Skip to content

General education, not advice for your situation.

Carry Forward Learning Start here Intern0 XP

Treasury Regulations · 26 CFR

§ 1.45V-4. Procedures for determining lifecycle greenhouse gas emissions rates for qualified clean hydrogen.

In effect eCFR current as of October 15, 2026

Regulation text, no changes From the eCFR, current as of October 15, 2026. The eCFR is an authoritative but unofficial editorial compilation of the Code of Federal Regulations; the official text is the annual CFR on govinfo. Compare it with this section on ecfr.gov (external site) or the official annual CFR on govinfo (external site).

Regulation under 26 U.S.C. § 45V

Cite as 26 CFR § 1.45V-4

At a glance

Read from the text and its source citation. Not part of the regulation.

Status
In the current eCFR
Issued
January 10, 2025 by 90 FR 2309
Issued under
26 U.S.C. § 45V
Length
9,910 words · about 43 min to read
Defines
28 terms
Cross-references
cites 4 Code sections and 6 regulations; cited by 5
(a) Overview—
(1) In general. Except as provided in paragraph (a)(2) of this section, the amount of the section 45V credit is determined under section 45V(a) of the Code and § 1.45V-1(b) according to the lifecycle GHG emissions rate of each hydrogen production process conducted at a hydrogen production facility during the taxable year. The lifecycle GHG emissions rate of each process is determined under the 45VH2-GREET Model. In the case of any hydrogen production pathway, as described in paragraph (c)(2)(i) of this section, for which a lifecycle GHG emissions rate has not been determined under the 45VH2-GREET Model for purposes of section 45V, a taxpayer producing hydrogen via such a pathway may file a petition for a provisional emissions rate (PER) with the IRS for the Secretary's determination of the lifecycle GHG emissions rate with respect to such hydrogen.
(2) Lifecycle GHG emissions rate of hourly electricity consumption. In the case of a facility's use of electricity generated on or after January 1, 2030, for which the taxpayer acquires and retires a qualifying EAC (as defined in paragraph (d)(2)(vii) of this section) that represents electricity that is generated in the same hour (Coordinated Universal Time (UTC)) that the taxpayer's process uses electricity to produce hydrogen, the taxpayer may determine the lifecycle GHG emissions associated with the use of such electricity by the taxpayer's process during such hour using the attributes of such qualifying EAC rather than using an annual average of the lifecycle GHG emissions associated with the use of electricity in the taxpayer's process. If a taxpayer determines the lifecycle GHG emissions associated with the use of electricity on an hourly basis in the manner provided in this paragraph (a)(2), such taxpayer must determine the lifecycle GHG emissions associated with the use of electricity on an hourly basis for the entire taxable year. In the case of hydrogen produced at a facility using electricity for which the taxpayer does not acquire and retire qualifying EACs that represent electricity that is generated in the same hour that the taxpayer's hydrogen production facility uses electricity to produce hydrogen on or after January 1, 2030, the lifecycle GHG emissions rate of such hydrogen is determined using the regional annual average emissions rate of such electricity usage as reflected in 45VH2-GREET. The taxpayer may determine the lifecycle GHG emissions associated with the use of electricity on an hourly basis only if the annual average lifecycle GHG emissions rate of the hydrogen production process during the taxable year is not greater than 4 kilograms of carbon dioxide equivalent (CO2e) per kilogram of hydrogen for all hydrogen produced pursuant to that process during the taxable year.
(3) Examples. The following examples illustrate the application of paragraphs (a)(1) and (2) of this section.
(i) Example 1: Annual emissions accounting—
(A) Facts. Taxpayer, which files its Federal income tax return based on the calendar year, owns a hydrogen production facility, Facility, that constantly produces hydrogen through electrolysis during all 24 hours of each day of taxable year 2031. Facility's only inputs are water and electricity. For the first 23 of the 24 hours of each day of 2031, Facility acquires and retires qualifying EACs that represent electricity that is generated in the same hour that the taxpayer's hydrogen production facility uses electricity to produce hydrogen. The qualifying EACs reflect electricity from wind power, a uniform source of zero-emission electricity depicted in 45VH2-GREET. During the last hour of each day in 2031, Facility sources electricity from a regional grid. During taxable year 2031, Taxpayer produces 2,402,145.12 kilograms of a hydrogen gas stream (an annual total of 2,302,055.74 kilograms produced during the first 23 hours of each day, and 100,089.38 kilograms produced during the remaining one hour of each day). To produce such a stream, Facility consumes 132,000 MWh of electricity. Of the 132,000 MWh of electricity consumed, 126,500 MWh of the electricity is from wind power, and 5,500 MWh of the electricity is from the regional electricity grid. On average, of the 2,402,145.12 kilograms produced, 99.99 percent by mol is pure hydrogen and 0.01 percent is water vapor (this translates to 99.9107 percent pure hydrogen and 0.0893 percent water vapor by mass). Thus, Facility produced an annual total of 2,400,000 kilograms of pure hydrogen by mass. In 2031, the Facility produces 10,000,000 kilograms of oxygen co-product. The pressure at which Facility produces the hydrogen gas stream is 300 psi.
(B) Analysis. To determine the annual average lifecycle GHG emissions rate of the process by which the 2,400,000 kilograms of pure hydrogen were produced in 2031, Taxpayer must account for the total amount of electricity consumed by Facility in taxable year 2031 (132,000 MWh), the annual average share of electricity that is from each source depicted in 45VH2-GREET (95.8333 percent wind power, 4.1667 percent regional electricity grid), the total amount of hydrogen gas stream produced in that year (2,402,145.12 kilograms), the average share of mixed gases in the hydrogen gas stream over the year (99.99 percent hydrogen by mol, 0.01 percent water by mol), the total amount of oxygen co-product produced in that year (10,000,000 kilograms); and the pressure at which the hydrogen gas stream is produced (300 psi). Assuming that, using these inputs, 45VH2-GREET reflects that the average annual lifecycle GHG emissions rate of the process by which the 2,400,000 kilograms of hydrogen were produced in 2031 not greater than 4 kilograms of CO2e per kilogram of hydrogen, then the hydrogen produced by Facility in 2031 is qualified clean hydrogen. Further, assuming that, using these inputs, 45VH2-GREET reflects that Facility produces hydrogen through a process that results in an annual lifecycle GHG emissions rate of less than 2.5 but not less 1.5 kilograms of CO2e per kilogram of hydrogen, the applicable percentage under section 45V(b)(2) is 25 percent. Accordingly, assuming all other requirements to claim the section 45V credit are met, and assuming prevailing wage and apprenticeship requirements under section 45V(e) are met, Taxpayer may claim the section 45V credit for the 2,400,000 kilograms of qualified clean hydrogen in the amount of $1,800,000 (2,400,000 kilograms of qualified clean hydrogen produced by Taxpayer at Facility during taxable year 2031 multiplied by $0.75 with respect to such hydrogen) (unadjusted for inflation).
(ii) Example 2: Hourly emissions accounting—
(A) Facts. The facts are the same as in paragraph (a)(3)(i)(A) of this section (Example 1), except that Taxpayer opts to determine the lifecycle GHG emissions rate of electricity used to produce hydrogen on an hourly basis pursuant to paragraph (a)(2) of this section.
