2224 Federal Register / Vol. 90, No. 6 / Friday, January 10, 2025 / Rules and Regulations 

DEPARTMENT OF THE TREASURY 

Internal Revenue Service 

26 CFR Part 1 

[TD 10023] 

RIN 1545–BQ97 

Credit for Production of Clean 

Hydrogen and Energy Credit 

AGENCY: Internal Revenue Service (IRS), 

Treasury. 

ACTION: Final regulations. 

SUMMARY: This document contains final 

regulations implementing the credit for 

production of clean hydrogen and 

certain provisions of the energy credit as 

enacted by the Inflation Reduction Act 

of 2022. The regulations provide rules 

for: determining lifecycle greenhouse 

gas emissions rates resulting from 

hydrogen production processes; 

petitioning for provisional emissions 

rates; verifying production and sale or 

use of clean hydrogen; modifying or 

retrofitting existing qualified clean 

hydrogen production facilities; using 

electricity from certain renewable or 

zero-emissions sources to produce 

qualified clean hydrogen; and electing 

to treat part of a specified clean 

hydrogen production facility instead as 

property eligible for the energy credit. 

These regulations affect all taxpayers 

who produce qualified clean hydrogen 

and claim the clean hydrogen 

production credit, elect to treat part of 

a specified clean hydrogen production 

facility as property eligible for the 

energy credit, or produce electricity 

from certain renewable or zeroemissions sources used by taxpayers or 

related persons to produce qualified 

clean hydrogen. 

DATES: 

Effective date: These regulations are 

effective January 10, 2025. 

Applicability dates: For dates of 

applicability, see §§ 1.45V–1(d), 1.45V– 

2(d), 1.45V–4(g), 1.45V–5(l), 1.45V–6(d), 

and 1.48–15(h). 

FOR FURTHER INFORMATION CONTACT: 

Courtney Hutson at (202) 317–5319 or 

Alan Tilley at (202) 317–6512 (not tollfree numbers). 

SUPPLEMENTARY INFORMATION: 

Authority 

This document contains final 

regulations that amend the Income Tax 

Regulations (26 CFR part 1) by adding 

regulations authorized to be issued by 

the Secretary of the Treasury or her 

delegate (Secretary) under sections 48 

and 45V of the Internal Revenue Code 

(Code). The final regulations are issued 

under the authority granted under 

sections 45V(c)(1)(B), 45V(e)(5), 45V(f), 

48(a)(15)(C), 48(a)(15)(E), 48(a)(16), 

6001, and 7805(a) of the Code. 

Section 45V(c)(1)(B) provides that 

lifecycle greenhouse gas emissions 

(lifecycle GHG emissions) shall only 

include emissions through the point of 

production (well-to-gate), as determined 

under the most recent Greenhouse 

gases, Regulated Emissions, and Energy 

use in Transportation model (commonly 

referred to as the ‘‘GREET model’’) 

developed by Argonne National 

Laboratory, or a successor model (as 

determined by the Secretary). 

Section 45V(e)(5) directs the Secretary 

to issue regulations and guidance as she 

determines to be necessary to carry out 

the purposes of section 45V(e), which 

relates to the increased credit amount 

for qualified clean hydrogen production 

facilities that satisfy certain prevailing 

wage and apprenticeship requirements. 

Further, section 45V(f) directs the 

Secretary to issue regulations or other 

guidance to carry out the purposes of 

section 45V, including for determining 

lifecycle GHG emissions. 

Section 48(a)(15)(C) provides that the 

term ‘‘specified clean hydrogen 

production facility’’ means any 

qualified clean hydrogen production 

facility (as defined in section 

45V(c)(3))(i) that is placed in service 

after December 31, 2022, (ii) with 

respect to which (I) no section 45V 

credit or section 45Q credit has been 

allowed, and (II) the taxpayer makes an 

irrevocable election to have section 

48(a)(15) apply, and (iii) for which an 

unrelated third party has verified (in 

such form or manner as the Secretary 

may prescribe) that such facility 

produces hydrogen through a process 

that results in lifecycle GHG emissions 

that are consistent with the hydrogen 

that such facility was designed and 

expected to produce under section 

48(a)(15)(A)(ii). 

Section 48(a)(15)(E) directs the 

Secretary to issue such regulations or 

other guidance as she determines 

necessary to carry out the purposes of 

the section 48 energy credit, including 

regulations or guidance related to the 

recapture of such credit that exceeds the 

allowed amount ‘‘if the expected 

production were consistent with the 

actual verified production (or all of the 

credit so allowed in the absence of such 

verification).’’ 

Section 48(a)(16) directs the Secretary 

to issue regulations or other guidance as 

she determines necessary to carry out 

the purposes of the section 48 energy 

credit, including for recordkeeping or 

information reporting requirements 

necessary for the administration of the 

credit. 

Section 6001 provides an express 

delegation of authority to the Secretary, 

stating that, ‘‘[e]very person liable for 

any tax imposed by this title, or for the 

collection thereof, shall keep such 

records, render such statements, make 

such returns, and comply with such 

rules and regulations as the Secretary 

may from time to time prescribe. 

Whenever in the judgment of the 

Secretary it is necessary, [s]he may 

require any person, by notice served 

upon such person or by regulations, to 

make such returns, render such 

statements, or keep such records, as the 

Secretary deems sufficient to show 

whether or not such person is liable for 

tax under this title.’’ 

These regulations are also issued 

under the express delegation of 

authority under section 7805(a), which 

provides that ‘‘[t]he Secretary shall 

prescribe all needful rules and 

regulations for the enforcement of [the 

Code], including all rules and 

regulations as may be necessary by 

reason of any alteration of law in 

relation to internal revenue.’’ 

Background 

This document contains final 

regulations to implement the statutory 

provisions of sections 45V and 48(a)(15) 

of the Code, as enacted by section 13204 

of Public Law 117–169, 136 Stat. 1818, 

1935 (August 16, 2022), commonly 

known as the Inflation Reduction Act of 

2022 (IRA). 

The IRA added several provisions to 

the Code related to the production of, 

and investment in, clean hydrogen, 

which, along with the provisions of 

sections 45V and 48(a)(15), are 

described in part I of this Background 

section. Part II of this Background 

section describes a previous request for 

public comment on these provisions, 

and part III describes the proposed 

regulations promulgated under these 

provisions that the final regulations in 

this document adopt or modify as 

explained in the Summary of Comments 

and Explanation of Revisions. 

I. IRA Provisions for Clean Hydrogen 

Production and Investment 

This part I describes the credit for 

production of clean hydrogen as 

determined under section 45V (section 

45V credit) and the irrevocable election 

to claim an energy credit under section 

48 (section 48 credit) in lieu of the 

section 45V credit. Also described are 

statutory exceptions to the requirement 

that electricity be sold to an unrelated 

person to be eligible for the renewable 

electricity production credit determined 


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Federal Register / Vol. 90, No. 6 / Friday, January 10, 2025 / Rules and Regulations 2225 

1The IRS will publish the inflation-adjusted 

section 45V applicable amount annually. The 

section 45V applicable amounts for calendar years 

2023 and 2024 were published in Notice 2024–45, 

2024–26 I.R.B. 1747. 

2Section 45V(e)(3)(A)(ii) requires the payment of 

wages at prevailing rates ‘‘with respect to any 

taxable year, for any portion of such taxable year 

which is within the period described in subsection 

(a)(2)’’, with respect to the alteration or repair of the 

facility. There is no ‘‘period described in subsection 

(a)(2).’’ The Treasury Department and the IRS 

interpret the reference to ‘‘subsection (a)(2)’’ as a 

reference to section 45V(a)(1) where the 10-year 

credit period is identified. 

3See §§ 1.45–7, 1.45–8, 1.45–12, and 1.45V–3, as 

published in the Federal Register (89 FR 53184) on 

June 25, 2024. 

4Under § 1.45V–3, the PWA requirements for 

purposes of section 45V(e)(2)(B) are satisfied if a 

facility meets the prevailing wage requirements of 

section 45(b)(7) and § 1.45–7, the apprenticeship 

requirements of section 45(b)(8) and § 1.45–8, and 

the recordkeeping and reporting requirements of 

§ 1.45–12. Those regulations are not a part of this 

Treasury decision and § 1.45V–3 is addressed only 

to the extent necessary for purposes of formatting 

the final regulations that are the subject of this 

decision in accordance with CFR standards. 

under section 45 (section 45 credit) or 

the zero-emission nuclear power 

production credit determined under 

section 45U (section 45U credit). Under 

these exceptions, electricity produced 

by a taxpayer from a qualified facility 

under section 45(d) or a qualified 

nuclear power facility under section 

45U(b)(1) may be treated as sold by the 

taxpayer to an unrelated person during 

the taxable year if the electricity is used 

by the taxpayer or a related person at a 

qualified clean hydrogen production 

facility to produce qualified clean 

hydrogen. 

A. Section 45V 

1. Amount of Credit 

Section 45V provides an income tax 

credit for the production of qualified 

clean hydrogen. For purposes of section 

38, section 45V(a) provides that the 

clean hydrogen production credit for 

any taxable year is an amount equal to 

the product of (i) the kilograms of 

qualified clean hydrogen produced by 

the taxpayer during such taxable year at 

a qualified clean hydrogen production 

facility during the 10-year period 

beginning on the date such facility was 

originally placed in service, and (ii) the 

applicable amount as determined under 

section 45V(b) with respect to such 

hydrogen. 

Section 45V(b)(1) provides that, for 

purposes of section 45V(a)(2), the 

applicable amount is an amount equal 

to the applicable percentage of $0.60. If 

the amount so determined is not a 

multiple of 0.1 cent, then such amount 

is rounded to the nearest multiple of 0.1 

cent. 

Section 45V(b)(2) provides that, for 

purposes of section 45V(b)(1), the 

applicable percentage is determined 

based on the lifecycle GHG emissions 

rate of the process used to produce any 

qualified clean hydrogen as follows: (i) 

if the lifecycle GHG emissions rate is 

not greater than 4 kilograms of carbon 

dioxide equivalent (CO2e) per kilogram 

of hydrogen, and not less than 2.5 

kilograms of CO2e per kilogram of 

hydrogen, then the applicable 

percentage is 20 percent; (ii) if the 

lifecycle GHG emissions rate is less than 

2.5 kilograms of CO2e per kilogram of 

hydrogen, and not less than 1.5 

kilograms of CO2e per kilogram of 

hydrogen, then the applicable 

percentage is 25 percent; (iii) if the 

lifecycle GHG emissions rate is less than 

1.5 kilograms of CO2e per kilogram of 

hydrogen, and not less than 0.45 

kilograms of CO2e per kilogram of 

hydrogen, then the applicable 

percentage is 33.4 percent; and (iv) if 

the lifecycle GHG emissions rate is less 

than 0.45 kilograms of CO2e per 

kilogram of hydrogen, then the 

applicable percentage is 100 percent. 

Section 45V(b)(3) provides that the 

$0.60 amount in section 45V(b)(1) is 

adjusted by multiplying such amount by 

the inflation adjustment factor (as 

determined under section 45(e)(2), 

determined by substituting ‘‘2022’’ for 

‘‘1992’’ in section 45(e)(2)(B)) for the 

calendar year in which the qualified 

clean hydrogen is produced. If any 

amount as increased under section 

45V(b)(3) is not a multiple of 0.1 cent, 

such amount is rounded to the nearest 

multiple of 0.1 cent.1

Section 45V(e)(1) provides that, in the 

case of any qualified clean hydrogen 

production facility that satisfies the 

requirements of section 45V(e)(2), the 

amount of the section 45V credit with 

respect to qualified clean hydrogen 

described in section 45V(b)(2) is equal 

to the amount determined under section 

45V(a) (determined without regard to 

section 45V(e)(1)) multiplied by five. 

A qualified clean hydrogen 

production facility meets the 

requirements of section 45V(e)(2) if: (i) 

the facility began construction before 

January 29, 2023, and with respect to 

any taxable year, for any portion of such 

taxable year that is within the 10-year 

period beginning on the date the facility 

is originally placed in service, the 

prevailing wage requirements of section 

45V(e)(3)(A) are met for any alteration 

or repair of the facility that occurs after 

January 29, 2023 (to the extent 

applicable); 2 or (ii) the facility satisfies 

the prevailing wage and apprenticeship 

(PWA) requirements of section 

45V(e)(3)(A) and (4).3

Generally, the prevailing wage 

requirements under section 45V(e)(3)(A) 

with respect to any qualified clean 

hydrogen production facility require the 

taxpayer to ensure that any laborers and 

mechanics employed by the taxpayer or 

by any contractor or subcontractor in (i) 

the construction of such facility, and (ii) 

with respect to any taxable year, for any 

portion of such taxable year that is 

within the 10-year period beginning on 

the date such facility was originally 

placed in service, the alteration or repair 

of such facility, are paid wages at rates 

not less than the prevailing rates for 

construction, alteration, or repair of a 

similar character in the locality in 

which such facility is located as most 

recently determined by the Secretary of 

Labor, in accordance with subchapter IV 

of chapter 31 of title 40 of the United 

States Code, commonly known as the 

Davis-Bacon Act. Correction and 

penalty rules similar to the rules of 

section 45(b)(7)(B) also apply. 

Section 45V(e)(4) provides that rules 

similar to the apprenticeship 

requirements of section 45(b)(8) apply 

for purposes of section 45V(e)(2)(B).4

For purposes of section 45V(a), in the 

case of a qualified clean hydrogen 

production facility that does not satisfy 

the requirements of section 45V(e)(2), 

the amount of the clean hydrogen 

production credit for any taxable year is 

$0.12, $0.15, $0.20, or $0.60 per 

kilogram of qualified clean hydrogen 

produced (before taking into account 

any inflation adjustment under section 

45V(b)(3)), depending on the lifecycle 

GHG emissions rate associated with the 

facility’s hydrogen production process. 

For facilities meeting the requirements 

of section 45V(e)(2), the credit amount 

determined under section 45V(a) (as 

adjusted for inflation subject to section 

45V(b)(3)) is multiplied by five. 

2. Definitions 

a. Lifecycle Greenhouse Gas Emissions 

Section 45V(c)(1)(A) provides that, 

subject to section 45V(c)(1)(B), the term 

‘‘lifecycle greenhouse gas emissions’’ 

has the same meaning given such term 

under section 211(o)(1)(H) of the Clean 

Air Act (42 U.S.C. 7545(o)(1)(H)), as in 

effect on August 16, 2022. Under section 

45V(c)(1)(B), the term ‘‘lifecycle 

greenhouse gas emissions’’ includes 

emissions only through the point of 

production (well-to-gate), as determined 

under the most recent Greenhouse 

gases, Regulated Emissions, and Energy 

use in Transportation model, referred to 

as the ‘‘GREET model’’ commonly and 

in this document, developed by 

Argonne National Laboratory, or a 

successor model as determined by the 

Secretary. 


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2226 Federal Register / Vol. 90, No. 6 / Friday, January 10, 2025 / Rules and Regulations 

5Section 45V does not specify an earliest date on 

which a qualified clean hydrogen production 

facility must begin construction or be placed in 

service to be eligible for the section 45V credit. 

However, the section 45V credit is available for 

qualified clean hydrogen produced after December 

31, 2022. See § 13204(a)(5)(A) of the IRA. Thus, the 

owner of a qualified clean hydrogen production 

facility originally placed in service after December 

31, 2012, could claim the section 45V credit for 

qualified clean hydrogen produced during at least 

some portion of the 10-year period described in 

section 45V(a)(1), provided all other requirements 

are met. 

b. Qualified Clean Hydrogen 

Section 45V(c)(2)(A) provides that the 

term ‘‘qualified clean hydrogen’’ means 

hydrogen that is produced through a 

process that results in a lifecycle GHG 

emissions rate of not greater than 4 

kilograms of CO2e per kilogram of 

hydrogen. Section 45V(c)(2)(B) further 

provides that the term ‘‘qualified clean 

hydrogen’’ does not include any 

hydrogen unless (i) such hydrogen is 

produced (A) in the United States (as 

defined in section 638(1) of the Code) or 

a United States territory (having the 

meaning of the term ‘‘possession’’ as 

defined in section 638(2)), (B) in the 

ordinary course of a trade or business of 

the taxpayer, and (C) for sale or use; and 

(ii) the production and sale or use of 

such hydrogen is verified by an 

unrelated party. 

c. Provisional Emissions Rate 

Section 45V(c)(2)(C) provides that, in 

the case of any hydrogen for which a 

lifecycle GHG emissions rate has not 

been determined for purposes of section 

45V, a taxpayer producing such 

hydrogen may file a petition with the 

Secretary for a determination of the 

lifecycle GHG emissions rate with 

respect to such hydrogen, referred to as 

a ‘‘provisional emissions rate’’ or PER. 

d. Qualified Clean Hydrogen Production 

Facility 

Section 45V(c)(3) provides that the 

term ‘‘qualified clean hydrogen 

production facility’’ means a facility (i) 

owned by the taxpayer, (ii) that 

produces qualified clean hydrogen, and 

(iii) the construction of which begins 

before January 1, 2033.5

3. Special Rules 

a. Treatment of Facilities Owned by 

More Than One Taxpayer 

Section 45V(d)(1) provides that rules 

similar to the rules of section 45(e)(3) 

apply for purposes of section 45V. 

Section 45(e)(3) provides that, in the 

case of a facility in which more than one 

person has an ownership interest, 

except to the extent provided in 

regulations prescribed by the Secretary, 

production from the facility is allocated 

among such persons in proportion to 

their respective ownership interests in 

the gross sales from such facility. 

b. Coordination With Section 45Q 

Section 45V(d)(2) provides that no 

section 45V credit is allowed with 

respect to any qualified clean hydrogen 

produced at a facility that includes 

carbon capture equipment for which a 

credit is allowed to any taxpayer under 

section 45Q (section 45Q credit) for the 

taxable year or any prior taxable year. 

c. Credit Reduced for Tax-Exempt 

Bonds 

Section 45V(d)(3) provides that rules 

similar to the rules under section 

45(b)(3) (credit reduced for tax-exempt 

bonds) apply for purposes of section 

45V. Section 45V(d)(3) is effective for 

facilities that begin construction after 

August 16, 2022. See § 13204(a)(5)(B) of 

the IRA. Section 45(b)(3) provides that 

the amount of the credit determined 

under section 45(a) with respect to any 

facility for any taxable year (determined 

after the application of section 45(b)(1) 

and (2) regarding phaseout and inflation 

adjustment rules) is reduced by the 

amount that is the product of the 

amount so determined for such year and 

the lesser of 15 percent or a fraction (A) 

the numerator of which is the sum, for 

the taxable year and all prior taxable 

years, of proceeds of an issue of any 

obligations the interest on which is 

exempt from tax under section 103 and 

that is used to provide financing for the 

qualified facility, and (B) the 

denominator of which is the aggregate 

amount of additions to the capital 

account for the qualified facility for the 

taxable year and all prior taxable years. 

Section 45(b)(3) further provides that 

the amounts determined under section 

45(b)(3) for any taxable year are 

determined as of the close of the taxable 

year. 

d. Modification of Existing Facilities 

Section 45V(d)(4) provides that for 

purposes of section 45V(a)(1), in the 

case of any facility that (A) was 

originally placed in service before 

January 1, 2023, and, prior to the 

modification described in section 

45V(d)(4)(B), did not produce qualified 

clean hydrogen, and (B) after the date 

such facility was originally placed in 

service (i) is modified to produce 

qualified clean hydrogen, and (ii) 

amounts paid or incurred with respect 

to such modification are properly 

chargeable to the capital account of the 

taxpayer, such facility is deemed to 

have been originally placed in service as 

of the date the property required to 

complete the modification described in 

section 45V(d)(4)(B) is placed in service. 

Section 45V(d)(4) is effective for 

modifications made after December 31, 

2022. See § 13204(a)(5)(C) of the IRA. 

B. Electricity Used at a Qualified Clean 

Hydrogen Production Facility 

Section 45(e)(13) provides that 

electricity produced by the taxpayer is 

treated as sold by such taxpayer to an 

unrelated person during the taxable year 

if (i) such electricity is used during such 

taxable year by the taxpayer or a person 

related to the taxpayer at a qualified 

clean hydrogen production facility (as 

defined in section 45V(c)(3)) to produce 

qualified clean hydrogen (as defined in 

section 45V(c)(2)); and (ii) such use and 

production is verified (in such form or 

manner as the Secretary may prescribe) 

by an unrelated third party. Section 

45(e)(13) is effective for electricity 

produced after December 31, 2022. See 

§ 13204(b)(3) of the IRA. 

Section 45U(c)(2) provides that rules 

similar to the rules of section 45(e)(13) 

apply for purposes of section 45U. 

Generally, section 45U is effective for 

electricity produced at a qualified 

nuclear power facility and sold after 

December 31, 2023, in taxable years 

beginning after that date. 

C. Election To Treat Clean Hydrogen 

Production Facilities as Energy Property 

Section 48(a)(15)(A)(i) provides that, 

in the case of any qualified property (as 

defined in section 48(a)(5)(D)) that is 

part of a specified clean hydrogen 

production facility, such property is 

treated as energy property. Section 

48(a)(15)(A)(ii) provides that the energy 

percentage of the basis of any qualified 

property that is treated as energy 

property is, for a facility that is designed 

and reasonably expected to produce 

qualified clean hydrogen with a 

lifecycle GHG emissions rate that is: (i) 

not greater than 4 kilograms of CO2e per 

kilogram of hydrogen, and not less than 

2.5 kilograms of CO2e per kilogram of 

hydrogen, 1.2 percent; (ii) less than 2.5 

kilograms of CO2e per kilogram of 

hydrogen, and not less than 1.5 

kilograms of CO2e per kilogram of 

hydrogen, 1.5 percent; (iii) less than 1.5 

kilograms of CO2e per kilogram of 

hydrogen, and not less than 0.45 

kilograms of CO2e per kilogram of 

hydrogen, 2 percent; and (iv) less than 

0.45 kilograms of CO2e per kilogram of 

hydrogen, 6 percent. Under section 

48(a)(9), the amount of the section 48 

credit determined for a specified clean 

hydrogen production facility under 

section 48(a)(15) is multiplied by five if 

the facility meets the requirements of 

section 48(a)(9)(B) (regarding 

application of certain maximum net 


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Federal Register / Vol. 90, No. 6 / Friday, January 10, 2025 / Rules and Regulations 2227 

6A comment requested that the Treasury 

Department and the IRS (1) hold additional public 

hearings in, at a minimum, each of the seven 

regions where hydrogen hubs have been proposed; 

(2) provide virtual options for attending and 

presenting; and (3) clarify the process for 

participation at the public hearing. The Treasury 

Department and the IRS held a hearing over three 

days, which provided the public an opportunity to 

present testimony either in person or over the 

telephone. Individuals, whether testifying or not, 

could attend the hearing either in person or by 

telephone. Notice of the hearing was published as 

part of the proposed regulations in the Federal 

Register on December 26, 2023, which provided 

details to the public on how to participate. 

Accordingly, the public was provided a meaningful 

opportunity to participate in the hearing process. 

output levels of electrical or thermal 

energy or prevailing wage and 

apprenticeship requirements). However, 

the domestic content and energy 

communities bonuses under section 

48(a)(12) and (14) do not apply to a 

specified clean hydrogen production 

facility. 

Section 48(a)(15) is effective for 

property placed in service after 

December 31, 2022, and for any 

property the construction of which 

began before January 1, 2023, only to the 

extent of the basis thereof attributable to 

construction, reconstruction, or erection 

after December 31, 2022. See 

§ 13204(c)(3) of the IRA. 

1. Denial of Production Credit 

Section 48(a)(15)(B) provides that no 

section 45V credit or section 45Q credit 

is allowed for any taxable year with 

respect to any specified clean hydrogen 

production facility or any carbon 

capture equipment included at such 

facility. 

2. Specified Clean Hydrogen Production 

Facility 

Section 48(a)(15)(C) provides that the 

term ‘‘specified clean hydrogen 

production facility’’ means any 

qualified clean hydrogen production 

facility (as defined in section 45V(c)(3)) 

(i) that is placed in service after 

December 31, 2022, (ii) with respect to 

which (I) no section 45V credit or 

section 45Q credit has been allowed, 

and (II) the taxpayer makes an 

irrevocable election to have section 

48(a)(15) apply, and (iii) for which an 

unrelated third party has verified (in 

such form or manner as the Secretary 

may prescribe) that such facility 

produces hydrogen through a process 

that results in lifecycle GHG emissions 

that are consistent with the hydrogen 

that such facility was designed and 

expected to produce under section 

48(a)(15)(A)(ii). 

3. Qualified Clean Hydrogen 

Section 48(a)(15)(D) provides that, for 

purposes of section 48(a)(15), the term 

‘‘qualified clean hydrogen’’ has the 

meaning given such term by section 

45V(c)(2). 

4. Regulations 

Section 48(a)(15)(E) requires the 

Secretary to issue regulations or other 

guidance as she determines necessary to 

carry out the purposes of section 48, 

including regulations or other guidance 

that recaptures so much of any section 

48 credit allowed as exceeds the amount 

of the credit that would have been 

allowed if the expected production were 

consistent with the actual verified 

production (or all of the credit so 

allowed in the absence of verification). 

II. Notice 2022–58 

On November 3, 2022, the Department 

of the Treasury (Treasury Department) 

and the IRS published Notice 2022–58, 

2022–47 I.R.B. 483. The notice 

requested general comments on issues 

arising under section 45V and the 

associated clean hydrogen production 

and investment incentives in sections 

45 and 48. The notice also requested 

specific comments concerning (i) 

definitions; (ii) boundaries of the wellto-gate analysis for determining the 

lifecycle GHG emissions rate; (iii) the 

PER process; (iv) recordkeeping and 

reporting; (v) verification by unrelated 

parties; and (vi) coordination with 

sections 45, 48, and 45Q. Stakeholders 

submitted more than 200 comments in 

response to Notice 2022–58, and those 

comments informed the development of 

the proposed regulations. 

III. Proposed Regulations 

On December 26, 2023, the Treasury 

Department and the IRS published 

proposed regulations under sections 

45V and 48(a)(15) (REG–117631–23) in 

the Federal Register (88 FR 89220) to 

provide guidance on the credit for 

production of clean hydrogen and the 

energy credit, respectively (proposed 

regulations). The provisions of the 

proposed regulations are explained in 

greater detail in the preamble to the 

proposed regulations. 

On April 11, 2024, the Treasury 

Department and the IRS published a 

supplemental notice of proposed 

rulemaking under sections 45V and 

48(a)(15) in the Federal Register (89 FR 

25551) inviting comments on the U.S. 

Department of Energy’s (DOE) 

information collection related to the 

DOE’s Emissions Value Request Process 

(EVRP) for use by applicants in 

obtaining an emissions value in support 

of a petition for a PER, as set forth in 

the proposed regulations. The EVRP is 

explained in greater detail in the 

supplemental notice of proposed 

rulemaking. On September 30, 2024, the 

DOE announced the opening of the 

EVRP. See Notice of Availability of the 

45V Emissions Value Request Process 

(89 FR 80898). 

Summary of Comments and Explanation 

of Revisions 

This Summary of Comments and 

Explanation of Revisions summarizes 

the proposed regulations and all the 

substantive comments submitted in 

response to the proposed regulations. 

The Treasury Department and the IRS 

received approximately 30,000 written 

comments in response to the proposed 

regulations. The comments are available 

for public inspection at 

www.regulations.gov or upon request. A 

hearing was conducted in person and 

telephonically on March 25, 26, and 27, 

2024, during which approximately 100 

individuals testified.6 After full 

consideration of the hearing testimony 

and the comments received, these final 

regulations adopt the proposed 

regulations with modifications in 

response to the comments described in 

this Summary of Comments and 

Explanation of Revisions. 

The Treasury Department and the IRS 

also consulted extensively with 

scientific and technical experts from 

across the Federal government, 

including personnel from the DOE and 

the U.S. Environmental Protection 

Agency (EPA), in developing and 

drafting these final regulations. The 

Treasury Department and the IRS had 

regular meetings with these experts 

from the time that sections 45V and 

48(a)(15) were enacted through the 

drafting and publication of the proposed 

regulations and the final regulations. 

The conclusions reached in these final 

regulations and explained in this 

Summary of Comments and Explanation 

of Revisions were deeply informed by 

the scientific and technical expertise 

that was shared by these experts. 

Comments merely summarizing the 

proposed regulations, expressing 

generic, non-specific, or extraneous 

concerns, recommending statutory 

revisions to sections 45V, 48(a)(15), or 

other statutes, or addressing issues that 

do not pertain to the purposes of 

sections 45V and 48(a)(15) are not 

applicable to this rulemaking and are 

not adopted. Additionally, except to the 

extent discussed in this Summary of 

Comments and Explanation of 

Revisions, comments addressing the 

features of 45VH2–GREET or the 

contents of any supporting 

documentation to be provided in 

seeking an emissions value from the 

DOE are outside the scope of this 


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2228 Federal Register / Vol. 90, No. 6 / Friday, January 10, 2025 / Rules and Regulations 

rulemaking and therefore are not 

addressed herein. 

I. General Rules and Definitions 

Proposed § 1.45V–1 provided 

definitions of key terms used in 

proposed §§ 1.45V–1 through 1.45V–6 

and 1.48–15, to determine eligibility for, 

and the amount of, the section 45V 

credit for production of clean hydrogen. 

Comments addressed several of the 

proposed definitions, as described in 

this part I.A of the Summary of 

Comments and Explanation of 

Revisions. 

In addition, these final regulations 

add the new terms ‘‘hydrogen gas 

stream,’’ ‘‘mixed gas or impurity,’’ and 

‘‘productive use,’’ which are discussed 

in part I.A.5 of the Summary of 

Comments and Explanation of 

Revisions, as well as the terms 

‘‘process’’ and ‘‘primary feedstock,’’ 

which are discussed in part I.A.7. With 

respect to the definition of ‘‘lifecycle 

GHG Emissions,’’ the final regulations 

add a new rule for certain emissions 

related to purification treated as through 

the point of production, which is 

discussed in part I.A.6.d of the 

Summary of Comments and Explanation 

of Revisions. The final regulations 

renumber the definitions to incorporate 

the added definitions. 

A. Definitions 

1. Applicable Amount 

Section 45V(b)(1) defines applicable 

amount, and section 45V(b)(3) provides 

the inflation adjustment that applies 

when calculating the applicable 

amount. Proposed § 1.45V–1(a)(2) 

would have adopted this definition and 

its related inflation adjustment 

provision. No comments addressed 

these provisions, and these final 

regulations adopt them as proposed. 

2. Applicable Percentage 

Section 45V(b)(2) defines the term 

‘‘applicable percentage.’’ Proposed 

§ 1.45V–1(a)(3) adopted this definition. 

No comments addressed this provision, 

and these final regulations adopt the 

definition as proposed. 

3. Claim 

Proposed § 1.45V–1(a)(4) would have 

provided that, with respect to the 

section 45V credit determined for 

qualified clean hydrogen produced by 

the taxpayer at a qualified clean 

hydrogen production facility, the term 

‘‘claim’’ means the filing of a completed 

Form 7210, Clean Hydrogen Production 

Credit, or any successor form(s), with 

the taxpayer’s Federal income tax return 

or annual information return for the 

taxable year in which the credit is 

determined, and includes the making of 

an election under section 6417 or 

section 6418 and the regulations 

thereunder, with respect to such section 

45V credit on the applicable entity’s or 

eligible taxpayer’s timely filed 

(including extensions) Federal income 

tax return or annual information return. 

One comment requested that the final 

regulations offer a streamlined process 

to claim the section 45V credit for small 

producers of hydrogen. Section 45V 

does not make any distinction based on 

the size of the hydrogen producer, and 

the importance of reporting and 

compliance are the same regardless of 

the producer’s size. Accordingly, 

providing a more streamlined process 

for claiming the section 45V credit for 

small producers is not appropriate. 

Additionally, to clarify, section 1.45V– 

1(a)(4) has no effect on the procedures 

for making an election under section 

6417 or 6418, the requirements for 

which are described in the regulations 

for each provision. For procedures for 

making an election under section 6417, 

see § 1.6417–2(b). For procedures for 

making an election under section 6418, 

see § 1.6418–2. Accordingly, section 

1.45V–1(a)(4) is adopted without 

change. 

4. Facility 

a. Equipment Included in the Definition 

of Facility 

Proposed § 1.45V–1(a)(7)(i) would 

have provided that, for purposes of the 

definition of qualified clean hydrogen 

production facility provided at section 

45V(c)(3), the term ‘‘facility’’ means a 

single production line that is used to 

produce qualified clean hydrogen, 

unless otherwise specified. Further, 

proposed § 1.45V–1(a)(7)(i) would have 

provided that a ‘‘single production line’’ 

includes all components of property 

that function interdependently to 

produce qualified clean hydrogen. 

Components of property would be 

functionally interdependent if the 

placing in service of each component 

were dependent upon the placing in 

service of each of the other components 

to produce qualified clean hydrogen. 

Proposed § 1.45V–1(a)(7)(iii) would 

have provided that components that 

have a purpose in addition to the 

production of qualified clean hydrogen 

may be part of a facility if such 

components function interdependently 

with other components to produce 

qualified clean hydrogen. Proposed 

§ 1.45V–1(a)(7)(iv) would have provided 

an example to illustrate the definition of 

facility for purposes of section 45V. 

Comments asked a variety of 

questions about the definition of 

‘‘facility,’’ including whether specific 

equipment is part of a facility. Some 

comments requested clarification on the 

meaning of ‘‘single production line’’ and 

‘‘functional interdependence’’ and 

whether components of a facility that 

produce hydrogen as a by-product of 

another production process are part of a 

‘‘single production line’’ that is used to 

produce hydrogen. Other comments 

asked for clarification on whether 

designated spaces and equipment 

necessary for commercial operation, but 

not necessary for hydrogen production 

(for example, break rooms and lighting) 

are part of the ‘‘facility.’’ Another 

comment requested that the final 

regulations specify a method for 

allocating lifecycle GHG emissions 

across multipurpose components. The 

comment suggested that, in many cases, 

it would not be appropriate to include, 

through the point of production, all 

lifecycle GHG emissions from 

multipurpose components that are part 

of the balance of plant, such as the 

cooling tower or air compressor if the 

hydrogen production process does not 

consume a significant amount of energy 

from the use of such equipment. 

One comment recommended that the 

final rules modify the definition of 

‘‘facility’’ to include all electrolyzers 

within the balance of plant to prevent 

hydrogen producers from designating 

one electrolyzer as having produced 

hydrogen without energy attribute 

certificates (EACs) should a producer 

not have EACs sufficient to ensure all 

hydrogen produced at a facility is 

qualified clean hydrogen. 

Another comment asked whether the 

definition of ‘‘facility’’ in proposed 

§ 1.45V–1(a)(7) would create a ‘‘circular 

loop’’ wherein the hydrogen producer 

would need to identify the components 

of the facility in order to obtain an 

emissions rate under 45VH2–GREET, 

but could not identify the components 

of the facility without knowing whether 

the facility produces hydrogen at an 

emissions rate of not greater than 4 

kilograms of CO2e per kilogram of 

hydrogen. 

One comment requested clarification 

that the definition of facility in 

proposed § 1.45V–1(a)(7) does not apply 

for purposes of the definition of 

‘‘industrial facility’’ in § 1.45Q–2(d). 

One comment requested clarification 

on whether a facility includes 

downstream property that uses the 

hydrogen produced at a qualified clean 

hydrogen production facility. Similarly, 

one comment requested clarification on 

whether hydrogen production 

equipment that is installed on the 

property of an industrial plant or a gas 

utility qualifies as a ‘‘facility.’’ Although 


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unclear, this comment appears to be 

requesting clarification whether an 

existing industrial plant or gas utility 

becomes a hydrogen production facility 

if hydrogen production equipment is 

added to the existing plant or utility. 

In response to these comments 

seeking clarification on what is 

included in the definition of facility, 

these final regulations modify proposed 

§ 1.45V–1(a)(7)(i) and (iv), as well as 

§ 1.45V–1(a)(7)(ii), which identifies 

equipment that is not included in the 

definition of facility. Generally, the 

definition of ‘‘facility’’ is sufficiently 

clear as an established tax concept. The 

concept of ‘‘functional 

interdependence’’ has been used by 

courts for many years to decide whether 

property was placed in service for 

depreciation and the investment tax 

credit. See, for example, Armstrong 

World Industries, Inc. v. Commissioner, 

974 F.2d 422, 434 (3d Cir. 1992) 

(‘‘[C]ourts appear to agree that 

individual components will be 

considered as a single property for tax 

purposes—when the component parts 

are functionally interdependent when 

each component is essential to the 

operation of the project as a whole and 

cannot be used separately to any 

effect.’’). The general definition of 

facility in proposed § 1.45V–1(a)(7)(i) 

uses this ‘‘functional interdependence’’ 

concept by indicating that a single 

production line includes all 

components of property that function 

interdependently to produce qualified 

clean hydrogen. To ease the 

determination of what equipment is 

included, the final regulations add to 

this definition the phrase ‘‘through a 

process that results in the lifecycle GHG 

emissions rate used to determine the 

credit.’’ This clarifies that all equipment 

used to produce the qualified clean 

hydrogen for which the section 45V 

credit is determined is included as part 

of the qualified clean hydrogen facility. 

For example, carbon capture equipment 

is part of the facility if it contributes to 

the lifecycle GHG emissions rate of the 

process by which the qualified clean 

hydrogen for which the credit is 

determined is produced. In addition, 

these final regulations update the 

example in § 1.45V–1(a)(7)(iv) to reflect 

the modifications made to the text in 

§ 1.45V–1(a)(7)(i). 

Purification equipment is part of the 

facility if such equipment contributes to 

the purity content of the qualified clean 

hydrogen for which the section 45V 

credit is determined. As discussed in 

part I.A.6.c of this Summary of 

Comments and Explanation of 

Revisions, purification equipment that 

is used downstream of the facility’s 

process of producing qualified clean 

hydrogen is not part of the facility, but 

in certain circumstances, emissions 

from such purification equipment are 

within the well-to-gate system boundary 

for purposes of the lifecycle GHG 

emissions rate analysis. 

Regarding multipurpose components, 

these final regulations adopt proposed 

§ 1.45V–1(a)(7)(iii) with a clarification 

that production is for qualified clean 

hydrogen. Proposed § 1.45V–1(a)(7)(iii) 

already clarifies that components can 

have multiple purposes, including but 

not limited to the production of 

qualified clean hydrogen, so long as the 

components function interdependently 

with other components to produce 

qualified clean hydrogen. With respect 

to the allocation of lifecycle GHG 

emissions attributed to multipurpose 

components, taxpayers must use a 

reasonable method to allocate the inputs 

used to determine such emissions. 

To the extent a facility produces 

hydrogen as a by-product of another 

production process, any components of 

the facility that function 

interdependently to produce qualified 

clean hydrogen—regardless of whether 

they serve a purpose in addition to the 

production of qualified clean 

hydrogen—are part of the qualified 

clean hydrogen production facility. 

With respect to whether equipment 

necessary for commercial operation, but 

not for hydrogen production, is part of 

the ‘‘facility’’ (such as break room 

lighting), § 1.45V–1(a)(7)(i) answers this 

question. If the placing in service of 

such equipment is not necessary to 

produce qualified clean hydrogen and is 

not part of the process that results in the 

lifecycle GHG emissions rate used to 

determine the credit, such equipment 

does not function interdependently with 

the qualified clean hydrogen production 

equipment and is not part of the 

‘‘facility.’’ If such non-functionally 

interdependent equipment draws from 

the same electricity source as the 

facility, to the extent it is separately 

metered, such electricity usage would 

not be an input into 45VH2–GREET. To 

the extent such equipment is not 

separately metered, taxpayers must use 

a reasonable method to allocate such 

electricity usage. 

