technology and life sciences sectors. Since 1840, we have provided creative and effective legal solutions for our clients while demonstrating an unrelenting commitment to excellence. For more information, please visit bakerbotts.com.