(B) Analysis. To determine whether Taxpayer is eligible to use hourly accounting, Taxpayer must first complete an analysis on an annual basis, as described in Example 1. Assuming that the lifecycle GHG emissions rate associated with pure hydrogen production at Facility during the taxable year is not greater than 4 kilograms of CO2e per kilogram of hydrogen, Taxpayer is eligible to use hourly accounting. To determine the hourly lifecycle GHG emissions rate, Taxpayer must first determine the average share of mixed gases in the hydrogen gas stream over taxable year 2031 (99.99 percent hydrogen by mol, 0.01 percent water vapor by mol) and the average amount of oxygen co-product produced for every kilogram of hydrogen gas stream produced in taxable year 2031 (10,000,000 kilograms of oxygen divided by 2,402,145.12 kilograms of hydrogen gas stream equals 4.163 kilograms of oxygen per kilogram of hydrogen gas stream). Then, for each hour, Taxpayer must account for the following inputs in 45VH2-GREET: the total kilograms of hydrogen gas stream produced in that hour, the product of the annual average oxygen co-product rate (4.163 kilograms of oxygen co-product per kilogram of hydrogen gas stream) and the total kilograms of hydrogen gas stream produced in that hour, the average impurity content of the hydrogen gas stream produced in that hour, the total amount of electricity consumed in that hour, and the source of the electricity used in that hour, as depicted in 45VH2-GREET (for example, wind power, regional electricity grid). Assuming that, using these inputs, 45VH2-GREET reflects that the lifecycle GHG emissions rate of the process by which the hydrogen was produced in each hour of the first 23 hours of each day in taxable year 2031 is less than 0.45 kilograms of CO2e per kilogram of hydrogen, then for purposes of section 45V(b)(2), the applicable percentage for such hydrogen produced in each hour of the first 23 hours of each day of taxable year 2031 is 100 percent. For the hydrogen produced during the last hour of each day of taxable year 2031, assuming that 45VH2-GREET reflects that the lifecycle GHG emissions rate of the process exceeded 4 kilograms of CO2e per kilogram of hydrogen, the applicable percentage for such hydrogen is zero percent (that is, the hydrogen produced is not qualified clean hydrogen). Assuming all other requirements of section 45V are met, including the prevailing wage and apprenticeship requirements of section 45V(e), Taxpayer is entitled to a section 45V credit equal to $3 (not adjusted for inflation) per kilogram of qualified clean hydrogen produced in the first 23 hours of each day of taxable year 2031 and no credit for the hydrogen produced in the last hour of each day of taxable year 2031. As described in Example 1, in taxable year 2031, Taxpayer produced 2,400,000 kilograms of pure hydrogen by mass at a constant rate. Accordingly, during the first 23 hours of each day of taxable year 2031, Taxpayer produced 2,300,000 kilograms of pure hydrogen. Taxpayer may therefore claim a section 45V credit of $6,900,000 (2,300,000 kilograms of qualified clean hydrogen produced by Taxpayer during the first 23 hours of each day of taxable year 2031 at Facility multiplied by $3 with respect to such hydrogen).
(b) Use of the 45VH2-GREET Model—
(1) In general. For each taxable year during the period described in section 45V(a)(1), a taxpayer claiming the section 45V credit determines the lifecycle GHG emissions rate of each hydrogen production process conducted at a hydrogen production facility under the 45VH2-GREET Model separately for each process. This determination is made following the close of each such taxable year and, subject to paragraph (a)(2) of this section, must include all of a process's hydrogen production during the taxable year. In using the 45VH2-GREET Model to calculate the lifecycle GHG emissions rate for purposes of determining the amount of the section 45V credit under section 45V(a) and § 1.45V-1(b), the taxpayer must accurately enter all information about its facility requested within the interface of 45VH2-GREET (as described in § 1.45V-1(a)(9)(ii)). Information regarding where taxpayers may access 45VH2-GREET and accompanying documentation will be included in the instructions to the Form 7210, Clean Hydrogen Production Credit, or any successor form(s).
(2) Beginning of construction safe harbor—
(i) In general. A taxpayer may, in its discretion, make an irrevocable election effective for the remaining taxable years within the period described in section 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 45VH2-GREET Model. In the case of a facility owned by the taxpayer that began construction prior to December 26, 2023, such taxpayer may, in its discretion, make an irrevocable election effective for the remaining taxable years within the period described in section 45V(a)(1), to treat the first publicly-available version of 45VH2-GREET (that is, the version of 45VH2-GREET released in December 2023) as the 45VH2-GREET Model. For purposes of this paragraph (b)(2), in the case of a facility that is modified to produce qualified clean hydrogen under section 45V(d)(4) and § 1.45V-6(a), or a facility that is retrofitted in a manner that entitles the facility to a new placed in service date under § 1.45V-6(b), the date when construction of the facility began is the date when construction of such modification or retrofit began. An election under this paragraph (b)(2)(i) relates to the version of 45VH2-GREET and does not alter any other rules provided in this section and in §§ 1.45V-1, -2, -3, -5, and -6.
(ii) Time and manner of making election. The taxpayer makes the election described in paragraph (b)(2)(i) of this section with respect to a qualified clean hydrogen production facility's hydrogen production process on Form 7210 or any successor form(s). The taxpayer must make the election by no later than the due date for filing its Federal income tax return or information return (including extensions) for a taxable period ending no later than December 31, 2025, or the due date for filing its Federal income tax return or information return (including extensions) for the taxable period in which such facility is placed in service, whichever due date is later.
(c) Provisional emissions rate (PER)—
(1) In general. For purposes of section 45V(c)(2)(C) and paragraph (a) of this section, the term provisional emissions rate or PER means the lifecycle GHG emissions rate of the hydrogen produced through a process at a hydrogen production facility as determined by the Secretary under this paragraph (c).
(2) Rate not determined—
(i) In general. For purposes of section 45V(c)(2)(C), a taxpayer may not file a petition for a PER unless a lifecycle GHG emissions rate has not been determined under the 45VH2-GREET Model with respect to hydrogen produced through a process by the taxpayer at a hydrogen production facility. A lifecycle GHG emissions rate has not been determined under the 45VH2-GREET Model with respect to hydrogen produced through a process by the taxpayer at a hydrogen production facility if either the feedstock used in such process or the facility's hydrogen production technology, together referred to as the facility's “hydrogen production pathway,” is not included in the 45VH2-GREET Model. If a taxpayer's request for an emissions value pursuant to paragraph (c)(5) of this section with respect to the hydrogen produced through a process by the taxpayer at a hydrogen production facility is pending at the time such facility's hydrogen production pathway becomes included in an updated version of 45VH2-GREET, the taxpayer's request for an emissions value will be automatically denied. In such case, the taxpayer must determine the lifecycle GHG emissions rate with respect to such hydrogen under paragraph (c)(2)(ii) of this section.