The final regulations do not adopt the 

comment to revise the definition of 

‘‘facility’’ to include all electrolyzers 

within the balance of plant. Under 

§ 1.45V–1(a)(7)(i), to the extent each 

electrolyzer produces qualified clean 

hydrogen separately from the other 

electrolyzers (that is, does not function 

interdependently with the other 

electrolyzers), each electrolyzer is 

treated as a separate facility. Treating 

each electrolyzer within the balance of 

plant as a separate facility is consistent 

with Revenue Ruling 94–31, 1994–1 

C.B. 16, which held that each wind 

turbine within a windfarm is a separate 

‘‘qualified facility’’ under section 45 

because each wind turbine can be 

separately operated and metered to 

produce electricity. Similar to a wind 

turbine within a wind farm, an 

electrolyzer within the balance of plant 

functions separately from the other 

electrolyzers to produce hydrogen. As to 

the concern that EACs may be shifted 

from one electrolyzer to another 

electrolyzer within the balance of plant, 

a hydrogen producer is free to acquire 

and retire EACs for some electrolyzers 

and not for others, no matter the 

production technology the electrolyzers 

use and no matter the extent of their colocation, so long as the retired EACs are 

matched to a particular electrolyzer’s 

electricity consumption from which 

hydrogen is produced. Imposing a rule 

that co-located electrolyzers are 

considered part of the same facility so 

that they each receive an equal 

allocation of EACs would not 

necessarily reflect each electrolyzer’s 

electricity consumption and would be 

inconsistent with existing tax law’s 

treatment of the definition of ‘‘facility.’’ 

In response to the comment that 

questioned whether the definition of 

‘‘facility’’ in § 1.45V–1(a)(7) creates a 

‘‘circular loop,’’ these final regulations 

modify proposed § 1.45V–1(a)(7)(i) to 

provide that equipment is part of the 

facility if it functions interdependently 

to produce qualified clean hydrogen 

through a process that results in the 

lifecycle GHG emissions rate used to 

determine the credit. The lifecycle GHG 

emissions analysis of the hydrogen 

production process is not coextensive 

with the tax definition of a hydrogen 

production facility. For example, 

lifecycle GHG emissions include 

emissions from stages of the hydrogen 

production process beyond the 

hydrogen production facility, such as 

emissions from growth, gathering, 

extraction, processing, and delivery of 

feedstock to a hydrogen production 

facility. See section 45V(c)(1)(A) 

(defining lifecycle GHG emissions by 

reference to section 211(o)(1)(H) of the 

Clean Air Act) and (B) (describing that 

lifecycle GHG emissions include 

emissions through the point of 

production (well-to-gate)); see also 

Guidelines to Determine Well-to-Gate 

Greenhouse Gas (GHG) Emissions of 

Hydrogen Production Pathways using 

45VH2–GREET (45VH2–GREET User 

Manual), § 2.4.1 (Emissions of 

Electricity Generation), which can be 


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2230 Federal Register / Vol. 90, No. 6 / Friday, January 10, 2025 / Rules and Regulations 

found at www.energy.gov/45vresources. 

The Summary of Comments and 

Explanation of Revisions to these final 

regulations generally refer to the 

45VH2–GREET User Manual as it is 

currently publicly available, but at times 

references intended modifications to it. 

As further discussed in the Summary of 

Comments and Explanation of Revisions 

to these final regulations, the DOE 

intends to release a new version of 

45VH2–GREET with an accompanying 

user manual in January 2025. 

Regarding whether a ‘‘facility’’ 

includes downstream property that uses 

hydrogen produced at a qualified clean 

hydrogen production facility, 

downstream property that does not 

contribute to the facility’s process of 

producing qualified clean hydrogen— 

but instead only to the later use of such 

hydrogen following its production—is 

not part of the facility because it does 

not function interdependently in the 

production of the qualified clean 

hydrogen for which the section 45V 

credit is determined. Further, § 1.45V– 

1(a)(7)(ii) provides that the facility does 

not include equipment used to 

condition or transport hydrogen beyond 

the point of production. 

Regarding the effect of § 1.45V–1(a)(7) 

on the definition of industrial facility 

under § 1.45Q–2(d), whether and the 

extent to which the section 45V 

regulations affect terms defined in 

section 45Q is a matter that falls within 

the scope of section 45Q and is therefore 

not applicable to these regulations. 

Regarding whether an industrial plant 

or gas utility becomes part of the 

hydrogen production ‘‘facility’’ when 

hydrogen production equipment is 

installed at the plant or utility, such an 

inquiry will depend on the facts and 

circumstances of the particular 

hydrogen production equipment and 

whether such equipment functions 

interdependently with the existing 

industrial plant or utility equipment to 

produce hydrogen. Accordingly, these 

final regulations provide sufficient 

criteria to apply to such an inquiry on 

a case-by-case basis. 

b. Equipment Excluded From the 

Definition of Facility 

Proposed § 1.45V–1(a)(7)(ii) would 

have provided that a facility does not 

include equipment used to condition or 

transport hydrogen beyond the point of 

production. Proposed § 1.45V–1(a)(7)(ii) 

also would have provided that a facility 

does not include electricity production 

equipment used to power the hydrogen 

production process, including any 

carbon capture equipment associated 

with the electricity production process. 

Some comments requested 

clarification that a ‘‘facility’’ does not 

include upstream facilities that generate 

and supply electricity, fuel, feedstock, 

water, ammonia, or other inputs into or 

for use at the hydrogen production 

facility. Another comment requested 

confirmation that a facility producing 

renewable natural gas (RNG) that is 

supplied to a facility that uses the RNG 

to produce hydrogen does not fall 

within the definition of ‘‘facility.’’ 

One comment recommended that the 

final rules exclude from the definition 

of ‘‘facility’’ any facility that includes an 

electrolyzer stack that was assembled in 

or by a ‘‘Covered Nation’’ as defined in 

10 U.S.C. 4872(d)(2), or a ‘‘Foreign 

Entity of Concern,’’ as referenced under 

§ 40207 of the Infrastructure Investment 

and Jobs Act, Public Law 117–58. 

The Treasury Department and the IRS 

agree that clarification is needed on 

whether feedstock production 

equipment is part of the ‘‘facility.’’ In 

addition, clarification is needed on 

whether feedstock recovery equipment 

is part of the ‘‘facility.’’ Although 

proposed § 1.45V–1(a)(7)(ii)(B) would 

have excluded electricity production 

equipment from the definition of 

‘‘facility,’’ the proposed rules would not 

have addressed other types of feedstock 

production and recovery equipment, 

such as RNG production equipment. 

The intent of the proposed rules was to 

exclude upstream feedstock production 

and recovery equipment, such as RNG 

production equipment, from the 

definition of facility. Accordingly, these 

final regulations add ‘‘feedstock-related 

equipment, including production, 

purification, recovery, transportation, or 

transmission equipment’’ to the list of 

items excluded from the definition of 

facility in § 1.45V–1(a)(7)(ii)(B). As 

discussed in this part I.A.6.c of this 

Summary of Comments and Explanation 

of Provisions, however, lifecycle GHG 

emissions associated with feedstock 

growth, gathering, extraction, 

processing, and delivery to a hydrogen 

production facility are still included in 

the lifecycle GHG analysis reflected in 

45VH2–GREET. 

As to excluding components 

assembled in or by a ‘‘Covered Nation’’ 

or a ‘‘Foreign Entity of Concern’’ from 

the definition of facility, there is no 

provision of section 45V that imposes 

such a rule, so these final regulations do 

not adopt this comment. 

5. Hydrogen Gas Stream, Mixed Gas or 

Impurity, and Productive Use 

The final regulations add three new 

definitions, ‘‘hydrogen gas stream,’’ to 

§ 1.45V–1(a)(8); ‘‘mixed gas or 

impurity,’’ to § 1.45V–1(a)(10); and 

‘‘productive use’’ to § 1.45V–1(a)(12). 

The term ‘‘hydrogen gas stream’’ means 

a flow of gases that includes hydrogen, 

either alone or with one or more other 

gases. The term ‘‘mixed gas or impurity’’ 

means a non-hydrogen gas that is part 

of a hydrogen gas stream. 

The term ‘‘productive use’’ means, 

with respect to a hydrogen gas stream, 

a consumption of the hydrogen gas 

stream in a manner that generates 

positive economic value, which is 

determined without regard to the 

availability of the section 45V credit. 

The term ‘‘productive use’’ means, with 

respect to qualified clean hydrogen, a 

consumption of qualified clean 

hydrogen in a manner that generates 

positive economic value, which is 

determined without regard to the 

availability of the section 45V credit. 

Positive economic value is determined 

without regard to the section 45V credit, 

consistent with the anti-abuse rule of 

§ 1.45V–2(b). Thus, for example, a 

hydrogen gas stream produced with the 

primary purpose of obtaining the benefit 

of the section 45V credit in a wasteful 

manner would not have a productive 

use. 

All three terms are relevant to the rule 

where certain emissions related to 

purification are treated as through point 

of production, described in part I.A.6.d 

of this Summary of Comments and 

Explanation of Revisions. The term 

‘‘productive use’’ also relates to the antiabuse rule described in part II.B of this 

Summary of Comments and Explanation 

of Revisions. 

6. Lifecycle GHG Emissions 

Section 45V(c)(1)(A) provides that, 

subject to section 45V(c)(1)(B), the term 

‘‘lifecycle greenhouse gas emissions’’ 

has the same meaning given such term 

under section 211(o)(1)(H) of the Clean 

Air Act (42 U.S.C. 7545(o)(1)) as in 

effect on the date of enactment of 

section 45V. Section 45V(c)(1)(B) 

provides that the term ‘‘lifecycle 

greenhouse gas emissions’’ only 

includes emissions through the point of 

production (well-to-gate), as determined 

under the most recent GREET model, or 

a successor model (as determined by the 

Secretary). Proposed § 1.45V–1(a)(8) 

would have defined ‘‘lifecycle GHG 

emissions.’’ The final regulations 

renumber proposed § 1.45V–1(a)(8) to 

§ 1.45V–1(a)(9). 

Proposed § 1.45V–1(a)(8)(i) would 

have incorporated the statutory 

definitions provided in section 

45V(c)(1)(A) and (B), specifically 

providing that the term has the same 

meaning as that in section 211(o)(1)(H) 

of the Clean Air Act as in effect on 

August 16, 2022, and includes 


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7Regulatory Impact Analysis, Renewable Fuel 

Standard Program, U.S. Environmental Protection 

Agency, EPA–420–R–10–10–006, at 311–312 (Feb. 

2010), available at https://www.regulations.gov/ 

document/EPA-HQ-OAR-2021-0324-0652. 

8See generally GREET, Office of Energy 

Efficiency & Renewable Energy, U.S. Department of 

Energy, available at https://www.energy.gov/eere/ 

greet. 

emissions only through the point of 

production (well-to-gate) as determined 

under the most recent GREET model, or 

a successor model. These final 

regulations modify proposed § 1.45V– 

1(a)(8)(i) to provide that, for purposes of 

section 45V, lifecycle GHG emissions 

are determined under the 45VH2– 

GREET Model. No comments were 

received on § 1.45V–1(a)(8)(i), and this 

provision is adopted as renumbered 

§ 1.45V–1(a)(9)(i) without further 

changes. 

By reference to section 211(o)(1)(H) of 

the Clean Air Act, section 45V(c)(1)(A) 

requires a complete assessment of direct 

and significant indirect emissions 

associated with a hydrogen production 

process. After consultation with the 

DOE and the EPA, the Treasury 

Department and the IRS interpret 

section 45V(c)(1)(A) with its reference to 

section 211(o)(1)(H) of the Clean Air Act 

as excluding emissions related to the 

manufacturing of the equipment within 

the hydrogen production pathway (for 

example, power generators, hydrogen 

production facility), from the definition 

of lifecycle GHG emissions. This 

interpretation is consistent with how 

EPA has implemented section 

211(o)(1)(H) of the Clean Air Act for the 

Renewable Fuel Standard (RFS) 

program.7

a. Most Recent GREET Model 

Proposed § 1.45V–1(a)(8)(ii) would 

have provided that, for purposes of the 

section 45V credit, the term ‘‘most 

recent GREET model’’ means the latest 

version of 45VH2–GREET developed by 

Argonne National Laboratory and 

published by the DOE, as provided in 

the instructions to the latest version of 

Form 7210, Clean Hydrogen Production 

Credit, or any successor form(s), 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. 

Proposed § 1.45V–1(a)(8)(ii) would have 

further provided that, if a version of 

45VH2–GREET becomes publicly 

available after the first day of the taxable 

year of production (but still within such 

taxable year), then the taxpayer could, 

in its discretion, treat such later version 

of 45VH2–GREET as the most recent 

GREET model. 

Several comments recommended 

changes to proposed § 1.45V–1(a)(8)(ii). 

Some comments requested that, instead 

of identifying 45VH2–GREET as the 

‘‘most recent GREET model’’ under 

section 45V(c)(1)(B), the final 

regulations identify the R&D GREET 

model developed by Argonne National 

Laboratory and published by the DOE as 

the most recent GREET model. 

Comments further recommended that 

the final regulations require the use of 

45VH2–GREET as a ‘‘successor model’’ 

only if 45VH2–GREET closely aligns in 

function and principle with the version 

of the R&D GREET model as it existed 

at the time that section 45V was 

enacted. Other comments supported 

45VH2–GREET as the best available 

open-source lifecycle analysis 

methodology for determining lifecycle 

GHG emissions for purposes of section 

45V. Yet another comment 

recommended that a model the 

comment had developed should be able 

to be used as an alternative to 45VH2– 

GREET. 

Except for changing the nomenclature 

of the ‘‘most recent GREET model’’ to 

the ‘‘45VH2–GREET Model,’’ as further 

discussed in this part I.A.6.a of the 

Summary of Comments and Explanation 

of Revisions, these final regulations do 

not adopt the comments recommending 

changes to proposed § 1.45V–1(a)(8)(ii). 

Though the Treasury Department and 

the IRS continue to view 45VH2–GREET 

as the most recent GREET model for the 

reasons described in the preamble to the 

proposed regulations and the fact that it 

was developed more recently than the 

R&D GREET model, the Treasury 

Department and the IRS recognize that 

the continued existence of the R&D 

GREET model and periodic updates to 

both 45VH2–GREET and the R&D 

GREET model have created some 

uncertainty in this regard. To avoid any 

potential uncertainty about the meaning 

of the most recent GREET model, which 

would be detrimental to the 

administration and implementation of 

the section 45V credit, the Secretary is 

invoking her express delegation of 

authority in section 45V(c)(1)(B) to 

determine 45VH2–GREET to be a 

‘‘successor model’’ and to require its 

use. 

In selecting 45VH2–GREET rather 

than the R&D GREET model or some 

other model, the Treasury Department 

and the IRS considered the statutory 

definition of lifecycle GHG emissions in 

section 211(o)(1)(H) of the Clean Air Act 

(as in effect on August 16, 2022) and the 

specific objectives of section 45V, and 

consulted with the DOE. 45VH2–GREET 

best meets these parameters. It is a 

model specifically developed by the 

Argonne National Laboratory as a 

derivative of and successor to the R&D 

GREET model, designed specifically to 

address hydrogen production processes 

and to meet the requirements and 

objectives of section 45V. 

The R&D GREET model has been 

maintained by the DOE since 1995 to 

enable research regarding lifecycle 

analyses of hundreds of different 

methods of producing, delivering, and 

using energy. The model includes many 

fuels other than hydrogen (for example, 

biofuels, synthetic fuels, fossil fuels, 

and electrification), and includes 

information that is based on preliminary 

analyses (that is, analyses that are not 

yet complete, have significant technical 

uncertainties, or are still being reviewed 

by laboratory staff, DOE staff, or 

independent experts).8 Annual updates 

to the model inform academic studies, 

informally guide decarbonization 

strategies and research and development 

funded by both the DOE and industry, 

and elicit stakeholder feedback that can 

improve the model, particularly with 

regard to preliminary pathways. R&D 

GREET is a valuable tool to characterize 

the benefits and impacts of energy 

technologies in a directional manner 

and to test out new and updated data 

and parameters, but it is not appropriate 

for use in analyses where a relatively 

high degree of precision and certainty is 

required, given the preliminary nature 

of much of the information represented, 

and where specific emissions fluxes and 

their representation are needed in a 

specific fashion (for example, to meet 

specifications within the statute). 

Moreover, because the R&D GREET 

model offers users many choices 

regarding analysis methodology (for 

example, co-product accounting, system 

boundaries, and global warming 

potential values), different users can 

achieve significantly different estimated 

GHG emissions rates even when 

representing the same facility. Many of 

these choices would not be appropriate 

in the specific context of the section 

45V credit given the preliminary nature 

of much of the data underlying aspects 

of the R&D GREET model and the fact 

that the model does not require the use 

of specific methodologies and 

accounting parameters. Accordingly, 

R&D GREET does not provide the degree 

of certainty, structure, and specificity 

necessary to meet the statutory 

requirement of reflecting lifecycle GHG 

emissions as defined by section 

211(o)(1)(H) of the Clean Air Act (as in 

effect on August 16, 2022), nor does it 

meet the specific objectives of such 

section or of the section 45V credit. 


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9Summary of Expansions and Updates in R&D 

GREET 2023 (2023), Argonne National Laboratory, 

available at https://greet.anl.gov/files/greet-2023- 

summary (R&D GREET Supporting Documentation). 

10For example, in a December 13, 2023, letter to 

the Treasury Department, the EPA noted that it has 

interpreted section 211(o)(1)(H) of the Clean Air Act 

in the context of the Clean Air Act’s RFS program. 

In that context, the EPA had previously determined 

that the version of ANL GREET that existed in 2010 

(that is, R&D GREET) was not sufficient to calculate 

lifecycle GHG emissions for purposes of 

211(o)(1)(H) of the Clean Air Act. The EPA also 

explained that the more recent version of ANL 

GREET that existed as of December 2023 similarly 

did not satisfy the relevant Clean Air Act criteria 

because it did not include the significant direct and 

indirect emissions that the EPA had previously 

determined were necessary. See Letter from Joseph 

Goffman, Principal Deputy Assistant Administrator 

for the Office of Air and Radiation, U.S. 

Environmental Protection Agency, to Lily 

Batchelder, Assistant Secretary for Tax Policy, U.S. 

Department of the Treasury (Dec. 13, 2023), 

available at https://home.treasury.gov/system/files/ 

136/Final-EPA-letter-to-UST-on-SAF-signed.pdf. 

In addition, implementation of the 

section 45V credit will be aided by a 

user-friendly model that characterizes 

the lifecycle GHG emissions rates of 

different hydrogen production processes 

consistently, with high levels of 

confidence, and with higher fidelity 

than R&D GREET, and consistent with 

the requirements, purposes, and 

objectives of the section 45V credit. The 

DOE directed the Argonne National 

Laboratory to develop 45VH2–GREET to 

meet three key parameters: (1) 

consistency of background assumptions 

for all users and across hydrogen 

production processes, while enhancing 

user friendliness, (2) technical 

robustness of the processes, and (3) 

consistency with the other requirements 

and purposes of section 45V. Each of 

these parameters is explained in 

additional detail as follows. 

First, 45VH2–GREET facilitates 

consistent analyses across different 

processes while enhancing user 

friendliness. While R&D GREET allows 

users to simulate hundreds of different 

fuel pathways (including but not limited 

to those that involve hydrogen) and 

several different system boundaries with 

different user-defined assumptions, 

45VH2–GREET exclusively allows 

simulations of the well-to-gate 

emissions associated with hydrogen 

production (as specified in section 

45V(c)(1)(B) and in alignment with 

these final regulations). The simpler 

interface in 45VH2–GREET as compared 

to R&D GREET ensures that the model 

is accessible to a broad range of 

taxpayers, including those without 

significant prior experience in lifecycle 

analysis or a GREET model. 

Second, 45VH2–GREET achieves 

technical robustness across hydrogen 

production pathways. Hydrogen 

production pathways represented in 

45VH2–GREET are a subset of those in 

R&D GREET and were included 

following rigorous interagency review 

for technical fidelity and alignment with 

the statute. While additional hydrogen 

production pathways are available in 

R&D GREET, many are preliminary in 

nature and inappropriate for analyses 

requiring relatively high precision, data 

reliability, and analytical rigor to 

support use in implementation of the 

section 45V credit (as described 

previously in this part of the Summary 

of Comments and Explanation of 

Revisions and further in supporting 

documentation to R&D GREET9). 

Implementation of the section 45V 

credit necessitates the use of lifecycle 

GHG emissions rate calculations that are 

as precise and robust as feasible, as 

section 45V(b)(2) provides differing 

applicable percentages based on a range 

of lifecycle GHG emissions rates and 

section 45V(c)(2)(A) includes within the 

definition of qualified clean hydrogen 

only hydrogen produced with a lifecycle 

GHG emissions rate below a threshold 

level. Absent analytically robust 

emissions calculations, these final 

regulations would fail to implement 

Congress’s directive to incentivize 

qualified clean hydrogen production, as 

distinguished among the different 

applicable percentage brackets, as well 

as fail to realize Congress’s underlying 

objective of crediting only qualified 

clean hydrogen and providing greater 

credit amounts to hydrogen produced 

with lower lifecycle GHG emissions 

rates. As data on and analyses of 

additional hydrogen production 

pathways in R&D GREET become more 

robust, such pathways may be 

incorporated into future versions of 

45VH2–GREET. 

Additionally, 45VH2–GREET was 

developed to align with the text of 

section 45V, which requires that the 

credit be based on the ‘‘lifecycle 

greenhouse gas emissions’’ as defined 

under section 211(o)(1)(H) of the Clean 

Air Act, subject to the additional 

requirements of section 45V(c)(1)(B), 

which references the use of GREET or a 

successor model as determined by the 

Secretary, and limits the emissions 

estimates to ‘‘well-to-gate’’ emissions. 

Lifecycle GHG emissions are defined in 

section 211(o)(1)(H) of the Clean Air Act 

to include both direct emissions and 

significant indirect emissions. R&D 

GREET does not robustly account for the 

variability in emissions estimates of all 

potential significant indirect emissions 

of certain hydrogen production 

pathways, particularly when 

representing counterfactual scenarios. 

The model additionally does not 

address the risk of significant indirect 

emissions related to changes in market 

behavior associated with the incentives 

created by section 45V.10 The proposed 

regulations therefore asked for 

comments on lifecycle analysis (LCA) 

considerations associated with 

hydrogen production pathways. 

In characterizing the lifecycle GHG 

emissions rate of a given hydrogen 

production pathway, 45VH2–GREET 

reflects key drivers of ‘‘lifecycle 

greenhouse gas emissions’’ as defined 

by section 45V(c)(1)(A) by crossreference to section 211(o)(1)(H) of the 

Clean Air Act, subject to the additional 

requirements of section 45V(c)(1)(B). 

Consistent with the Clean Air Act, 

45VH2–GREET, in conjunction with the 

broader regulatory framework, addresses 

direct GHG emissions (for example, at a 

hydrogen production facility) and 

significant indirect emissions (for 

example, upstream emissions associated 

with electricity consumption at a 

hydrogen production facility). 

Third, 45VH2–GREET is consistent 

with the other requirements and 

purposes of section 45V. The accurate 

and fair administration of the section 

45V credit requires the use of fixed 

‘‘background data’’ assumptions for 

parameters for which bespoke inputs 

from hydrogen producers would present 

challenges for tax administration, which 

requires high fidelity to ensure the 

accurate assessment and reporting of 

lifecycle GHG emissions rates associated 

with the production of hydrogen. 

Allowing taxpayers to provide bespoke 

values for parameters that cannot be 

accurately determined at an individual 

taxpayer level or cannot be verified 

would invite exaggerated or understated 

estimates that could result in inaccurate 

section 45V credit determinations. Use 

of verifiable data ensures that the 

section 45V credit is available only to 

those facilities that meet statutory 

requirements and that the appropriate 

section 45V credit amount is 

determined with respect to those 

facilities. To facilitate the use of 

bespoke values where feasible and the 

use of appropriate alternative values 

where that is not feasible, as well as 

consistency across taxpayers, the 

proposed regulations introduced the 

concepts of ‘‘background data’’ (which 

cannot be changed by 45VH2–GREET 

users) and ‘‘foreground data’’ (which 

allows for bespoke inputs by 45VH2– 

GREET users), and 45VH2–GREET 

distinguishes between them in a 

consistent manner. For example, 

45VH2–GREET incorporates the GHG 

emissions rates of regional grids as a 


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fixed background data parameter that 

users cannot change. The values 

incorporated in 45VH2–GREET as 

background data are based on 

individual power generators’ reporting 

to the U.S. Energy Information 

Administration (EIA), emissions factors 

derived from the EPA’s Emissions & 

Generation Resource Integrated 

Database (eGRID), estimates of upstream 

emissions derived by Argonne National 

Laboratory, and estimates of 

transmission and distribution losses 

based on State level reporting to the 

EIA. Given that GHG emissions 

estimates of regional grids are derived 

using the best available data and 

science, it is unlikely that a given 

taxpayer would be able to establish a 

value that differs materially from the 

45VH2–GREET default and also has 

high fidelity. Moreover, given that this 

parameter is expected to be consistent 

across all taxpayers within a given 

region, it is appropriate to require that 

all such taxpayers utilize the same value 

rather than allowing for deviation across 

facilities. 

Thus, 45VH2–GREET is consistent 

with the specific requirements of 

section 45V while maintaining R&D 

GREET’s overall modeling approach and 

much of R&D GREET’s background 

assumptions. This furthers the purposes 

reflected in section 45V(c)(1)(A) and (B). 

For these reasons, the Secretary has 

determined that 45VH2–GREET is a 

successor model for purposes of section 

45V(c)(1)(B), and the final regulations 

require its use. Accordingly, proposed 

§ 1.45V–1(a)(8)(ii) is modified and 

renumbered as § 1.45V–1(a)(9)(ii) to 

provide that the term ‘‘45VH2–GREET 

Model’’ means the latest publicly 

available version of 45VH2–GREET 

developed by Argonne National 

Laboratory and published by the DOE, 

as identified in the instructions to the 

latest version of Form 7210, or a 

successor form(s), 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. Additionally, as further 

discussed in this Summary of 

Comments and Explanation of 

Revisions, proposed § 1.45V–4(a) is 

modified to provide that the lifecycle 

GHG emissions rate of each hydrogen 

production process at a qualified clean 

hydrogen production facility is 

determined under the 45VH2–GREET 

Model. Conforming changes have also 

been made throughout the regulatory 

text to replace ‘‘most recent GREET 

model’’ with ‘‘45VH2–GREET Model.’’ 

b. Differences From R&D GREET 

Several comments requested that 

45VH2–GREET include all the pathways 

and technologies that are present in 

R&D GREET. Some of these comments 

also requested that 45VH2–GREET 

employ the same methodology used for 

measuring lifecycle GHG emissions as 

those used in R&D GREET. Some 

comments specifically requested that 

the transportation-related emissions be 

consistent between the two models. 

The final regulations do not adopt 

these comments. As described in the 

45VH2–GREET User Manual and as 

described in this part I.A.6 of the 

Summary of Comments and Explanation 

of Revisions, some pathways may be 

included in R&D GREET but not in a 

given version of 45VH2–GREET because 

the pathways were still preliminary 

when such version of 45VH2–GREET 

was developed and/or because the 

pathways did not adequately address all 

key sources of direct and significant 

indirect emissions (as required for 

consistency with section 211(o)(1)(H) of 

the Clean Air Act). Uncertainties around 

many of these pathways may include 

parameters such as identification of all 

relevant feedstocks or the choice of 

counterfactual scenarios. These 

uncertainties are described in sections 

2.1.1 and 2.1.4 of the R&D GREET 

Supporting Documentation. Some 

pathways, such as those using certain 

types of biomass, also had uncertainties 

and had not completed the 45VH2– 

GREET technical review process at the 

time the most recent version was 

released, but may be added in future 

updates as data and other parameters 

become more robust. The proposed 

regulations requested comments on 

lifecycle analysis considerations 

associated with some of the pathways 

that were not included in the initial 

45VH2–GREET release (for example, 

certain RNG pathways and fugitive 

methane), which could inform future 

updates to the model. 

Some specific aspects of hydrogen 

production pathways within R&D 

GREET have completed an interagency 

review process, have been deemed 

sufficiently robust and, have therefore 

also been included in 45VH2–GREET. 

Examples include default assumptions 

associated with methane leakage during 

natural gas transportation to a facility or 

assumptions of the emissions that result 

from electricity generation from specific 

generators. Thus, some assumptions 

related to transportation emissions have 

been made consistent between R&D 

GREET and 45VH2–GREET, while other 

assumptions are still too uncertain to 

include in 45VH2–GREET but may be 

included if deemed sufficiently robust 

in the future based on evaluation by 

interagency technical experts. 

R&D GREET is used for a range of 

purposes, including academic studies 

and research that do not necessarily 

require verification of assumptions with 

real-world data at specific facilities and 

at times rely on small and therefore 

uncertain sample sizes or datasets. 

Implementation of the section 45V 

credit, however, requires that 

information used to calculate the 

lifecycle GHG emissions rate reflect a 

given taxpayer’s actual operation with a 

reasonable degree of certainty and be 

subject to independent verification 

where possible or, where not, that 

values used appropriately reflect the 

range of possibilities rather than 

allowing use of unverifiable inputs that 

inappropriately maximize the amount of 

the section 45V credit. As described 

previously, use of verifiable data is 

necessary in the context of tax 

administration and in particular with 

respect to the section 45V credit where 

eligibility for the amount of the credit is 

based on the facility’s lifecycle GHG 

emissions rate. 

c. Emissions Through the Point of 

Production (Well-to-Gate) 

Proposed § 1.45V–1(a)(8)(iii) would 

have provided that, for purposes of 

section 45V(c)(1)(B) and proposed 

§ 1.45V–1(a)(8)(i), the term ‘‘emissions 

through the point of production (wellto-gate)’’ means the aggregate lifecycle 

GHG emissions related to hydrogen 

produced at a hydrogen production 

facility during the taxable year through 

the point of production. Further, 

proposed § 1.45V–1(a)(8)(iii) would 

have provided that such term includes 

emissions associated with feedstock 

growth, gathering, extraction, 

processing, and delivery to a hydrogen 

production facility. Finally, proposed 

§ 1.45V–1(a)(8)(iii) would have provided 

that such term includes the emissions 

associated with the hydrogen 

production process, inclusive of the 

electricity used by the hydrogen 

production facility and any capture and 

sequestration of carbon dioxide 

generated by the hydrogen production 

facility. 

Some comments requested 

clarification on the definition of ‘‘wellto-gate’’ and whether emissions related 

to hydrogen purification, compression, 

liquefaction, transport, storage, and 

other activities are included in the 

definition for purposes of calculating 

the lifecycle GHG emissions rate of the 

hydrogen. Other comments provided 

feedback on the requirement in 

proposed § 1.45V–1(a)(8)(iii) that 


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2234 Federal Register / Vol. 90, No. 6 / Friday, January 10, 2025 / Rules and Regulations 

taxpayers calculate the lifecycle GHG 

emissions rate of hydrogen produced at 

a hydrogen production facility based on 

the aggregate amount of hydrogen 

produced at the facility over the taxable 

year (in other words, use the average 

annual emissions rate). While some 

comments supported requiring 

taxpayers to calculate the lifecycle GHG 

emissions rate of hydrogen on an annual 

basis, other comments requested that 

taxpayers be permitted to calculate the 

lifecycle GHG emissions rate of 

hydrogen produced at their facility on a 

more granular basis. One comment 

expressed disappointment that the 

Treasury Department and the IRS did 

not engage States in defining lifecycle 

GHG emissions. Another comment 

recommended that the final regulations 

require State governments to adopt 

regulations to complement and enhance 

section 45V. Finally, one comment 

requested that the term ‘‘emissions 

through the point of production (wellto-gate)’’ exclude emissions from the 

production of hydrogen during natural 

disasters, emergency events, start-ups, 

shut-downs, and maintenance activities. 

Regarding the request for clarification 

of whether specific activities fall within 

the well-to-gate system boundary, the 

definition of ‘‘emissions beyond the 

point of production (well-to-gate)’’ in 

proposed § 1.45V–1(a)(8)(iii) and 

renumbered as § 1.45V–1(a)(9)(iii) is 

sufficiently clear. Comments have 

indicated confusion, however, as to how 

the well-to-gate system boundary and 

the definition of facility interact. To 

clarify, the well-to-gate system 

boundary for purposes of determining 

the lifecycle GHG emissions rate of a 

process is distinct from the definition of 

facility for Federal income tax purposes. 

First, as specified in § 1.45V–1(a)(9)(iii), 

the well-to-gate system boundary 

includes certain emissions that occur 

upstream of the facility. For example, 

the well-to-gate system boundary 

includes emissions associated with 

feedstock growth, gathering, extraction, 

processing, and delivery to a hydrogen 

production facility. While such 

emissions are included in the well-togate system boundary, equipment used 

in such upstream activities—such as 

electricity generating equipment—is not 

part of the facility, as specified in 

§ 1.45V–1(a)(7)(ii)(B). Second, as further 

specified in § 1.45V–1(a)(9)(iii), the 

well-to-gate system boundary also 

includes all emissions resulting from 

the facility’s hydrogen production 

process, inclusive of the production of 

a mixed gas or impurity and the 

electricity used by the hydrogen 

production facility and any capture and 

sequestration of carbon dioxide 

generated by the hydrogen production 

facility. This includes emissions 

resulting from the use of all components 

that function interdependently to 

produce the qualified clean hydrogen 

for which the section 45V credit is 

determined. Emissions from activities 

that occur after the facility’s hydrogen 

production process is complete, such as 

liquefaction, storage, or transport, are 

generally beyond the well-to-gate 

system boundary. The final regulations 

include a non-exhaustive list of 

examples of such activities in § 1.45V– 

1(a)(9)(iii). Finally, as explained in part 

I.A.6.d, § 1.45V–1(a)(9)(iv) is added to 

provide that emissions that result from 

certain purification activities that occur 

downstream of the facility’s qualified 

clean hydrogen production process are 

still within the well-to-gate system 

boundary. Even though equipment used 

in such purification activities is not part 

of the facility, emissions associated with 

such purification are nevertheless 

within the well-to-gate system boundary 

for purposes of determining the section 

45V credit. 

However, the Treasury Department 

and the IRS, based on advice of the 

DOE, note that, in situations where a 

man-made chemical is produced using 

hydrogen feedstock (for example, 

ammonia), and is later cracked or 

‘‘dehydrogenated’’ to release the 

hydrogen, the chemical represents a 

means of hydrogen storage and the 

cracking step releases the hydrogen 

from such storage. These steps occur 

downstream of hydrogen production 

and are therefore outside of the well-togate system boundary, and also do not 

constitute a distinct hydrogen 

production process. Accordingly, 

hydrogen released from cracking such 

chemicals cannot be used to claim the 

section 45V credit. 

Regarding the requirement that 

taxpayers calculate the lifecycle GHG 

emissions rate of their hydrogen on an 

annual basis, these comments are 

addressed in response to comments 

received on proposed § 1.45V–4(a) in 

part III.A of this Summary of Comments 

and Explanation of Revisions. 

Regarding a comment’s criticism that 

the Treasury Department and the IRS 

did not engage the States in defining 

lifecycle GHG emissions, this term is 

defined in section 45V(c)(1)(A) as 

having the same meaning given such 

term under section 211(o)(1)(H) of the 

Clean Air Act. Moreover, States were 

afforded the opportunity to comment on 

the proposed regulations, and some did. 

Section 45V does not require State 

governments to take any action or to 

enact any legislation to complement 

section 45V. Section 45V provides a 

Federal income tax credit to owners of 

qualified clean hydrogen production 

facilities for the production of qualified 

clean hydrogen and imposes no 

obligations on the States. Accordingly, 

these final regulations do not adopt the 

request to require the States to enact 

legislation to complement section 45V. 

Finally, regarding the request to 

exclude emissions from the production 

of hydrogen during periods of natural 

disasters, emergency events, start-ups, 

shut-downs, and maintenance activities, 

section 45V(c)(1) does not provide for or 

contemplate any such exceptions. These 

final regulations, therefore, do not adopt 

this comment’s suggestion. 

d. Certain Emissions Related to 

Purification Treated as Through Point of 

Production 

In consultation with the DOE, the 

final regulations add a new § 1.45V– 

1(a)(9)(iv), which addresses emissions 

attributable to the purification of 

hydrogen. Section 1.45V–1(a)(9)(iv) 

provides that, if the taxpayer knows or 

has reason to know the purification of 

a hydrogen gas stream (that is, removal 

of a mixed gas or impurity) is necessary 

for a hydrogen gas stream to be 

productively used, or to be sold for 

productive use, any lifecycle GHG 

emissions relating to such purification 

(for example, emissions from electricity 

used in purification, or carbon dioxide 

that is separated from a hydrogen gas 

stream and then vented as part of 

purification) are treated as emissions 

through the point of production (wellto-gate). Additionally, if the taxpayer 

knows or has reason to know that a 

hydrogen gas stream contains less than 

99 percent hydrogen and will be 

combusted without purification, any 

lifecycle GHG emissions relating to the 

purification needed to purify the 

hydrogen gas stream to contain 99 

percent hydrogen are treated as 

emissions through the point of 

production (well-to-gate). Section1.45V– 

1(a)(9)(v) provides an example to 

illustrate this rule. 

To ascertain the emissions associated 

with production of hydrogen in a 

manner that is consistent with section 

45V, which requires that section 45V 

credit eligibility be determined on the 

basis of ‘‘kilograms of CO2e per 

kilogram of hydrogen’’, 45VH2–GREET 

levelizes all well-to-gate emissions 

associated with a hydrogen production 

process over only the kilograms of pure 

hydrogen produced. This includes 

emissions attributable to the 

purification of a hydrogen gas stream to 

remove a mixed gas or impurity. 

Emissions attributable to purification 


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Federal Register / Vol. 90, No. 6 / Friday, January 10, 2025 / Rules and Regulations 2235 

include emissions associated with 

energy consumption (for example, 

electricity consumed by purification 

equipment or by equipment used for 

carbon dioxide capture), as well as 

greenhouse gases that are separated out 

by purification equipment and not 

sequestered (for example, carbon 

dioxide that is captured and then 

vented). 

Previous versions of 45VH2–GREET 

accounted for carbon dioxide emissions 

that may occur from the conversion of 

impurities or mixed gases downstream 

of the hydrogen production facility, thus 

including such emissions in the 

levelization. This approach will be 

revised in the forthcoming January 2025 

version of 45VH2–GREET, such that 

emissions outside of the well-to-gate 

boundary are not accounted for in 

determining a process’ lifecycle GHG 

emissions rate for purposes of section 

45V. Qualified clean hydrogen 

production facilities can therefore be 

designed to achieve the level of purity 

required for sale or use (subject to the 

rules of section 45V and these final 

regulations), without regard to the 

carbon dioxide emissions that may 

occur from the conversion of impurities 

or mixed gases downstream (for 

example, the ultimate conversion to 

carbon dioxide of methanol produced 

from a mixed gas stream of hydrogen 

and carbon monoxide). 

As the result of the January 2025 

modification to 45VH2–GREET and the 

45VH2–GREET User Manual, and to 

clarify the appropriate well-to-gate 

boundary, these final regulations, 

following consultation with the DOE, 

clarify the definition of emissions 

through the point of production (wellto-gate) to address emissions 

attributable to purification that the 

taxpayer knows or has reason to know 

are necessary in order for the hydrogen 

gas stream to be productively used, 

regardless of where such purification 

occurs. These emissions are properly 

treated as occurring within the well-togate boundary in § 1.45V–1(a)(9)(iv). 

In certain cases—absent the section 

45V credit—the taxpayer would 

normally purify a hydrogen gas stream 

prior to it being productively used or 

sold for productive use, and such 

purification would have lifecycle GHG 

emissions attributed to the hydrogen 

produced. Taxpayers, however, could 

have an incentive to claim that the 

purification (and its attendant 

emissions) occurs beyond the hydrogen 

production ‘‘gate.’’ If these emissions 

occur outside of the ‘‘gate,’’ then they 

would not be attributed in 45VH2– 

GREET to the hydrogen production 

process and therefore would not be 

included in the hydrogen production 

process’ lifecycle GHG emissions rate 

for purposes of determining the amount 

of the section 45V credit. The taxpayer 

may, for example, forgo hydrogen 

purification that it would have 

performed absent the incentive of the 

section 45V credit, and produce 

comparatively ‘‘impure hydrogen.’’ The 

‘‘impure hydrogen’’ may then be sold to 

a customer who would purify the 

hydrogen gas stream (something it 

would not need to do absent the 

incentive to the hydrogen producer due 

to the section 45V credit), thereby 

generating lifecycle GHG emissions that 

the taxpayer was able to forgo. 

Similarly, a taxpayer could have an 

incentive to instead sell a stream of 

impure hydrogen and a mixed gas or 

impurity (such as carbon monoxide), 

instead of the purified hydrogen gas 

stream, for combustion. The DOE has 

advised that, absent the section 45V 

credit, hydrogen gas streams are 

consistently sold at purity levels well 

above 99 percent today and that 

customers would likely have to 

substantially modify their operations to 

accept less pure gas streams. Therefore, 

DOE has advised that the predominant 

motivation to sell hydrogen for 

combustion at lower purities would be 

so the emissions associated with those 

impurities would not be accounted for 

within the well-to-gate boundary. 

These circumstances would be 

inconsistent with a purpose of section 

45V, which is to provide an incentive to 

produce qualified clean hydrogen and to 

provide a higher incentive to produce 

qualified clean hydrogen as more 

lifecycle GHG emissions are avoided. 

Producing hydrogen with a lower 

lifecycle GHG emissions rate and 

receiving a section 45V credit reflecting 

such an emissions rate in the case where 

the taxpayer knows or has reason to 

know that the customer must further 

purify the hydrogen gas stream (and 

emit additional emissions) so that such 

gas stream can be productively used by 

its customer is contrary to this purpose 

and to the requirement in section 

45V(c)(2)(B)(i)(II) for hydrogen to be 

produced in the ordinary course of a 

trade or business of the taxpayer. To 

address this, and consistent with the 

purposes of section 45V, in cases where 

the taxpayer knows or has reason to 

know that additional purification is 

needed for a hydrogen gas stream to be 

productively used, the final regulations 

clarify that the emissions associated 

with the purification needed to produce 

the hydrogen for a productive use occur 

within the well-to-gate boundary. 

Likewise, in cases where the taxpayer 

knows or has reason to know that a 

hydrogen gas stream contains less than 

99 percent hydrogen and will be 

combusted without purification, 

emissions that would have resulted 

from purifying the hydrogen gas stream 

to that percentage prior to combustion 

are treated as emissions within the wellto-gate boundary. 

The final regulations are consistent 

with the treatment of emissions related 

to purification in the January 2025 

version of 45VH2–GREET, which treats 

emissions attributable to purification 

that the taxpayer knows or has reason to 

know are necessary in order for the 

hydrogen gas stream to be productively 

used as within the gate. 

7. Process 

Section 45V(c)(1)(A) and (B) establish 

the boundaries for determining lifecycle 

GHG emissions rates associated with the 

production of hydrogen. Section 

45V(c)(1)(A) mandates consideration of 

GHG emissions that are described in 

section 211(o)(1)(H) of the Clean Air 

Act. Section 45V(c)(1)(B) further 

specifies that the term ‘‘lifecycle 

greenhouse gas emissions’’ only 

includes emissions through the point of 

production (well-to-gate), as determined 

under the most recent GREET model or 

a successor model as determined by the 

Secretary. Accordingly, section 

45V(c)(1)(B) specifies an ending 

boundary (that is, the gate of a hydrogen 

production facility) for the emissions 

that must be considered for purposes of 

the section 45V credit. It also specifies 

a model for use in determining lifecycle 

GHG emissions rates. Taken together, 

these statutory rules provide the 

boundaries for assessing lifecycle GHG 

emissions for purposes of section 45V. 

Section 45V provides authority for the 

Secretary to specify and clarify how to 

determine lifecycle GHG emissions rates 

within these statutorily determined 

boundaries. Exercise of this authority is 

necessary because this statutory 

framework must address a wide range of 

hydrogen production processes that are 

currently viable or that may become 

viable in the future, the technical details 

of each hydrogen production process, 

and scientific advancements and 

uncertainties associated with lifecycle 

GHG analyses. Congress acknowledged 

that the Secretary would need to 

identify a system for determining 

lifecycle GHG emissions rates and 

expressly delegated to her the authority 

to do so in section 45V(f), which 

provides ‘‘the Secretary shall issue 

regulations or other guidance to carry 

out the purposes of this section, 

including regulations or other guidance 

for determining lifecycle greenhouse gas 


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11Process, Merriam-Webster Dictionary, available 

at https://www.merriam-webster.com/dictionary/ 

process. 

12 International Organization for Standardization, 

ISO 14040:2006, Environmental Management—Life 

Cycle Assessment—Principles and Framework (2d 

ed. 2006). 

emissions.’’ As noted previously, this 

authority is cabined by the directives in 

the statute, most critically the directive 

to measure well-to-gate lifecycle GHG 

emissions as defined by section 

211(o)(1)(H) of the Clean Air Act. 

The term ‘‘process,’’ as used in 

sections 45V(b)(2)(A) through (D) and in 

section 45V(c)(2)(A), is a parameter that 

requires further clarification. Proposed 

§ 1.45V–4(a) and (b) would have 

required the section 45V credit to be 

determined according to the lifecycle 

GHG emissions rate of all hydrogen 

produced at a hydrogen production 

facility during the taxable year. Under 

this proposal, the term ‘‘process’’ 

included all the operations and inputs 

used by a facility to produce hydrogen 

during a taxable year. 

The Treasury Department and the IRS 

received a number of comments which 

led to a reconsideration of how the term 

‘‘process’’ is used in determining 

lifecycle GHG emission rates. After 

reviewing these comments and 

reexamining the meaning of the term 

‘‘process’’ as it relates to the structure 

and purposes of section 45V, these final 

regulations add § 1.45V–1(a)(11) to 

define the terms ‘‘process’’ and 

‘‘primary feedstock,’’ as discussed 

further in this part I.A.7 of this 

Summary of Comments and Explanation 

of Revisions. These final regulations 

also make a corresponding modification 

to § 1.45V–1(b) regarding the amount of 

the credit. 

Several comments recommended that 

45VH2–GREET allow for the blending of 

feedstocks, like natural gas and RNG. In 

the case of RNG, comments claimed that 

given the high cost of RNG, combining 

RNG with conventional natural gas 

could create certain market efficiencies 

that would justify the combined use of 

RNG and natural gas. Several comments 

opposed allowing the mixing of RNG (or 

other types of biomethane) with 

conventional natural gas to produce 

clean hydrogen; in particular, one 

comment noted that ‘‘splash blending,’’ 

or combining small amounts of RNG 

with conventional natural gas, could 

cost the U.S. government billions of 

dollars annually while potentially 

increasing overall emissions. According 

to one comment, to avoid splash 

blending, each methane-based feedstock 

should be considered a separate 

production line. 

Section 45V generally requires that 

lifecycle GHG emissions rates be 

determined according to the process by 

which the hydrogen is produced. 

Section 45V(b)(2) provides the rules for 

determining the applicable percentages 

that are ultimately used to calculate the 

amount of the section 45V credit. In 

general, section 45V(b) requires 

applicable percentages to be determined 

with respect to ‘‘qualified clean 

hydrogen which is produced through a 

process that results in a lifecycle 

greenhouse gas emissions rate’’ that falls 

within statutorily mandated emissions 

rate ranges. Section 45V(c)(2)(A) defines 

the term qualified clean hydrogen as 

hydrogen that is produced through a 

process that results in a lifecycle 

greenhouse gas emissions rate of not 

greater than 4 kilograms of CO2e per 

kilogram of hydrogen. 

Section 45V does not expressly define 

the term ‘‘process.’’ The plain meaning 

of the term ‘‘process’’ is ‘‘a series of 

actions or operations conducing to an 

end.’’ 11 In particular, for lifecycle 

assessment purposes, the term 

‘‘process’’ has been defined as a ‘‘set of 

interrelated or interacting activities that 

transforms inputs into outputs.’’ 12

Building upon these definitions, 

combined with the statutory 

distinctions between processes that 

result in different specified ranges of 

lifecycle GHG emissions rates, the 

statutory text indicates that the term 

‘‘process’’ necessarily includes a degree 

of uniformity and consistency among 

those inputs that can meaningfully 

differ in their GHG intensity. Section 

45V(b)(2) provides varying credit 

amounts for hydrogen that is ‘‘produced 

through a process that results in a 

lifecycle greenhouse gas emissions rate’’ 

that falls into specified ranges. The term 

‘‘process’’ must therefore mean more 

than just the production technique 

because the same production technique, 

such as steam methane reforming, could 

produce lifecycle GHG emissions rates 

that fall into different ranges specified 

in the statute depending on the inputs 

used. The statute differentiates between 

‘‘a process that results in’’ one specified 

range of GHG emissions rates from ‘‘a 

process that results in’’ a different 

specified range of GHG emissions rates. 

See section 45V(b)(2)(A) through (D). 

The only effective way to distinguish 

between hydrogen production processes 

is to define the term ‘‘process’’ with 

respect to both the production 

technique and a class of uniform or 

similar inputs used in that technique. 

This interpretation of the term 

‘‘process’’ is consistent with the 

chemical transformations that are used 

to produce hydrogen, and with the 

language in section 45V. Treating input 

feedstocks with significantly different 

attributes as part of the same hydrogen 

production process (for example, by 

averaging the attributes of multiple 

types of methane used over a time 

period) often would not accurately 

reflect the chemical dynamic whereby 

each molecule of hydrogen originates 

from distinct source-molecule inputs 

that have distinct attributes affecting the 

lifecycle emissions of each hydrogen 

molecule and, as a result, often would 

not reflect the lifecycle GHG emissions 

rate of the resulting hydrogen 

molecules, as required by the statute. 

The most granular approach to assessing 

lifecycle GHG emissions would 

therefore be to match each molecule of 

hydrogen with its molecular inputs and 

identify the lifecycle emissions 

associated with the resulting hydrogen. 

However, this level of granularity is 

impractical to administer and 

unnecessary to implement the statute. 

The feasible and appropriate approach 

to aggregating molecules is to assess 

each hydrogen production process by 

grouping source molecules into 

categories of primary feedstock. 

This aggregation approach best 

implements the statutory requirements 

of section 45V because the production 

of hydrogen using inputs with similar 

attributes can be expected to produce 

consistent emissions results, allowing 

the appropriate determination of 

eligibility and credit amounts under 

section 45V. An approach that 

incorrectly assumed all hydrogen 

molecules are a blend of feedstocks 

would not yield a correct lifecycle 

assessment, would have perverse 

incentive effects (as discussed 

subsequently in this Summary of 

Comments and Explanation of 

Revisions), and would be no more 

administrable than the approach 

adopted in these final rules. 

With the exception of geologic 

hydrogen, all hydrogen production 

processes involve conversion of 

hydrogen-containing molecules into 

pure hydrogen. In electrolysis, for 

example, the feedstock—the source of 

the hydrogen molecules—is water, 

which contains no carbon and therefore 

does not directly produce carbon 

dioxide (or other GHGs) in the 

production of hydrogen. By contrast, in 

steam methane reforming, the feedstock 

is water and methane, which produces 

hydrogen and carbon dioxide when 

reformed. In pyrolysis, the feedstock is 

organic matter, which produces 

hydrogen and solid carbon when 

pyrolyzed. In methane pyrolysis, the 

feedstock is methane, which is 

converted into hydrogen and solid 


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carbon through the application of high 

temperatures. 

Energy attributes and lifecycle GHG 

emissions can vary considerably among 

hydrogen-containing feedstocks. For 

instance, the water inputs into 

electrolysis generally have limited 

upstream emissions and zero direct 

GHG emissions from the chemical 

reaction that produces hydrogen. 

Hydrocarbon inputs into methane 

reforming produce a standard quantity 

of direct emissions through the 

chemical reaction that produces 

hydrogen, but upstream emissions vary 

considerably for different sources. 

Different hydrocarbon inputs have 

significantly different upstream 

practices (for example, methods of 

gathering, processing, or delivery) and 

counterfactuals, among other factors, 

which result in dramatic differences in 

resulting lifecycle GHG emissions rates 

of producing hydrogen from that 

methane source. 

Because of the potential for significant 

variation in the lifecycle GHG emissions 

rates associated with different inputs, 

and the structure of section 45V, it is 

necessary to assess hydrogen production 

using different hydrogen-containing 

feedstocks as distinct processes. 

Accordingly, these final regulations 

distinguish processes based on their 

hydrogen-containing feedstock, which is 

referred to in these final regulations as 

a ‘‘primary feedstock.’’ A ‘‘primary 

feedstock’’ is defined in § 1.45V–1(a)(11) 

as a hydrogen-containing chemical that 

is transformed to produce hydrogen at a 

hydrogen production facility and has 

uniform or similar attributes 

distinguished by the source from which 

it is derived, if such source materially 

affects the lifecycle GHG emissions rate 

associated with use of the chemical to 

produce hydrogen. 

If the term ‘‘process’’ were instead 

interpreted to encompass feedstocks 

with significantly different attributes as 

relevant to determining lifecycle GHG 

emissions, then the approach to 

determining whether a ‘‘process’’ has 

comported with statutorily prescribed 

lifecycle GHG emissions rate ranges for 

the purposes of determining the amount 

of the section 45V credit would not 

effectively, in fact, incentivize the 

production of hydrogen within a 

specific lifecycle GHG emissions rate 

range. For example, allowing a process 

to calculate a single emissions rate 

based on a mix of feedstocks with 

disparate attributes would increase the 

risk that hydrogen production that 

would otherwise not meet the statutory 

emissions requirements receives the 

section 45V credit simply by virtue of 

being commingled or averaged with 

hydrogen production that does meet the 

statutory emissions requirements using 

other inputs. This would be a 

foreseeable and inappropriate result if, 

as several comments urged, the term 

‘‘process’’ were interpreted as any 

activities and inputs that resulted in the 

production of a kilogram of hydrogen. 

The statute’s singular reference to ‘‘a 

process’’ and ‘‘a lifecycle greenhouse 

gas emissions rate’’ indicates that the 

statutory references to the term 

‘‘process’’ requires evaluation on the 

basis of each specific process, with 

uniformity and consistency across its 

operations and primary feedstock that 

generally results in a consistent lifecycle 

GHG emissions rate. Defining the term 

‘‘process’’ based solely on the type of a 

facility’s operations that produce 

hydrogen (for example, steam methane 

reforming or autothermal reforming) is 

not appropriate because such operations 

could rely on feedstocks with materially 

different attributes and carbon 

intensities, which would result in very 

different lifecycle GHG emission rates 

that would not be observable if 

feedstocks are aggregated. Thus, 

feedstocks to a process should have 

attributes with a sufficient degree of 

uniformity and consistency to be 

considered part of the same ‘‘process.’’ 

Separately evaluating each hydrogen 

production process at a qualified clean 

hydrogen production facility is 

consistent with the statutory language 

and scheme of section 45V, which 

requires accuracy in determining ‘‘a 

lifecycle [GHG] emissions rate’’ for 

hydrogen produced via ‘‘a process.’’ See 

section 45V(c)(2)(A). 

For these reasons, consistent with the 

transformation of feedstock in the 

production of hydrogen, § 1.45V– 

1(a)(11) defines the term ‘‘process’’ to 

mean the operations conducted by a 

facility to produce hydrogen (for 

example, electrolysis or steam methane 

reforming) during a taxable year using 

one primary feedstock. A facility 

producing hydrogen through 

electrolysis, for example, will have a 

single hydrogen production process in a 

taxable year with water as its primary 

feedstock. Electricity with different 

attributes would not result in distinct 

processes because electricity is not a 

primary feedstock (that is, it is not 

contributing hydrogen atoms to the 

hydrogen molecule); additionally, 

electricity cannot be differentiated at the 

molecular level. Electricity and heat are 

integral to the operations of hydrogen 

production facilities, and the form of 

energy used by a facility (for example, 

electricity versus heat) plays an 

essential role in discerning different 

hydrogen production processes. The 

energy powering a facility’s operations 

enables the chemical transformation of 

molecular feedstocks into hydrogen, but 

energy does not itself contribute atoms 

to the hydrogen produced by a facility. 

Thus, the final regulations do not treat 

electricity and heat as primary 

feedstocks, but instead require tracking 

and assessing the emissions associated 

with energy used in a process through 

different mechanisms, as described in 

part III.D of this Summary of Comments 

and Explanation of Revisions and 

specified in 45VH2–GREET. For a 

facility that produces hydrogen through 

steam methane reforming using fossil 

natural gas, for example, the 

combination of fossil natural gas and 

water would be considered one primary 

feedstock because hydrogen molecules 

derive from both fossil natural gas and 

water and this form of hydrogen 

production requires use of both water 

and methane. Thus, a facility producing 

hydrogen exclusively through reforming 

of fossil natural gas with water would 

have a single hydrogen production 

process in a taxable year. A facility 

producing hydrogen through reforming 

of both fossil natural gas and RNG from 

animal manure with water would have 

two hydrogen production processes in 

that year; the primary feedstock for one 

process would be fossil natural gas and 

water, and the primary feedstock for the 

other process would be RNG from 

animal manure and water. 

As further specified in the 45VH2– 

GREET User Manual and reflected in 

45VH2–GREET, some types of primary 

feedstocks are distinguished by their 

origin (for example, methane from a 

specific source), as well as attributes of 

that source as relevant to determining 

lifecycle GHG emissions. While these 

final regulations cannot anticipate and 

address all possible primary feedstocks 

that may be utilized for hydrogen 

production, the Treasury Department 

and the IRS note that it is currently 

appropriate to treat fossil natural gas, 

RNG derived from landfill gas, RNG 

derived from animal waste, RNG 

derived from wastewater treatment 

plants, and gas derived from coal mine 

methane as distinct primary feedstocks. 

If a facility uses any of these gas streams 

in combination with water via 

interdependent steps (for example, in 

the case of reforming), then the 

combination of that gas stream (for 

example, fossil natural gas, RNG derived 

from landfill gas, etc.) and water is a 

singular primary feedstock. Such 

treatment implements the definition of 

primary feedstock adopted here, which 

treats as a single feedstock that which 


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has uniform or similar attributes 

distinguished by the source from which 

it is derived, if such source materially 

affects the lifecycle GHG emissions 

associated with use of the molecule to 

produce hydrogen. 

If a facility utilizes more than one 

primary feedstock to produce hydrogen, 

then that facility will have an equal 

number of separate hydrogen 

production processes that each must be 

assessed separately to determine a 

lifecycle GHG emissions rate for the 

quantity of hydrogen produced through 

that process for purposes of section 45V. 

For example, if a taxpayer procures RNG 

sourced from a blend of sources, the 

taxpayer must account for the share of 

RNG derived from each source 

distinctly within 45VH2–GREET or an 

Emissions Value Request Application. 

Future releases of 45VH2–GREET and 

analyses conducted through the DOE’s 

EVRP may address additional primary 

feedstocks, but any new primary 

feedstock must also be treated as 

distinct. 

The Treasury Department and the IRS 

note that there is precedent for this type 

of approach for assessing emissions 

associated with the production of fuels. 

The RFS is another example of a 

framework that requires a determination 

of what activities should be aggregated 

or separated for purposes of lifecycle 

analysis to determine GHG emissions. 

Similar to the approach provided for 

here, the RFS conducts LCAs for 

distinct feedstock-technology-output 

combinations because those 

combinations have the potential to have 

distinct lifecycle emissions that should 

be credited differently under the RFS’s 

statutory scheme. See ‘‘Regulation of 

Fuels and Fuel Additives: Changes to 

Renewable Fuel Standard Program,’’ 75 

FR 14670, 14713 (Mar. 26, 2010) (EPA 

final regulation providing that different 

combinations of feedstock, production 

process, and fuel that result in different 

lifecycle GHG outcomes must be 

evaluated separately). 

8. Qualified Clean Hydrogen 

Section 45V(c)(2)(A) provides that 

‘‘qualified clean hydrogen’’ means 

hydrogen which is produced through a 

process that results in a lifecycle GHG 

emissions rate of not greater than 4 

kilograms of CO2e per kilogram of 

hydrogen. Further, section 45V(c)(2)(B) 

provides that such term does not 

include any hydrogen unless the 

production and sale or use of such 

hydrogen is verified by an unrelated 

party, and such hydrogen is produced in 

the United States (as defined in section 

638(1) of the Code) or a United States 

possession (as defined in section 

638(2)); in the ordinary course of a trade 

or business of the taxpayer; and for sale 

or use. Proposed § 1.45V–1(a)(9) 

substantially repeats the statutory 

definition. 

Several comments requested 

clarification on the definition of 

‘‘qualified clean hydrogen.’’ Some 

comments requested clarification that 

hydrogen does not need to be of a 

certain level of purity to constitute 

‘‘qualified clean hydrogen.’’ 

Specifically, comments requested 

clarification that ‘‘qualified clean 

hydrogen’’ includes hydrogen that is 

produced as one of several constituents 

in a gas stream so long as the gas stream 

is valorized. The comments suggested 

that the statute does not specify that the 

hydrogen production must isolate the 

hydrogen or that the gas stream 

containing the hydrogen achieve a 

certain threshold hydrogen content to be 

eligible for the credit. These comments 

further suggested that requiring 

hydrogen to be separated from other 

components in a gas stream when those 

components would be immediately 

recombined with the hydrogen would 

be inefficient. One comment requested 

clarification on whether there are 

specific metering requirements for 

monitoring the purity of the hydrogen. 

These final regulations do not modify 

the definition of ‘‘qualified clean 

hydrogen’’ to specify a certain level of 

purity, or to specify that no level of 

purity is required. A purity requirement 

does not need to be added to the 

definition of ‘‘qualified clean hydrogen’’ 

because 45VH2–GREET already 

accounts for impurities by assessing the 

well-to-gate emissions of a hydrogen 

production facility over only the 

kilograms of pure hydrogen produced. 

The treatment of mixed gases or 

impurities is further discussed in part 

I.A.6.d. of this Summary of Comments 

and Explanation of Revisions. 

The decisions to characterize well-togate emissions of hydrogen based only 

on the kilograms of pure hydrogen 

produced, and to address impurities 

through the well-to-gate lifecycle GHG 

emissions analysis (in 45VH2–GREET or 

the PER process)—rather than by 

requiring hydrogen to be of a certain 

level of purity—are consistent with 

Congress’s directive under section 

45V(c)(1)(A) and (B) to determine 

lifecycle GHG emissions as defined 

under section 211(o)(1)(H) of the Clean 

Air Act and 45VH2–GREET. 

As to the request for clarification on 

whether there are specific metering 

requirements for monitoring the purity 

of the hydrogen, as discussed in this 

part, impurities are accounted for 

through the well-to-gate lifecycle GHG 

emissions analysis (in 45VH2–GREET or 

the PER process). Metering requirements 

for all relevant inputs into 45VH2– 

GREET, including purity, are addressed 

in § 1.45V–5(g)(5), and no special 

metering requirements for purity, apart 

from those specified in § 1.45V–5(g)(5), 

are needed. 

9. For Sale or Use 

For purposes of section 

45V(c)(2)(B)(i)(III) and proposed 

§ 1.45V–1(a)(9)(i)(C), proposed § 1.45V– 

1(a)(9)(ii) would have provided that, the 

term ‘‘for sale or use’’ means for the 

primary purpose of making hydrogen 

ready and available for sale or use. 

Following production, storage of 

hydrogen before its sale or use would 

not disqualify such hydrogen from being 

considered produced for sale or use. No 

comments were received on proposed 

§ 1.45V–1(a)(9)(ii), and this provision is 

adopted without change as renumbered 

§ 1.45V–1(a)(13)(ii). 

B. Amount of Credit 

1. In General 

Under section 45V(a), the clean 

hydrogen production credit is based on 

the amount of qualified clean hydrogen 

produced ‘‘during the 10-year period 

beginning on the date such facility was 

originally placed in service’’ multiplied 

by the applicable amount identified in 

section 45V(b). Proposed § 1.45V–1(b)(1) 

would have incorporated this 

calculation of the amount of credit by 

providing that the amount of the section 

45V credit determined under section 

45V(a) and the section 45V regulations 

for any taxable year is the product of the 

kilograms of qualified clean hydrogen 

produced by the taxpayer during such 

taxable year at a qualified clean 

hydrogen production facility during the 

10-year period beginning on the date 

such facility was originally placed in 

service, multiplied by the applicable 

amount with respect to such hydrogen. 

Several comments requested changes 

related to the 10-year credit period and 

the placed in service date specified in 

proposed § 1.45V–1(b)(1). One comment 

requested that the 10-year credit period 

be tolled for circumstances beyond the 

taxpayer’s control or during periods of 

diminished capacity. Another comment 

requested that the placed in service date 

of a qualified clean hydrogen 

production facility be delayed until 

operational testing is complete and 

commercial quantities of hydrogen are 

produced. Another comment requested 

that the final regulations provide that a 

qualified clean hydrogen production 

facility cannot be placed in service until 

after December 31, 2022. This comment 


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suggested that, prior to January 1, 2023, 

it was impossible to produce qualified 

clean hydrogen because section 45V, 

which established what is qualified 

clean hydrogen, did not become 

effective until that date. Thus, this 

comment suggested, no hydrogen 

production facility could properly be 

treated as having been placed in service 

as a ‘‘qualified clean hydrogen 

production facility’’ until that date. 

Another comment requested 

clarification of the requirements for preexisting facilities that were originally 

placed in service prior to the enactment 

of section 45V and the extent to which 

such facilities can claim the section 45V 

credit for the years remaining in the 10- 

year period beginning on the date such 

facilities were originally placed in 

service. 

These final regulations do not adopt 

the changes to proposed § 1.45V–1(b)(1) 

recommended by these comments. 

Section 45V(a) establishes that the 

credit is based, in part, on the placed in 

service date and the definition of 

‘‘placed in service’’ is sufficiently clear 

as an established tax concept. Section 

1.46–3(d)(1) provides that, for purposes 

of the section 38 credit (which includes 

the clean hydrogen production credit 

determined under section 45V, see 

section 38(b)(36)), property is 

considered placed in service in the 

earlier of the taxable year in which, 

under the taxpayer’s depreciation 

practice, the period for depreciation 

with respect to such property begins; or 

the taxable year in which the property 

is placed in a condition or state of 

readiness and availability for a 

specifically assigned function, whether 

in a trade or business, in the production 

of income, in a tax-exempt activity, or 

in a personal activity. Examples of 

property that is considered in a 

condition or state of readiness and 

availability for a specifically assigned 

function are set forth in § 1.46–3(d)(2). 

Section 1.46–3(d)(2)(ii) provides that 

operational farm equipment that is 

acquired during the taxable year and is 

not practicable to use until the 

following year is still considered ready 

and available for its assigned function in 

the taxable year. Section 1.46– 

3(d)(2)(iii) provides that equipment that 

is operational but is still undergoing 

testing to eliminate any defects is still 

considered ready and available for its 

assigned function. These examples 

clarify that property can be ready and 

available for its assigned function 

regardless of the level of production 

attained. 

Various revenue rulings and case law 

have established a five-factor test for 

determining when a facility is placed in 

service, including (1) whether the 

necessary permits for operation have 

been obtained; (2) whether critical 

preoperational testing has been 

completed; (3) whether the taxpayer has 

control of the facility; (4) whether the 

unit has been synchronized with the 

transmission grid; and (5) whether daily 

or regular operation has begun. See 

Ampersand Chowchilla Biomass, LLC v. 

United States, 150 Fed. Cl. 620 (2020) 

(citing Rev. Rul. 84–85, 1984–1 C.B. 10; 

Rev. Rul. 79–98, 1979–1 C.B. 103; Rev. 

Rul. 76–256, 1976–2 C.B. 46; and Rev. 

Rul. 76–428, 1976–2 C.B. 47), aff’d, 26 

F.4th 1306 (Fed. Cir. 2022). No one 

factor is dispositive. 

Determining the date on which a 

qualified clean hydrogen production 

facility was placed in service is 

inherently fact intensive, and the 

existing case law and revenue rulings 

are sufficient for taxpayers to determine 

their facility’s placed in service date. 

Relying upon existing standards 

provides sufficient clarity to taxpayers 

and avoids the confusion of creating 

multiple placed in service standards. 

Regarding whether the final 

regulations should provide that the 10- 

year credit period is tolled to account 

for circumstances beyond the taxpayer’s 

control or during periods of a facility’s 

diminished capacity, the 10-year credit 

period is a statutory requirement under 

section 45V(a)(1), and there is no 

provision that provides an exception to 

this statutory rule. 

Regarding whether the final 

regulations should clarify that a 

qualified clean hydrogen production 

facility cannot be placed in service until 

after December 31, 2022, the Treasury 

Department and the IRS clarify in this 

Summary of Comments and Explanation 

of Revisions that a qualified clean 

hydrogen production facility may have 

been placed in service prior to January 

1, 2023. First, section 45V does not 

specify an earliest date on which a 

qualified clean hydrogen production 

facility must be placed in service to be 

eligible for the section 45V credit, and 

as explained in the Explanation of 

Provisions to the proposed regulations, 

the owner of a qualified clean hydrogen 

production facility originally placed in 

service after December 31, 2012, can 

claim the section 45V credit for 

qualified clean hydrogen produced 

during at least some portion of the 10- 

year period described in section 

45V(a)(1), provided all other 

requirements are met. Second, 

providing a rule that a qualified clean 

hydrogen production facility cannot be 

placed in service until January 1, 2023, 

would conflict with section 45V(d)(4), 

which provides that a facility that did 

not produce qualified clean hydrogen 

and that was originally placed in service 

prior to January 1, 2023, can receive a 

new, deemed placed in service date as 

of the date the facility is modified after 

December 31, 2022, to produce qualified 

clean hydrogen. If, as the comment 

suggests, no qualified clean hydrogen 

production facility could be placed in 

service until January 1, 2023, then 

existing hydrogen production facilities 

would receive a new placed in service 

date regardless of whether they meet the 

requirements of section 45V(d)(4), 

rendering section 45V(d)(4) superfluous. 

Third, under the comment’s reading, no 

qualified clean hydrogen production 

facility could be placed in service until 

the hydrogen production and its sale or 

use is verified, as those are requirements 

to have qualified clean hydrogen. 

Verification might not occur until a 

taxable year following the year in which 

the hydrogen was produced, which 

would prevent the credit from being 

determined in the first taxable year of 

production. Fifth, the comment’s 

reading conflicts with section 

6417(b)(5), which makes clear that a 

qualified clean hydrogen production 

facility can be originally placed in 

service prior to January 1, 2023. See 

section 6417(b)(5) (an applicable credit 

includes ‘‘[s]o much of the credit for 

production of clean hydrogen 

determined under section 45V(a) as is 

attributable to qualified clean hydrogen 

production facilities which are 

originally placed in service after 

December 31, 2012.’’). 

Finally, regarding the requirements 

and extent to which pre-existing 

facilities that were originally placed in 

service prior to the enactment of section 

45V can claim the section 45V credit, 

for the reasons explained herein, this 

Summary of Comments and Explanation 

of Revisions clarifies that the owner of 

a qualified clean hydrogen production 

facility originally placed in service prior 

to the enactment of section 45V but after 

December 31, 2012, can claim the 

section 45V credit for the qualified 

clean hydrogen produced during at least 

some portion of the 10-year period 

described in section 45V(a)(1), provided 

all other requirements are met. Thus, 

owners of pre-existing facilities can 

potentially claim the section 45V credit 

for the remaining portion of the 10-year 

credit period. Alternatively, a preexisting facility can receive a new date 

on which it is considered originally 

placed in service if it satisfies the 

requirements of § 1.45V–6(a) (regarding 

the modification of an existing facility 

to produce qualified clean hydrogen) or 


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(b) (regarding the retrofitting of an 

existing hydrogen production facility). 

2. Producer of Qualified Clean 

Hydrogen 

For purposes of section 45V(a)(1) and 

proposed § 1.45V–1(b)(1), proposed 

§ 1.45V–1(b)(2) would have provided 

that the term ‘‘taxpayer’’ means the 

taxpayer that owns the qualified clean 

hydrogen production facility at the time 

of the facility’s production of qualified 

clean hydrogen with respect to which 

the section 45V credit is claimed, 

regardless of whether such taxpayer is 

treated as a producer under section 

263A of the Code or under any other 

provision of law with respect to such 

hydrogen. 

One comment asked whether the 

phrase ‘‘treated as a producer under 

section 263A’’ in proposed § 1.45V– 

1(b)(2) has the same meaning as 

‘‘produced by the taxpayer’’ under 

section 45X(a)(1)(A). To clarify, the term 

‘‘produced by the taxpayer’’ as used in 

section 45X(a)(1)(A) is defined in 

§ 1.45X–1(c) and that definition does 

not apply for purposes of section 45V. 

Section 45X and § 1.45X–1(c) address 

the production of eligible components 

as that term is used in section 45X, and 

not the production of hydrogen for 

purposes of section 45V. Therefore, 

taxpayers must determine whether they 

are considered the producer of the 

qualified clean hydrogen for purposes of 

determining the credit under section 

45V using the definition provided in 

§ 1.45V–1(b)(2), and not by reference to 

the definition of ‘‘produced by the 

taxpayer’’ under § 1.45X–1(c). 

Under section 45V(a)(1) and (c)(3)(A), 

the taxpayer must be both the owner of 

the qualified clean hydrogen production 

facility and the producer of qualified 

clean hydrogen at the facility to be 

eligible for the section 45V credit, 

respectively. The intent of proposed 

§ 1.45V–1(b)(2) was to clarify that, for 

purposes of section 45V(a)(1) and 

§ 1.45V–1(b)(1), the ‘‘taxpayer’’ for these 

purposes is the owner of the qualified 

clean hydrogen production facility at 

the time the hydrogen is produced, 

regardless of whether the owner is 

required to capitalize costs under 

section 263A and § 1.263A–2(a), which 

provide rules relating to property 

produced by the taxpayer. As explained 

in the Explanation of Provisions to the 

proposed regulations, the definition of 

‘‘taxpayer’’ in § 1.45V–1(b)(2) is 

intended, among other things, to avoid 

unintended consequences that could 

arise under § 1.263A–2(a)(1)(ii)(A) and 

(B)(1) with respect to contract 

manufacturing and tolling arrangements 

in the context of the section 45V credit. 

For example, under § 1.45V–1(b)(1), an 

owner of a hydrogen production facility 

that enters into an arrangement with a 

third party service recipient to produce 

qualified clean hydrogen using the 

service recipient’s raw materials and 

inputs in exchange for a fee (a toller) is 

considered the producer of the qualified 

clean hydrogen for purposes of section 

45V regardless of whether the toller is 

required to capitalize costs of producing 

the qualified clean hydrogen under 

section 263A. The final regulations 

provide the intended clarification 

described previously in this paragraph 

to § 1.45V–1(b)(2). 

3. Increased Credit Amount for 

Qualified Clean Hydrogen 

Proposed § 1.45V–1(b)(3) contained a 

cross-reference to § 1.45V–3, which 

provides rules under section 45V(e) that 

permit the amount of the section 45V 

credit determined under section 45V(a) 

and § 1.45V–1(b)(1) to be multiplied by 

five if certain requirements related to 

prevailing wages and apprenticeships 

are met. 

Several comments were received 

relating to the prevailing wage and 

apprenticeship requirements of section 

45V(e). Rules addressing the prevailing 

wage and apprenticeship requirements 

of section 45V(e) are provided in 

§ 1.45V–3, which is not included in this 

rulemaking. See TD 9998, Increased 

Amounts of Credit or Deduction for 

Satisfying Certain Prevailing Wage and 

Registered Apprenticeship 

Requirements (89 FR 53184). 

Accordingly, comments addressing the 

prevailing wage and apprenticeship 

requirements are beyond the scope of 

this rulemaking. These final regulations 

adopt the language in proposed § 1.45V– 

1(b)(3) without change. 

C. Determination of Credit 

Proposed § 1.45V–1(c) would have 

provided that, subject to any applicable 

Code sections that may limit the section 

45V credit amount, the section 45V 

credit for any taxable year is determined 

with respect to the qualified clean 

hydrogen produced by the taxpayer 

during that taxable year, although the 

verification of the production and sale 

or use of such hydrogen may occur in 

a later taxable year. The taxpayer would 

not be eligible to claim the section 45V 

credit with respect to that hydrogen 

until all relevant verification 

requirements, and the verification itself, 

have been completed. Therefore, despite 

such verification occurring in a later 

taxable year, the section 45V credit 

would be properly claimed with respect 

to the taxable year of hydrogen 

production and subject to the general 

period of limitations for filing a claim 

for credit or refund. Thus, if verification 

occurred after the extended return filing 

due date for the taxable year in which 

the hydrogen was produced, the 

taxpayer would need to file an amended 

return or administrative adjustment 

request (AAR), as applicable, to claim 

the section 45V credit for such 

produced hydrogen. 

The Treasury Department and the IRS 

requested comments on proposed 

§ 1.45V–1(c), and whether taxpayers 

anticipated that they would be able to 

complete all the requirements for 

claiming the section 45V credit, 

including the requirements for 

verification specified in proposed 

§ 1.45V–5, by the extended return filing 

deadline for the taxable year of 

hydrogen production. Comments were 

also requested on whether alternatives 

existed. 

Several comments suggested 

alternatives to the requirement in 

§ 1.45V–1(c) that the credit is 

determined in the taxable year of 

hydrogen production. Some comments 

expressed concern that a late 

verification report, filed after the 

extended return filing deadline for the 

taxable year of hydrogen production, 

would preclude taxpayers from making 

an elective payment under section 6417 

or transfer election under section 6418, 

as the necessary elections under those 

statutes cannot be made on an amended 

return or AAR. See sections 6417(d)(3) 

and 6418(e)(1). 

One comment recommended that 

taxpayers be allowed to claim the 

section 45V credit initially without a 

verification report, then once the 

verification report for the relevant 

taxable year is eventually submitted, the 

credit amount is ‘‘trued up,’’ with either 

the government or the taxpayer 

remitting funds to reflect the verified 

emissions rate and amount of 

production. Some comments requested 

taxpayers be allowed to make or change 

an election under section 6417 or 6418 

on an amended return or AAR if they 

are claiming a section 45V credit on 

such amended return or AAR. Another 

comment proposed only requiring 

verification when there has been a 

change in the operation of a taxpayer’s 

hydrogen production facility since the 

last verification, claiming that this 

would reduce the risk of late 

verifications precluding monetization 

elections. Finally, one comment asked 

that taxpayers be allowed to claim the 

section 45V credit and make an elective 

payment election or transfer election 

prior to the formal completion of the 

verification report to avoid missing the 


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extended return filing deadline due to a 

late verification report. 

These final regulations do not adopt 

these comments suggesting revisions to 

the requirements of proposed § 1.45V– 

1(c). First, based on the comments 

received on the timing of verification, 

the Treasury Department and the IRS 

anticipate that qualified verifiers will be 

able to verify a taxpayer’s production 

and sale or use of hydrogen by the 

deadline for filing the taxpayer’s Federal 

income tax return, including extensions, 

so there should be no issue with making 

a timely elective payment or transfer 

election under section 6417 or 6418, 

respectively. Second, the requirement 

that the credit is determined in the 

taxable year of hydrogen production 

adheres to the requirement in section 

45V(a)(1) that the section 45V credit for 

any taxable year is determined based on 

the kilograms of qualified clean 

hydrogen produced by the taxpayer 

during such taxable year. Providing a 

rule that the credit is determined in a 

year other than the taxable year of 

hydrogen production—such as the year 

of verification—would potentially create 

a timing mismatch between the taxable 

year in which the hydrogen is produced 

and creditable under section 45V(a)(1) 

and the taxable year in which the 

section 45V credit for such production 

can be claimed. Third, comments 

suggesting modifications to the rules 

regarding elective payment elections or 

transferability elections under sections 

6417 and 6418, respectively, are beyond 

the scope of this rulemaking under 

section 45V. 

Regarding the comments 

recommending exceptions to the 

verification requirements or allowing 

taxpayers to file verification reports 

after the section 45V credit has been 

claimed, the requirement that the 

production and sale or use of the 

hydrogen be verified is statutorily 

prescribed in section 45V(c)(2)(B)(ii), so 

these final regulations adopt the 

language in proposed § 1.45V–1(c) 

without change. 

II. Special Rules 

A. Coordination With Credit for Carbon 

Oxide Sequestration 

Section 45V(d)(2) provides that no 

section 45V credit is allowed for any 

qualified clean hydrogen produced at a 

facility which includes carbon capture 

equipment for which a section 45Q 

credit is allowed to any taxpayer for the 

taxable year or any prior taxable year. 