(ii) Subsequent inclusion in 45VH2-GREET. Notwithstanding the definition of the 45VH2-GREET Model provided at § 1.45V-1(a)(9)(ii), for the taxable year in which the hydrogen production facility's hydrogen production pathway is first included in an updated version of 45VH2-GREET, the updated version of 45VH2-GREET will be considered the 45VH2-GREET Model with respect to the hydrogen produced through a process by the taxpayer at the hydrogen production facility during such taxable year, and for purposes of section 45V(c)(2)(C), a lifecycle GHG emissions rate for such hydrogen will be considered to have been determined.
(3) Process for filing a PER petition. To file a PER petition with the Secretary, a taxpayer must submit a PER petition attached to the taxpayer's Federal income tax return (or information return) for the first taxable year of hydrogen production ending within the 10-year period described in section 45V(a)(1) for which the taxpayer claims the section 45V credit for hydrogen to which the PER petition relates and for which a lifecycle GHG emissions rate has not been determined, as defined under paragraph (c)(2)(i) of this section. A PER petition must contain the letter received from the DOE stating the emissions value the DOE determined with respect to the facility's hydrogen production pathway, and the control number the DOE assigned to the emissions value request application. If the taxpayer obtained more than one emissions value from the DOE, the PER petition must contain the emissions value setting forth the lifecycle GHG emissions rate of the hydrogen for which the section 45V credit is claimed on the Form 7210, Clean Hydrogen Production Credit, or any successor form(s), to which the PER petition is attached.
(4) PER determination. Upon the taxpayer's filing of its Federal income tax return (or information return) containing a PER petition in a manner consistent with paragraph (c)(3) of this section, the emissions value of the hydrogen determined by the DOE will be deemed accepted. The taxpayer may rely upon an emissions value provided by the DOE for purposes of calculating and claiming a section 45V credit, provided that any information, representations, or other data provided to the DOE in support of the request for an emissions value are accurate. The IRS's deemed acceptance of such emissions value is the Secretary's determination of the PER. However, the production, including the data the taxpayer submitted in the PER petition and the data provided to the DOE in support of the taxpayer's request for an emissions value, and sale or use of such hydrogen must be verified by an unrelated party under section 45V(c)(2)(B)(ii) and § 1.45V-5. Such verification and any information, representations, or other data provided to the DOE in support of the request for an emissions value are subject to later examination by the IRS.
(5) Department of Energy (DOE) emissions value request process (EVRP). An applicant that submits a request for an emissions value must follow the procedures specified by the DOE to request and obtain such emissions value. Emissions values will be evaluated using the same well-to-gate system boundary that is employed in 45VH2-GREET. Additionally, background data parameters in 45VH2-GREET will also be treated as background data (fixed values that an applicant cannot change) in the emissions value request process. Treatment of qualifying EACs and other sources of emissions addressed in the section 45V regulations will be consistently applied in the EVRP. An applicant may request an emissions value from the DOE only after a Class 3 front-end engineering and design (FEED) study or similar indication of project maturity, as determined by the DOE, such as project specification and cost estimation sufficient to inform a final investment decision, has been completed for the hydrogen production facility. The DOE may decline to review applications that are not responsive, including those applications that use a hydrogen production technology and feedstock already in 45VH2-GREET or applications that are incomplete. Applicants seeking a new emissions value for a given hydrogen production facility after the DOE has completed its analysis may reapply only if they wish to resubmit their application with new or revised technical information or clarifications related to the information previously submitted. Guidance and procedures for applicants to request and obtain an emissions value from the DOE will be published by the DOE.
(6) Effect of PER—
(i) In general. A taxpayer may use a PER determined by the Secretary to calculate the amount of the section 45V credit under section 45V(a) and § 1.45V-1(b) with respect to qualified clean hydrogen produced at a qualified clean hydrogen production facility, provided—
(A) The lifecycle GHG emissions rate of such hydrogen has not been determined (for purposes of section 45V(c)(2)(C)) under the 45VH2-GREET Model;
(B) There are no material changes to the information about the taxpayer's hydrogen production process from the information provided to the DOE to obtain an emissions value pursuant to paragraph (c)(5) of this section; and
(C) All other requirements of section 45V are met.
(ii) Material change. For purposes of paragraph (c)(6)(i)(B) of this section, a material change means any change that would cause a qualified verifier (as defined in § 1.45V-5(h)) to be unable to complete a production attestation under section 45V(c)(2)(B)(ii) of the Code and § 1.45V-5(c).
(iii) Subsequent inclusion safe harbor—
(A) In general. The taxpayer may, in its discretion, make an irrevocable election, effective for the remaining taxable years within the period described in section 45V(a)(1), to treat the first version of 45VH2-GREET that includes the taxpayer's qualified clean hydrogen production facility's hydrogen production pathway as the 45VH2-GREET Model.
(B) Time and manner of making election. The taxpayer makes the election described in paragraph (c)(6)(iii)(A) of this section with respect to a qualified clean hydrogen production facility on Form 7210 or any successor form(s). The taxpayer must make the election by no later than the due date for filing its Federal income tax return or information return (including extensions) for a taxable period ending no later than December 31, 2025, or the due date for filing its Federal income tax return or information return (including extensions) for the taxable period in which the taxpayer's qualified clean hydrogen production facility's hydrogen production pathway is first included in 45VH2-GREET, whichever due date is later.
(iv) Special rule for facilities that receive an emissions value prior to the beginning of construction. Notwithstanding the requirement of paragraph (c)(6)(i)(A) of this section, a taxpayer who received an emissions value from the DOE with respect to a qualified clean hydrogen production facility (pursuant to paragraph (c)(5) of this section) before the date when construction of the facility began, may, in its discretion, use the PER determined by the Secretary and the associated emissions value to calculate the amount of section 45V credit with respect to qualified clean hydrogen produced at the qualified clean hydrogen production facility for the entirety of the period described in section 45V(a)(1), provided that the taxpayer continues to satisfy the requirements of paragraphs (c)(6)(i)(B) and (C) of this section.
(v) Not an examination of books and records. The Secretary's PER determination is not an examination or inspection of books of account for purposes of section 7605(b) of the Code and does not preclude or impede the IRS (under section 7605(b) or any administrative provisions adopted by the IRS) from later examining a return or inspecting books or records with respect to any taxable year for which the section 45V credit is claimed. For example, the verification report submitted under section 45V(c)(2)(B)(ii) and § 1.45V-5 and any information, representations, or other data provided to the DOE in support of the request for an emissions value are still subject to examination. Further, a PER determination does not signify that the IRS has determined that the requirements of section 45V have been satisfied for any taxable year.