Proposed § 1.45V–2(a) would have 

followed that statutory provision and 

additionally provided that if the socalled ‘‘80/20 Rule’’ provided in 

§ 1.45Q–2(g)(5) is satisfied with respect 

to such carbon capture equipment, and 

no new section 45Q credit has been 

allowed to any taxpayer for such carbon 

capture equipment, then the unit of 

carbon capture equipment (as defined in 

§ 1.45Q–2(c)(3)) for which the 80/20 

Rule is satisfied will not be treated as 

carbon capture equipment for which a 

section 45Q credit was allowed to any 

taxpayer for any prior taxable year for 

purposes of section 45V(d)(2) and 

proposed § 1.45V–2(a). 

Further, proposed § 1.45V–1(a)(7)(i) 

would have clarified that equipment 

(which includes carbon capture 

equipment) that functions 

interdependently with other 

components of property to produce 

qualified clean hydrogen is part of the 

qualified clean hydrogen production 

facility, and proposed § 1.45V– 

1(a)(7)(ii)(B) would have clarified that 

electricity production equipment used 

to power the hydrogen production 

process, including any carbon capture 

equipment associated with the 

electricity production process, is not 

part of the qualified clean hydrogen 

production facility. 

Several comments requested 

clarification that a separate, 

independent production line containing 

carbon capture equipment for which a 

section 45Q credit is allowed and that 

is co-located with a hydrogen 

production facility at a single industrial 

site does not disqualify the hydrogen 

production facility from the section 45V 

credit. For example, one comment 

requested clarification that an electricity 

generation facility that is co-located and 

interconnected with the hydrogen 

production facility, and for which the 

section 45Q credit is allowed, will not 

disqualify the hydrogen production 

facility from the section 45V credit. 

Conversely, some comments 

recommended that the final regulations 

modify proposed § 1.45V–1(a)(7)(ii)(B) 

to disallow the section 45V credit for 

hydrogen produced using electricity 

that was generated by an electricity 

generation facility for which the section 

45Q credit is allowed. 

One comment appeared to seek 

clarification that ‘‘allowed,’’ with 

respect to section 45V(d)(2), means the 

taxpayer has claimed the section 45Q 

credit on their tax return, not merely 

that they are eligible for claiming the 

section 45Q credit. The same comment 

requested confirmation that a taxpayer 

can claim the section 45V credit and 

then claim the section 45Q credit in a 

later taxable year on the same facility. 

Finally, one comment requested an 

exception to section 45V(d)(2) to allow 

a taxpayer to claim both the section 45Q 

and section 45V credits on the same 

facility if the facility combines hydrogen 

and CO2 for the purpose of creating 

synthetic molecules. 

These final regulations are not 

modified in response to these 

comments. The final regulations are 

sufficiently clear that the section 

45V(d)(2) rules coordinating the section 

45V credit with the section 45Q credit 

for carbon oxide sequestration only 

apply to the qualified clean hydrogen 

production facility. The definition of 

‘‘facility’’ in § 1.45V–1(a)(7), as clarified 

in these final regulations and described 

in greater detail in part I.A.4 of this 

Summary of Comments and Explanation 

of Revisions, means all the components 

that function interdependently to 

produce clean hydrogen through a 

process that results in the lifecycle GHG 

emissions rate used to determine the 

credit, but does not include electricity 

production equipment used to power 

the hydrogen production process. 

Further, disallowing the section 45V 

credit for hydrogen produced using 

electricity generated at a facility 

containing carbon capture equipment 

for which a section 45Q credit has been 

allowed would require modifying the 

definition of ‘‘facility’’ at § 1.45V–1(a)(7) 

to include electricity production 

equipment. It would also present 

serious horizontal equity concerns for 

hydrogen producers who co-locate with 

electricity generators and those who do 

not. Therefore, electricity production 

equipment that powers the hydrogen 

production process and contains carbon 

capture equipment for which a section 

45Q credit is allowed will not disqualify 

the hydrogen production facility from 

the section 45V credit. Further, these 

final regulations do not modify the 

definition of facility in § 1.45V–1(a)(7) 

to address specific co-located 

equipment used for other industrial 

processes because creating a rule to 

specifically address such co-located 

equipment is not necessary nor possible, 

given that the determination will 

depend on the facts and circumstances 

of such equipment. 

Regarding the meaning of the term 

‘‘allowed,’’ such term generally means 

that the item was claimed on the return 

and not challenged by the IRS. See 

generally Virginian Hotel Corp. of 

Lynchburg v. Helvering, 319 U.S. 523, 

526–27 (1943); Lenz v. Commissioner, 

101 T.C. 260, 264–65 (1993). The 

meaning of ‘‘allowed’’ is sufficiently 

clear as an established tax concept, as 

its definition derives from case law and 

general tax principles, and because the 

term ‘‘allowed’’ appears so frequently in 

the Code and its accompanying 

regulations. 


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Regarding whether a taxpayer can 

claim a section 45Q credit in a 

subsequent taxable year, section 

45V(d)(2) contains no such prohibition, 

so the statute is already sufficiently 

clear and does not need further 

clarification. 

Finally, regarding the comment’s 

request for an exception to section 

45V(d)(2) for the creation of synthetic 

molecules, the prohibition on claiming 

the section 45V credit on a facility for 

which a section 45Q credit has already 

been allowed is statutory, and the 

statute provides no such exception. 

Accordingly, these final regulations 

adopt § 1.45V–2(a) as proposed. 

B. Anti-Abuse Rule 

Section 45V(c)(2)(B)(i) provides, 

among other things, that hydrogen is not 

qualified clean hydrogen unless it is 

produced in the ordinary course of a 

trade or business of the taxpayer, and 

for sale or use. 

Section 45V(f) empowers the 

Secretary to issue regulations or other 

guidance to carry out the purposes of 

section 45V. 

Proposed § 1.45V–2(b)(1) would have 

disallowed the section 45V credit where 

the primary purpose of the production 

and sale or use of qualified clean 

hydrogen was to obtain the section 45V 

credit in a manner that is wasteful. 

Proposed § 1.45V–2(b)(1) would have 

provided as an example the production 

of qualified clean hydrogen that the 

taxpayer knows or has reason to know 

will be vented, flared, or used to 

produce hydrogen. This proposed rule 

is referred to as the ‘‘anti-abuse rule.’’ 

Proposed § 1.45V–5(d)(1) would have 

provided, among other things, that the 

qualified verifier must attest that a 

person has sold or made a verifiable use 

of such hydrogen. Proposed § 1.45V– 

5(d)(2) would have provided that a 

person’s verifiable use of hydrogen 

undergoing verification ‘‘does not 

include—(i) Use of hydrogen to generate 

electricity that is then directly or 

indirectly used in the production of 

more hydrogen; or (ii) venting or flaring 

of hydrogen.’’ This proposed rule is 

referred to as the ‘‘verifiable use rule.’’ 

Many comments in response to the 

proposed regulations made suggestions 

or asked for clarification regarding the 

prohibition in proposed § 1.45V–2(b)(1) 

against the sale or use of hydrogen for 

the primary purpose of obtaining the 

section 45V credit in a wasteful manner, 

often asking that the prohibition not 

apply to a particular scenario or set of 

circumstances. 

Some comments recommended rules 

or asked for clarification regarding the 

prohibition in proposed § 1.45V–2(b)(1) 

against hydrogen production that the 

taxpayer knows or has reason to know 

will be vented or flared. These 

comments noted that venting and flaring 

are often required for routine safety or 

maintenance purposes and contended 

that such use of venting and flaring 

should not disqualify facilities from 

credit eligibility. However, in order to 

align with the purpose of section 45V 

and safeguard against abuse, one of 

these comments asked that the Treasury 

Department and the IRS more clearly 

state that it is the amount of clean 

hydrogen sold or used, not produced, 

that ultimately determines the credit 

amount. 

One comment asked for explicit 

assurance that hydrogen produced and 

sold for use in energy storage would not 

run afoul of the anti-abuse rule when 

the stored energy is later used to 

produce hydrogen. 

Some comments suggested 

disallowing the section 45V credit for 

hydrogen that is produced at the same 

time electricity is generated from 

hydrogen-to-power equipment that is 

physically connected via pipeline. 

Some comments expressed concern 

that the anti-abuse rule would apply to 

certain non-abusive scenarios where 

hydrogen production facilities and 

hydrogen-based electricity generators 

operate concurrently but are connected 

to the same electric grid. 

Another comment asked for 

clarification that capturing excess heat 

from hydrogen production, converting 

that heat to electricity, and using that 

electricity to power the production 

process does not run afoul of the antiabuse rule. 

Some comments asked for 

clarification that the anti-abuse rule 

does not apply to instances where 

produced hydrogen, in some cases from 

process waste streams, is used to power 

the production facility, resulting in 

lower emissions than would otherwise 

be achieved. 

One comment suggested that the antiabuse rule should not consider the cost 

of producing qualified clean hydrogen 

in relation to the amount of the section 

45V credit because doing so would 

disincentivize development of costefficient hydrogen production 

technologies. 

The Treasury Department and the IRS 

agree that clarification of the anti-abuse 

rule is appropriate. The DOE has 

advised that venting of hydrogen 

downstream of a hydrogen production 

facility is a standard industry practice 

where necessary for safety or 

maintenance reasons. The DOE has also 

advised that, in the future, flaring of 

hydrogen that would otherwise have 

been vented could become standard 

industry practice to mitigate the 

environmental impacts of venting. 

Further, the DOE has advised that 

concurrent operation of hydrogen 

production and power generation 

within the same energy storage system 

and at the same time may be wasteful 

if no measures are taken to mitigate or 

reduce the production and consumption 

of the hydrogen at the same time; for 

example, if an electrolytic hydrogen 

production facility as standard practice 

is producing hydrogen at the same time 

as the produced hydrogen is being used 

to produce electricity. However, the 

Treasury Department and the IRS clarify 

here that the anti-abuse rule is not 

meant to apply to the use of hydrogen 

to store energy for later conversion to 

electricity and sale to a regional 

electricity grid, when a buyer from the 

grid uses such electricity to produce 

hydrogen. 

Accordingly, these final regulations 

clarify that the section 45V credit is not 

allowable if the primary purpose of the 

sale or use (rather than the production 

and sale or use) of qualified clean 

hydrogen is to obtain the benefit of the 

section 45V credit in a manner that is 

wasteful. Additionally, these final 

regulations clarify that the taxpayer 

obtains the section 45V credit in a 

wasteful manner if the taxpayer sells 

qualified clean hydrogen that the 

taxpayer knows or has reason to know 

will be vented, flared, used to produce 

heat or power that is then directly used 

to produce hydrogen, or otherwise used 

to produce hydrogen, in excess of 

standard commercial practices. 

Hydrogen is used to produce power that 

is then directly used to produce 

hydrogen if the hydrogen production 

facility exclusively uses such power to 

produce hydrogen or is treated as using 

the power produced by the electricity 

generating facility using the hydrogen 

and such use is verified by the 

acquisition and retirement of qualifying 

EACs. Hydrogen is not used to produce 

power that is then directly used to 

produce hydrogen if the power 

produced using hydrogen is merely 

supplied to the same electricity grid 

from which the hydrogen production 

facility draws power. Proposed § 1.45V– 

2(b)(1) is further modified to provide 

that venting or flaring for safety or 

maintenance reasons in the ordinary 

course of business is a non-abusive 

commercial industry practice. 

Consistent with the comment asking for 

clarity that it is the amount of clean 

hydrogen sold or used, not produced, 

that ultimately determines the credit 

amount, § 1.45V–2(b) of the final 


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regulations adds that, while not abusive, 

such venting or flaring is also not a 

verifiable use under § 1.45V–5(d)(2), 

and therefore any such hydrogen that is 

vented or flared for safety reasons is not 

eligible for the section 45V credit. 

Finally, these final regulations modify 

the example in § 1.45V–2(b)(2) (where 

qualified clean hydrogen is sold to 

obtain the benefit of the section 45V 

credit in a manner that is wasteful and 

thus not eligible for the section 45V 

credit) to reflect that the hydrogen in 

that example will be vented or flared in 

excess of standard commercial practices 

and add an example in § 1.45V–5(d) to 

illustrate the verifiable use rule in the 

context of a facility’s use of its own 

hydrogen within its hydrogen 

production process, flaring of hydrogen 

for testing and maintenance, and waste 

heat recovery. 

Finally, the Treasury Department and 

the IRS disagree with the comment’s 

request that the anti-abuse rule be 

revised to not consider the cost of 

producing qualified clean hydrogen 

relative to the amount of the section 45V 

credit. The cost of hydrogen production 

relative to the amount of the section 45V 

credit is just one of many factors 

considered in the example provided in 

§ 1.45V–2(b)(2). Whether a particular 

taxpayer’s hydrogen production 

activities violate the anti-abuse rule will 

depend on all relevant facts and 

circumstances, and no one factor is 

controlling. Because the cost of 

hydrogen production relative to the 

value of the credit is not the only 

relevant factor, the Treasury Department 

and the IRS do not anticipate that 

including it within the example will 

deter investment in cost-efficient 

technologies. 

A few comments asked that the antiabuse rule be significantly pared back or 

removed altogether. One comment 

argued that the anti-abuse rule’s 

prohibition of a wasteful primary 

purpose has no basis in the statute and 

is too broad to be authorized by the 

‘‘ordinary course of a trade or business 

of the taxpayer’’ requirement of section 

45V(c)(2)(B)(i)(II). The same comment 

proposed revising the anti-abuse rule to 

disallow the section 45V credit only 

where the taxpayer’s sole purpose is to 

obtain the credit in a wasteful manner. 

The same comment asserted that the 

anti-abuse rule exacerbates uncertainty 

by requiring that the rules of section 

45V and the section 45V regulations be 

applied in a manner consistent with the 

purposes of section 45V and the section 

45V regulations, while section 45V only 

authorizes regulations that carry out the 

purposes of the statute. The comment 

further argued that the primary purpose 

examples of wasteful ‘‘production of 

qualified clean hydrogen that the 

taxpayer knows or has reason to know 

will be vented, flared, or used to 

produce hydrogen’’ have no foundation 

in the statute. The comment asked for 

clarification whether a producer having 

a disqualifying purpose at the time of 

production or sale is sufficient to 

disallow the credit under proposed 

§ 1.45V–2(b)(1), or if a disqualifying 

purpose at production and sale is 

required. The comment suggested that 

the example at proposed § 1.45V–2(b)(2) 

seems to indicate that a disqualifying 

purpose at the time of sale is sufficient 

to disallow the credit, while proposed 

§ 1.45V–2(b)(1) seems to indicate that a 

producer must have a disqualifying 

purpose at production and sale for the 

credit to be disallowed. 

First, the argument that section 45V 

provides no basis to support the 

prohibition of a wasteful primary 

purpose through an anti-abuse rule is 

mistaken because (1) the ‘‘for sale or 

use’’ requirement is plainly a purpose 

requirement, and the anti-abuse rule 

implements that purpose requirement; 

in other words, Congress did not intend 

that a nominal sale or use for purposes 

of generating credit claims would entitle 

taxpayers to the credit, but rather 

intended that only a sale or use 

possessing some degree of business 

purpose or economic effect would 

suffice; (2) likewise, the ‘‘in the ordinary 

course of a trade or business of the 

taxpayer’’ requirement justifies an antiabuse rule since any activity with a 

primary purpose of wastefully obtaining 

a tax credit is not within the ordinary 

course of a trade or business; and (3) 

section 45V(f) authorizes the 

promulgation of regulations ‘‘to carry 

out the purposes of this section’’ and the 

obvious purpose of Congress to increase 

the supply of clean hydrogen in the 

United States would be undermined if 

credit claimants were not required to 

make their hydrogen reasonably 

available to legitimate hydrogen 

consumers. Hydrogen that is not so 

available cannot affect hydrogen supply. 

Second, regarding the comment’s 

objection to the proposed anti-abuse 

rule’s requirement that the rules of 

section 45V and its regulations must be 

applied consistently with the purposes 

of the regulations, these final 

regulations do not modify the language 

in the proposed regulations. The section 

45V regulations implement the section 

45V statute. Therefore, taxpayers must 

apply the regulations consistently with 

the purposes of both the statute and its 

implementing regulations. 

Third, the request that the proposed 

anti-abuse rule be modified to only 

disallow the section 45V credit where 

the taxpayer’s ‘‘sole purpose’’ is to 

obtain the credit in a wasteful manner 

is problematic. The ‘‘primary purpose’’ 

requirement is the appropriate standard, 

because a sole purpose requirement 

could allow hydrogen producers to 

argue entitlement to claim the credit 

when nearly all their output is 

knowingly wasted while asserting there 

is some legitimate use for the small 

remainder thereof. 

Fourth, the Treasury Department and 

the IRS agree that a discrepancy exists 

between the text of the proposed 

regulations and the example that would 

have followed regarding whether a 

wasteful primary purpose at the time of 

production or sale or use is sufficient to 

disallow the credit under proposed 

§ 1.45V–2(b)(1), or if a disqualifying 

purpose at production and sale or use is 

required. Accordingly, these final 

regulations adopt proposed § 1.45V–2(b) 

with modifications to the rule and the 

example in order to clarify that only a 

sale or use with the primary purpose of 

obtaining the benefit of the section 45V 

credit in a wasteful manner is sufficient 

to disallow the credit under § 1.45V– 

2(b)(1). Note, the requirements of 

§ 1.45V–2(b)(1) are independent of the 

excessive payment rules provided in 

§ 1.6417–6 and the excessive credit 

transfer rules provided in § 1.6418–5. 

Taxpayers making the election under 

section 6417 or 6418 must separately 

meet the requirements provided in 

§§ 1.6417–6 and 1.6418–5. 

C. Recordkeeping 

Section 6001 provides, among other 

things, that (1) every person liable for 

tax under the Code shall keep such 

records as the Secretary may from time 

to time prescribe; and (2) whenever the 

Secretary deems it necessary, she may 

require any person, by regulations, to 

keep such records as she deems 

sufficient to show whether or not such 

person is liable for tax under the Code. 

Section 45V(e)(5) provides that the 

Secretary shall issue such regulations or 

other guidance as she determines 

necessary to carry out the purposes of 

section 45V(e), including regulations or 

other guidance which provides 

recordkeeping or information reporting 

requirements for purposes of 

administering the requirements of 

section 45V(e). 

Proposed § 1.45V–2(c) would have 

provided recordkeeping requirements 

for all taxpayers claiming the section 

45V credit, including requirements 

related to the section 45V(e) increased 

credit amount. No comments addressed 

this provision. Proposed § 1.45V–2(c) is 

therefore adopted as proposed. 


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III. Procedures for Determining 

Lifecycle Greenhouse Gas Emissions 

Rates for Qualified Clean Hydrogen 

A. In General 

Proposed § 1.45V–4(a) would have 

provided that the amount of the section 

45V credit is determined under section 

45V(a) and proposed § 1.45V–1(b) based 

upon the lifecycle GHG emissions rate 

of all hydrogen produced at a qualified 

clean hydrogen production facility (as 

defined in proposed § 1.45V–1(a)(10)) 

during the taxable year. This 

determination would be required to be 

made following the close of such taxable 

year and must include all hydrogen 

production from the year. See proposed 

§ 1.45V–4(b). Further, proposed 

§ 1.45V–4(a) would have provided that 

the lifecycle GHG emissions rate for 

purposes of section 45V is determined 

under the most recent GREET model (as 

defined in proposed § 1.45V–1(a)(8)(ii)). 

Finally, proposed § 1.45V–4(a) would 

have provided that in the case of any 

hydrogen for which a lifecycle GHG 

emissions rate has not been determined 

under the most recent GREET model for 

purposes of section 45V, a taxpayer 

producing such hydrogen would be 

permitted to file a petition for a 

provisional emissions rate (PER) with 

the Secretary for a determination of the 

lifecycle GHG emissions rate with 

respect to such hydrogen. 

Some comments supported the 

proposed requirement that taxpayers 

calculate the lifecycle GHG emissions 

rate of hydrogen produced at a hydrogen 

production facility based on the 

aggregate amount of hydrogen produced 

at the facility over the taxable year (that 

is, annual emissions averaging). These 

comments claimed that annual 

emissions averaging is more 

straightforward and less 

administratively burdensome than 

alternative methods. The comments also 

claimed that annual emissions averaging 

is less prone to being manipulated 

because it takes into consideration all 

hydrogen produced by the taxpayer over 

the taxable year. The comments 

appeared to suggest that sub-annual 

emissions averaging, where taxpayers 

could potentially select certain subannual periods of clean hydrogen 

production to offset other sub-annual 

periods of hydrogen production that 

would not otherwise meet the lifecycle 

GHG emissions levels required by 

section 45V, is inconsistent with section 

45V. Finally, some comments argued 

that annual emissions averaging is more 

aligned with the capabilities of 45VH2– 

GREET and therefore would help to 

facilitate compliance. 

In contrast, other comments requested 

that hydrogen producers be permitted to 

calculate the lifecycle GHG emissions 

rate of hydrogen produced at their 

facility on a more granular basis, 

suggesting changes to the definition of 

‘‘emissions through the point of 

production (well-to-gate)’’ in proposed 

§ 1.45V–1(a)(8)(iii). Comments 

maintained that determining the 

lifecycle GHG emissions rate for all 

hydrogen produced at a given hydrogen 

production facility during a taxable year 

is burdensome for taxpayers and creates 

uncertainty and risk. Some comments 

requested that lifecycle GHG emissions 

be permitted to be calculated on an 

hourly basis, including in the case of 

hydrogen produced using electricity, 

and in particular once the qualifying 

EAC requirements require temporal 

matching on an hourly basis (see part 

III.D.3.c of this Summary of Comments 

and Explanation of Revisions). Without 

calculation of lifecycle GHG emissions 

on an hourly basis, according to these 

comments, hours of hydrogen 

production that do not have 

corresponding hourly EACs could 

increase the lifecycle GHG emissions 

rate of all hydrogen produced for the 

year—even hydrogen produced using 

electricity represented by a 

corresponding hourly EAC—which 

would be contrary to the hourly 

matching principle. These comments 

note the variability of certain renewable 

or zero-emissions energy sources and 

the limited ability of hydrogen 

production facilities to quickly ramp up 

and down due to technical and 

economic reasons. Still, other comments 

requested that lifecycle GHG emissions 

be permitted to be calculated on a 

kilogram-by-kilogram basis, or by 

batching kilograms of hydrogen into 

distinct groups, to ensure a more precise 

determination of a facility’s lifecycle 

GHG emissions rate. One comment 

requested that, for facilities placed in 

service before 2028, the credit be 

determined with respect to the specific 

volumes of hydrogen that meet the 

temporal matching EAC requirements of 

proposed § 1.45V–4(d)(3)(ii) rather than 

according to the average lifecycle GHG 

emissions rate of all hydrogen produced 

at a qualified clean hydrogen 

production facility on an annual basis. 

The Treasury Department and the IRS 

disagree with eliminating the 

requirement that, in general, the 

lifecycle GHG emissions of a hydrogen 

production process be calculated on an 

annual basis. Section 211(o)(1)(H) of the 

Clean Air Act defines ‘‘lifecycle GHG 

emissions’’ as the aggregate quantity of 

GHG emissions (including direct 

emissions and significant indirect 

emissions such as significant emissions 

from land use changes), as determined 

by the EPA. Determining the lifecycle 

GHG emissions rate of a hydrogen 

production process, therefore, requires 

taking the ‘‘aggregate’’ quantity of 

emissions from a hydrogen production 

process over the course of the taxable 

year to derive a single emissions rate. 

This is consistent with the 

determination of the section 45V credit 

on an annual basis. Section 45V(a)(1) 

provides that ‘‘the clean hydrogen 

production credit for any taxable year is 

an amount equal to the product of the 

kilograms of qualified clean hydrogen 

produced by the taxpayer during such 

taxable year’’ (emphasis added). 

Calculating lifecycle GHG emissions for 

a hydrogen production process on an 

annual basis, therefore, aligns with the 

manner in which the section 45V credit 

is determined. 

The Treasury Department and the IRS 

clarify that such annual determination 

is made separately for each hydrogen 

production process conducted at a 

hydrogen production facility during the 

taxable year. As a result, hydrogen 

producers will be able to claim higher 

credit amounts for producing qualified 

clean hydrogen using lower-emitting 

hydrogen production processes during 

the year, such as by using feedstocks 

with lower carbon intensities. For 

further discussion on process, see part 

I.A.7 of this Summary of Comments and 

Explanation of Revisions (explaining 

that production using each type of 

primary feedstock is considered a 

separate production process). 

However, once hourly matching is 

required for qualifying EACs, hydrogen 

produced through a process that uses 

electricity may be at risk of not 

qualifying for the section 45V credit at 

an expected amount if a small number 

of hours are not covered by the 

acquisition and retirement of qualifying 

EACs, which could occur as a result of 

unforeseeable circumstances beyond a 

taxpayer’s control. 

Further, if a taxpayer believes it is 

infeasible to secure EACs from 

renewable or zero-emissions sources for 

every hour or a significant share of 

hours in a taxable year, then calculating 

lifecycle GHG emissions on an annual 

basis may cause such taxpayer to have 

no incentive to produce qualified clean 

hydrogen or qualified clean hydrogen in 

the lowest lifecycle GHG emissions tier. 

This is inconsistent with the purposes 

of section 45V, which includes 

encouraging the production of qualified 

clean hydrogen (with a higher credit 

amount for hydrogen with lower 

lifecycle GHG emissions rates) and 


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investments in hydrogen production 

facilities and processes that produce 

qualified clean hydrogen. 

Section 1.45V–4(a)(2) of these final 

regulations provides a method to 

mitigate the risk associated with 

potential limitations in the supply of 

qualifying EACs, coupled with a 

guardrail to limit availability of this 

election to processes in which the 

taxpayer is producing qualified clean 

hydrogen, calculated on an annual 

basis. Specifically, proposed § 1.45V– 

4(a) is modified to provide that, solely 

for purposes of determining the lifecycle 

GHG emissions associated with a 

hydrogen production facility’s use of 

electricity generated on or after January 

1, 2030, to produce hydrogen, such 

emissions may be determined on an 

hourly basis. If a taxpayer utilizes this 

method, it must determine all emissions 

from the facility’s use of electricity for 

the taxable year on an hourly basis. On 

or after January 1, 2030, when hourly 

matching is required, a facility’s 

lifecycle GHG emissions from electricity 

for that hour will reflect the attributes 

of the qualifying EAC acquired and 

retired for that hour. In the case of 

electricity use as part of the hydrogen 

production process for which the 

taxpayer does not acquire and retire a 

qualifying EAC that reflects a specific 

hour in which such electricity was 

generated on or after January 1, 2030, 

the electricity emissions for that hour is 

determined by assuming that the facility 

is sourcing power with emissions equal 

to the default electricity emissions 

intensity within the regional electricity 

grid. The January 2025 version of the 

45VH2–GREET User Manual provides 

further information on how such hourly 

accounting may be conducted in 

45VH2–GREET. These final regulations 

add § 1.45V–4(a)(3)(i) and (ii) to provide 

examples illustrating the calculation of 

the lifecycle GHG emissions rate of the 

process used to produce hydrogen at a 

qualified clean hydrogen production 

facility, determined on an annual and 

an hourly basis, respectively. 

This method is provided pursuant to 

the authority in section 45V(f) to ‘‘issue 

regulations or other guidance to carry 

out the purposes of [section 45V].’’ With 

respect to a facility’s use of electricity in 

a hydrogen production process 

(including a facility that produces 

hydrogen through electrolysis, which is 

a single hydrogen production process), 

these final regulations modify the 

proposed rules to further incentivize the 

production of clean hydrogen in light of 

the temporal matching requirement 

provided in § 1.45V–4(d)(3)(ii). In 

particular, once the qualifying EAC 

requirements require temporal matching 

on an hourly basis, in the case of 

hydrogen produced using electricity 

that is represented by a qualifying EAC, 

a taxpayer who owns a facility that 

produces hydrogen through a process 

that results in annual emissions not 

greater than 4 kilograms of CO2e per 

kilogram of hydrogen can elect to 

determine the emissions associated with 

the electricity used in that process on an 

hourly basis. This method would enable 

hydrogen producers to mitigate the risk 

that limited availability of qualifying 

EACs could adversely affect eligibility 

for the section 45V credit for all 

hydrogen from a single process. 

This method is available only if the 

process for which an election is made 

achieves an annual lifecycle GHG 

emissions rate of not greater than 4 

kilograms of CO2e per kilogram of 

hydrogen for all hydrogen produced 

pursuant to that process during the 

taxable year. This guardrail advances 

the purposes of section 45V because it 

provides added flexibility and risk 

mitigation only in circumstances where 

the hydrogen production process 

produces hydrogen that, over the course 

of the year, meets the definition of 

qualified clean hydrogen on an annual 

basis. In the absence of this condition, 

allowing the lifecycle GHG emissions 

associated with electricity used in a 

hydrogen production process to be 

determined on an hourly basis could 

encourage the production of hydrogen 

through processes that do not meet the 

emissions requirements of section 45V, 

contrary to the statute and the purpose 

of section 45V. 

B. Use of 45VH2–GREET 

Proposed § 1.45V–4(b) would have 

provided procedures to calculate the 

lifecycle GHG emissions rate of 

hydrogen produced at a hydrogen 

production facility using the most 

recent GREET model as defined in 

proposed § 1.45V–1(a)(8)(ii) (referring to 

45VH2–GREET). Proposed § 1.45V–4(b) 

would have further provided that 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 hydrogen produced at a hydrogen 

production facility within the interface 

of 45VH2–GREET. 

The 45VH2–GREET User Manual 

released in conjunction with the 

proposed regulations provided that 

45VH2–GREET is expected to be 

updated on at least a yearly basis. 

Moreover, it mentioned that these 

updates are expected to include 

representations of additional hydrogen 

production processes and updates to 

background data (as supporting analysis 

is completed by the Argonne National 

Laboratory). This means that, under 

proposed § 1.45V–4(b), use of 45VH2– 

GREET would result in taxpayers using 

an updated version of 45VH2–GREET 

each taxable year (insofar as such an 

update arises). 

Multiple comments raised concern 

about the requirement for taxpayers to 

use a potentially updated version of 

45VH2–GREET each taxable year during 

the 10-year credit period due to 

uncertainty about whether changes to 

45VH2–GREET may unexpectedly alter 

annual emissions assessments, which 

would directly impact the amount of the 

section 45V credit. Several comments 

requested that taxpayers be allowed to 

‘‘lock in’’ the version of 45VH2–GREET 

that was available on the date the ‘‘final 

investment decision’’ was made. 

Similarly, several other comments 

requested that taxpayers be allowed to 

use the latest version of 45VH2–GREET 

that was available on the date the 

hydrogen production facility was placed 

in service or the date when construction 

of the facility began (beginning of 

construction or BOC). Some of these 

comments further requested that 

taxpayers be allowed to use subsequent 

updated versions of 45VH2–GREET at 

their discretion. Finally, some 

comments requested that taxpayers be 

permitted to rely upon a single version 

of 45VH2–GREET unless and until there 

is a material change to the facility’s 

hydrogen production process. 

In considering these comments, the 

Treasury Department and the IRS note 

that the statute envisions use of updated 

models, referencing use of ‘‘the most 

recent’’ version of GREET or a successor 

model. However, the Treasury 

Department and the IRS understand that 

taxpayers would benefit from having 

more certainty about a hydrogen 

production facility’s lifecycle GHG 

emissions rate throughout the credit 

period for that facility, and therefore 

have determined that a beginning of 

construction safe harbor provision 

would help mitigate taxpayers’ 

reasonable concern. Accordingly, the 

final regulations modify proposed 

§ 1.45V–4(b) by adding a second 

paragraph (§ 1.45V–4(b)(2)) giving 

taxpayers the option to make an election 

to use the version of 45VH2–GREET that 

was in effect on the date when 

construction of their hydrogen 

production facility began for the 

remaining taxable years within the 10- 

year credit period. 

In the case of a facility owned by the 

taxpayer that began construction prior 

to December 26, 2023, § 1.45V–4(b)(2) 

provides taxpayers with the option to 

make an election to use the first 


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13 2022–52 I.R.B. 560. 

14See Notice 2013–29, 2013–20 I.R.B. 1085, 

clarified by Notice 2013–60, 2013–44 I.R.B. 431, 

then clarified and modified by Notice 2014–46, 

2014–36 I.R.B. 520, then updated by Notice 2015– 

25, 2015–13 I.R.B. 814, then clarified and modified 

by Notice 2016–31, 2016–23 I.R.B. 1025, and then 

updated, clarified, and modified by Notice 2017– 

04, 2017–4 I.R.B. 541; Notice 2018–59, 2018–28 

I.R.B. 196, modified by Notice 2019–43, 2019–31 

I.R.B. 487, then modified by Notice 2020–41, 2020– 

25 I.R.B. 954, and then clarified and modified by 

Notice 2021–5, 2021–3 I.R.B. 479, and then clarified 

and modified by Notice 2021–41, 2021–29 I.R.B. 17. 

15See Notice 2020–12, 2020–11 I.R.B. 495. 

16See Notice 2018–59, modified by Notice 2019– 

43 and by Notice 2020–41, and then clarified and 

modified by Notice 2024–41. 

publicly available version of 45VH2– 

GREET (that is, the version of 45VH2– 

GREET released in December 2023) for 

the remaining taxable years within the 

10-year credit period. This election is 

irrevocable, meaning taxpayers may not 

subsequently opt to use an updated 

version of 45VH2–GREET once they 

have opted to lock-in the applicable 

version of 45VH2–GREET. Section 

1.45V–4(b)(2)(i) of the final regulations 

further provides that, 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 

the facility began construction is the 

date construction of the modification or 

retrofit began. Finally, § 1.45V– 

4(b)(2)(ii) is added to provide that a 

taxpayer makes the election with 

respect to a qualified clean hydrogen 

production facility’s hydrogen 

production process on Form 7210 by no 

later than the due date (including 

extensions) for filing the taxpayer’s 

Federal income tax return for a taxable 

year ending no later than December 31, 

2025, or for the taxable year in which 

such facility is placed in service, 

whichever taxable year is later. The 

election is made separately for each 

hydrogen production process (but on 

the same Form 7210). For purposes of 

determining BOC, taxpayers may rely 

upon the guidance provided in Notice 

2022–61,13 as well as the guidance 

issued under sections 45,14 45Q,15 and 

48.16 Changes have also been made to 

proposed § 1.48–15(d) to provide a 

corresponding BOC safe harbor with 

respect to a specified clean hydrogen 

production facility. 

It is appropriate to provide this safe 

harbor based on a facility’s beginning of 

construction date because it better 

supports the purpose of taxpayer 

certainty than a placed in service date, 

and because, unlike a ‘‘final investment 

decision’’ date, the beginning of 

construction date is an established, 

defined concept in tax law. For 

taxpayers that elect to lock-in a version 

of 45VH2–GREET, these final 

regulations do not adopt the comments’ 

suggestions that taxpayers also be given 

the option to use subsequent updated 

versions of 45VH2–GREET at their 

discretion. Such an option would enable 

taxpayers to lock-in a version of 45VH2– 

GREET while retaining the option to 

elect a future version of 45VH2–GREET 

that would reflect lower lifecycle GHG 

emissions, which would fail to further 

the purpose of this safe harbor to 

provide additional taxpayer certainty. 

In all other cases, taxpayers must use 

the latest version of 45VH2–GREET 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; or, if a version of 

45VH2–GREET becomes publicly 

available after the first day of the taxable 

year of production (but still within such 

taxable year), then the taxpayer may, in 

its discretion, treat such later version of 

45VH2–GREET as the 45VH2–GREET 

Model. 

C. Provisional Emissions Rate (PER) 

1. In General 

Proposed § 1.45V–4(c)(1) would have 

provided that, for purposes of section 

45V(c)(2)(C) and proposed § 1.45V–4(a), 

the term ‘‘provisional emissions rate’’ or 

‘‘PER’’ means the lifecycle GHG 

emissions rate of the process by which 

qualified clean hydrogen is produced by 

the taxpayer at a qualified clean 

hydrogen production facility as 

determined by the Secretary under 

proposed § 1.45V–4(c). No comments 

addressed this definition, so it is 

adopted as proposed with one change 

made to clarify that 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 § 1.45V–4(c). 

2. Restriction on Filing a Provisional 

Emissions Rate Petition 

Proposed § 1.45V–4(c)(2)(i) would 

have provided that a taxpayer may not 

file a petition with the Secretary for a 

PER unless a lifecycle GHG emissions 

rate has not been determined under the 

most recent GREET model (as defined in 

proposed § 1.45V–1(a)(8)(ii) as 45VH2– 

GREET) for hydrogen produced by the 

taxpayer at a hydrogen production 

facility. Further, proposed § 1.45V– 

4(c)(2)(i) would have provided that a 

lifecycle GHG emissions rate has not 

been determined under the most recent 

GREET model with respect to hydrogen 

produced by the taxpayer at a hydrogen 

production facility if it uses a hydrogen 

production pathway that is not included 

in the most recent GREET model—that 

is, if either the feedstock used by such 

facility or the facility’s hydrogen 

production technology is not included 

in the most recent GREET model. 

Proposed § 1.45V–4(c)(2)(i) also would 

have provided that, if a taxpayer’s 

request for an emissions value from the 

DOE under proposed § 1.45V–4(c)(5) 

with respect to the hydrogen produced 

by the taxpayer at a hydrogen 

production facility is pending at the 

time such hydrogen production 

facility’s pathway is included in an 

updated version of 45VH2–GREET, then 

the taxpayer’s request for an emissions 

value will automatically be denied. 

Some comments, despite proposed 

§ 1.45V–4(c)(2)(i), and in disagreement 

with its restriction on filing a PER 

petition, sought to clarify that a taxpayer 

using a hydrogen production pathway 

included in 45VH2–GREET may 

nevertheless file a PER petition because 

they have independently verifiable data 

that differs from the background data 

used by 45VH2–GREET. Many of these 

comments challenged the 

appropriateness of the background data 

used by 45VH2–GREET, claiming that 

they do not reflect the actual values of 

such parameters and that more accurate 

measurements of such parameters can 

be reliably obtained by taxpayers. These 

comments therefore requested that 

taxpayers be allowed to file a PER 

petition after challenging these 

assumptions through the EVRP, because 

using actual values would likely result 

in a lower and more accurate emissions 

rate. 

The parameters in 45VH2–GREET 

have been deemed background data if 

independent verification of bespoke 

values for individual facilities is 

expected to be infeasible with 

reasonable fidelity. The Treasury 

Department and the IRS recognize that 

the capabilities of verification resources 

are evolving, and the DOE is 

continuously monitoring the availability 

of robust data and verification methods 

for both background and foreground 

data parameters in 45VH2–GREET. For 

example, as described in part III.E of 

this Summary of Comments and 

Explanation of Revisions, an upcoming 

release of 45VH2–GREET will include 

upstream methane loss rates as 

foreground data once enhanced GHG 

reporting to the EPA is available and 

other program integrity measures are 

fully implemented. Once a parameter 

becomes foreground data in 45VH2– 

GREET, taxpayers may treat that 


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parameter as foreground data in their 

emissions value request application 

(through an EVRP in support of the PER 

process). Allowing taxpayers to provide 

their own values for background data 

would run counter to the rationale for 

determining that a given parameter is 

background data. The Treasury 

Department and the IRS note that 

allowing taxpayers to challenge 

background data through the EVRP 

likely would significantly increase the 

number of emissions value request 

applications, resulting in substantial 

administrative burden and 

administrability concerns for the DOE, 

and potentially far slower reviews for all 

interested taxpayers. Therefore, these 

final regulations do not allow taxpayers 

to avail themselves of the PER petition 

process if their hydrogen production 

pathway (which consists of the 

combination of production technology 

and input feedstock materials and 

sources) is included in 45VH2–GREET 

regardless of any disagreement with the 

background assumptions. 

Several comments also raised 

concerns about the treatment of novel 

variations of hydrogen production 

pathways that currently are represented 

in 45VH2–GREET, claiming that the 

model does not provide the correct 

emissions value for their variation. 

These comments asked that the final 

regulations modify proposed § 1.45V– 

4(c)(2)(i) to state explicitly that 

taxpayers may use the PER process for 

novel variations of existing pathways. 

These final regulations do not adopt 

these comments. Since the original 

version of 45VH2–GREET and 

supporting documentation were 

published, the DOE has updated the 

model and the 45VH2–GREET User 

Manual to include specific definitions 

of the feedstocks and technologies 

represented in the model. Taxpayers 

who have developed a novel variation of 

a hydrogen production pathway may 

use the PER process if their pathway 

does not meet the definitions of the 

feedstocks and technologies represented 

in the 45VH2–GREET Model. The text of 

§ 1.45V–4(c)(2)(i) and the definitions in 

the 45VH2–GREET User Manual 

provide sufficient information to 

taxpayers to determine whether their 

pathway qualifies for the PER process. 

Several comments asked to streamline 

the process for petitioning for a PER for 

RNG feedstocks derived from nonlandfill sources (for example, food 

waste, animal waste, and biogas derived 

from renewable diesel or sustainable 

aviation fuel production), claiming that 

these sources make up 30 percent of 

North American RNG production. It is 

not clear whether these comments, in 

requesting to streamline the process for 

petitioning for a PER, are asking the 

Treasury Department and the IRS to 

allow these taxpayers to participate in 

the PER process altogether or whether 

they are requesting the Treasury 

Department and the IRS create a 

separate, streamlined PER petition 

process for taxpayers who plan to 

produce hydrogen using non-landfill 

RNG. To the extent that the comments 

ask for the former, as stated above, 

taxpayers may petition the Secretary for 

a PER if either the feedstock used by 

their facility or the facility’s hydrogen 

production technology is not included 

in 45VH2–GREET. Moreover, it is 

anticipated that some non-landfill RNG 

hydrogen production processes (such as 

from livestock manure) will be added to 

45VH2–GREET in 2025, in a manner 

that is consistent with these final 

regulations. To the extent that the 

comments ask for a separate, 

streamlined PER process, these final 

regulations do not adopt this request as 

it is not consistent with the statutory 

purposes of section 45V to offer 

preferential treatment to any group of 

feedstocks. 

Lastly, one comment asked that the 

Treasury Department and the IRS 

decline to issue a PER for taxpayers 

using geologic hydrogen until more 

robust climate and environmental data 

is available. The Treasury Department 

and the IRS are aware that emissions 

analysis of newer methods of hydrogen 

production, such as geologic hydrogen, 

is subject to technical uncertainty. The 

DOE intends to address these 

uncertainties by engaging with 

applicants during the EVRP and through 

independent research. The DOE intends 

to issue emissions values only when an 

analysis has been completed robustly 

addressing these uncertainties, and to 

an extent comparable to other 

uncertainties within 45VH2–GREET. 

Applicants to the PER process will 

additionally be subject to the 

independent verification requirements 

of proposed § 1.45V–5, which will help 

ensure the key sources of greenhouse 

gases are reflected in the lifecycle 

analysis of a given facility. Given these 

safeguards, the Treasury Department 

and the IRS clarify in this Summary of 

Comments and Explanation of Revisions 

to these final regulations that PERs may 

be used for any hydrogen production 

pathway (meaning a specific technology 

and input feedstock materials and 

sources) not included in the 45VH2– 

GREET Model, including geologic 

hydrogen. No further clarification in the 

regulatory text is needed; therefore, 

these final regulations adopt proposed 

§ 1.45V–4(c)(2)(i) with conforming 

changes made to confirm that the 

Secretary has designated 45VH2–GREET 

as a successor model. 

Proposed § 1.45V–4(c)(2)(ii) would 

have specified that, notwithstanding 

proposed § 1.45V–1(a)(8)(ii), for the 

taxable year in which the hydrogen 

production pathway the taxpayer uses 

to produce hydrogen at a qualified clean 

hydrogen production facility is first 

included in an updated version of 

45VH2–GREET, the updated version of 

45VH2–GREET will be considered the 

most recent GREET model with respect 

to the hydrogen produced by the 

taxpayer at the hydrogen production 

facility. No comments addressed this 

provision. It is adopted as proposed 

with changes made to confirm that the 

Secretary has designated 45VH2–GREET 

as a successor model and to clarify that, 

for purposes of the PER process, the 

lifecycle GHG emissions rate of the 

hydrogen produced at a hydrogen 

production facility is made with respect 

to hydrogen produced through a 

process. 

3. Process for Filing a Provisional 

Emissions Rate Petition 

Proposed § 1.45V–4(c)(3) would have 

provided that a taxpayer petitions the 

Secretary for a PER by attaching a PER 

petition to its Federal income tax 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 

proposed § 1.45V–4(c)(2)(i). Proposed 

§ 1.45V–4(c)(3) would have provided 

that a PER petition must contain (i) an 

emissions value obtained from the DOE 

setting forth the DOE’s analytical 

assessment of the lifecycle GHG 

emissions associated with the facility’s 

hydrogen production pathway, and (ii) 

a copy of the taxpayer’s request to the 

DOE for an emissions value, including 

any information that the taxpayer 

provided to the DOE pursuant to the 

emissions value request process 

specified in proposed § 1.45V–4(c)(5). 

The Treasury Department and the IRS 

understand that this filing requirement 

may mean that a taxpayer must attach 

voluminous documents to its return, 

which may cause tax administration 

issues. For effective tax administration, 

the Treasury Department and the IRS 

have modified this provision to state 

that a PER petition must contain (i) the 

letter received from the DOE stating the 

emissions value the DOE determined 

with respect to the facility’s hydrogen 


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production pathway, and (ii) the DOE 

control number assigned to the 

emissions value request of the taxpayer. 

This information will be sufficient for 

the Treasury Department and the IRS to 

be able to request additional 

information from the taxpayer, as 

necessary. 

Proposed § 1.45V–4(c)(3) would have 

further provided that, if the taxpayer 

obtained more than one emissions value 

from the DOE, then 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 to 

which the PER petition is attached. No 

comments were received on this 

provision and it is adopted as proposed 

with amendments to reflect the new 

requirements for what a PER petition 

must contain and to clarify that the 

taxpayer attaches the PER petition to its 

Federal income tax return or 

information return. 

4. Provisional Emissions Rate 

Determination 

Proposed § 1.45V–4(c)(4) would have 

provided that upon the IRS’s acceptance 

of the taxpayer’s Federal income tax 

return or information return containing 

a PER petition, the emissions value 

specified on such PER petition will be 

deemed accepted. Proposed § 1.45V– 

4(c)(4) would have provided that a 

taxpayer would be able to 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. Proposed § 1.45V–4(c)(4) also 

would have provided that the IRS’s 

deemed acceptance of such emissions 

value is the Secretary’s determination of 

the PER. Proposed § 1.45V–4(c)(4) 

would have stated, however, that the 

production and sale or use of such 

hydrogen must be verified by an 

unrelated party under section 

45V(c)(2)(B)(ii) and in compliance with 

the procedures provided in proposed 

§ 1.45V–5. Proposed § 1.45V–4(c)(4) 

would have stated that 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. No comments were received on 

this provision. This provision is 

adopted as proposed with a clarification 

to § 1.45V–4(c)(4) to clarify that the 

emissions value is deemed accepted 

upon the taxpayer’s filing of its Federal 

income tax return (or information 

return), and to clarify that 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 EVRP 

application, and sale or use of the 

hydrogen must be verified under 

§ 1.45V–5. 

5. Department of Energy Emissions 

Value Request Process 

Proposed § 1.45V–4(c)(5) would have 

provided that, in order to obtain an 

emissions value, an applicant must 

submit a request for an emissions value 

following procedures specified by the 

DOE. The DOE opened the EVRP to the 

public on September 30, 2024. 

Proposed § 1.45V–4(c)(5) also would 

have provided that emissions values 

will be evaluated using the same wellto-gate system boundary that is 

employed in 45VH2–GREET, as 

proposed in § 1.45V–1(a)(8)(iii). 

Additionally, proposed § 1.45V–4(c)(5) 

would have provided that, if applicable, 

background data parameters in 45VH2– 

GREET would be treated as background 

data (with fixed values that an applicant 

cannot change) in the EVRP. The EVRP 

would be subject to any guidance issued 

under section 45V, including any 

guidance related to the use of EACs. 

Proposed § 1.45V–4(c)(5) would have 

further provided that an applicant may 

request an emissions value from the 

DOE only after a front-end engineering 

and design (FEED) study or similar 

indication of project maturity, such as 

project specification and cost estimation 

sufficient to inform a final investment 

decision, has been completed for the 

hydrogen production facility. 

Additionally, proposed § 1.45V–4(c)(5) 

would have provided that 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. 

Guidance and procedures for applicants 

to request and obtain an emissions value 

from the DOE are published by the DOE 

on its 45V Emissions Value Request 

application page, which may be found 

at https://www.energy.gov/eere/45vemissions-value-request. 

In the Explanation of Provisions to the 

proposed regulations, the Treasury 

Department and the IRS requested 

comments on the appropriate indicators 

of project readiness that should be in 

place before an applicant requests an 

emissions value to ensure that requests 

correspond to hydrogen production 

facilities with significant commercial 

interest, and standards against which 

these indicators could be measured. 

The Treasury Department and the IRS 

received many comments in response to 

that request for comments. The 

comments questioned the FEED study 

requirement, claiming that these studies 

are costly and create uncertainty in 

investment decisions. The comments 

claimed that a key economic factor in 

justifying the cost of a FEED study is the 

amount of section 45V credit a project 

can claim, and estimating the credit 

without the emissions value is not 

feasible. The comments further claimed 

that the level of project maturity 

required for a FEED study necessitates 

a substantial amount of capital 

investment, which creates uncertainty 

because taxpayers would be taking a 

risk that their substantial investment 

may be frustrated by a higher-thanexpected emissions value and thus a 

lower section 45V credit. Instead of 

requiring a FEED study, the comments 

suggested a variety of alternatives: (i) a 

front-end loading (FEL–2) level 

feasibility study, coupled with a 

detailed financial model and a lifecycle 

GHG emissions analysis prepared by a 

qualified party; (ii) sufficient 

engineering definition to produce a 

Class 4 cost estimate, as defined by the 

Association for the Advancement of 

Cost Engineering (AACE) International 

Recommended Practice No. 18R–97; and 

(iii) exemption from this requirement 

for certain pathways. 

At this nascent stage of the EVRP and 

after consultation with the DOE, these 

final regulations retain the requirement 

for a FEED study but clarify that a 

taxpayer only needs a Class 3 FEED 

study or similar indication of project 

maturity, as determined by the DOE, to 

apply for an emissions value. Class 3 

FEED studies reflect more mature 

projects than FEED studies of Class 4 or 

5, making them more likely to be robust 

and therefore likely to facilitate faster 

reviews. Class 3 FEED studies can be 

conducted sooner in a project and are 

generally less detailed or timeconsuming than a Class 1 or 2 FEED 

study, addressing the comments’ 

concerns on cost. Further, the DOE 

advised that Class 3 FEED studies are 

likely to be conducted by a majority of 

developers of hydrogen production 

facilities across pathways, given how 

complex and capital intensive these 

facilities are. However, the DOE will 

continue to explore the feasibility of 

alternatives to a Class 3 FEED study (for 

example, a FEED study of a different 

class) and may identify such 

alternatives in the future. To the extent 

the DOE determines that a similar 

indicator of project maturity would 

satisfy the requirements of § 1.45V– 

4(c)(5), such determination will be 

published by the DOE on its 45V 


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Emissions Value Request application 

page. Thus, the provision is adopted as 

proposed with changes made to clarify 

that a taxpayer may apply for an 

emissions value only after it has 

completed a Class 3 FEED study or other 

indication of project maturity, as 

determined by the DOE. The receipt of 

an emissions value, however, does not 

constitute a determination that all other 

requirements for claiming the section 

45V credit, including compliance with 

the anti-abuse and verifiable use rules, 

are met. 

The Treasury Department and the IRS 

also received many comments on the 

EVRP generally. Some of these 

comments requested that the Treasury 

Department and the IRS (in conjunction 

with the DOE) create an appeals process 

through which an applicant can 

challenge their emissions value. A few 

comments requested that applicants be 

allowed to revise or supplement their 

emissions value request application at 

various stages of the application 

process. Some comments requested that 

the DOE allow applicants with multiple 

facilities to apply for one emissions 

value. And other comments asked that 

applicants be able to submit various 

documents in support of their 

applications (for example, submitting 

documents obtained using modeling 

software or the R&D GREET model). 

The DOE has not developed an 

appeals process or a method for an 

applicant to unilaterally revise or 

supplement their application. However, 

an applicant may submit additional 

information to the DOE before the DOE 

has completed its analysis or after it has 

determined the facility’s emissions 

value. These final regulations provide 

that applicants seeking a new emissions 

value 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. If the applicant’s 

resubmissions result in the applicant 

receiving multiple emissions values 

from the DOE for a given hydrogen 

production pathway, the applicant 

should use the value that aligns with the 

information the applicant provided to 

the DOE with respect to the facility’s 

operations in support of the application 

that resulted in the emissions value 

used The DOE will evaluate emissions 

value request applications using 

information provided by applicants 

coupled with background data in 

45VH2–GREET (for example, grid 

emissions, upstream methane 

emissions). If background data in 

45VH2–GREET evolve, information in 

the latest version of 45VH2–GREET will 

be used. As new background data 

parameters are added to 45VH2–GREET 

or existing parameters become 

disaggregated (for example, if 

regionalized upstream methane 

parameters are incorporated in lieu of a 

national average), the DOE may revise 

the information requested through the 

EVRP to be consistent with the 

information required to run 45VH2– 

GREET. For example, if 45VH2–GREET 

is modified to include regional 

upstream methane background 

assumptions, and to require users to 

select the region that their natural gas is 

sourced from, applicants to the EVRP 

will also be expected to provide 

information about the region their 

natural gas is sourced from and will be 

evaluated using the same regional 

upstream methane background 

assumptions. 

Some comments expressed concern 

about the timing and transparency of the 

EVRP. Regarding timing, the comments 

expressed concern that submitted 

requests would have long processing 

times and that could affect project 

funding and create delays. These 

comments suggested that the DOE 

impose on itself a time limit to process 

applications, after which time an 

applicant’s emissions value is deemed 

to be the value determined by the 

lifecycle GHG emissions analysis 

attached to their tax return. 

The DOE has advised that it 

endeavors to review requests as quickly 

as possible. A provision to impose a 

time limit on the DOE’s consideration of 

emissions value requests could impede 

an accurate and rigorous review of the 

requests and would require additional 

administrative processes. Additionally, 

because the IRS deems as accepted the 

emissions value provided by the DOE 

upon filing, and such deemed 

acceptance is the Secretary’s 

determination of the PER as provided in 

proposed § 1.45V–4(c)(4), an accurate 

and rigorous review is necessary to such 

a determination. Regarding 

transparency, the DOE has stated 

publicly in the Emissions Value Request 

Application Instructions the variables 

that drive the timeline for application 

review, which include the volume of 

applications around a given pathway, 

complexity/ease of evaluating the 

hydrogen production pathway, and the 

commercial readiness of the pathway. 

The DOE has advised that it expects to 

be able to provide additional 

transparency regarding the timeline 

required for application review. Any 

additional information will be 

published by the DOE on its 45V 

Emissions Value Request page. 

6. Effect of Provisional Emissions Rate 

Proposed § 1.45V–4(c)(6) would have 

provided that a taxpayer may use a PER 

determined by the Secretary to calculate 

the amount of the clean hydrogen 

production credit under section 45V(a) 

and proposed § 1.45V–1(b) with respect 

to qualified clean hydrogen produced by 

the taxpayer at a qualified clean 

hydrogen production facility beginning 

with the first taxable year in which a 

PER determined by the Secretary has 

been obtained and for any subsequent 

taxable year during the 10-year period 

beginning on the date such facility was 

originally placed in service, provided all 

other requirements of section 45V are 

met, and until the lifecycle GHG 

emissions rate of such hydrogen has 

been determined (for purposes of 

section 45V(c)(2)(C)) under the most 

recent version of 45VH2–GREET (as 

defined in proposed § 1.45V–1(a)(8)(ii)). 

Proposed § 1.45V–4(c)(6) would have 

further provided that the Secretary’s 

PER determination is not an 

examination or an inspection of books 

of account for purposes of section 

7605(b) of the Code, and would 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. Proposed § 1.45V– 

4(c)(6) would have provided that a 

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 an emissions value request 

would still be subject to IRS 

examination. Further, proposed 

§ 1.45V–4(c)(6) would have stated that a 

PER determination would not mean that 

the IRS has determined that all the 

requirements of section 45V have been 

satisfied for any taxable year, nor would 

it create an inference that such a 

presumption exists. 

Some comments asked the Treasury 

Department and the IRS to allow 

optionality between using the PER 

process or 45VH2–GREET, claiming that 

the optionality would provide more 

flexibility and certainty for hydrogen 

producers. Other comments asked for 

the creation of a ‘‘safe harbor’’ rule, 

allowing taxpayers to continue using 

their PERs in cases where their pathway 

was incorporated into 45VH2–GREET 

and the model calculated a higher 

emissions rate than the taxpayers’ 

respective PERs. These comments also 

claimed that a ‘‘safe harbor’’ rule would 

provide certainty and alleviate any 

unfairness that may come from having 


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2250 Federal Register / Vol. 90, No. 6 / Friday, January 10, 2025 / Rules and Regulations 

a higher emissions rate with 45VH2– 

GREET than with a PER. 

The Treasury Department and the IRS 

recognize that a taxpayer’s inability to 

estimate with a high degree of certainty 

the amount of section 45V credit—due 

to the possibility that their hydrogen 

production pathway will be 

subsequently included in 45VH2– 

GREET, which might reflect a higher 

lifecycle GHG emissions rate than their 

PER—could affect a taxpayer’s efforts to 

obtain financing for a hydrogen 

production facility. Allowing taxpayers 

to lock-in a PER in all instances, 

however, would be inconsistent with 

the statute. Section 45V(c)(1)(B) 

provides that lifecycle GHG emissions 

shall be determined using the most 

recent version of the GREET model or a 

successor model, as determined by the 

Secretary. Section 45V(c)(2)(C) provides: 

‘‘In the case of any hydrogen for which 

a lifecycle greenhouse gas emissions 

rate has not been determined for 

purposes of this section, a taxpayer 

producing such hydrogen may file a 

petition with the Secretary for 

determination of the lifecycle 

greenhouse gas emissions rate with 

respect to such hydrogen.’’ Section 

45V(c)(2)(C) is a conditional sentence. 

For a taxpayer to be eligible to petition 

the Secretary for a PER, the taxpayer 

must meet the condition of producing 

hydrogen for which a lifecycle GHG 

emissions rate has not been determined 

(that is, hydrogen whose technology or 

feedstock is not in 45VH2–GREET). 

Likewise, for a taxpayer to be eligible to 

continue using a PER, the taxpayer’s 

technology or feedstock must not be in 

45VH2–GREET. Allowing optionality or 

creating a safe harbor rule in this case 

would mean ignoring the condition set 

by Congress. Therefore, these final 

regulations do not adopt these 

comments. 

Following the confines of the statute, 

these final regulations clarify in 

§ 1.45V–4(c)(6)(i) that taxpayers may 

continue to use the PER determined by 

the Secretary under § 1.45V–4(c)(4) to 

calculate the amount of the section 45V 

credit with respect to qualified clean 

hydrogen produced at a qualified clean 

hydrogen production facility, provided 

that (1) 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 (as described in § 1.45V– 

4(c)(2)(ii)) (subject to the exception in 

§ 1.45V–4(c)(6)(iv)); (2) 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 

§ 1.45V–4(c)(2)(i), and (3) all other 

requirements of section 45V are met. 

These final regulations further clarify in 

§ 1.45V–4(c)(6)(ii) that 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) and § 1.45V–5(c). 

Further, § 1.45V–4(c)(6)(iii)(A) is 

added to provide that 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 version of 45VH2–GREET in which 

the taxpayer’s qualified clean hydrogen 

production facility’s hydrogen 

production pathway is first included as 

the 45VH2–GREET Model. The final 

regulations also add § 1.45V– 

4(c)(6)(iii)(B) to provide that the 

taxpayer makes the election with 

respect to a qualified clean hydrogen 

production facility on Form 7210 for the 

taxable year in which the taxpayer’s 

qualified clean hydrogen production 

facility’s hydrogen production pathway 

is first included in 45VH2–GREET. 

Changes have also been made to § 1.48– 

15(d) to provide a corresponding 

subsequent inclusion safe harbor 

election with respect to a specified 

clean hydrogen production facility. 

Finally, § 1.45V–4(c)(6)(iv) is added to 

provide a special rule for taxpayers who 

received an emissions value from the 

DOE prior to beginning construction of 

their respective facility. This rule allows 

a taxpayer to continue relying on its 

PER, despite the rate having been 

determined under the 45VH2–GREET 

Model. Section 1.45V–4(c)(6)(iv) 

provides that, notwithstanding the 

requirement of § 1.45V–4(c)(6)(i)(A), a 

taxpayer who received an emissions 

value from the DOE with respect to a 

qualified clean hydrogen production 

facility pursuant to § 1.45V–4(c)(2)(i) 

before the date when construction of the 

facility began, may, in its discretion, 

continue to use the PER determined by 

the Secretary and the associated 

emissions value to calculate the amount 

of the section 45V credit with respect to 

qualified clean hydrogen produced at 

the qualified clean hydrogen production 

facility for the remainder of the period 

described in section 45V(a)(1), provided 

that the taxpayer continues to satisfy the 

requirements of § 1.45V–4(c)(6)(i)(B) 

and (C). This special rule is limited to 

taxpayers who obtained an emissions 

value before the date when construction 

of their facility began because these 

taxpayers began construction in reliance 

on their PERs. Taxpayers who began 

construction before obtaining an 

emissions value did not do so in 

reliance on their PERs and therefore, as 

a temporal matter, did not need to lockin their PERs in order to secure 

financing to begin construction. This 

special rule provides parallel treatment 

to the beginning of construction safe 

harbor for 45VH2–GREET in § 1.45V– 

4(b)(2)(i). 

D. Use of Energy Attribute Certificates 

(EACs) 

1. In General 

Proposed § 1.45V–4(d) would have 

provided a framework for the use of 

EACs as the sole means of documenting 

purchased electricity inputs from 

specific sources and reflecting 

emissions impacts of that electricity 

used in the production of hydrogen for 

purposes of the section 45V credit. 

Under this framework, a taxpayer must 

acquire and retire qualifying EACs to 

establish, for purposes of section 45V, 

that it acquired for use electricity from 

a specific electricity generation facility 

(and therefore did not rely on the 

electricity generally sourced via the 

regional electricity grid). The framework 

would have required taxpayers to 

acquire and retire EACs that meet 

requirements for incrementality, 

temporal matching, and deliverability 

(qualifying EAC requirements), as 

provided in proposed § 1.45V–4(d)(3). 

These final regulations generally adopt 

the qualifying EAC framework of the 

proposed regulations, with the 

modifications noted in this part III.D of 

this Summary of Comments and 

Explanation of Revisions. 

Proposed § 1.45V–4(d)(1) would have 

provided that for purposes of section 

45V, if a taxpayer determines a lifecycle 

GHG emissions rate for hydrogen 

produced at a hydrogen production 

facility using the most recent version of 

45VH2–GREET (as defined in proposed 

§ 1.45V–1(a)(8)(ii)) or a PER (as defined 

in proposed § 1.45V–4(c)(1)), then the 

taxpayer may reflect in 45VH2–GREET 

or include in a PER such hydrogen 

production facility’s use of electricity as 

being from a specific electricity 

generating facility rather than being 

from the regional electricity grid (as 

represented in 45VH2–GREET) only if 

the taxpayer acquires and retires a 

qualifying EAC (as defined in proposed 

§ 1.45V–4(d)(2)(iv)) 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, proposed 

§ 1.45V–4(d)(1) would have provided 

that in order to satisfy this requirement, 

a taxpayer’s acquisition and retirement 


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Federal Register / Vol. 90, No. 6 / Friday, January 10, 2025 / Rules and Regulations 2251 

17 Double Counting, U.S. Environmental 

Protection Agency, available at https://

www.epa.gov/green-power-markets/doublecounting (last updated Jan. 15, 2024). 

of qualifying EACs must also be 

recorded in a qualified EAC registry or 

accounting system (as defined in 

proposed § 1.45V–4(d)(2)(iv)) so that the 

acquisition and retirement of such EACs 

may be verified by a qualified verifier 

(as defined in proposed § 1.45V–5(h)). 

With respect to the requirement that 

each unit of electricity used to produce 

hydrogen needs to be matched with the 

electricity represented by the qualifying 

EACs, in the proposed regulations the 

Treasury Department and the IRS 

specifically requested comment as to 

whether a different treatment would be 

more appropriate to account for 

transmission and distribution line 

losses. For example, taxpayers could be 

required to adjust the electricity 

represented by the qualifying EAC 

downward to account for such losses, 

which would necessitate buying 

additional qualifying EACs to make up 

for the adjustment. Some comments 

supported the approach of the proposed 

regulations to not impose a downward 

adjustment of EACs because granular 

geographic matching would already 

mitigate transmission and distribution 

line losses. Other comments agreed 

there should be no downward 

adjustment to EACs, expressing 

administrability concerns that an 

adjustment to an EAC to account for 

losses would vary depending on the 

taxpayer’s location. In contrast, other 

comments countered that an adjustment 

should be made to account for 

transmission and distribution line 

losses, to accurately determine 

electricity usage and GHG emissions, 

unless the hydrogen production facility 

can provide sufficient documentation 

that shows that no losses have occurred. 

These comments posit that not requiring 

an adjustment could cause a 

mismeasurement of GHG emissions, by 

failing to take into account the 

electricity used to make up for such 

losses. In response to these comments, 

the Treasury Department and the IRS, 

after consultation with the DOE and the 

EPA, note that existing EAC markets— 

including markets where purchasers 

buy EACs to comply with Clean Energy 

Standards (CES) or Renewable Portfolio 

Standards (RPS) as well as those where 

purchasers voluntarily choose to buy 

EACs—use EACs to enable end-use 

claims on a one-to-one basis. As noted 

by the comments, accounting for 

transmission and distribution line losses 

also would pose administrability 

challenges for taxpayers and for 

verification given uncertainty regarding 

appropriate assumptions to account for 

such losses. For these reasons, these 

final regulations maintain standard 

practice and therefore retain the one-toone rule of the proposed regulations. 

Given the increased accuracy that 

accounting for such losses would 

provide, the Treasury Department and 

the IRS may revisit this requirement if 

the administrability and verification 

challenges abate. 

Several comments asked that the final 

regulations state that distributed energy 

resources may generate qualifying EACs. 

One of these comments proposed 

clarifying that all resources that qualify 

for wholesale bidding under Federal 

Energy Regulatory Commission (FERC) 

Order No. 2222, Participation of 

Distributed Energy Resource 

Aggregations in Markets Operated by 

Regional Transmission Organizations 

and Independent System Operators (85 

FR 67094), may generate EACs. In 

response, the Treasury Department and 

the IRS confirm that distributed energy 

resources that are grid connected or are 

directly connected to a hydrogen 

production facility may generate 

qualifying EACs, provided that the 

requirements of § 1.45V–4(d) are met. 

Several comments asked for 

exceptions to the EAC framework, under 

which a taxpayer could establish the use 

of electricity from a specific electricity 

generation source without the 

acquisition and retirement of qualifying 

EACs. Another comment proposed 

allowing the use of power purchase 

agreements as an alternative to the EAC 

framework. Similarly, several comments 

suggested exempting any hydrogen 

production facility with its own behindthe-meter source of clean electricity (for 

example, a directly connected hydrogen 

production facility) from the EAC 

framework. 

In response to these comments, the 

Treasury Department and the IRS note 

that the EAC framework is necessary to 

prevent double counting of the energy 

and emissions attributes represented by 

EACs and to mitigate the risk of 

significant indirect emissions. As 

explained in part V.C of the Explanation 

of Provisions to the proposed 

regulations, the double counting of 

EACs and their underlying energy and 

emissions attributes would undermine 

the integrity of lifecycle GHG emissions 

rate determinations that incorporate 

EACs. Double counting occurs if two 

different parties claim the energy and 

emissions attributes and associated 

environmental benefits from generated 

energy.17 Uniformly requiring claims of 

using electricity generated from specific 

sources to be evidenced by EACs that 

meet the requirements of § 1.45V– 

4(d)(1) would mitigate the risk of double 

counting. Thus, the requirements of the 

EAC framework must be met regardless 

of whether the electricity generating 

facility giving rise to the qualifying EAC 

is grid connected, directly connected, or 

co-located with the hydrogen 

production facility (that is, regardless of 

whether the underlying source of the 

qualifying EAC physically supplies 

electricity through a direct connection 

to the hydrogen production facility). 

With respect to behind-the-meter 

sources of clean electricity, the Treasury 

Department and the IRS note that many 

such sources already participate in EAC 

registries and sell EACs. Even in cases 

in which the electricity source does not 

participate in a formal EAC registry, 

because every unit of electricity 

generated has tradeable attributes, and 

because the use of such electricity for 

hydrogen production can still result in 

increased emissions, EACs must still be 

generated and retired. In addition, 

behind-the-meter sources still pose a 

risk of induced emissions if such 

sources involve pre-existing generation 

that was grid-connected or was used for 

a purpose other than hydrogen 

production; such sources would result 

in induced emissions if they were 

diverted to hydrogen production. 

Similarly, making the EAC framework 

optional or allowing an exception for 

power purchase agreements raises the 

possibility of double counting of energy 

and emissions attributes. While it is 

possible this concern could potentially 

be reduced through alternative measures 

such as a ‘‘no double sale’’ attestation 

made by the electricity source with 

respect to the attributes, such 

alternatives would create 

administrability and coordination 

problems for sales made outside the 

EAC framework. In contrast, the 

required use of the EAC framework 

described in the proposed regulations 

provides for a consistent and effective 

anti-double counting system that is 

uniform for all taxpayers, regardless of 

their sources of electricity, and 

represents standard industry practice 

across regulatory and voluntary markets. 

Because of these many reasons, no 

alternative measures are necessary or 

appropriate. 

Several comments suggested that the 

Treasury Department and the IRS 

should explicitly forbid double counting 

of EACs in the final regulations. One 

comment was concerned that given the 

number of EAC registries on the market 

there would be a high risk of double 

counting when multiple registries 


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2252 Federal Register / Vol. 90, No. 6 / Friday, January 10, 2025 / Rules and Regulations 

substantiate an EAC for the same unit of 

electricity. While the Treasury 

Department and the IRS concur that 

double counting is a risk absent an EAC 

framework that prevents double 

counting, the EAC framework of these 

final regulations is intended to mitigate 

that risk by requiring qualifying EACs to 

be tracked in EAC registries and 

establishing minimum requirements for 

such registries. The Treasury 

Department and the IRS are confident 

that EAC registries can continue to 

mitigate the risks of double counting in 

part by working together to ensure that 

each issued EAC is distinct and unique. 

In addition, these final regulations 

modify the requirements for third-party 

verification to require verifiers to 

confirm and attest either that electricity 

generators tied to EACs applied to a 

particular section 45V credit claim are 

not registered on multiple qualifying 

EAC registries, or that, if such 

generators are registered on multiple 

qualifying EAC registries, each EAC 

undergoing verification from each such 

generator is being issued by only one 

qualifying EAC registry. This will 

further reduce double counting risks. 

See § 1.45V–5(c)(2). The final 

regulations also modify the definition of 

eligible EAC in § 1.45V–4(d)(2)(iii) to 

clarify that the EAC must be registered 

on only one qualified EAC registry or 

accounting system. 

One comment stated that the EAC 

framework in the proposed regulations 

does not align with similar frameworks 

adopted by States through RPS and CES. 

The comment suggested that the 

misalignment could lead to double 

counting and other accounting issues 

and recommended that the Treasury 

Department and the IRS align its EAC 

framework with that of the States. 

However, the Treasury Department and 

the IRS do not agree that the EAC 

framework of the proposed regulations 

is misaligned with similar frameworks 

adopted by States through RPS and CES. 

Under section 45V, hydrogen producers 

are likely to be able to use the same EAC 

registries as are employed by the States 

for purposes of RPS compliance, 

voluntary markets, and other needs. It is 

true that the statutory basis of section 

45V requires the Treasury Department 

and the IRS to establish EAC qualifying 

criteria that are different from State RPS 

programs. Some of these criteria will 

require EAC registries to augment their 

capabilities to ensure that clean 

hydrogen producers have access to 

qualifying EACs. However, the Treasury 

Department and the IRS are confident 

that if market demand for qualifying 

EACs exist, EAC registries will develop 

the necessary functional requirements 

for EAC tracking to meet that demand. 

Such development is already occurring. 

For example, a variety of comments 

have stated that hourly tracking by 2030 

or earlier would be feasible, and several 

EAC registries have begun to introduce 

such tracking. 

Several comments requested 

clarification of the extent to which 

taxpayers can claim the section 45V 

credit while availing themselves of 

other incentive programs that also 

require the acquisition and retirement of 

EACs. For example, one comment 

requested clarification that an EAC can 

be used to satisfy both section 45V 

requirements and the California Low 

Carbon Fuel Standard (CA LCFS). In 

response to these comments, the 

Treasury Department and the IRS reaffirm that double counting of EACs is 

disallowed. EACs may not be acquired 

and retired for purposes of the EAC 

framework of section 45V if they are 

separately acquired and retired for any 

other purpose. However, taxpayers may 

take advantage of section 45V 

concurrently with State incentive and 

other programs in other ways, at the 

discretion of State policymakers. For 

instance, hydrogen credited by section 

45V may be an eligible fuel in CA LCFS 

(to the extent this is allowed by 

California’s rules). In addition, the 

treatment within State programs of 

clean electricity, the EACs of which 

have been acquired and retired for 

hydrogen production under section 45V, 

is a matter of State policy. 

One comment asked that the final 

regulations allow for relief from filing 

deadlines if a taxpayer is unable to 

comply with the EAC framework due to 

a delay, such as with third-party 

verification. The comment suggested 

that because the verification process is 

new and untested, there should be an 

accommodation process for producers 

that are unable to file or amend their 

returns prior to the close of the section 

6511(a) statute of limitations on filing a 

claim for credit or refund. The Treasury 

Department and the IRS are aware that 

taxpayers may encounter unforeseeable 

compliance issues. The section 45V 

credit may be claimed on an amended 

return or AAR, as with other credits, 

subject to the section 6511(a) statute of 

limitations noted by the comment. Part 

IV.K of this Summary of Comments and 

Explanation of Revisions explains 

further clarifications to the third-party 

verification rules of proposed § 1.45V– 

5(k)(2), that such verification, so long as 

it is made prior to the date the amended 

return or AAR is filed, is considered 

timely. Accordingly, these final 

regulations do not provide the requested 

filing relief at this time, but the Treasury 

Department and the IRS will continue to 

monitor the compliance concerns raised 

by the comment. 

The same comment requested that 

hydrogen producers that acquire EACs 

from a qualified EAC registry or 

accounting system in good faith be 

permitted to rely on the EACs and not 

be held accountable for errors or 

inaccuracies in such information after 

the fact. In response, the Treasury 

Department and the IRS again note that 

the EAC framework is intended to 

mitigate double counting and other 

errors. To the extent the comment 

requests a safe harbor for the 

information contained in any acquired 

EAC, these final regulations do not 

adopt the comment, as the creation of 

such a safe harbor would require the 

Treasury Department and the IRS to 

determine what constitutes good faith. 

In response to the comment’s concern 

about errors with respect to EACs, 

§ 1.45V–4(d)(2)(viii) of the final 

regulations provides standards that a 

qualified EAC registry or accounting 

system must meet, and the Treasury 

Department and the IRS expect that 

registries meeting these standards will 

help ensure a high degree of accuracy 

with respect to their qualifying EACs. 

Finally, a number of comments raised 

questions with respect to how the EAC 

framework and qualifying EAC 

requirements relate to hydrogen 

produced using renewable natural gas or 

fugitive methane. These comments are 

addressed in the general discussion of 

hydrogen produced using RNG or 

fugitive methane, in part III.H of this 

Summary of Comments and Explanation 

of Revisions. 

2. Definitions 

Proposed § 1.45V–4(d)(2) included 

definitions for the terms (i) ‘‘commercial 

operations date;’’ (ii) ‘‘energy attribute 

certificate;’’ (iii) ‘‘eligible EAC;’’ (iv) 

‘‘qualifying EAC;’’ (v) ‘‘qualified EAC 

registry or accounting system;’’ and (vi) 

‘‘region.’’ These terms are retained in 

these final regulations. The final 

regulations also add the new definitions 

of (i) ‘‘qualifying electricity 

decarbonization standard;’’ (ii) 

‘‘qualifying GHG cap program;’’ (iii) 

‘‘merchant nuclear reactor’’; (iv) 

‘‘qualifying nuclear reactor;’’ (v) 

‘‘written binding contract;’’ and (vi) 

‘‘qualifying State,’’ which are discussed 

in part III.D.3.b of this Summary of 

Comments and Explanation of 

Revisions. The paragraphs of § 1.45V– 

4(d)(2) are renumbered in these final 

regulations to account for these 

additional terms. 


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Federal Register / Vol. 90, No. 6 / Friday, January 10, 2025 / Rules and Regulations 2253 

18WREGIS was identified as a qualified EAC 

registry in the Explanation of Provisions to the 

proposed regulations. See Proposed § 1.45V–4, 88 

FR 89220, 89228 (Dec. 26, 2023). 

These final regulations amend the 

definition of eligible EACs and provide 

additional requirements for electricity 

sources that use carbon capture 

technology (discussed in part III.D.3.b.ii 

of the Summary of Comments and 

Explanation of Provisions). 

The Treasury Department and the IRS 

received several comments concerning 

the proposed definitions. Proposed 

§ 1.45V–4(d)(2)(iii)(C) would have 

required an EAC (as defined in 

proposed § 1.45V–4(d)(2)(i)) to provide a 

‘‘commercial operations date’’ or ‘‘COD’’ 

to be an ‘‘eligible EAC.’’ Proposed 

§ 1.45V–4(d)(2)(i) would have defined 

COD as the date on which a facility that 

generates electricity begins commercial 

operations. The COD, as defined here, 

would be the first date of the operation 

of the relevant electricity generating 

facility. The general rules for 

determining an electricity generating 

facility’s placed in service date for 

Federal income tax purposes would not 

have applied in determining its COD. 

One comment noted that the Western 

Renewable Energy Generation 

Information System (WREGIS) 18

database does not currently track the 

COD of electricity generation facilities 

and asked the requirement to provide a 

COD be removed from the definition of 

eligible EAC. The comment suggested 

that the final regulations instead rely on 

qualified verifiers to determine the 

COD. The Treasury Department and the 

IRS disagree that COD is not tracked in 

WREGIS. The COD of each generator is 

available in the WREGIS database and 

linked to a project identification. 

Therefore, the final regulations do not 

adopt this comment. 

Proposed § 1.45V–4(d)(2)(v) would 

have defined ‘‘qualified EAC registry or 

accounting system’’ to mean a tracking 

system that (i) assigns a unique 

identification number to each EAC 

tracked by such system, (ii) enables 

verification that only one EAC is 

associated with each unit of electricity, 

(iii) verifies that the underlying 

attributes of each EAC is claimed and 

retired only once, (iv) identifies the 

owner of each EAC, and (v) provides a 

publicly accessible view (for example, 

through an application programming 

interface) of all currently registered 

electricity generators in the tracking 

system to prevent the duplicative 

registration of such generators. Many 

comments called for the Treasury 

Department and the IRS to develop 

standardized rules for EAC registries. 

Several comments suggested adoption of 

the ‘‘EnergyTag’’ standard would 

prevent fraud, enhance auditability, 

facilitate registry interoperability, and 

provide application programming 

interface access features as well as 

cybersecurity standards. 