(d) Use of energy attribute certificates (EACs)—
(1) In general. For purposes of the section 45V credit, if a taxpayer determines a lifecycle GHG emissions rate for hydrogen produced at a hydrogen production facility using the 45VH2-GREET Model or the Secretary determines a PER for hydrogen produced at a hydrogen production facility subject to a PER petition, then the taxpayer may treat such hydrogen production facility's use of electricity as being from a specific electricity generating facility rather than as electricity with the annual average lifecycle GHG emissions of the regional electricity grid (as represented in 45VH2-GREET) only if the taxpayer acquires and retires qualifying EACs (as defined in paragraph (d)(2)(vii) of this section) for each unit of electricity that the taxpayer claims from such source. For example, one megawatt-hour of electricity used to produce hydrogen would need to be matched with one megawatt-hour of qualifying EACs. Further, to satisfy this requirement, a taxpayer's acquisition and retirement of qualifying EACs must also be recorded in a qualified EAC registry or accounting system (as defined in paragraph (d)(2)(viii) of this section) so that the acquisition and retirement of such EACs may be verified by a qualified verifier (as defined in § 1.45V-5(h)). The requirements of this paragraph (d)(1) apply regardless of whether the electricity generating facility is grid connected, directly connected, or co-located with the hydrogen production facility.
(2) Definitions. For purposes of this section—
(i) Commercial operations date. The term commercial operations date or COD means the date on which a facility that generates electricity begins commercial operations.
(ii) Energy attribute certificate. The term energy attribute certificate (EAC) means a tradeable contractual instrument, issued through a qualified EAC registry or accounting system (as defined in paragraph (d)(2)(viii) of this section), that represents the energy attributes of a specific unit of energy produced. An EAC may be traded with or separately from the underlying energy it represents. An EAC can be retired by or on behalf of its owner, which is the party that has the right to claim the underlying attributes represented by an EAC. Renewable energy certificates (RECs) and other similar energy certificates issued through a registry or accounting system are forms of EACs.
(iii) Eligible EAC. The term eligible EAC means an EAC that represents electricity that is produced by an electricity generating facility that is registered on only one qualified EAC registry or accounting system and that, with respect to the electricity to which the EAC relates, provides, at a minimum, the information described in paragraphs (d)(2)(iii)(A) through (H) of this section—
(A) A description of the facility, including the technology and feedstock used to generate the electricity;
(B) The amount and units of electricity;
(C) The COD of the facility that generated the electricity;
(D) For electricity that is generated before January 1, 2030, the calendar year in which such electricity was generated;
(E) For electricity that is generated after December 31, 2029, the date and hour (including time zone, or in UTC) in which such electricity was generated;
(F) Other attributes required by 45VH2-GREET or in the determination of a PER to accurately determine the emissions associated with such electricity;
(G) For electricity generating sources that use carbon capture equipment, the placed in service date of such equipment; and
(H) The project identification number or assigned identifier.
(iv) Qualifying electricity decarbonization standard. A qualifying electricity decarbonization standard is a standard that—
(A) Contains a target that 100 percent of the State's retail sales of electricity from obligated entities be supplied by renewable, non-emitting, zero-emitting, or minimal-emitting sources, where obligated entities and eligible sources are defined by State policy, or a target for GHG emissions from the State's electricity sector that reflects an equivalent of such a retail sales target, by 2050 or earlier;
(B) Applies to the large majority of eligible electricity supplied to the state, as determined by the State; and
(C) Includes policies that would achieve the target, a requirement that the state develop a plan to achieve the standard, or a requirement that entities subject to the standard are required to develop such a plan.
(v) Qualifying GHG cap program. A qualifying GHG cap program is a legally binding program that meets the following minimum criteria—
(A) Creates a limitation (cap) on the quantity of GHG emissions from the electricity sector (either alone or along with other sectors) in a State through issuance of a limited number of allowances or other compliance instruments to covered entities for each compliance period;
(B) Includes annual obligations (even if part of multi-year compliance periods) under which an entity subject to the cap must provide information about such entity's GHG emissions and for which an entity must submit at least some compliance instruments to the State's regulatory authority;
(C) Includes a cap on GHG emissions from covered entities that generally declines over time from the cap on GHG emissions in effect in calendar year 2025 (or the first calendar year in which the cap is in effect, if later), with adjustments as appropriate for expansions in the scope of the cap;
(D) Applies to the large majority of in-state electricity sources of emissions that emit greater than 25,000 metric tons of CO2e in a calendar year;
(E) Applies to the large majority of out-of-state electricity supplied to the State and to emissions associated with those imports, including emissions that arise from entities that emit greater than 25,000 metric tons of CO2e in a calendar year;
(F) Generally ensures that the prices of allowances sold in a state-run auction cannot fall below $25 per metric ton of CO2e, adjusted for inflation from 2025 dollars using at a minimum the most recently available twelve-month value of the Consumer Price Index for All Urban Consumers (CPI-U), as published by the United States Bureau of Labor Statistics (BLS); and
(G) Generally ensures that the cap on greenhouse gas emissions cannot be exceeded for less than $90 per metric ton of CO2e, adjusted for inflation from 2025 dollars using at a minimum the most recently available twelve-month value of the CPI-U, as published by the BLS.
(vi) Merchant nuclear reactor. The term merchant nuclear reactor means a nuclear reactor that competes in a competitive electricity market through the sale of energy and, in some cases, other services 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.
(vii) Qualifying EAC. The term qualifying EAC means an eligible EAC that meets the requirements of paragraph (d)(3) of this section and for which the satisfaction of those requirements has been verified by a qualified verifier (as defined in § 1.45V-5(h)).
(viii) Qualified EAC registry or accounting system. The term qualified EAC registry or accounting system means a tracking system that—
(A) Assigns a unique identification number to each EAC tracked by such system;
(B) Enables verification that only one EAC is associated with each unit of electricity;
(C) Verifies that each EAC is claimed and retired only once;
(D) Identifies the owner of each EAC; and
(E) Provides a publicly accessible view (for example, through an application programming interface) of all currently registered generators in the tracking system to prevent the duplicative registration of generators.
(ix) Region. The term region means a Region that corresponds to a Balancing Authority, as identified in the following table. Alaska, Hawaii, and each U.S. territory will be treated as separate regions. Future versions of this table may be provided as a safe harbor in guidance published in the Internal Revenue Bulletin.

Table 1 to Paragraph (d)(2)(ix)

Balancing AuthorityRegion
Balancing Authority of Northern CaliforniaCalifornia.
California Independent System Operator (Balancing Authority)California.
Imperial Irrigation DistrictCalifornia.
Los Angeles Dept of Water & PowerCalifornia.
Turlock Irrigation DistrictCalifornia.
Midcontinent ISO (Balancing Authority): SouthDelta.
Duke Energy Florida IncFlorida.
Florida Municipal Power PoolFlorida.
Florida Power & LightFlorida.
Gainesville Regional UtilitiesFlorida.
Homestead (City of)Florida.
JEAFlorida.
New Smyrna Beach Utilities CommissionFlorida.
Reedy Creek Improvement DistrictFlorida.
Seminole Electric Coop IncFlorida.
Tallahassee FL (City of)Florida.
Tampa Electric CoFlorida.
East Kentucky Power Coop IncMid-Atlantic.
LG&E & KU Services CoMid-Atlantic.
Ohio Valley Electric CorpMid-Atlantic.
PJM InterconnectionMid-Atlantic.
Associated Electric Coop IncMidwest.
Electric Energy IncMidwest.
Gridliance HeartlandMidwest.
Midcontinent ISO (Balancing Authority): North and CentralMidwest.
NaturEner Power Watch LLC (GWA)Mountain.
NaturEner Wind Watch LLCMountain.
Nevada Power CoMountain.
Northwestern EnergyMountain.
PacifiCorp EastMountain.
Public Service Co of ColoradoMountain.
WAPA Rocky Mountain RegionMountain.
WAPA Upper Great Plains WestMountain.
New England ISO (Balancing Authority)New England.
Northern MaineNew England.
New York ISO (Balancing Authority)New York.
Avangrid Renewables LCCNorthwest.
Avista CorpNorthwest.
Bonneville Power AdministrationNorthwest.
Gridforce Energy Management LLCNorthwest.
Idaho Power CoNorthwest.
PacifiCorp WestNorthwest.
Portland General ElectricNorthwest.
PUD No 1 of Chelan CountyNorthwest.
PUD No 1 of Douglas CountyNorthwest.
PUD No 2 of Grant CountyNorthwest.
Puget Sound Energy IncNorthwest.
Seattle City LightNorthwest.
Tacoma PowerNorthwest.
Southwest Power Pool (Balancing Authority)Plains.
Southwestern Power AdministrationPlains.
Alcoa Power Generating Inc Yadkin DivisionSoutheast.
Duke Energy Carolinas LLCSoutheast.
Duke Energy Progress EastSoutheast.
Duke Energy Progress WestSoutheast.
PowerSouth Energy CoopSoutheast.
South Carolina Electric & Gas CoSoutheast.
South Carolina Public Service AuthoritySoutheast.
Southeastern Power Administration (Southern)Southeast.
Southern Co Services IncSoutheast.
Tennessee Valley AuthoritySoutheast.
Arizona Public Service CoSouthwest.
Arlington Valley LLCSouthwest.
El Paso ElectricSouthwest.
Gila River Power LLCSouthwest.
Griffith Energy LLCSouthwest.
New Harquahala Generating Co LLCSouthwest.
Public Service Co of New MexicoSouthwest.
Salt River ProjectSouthwest.
Tucson Electric Power CoSouthwest.
WAPA Desert Southwest RegionSouthwest.
ERCOT ISO (Balancing Authority)Texas.
(x) Qualifying nuclear reactor. The term qualifying nuclear reactor means, with respect to an EAC, a nuclear reactor—
(A) That is a merchant nuclear reactor, as defined in paragraph (d)(2)(vi) of this section, or is a nuclear reactor that is not co-located with any other operating nuclear reactor,
(B) For which the average annual gross receipts within the meaning of section 45U(b)(2)(A)(ii)(I) of the reactor are less than 4.375 cents per kilowatt hour, for any two of the calendar years 2017 through 2021, as determined with respect to any one owner of the reactor, and
(C) That either
(1) Has a physical electrical connection with the hydrogen production facility which acquires and retires the EAC, which is on the reactor's side of a utility service meter before the reactor or the hydrogen production facility connect to a distribution or transmission system, or
(2) Is the subject of a written binding contract, as defined in paragraph (d)(2)(xi) of this section, for a fixed term of at least 10 years beginning on the first date on which qualified EACs 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 revenue risk.
(xi) Written binding contract. For purposes of this paragraph (d)(2)(xi), a contract is a written binding contract if it is enforceable under state law against the taxpayer or a predecessor and does not limit damages to a specified amount (for example, by use of a liquidated damages provision). For this purpose, a contractual provision that limits damages to an amount equal to at least five percent of the total contract price will not be treated as limiting damages to a specified amount. For additional guidance regarding the definition of a written binding contract, see § 1.168(k)-2(b)(5)(iii).
(xii) Qualifying State. The term qualifying State means a state which, as determined by the Secretary, has under its state law or regulations a qualifying electricity decarbonization standard as defined in paragraph (d)(2)(iv) of this section and a qualifying GHG cap program as defined in paragraph (d)(2)(v) of this section. For purposes of this rule, the District of Columbia, Commonwealth of Puerto Rico, Guam, the U.S. Virgin Islands, American Samoa, and the Commonwealth of the Northern Mariana Islands are treated as states.
(3) Qualifying EAC requirements. An eligible EAC meets the requirements of this paragraph (d)(3) if it meets the requirements of paragraphs (d)(3)(i) through (iii) of this section.
(i) Incrementality. An EAC meets the requirements of this paragraph (d)(3)(i) if it meets the requirements of paragraph (d)(3)(i)(A), (B), (C), or (D) of this section. Paragraph (d)(3)(i)(B)(4) of this section provides an example that illustrates the application of paragraph (d)(3)(i)(B) of this section.
(A) In general. An EAC meets the requirements of this paragraph (d)(3)(i)(A) if the electricity generating facility that produced the unit of electricity to which the EAC relates has a COD that is no more than 36 months before the hydrogen production facility for which the EAC is retired was placed in service, or, if the electricity represented by the EAC is produced by an electricity generating facility that uses carbon capture and sequestration (CCS) technology, such technology 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.
(B) Uprates—
(1) In general. An EAC meets the requirements of this paragraph (d)(3)(i)(B) if the electricity represented by the EAC is produced by an electricity generating facility that had an uprate no more than 36 months before the hydrogen production facility with respect to which the EAC is retired was placed in service and such electricity is part of such electricity generating facility's uprated production. The term uprate means an increase in an electricity generating facility's rated nameplate capacity (in nameplate megawatts) or capacity measured by a standard other than nameplate capacity (specified capacity) meeting the requirements of the measurement standard described in paragraph (d)(3)(i)(B)(3) of this section. The term pre-uprate capacity means the nameplate capacity or specified capacity of an electricity generating facility before an uprate. The term post-uprate capacity means the nameplate capacity or specified capacity of an electricity generating facility after an uprate. The term incremental generation capacity means the increase in an electricity generating facility's rated nameplate capacity or specified capacity from the pre-uprate capacity to the post-uprate capacity. The term uprated production rate means the incremental generation capacity (in nameplate megawatts) divided by the post-uprate capacity (in nameplate megawatts). The term uprated production means the uprated production rate of an electricity generating facility multiplied by its total generation output (in megawatt hours). An electricity generating facility's uprated production must be prorated to each hour of such facility's generation by multiplying the production for each hour or each year, consistent with the requirements in paragraph (d)(3)(ii) of this section, by the uprated production rate to determine the electricity to which the uprate relates.