In response to these comments, the 

Treasury Department and the IRS note 

that rules of proposed § 1.45V– 

4(d)(2)(v), finalized herein under 

§ 1.45V–4(d)(2)(viii), provide a set of 

standardized requirements that EAC 

registries must satisfy. These final 

regulations do not provide specific rules 

prescribing the standards that EAC 

registries must follow to satisfy these 

requirements. A single standard, while 

desirable, is not adopted due to lack of 

sufficient consensus among EAC 

registries and their participants. Further, 

adopting a single standard could have 

unintended consequences and 

unnecessarily burden or exclude certain 

EAC registries. The Treasury 

Department and the IRS, however, 

encourage EAC registries and external 

stakeholders to work together to develop 

such standards. The proposed 

regulations noted that qualified EAC 

registries currently include, but are not 

necessarily limited to, the following: 

Electric Reliability Council of Texas 

(ERCOT); Michigan Renewable Energy 

Certification System (MIRECS); Midwest 

Renewable Energy Tracking System, Inc. 

(M–RETS); North American Registry 

(NAR); New England Power Pool 

Generation Information System 

(NEPOOL–GIS); New York Generation 

Attribute Tracking System (NYGATS); 

North Carolina Renewable Energy 

Tracking System (NC–RETS); PJM 

Generation Attribute Tracking System 

(PJM–GATS); and WREGIS. The 

Treasury Department and the IRS 

continue to expect that these registries 

will be qualified EAC registries as 

defined in § 1.45V–4(d)(2)(viii) of the 

final regulations but note that these 

registries currently do not generally 

issue or track EACs that meet the hourly 

tracking requirements of § 1.45V– 

4(d)(3)(ii)(A) of the final regulations. 

One comment emphasized that EAC 

registries are currently not fully 

developed for use with respect to 

section 45V and noted that many of the 

identified qualified EAC registries do 

not track all electricity sources. In 

response, the Treasury Department and 

the IRS recognize that the section 45V 

final regulations will require EAC 

registries to develop new capabilities. 

For instance, some EAC registries do not 

track all forms of electricity, and hourly 

tracking capabilities are just being 

developed. However, the EAC registry 

rules established in these final 

regulations ensure consistency with the 

section 45V statutory requirements, 

including its requirement to determine 

lifecycle GHG emissions rates, which 

includes addressing significant indirect 

emissions such as potential induced 

emissions. In addition, the Treasury 

Department and the IRS anticipate that 

EAC registry rules in these final 

regulations, and industry interest in 

complying with requirements for 

securing the tax credit, will provide a 

significant market incentive for 

registries to enhance their capabilities to 

meet the needs of the clean hydrogen 

industry. The Treasury Department and 

the IRS also note that there is 

substantial interest from a broad crosssection of electricity consumers, 

including but not limited to hydrogen 

production facilities, in the 

development of these same capabilities 

to enable voluntary market claims 

related to hourly matching of clean 

electricity. The Treasury Department 

and the IRS encourage EAC registries to 

work together and with stakeholders to 

develop appropriate, common 

approaches to enhancing the ability of 

EAC registries to provide additional, 

reliable tracking information, and are 

confident that the new capabilities can 

be developed by the EAC registries to 

facilitate compliance with section 45V 

and accelerate the growth of clean 

hydrogen production. 

Finally, the Treasury Department and 

the IRS received comments with respect 

to the definition of ‘‘region’’, which are 

addressed in response to comments 

received regarding deliverability in 

proposed § 1.45V–4(d)(3)(iii) in part 

III.D.3.d of this Summary of Comments 

and Explanation of Revisions. 

3. Qualifying EAC Requirements 

a. In General 

Proposed § 1.45V–4(d)(3) would have 

provided that an EAC meets the 

requirements to be a qualifying EAC if 

it meets the qualifying EAC 

requirements for incrementality, 

temporal matching, and deliverability. 

A taxpayer is not required to acquire 

and retire qualifying EACs. However, 

the taxpayer may only reflect in 45VH2– 

GREET or include in a PER the 

taxpayer’s use of electricity as being 

from a specific electricity generating 

facility (rather than being from the 

regional electricity grid) if the taxpayer 

acquires and retires qualifying EACs. 

See proposed § 1.45V–4(d)(1). 

Many comments supported these 

requirements. Generally, these 

comments agreed that the qualifying 

EAC requirements are necessary to 

ensure that electricity consumption 


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2254 Federal Register / Vol. 90, No. 6 / Friday, January 10, 2025 / Rules and Regulations 

19See Letter from Janet McCabe, Deputy 

Administrator, U.S. Environmental Protection 

Agency, to Lily Batchelder, Assistant Secretary for 

Tax Policy, U.S. Department of the Treasury (Dec. 

20, 2023), available at https://home.treasury.gov/ 

system/files/136/45V-NPRM-EPA-letter.pdf (EPA 

December 2023 Letter). 

20See U.S. Department of Energy, Assessing 

Lifecycle Greenhouse Gas Emissions Associated 

with Electricity Use for the Section 45V Clean 

Hydrogen Production Tax Credit (Dec. 19, 2023), 

available at https://www.energy.gov/45vresources 

(scroll to ‘‘45V White Paper;’’ then click ‘‘Read and 

download the 45V White Paper’’). 

associated with hydrogen production, 

and particularly with electrolytic 

hydrogen production and other 

electricity-intensive hydrogen 

production pathways, do not result in 

significant induced grid emissions that 

would disqualify the hydrogen 

production from the tax credit under the 

statute. Comments also stated that the 

qualifying EAC requirements are the 

best way to adhere to the statutory 

requirements of section 45V(c)(1). One 

comment stated that the proposed 

regulations’ interpretation of section 

211(o)(1)(H) of the Clean Air Act aligned 

with both section 45V and the EPA’s 

interpretation. Another comment 

suggested that the proposed regulations’ 

accounting of induced grid emissions is 

consistent with longstanding 

interpretation by the EPA with respect 

to the Clean Air Act, about which 

Congress was aware when section 45V 

was enacted. 

On the other hand, many comments 

criticized the qualifying EAC 

requirements. Several comments 

contended that the qualifying EAC 

requirements lack legal support in 

section 45V and fail to align with 

congressional intent. These comments 

questioned the underlying policy 

rationale. Comments also criticized the 

concept of ‘‘induced grid emissions.’’ 

One comment argued that neither 

section 45V, the Clean Air Act, nor any 

other Federal statute identifies the risk 

of ‘‘induced grid emissions’’ as a basis 

for imposing the qualifying EAC 

requirements. 

After consideration of these 

comments, these final regulations retain 

the qualifying EAC requirements. The 

consideration of significant indirect 

emissions, which in this context 

includes induced grid emissions, is 

required by section 45V. Section 

45V(c)(1) defines the term ‘‘lifecycle 

greenhouse gas emissions’’ to have the 

same meaning as that under section 

211(o)(1)(H) of the Clean Air Act, 

limited to include only emissions 

through the point of production (wellto-gate). Section 211(o)(1)(H) of the 

Clean Air Act provides, in relevant part, 

that ‘‘[t]he term ‘lifecycle greenhouse 

gas emissions’ means the aggregate 

quantity of greenhouse gas emissions 

(including direct emissions and 

significant indirect emissions such as 

significant emissions from land use 

changes), as determined by the [EPA] 

Administrator, related to the full fuel 

lifecycle’’ (emphasis added). Thus, not 

considering significant indirect 

emissions related to the full lifecycle of 

the fuel (including the electricity used 

to produce the hydrogen) in the 

determination of a lifecycle GHG 

emissions rate for a hydrogen process 

would be contrary to the statute. 

As noted in the Explanation of 

Provisions of the proposed regulations, 

the Treasury Department and the IRS 

consulted with the EPA and the DOE to 

develop the qualifying EAC framework. 

The EPA advised that, based on its prior 

implementation of section 211(o)(1)(H) 

of the Clean Air Act in the context of the 

RFS, it would be reasonable for the 

Treasury Department and the IRS to 

determine that induced grid emissions 

are an anticipated real-world result of 

electrolytic hydrogen production that 

constitute significant indirect emissions 

and must therefore be considered in 

lifecycle GHG analyses for purposes of 

the section 45V credit.19 As the EPA 

December 2023 Letter explained, 

‘‘[e]lectricity users, including hydrogen 

producers, can cause or induce 

emissions by adding new load and 

consuming electricity. Because the grid 

must always balance electricity demand 

with supply, this increased electricity 

demand results in increased electricity 

supply and, if the new electricity is not 

zero-emitting, additional emissions from 

the grid.’’ As induced grid emissions are 

not currently included in the emissions 

calculations provided by any version of 

GREET, the use of qualifying EACs as a 

means to consider induced GHG 

emissions is a reasonable 

methodological proxy in lieu of 

calculating these emissions as part of 

the LCA assessment. 

The EPA also noted that EACs are an 

established means for documentation 

and verification of the generation and 

purchase of zero-GHG-emitting 

electricity. Moreover, the EPA advised 

that, in the context of electrolytic 

hydrogen, EACs that possess specific 

attributes that meet certain criteria are 

an appropriate way in the context of 

section 45V of verifying the generation 

and delivery of zero GHG-emitting 

electricity and can serve as a reasonable 

methodological proxy for quantifying 

induced grid emissions associated with 

new load from electrolytic hydrogen 

production being added to an existing 

grid. Such requirements would mitigate 

the risk of inappropriately crediting 

hydrogen production that does not meet 

the lifecycle GHG levels required by 

section 45V. 

The development of the qualifying 

EAC requirements and framework was 

also informed by a 2023 DOE technical 

paper (DOE Technical Paper).20 As 

discussed therein, incrementality, 

temporal matching, and deliverability 

requirements are important guardrails to 

ensure that hydrogen producers’ 

electricity use can be reasonably 

deemed to reflect the emissions 

associated with the specific generators 

from which the EACs were purchased 

and retired. If hydrogen producers rely 

on EACs without attributes that meet 

these three criteria there is a significant 

risk that hydrogen production would 

significantly increase direct and 

significant indirect GHG emissions— 

and, in particular, induced grid 

emissions—beyond the levels required 

to qualify for the section 45V credit. 

Based on advice of the DOE and the 

EPA, the proposed regulations included 

the qualifying EAC requirements. Upon 

consideration of the comments received, 

these final regulations retain the 

requirements. The qualifying EAC 

requirements are indeed necessary to 

address the risk of significant indirect 

emissions associated with electricity use 

for purposes of the section 45V credit. 

Electricity from a specific generator will 

have a GHG emissions profile that 

results from both its direct and indirect 

emissions. Requiring EACs with 

attributes that meet the three criteria is 

necessary to address and prevent, to the 

extent reasonably practicable, indirect 

GHG emissions resulting from the 

dynamics of the electricity market and 

the electric grid and fulfill the statute’s 

directive to only award the section 45V 

credit to hydrogen production with 

lifecycle GHG emissions within 

specified levels. 

Section 45V(c)(1) and section 

211(o)(1)(H) of the Clean Air Act require 

the consideration of significant indirect 

emissions. A few comments questioned 

how the induced indirect emissions 

from the use of electricity to produce 

hydrogen are significant. Some stated 

that modeling should be done to 

determine if indirect emissions are 

significant. Other comments included 

analysis and modeling, finding that 

induced grid emissions will often be 

large enough to affect whether a project 

qualifies for the section 45V credit or 

what tier of the credit it qualifies for, 

indicating that these emissions are 

significant. 

In response, the Treasury Department 

and the IRS note that whether emissions 

are significant must be understood 


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Federal Register / Vol. 90, No. 6 / Friday, January 10, 2025 / Rules and Regulations 2255 

21 DOE Technical Paper supra note 20. 

22EPA December 2023 Letter supra note 19 

(citing U.S. Department of Energy, Pathways to 

Commercial Liftoff: Clean Hydrogen (2023), at 10– 

12, available at https://liftoff.energy.gov/wpcontent/uploads/2023/05/20230523-Pathways-toCommercial-Liftoff-Clean-Hydrogen.pdf). 

23Wilson Ricks et al., Minimizing Emissions from 

Grid-Based Hydrogen Production in the United 

States, 18 Environmental Research Letters, no. 1, 

Jan. 2023, available at https://iopscience.iop.org/ 

article/10.1088/1748-9326/acacb5/pdf. 

24 Dan Esposito et al., Smart Design of 45V 

Hydrogen Production Tax Credit Will Reduce 

Emissions and Grow the Industry, at 19 (Apr. 2023), 

available at https://energyinnovation.org/wpcontent/uploads/Smart-Design-Of-45V-HydrogenProduction-Tax-Credit-Will-Reduce-Emissions-AndGrow-The-Industry.pdf. 25The study notes this figure assumes no 

improvement in grid carbon intensity over time. 

Ben King et al., Scaling Green Hydrogen in a PostIRA World, Rhodium Group (Blog) (Mar. 16, 2023), 

available at https://rhg.com/research/scaling-cleanhydrogen-ira/. 26See EPA December 2023 Letter supra note 19. 

within the structure of section 45V. For 

purposes of section 45V, the specific 

amount of emissions determine whether 

hydrogen produced is qualified clean 

hydrogen (with a lifecycle GHG 

emissions rate of not greater than 4 

kilograms of CO2e per kilogram of 

hydrogen) and what applicable 

percentage, and therefore amount of 

credit, the taxpayer may qualify for. See 

Section 45V(b) and (c)(2). In this 

statutory context, any indirect emissions 

may be significant, because such 

emissions could affect the qualification 

for, and amount of, the section 45V 

credit. In addition, the Treasury 

Department and the IRS note that the 

DOE advised that ‘‘electrolysis projects 

that use grid electricity have the 

potential to be several times more GHG 

intensive than the threshold for the 

lowest value § 45V tax credit tier (i.e., 4 

kg of CO2e/kg H2), and could be more 

GHG intensive than existing forms of 

conventional hydrogen production.’’ 21

Further, the EPA advised in the EPA 

December 2023 Letter that ‘‘publications 

have noted that electrolysis projects that 

use large amounts of grid electricity to 

produce hydrogen have the potential to 

be several times more greenhouse-gas 

intensive than the threshold for even the 

lowest value IRC section 45V tax credit 

tier, and could in fact be more 

greenhouse-gas intensive than existing 

forms of conventional hydrogen 

production.’’ 22 For example, one study 

found that subsidized grid-connected 

hydrogen production has the potential 

to induce additional emissions at 

effective rates worse than those of 

conventional, fossil-based hydrogen 

production pathways and that hydrogen 

electrolysis with no incrementality 

requirement would cause GHG 

emissions rates at nearly 20 kilograms of 

CO2e per kilogram of hydrogen in an 82 

percent carbon-free California power 

grid in 2030.23 Another study found that 

electrolysis using non-additional clean 

energy would incur 22 to 40 kilograms 

of CO2e per kilogram of hydrogen across 

all 14 modeled regions comprising the 

48 contiguous U.S. states and the 

District of Columbia.24 Another study 

assessed the impact on GHG emissions 

of electrolytic hydrogen production 

without an incrementality requirement 

and found that this could increase 

emissions by 73 million metric tons in 

2030.25 Further, the level of induced 

grid emissions is expected to often be 

large enough to disqualify hydrogen 

production from credit eligibility or, at 

minimum, affect which level of credit 

the production is eligible for. Based on 

the evidence, the Treasury Department 

and the IRS are statutorily required 

under section 45V to consider induced 

grid emissions as ‘‘significant indirect 

emissions,’’ consistent with the EPA’s 

previous interpretation of that term in 

section 211(o)(1)(H) of the Clean Air 

Act.26

Many of the comments that criticized 

the qualifying EAC requirements and 

framework also raised concerns about 

the effect that the requirements may 

have on industry. For example, some 

comments opposed the requirements on 

the grounds that they exacerbate 

challenges that already exist in getting 

hydrogen production projects 

underway, such as higher costs related 

to debt, materials, and labor, as well as 

competition to electrolytic hydrogen 

from other types of fuel production 

processes. Similarly, one comment 

claimed that the proposed qualifying 

EAC requirement framework would 

significantly increase the production 

cost of the lowest carbon-intensity 

hydrogen. Other comments claimed that 

the regulatory costs outweigh the 

emissions benefits. Comments also 

stated that implementing the qualifying 

EAC requirements could cause a 

significant expansion of renewable 

energy generation sources without 

regard to existing generation sources 

and therefore artificially accelerate the 

development of such sources; this may 

cause problems if the development does 

not also address reliability concerns of 

a particular region’s infrastructure. 

In contrast, several other comments 

stressed the importance of maintaining 

the rigor of the qualifying EAC 

requirements and cautioned that any 

flexibility should be done with care and 

consideration to ensure that the 

intended purpose of the qualifying EAC 

requirements is not undermined. One 

comment urged that the final 

regulations maintain the strictness of 

the qualifying EAC requirements for 

purposes of determining section 45V 

credit eligibility to ensure that hydrogen 

producers are properly incentivized and 

constrained to utilize the section 45V 

credit for the generation of qualified 

clean hydrogen. Some supportive 

comments, despite acknowledging the 

challenges of meeting the requirements 

of the qualifying EAC requirements in 

the near term, claimed that electricity 

meeting the qualifying EAC 

requirements is likely to be available in 

vast quantities. These comments 

generally contended that the qualifying 

EAC framework will make electrolytic 

hydrogen production economically 

beneficial and environmentally 

sustainable. 

As noted previously in this part of the 

Summary of Comments and Explanation 

of Revisions, the qualifying EAC 

requirements address the risk of 

significant indirect emissions associated 

with electricity used in the production 

of hydrogen for purposes of the section 

45V credit. The comments outlined in 

this part reflect different views on how 

the consideration of significant indirect 

emissions may affect the hydrogen 

industry. The section 45V credit 

incentivizes certain hydrogen 

production, but subject to limitations 

regarding the level of lifecycle GHG 

emissions. One of those limitations is 

the statutory requirement to take into 

account significant indirect emissions. 

Therefore, the recommendation to 

eliminate the qualifying EAC 

requirements is not adopted by these 

final regulations because it would fail to 

address such emissions. 

While some comments advocated for 

abandoning the qualifying EAC 

requirements in their entirety, other 

comments suggested modifications, 

such as by giving hydrogen producers 

more time to adjust or allowing greater 

flexibility in sourcing the electricity 

used. They also emphasized the need 

for such modifications to ensure that the 

qualifying EAC requirements do not 

create an uneven playing field across 

regions, disadvantage existing clean 

electricity generators, or have the effect 

of incentivizing only non-electrolytic, 

fossil-fuel-based hydrogen production. 

The Treasury Department and the IRS 

have considered these comments, and 

these final regulations make 

adjustments to each of the qualifying 

EAC requirements to provide additional 

flexibility, while continuing to adhere to 

the statutory requirements of section 

45V. These final regulations adopt 

certain alternative rules under the 

incrementality requirement of proposed 

§ 1.45V–4(d)(3)(i) that reflect situations 


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that do not pose the same risk of 

induced grid emissions that the 

incrementality requirement is otherwise 

needed to address. These alternatives 

are discussed in more detail in part 

III.D.3.b.ii through v of the Summary of 

Comments and Explanation of 

Revisions. In addition, these final 

regulations, in response to the 

comments, delay until 2030 the 

requirement that temporal matching be 

hourly (from 2028 in the proposed 

regulations). This change is discussed in 

more detail in part III.D.3.c.ii of this 

Summary of Comments and Explanation 

of Revisions. These final regulations, 

however, do not delay the imposition of 

the qualifying EAC requirements or 

provide rules that would exempt certain 

hydrogen producers from those 

requirements. As previously noted, the 

qualifying EAC requirements are needed 

to address the risk that induced grid 

emissions will otherwise lead to 

lifecycle GHG emissions rates that are 

beyond the statutory thresholds. 

Consideration of significant induced 

grid emissions and disqualifying 

hydrogen production above the 

statutory thresholds is required under 

section 45V. In addition to addressing 

induced grid emissions risk, the 

qualifying EAC framework also is 

needed to prevent double counting of 

energy attributes. Furthermore, EACs 

play a secondary role to inform and 

verify the feedstock assumptions 

applied in 45VH2–GREET in estimating 

the lifecycle emissions of hydrogen 

production. 

One comment recommended an 

alternative to the qualifying EAC 

requirements that follows European 

Union (EU) rules allowing hydrogen 

production to qualify as green where 

hydrogen is produced in a region with 

an average renewable electricity share 

exceeding 90 percent in the previous 

calendar year, if the hydrogen 

production does not exceed the 

proportion of renewable electricity in 

the region. Another comment noted that 

while the EU has exemptions to 

incrementality, the EU also has an 

Emissions Trading System that caps 

consequential emissions that may result 

from the exemption. In consultation 

with the DOE, the Treasury Department 

and the IRS note that the approach 

taken by the first comment cannot 

ensure consistency with the 4 kilograms 

of CO2e per kilogram of hydrogen 

emissions intensity threshold based on 

a lifecycle GHG emissions analysis that 

conforms with section 45V because 

diverted zero emission electricity 

generation could still be backfilled with 

GHG emitting generation. However, 

these final regulations adopt an 

incrementality pathway consistent with 

statutory requirements that looks to 

features of State law, as discussed in 

part III.D.3.b.iv of this Summary of 

Comments and Explanation of 

Revisions. 

Another comment suggested that 

EACs be required only corresponding to 

the percentage of electricity purchased 

by the hydrogen producer that equals 

the percentage of the total electricity 

demand of production in the region that 

is not currently renewable. In response, 

the Treasury Department and the IRS 

note that the most reliable way to 

validate electricity use claims is through 

the retirement of EACs. Doing otherwise 

risks the possibility of double sale and 

counting of energy attributes. Further, as 

described in the Explanation of 

Provisions to the proposed regulations, 

the three qualifying EAC requirements 

combine to mitigate the risk that 

induced grid emissions will lead to 

lifecycle GHG emission rates that are 

above what is permitted for eligibility 

for the section 45V credit. If the 

hydrogen facility’s increased electricity 

load is only partly matched with 

incremental clean generation, then there 

can be no assurance that the remaining 

portion of that increased load has no 

induced grid emissions (in fact, induced 

grid emissions would be expected). 

Such emissions must be considered in 

estimating the lifecycle GHG emission 

rate under section 45V. 

A number of comments suggested that 

the regulations allow the use of carbon 

or emissions matching in lieu of, or as 

an alternative to, the current EAC 

framework. One of these comments 

explained that such an approach would 

identify the annual emissions induced 

by the energy consumption of a 

hydrogen electrolyzer and offset them 

by at least an equivalent amount of 

avoided emissions attributable to the 

procurement of onsite or offsite sources 

of renewable energy generation. 

Similarly, several comments proposed 

that carbon matching or carbon 

accounting could be used as substitute 

for certain qualifying EACs. For 

instance, comments suggested allowing 

the use of marginal carbon accounting, 

paired with incrementality, to replace 

temporal matching and deliverability. In 

response to these comments, the 

Treasury Department and the IRS note 

that the three qualifying EAC 

requirements are intended to mitigate 

the risk of significant indirect 

emissions, including induced grid 

emissions. As described in the DOE 

Technical Paper, and supported in 

multiple comments, the requirements 

address both operational (short-term) 

and structural (long-term) effects that 

can affect lifecycle emissions outcomes. 

The Treasury Department and the IRS 

are concerned about the ability to 

develop a rigorous, fully standardized, 

and carbon-based accounting system, 

whereas the EAC qualifying criteria 

have already been established, is 

consistent with standard industry 

practice for the voluntary market and 

most State regulatory programs, and will 

be readily administrable on a 

nationwide basis. 

Several comments were not 

convinced of the viability of EACs and 

the qualifying EAC requirements, and 

questioned models and scenarios that 

are used to justify the viability of the 

requirements. Whereas some comments 

requested exemptions from the 

qualifying EAC requirements, other 

comments requested delays in 

implementation. Requests for 

exemptions addressed specific 

technologies or feedstocks, specific 

electricity generators, certain types of 

hydrogen production facilities, certain 

reliance periods, and certain 

jurisdictions or regions. Some 

comments requested a specific 

exception from the qualifying EAC 

requirements where the hydrogen 

production facility uses electricity to 

produce hydrogen and such electricity 

generating facility is directly connected 

with the hydrogen production facility 

(that is, behind-the-meter). One 

comment suggested that the qualifying 

EAC requirements should not apply in 

their entirety if a hydrogen production 

facility uses electricity generated by a 

facility that qualifies for either the 

section 45Y credit or the section 48E 

credit. Many comments requested 

reliance rules (sometimes referred to in 

comments as ‘‘grandfathering’’) with 

respect to some or all of the qualifying 

EAC requirements, for hydrogen 

production facilities with a beginningof-construction date, placed in service 

date, or commercial-operations date 

before a certain point. 

Comments that recommended that the 

regulations delay implementing the 

qualifying EAC requirements due to 

viability concerns varied considerably. 

One comment recommended that 

implementation be based upon meeting 

defined requirements that establish 

viability of imposing qualifying EAC 

requirements. Other comments 

suggested a variety of proposed 

timelines for implementation. 

In contrast, other comments urged 

that the final regulations should not 

provide any exemptions from or delays 

in implementation. Some comments 

advocated for an accelerated timeline 

for implementing the qualifying EAC 


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requirements to reduce the risk of 

induced grid emissions, and urged that 

delays be avoided. 

In response to these comments, these 

final regulations do not provide 

exemptions from the qualifying EAC 

requirements or delay their application, 

as such exemptions or delays would 

lead to induced grid emissions. Section 

45V requires that the determination of 

lifecycle GHG emissions consider 

significant indirect emissions, and as 

described earlier, the qualifying EAC 

requirements are the best available 

approach for addressing induced grid 

emissions that could constitute 

significant indirect emissions given the 

statutory requirement to use the most 

recent GREET model or a successor 

model. Delaying the qualifying EAC 

requirements would delay the entire 

regulatory framework that addresses the 

risk of significant indirect emissions 

and ensures that the credit is only 

awarded to hydrogen produced through 

a process that results in qualifying 

lifecycle GHG emission rates, which 

would be in a manner that is contrary 

to the statute. 

With respect to comments’ requests 

for an exception for behind-the-meter 

generation, these final regulations do 

not create such an exception. As 

explained in part III.D.1 of this 

Summary of Comments and Explanation 

of Revisions regarding the discussion of 

the EAC framework, uniformly requiring 

claims of electricity usage generated 

from specific sources to be evidenced by 

EACs that meet the requirements of 

§ 1.45V–4(d)(1) is necessary to mitigate 

the risks of double counting of 

electricity attributes and of induced grid 

emissions that would make the 

hydrogen production ineligible for the 

credit or a specific credit level. Because 

behind-the-meter electricity generating 

facilities have tradeable attributes that 

may be sold and because diversion of 

electricity from these facilities can 

result in induced emissions, imposing a 

uniform set of requirements that does 

not exempt these facilities is the most 

administrable way to mitigate the risk of 

double counting and ensure that any 

induced grid emissions relating to such 

facilities are addressed. 

With respect to requests for a reliance 

rule, such a rule would function as a 

limited or complete exemption to the 

qualifying EAC requirements, and thus 

would not appropriately address the 

risk of induced grid emissions for the 

facilities under such rule. For this 

reason and because such a reliance rule 

is contrary to the statute, these final 

regulations do not to adopt such a rule. 

However, as described in this 

Summary of Comments and Explanation 

of Revisions, the final regulations 

provide additional flexibilities within 

the framework established by the 

qualifying EAC requirements, consistent 

with statutory requirements. For 

example, as described in part III.D.3.c.ii 

of this Summary of Comments and 

Explanation of Revisions, these final 

regulations extend the transition rule 

regarding the temporal matching 

requirement to address administrative 

challenges raised by the comments, 

while still requiring annual matching 

during the transition period. Other 

additional flexibilities are described in 

parts III.D.3.b.ii through v, III.D.3.c.ii 

and v, and III.D.3.d.iii. 

Finally, comments requested 

clarification as to whether the qualifying 

EAC requirements are applicable only to 

electrolytic hydrogen production or if 

they also extend to processes that use 

electricity indirectly in the production 

of hydrogen, such as, for example, 

biogenic hydrogen production. In 

response, the Treasury Department and 

the IRS clarify that the acquisition and 

retirement of qualifying EACs is 

required whenever a taxpayer seeks to 

treat a hydrogen production facility’s 

use of electricity as being from a specific 

electricity generating facility rather than 

being from the regional electricity grid, 

regardless of the specific production 

process. 

b. Incrementality 

i. In General 

Proposed § 1.45V–4(d)(3)(i)(A) would 

have provided that an EAC meets the 

incrementality requirement if the 

electricity generating facility that 

produced the unit of electricity to which 

the EAC relates has a COD (as defined 

in proposed § 1.45V–4(d)(2)(i)) that is no 

more than 36 months before the 

hydrogen production facility for which 

the EAC is retired was placed in service. 

Proposed § 1.45V–4(d)(3)(i)(B) would 

have provided an alternative test for 

establishing incrementality for 

electricity generating facilities that 

undergo an uprate. Proposed § 1.45V– 

4(d)(3)(i)(C) would have provided an 

example to illustrate the application of 

the alternative test for establishing 

incrementality due to uprates. 

The Treasury Department and the IRS 

received numerous comments with 

respect to the incrementality 

requirement. To the extent that these 

comments concern the qualifying EAC 

requirements in general, they are 

addressed in part III.D.3.a of this 

Summary of Comments and Explanation 

of Revisions. 

A number of comments addressed the 

36-month lookback period for 

incrementality. Several comments 

requested that the period be lengthened, 

to take into account supply chain 

delays, or otherwise be more flexible. 

These final regulations do not adopt 

such changes, which could significantly 

extend the lookback period. The 

lookback period rule was meant to 

balance the need for flexibility, 

recognizing that it may be hard to 

perfectly align the placed in service date 

of the hydrogen producer with the COD 

of the clean power generator, with the 

requirement that the lifecycle GHG 

emissions account for direct and 

significant indirect emissions, including 

induced grid emissions. Further 

extending that lookback period beyond 

36 months risks induced grid emissions, 

as such clean power facilities may not 

be truly incremental. Furthermore, the 

Treasury Department and the IRS note 

that significant new clean power 

generation is being deployed each year, 

some of which may be available to 

hydrogen producers. While permitting 

and interconnection is time consuming, 

substantial amounts of new clean power 

have completed interconnection 

agreements, so a significant portion of 

such generation has largely already gone 

through that process. On balance, the 

36-month lookback provides sufficient 

flexibility while providing a meaningful 

check against the risk of induced grid 

emissions and lifecycle GHG emission 

rates that would be in excess of those 

allowed by section 45V. 

Similarly, other comments stated that 

the lookback period should begin at the 

hydrogen production facility’s 

beginning of construction date instead 

of the facility’s placed in service date. 

The final regulations do not adopt these 

comments, as they would significantly 

lengthen the lookback period relative to 

the point at which the hydrogen 

production facility actually begins 

producing hydrogen. Other comments 

raised issues relating to the retrofitting 

or repowering of facilities or the 80/20 

Rule. These comments are discussed 

part V.B of the of this Summary of 

Comments and Explanation of 

Revisions. 

The Treasury Department and the IRS 

received several comments that stated 

that the incrementality requirement is 

against the Congressional purpose of 

jumpstarting the clean hydrogen 

industry and is not supported by the 

statute. These comments also suggested 

that hydrogen produced using nuclear 

energy from a nuclear facility that might 

otherwise retire would mitigate the risk 

of induced grid emissions. The 

comments make several statutory 

arguments. First, they point to the 

section 45U credit, which was 


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established by the IRA and applies only 

to nuclear facilities placed in service 

prior to the enactment of the IRA. 

Section 45U(c)(2) incorporates rules set 

forth in section 45(e)(13) that allow 

nuclear facilities receiving credits under 

section 45U to treat the electricity such 

facilities generate as sold to an 

unrelated person during the taxable year 

if such electricity is used by the 

taxpayer or a person related to the 

taxpayer at a qualified clean hydrogen 

production facility to produce qualified 

clean hydrogen. The comments contend 

that the incrementality requirement 

renders section 45U(c)(2) superfluous, 

as it would prevent the electricity 

produced by a facility that is eligible for 

the section 45U credit from being 

treated as zero-emissions electricity in 

the production of qualified clean 

hydrogen. Second, the comments state 

that an incrementality requirement is 

inconsistent with the definition of 

lifecycle GHG emissions in section 

45V(c)(1)(A) and section 211(o)(1)(H) of 

the Clean Air Act, and specifically 

assert that well-to-gate GHG emissions 

from nuclear-based hydrogen 

production are minimal. Third, the 

comments point out that section 45V 

contains two provisions that are 

explicitly limited to facilities of a 

particular age (section 45V(c)(3)(C) and 

(e)(2)(A)) and submit that the lack of 

such an explicit rule with respect to 

induced grid emissions suggests that the 

incrementality requirement violates 

Congressional intent. Fourth, the 

comments assert that the incrementality 

requirement violates the major 

questions doctrine. Finally, these 

comments state that the incrementality 

requirement discriminates against 

electricity produced from nuclear power 

and that it may jeopardize the viability 

of the Regional Clean Hydrogen Hubs 

initiative of the Infrastructure 

Investment and Jobs Act (Pub. L. 117– 

58). 

In response to these comments, the 

Treasury Department and the IRS note 

that the incrementality requirement and 

qualifying EAC requirements are not 

mandatory under these final regulations. 

A taxpayer is not required to acquire 

and retire qualifying EACs. However, 

the taxpayer may only reflect in 45VH2– 

GREET or include in a PER the 

taxpayer’s use of electricity as being 

from a specific electricity generating 

facility (rather than being from the 

regional electricity grid) if the taxpayer 

acquires and retires qualifying EACs 

that satisfy the qualifying EAC 

requirements. The Treasury Department 

and the IRS disagree with the arguments 

that the incrementality requirement is 

inconsistent with the statute. Instead, as 

explained in part III.D.3.a of this 

Summary of Comments and Explanation 

of Revisions, the qualifying EAC 

requirements, including incrementality, 

are a reasonable methodological proxy 

for quantifying induced grid emissions 

associated with new load from 

electrolytic hydrogen production being 

added to an existing grid. The lack of 

such requirements would fail to provide 

a method for addressing significant 

indirect emissions, as required by 

section 45V(c)(1)(A) and section 

211(o)(1)(H) of the Clean Air Act, and so 

would be inconsistent with section 45V. 

Furthermore, the incrementality 

requirement as modified under these 

final regulations does not render 

sections 45U(c)(2) and 45(e)(13) 

superfluous, both because the qualifying 

EAC requirements are not mandatory, 

and because, under these final 

regulations, electricity from certain 

existing nuclear reactors provides an 

alternative pathway to incrementality, 

as discussed in part III.D.3.b.v of this 

Summary of Comments and Explanation 

of Revisions. The Treasury Department 

and the IRS likewise disagree that the 

incrementality requirement 

discriminates against nuclear power. As 

with other facilities, redirecting 

electricity produced by existing nuclear 

facilities to hydrogen production can 

result in induced emissions. For the 

reasons previously explained, electricity 

that meets the incrementality 

requirement does not pose the same risk 

of induced emissions. In addition, the 

two provisions in section 45V cited by 

the comments, which are limited to 

facilities of a particular age, are 

unrelated to determining lifecycle GHG 

emissions and therefore are irrelevant to 

Congressional intent on this issue. 

Finally, with respect to comments 

suggesting the incrementality 

requirement is incompatible with the 

major questions doctrine, the Treasury 

Department and the IRS note that 

section 45V, consistent with other parts 

of the IRA, contains several express 

grants of authority to the Secretary, 

including under section 45V(f), to issue 

regulations or other guidance to carry 

out the purposes of section 45V, 

including regulations or other guidance 

for determining lifecycle GHG 

emissions. As explained previously, the 

qualifying EAC requirements are 

integral to the assessment of lifecycle 

GHG emissions as mandated by section 

45V(c)(1) and are thus clearly within the 

Secretary’s authority, as several 

comments have noted. 

The Treasury Department and the IRS 

agree with the comments that suggest 

that the use of electricity generated by 

an existing nuclear facility may, in 

certain cases, have a limited risk of 

induced grid emissions. Accordingly, 

the final regulations adopt an additional 

incrementality pathway for electricity 

that is produced by an electricity 

generation facility that is a qualifying 

nuclear reactor, which is discussed in 

part III.D.3.b.v of this Summary of 

Comments and Explanation of 

Revisions. The Treasury Department 

and the IRS also note that a qualifying 

nuclear reactor that produces electricity 

used by a hydrogen production facility 

under this pathway may qualify for the 

section 45U credit if the requirements 

for the section 45U credit are otherwise 

met. One comment raised the issue of 

‘‘test’’ energy—electricity produced 

prior to COD. The comment asked that 

such electricity production be deemed 

incremental, noting that some EAC 

registries already issue certificates for 

test energy. The Treasury Department 

and the IRS affirm that EACs associated 

with test energy are allowed and may be 

considered incremental if the other 

requirements are met. 

In consideration of additional 

comments received and as discussed in 

the following parts III.D.3.b.ii through v 

of this Summary of Comments and 

Explanation of Revisions, these final 

regulations modify the general 

incrementality rule in proposed 

§ 1.45V–4(d)(3)(i)(A) to allow for 

electricity represented by an EAC that is 

produced by an electricity generating 

facility that has placed in service carbon 

capture and sequestration technology 

within a certain timeframe. In addition, 

the final regulations adopt the following 

additional ways to satisfy the 

incrementality requirement: (i) an 

alternative for electricity represented by 

an EAC that is produced by an 

electricity generation facility in a 

qualifying State; and (ii) an alternative 

for electricity represented by an EAC 

that is produced by an electricity 

generation facility that is a qualifying 

nuclear reactor. 

ii. Carbon Capture and Sequestration 

The final regulations modify proposed 

§ 1.45V–4(d)(3)(i)(A) and provide that 

an EAC also meets the incrementality 

requirement if the electricity 

represented by the EAC is produced by 

an electricity generating facility that 

uses carbon capture and sequestration 

(CCS) technology and the carbon 

capture equipment has a placed in 

service date that is no more than 36 

months before the hydrogen production 

facility for which the EAC is retired was 

placed in service (CCS retrofit rule). The 

definition of ‘‘eligible EAC’’ in proposed 


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§ 1.45V–4(d)(2)(iii) is amended to 

require that the EAC include the placed 

in service date of the carbon capture 

equipment used in the production of 

electricity. In addition, as further 

discussed in part III.G of this Summary 

of Comments and Explanation of 

Revisions, these final regulations add 

§ 1.45V–4(e), which provides that CCS 

may be taken into account only if the 

carbon 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. The Treasury Department 

and the IRS note that an electricity 

generating facility producing electricity 

that is represented by an EAC that 

utilizes the CCS retrofit rule to satisfy 

the incrementality requirement is 

subject to this requirement. The 

Treasury Department and the IRS 

received several comments on CCS 

generally, which are discussed in part 

III.G of this Summary of Comments and 

Explanation of Revisions. With respect 

to the incrementality requirement, the 

Treasury Department and the IRS noted 

in the proposed regulations that there 

are circumstances in which an existing 

higher-emitting electricity generating 

facility may make upgrades to 

subsequently deliver electricity with 

lower emissions. For example, an 

existing fossil-fuel electricity generating 

facility may add CCS capability, thereby 

reducing its emissions. The Treasury 

Department and the IRS requested 

comments on whether the electricity 

generated by such a facility should be 

considered incremental under 

circumstances such as if an existing 

fossil fuel electricity-generating facility 

after the addition of carbon capture 

equipment (after upgrade) had a COD 

that is no more than 36 months before 

the relevant hydrogen production 

facility was placed in service. Comment 

also was requested on the related 

question whether, depending on its 

carbon dioxide capture rate, it would be 

appropriate to treat such a facility as a 

new source of minimal-emitting 

generation on the grid that would not be 

associated with induced grid emissions. 

Relevant to these questions, the 

Treasury Department and the IRS 

requested comments on what 

information would be needed to allow 

for qualifying EACs representing 

existing fossil fuel-powered electricity 

from facilities that have added carbon 

capture equipment, and whether there 

are safeguards that can ensure that a 

hydrogen producer’s purchase and use 

of electricity from an existing fossil fuelfired electricity generating facility that 

installs carbon capture equipment does 

not result in emissions due to the 

dynamics of the electricity market and 

electric grid. Finally, the Treasury 

Department and the IRS requested 

comments on the direct and indirect 

emissions impacts of making such a 

facility eligible, and whether and under 

what circumstances it would be 

appropriate to do so. 