(2) Special rule for restarted facilities. For purposes of this paragraph (d)(3)(i)(B), a 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 the following conditions are met:
(i) The existing facility must have ceased operations;
(ii) The existing facility must have a shutdown 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 must not have ceased operations for the purpose of qualifying for the special rule for restarted facilities.
(3) Measurement standard. For purposes of paragraph (d)(3)(i)(B)(1) of this section, taxpayers must use one of the following measurement standards described in paragraph (d)(3)(i)(B)(3)(i), (ii), or (iii) of this section to measure the capacity and change in capacity of a facility, except a taxpayer cannot use the measurement standard described in paragraph (d)(3)(i)(B)(3)(ii) of this section if the taxpayer is able to use the measurement standard described in paragraph (d)(3)(i)(B)(3)(i) of this section:
(i) Modified or amended facility operating licenses from FERC or NRC, or related reports prepared by FERC or NRC as part of the licensing process;
(ii) The International Standard Organization (ISO) conditions to measure the nameplate capacity of the facility consistent with the definition of nameplate capacity provided in 40 CFR 96.202; or
(iii) A measurement standard prescribed by the Secretary in guidance published in the Internal Revenue Bulletin (see § 601.601 of this chapter).
(4) Example. The following example illustrates the application of paragraph (d)(3)(i)(B) of this section.
(i) Facts. Power Plant undergoes an uprate that expands its rated nameplate capacity from a pre-uprate capacity of 10 megawatts (MW) to a post-uprate capacity of 12 MW. After the uprate, its generation output increases to a total of 40,000 megawatt hours (MWh) for the year.
(ii) Analysis. Power Plant's incremental generation capacity is 2 MW, its uprated production rate is 0.167 (2 MW divided by 12 MW), and its total uprated production for the year is 6,667 MWh (2 MW divided by 12 MW multiplied by 40,000 MWh). Two-twelfths (0.167) of each hour of Power Plant's production may be considered uprated production.
(C) Electricity produced in qualifying States. An EAC meets the requirements of this paragraph (d)(3)(i)(C) if the electricity represented by the EAC is produced by an electricity generating facility that is located in a qualifying State, as defined in paragraph (d)(2)(xii) of this section, and the hydrogen production facility acquiring and retiring such EAC is also located in a qualifying State.
(D) Electricity produced by certain nuclear facilities—
(1) In general. An EAC meets the requirements of this paragraph (d)(3)(i)(D) if the electricity represented by the EAC is produced by an electricity generating facility that is a qualifying nuclear reactor, as defined in paragraph (d)(2)(x).
(2) For purposes of paragraph (d)(3)(i) of this section, only 200 megawatt hours of electricity per operating hour per qualifying nuclear reactor may be considered incremental, except that, if a qualifying nuclear reactor has integrated operations with one or more other qualifying nuclear reactors, the amount of electricity from those integrated reactors deemed incremental shall instead be subject to an aggregate limit of 200 megawatt hours per operating hour multiplied by the number of integrated nuclear reactors that have not permanently ceased operations.
(3) A qualifying nuclear reactor is treated as having integrated operations with any other qualifying nuclear reactor if the reactors—
(i) Are owned by the same or related taxpayers; and
(ii) Transmit electricity generated by the reactors through the same point of interconnection or, if the reactors are not grid-connected, or are delivering electricity directly to an end user behind a utility meter, are able to support the same end user, or, if the reactors have multiple points of interconnection, are co-located with each another.
(4) For purposes of paragraph (d)(3)(i)(D)(3)(i) of this section, the term related taxpayers means members of a group of trades or businesses that are under common control (as defined in § 1.52-1(b)). Related taxpayers are treated as one taxpayer in determining whether a qualifying nuclear reactor has integrated operations.
(5) In the case of a nuclear reactor that satisfies the definition of a qualifying nuclear reactor because it is the subject of a written binding contract as provided in paragraph (d)(2)(x)(C)(2) of this section, the megawatt hours of electricity per hour per qualifying nuclear reactor that may be considered incremental are further limited to those megawatt hours of electricity for which the taxpayer acquires EACs from the nuclear reactor pursuant to the written binding contract.
(ii) Temporal matching—
(A) In general. An EAC meets the requirements of this paragraph (d)(3)(ii) if the electricity represented by the EAC is generated in the same hour that the taxpayer's hydrogen production facility uses electricity to produce hydrogen.
(B) Transition rule. For EACs that represent electricity generated before January 1, 2030, the EAC will be considered generated in the same hour that the taxpayer's hydrogen production facility uses electricity to produce hydrogen as required in paragraph (d)(3)(ii)(A) of this section if the electricity represented by the EAC is generated in the same calendar year that the taxpayer's hydrogen production facility uses electricity to produce hydrogen.
(C) Use of energy storage. For purposes of meeting the requirements of paragraph (d)(3)(ii)(A) of this section, an EAC meets such requirements if the electricity represented by the EAC is discharged from a storage system in the same hour that the taxpayer's hydrogen production facility uses electricity to produce hydrogen. The storage system must be located in the same region as both the hydrogen production facility and the facility generating the stored electricity. To use the rule described in this paragraph (d)(3)(ii)(C), the volume of electricity use substantiated by each EAC representing stored electricity must account for storage-related efficiency losses. In addition, to use the rule described in this paragraph (d)(3)(ii)(C), EACs representing stored electricity must comprehensively address the storage of electricity by reflecting the energy attributes of the electricity generating facility that provided electricity to the storage facility, reflecting the temporal attributes regarding when the electricity is discharged from energy storage, and ensuring that paragraph (d)(2)(viii)(C) of this section relating to verification that each EAC is claimed and retired only once applies to EACs representing stored electricity.
(iii) Deliverability—
(A) In general. An EAC meets the requirements of this paragraph (d)(3)(iii) if the electricity represented by the EAC is generated by a facility that is in the same region (as defined in paragraph (d)(2)(ix) of this section) as the hydrogen production facility. Whether the electricity generating source and the hydrogen production facility are located in the same region is determined by the balancing authority to which each is electrically interconnected, not the geographic location.
(B) Interregional delivery. For purposes of meeting the requirements of paragraph (d)(3)(iii)(A) of this section, an EAC meets such requirements if the electricity generation represented by the EAC has transmission rights from the generator location to the region in which the hydrogen production facility is located and that generation is delivered to (i.e., scheduled and dispatched or settled in) such facility's region. Such delivery must be demonstrated on at least an hour-to-hour basis, with no direct counterbalancing reverse transactions, and must be verified with NERC E-tags or the equivalent. In addition, to use the rule described in this paragraph (d)(3)(iii)(B), the qualified EAC registry or accounting system for each eligible EAC representing delivered electricity must track such delivery. Finally, to use the rule described in this paragraph (d)(3)(iii)(B), in the case of electricity imported from Canada or Mexico, the electricity generator must provide an attestation to the hydrogen production facility for purposes of the verification process described in § 1.45V-5 that the use or attributes of the electricity represented by each EAC are not being claimed for any other purpose.
(e) Carbon capture and sequestration. For purposes of the section 45V credit, if a taxpayer determines a lifecycle GHG emissions rate for hydrogen produced at a hydrogen production facility using the 45VH2-GREET Model or the Secretary determines a PER for hydrogen produced at a hydrogen production facility subject to a PER petition, then carbon capture and sequestration may be taken into account only if the carbon capture occurs in the production of qualified clean hydrogen (for subsequent sequestration) or occurs in the production of electricity, fuel, or feedstock that is used by such facility to produce hydrogen and is captured and disposed of in secure geological storage, pursuant to section 45Q(f)(2) and any regulations established thereunder, or utilized in a manner described in section 45Q(f)(5) and any regulations established thereunder. Such carbon capture and sequestration that occurs in the production of qualified clean hydrogen (rather than in the production of electricity, fuel, or feedstock) may only be taken into account if the carbon capture equipment is part of the qualified clean hydrogen production facility.
(f) Use of methane from certain sources to produce hydrogen—
(1) In general. The requirements provided by this paragraph (f) apply to a process (as defined in § 1.45V-1(a)(11)) that uses methane derived from biogas, renewable natural gas (RNG) derived from biogas, or fugitive sources of methane.
(2) Definitions. The following definitions apply for purposes of this paragraph (f):
(i) 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).
(ii) Biogas. The term biogas means gas containing methane that results from the decomposition of organic matter under anaerobic conditions.
(iii) Coal mine methane. The term coal mine methane means methane that is stored within coal seams and is liberated as a result of current or past mining activities. Liberated coal mine methane can be released intentionally by the mine for safety purposes, such as through mine degasification boreholes or underground mine ventilation systems, or it may leak out of the mine through vents, fissures, or boreholes. The term coal mine methane does not include methane removed from virgin coal seams (for example, coal bed methane).
(iv) Fugitive methane. The term fugitive methane means methane released from equipment leaks or venting during the extraction, processing, transformation, or delivery of fossil fuels and other gaseous fuels to the point of final use.
(v) Renewable natural gas. The term renewable natural gas (RNG) means biogas that has been upgraded to remove water, CO2, and other impurities such that it is interchangeable with fossil natural gas.
(vi) Gas energy attribute certificate. The term gas energy attribute certificate (gas EAC) means a tradeable contractual instrument, issued through and retired within a qualified gas EAC registry or accounting system (as defined in paragraph (f)(2)(ix) of this section), that represents the attributes of a specific unit of RNG or coal mine methane. A gas EAC may be traded with or separately from the underlying gas it represents. A gas EAC can be retired by or on behalf of its owner, which is the party that has the right to claim the underlying attributes represented by a gas EAC.
(vii) Eligible gas EAC. The term eligible gas EAC means a gas EAC that represents the quantity of RNG or coal mine methane that is produced by a producing facility that is registered on only one qualified gas EAC registry or accounting system (as defined in paragraph (f)(2)(ix) of this section) and that, with respect to the RNG or coal mine methane to which the gas EAC relates, provides, at a minimum, the following information:
(A) A description of the production facility, including the technology or practice and feedstock used to produce RNG or coal mine methane;
(B) The amount (and units) of RNG or coal mine methane;
(C) The month and year in which the RNG or coal mine methane is produced;
(D) The location at which the RNG or coal mine methane is injected into a natural gas pipeline (or the location of the production facility if directly used without injection into a natural gas pipeline);
(E) The source or sources of the gas that comprises the RNG or coal mine methane associated with each certificate as well as other attributes required by 45VH2-GREET, or in the determination of a PER, to determine the emissions associated with such RNG or coal mine methane; and
(F) A project identification number or assigned identifier.
(viii) Qualifying gas EAC. The term qualifying gas EAC means an eligible gas EAC that meets the requirements of paragraph (f)(4)(iii) of this section and for which the satisfaction of those requirements has been verified by a qualified verifier (as defined in § 1.45V-5(h)).
(ix) Qualified gas EAC registry or accounting system. The term qualified gas EAC registry or accounting system means an electronic tracking system that—
(A) Assigns a unique identification number to each certificate associated with RNG and coal mine methane tracked by such system;
(B) Requires independent verification of the source or sources of the gas that comprises the RNG or coal mine methane and any other factual considerations relevant to the lifecycle GHG emissions assessment for purposes of section 45V for tracking and verification purposes (self-reported data without independent verification are not allowed);
(C) Requires use of a revenue grade meter, with production volumes reported to the registry via an application programming interface (API) or with independent reporting to ensure accurate accounting for production volumes (self-reported data are not allowed);
(D) Enables verification that only one certificate is associated with each unit of RNG or coal mine methane;
(E) Verifies that each certificate is claimed and retired only once;
(F) Identifies the owner of each certificate and provides for documentation of the chain-of-custody of any transfers of certificates;
(G) Requires an attestation that a producer has not registered the RNG or coal mine methane with other registries;
(H) Provides a publicly accessible view (for example, through an application programming interface) of all currently registered RNG or coal mine methane production facilities in the tracking system to prevent the duplicative registration of such production facilities; and
(I) Requires verification of pipeline interconnection, if applicable.
(3) Considerations regarding the lifecycle greenhouse gas emissions associated with the production of hydrogen using methane from certain sources—