The Treasury Department and the IRS 

received numerous comments in 

response to these requests. After 

consideration of these comments and in 

consultation with the DOE, these final 

regulations incorporate the CCS retrofit 

rule under the incrementality 

requirement. A number of comments 

supported the adoption of such a rule, 

many providing qualitative or 

quantitative arguments for why the 

induced grid emissions resulting from 

an existing generating facility retrofitted 

with CCS would be minimal. In 

contrast, comments opposed to a CCS 

retrofit rule stated that the emissions 

effect of such a rule was uncertain. One 

comment stated that hydrogen produced 

by an electricity source using a CCS 

retrofit would still need to be met by 

new generation. Another comment 

noted specifically that any CCS that is 

legally required should not be deemed 

incremental. 

These final regulations adopt the CCS 

retrofit rule because an electricitygenerating facility retrofit with carbon 

capture equipment may be considered a 

new source of lower-carbon supply. 

Such a plant produces lower emissions 

by virtue of the addition of CCS, 

compared to one without CCS, and its 

EACs will reflect its relevant attributes, 

as discussed more in part III.D.3.a of 

this Summary of Comments and 

Explanation of Revisions. 

The Treasury Department and the IRS 

recognize that section 45V may create 

incentives for existing fossil fuel 

electricity generation to place in service 

carbon capture equipment. New CCS 

retrofits will generally reduce emissions 

even in the presence of increased load 

due to hydrogen production, in part 

because any increased grid electricity 

for such increased load is likely to be 

met by new sources of electricity 

generation with an equivalent or lower 

emissions profile than the existing 

electricity source prior to its retrofit 

with carbon capture technology. For 

simplicity and administrability, the CCS 

retrofit rule ties incrementality to the 

date the new carbon capture equipment 

is placed in service. Additionally, these 

final regulations do not adopt a rule that 

CCS retrofits mandated by law are not 

incremental. To do otherwise would be 

inconsistent with the requirements for 

other clean generation, which are 

treated as incremental based on the 

generating facility’s COD regardless of 

whether that new generation is 

mandated by law. Determining what is 

mandated by law is not straightforward, 

which raises administrability concerns. 

Consistent with the comments’ 

recommendations regarding the 

treatment of new power plants that are 

equipped with carbon capture 

equipment (new build CCS), EACs from 

plants retrofitted with new carbon 

capture equipment will not have a zero 

emissions rate, and this information 

would need to be reflected accordingly 

in 45VH2–GREET as part of the GHG 

emissions rate calculation. Rules for 

such EACs are discussed in part III.D.3.a 

of this Summary of Comments and 

Explanation of Revisions. 

iii. Uprates 

Proposed § 1.45V–4(d)(3)(i)(B) would 

have provided rules for determining 

uprated production. Specifically, 

proposed § 1.45V–4(d)(3)(i)(B) would 

have provided that an uprated 

electricity generating facility’s 

production must be prorated to each 

hour or year, consistent with the 

requirements in proposed § 1.45V– 

4(d)(3)(ii), of such facility’s generation 

by multiplying each hour’s production 

by the uprated production rate to 

determine the electricity to which the 

uprate relates. Proposed § 1.45V– 

4(d)(3)(i)(B) would have defined key 

terms, including: (i) ‘‘uprate,’’ which 

means an increase in an electricity 

generating facility’s rated nameplate 

capacity (in nameplate megawatts); (ii) 

‘‘pre-uprate capacity,’’ which means the 

nameplate capacity of an electricity 

generating facility immediately before 

an uprate; (iii) ‘‘post-uprate capacity,’’ 

which means the nameplate capacity of 

an electricity-generating facility 

immediately after an uprate; (iv) 

‘‘incremental generation capacity,’’ 

which means the increase in an 

electricity generating facility’s rated 

nameplate capacity from the pre-uprate 

capacity to the post-uprate capacity; (v) 

‘‘uprated production rate,’’ which 

means the incremental generation 

capacity (in nameplate megawatts) 

divided by the post-uprate capacity (in 

nameplate megawatts); and (vi) 

‘‘uprated production,’’ which means the 

uprated production rate of an electricity 

generating facility multiplied by its total 

generation output in a given hour (in 

megawatt hours). Thus, the uprated 

production gets pro-rated over the 

course of the year during each hour 

electricity is generated. Proposed 

§ 1.45V–4(d)(3)(i)(C) would have 


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provided an example to illustrate the 

application of the alternative test for 

establishing incrementality due to 

uprates. 

The Treasury Department and the IRS 

received comments with respect to 

uprates. Some comments suggested that 

any uprate used to satisfy the 

incrementality requirement must be 

established through approval of an 

amended or modified operating license 

or similar approval by a governmental 

or quasi-governmental agency, such as 

the Nuclear Regulatory Commission 

(NRC), FERC, or a regional grid operator. 

These final regulations do not adopt this 

as a standalone measurement standard. 

A sole, general rule requiring modified 

or amended licenses, or for electricity 

generating facilities to obtain other 

forms of governmental approval, is not 

needed to reasonably capture additions 

to capacity. Because the uprated 

production represents new production 

capacity, it should satisfy the 

incrementality requirement. In addition, 

some uprates come from facilities that 

do not require approval from the NRC, 

the FERC, or a regional operator. 

One comment requested that guidance 

clarify that uprates or upgrades with 

respect to a nuclear facility or other 

zero-emission-generating facility, such 

as hydropower, satisfy the 

incrementality requirement provided 

that the uprate or upgrade results in an 

incremental increase in the electricity 

generation output based on the actual 

productive capability of such facility, 

after considering degradation and other 

limitations on its original nameplate, 

licensed, or rated capacity. The 

Treasury Department and the IRS 

acknowledge that measuring capacity 

using nameplate capacity would, in 

some cases, not reflect age-based 

degradation in capacity or certain types 

of capacity increases. 

In response to these comments, these 

final regulations modify the uprate rules 

in § 1.45V–4(d)(3)(i)(B) to account for 

potential differences in the nameplate 

capacity and the actual productive 

capacity of the facility. The final 

regulations provide that the term uprate 

means the increase in either an 

electricity generating facility’s 

nameplate capacity (in nameplate 

megawatts) or its capacity measured by 

a standard other than nameplate 

capacity, which the final regulations 

define as specified capacity. 

Measurement of specified capacity may 

be determined using one of three 

standards: (1) a modified or amended 

facility license from FERC or NRC, or 

related reports prepared by FERC or 

NRC as part of the licensing process; (2) 

the ISO conditions to measure the 

nameplate capacity of the facility 

consistent with the definition of 

‘‘nameplate capacity’’ provided in 40 

CFR 96.202; or (3) a measurement 

standard as determined by the Secretary 

in guidance published in the Internal 

Revenue Bulletin. See § 1.45V– 

4(d)(3)(i)(B)(3). The final regulations 

provide that if a taxpayer is able to 

determine a measurement standard 

based on a modified or amended license 

from FERC or the NRC as part of the 

licensing process, they may not use the 

standard based on ISO conditions. Such 

a rule should provide sufficient 

flexibility to taxpayers in determining 

uprated production. Similarly, the 

definitions of ‘‘pre-uprate capacity’’ and 

‘‘post-uprate capacity’’ are modified to 

include specified capacity. 

Another comment recommended that 

uprated production not be subject to a 

36-month lookback period. However, as 

the absence of a lookback period would 

result in induced grid emissions that 

would need to be reflected in the 

lifecycle GHG emissions rate, these final 

regulations do not adopt this comment. 

The final regulations renumber the 

general rule as § 1.45V–4(d)(3)(i)(B)(1), 

include a new rule for restarts as 

§ 1.45V–4(d)(3)(i)(B)(2), and retain the 

example as § 1.45V–4(d)(3)(i)(B)(4). 

The final regulations also delete the 

word ‘‘immediately’’ from the 

definitions of ‘‘pre-uprate capacity’’ and 

‘‘post-uprate capacity,’’ in order to 

provide clarity. A time-period limitation 

is not necessary, and the word 

‘‘immediately’’ might otherwise create 

uncertainty as to what capacity should 

be taken into account. Thus, under the 

final regulations, the term ‘‘pre-uprate 

capacity’’ means the nameplate capacity 

or specified capacity of an electricity 

generating facility before an uprate, and 

the term ‘‘post-uprate capacity’’ means 

the nameplate capacity or specified 

capacity of an electricity generating 

facility after an uprate. 

Some comments stated that an EAC 

should satisfy the incrementality 

requirement if it is produced from an 

electricity generation facility that has 

shut down and then restarted. Several of 

these comments gave the specific 

example of decommissioned and 

restarted nuclear facilities. In response 

to this, the Treasury Department and the 

IRS note that, unless the restarted 

electricity generation facility has a new 

COD, the incrementality requirement 

would generally not be satisfied, as the 

electricity generation facility that 

produced the unit of electricity to which 

the EAC relates would have a COD more 

than 36 months before the hydrogen 

production facility for which the EAC is 

retired was placed in service. However, 

the Treasury Department and the IRS 

agree with comments asserting that the 

electricity generated from a restarted 

facility should be considered 

incremental production. To provide for 

this, the final regulations add § 1.45V– 

4(d)(3)(i)(B)(2), which clarifies that 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 existing facility has 

ceased operations. Additionally, the 

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 

(either the FERC or the NRC), and the 

increased capacity of the restarted 

facility must be eligible to restart based 

on an operating license issued by the 

regulatory authority. The existing 

facility must also not have ceased 

operations for the purpose of qualifying 

for the special rule for restarted 

facilities. This special rule for restarted 

facilities relies, in part, on operating 

authorizations provided by 

governmental or quasi-governmental 

agencies to provide an administrable 

and verifiable means of distinguishing a 

restart that should be treated like an 

addition of incremental electricitygenerating capacity from temporary 

cessations or interruptions in an 

electricity-generating facility’s 

operations. 

Finally, the Treasury Department and 

the IRS remind taxpayers that a 

qualified hydrogen production facility is 

only able to claim incremental 

production associated with an uprate if 

the relevant EAC registry tracks it via 

EACs. The Treasury Department and the 

IRS expect that EAC registries will 

identify a proportional amount of EACs 

generated in every month—or, 

beginning in 2030—every hour as 

‘‘incremental’’ for purposes of 45V, 

based on the proportional increase in 

capacity due to the uprate. 

iv. Qualifying States 

In the Explanation of Provisions to the 

proposed regulations, the Treasury 

Department and the IRS noted that, in 

certain circumstances, the diversion of 

existing minimal (that is, zero or nearzero) emissions power generation to 

hydrogen production may be unlikely to 

result in significant induced GHG 

emissions and noted as one such 

circumstance the generation from 

minimal-emitting power plants in 

locations where grid-electricity is 100 

percent generated by minimal-emitting 

generators or where increases in load do 

not increase grid emissions, for 


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27Because this is an alternative pathway only to 

the incrementality requirement, the deliverability 

and temporal matching requirements still apply. 

example, due to State policy capping 

total GHG emissions. 

The Treasury Department and the IRS 

received numerous comments in 

support of a rule that accounts for such 

circumstances. In response to comments 

and after consultation with the DOE and 

the EPA, the final regulations provide 

an alternative pathway for establishing 

incrementality, under which an EAC 

meets the incrementality requirement if 

the electricity represented by the EAC is 

produced by an electricity generating 

facility that is physically located in a 

qualifying state (as defined in § 1.45V– 

4(d)(2)(xii)), and the hydrogen 

production facility is also located in a 

qualifying state.27 The final regulations 

define qualifying State as a State which, 

as determined by the Secretary, has 

under its State law or regulations, 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 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; (ii) 

applies to the large majority of eligible 

electricity supplied to the State, as 

determined by the State; and (iii) 

includes policies that would achieve 

that 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. A State RPS or CES that 

meets these requirements would be a 

qualifying electricity decarbonization 

standard. 

A qualifying GHG cap program is 

defined as a legally binding program 

that (i) creates a limitation (cap) on the 

quantity of GHG emissions from the 

electricity sector (either alone or along 

with other sectors) in the State through 

issuance of a limited number of 

allowances or other compliance 

instruments to covered entities for each 

compliance period; (ii) includes annual 

obligations 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; (iii) 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; 

(iv) applies to the large majority of instate power-sector sources of emissions 

that emit greater than 25,000 metric tons 

of CO2e in a calendar year; (v) 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; (vi) 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 (vii) 

generally ensures that the cap on GHG 

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. 

The definition of qualifying State 

provides conditions under which State 

law is sufficiently effective and 

stringent to conclude with a reasonable 

degree of certainty that new load is 

highly unlikely to cause induced grid 

emissions. As further described in this 

part III.D.3.b.iv, a robust, legally binding 

State GHG emissions cap that satisfies 

the qualifying GHG cap requirements is 

the primary criterion, because it ensures 

that overall GHG emissions are 

effectively capped regardless of 

electricity demand growth. The 

qualifying electricity decarbonization 

standard provides a further protection to 

ensure that significant induced power 

grid emissions are avoided, even in the 

context of a multi-sector GHG emissions 

cap, by requiring a State to also 

maintain a statutory commitment to 

decarbonize its own power supply, such 

as a CES or RPS. 

Hydrogen production facilities 

located in qualifying States can 

therefore satisfy the incrementality 

requirement by using qualifying EACs 

from existing clean electricity sources 

located in qualifying States. Temporal 

matching and deliverability 

requirements will continue to apply for 

qualified EACs, as will the need to retire 

those EACs to ensure EACs and their 

energy and emissions attributes are not 

double counted or claimed by other 

electricity consumers. 

The requirement that a qualifying 

State have a qualifying GHG cap 

program and qualifying electricity 

decarbonization standard, and the 

requirements for such program and 

standard, are meant to identify 

circumstances under which new 

electricity load is highly unlikely to 

cause induced grid emissions. In 

consultation with the DOE, the 

Secretary has determined that, as of the 

date of publication of these final 

regulations, California and Washington 

are qualifying States under these final 

regulations. The requirements in these 

regulations to be a qualifying GHG cap 

program and meet the qualifying 

electricity decarbonization standard are 

based in part on those programs, which 

the DOE has advised have functioned in 

practice as robust caps. 

With respect to the definition of a 

qualifying GHG cap program, the 

Treasury Department and the IRS note 

that whether a State GHG cap is binding 

is influenced by many features, 

including but not limited to, the 

magnitude of the emissions cap relative 

to historical and projected emissions; 

definitions of and use limitations 

regarding carbon offsets; and the status 

of and procedures governing the 

withholding of and release of allowance 

reserves. As a check on the combined 

effect of these features on the stringency 

of the GHG policy and to ensure that 

they are not undermining the cap to the 

point where it is not sufficiently 

ensuring that new electricity load, such 

as from hydrogen production, will not 

result in induced grid emissions, 

requirements for a qualifying GHG cap 

program generally ensures a minimum 

allowance price set through statute or 

regulation. To determine the 

appropriate allowance price, the 

Treasury Department and the IRS, in 

consultation with the DOE, took into 

consideration observed allowance prices 

over the past several years in the 

existing State systems that the DOE has 

advised were robust over that period. 

Upon conclusion of that exercise, the 

minimum required allowance price of 

$25 per metric ton in 2025, and 

increasing with inflation each year after 

2025, was determined to be high enough 

such that a GHG cap policy provides 

sufficient incentive to reduce emissions 

beyond what might occur without the 

program. In other words, the level is 

high enough to ensure the cap provides 

a meaningful constraint on emissions. 

The Treasury Department and the IRS 

are aware that GHG cap systems are 

often designed with ceiling prices, such 

as, for example, an alternative 


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2262 Federal Register / Vol. 90, No. 6 / Friday, January 10, 2025 / Rules and Regulations 

28California Air Resources Board, California 

Greenhouse Gas Emissions from 2000 to 2022: 

Trends of Emissions and Other Indicators (Sept. 20, 

2024), available at https://ww2.arb.ca.gov/sites/ 

default/files/2024-09/nc-2000_2022_ghg_inventory_

trends.pdf. 

29See Morgan Browning, et al., Net-Zero CO2 by 

2050 Scenarios for the United States in the Energy 

Modeling Forum 37 Study, 4 Energy and Climate 

Change, Dec. 2023; John Bistline et al., Emissions 

and Energy Impacts of the Inflation Reduction Act, 

380 Science, no. 6652, Jun. 29, 2023, at 1324–27; 

James Williams, et al., Carbon-Neutral Pathways for 

the United States, 2 AGU Advances, no. 1, Mar. 

2021, available at https://

agupubs.onlinelibrary.wiley.com/doi/epdf/10.1029/ 

2020AV000284; James R. McFarland, et al., 

Overview of the EMF 32 Study on U.S. Carbon Tax 

Scenarios, 9 Climate Change Economics, no. 1, Feb. 

2018, available at https://www.worldscientific.com/ 

doi/epdf/10.1142/S201000781840002X; Leon E. 

Clarke, et al., Technology and U.S. Emissions 

Reductions Goals: Results of the EMF 24 Modeling 

Exercise, 35 The Energy Journal, no. 1, Jun. 2014. 

30Preliminary Monthly Electric Generator 

Inventory (based on Form EIA–860M as a 

Supplement to Form EIA–860), U.S. Energy 

Information Administration, available at https://

www.eia.gov/electricity/data/eia860m/. 

compliance pathway wherein obligated 

entities are allowed emissions in excess 

of the stated GHG cap in the event that 

allowance prices reach the ceiling. If 

diversion of existing clean electricity to 

hydrogen production caused the ceiling 

price to be reached, that would 

effectively cause emissions to exceed 

the cap. Therefore, if a State system has 

a ceiling price set through statute or 

regulation, requiring that ceiling price to 

be set well above the maximum 

allowance price observed in existing 

systems is necessary to help ensure that 

a State is, in practice, unlikely to reach 

the ceiling price as a result of increased 

electricity demand for hydrogen 

production. These final regulations 

require this ceiling price to be 

established by statute or regulation at 

$90 per metric ton of CO2e or more in 

2025, increasing with inflation each 

year after 2025. This level is more than 

two times higher than the average prices 

observed over the last several years in 

the two existing State systems the DOE 

advises were robust over that period. 

Collectively, these requirements help 

ensure that, in the context of this 

alternative incrementality pathway, any 

increased electricity load is highly 

unlikely to cause induced grid 

emissions. With the requirements 

specified here, qualified GHG cap 

policies will be enforceable by legal 

means, feature emissions targets and 

carbon allowance prices that provide a 

sufficient incentive to reduce emissions 

to meet those targets and achieve 

emissions reductions beyond what 

might occur without the program, 

enable carbon allowance prices to rise to 

ensure the cap is maintained, and 

minimize the risk of emissions leakage 

to other geographies and entities not 

obligated to comply with the program. 

The Treasury Department and the IRS 

note that a robust but a multi-sectoral 

GHG cap program alone cannot, with 

sufficient certainty, ensure that induced 

grid emissions in States with such a 

program are insignificant. A multisectoral cap may allow emissions to rise 

in the power sector as a result of 

induced demand from hydrogen 

production while offsetting those 

emissions increases with reductions in 

other sectors. 

There are several reasons the Treasury 

Department, the IRS, the DOE, and the 

EPA have confidence that the risk of 

induced grid emissions will be limited 

in States with a qualifying GHG cap, as 

required by these final regulations. First, 

in the State with the longest experience 

with a robust multi-sector GHG cap, 

California, the electricity sector has 

been a leading source of emissions 

reductions over the last decade.28

Second, numerous studies have shown 

that in the context of effective GHG 

emission policies, the electricity sector 

is likely to remain a leading sector for 

decarbonization, in part given the 

availability of multiple low-cost clean 

electricity technologies.29 Third, as a 

result, it is unlikely in practice that a 

State could remain in compliance with 

its cap while experiencing a significant 

absolute increase in grid emissions due 

to new hydrogen production. Finally, as 

noted, States are also required to meet 

certain minimum requirements for an 

electricity decarbonization standard, 

providing additional assurance that the 

State is committed to ongoing 

reductions in power sector emissions. 

With respect to the qualifying 

electricity decarbonization standard, 

some comments suggested that a CES or 

RPS requirement, on its own, should be 

sufficient to ensure incrementality. 

However, a clean electricity target, 

absent a legally binding emissions cap, 

does not protect against induced grid 

emissions and ensure a lifecycle GHG 

emissions rate that is eligible for the 

section 45V credit; a State with such a 

target could still experience a significant 

increase in GHG emissions due to 

diverted grid electricity from out-ofstate or increased electricity demand for 

hydrogen production, with no reliable 

mechanism to prevent these increases. 

Critically, unless a State policy requires 

100 percent clean electricity in any year, 

including from imports, even a legally 

binding decarbonization standard 

would permit diverted clean electricity 

to be partially replaced with non-clean 

sources, increasing grid emissions that 

would need to be captured in the 

facility’s lifecycle GHG emissions rate. 

Currently, no State has adopted a policy 

that requires 100 percent clean 

electricity in 2024 or 2025. 

Hydrogen production facilities 

located in qualifying States can satisfy 

the incrementality requirement by using 

qualifying EACs from existing clean 

electricity generators located in those 

same or other qualifying States. Some 

comments requesting an exception 

based on State policies on qualifying 

GHG emissions caps and qualifying 

electricity decarbonization standards 

recommended expanding the exception 

to include all three qualifying EAC 

requirements. These final regulations do 

not adopt a broader rule, instead 

limiting the rule as an alternative way 

to satisfy the incrementality 

requirement only. The qualifying States 

pathway provides reasonable assurance 

that any existing clean electricity 

generation that is diverted from another 

end use will not result in an increase in 

grid emissions and will instead be 

replaced by more clean electricity. 

Notably, the fact that meeting these 

requirements adequately addresses the 

incrementality requirement does not 

obviate the temporal matching or 

geographic matching requirements, 

which must also be met to provide 

assurances that the electricity was 

available and deliverable to the 

hydrogen producer. Therefore, temporal 

matching and deliverability 

requirements will continue to apply, 

and producers will need to obtain and 

retire qualifying EACs to demonstrate 

that they meet these requirements and 

to thereby avoid the possible double 

crediting of energy and emissions 

attributes. 

v. Qualifying Nuclear Reactors 

In the Explanation of Provisions to the 

proposed regulations, the Treasury 

Department and the IRS sought 

comments on whether to treat EACs 

from an existing electricity generating 

facility as satisfying the incrementality 

requirement if the facility is likely to 

mitigate its risk of retirement because of 

its relationship with a hydrogen 

production facility. The Treasury 

Department and the IRS also noted that 

the available data indicates there is an 

ongoing risk of certain clean power 

plants retiring. Some clean power 

plants, primarily nuclear plants, have 

retired in recent years. Based on data 

from the EIA, from 2013 through 2022, 

10,800 megawatts (MW) of nuclear have 

retired.30 Studies have shown that there 

is risk of continued retirement in the 


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Federal Register / Vol. 90, No. 6 / Friday, January 10, 2025 / Rules and Regulations 2263 

31See John Bistline et al., Emissions and Energy 

Impacts of the Inflation Reduction Act, 380 Science, 

no. 6652, Jun. 29, 2023, at 1324–27; Annual Energy 

Outlook 2023, U.S. Energy Information 

Administration, available at https://www.eia.gov/ 

outlooks/aeo/tables_ref.php (last updated Mar. 16, 

2023). 

32For example, a 2023 article in the journal 

Science highlights findings across nine different 

models, showing uncertainty but significant nuclear 

retirement risk across many assessments over the 

longer term. See John Bistline et al., Emissions and 

Energy Impacts of the Inflation Reduction Act, 380 

Science, no. 6652, Jun. 29, 2023, at 1324–27. 

33For example, the Nuclear Energy Institute has 

estimated that single-unit plants’ costs averaged 

$41/MWh in 2022, whereas multi-unit plants’ costs 

average $29/MWh. See Nuclear Energy Institute, 

Nuclear Costs in Context (Dec. 2023), available at 

https://www.nei.org/CorporateSite/media/filefolder/ 

resources/reports-and-briefs/2023-Costs-in-Context_

r1.pdf. 

years ahead.31 Plant owners may decide 

whether to retire based on the finances 

of continuing to operate. Additional 

revenue from selling EACs and 

electricity to hydrogen producers may 

improve the financial outlook of some 

plants enough to help avert retirement, 

thereby keeping the plant in operation 

and substantially reducing induced grid 

emissions compared to a scenario in 

which the plant retires. 

Several comments urged the Treasury 

Department and the IRS to consider an 

exception to the qualifying EAC 

requirements for hydrogen production 

facilities using electricity from existing 

nuclear facilities. After considering 

these comments, the final regulations 

adopt a rule under which an EAC may 

meet the incrementality requirement if 

the electricity represented by the EAC is 

produced by an electricity generating 

facility that is a qualifying nuclear 

reactor, as defined in § 1.45V–4(d)(2)(x). 

For purposes of this rule, only up to 200 

megawatt hours (MWh) of electricity per 

operating hour per qualifying nuclear 

reactor may be considered incremental, 

subject to an integrated operations rule 

described in this part III.D.3.b.v of the 

Summary of Comments and Explanation 

of Revisions. 

The term qualifying nuclear reactor is 

defined as, with respect to an EAC, a 

nuclear reactor that: (i) is a merchant 

nuclear reactor, as defined in § 1.45V– 

4(d)(2)(vi), or is a nuclear reactor that is 

not co-located with any other operating 

nuclear reactor (that is, the nuclear 

reactor is a single unit plant); (ii) meets 

a financial test related to that used for 

purposes of the section 45U credit for 

any two of the calendar years 2017 

through 2021, as determined with 

respect to any one owner of the reactor; 

and (iii) either (A) has a behind-themeter physical electric connection with 

the hydrogen production facility that 

acquires and retires the EAC or (B) is the 

subject of a written binding contract, for 

a fixed term of at least 10 years 

beginning on the first date on which 

qualified EAC are acquired, under 

which the owner of the hydrogen 

production facility agrees to acquire and 

retire EACs from the nuclear reactor, 

and which manages the qualifying 

nuclear reactor’s risk of price changes 

with respect to EACs or electricity. 

‘‘Merchant nuclear reactors’’ are nuclear 

reactors that compete 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. However, as provided in 

§ 1.45V–4(d)(3)(i)(D)(5), to the extent the 

nuclear reactor satisfies the definition of 

a qualifying nuclear reactor because it is 

the subject of a written binding contract 

as provided in paragraph § 1.45V– 

4(d)(2)(x)(C)(2), only the megawatt 

hours of electricity for which the 

taxpayer acquires EACs from the 

nuclear reactor pursuant to the written 

binding contract—subject to the 200 

MWh per hour per qualifying nuclear 

reactor limit—may be considered 

incremental. 

The Treasury Department and the IRS 

note that, among existing clean 

electricity generating facilities, nuclear 

plants have the most demonstrably 

significant risk of retirement based on 

historical trends and future projections. 

Nuclear generators are also the largest 

sources of clean electricity on an 

individual reactor basis, and therefore 

closure of any reactor represents 

significant potential emissions 

increases. While the total capacity of 

operational nuclear power has declined 

in the past decade, the capacity of most 

other clean energy sources has 

increased. Future retirement risk is also 

concentrated on nuclear power plants.32

The requirements defining a 

qualifying nuclear reactor identify those 

plants that are most at risk of retirement. 

First, the rule limits qualifying nuclear 

reactors to nuclear reactors that bear 

substantial wholesale electricity market 

price risk through merchant power 

sales, rather than cost-of-service (COS)- 

based guaranteed revenue, and to singleunit COS plants. Not all nuclear plants 

are at equal risk of retirement; plants 

with greatest risk are those with lower 

or more uncertain revenue and/or with 

higher operational costs, namely 

merchant plants and single-unit plants. 

Merchant plants are exposed to volatile 

and sometimes low wholesale market 

prices. Although such plants may have 

some power purchase agreements 

(PPAs) and hedges, those tend to be 

limited, and such plants are very 

exposed to changes in wholesale power 

markets. By contrast, COS plants are 

less exposed, as their ability to remain 

economic depends on periodic ratecases and resultant cost-based rates. 

Competitive pressures remain but are 

mediated with more long-term planning 

considerations by plant owners as well 

as regulators and other stakeholders. 

Based on responses collected through its 

Form EIA–860, Annual Electric 

Generator Report, EIA reports the 

‘‘Regulatory Status’’ of power plants in 

its Form EIA–860 data. Following 

consultation with the DOE, the Treasury 

Department and the IRS understand that 

those nuclear reactors that are part of 

nuclear power plants listed as ‘‘NR’’ 

(non-regulated) in the 2023 Final Form 

EIA–860 data are generally likely to 

meet the merchant plant definition in 

these final regulations. 

Single-unit COS plants are also at risk 

because they tend to have higher 

operating costs per MWh of production 

than multi-unit plants.33 The DOE has 

also surveyed past retirement patterns to 

identify the plant characteristics 

associated with the highest retirement 

rates, and its findings are consistent 

with the above proposed restrictions. 

As part of identifying nuclear reactors 

most at risk of retirement, these final 

regulations provide a financial test. A 

nuclear reactor meets the financial test 

if the average annual gross receipts (as 

defined under section 45U) of the 

reactor were less than 4.375 cents per 

kilowatt hour for any two of the 

calendar years from 2017 through 2021. 

This financial test reflects the 

framework adopted by Congress in the 

IRA in section 45U, which provides 

support for existing nuclear plants 

during periods in which their receipts 

are below a threshold level. The 

Treasury Department and the IRS 

anticipate releasing guidance under 

section 45U in the future, including on 

the definition of gross receipts. Rules 

under such guidance for calculating 

gross receipts would also apply for 

purposes of the financial test provided 

in § 1.45V–4(d)(2)(x)(B). The threshold 

of 4.375 cents is the gross receipts 

amount per kilowatt hour at which the 

section 45U credit falls to zero in its 

first year. Calendar years 2017 through 

2021 were chosen to make the test a 

retrospective one, spanning the five 

calendar years prior to the year of 

enactment of the IRA, allowing the 

financial test to serve as one of multiple 

indicators of retirement risk while 

enabling owners of nuclear reactors to 


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2264 Federal Register / Vol. 90, No. 6 / Friday, January 10, 2025 / Rules and Regulations 

determine in advance whether their 

reactors meet it. If a single nuclear 

reactor has multiple owners, any coowner of the reactor may qualify the 

reactor for the financial test. This would 

provide a simplified calculation that 

does not require averaging across 

different owners that may have different 

gross receipts calculations. Although the 

co-owner used to satisfy the financial 

test does not have to be the same coowner from whom the hydrogen 

producer acquires the relevant EACs 

and electricity generated by the reactor, 

the same co-owner must be used for 

both of the two relevant years from 2017 

to 2021 to satisfy the financial test with 

respect to the reactor. 

The rule includes two alternatives for 

demonstrating that the hydrogen 

production facility is materially 

contributing to the continued operation 

of the at-risk nuclear reactor over the 

long term. Under the first approach, a 

physical, behind-the-meter, connection 

and investment between hydrogen 

production facility and plant 

demonstrates a long-term commitment 

to operation of both, thereby enabling 

the hydrogen producer to reduce the 

risk of retirement for the nuclear reactor. 

The DOE has advised that hydrogen 

production facilities are capitalintensive, long-lived assets, so that a 

behind-the-meter arrangement of this 

type is expected to reduce retirement 

risk. Under the second approach, the 

long-term commitment is demonstrated 

by a written binding contract between 

the owner of the hydrogen production 

facility and the owner of the nuclear 

reactor, under which the owner of the 

hydrogen production facility agrees to 

acquire and retire EACs from the 

nuclear reactor. The written binding 

contract must be for at least 10 years 

beginning on the first date on which 

qualified EAC are acquired and in effect 

during the time the EACs for which the 

incrementality requirement is being 

satisfied is being acquired. Further, only 

the megawatt hours of electricity for 

which the taxpayer acquires EACs from 

the nuclear reactor pursuant to the 

written binding contract may be 

considered incremental. 

The contract must also provide a 

means of managing the qualifying 

nuclear reactor’s revenue risk. This 

could be satisfied by either a PPA or 

virtual PPA with respect to the 

electricity generated by the nuclear 

reactor, or by another provision in the 

contract that fixes the price of the 

electricity or allows the price of EACs 

to vary in a manner that hedges the 

seller’s exposure to market price risk. 

EAC sales that lack a long-term binding 

contract do not reflect the same longterm investment and planning, so would 

not qualify for this allowance. 

For purposes of the written binding 

contract definition under § 1.45V– 

4(d)(2)(xi), a contract is a ‘‘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). In addition, 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, the MWh 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. 

Finally, the final regulations cap the 

amount of electricity that is deemed 

incremental at 200 MWh per operating 

hour per nuclear reactor. See § 1.45V– 

4(d)(3)(i)(D)(2). The Treasury 

Department and the IRS note that 

reducing retirement risk does not 

require the electrolyzer to be sized at the 

full capacity of the co-located nuclear 

plant, and sizing at full capacity 

significantly increases the risk of 

induced grid emissions. A hydrogen 

producer’s purchases of electricity 

beyond the amounts needed to 

substantially reduce the retirement risk 

of the nuclear reactor would divert that 

electricity from other uses on the grid, 

requiring additional electricity 

generation with the substantial risk that 

it will be generated by emitting sources. 

A 200 MWh per operating hour per 

nuclear reactor limit is consistent with 

the size of commercial scale 

electrolyzers, the deployment of which 

would demonstrate a significant longterm commitment, investment, and 

revenue stream, reducing the risk of the 

nuclear plant’s retirement. In contrast, 

as advised by the DOE, a hydrogen 

producer’s additional purchases of 

electricity beyond these amounts would 

not meaningfully provide for an 

additional reduction in the retirement 

risk of the nuclear reactor. Therefore, 

permitting the diversion of this 

electricity from other uses is likely to 

increase emissions. 

The 200 MWh per operating hour per 

reactor limit is subject to an integrated 

operations rule, which offers additional 

flexibility by providing an aggregate 

limit of 200 MWh per hour multiplied 

by the number of integrated nuclear 

reactors that have not permanently 

ceased operations. For example, two 

qualifying nuclear reactors treated as 

having integrated operations with each 

other would have an aggregate 400 

MWh per operating hour that may be 

considered incremental, which can be 

allocated across both reactors. A 

qualifying nuclear reactor is treated as 

having ‘‘integrated operations’’ with any 

other qualifying nuclear reactor if the 

reactors are: (i) 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. 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. 

Applying the 200 MWh per operating 

hour limit at the reactor level (rather 

than the plant level) is appropriate 

because project owners can vary across 

reactors at multi-reactor plants; so too 

can revenues and costs and therefore 

retirement decisions. Historically, there 

have been instances when a single 

reactor at a multi-reactor site has retired, 

indicating that decisions of whether to 

retire individual reactors could be made 

independent of other reactors in a 

facility. The Treasury Department and 

the IRS note that EAC registries would 

need to develop methods to identify 

incremental EACs consistent with the 

cap of 200 MWh of electricity per 

operating hour per nuclear reactor. 

Some comments supported allowing 

the entire capacity of any nuclear power 

plant that undergoes relicensing to 

qualify as incremental, with no other 

limitations on co-location or other 

qualifying criteria. These comments 

characterized the decision to undergo 

relicensing as a significant business 

decision that often requires significant 

capital and operational expenditures. 

Some comments suggest that both 

nuclear and hydropower plants should 

qualify on this basis. In response to 

these comments, the Treasury 

Department and the IRS note that, 

unlike the criteria for qualified nuclear 

plants provided in these final 


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Federal Register / Vol. 90, No. 6 / Friday, January 10, 2025 / Rules and Regulations 2265 

regulations, a rule that were to treat the 

full capacity of any nuclear plant that 

undergoes relicensing as incremental 

would not be reasonably tailored to 

identify reactors with high retirement 

risk or to circumstances in which a 

hydrogen producer will meaningfully 

forestall retirement. It would fail to 

account for the likelihood that facilities 

in strong financial condition are just as, 

if not more, likely to seek relicensing as 

those at financial risk because, as the 

DOE has advised, nuclear plants have 

been consistently relicensed when they 

reach the end of a licensing period. 

Whether a plant is relicensed is 

primarily a function of the plant’s age, 

not its retirement risk. While relicensing 

an older plant involves a significant 

business decision, and continued 

operation of a nuclear plant after 

relicensing will often require additional 

capital and operational expense, these 

expenses, alone, do not demonstrate 

that the plant is at risk of retirement. 

Such costs would be required and 

expended for facilities that are at little 

risk of retirement for economic reasons, 

such as those whose gross revenues 

from customers other than hydrogen 

producers significantly exceed these 

costs, or those who can rely on cost-ofservice rate recovery. The DOE has 

further advised that past retirement 

decisions for nuclear reactors have often 

been tied to unfavorable economic 

conditions, but have not obviously been 

triggered by license renewal timelines. 

Many historic retirements have occurred 

after a plant sought, and in many cases 

received, a license renewal. This 

evidence further shows that relicensing 

is related to plant age but is not a strong 

indicator of retirement risk. Including 

all nuclear facilities that undergo 

relicensing under this rule, despite the 

fact that not all such plants are at 

significant risk of retirement and many 

would continue serving existing nonhydrogen customers after relicensing, 

would incorrectly result in a large 

amount of energy to be deemed 

incremental. Such a scenario presents a 

high risk of significant unaccounted for 

induced grid emissions, and so would 

be inconsistent with statutory 

requirements. Comments addressing 

hydropower electricity are addressed in 

part III.D.3.b.vi of this Summary of 

Comments and Explanation of 

Revisions. 

In response to comments, the 

Treasury Department and the IRS also 

considered whether to add relicensing 

as an additional requirement of the 

qualifying nuclear facility rule. 

However, adding such a requirement 

could unduly limit the ability of plants 

that have recently been relicensed or 

whose relicensing date is many years in 

the future, but that are nonetheless at 

risk of retirement and for which 

hydrogen production could significantly 

reduce that risk, from benefiting from 

the rule. These final regulations, 

therefore, do not adopt criteria related to 

nuclear plant relicensing recommended 

by comments. 

vi. Other Proposed Alternatives 

The Treasury Department and the IRS 

received comments suggesting other, 

incrementality pathways. One comment 

recommended the use of locational 

marginal prices as a proxy for 

incrementality and temporal matching 

under certain price conditions. 

Locational marginal prices are not 

available on a nationwide basis and vary 

considerably from one year to the next— 

and even one hour to the next. Use of 

locational marginal prices would not 

provide a comprehensive or consistent 

measure for incrementality, and it is 

unclear how hydrogen production 

facilities could use such a proxy. 

In the Explanation of Provisions to the 

proposed regulations, the Treasury 

Department and the IRS sought specific 

comment with respect to formulaic 

approaches to incrementality. As 

described therein, one such approach 

deems five percent of the hourly 

generation from minimal-emitting 

electricity generators (for example, 

wind, solar, nuclear, and hydropower 

facilities) placed in service before 

January 1, 2023, as satisfying the 

incrementality requirement. The 

Treasury Department and the IRS noted 

that this pathway may be appropriate 

because some circumstances during 

which incremental generation would be 

unlikely to result in significant indirect 

grid emissions (including periods of 

curtailment or times when generation 

from minimal-emitting electricity 

generation is on the margin) may be 

difficult to anticipate or identify, or 

because the process for identifying the 

circumstances (such as avoided 

retirement risk or modeling of minimal 

emissions) may be overly burdensome 

to evaluate for specific electricity 

generators or require data that is not 

available. 

In response to this, several comments 

recommended that the final regulations 

adopt an alternative incrementality 

pathway based on a proxy for 

curtailment. As one comment 

explained, if both demand and clean 

supply are in the same transmission 

region or pocket during a period when 

the marginal producer is a clean energy 

resource (such as during periods of 

curtailment), then incremental power 

demand for clean hydrogen production 

is met by existing clean electricity 

generators without increasing overall 

grid emissions. Following consultation 

with the DOE and the EPA, these final 

regulations do not adopt such an 

approach at this time, as identifying 

specific cases where incremental power 

demand is met with existing clean 

electricity would require determining 

the marginal source of electricity 

production for each time period and 

region, the data for which does not 

currently exist nationally. However, the 

Treasury Department and the IRS will 

continue to study the issue, in 

consultation with the DOE and the EPA. 

Other comments expressed support 

for a formulaic approach that deemed a 

certain percent of the hourly generation 

from minimal-emitting electricity 

generators as satisfying the 

incrementality requirement. Some 

expressed support for a five-percent 

threshold, while others suggested that 

the threshold should be ten percent or 

higher. Others disagreed with a specific 

percentage and suggested instead that a 

deemed amount of incrementality be 

determined based on market factors or 

average curtailment. Comments in 

support of a formulaic approach 

justified the approach as an appropriate 

proxy for curtailment, retirement risk, or 

other cases where additional use is 

likely to be met with clean electricity. 