(i) In general. For purposes of determining the lifecycle GHG emissions rate of a process (as defined § 1.45V-1(a)(11)) that uses methane derived from biogas, RNG, or fugitive methane to produce hydrogen, estimates of lifecycle GHG emissions must consider all the direct and significant indirect emissions from the hydrogen production process. Such determinations must consider the alternative fates of that methane, including 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.
(ii) Methane from landfill sources. For purposes of determining the lifecycle GHG emissions rate of a process (as defined § 1.45V-1(a)(11)) that uses methane derived from landfill sources, the alternative fate of such gas must be flaring using an efficiency determined by 45VH2-GREET.
(iii) Methane from wastewater sources. For purposes of determining the lifecycle GHG emissions rate of a process (as defined § 1.45V-1(a)(11)) that uses methane derived from wastewater sources, the alternative fate of such gas must assume flaring and use the flaring efficiency and other factors as determined by 45VH2-GREET, including accounting for the proportion of the gas typically used to heat the anaerobic digester.
(iv) Coal mine methane. For purposes of determining the lifecycle GHG emissions rate of a process (as defined § 1.45V-1(a)(11)) that uses coal mine methane, flaring of such gas must be used as the alternative fate.
(v) Methane from animal waste. For purposes of determining the lifecycle GHG emissions rate of a process (as defined § 1.45V-1(a)(11)) that uses methane derived from biogas sourced from animal waste, the emissions associated with producing and transporting such biogas to the point where it is fed into an upgrader must use an alternative fate derived from the national average of all animal waste management practices, which results in a carbon intensity score of -51 grams of CO2e per megajoule (MJ), where the MJ basis refers to the lower heating value of the methane contained in the biogas prior to upgrading.
(vi) Fugitive methane other than coal mine methane. For purposes of determining the lifecycle GHG emissions rate of a process (as defined § 1.45V-1(a)(11)) that uses fugitive methane other than coal mine methane, such as fugitive methane from oil and gas operations, productive use of such gas must be used as the alternative fate, which would result in emissions equivalent to the carbon intensity of using fossil natural gas.
(4) Use of gas EACs—
(i) In general. Subject to paragraph (f)(4)(ii) of this section, for purposes of the section 45V credit, if a taxpayer determines a lifecycle GHG emissions rate for hydrogen produced at a hydrogen production facility using the 45VH2-GREET model or the Secretary determines a PER for hydrogen produced at a hydrogen production facility subject to a PER petition, then the taxpayer may treat such hydrogen production facility's use of RNG (as defined in paragraph (f)(2)(v) of this section) or coal mine methane (as defined in paragraph (f)(2)(iii) of this section) as being from a specific source of such gas rather than fossil natural gas only if the taxpayer acquires and retires qualifying gas EACs (as defined in paragraph (f)(2)(viii) of this section) for each unit of such gas that the taxpayer claims from such source. To satisfy this requirement, a taxpayer's acquisition and retirement of qualifying gas EACs must also be recorded in a qualified gas EAC registry or accounting system (as defined in paragraph (f)(2)(ix) of this section) so that the acquisition and retirement of such gas EACs may be verified by a qualified verifier (as defined in § 1.45V-5(h)). The requirements of this paragraph (f)(4) apply regardless of whether the source of the RNG or coal mine methane is connected to a pipeline network, directly connected to a hydrogen production facility, or co-located with the hydrogen production facility.
(ii) System readiness. Paragraph (f)(4)(i) of this section applies only if the Secretary determines that one or more electronic tracking systems meet the definition of a qualified gas EAC registry or accounting system (as defined in paragraph (f)(2)(ix) of this section). The Secretary may make this determination no earlier than January 1, 2027. Prior to the Secretary making a determination described in this paragraph (f)(4)(ii), a taxpayer using RNG or coal mine methane in a hydrogen production process must substantiate the use of such gas by maintaining a direct pipeline connection to a supplier of such gas or documentation of other physical methods of exclusive delivery of such gas. Prior to the Secretary making a determination described in this paragraph (f)(4)(ii), a taxpayer must ensure that attributes of the RNG or coal mine methane used in a hydrogen production process are not double counted by obtaining attestations from the RNG or coal mine methane producers that there has been and will be no double counting of such attributes. The taxpayer must provide such attestations to the taxpayer's qualified verifier (as defined in § 1.45V-5(h)).
(iii) Qualifying gas EAC requirements. An eligible gas EAC meets the requirements of this paragraph (f)(4)(iii) if it meets the requirements of paragraphs (f)(4)(iii)(A) and (B) of this section.
(A) Temporal matching. An eligible gas EAC meets the requirements of this paragraph (f)(4)(iii)(A) if the RNG or coal mine methane represented by the eligible gas EAC was injected into a pipeline described in paragraph (f)(4)(iii)(B) of this section in the same calendar month that the hydrogen production facility uses the RNG or coal mine methane in the production of hydrogen or, if the RNG or coal mine methane represented by the eligible gas EAC was delivered to the hydrogen production facility from the RNG or coal mine methane producer, through a direct pipeline connection or other physical method of exclusive delivery.
(B) Deliverability. An eligible gas EAC meets the requirements of this paragraph (f)(4)(iii)(B) if the RNG or coal mine methane represented by the eligible gas EAC is injected into a natural gas pipeline in the contiguous United States and the hydrogen production facility is also located in and connected to a natural gas pipeline in the contiguous United States. Alaska, Hawaii, and each U.S. territory are separate regions, such that an eligible gas EAC meets the requirements of this paragraph (f)(4)(iii)(B) if the RNG or coal mine methane represented by the eligible gas EAC is injected into a natural gas pipeline in one of these regions and the hydrogen production facility is located in and connected to a natural gas pipeline in the same region. An eligible gas EAC also meets the requirements of this paragraph (f)(4)(iii)(B) if the RNG or coal mine methane represented by the eligible gas EAC was delivered to the hydrogen production facility from the RNG or coal mine methane producer through a direct pipeline connection or other physical method of exclusive delivery.
(g) Applicability date. This section applies to taxable years beginning after December 26, 2023.

[T.D. 10023; 90 FR 2309, Jan. 10, 2025]

Terms defined here

Where the text says “the term … means”. Select a term to jump to its definition.

Other regulations under § 45V

Cross-references

Computed from the citations in the text of 26 CFR.

Code sections it cites

Regulations it cites

Cited by 5 other regulations

Amendment history

From the source citation at the end of the section, newest first. T.D. is a Treasury decision; FR is the Federal Register.

  1. Issued (90 FR 2309)

Where it sits in 26 CFR

  1. Subchapter A Income tax
  2. Part 1 Income taxes
  3. Rules for computing credit for investment in certain depreciable property

Nearby sections