On the other hand, many comments 

opposed a formulaic approach, asserting 

that it is an inadequate proxy for 

incrementality and would lead to 

induced grid emissions. Comments 

provided estimates indicating that the 

large majority of the generation exempt 

from incrementality requirements under 

a formulaic approach would not be 

generated during periods of curtailment 

and would be expected to result in 

induced emissions, even under an 

approach where proxy amounts varied 

based on regional curtailment rates. 

Comments also provided estimates of 

the impact of a five-percent formulaic 

proxy on induced emissions, 

contending that the result of this 

approach would be to provide the 

section 45V credit to substantial 

generation for which actual emissions 

exceeded statutory thresholds. In 

consideration of these comments and in 

consultation with the EPA, the Treasury 

Department and the IRS agree with 

those comments that oppose the 

formulaic approach for the reason that 

it is an inadequate proxy. The Treasury 

Department and the IRS understand that 

curtailment is very region and time 

dependent, and the precise timing of 

curtailment is hard to predict. A broadVerDate Sep<11>2014 19:12 Jan 08, 2025 Jkt 265001 PO 00000 Frm 00043 Fmt 4701 Sfmt 4700 E:\FR\FM\10JAR4.SGM 10JAR4

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2266 Federal Register / Vol. 90, No. 6 / Friday, January 10, 2025 / Rules and Regulations 

34See DOE Technical Paper supra note 20; see 

also Michael A. Giovanniello, et al., The Influence 

of Additionality and Time-Matching Requirements 

on the Emissions from Grid-Connected Hydrogen 

Production, 9 Nature Energy, Feb. 2024, at 197–207; 

Electric Power Research Institute, et al., Impacts of 

IRA’s 45V Clean Hydrogen Production Tax Credit 

(2023), available at https://www.epri.com/research/ 

products/000000003002028407; Evolved Energy 

Research, 45V Hydrogen Production Tax Credits: 

Three-Pillars Accounting Impact Analysis (2023), 

available at https://www.evolved.energy/post/45vthree-pillars-impact-analysis. 

based formulaic approach would not 

likely align in time or geography with 

generation that would otherwise have 

been curtailed, which happens in 

temporally and geographically 

concentrated windows. These factors 

make the formulaic approach 

inadequate in mitigating induced grid 

emissions, while an approach that is 

based on real-time market factors would 

be difficult to administer and use. As a 

result, most generation exempt from 

incrementality requirements under the 

formulaic approach would be expected 

to result in significant indirect 

emissions. Therefore, the formulaic 

approach is in conflict with the 

statutory requirements regarding 

lifecycle GHG emissions. In contrast, 

these final regulations contain two 

additional alternative pathways, the 

qualifying States pathway and the 

qualifying nuclear reactor pathway, that 

are better tailored to circumstances in 

which the use of existing clean 

generation to produce hydrogen is 

unlikely to result in induced grid 

emissions. The addition of these more 

specific, alternative incrementality 

pathways casts further doubt on the 

need for and appropriateness of a 

percentage-based proxy that is not 

tailored to any specific conditions or 

circumstances that relate to the 

likelihood of induced grid emissions. 

Finally, several comments noted the 

prevalence and importance of 

hydropower as a clean electricity source 

in certain parts of the country and 

advocated for an across-the-board 

exception to the incrementality 

requirement for electricity derived from 

clean hydropower. Other comments, 

noting the long time period for the 

permitting and construction of a 

hydropower facility, stated that the 36- 

month lookback period is too short. On 

the other hand, one comment noted the 

possibility that the section 45V credit 

could incentivize hydropower projects 

that are societally and ecologically 

detrimental and advocated that an 

additional requirement be placed on 

such projects, requiring them to obtain 

low-impact certification using sciencebased criteria. In response, these final 

regulations do not adopt a rule 

exempting hydropower from the 

incrementality requirement, as such a 

rule would fail to take into account 

significant indirect emissions, as 

required by section 45V(c)(1)(A) and 

section 211(o)(1)(H) of the Clean Air 

Act. In addition, the DOE has advised 

that the risk of retirement for 

hydropower is comparatively lower 

than the risk of retirement for nuclear 

power. Finally, certain hydropower 

plants may be able to utilize the 

qualifying State pathway or the uprates 

pathway to satisfy the incrementality 

requirement. These regulations also do 

not impose an additional requirement 

on hydropower, such as a low-impact 

certification requirement, as this is not 

required by the statute and would 

disadvantage incremental hydropower 

relative to other incremental sources of 

clean energy. 

c. Temporal Matching 

Proposed § 1.45V–4(d)(3)(ii) would 

provide that an EAC meets the temporal 

matching requirement 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. It also 

would provide a transition rule for 

EACs representing electricity generated 

before January 1, 2028, stating that an 

EAC meets the temporal matching 

requirement 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. 

i. Hourly Matching 

Many comments expressed support 

for the proposed temporal matching 

rule, referred to as ‘‘hourly matching.’’ 

One comment noted that requiring 

hourly matching will lead EAC 

registries to quickly create hourly 

tracking mechanisms. Several comments 

suggested that delaying the 

implementation of hourly matching 

until 2028 was unnecessary, offering a 

variety of suggestions to move up the 

timeline. 

Other comments opposed the hourly 

matching rule for various reasons. Some 

comments opposed hourly matching 

because it does not account for the 

variability of wind and solar, which are 

prevalent sources of clean energy. Some 

comments noted that hourly matching 

leads to increased capital costs that 

decrease the viability of electricityintensive hydrogen production. One 

comment expressed concern that hourly 

matching increases costs more than the 

credit will reduce them. One comment 

noted that the increased costs would 

push the industry to shift to lower cost 

solutions, like purchasing foreign 

equipment that may be less expensive 

than higher cost domestic equipment. 

Another comment noted that these 

higher costs will specifically hinder 

investment in smaller regional facilities. 

Several comments expressed concern 

about the hourly matching rule as 

applied to the Regional Clean Hydrogen 

Hubs because hourly EAC requirements 

were not contemplated by hydrogen hub 

participants at the time they applied for 

funding from the DOE to be a hydrogen 

hub participant or because the 

requirement does not align with 

anticipated construction schedules. One 

comment contended that hourly 

matching is too difficult to administer 

because of poor infrastructure, software 

limitations, and regulatory hurdles. 

Several comments recommended 

alternative periods for matching, such as 

daily, monthly, quarterly, or annual. 

Comments advocating for monthly 

matching suggested that monthly 

matching would be more beneficial than 

hourly matching for electrolytic 

hydrogen producers because it would 

likely decrease the operational impact 

on electrolyzers by reducing the number 

of stoppages, which can lower costs and 

prolong the durability of the equipment. 

Other comments recommended monthly 

matching as a reasonable compromise 

between annual and hourly matching. 

One comment stated that the required 

timeline for matching should align with 

the battery electric vehicle standards. 

One comment maintained that hourly 

matching is unworkable based on 

current tracking practices. 

Temporal matching at an hourly level 

best mitigates the risk of induced grid 

emissions by requiring that the 

generation that created the EACs must 

occur at the same time as the EAC 

buyer’s load. As noted in the DOE 

Technical Paper and studies cited by 

comments, the three qualifying EAC 

requirements address both operational 

(short-term) and structural (long-term) 

effects that can affect lifecycle emissions 

outcomes.34

The DOE Technical Paper noted that 

hourly matching is necessary to 

properly address induced grid 

emissions. Hourly matching of EACs 

will provide significantly greater 

certainty about mitigating the risk of 

induced grid emissions by ensuring 

actual alignment between load and 

generation. However, as noted in the 

preamble to the proposed regulations, 

the Treasury Department and the IRS 

acknowledge that hourly tracking of 

EACs is not yet widely available on a 

standardized basis. The DOE has 

advised the Treasury Department and 


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35National Renewable Energy Laboratory, 

Regional Energy Deployment System (ReEDS) 

Model Documentation (2021), available at https://

www.nrel.gov/docs/fy21osti/78195.pdf. 

the IRS that tracking systems and 

related contractual structures for hourly 

matching will take some time to develop 

to an appropriate level of maturity. 

Accordingly, a transition rule that 

allows annual matching remains 

appropriate. The transition rule is 

intended to provide time for the EAC 

market to develop the hourly tracking 

capability necessary to verify 

compliance with this requirement, and 

for associated hourly EAC markets to 

develop. The transition rule, and 

associated comments, are discussed in 

part III.D.3.c.ii of this Summary of 

Comments and Explanation of 

Revisions. 

Several comments suggested the 

adoption of a provisional approach to 

hourly matching before hourly matching 

is integrated into EAC registries. One 

comment suggested that this proposed 

approach could use hourly generation 

and hydrogen production meter data 

merged with annual or monthly EACs to 

demonstrate hourly matching where 

hourly EACs are not available. 

The Treasury Department and the IRS 

note that nothing in this final regulation 

prohibits hydrogen producers from 

voluntarily implementing hourly 

matching prior to the phase-in date for 

hourly matching. Hence, no specific 

guidance is required on the allowed use 

of a provisional hourly matching 

approach prior to the end of the 

transition period. Allowing the 

provisional approach after the transition 

to hourly matching would place 

additional administrative burden on 

hydrogen producers and third-party 

verifiers and would complicate IRS 

administration. Moreover, allowing the 

provisional approach after the transition 

date may diminish the incentive for 

EAC registries to develop full hourly 

EAC tracking capability. Given these 

considerations, these final regulations 

neither explicitly allow nor require the 

provisional approach. 

Multiple comments suggested that the 

Treasury Department and the IRS 

should consider providing a degree of 

flexibility in meeting the hourly 

temporal requirement, such as through 

allowing a limited percentage of annual 

electricity supply to be exempt from 

hourly temporality requirements. As 

one example, a comment recommended 

flexibility with respect to temporal 

matching for hydrogen producers 

located in States where the production 

of certain renewable energy is highly 

seasonal. However, as previously 

described, hourly matching is necessary 

to properly address induced grid 

emissions and to ensure that a hydrogen 

producer can properly attribute its load 

to a specific electricity source. The DOE 

has advised that exceptions that would 

allow some fraction of EACs to not be 

matched hourly increase the risk of 

induced grid emissions that would 

undermine one of the purposes of 

section 45V. In addition, any such 

fractional exception would require 

detailed and granular regional analysis. 

Allowing such fractional exceptions is 

therefore inconsistent with the statutory 

requirements and is not readily 

administrable. These final regulations, 

therefore, do not provide for fractional 

exceptions. 

Along with the transition rule, these 

final regulations allow electricity 

storage to be used to shift the temporal 

profile of clean electricity supply as 

described in part III.D.3.c.v of this 

Summary of Comments and Explanation 

of Revisions. The Treasury Department 

and the IRS anticipate that these 

allowances may partially alleviate 

concerns with hourly temporal 

matching. 

One comment requested clarification 

regarding the applicability of the 

National Renewable Energy Laboratory’s 

Regional Energy Deployment System 

(NREL-ReEDS), a capacity planning 

model, to tracking hourly matching. The 

comment was submitted by a 

stakeholder that belongs to multiple 

power regions and expressed a need to 

acquire capacity in the next few years. 

The comment indicated that NRELReEDS is a potentially helpful tool in 

this regard because it covers 134 

balancing areas. 

The DOE has advised that NRELReEDS would not be an applicable tool 

for the purposes of compliance with 

hourly matching requirements or for 

providing detailed hourly grid carbonintensity estimates. Hourly matching 

systems and hourly grid carbonintensity estimates require detailed data 

of real-life plant-level generation 

patterns, whereas NREL-ReEDS is a 

forward-looking simulation tool that 

does not fully capture actual operations. 

Furthermore, NREL-ReEDs does not 

have the temporal resolution to 

characterize detailed operating 

behaviors of individual units,35 which 

would be required of an hourly 

matching system used for compliance 

with these final regulations. 

ii. Transition Period 

Comments expressed divergent views 

on the appropriate timing of the 

transition rule. Many comments 

supported the proposed rule to allow 

annual accounting until 2028 and did 

not want it extended. Some comments 

supported hourly matching sooner than 

2028. Several comments noted that a 

transition date of January 1, 2028, 

would provide enough time for 

registries to test and scale hourly EAC 

tracking systems nationwide. These 

comments urged the Treasury 

Department and the IRS not to 

unnecessarily delay or extend the 

transition date. According to one 

comment, the implementation date of 

January 1, 2028, would align with EU 

member states that decide to transition 

to hourly matching by mid-2027. 

However, the rest of the EU is required 

to transition to hourly matching in 2030 

without a reliance rule. According to 

this comment, such alignment would 

help ensure that clean hydrogen and 

hydrogen-derived products such as 

ammonia, steel, and fertilizer will be 

available in the European market 

without confused, disjointed, or weak 

claims of low-carbon status. One 

comment expressed support for the 

current length of the transition rule but 

has suggested that, if the Treasury 

Department and the IRS decide to 

extend the duration of the pre-transition 

period, it should not go beyond 

December 31, 2029, to match EU 

regulations. Some comments stated that 

the Treasury Department and the IRS 

could implement hourly matching at 

present, even if hourly EACs are not yet 

available, by allowing taxpayers to use 

hourly meter data and annual or 

monthly EACs. One comment further 

recommended that the Treasury 

Department and the IRS review tracking 

registries’ progress in developing the 

needed software by 2026 or 2027 and, 

if necessary, delay the transition by one 

year at a time (rather than to 

preemptively assume systems will not 

be ready). 

Many other comments asked for a 

more extended timeframe before hourly 

matching is required. Generally, most 

comments supported extending the pretransition period several years beyond 

2027. Some comments recommended 

that the pre-transition period align with 

the EU’s implementation of hourly 

matching in 2030. Additionally, while 

some comments did not specify a 

preferred duration of the pre-transition 

period, they did emphasize that hourly 

matching should be implemented only 

after the hourly EAC market is fully 

developed and ready for use, in 

particular for the relevant geographic 

region. Some of these comments 

expressed concerns about EAC registry 

and market readiness as well as the 

possible cost and operational burdens 


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2268 Federal Register / Vol. 90, No. 6 / Friday, January 10, 2025 / Rules and Regulations 

36Rachael Terada, Director, Technical Products, 

Center for Resource Solutions, Readiness for 

Hourly: U.S. Renewable Energy Tracking Systems 

(Jun. 15, 2023), available at https://resourcesolutions.org/wp-content/uploads/2023/06/ 

Readiness-for-Hourly-U.S.-Renewable-EnergyTracking-Systems.pdf. 

37See DOE Technical Paper supra note 20. 

for clean hydrogen producers. Separate 

from the precise timing of the transition, 

other comments suggested 

preconditions or triggers for the 

transition, for example, a future study 

assessing readiness before proceeding. 

Some comments recommending 

extension of the pre-transition period 

suggested allowing annual matching to 

continue for a longer duration before 

requiring hourly matching. Other 

comments recommended introducing 

quarterly or monthly matching, or some 

combination of annual and hourly 

matching, during an extended pretransition period. Some comments also 

recommended extending the pretransition period beyond the current 

end date, but on a facility-by-facility 

basis. 

Comments also expressed that the 

Treasury Department and the IRS have 

focused on the wrong metric—whether 

the technology and systems exist for 

tracking hourly EACs—for evaluating 

when hourly matching should be 

required. According to these comments, 

a better metric for evaluating whether to 

proceed with the implementation of 

hourly matching is whether there is a 

consistent need for and supply of 

electricity from renewable sources. 

Other comments argued that the phasein of hourly matching is not feasible 

until the grid’s infrastructure can 

support 24-hour clean energy 

production. These comments argued 

that while clean energy technologies 

continue to grow, the infrastructures are 

not developing fast enough to support 

hourly matching. One such comment 

suggested that if hourly matching is 

mandated, there should be a monthly 

netting of the hourly mismatch between 

the actual energy provided and the 

energy that was scheduled. This 

comment claimed that errors in clean 

energy scheduling would significantly 

harm hydrogen producers using hourly 

matching. 

Balancing these various comments 

and concerns, and as advised by the 

DOE and the EPA, the final regulations 

extend the transition period by two 

additional years, to 2030. Annual 

matching will be required through 2029, 

and hourly matching will be required 

thereafter. This requirement will apply 

to all production of qualified clean 

hydrogen represented by EACs starting 

in 2030, regardless of when the facility 

was placed in service. 

These additional two years are 

warranted to ensure tracking systems 

can achieve the necessary functionality 

for an hourly matching requirement, 

and to allow the market to develop for 

hourly-matched EACs. In a survey of 

nine existing tracking systems, two 

respondents indicated that their systems 

are tracking on an hourly basis, 

although software functionality remains 

limited.36 Fully developing the 

functionality of these systems will take 

time, as will creating and developing 

the functionality of hourly tracking 

infrastructure in other regions of the 

country. Of the other tracking systems, 

assuming that challenges are overcome, 

four respondents indicated that their 

systems will be able to adopt hourly 

matching in less than two years. One 

respondent indicated that their system 

will take from three to five years, noting 

that the timeline could be closer to three 

years if there is full State agency buyin, clear instructions are received from 

Federal or State agencies, and funding 

for stakeholder participation is made 

available. Two respondents declined to 

give a timeline for how long it would 

take for their systems to develop this 

functionality. In the same survey, the 

respondents identified several 

challenges to hourly tracking that will 

need to be overcome, including cost, 

regulatory approval, interactions with 

state policy, sufficient stakeholder 

engagement, data availability and 

management, and user confusion. 

Among the issues that require resolution 

as EAC tracking systems move to hourly 

resolution is the treatment of electricity 

storage,37 which this final regulation 

will allow as a means of shifting the 

temporal profile of clean generation. 

Some comments expressed confidence 

in the rapid scaling of hourly EAC 

tracking, markets, and matching, and 

others were skeptical. The survey of 

EAC registries is particularly 

informative, and it indicates that the 

registries themselves are generally 

confident that they can achieve the 

required functionality comfortably 

within the transition period provided in 

these final regulations. 

In response to concerns raised by 

comments that the 2028 transition 

timeline proposed in § 1.45V– 

4(d)(3)(ii)(B) offers relatively little 

flexibility should technological or 

institutional implementation issues or 

delays arise, these final regulations add 

an additional two years to the transition 

so as to provide more flexibility and 

high confidence that implementation 

deadlines will be met. With this 

additional time, EAC registries should 

have ample time to develop hourly 

tracking mechanisms, and associated 

trading markets and contractual 

mechanisms will have sufficient time to 

mature. Given this extension, it is not 

necessary to establish a future triggerbased approach wherein the timing of 

the transition would be based on a 

future study because such an approach 

would diminish the incentives to create 

hourly matching functionality, 

potentially further delaying the 

transition with the risk of induced grid 

emissions that would result in tax credit 

claims that are contrary to the statute. 

iii. Reliance Rule 

Many comments requested a reliance 

rule or legacy allowance wherein 

facilities that have met a certain 

milestone by a certain date would be 

permitted to continue to satisfy the 

temporal matching rule by using 

annually-matched, instead of hourlymatched, EACs, for hydrogen produced 

after December 31, 2027. Recommended 

milestones include (1) beginning of 

construction; (2) placed in service; or (3) 

commencement of commercial 

operations. While most comments 

recommended requiring that the 

milestone be reached before January 1, 

2028, some comments recommended 

that the Treasury Department and the 

IRS consider using later milestone dates. 

Additionally, there are differing views 

on the scope of the reliance rule. While 

many comments supported it for the 

entire duration of the 10-year credit 

period, one comment suggested that the 

rule should only apply to the first five 

years. Other comments suggested that 

the first 10 gigawatts of project capacity 

should be represented by annual EACs, 

and hourly EACs thereafter. Similarly, 

some comments suggested allowing 

annual EACs to be used after December 

31, 2027, for either a percentage of 

hydrogen production or a percentage of 

the total electricity used to produce 

hydrogen. Finally, the comments 

included both individual 

recommendations and combinations of 

multiple recommendations. 

The comments provided various 

rationales for a reliance rule. One 

comment said that a reliance rule would 

enable the U.S. to become the global 

leader in green hydrogen, create jobs 

and a domestic supply chain, and 

ensure a reduction in GHG emissions in 

the industrial sector long term. Several 

comments indicated that a reliance rule 

would alleviate investment uncertainty 

during the 10-year credit period for 

certain projects (for example, early 

movers). Similarly, another comment 

claimed that a reliance rule would 

create consistent, ratable, and lower-cost 

volumes of hydrogen production. 


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Another comment said that, without a 

reliance rule, taxpayers will have to use 

hourly EACs for financial projection 

purposes beginning in year one, even 

though hourly EACs are not necessary 

until 2028. Another comment indicated 

that there is great uncertainty whether 

the industry can rely on hourly EACs 

and noted that the change from annual 

EACs to hourly EACs is too aggressive. 

For example, one comment said that 

hourly EACs effectively will restrict the 

operation of electrolyzers to times when 

renewable generation sources are 

available, which could increase the 

levelized cost of hydrogen for initial 

projects. 

Several comments specifically 

advocated against any reliance rule that 

would allow producers to avoid the 

phasing-in of hourly matching. Another 

comment recommended a temporary 

approach prior to the 2028 phase-in that 

would utilize annual/monthly EACs so 

tracking systems like M–RETS will have 

an easier time transitioning to hourly 

matching. According to the comment, 

this temporary approach would also act 

as a provisional pathway if hourly 

matching were not feasible by 2028. 

Finally, one comment supported 

requiring a simulation of hourly 

matching in the years prior to 2028, 

beginning in 2026, which would 

facilitate a smoother transition to hourly 

matching. This would be in addition to 

the annual matching of EACs to actual 

hydrogen production for the purpose of 

calculating the section 45V credit. 

These final regulations do not adopt 

a reliance rule or legacy allowance 

whereby projects that reach a certain 

milestone prior to a certain date are 

allowed to maintain something more 

permissive than hourly matching for a 

specified period or for the duration of 

the credit period. The qualifying EAC 

requirements are essential to fulfill the 

statutory mandate in section 

45V(c)(1)(A) and section 211(o)(1)(H) of 

the Clean Air Act to address significant 

indirect emissions, which includes 

induced grid emissions, in assessing 

lifecycle GHG emissions for purposes of 

section 45V. A reliance rule or legacy 

allowance would increase the risk of 

such significant indirect emissions that 

must, under the statute, be considered 

in assessing the lifecycle GHG emissions 

rate. It is imperative to apply each of the 

qualifying EAC requirements to 

qualifying clean hydrogen production as 

soon as practicable to implement the 

statutory requirements. 

iv. Other Approaches 

Several comments recommended 

broader changes, alternatives, or 

exceptions to the proposed hourly 

matching framework. One comment 

suggested that, in the case of distributed 

renewable energy that is not connected 

to the grid, the final regulations should 

exempt such electricity from the hourly 

matching requirement and consider 

doing the same in the case of distributed 

renewable energy that is connected to 

the grid. Similarly, another comment 

requested that the Treasury Department 

and the IRS reconsider the hourly 

matching requirement and 

recommended alternative compliance 

methods, such as co-location with clean 

energy facilities or contractual pairing. 

Alternatively, one comment 

recommended that the final regulations 

employ a CO2 accounting approach to 

address significant indirect emissions. 

Another comment asserted that 

temporal matching makes hydrogen 

production during certain periods of the 

day or year uneconomical, which leads 

to a decrease in hydrogen, and so the 

final regulations should employ a net 

energy monitoring approach. Another 

comment requested that the final 

regulations allow projects to use ‘‘low 

price’’ market signals as a proxy for 

temporal matching because such an 

approach would create a transparent 

market signal for hydrogen production 

resources to efficiently capture surplus 

energy by locating and designing 

facilities to capture and store this excess 

renewable energy. 

Finally, one comment recommended 

an exception to the temporal matching 

requirement based on capacity where 

the final investment decision is made 

before 2028 with respect to a hydrogen 

production facility. Specifically, the 

comment recommended a 15 percent 

capacity exemption for all regions 

except California Independent System 

Operator (CAISO) and a 30 percent 

capacity exemption in solar intensive 

regions. 

As indicated in the proposed 

regulations, the three qualifying EAC 

requirements work together to mitigate 

the risk of induced grid emissions, as 

they constitute significant indirect 

emissions, consideration of which is 

required by section 45V(c)(1)(A) and 

section 211(o)(1)(H) of the Clean Air 

Act. As noted in the DOE Technical 

Paper, and supported by multiple 

comments, the three requirements 

address both operational (short-term) 

and structural (long-term) effects that 

can cause induced grid emissions and 

thus affect lifecycle emissions 

outcomes. Further discussion as to why 

an exception to the qualifying EAC 

requirements for energy generation that 

is co-located or not connected to the 

grid is not viable is discussed in part 

III.D.1 in this Summary of Comments 

and Explanation of Revisions. Given 

these findings and upon the advice of 

the DOE and the EPA, these final 

regulations do not add any additional 

exceptions to the hourly matching 

requirement, with the exception for 

clarifying the use of energy storage, as 

explained in part III.D.3.c.v of this 

Summary of Comments and Explanation 

of Revisions. Any such exceptions 

increase the risk of significant indirect 

emissions in the form of induced grid 

emissions that must be taken into 

account under the statute in 

determining the lifecycle GHG 

emissions rate. 

Many comments stated that, if the 

Treasury Department and the IRS 

impose a temporal matching 

requirement, then hydrogen production 

facilities located in States with 

statutorily mandated clean energy 

policies should be deemed to have 

already met those Federal requirements. 

One comment recommended that 

hydrogen production facilities located 

in such States or regions should receive 

a waiver of the requirement for hourly 

matching. Other comments stated that, 

because hourly matching imposes a 

significant cost, section 45V accounting 

should instead require clean hydrogen 

production facilities in California and 

other similarly situated States to apply 

the same temporal matching system that 

those States apply to other carbon-free 

technologies, like batteries. 

As described in part III.D.3.b.iv of this 

Summary of Comments and Explanation 

of Revisions, the Treasury Department 

and the IRS agree with these comments 

that certain States have enacted policies 

that effectively address the risk of 

induced grid emissions. However, these 

State policies only address the 

incrementality requirement; temporal 

matching and deliverability 

requirements must still be met. 

Temporal matching on an hourly basis 

ensures that there is actual alignment 

between the timing of generation and 

the additional load created by the 

production of hydrogen. Put another 

way, the temporal matching and 

deliverability requirements together 

ensure that the hydrogen producer 

could consume the incremental 

generation it is claiming by virtue of 

such generation being deliverable to the 

producer at the same time the electricity 

is being consumed. These requirements 

enable the hydrogen producer to assert 

that its hydrogen production is utilizing 

electricity generation with no (or 

minimal) direct emissions, and to 

reduce the risk of induced grid 

emissions. The incrementality 

requirement is additionally necessary to 

ensure that use of zero- or minimalVerDate Sep<11>2014 19:12 Jan 08, 2025 Jkt 265001 PO 00000 Frm 00047 Fmt 4701 Sfmt 4700 E:\FR\FM\10JAR4.SGM 10JAR4

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emitting generation does not indirectly 

lead to significant increases in 

emissions elsewhere on the grid. State 

policies that meet certain requirements 

can obviate the need for the 

incrementality requirement by 

providing certainty that use of any clean 

power generation will not indirectly 

lead to an increase in emitting 

generation. But to qualify for the section 

45V credit, the facility still needs to 

demonstrate availability of the use of 

such generation to produce the qualified 

clean hydrogen in the first place, 

necessitating the purchase and 

retirement of EACs that meet the 

temporal matching and deliverability 

requirements. Accordingly, these final 

regulations do not adopt these 

comments. 

Another comment noted that there 

should be a Scope 2 attribute approach 

with a small amount of operational 

flexibility. The Scope 2 approach, 

specifically referencing the Greenhouse 

Gas Protocol’s market-based 

methodology, is based on the attributes 

of the electricity supply, accounting for 

the conveyance of those attributes via 

market-based mechanisms such as 

EACs. The market-based methodology 

for calculation of Scope 2 emissions 

calculates hourly grid carbon intensity 

by deliverability region rather than the 

current location-based methodology. 

The Treasury Department and the IRS 

are unsure of the nature of this request. 

However, the DOE has advised that the 

lack of consistent, comprehensive, realtime, national data on hourly marginal 

emissions prevents implementing 

hourly marginal emissions as the 

regional default rates employed in 

45VH2–GREET. The DOE Technical 

Paper also notes the limits to solely 

relying on short-run marginal emissions 

rates that exclude structural effects. 

Additionally, it is difficult to envision 

how a clean hydrogen producer would 

utilize those data in real time were they 

available and implemented in 45VH2– 

GREET. As such, the Treasury 

Department and the IRS understand that 

45VH2–GREET will retain the regional, 

annual average grid emissions rate as 

the default emissions rate. The Treasury 

Department and the IRS reiterate, 

however, that a clean hydrogen 

producer may purchase qualifying EACs 

as a means to select an alternative to 

using 45VH2–GREET’s default 

emissions rate for the regional grid and 

may select the electricity source 

technology (for example, solar and 

wind) of the specific electricity 

generator(s) from which it has 

purchased qualifying EACs as part of 

the calculation determining its lifecycle 

GHG emissions. 

v. Treatment of Energy Storage 

Several comments requested 

clarification on how the temporal 

matching requirement applies to energy 

storage. Some comments suggested a 

provision setting the temporal matching 

time stamp for stored green energy to 

the time of dispatch from the storage 

unit, not to the time of generation of the 

energy or the time of storage. Comments 

explained that this incentivizes 

renewable energy storage and will lead 

to greater levels of temporal matching. 

Some comments requested 

implementing a ‘‘portfolio’’ method to 

allow temporal matching from a 

‘‘portfolio’’ of clean energy assets. Such 

comments advocated allowing temporal 

matching from both behind-the-meter 

and front-of-the-meter energy storage. 

However, one comment expressed 

concern with implementing a 

‘‘portfolio’’ method. This comment 

noted that tracking EACs of stored 

electricity over time is complicated by 

issues such as carbon-free energy 

content, round-trip efficiency loss, and 

nuances of energy storage operations 

including ancillary services. 

The Treasury Department and the IRS 

acknowledge the growth of electricity 

storage and the ability of such storage to 

shift the hourly temporal profile of 

clean generation. Similarly, storage sited 

at a clean hydrogen production facility 

may shift the hourly load of that facility. 

Therefore, these final regulations will 

allow temporal shifting of clean 

generation, but the ability of entities to 

claim and verify the use of energy 

storage is contingent on whether and 

when EAC registries can substantiate 

the effective tracking of electricity 

through that storage. Specifically, 

§ 1.45V–4(d)(3)(ii)(C) will allow 

hydrogen producers and their electricity 

suppliers to use electricity storage to 

shift the temporal profile of EACs based 

on the period of time in which the 

corresponding electricity is discharged 

from storage. However, such allowance 

is predicated on certain requirements. 

An EAC meets the requirements of 

§ 1.45V–4(d)(3)(ii)(A) 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 also 

be located in the same region as both the 

hydrogen production facility and the 

facility generating the electricity to be 

stored. Storage systems need not 

themselves meet the incrementality 

requirement, but the EACs that 

represent electricity stored in such 

storage systems must meet the 

incrementality requirement based on the 

attributes of the generator of such 

electricity. EACs that represent the 

attributes of stored electricity for 

purposes of section 45V must be retired 

in EAC registries that ensure that such 

EACs support energy use claims without 

double counting; ensure that the volume 

of energy use substantiated by such 

EACs accounts for storage-related 

efficiency losses; develop frameworks 

that comprehensively address storage, 

that is, do not allow selective reporting 

of EACs of stored electricity; and 

develop frameworks for estimating the 

temporal profile of stored and 

discharged electricity represented by 

EACs, including when storage is 

charged with multiple electricity 

generators, not all of which produce 

sufficiently minimal emissions to 

produce hydrogen that qualifies for the 

section 45V credit. If an EAC satisfies 

these basic conditions and its 

acquisition and retirement can be 

substantiated by an EAC registry, then 

such EACs may meet the temporal 

matching requirement based on the time 

the stored electricity is discharged. 

Some comments asked that hydrogen 

producers also be allowed to contract 

with off-site electricity storage to shift 

their load profile. These final 

regulations do not offer this option as it 

adds an additional layer of 

administrative complexity. The 

previously described allowances for onsite energy storage to shift load 

(verifiable through meter readings) and 

off-site energy storage to shift clean 

power production profiles (verifiable via 

EAC registries that develop that 

capability) provide adequate flexibility 

for clean hydrogen producers without 

adding another administratively 

complex option. 

Another comment suggested that the 

Treasury Department and the IRS 

require EAC fractionalization to the 

nearest kilowatt hour (kWh) (0.001 

MWh) so credit calculations can be 

accurate and because, in some regions, 

a difference of a single kWh is enough 

to move a taxpayer from one section 

45V credit tier to another tier. 

Concerning fractionalization of EACs, 

the technical details for tracking 

qualifying hourly EACs are best left to 

EAC registries. As described in part 

III.D.3.c.ii of this Summary of 

Comments and Explanation of 

Revisions, hourly matching of EACs is 

required by 2030. Other rules in these 

final regulations similarly will require 

EAC registries to develop new 

capabilities. The Treasury Department 

and the IRS encourage EAC registries to 

work together and with external 


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38U.S. Department of Energy, National 

Transmission Needs Study, (Oct. 2023) available at 

https://www.energy.gov/gdo/national-transmissionneeds-study (click ‘‘Read the Full Report’’). 

stakeholders to develop appropriate, 

common approaches to tackling these 

new issues. More broadly, some 

comments asked the Treasury 

Department and the IRS to establish a 

specific standard for hourly EACs, such 

as EnergyTag. While the Treasury 

Department and the IRS acknowledge 

that standardizing the approach to 

hourly matching across EAC registries 

would be valuable, these final 

regulations do not require such a 

comprehensive standard at this time 

given potential risks in doing so and the 

limited comment record. 

vi. Temporal Matching and Interaction 

With Annual Emissions Averaging 

Several comments noted that 45VH2– 

GREET does not facilitate hourly data or 

calculations. One comment 

recommended that, if the Treasury 

Department and the IRS implement 

hourly matching on January 1, 2028, 

then 45VH2–GREET should be updated 

to reflect grid emissions on an hourly 

basis (rather than on an annual basis) to 

ensure the highest level of accuracy, 

incentivize the use of electrolysis during 

periods of low grid emissions, and 

better tie hydrogen production to 

periods of operations. Alternatively, one 

comment requested additional guidance 

on how data from hourly EACs should 

be aggregated and applied to create the 

required annual average grid mix for 

purposes of 45VH2–GREET. As support, 

the comment contended that aggregating 

data on a more granular basis to support 

the higher-level input into 45VH2– 

GREET would reduce administrative 

burden and achieve the same intended 

outcome. The same comment also 

asserted that 45VH2–GREET should not 

be performing hourly lifecycle 

calculations because doing so would be 

too tedious and provide little value. 

The Treasury Department and the IRS 

acknowledge that the current version of 

45VH2–GREET does not represent grid 

emissions on an hourly basis. Carbon 

intensities of regional grids in the model 

are currently based on estimates of 

average generation mixes in a given 

year, as described in the 45VH2–GREET 

User Manual. The current model 

therefore reflects GHG emissions 

associated with regional grid electricity 

production and transmission on the 

basis of annual averages. The DOE has 

advised that representation of regional 

grid emissions on an hourly basis is not 

technically feasible within the current 

model and is not expected to be feasible 

in the near future, given lack of highfidelity data and streamlined modeling 

capabilities available at this granularity. 

This is especially true given the need to 

account for both operational and 

structural effects in emissions modeling. 

Separately, as described in § 1.45V– 

4(a)(2), qualified clean hydrogen 

production facilities will be permitted 

to perform sub-annual (hourly) 

accounting of their lifecycle GHG 

emissions associated with electricity 

used in a hydrogen production process 

for section 45V credit tier eligibility 

determinations, subject to certain 

conditions, once the hourly matching 

requirement begins in 2030. This subannual accounting approach will allow 

facilities to reflect emissions from 

electricity consumption on an hourly 

basis if the electricity is procured from 

a specific generator and the 

consumption of that electricity is 

verified via the purchase and retirement 

of qualifying EACs. 45VH2–GREET may 

require updates to enable this method. 

More information on methods to 

estimate emissions on a sub-annual 

basis will be available in future 45VH2– 

GREET supporting documentation. 

d. Deliverability 

Proposed § 1.45V–4(d)(3)(iii) would 

provide that an EAC meets the 

deliverability requirement if the 

electricity represented by the EAC is 

generated by a facility that is in the 

same grid region as the hydrogen 

production facility. ‘‘Region’’ would be 

defined in proposed § 1.45V–4(d)(2)(vi) 

as a region derived from the National 

Transmission Needs Study that was 

released by the DOE on October 30, 

2023 (DOE Needs Study).38 Alaska, 

Hawaii, and each U.S. territory would 

be treated as separate regions. 

i. Alternative Deliverability Regions 

While many comments supported the 

proposed rule’s definition of geographic 

regions, some variously suggested 

larger, smaller, or different regions. 

Many comments requested that 

something other than the DOE Needs 

Study be used as the basis for the 

deliverability regions, such as the six 

North American Electric Reliability 

Corporation (NERC) regions, the FERC 

power markets, the Balancing Authority 

Areas, the existing tradeable REC 

markets, the three large interconnection 

regions (that is, Eastern, Western, and 

ERCOT), and the power pool boundaries 

and interregional transmission. There 

were several unique proposals made by 

individual comments. One comment 

argued that deliverability regions should 

reflect transmission links between 

NERC regional reliability councils and 

market alignment such as the Western 

Energy Imbalance Market (WEIM) with 

the Western Energy Imbalance Service 

Market (WEIS). Other comments asked 

for Independent System Operator (ISO) 

areas to be used as the deliverability 

regions, or that regions should accord 

with existing regional tracking systems 

(for example, the Western Electricity 

Coordinating Council (WECC) and 

WREGIS). Another comment proposed 

that Regional Transmission 

Organization (RTO)- or ISO-defined 

local areas be used to establish 

deliverability for EACs, offering 

Midcontinent Independent System 

Operator (MISO) Local Resource Zones 

as an example. One comment requested 

that co-location within the same RTO be 

treated as establishing deliverability. 

One comment stated that the final 

regulations should provide a correct and 

consistent definition of the MISO and 

Southwest Power Pool (SPP) grids 

where a facility is located in an area 

served by both. Another comment asked 

that the final regulations explicitly state 

that each U.S. balancing authority is 

linked to a DOE Needs Study region, 

claiming that this is already in the 

45VH2–GREET User Manual. Finally, 

one comment argued that the location of 

an electricity generator and of a 

hydrogen production facility should be 

determined by the balancing authority 

with which the facility is 

interconnected, not strictly its 

geographic location. 

Regarding specific regions, some 

comments asked that the SPP region be 

considered its own deliverability region; 

that MISO be treated as one 

deliverability region, rather than as two; 

that the entire WECC be used as a 

deliverability region in the Western 

U.S.; and that WECC be treated as two 

regions based on the WEIM and the 

WEIS. 

The final regulations retain the 

proposed regulations’ general 

framework for drawing the regional 

boundaries, which were derived from 

the DOE Needs Study. To clarify the 

regions, the final regulations add a table 

of balancing authorities and their 

corresponding regions. The table 

published in these final regulations is 

the definitive source for identifying the 

regions. A copy of this table is also 

reprinted in the forthcoming 45VH2– 

GREET User Manual (January 2025). In 

response to comments seeking 

clarification regarding how to determine 

the appropriate region, the final 

regulations provide in § 1.45V– 

4(d)(3)(iii)(A) that the electricity 

generating source and the hydrogen 

production facility are located in the 

same region if they are both electrically 


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interconnected to a balancing authority 

(or balancing authorities) that is located 

in the same region, as identified in the 

table provided in § 1.45V–4(d)(2)(ix). 

For example, a hydrogen production 

facility that is electrically 

interconnected to the East Kentucky 

Power Coop, Inc. Balancing Authority 

and an electricity generating source that 

is electrically interconnected to the 

Ohio Valley Electric Corp. Balancing 

Authority are both in the Mid-Atlantic 

Region as reflected in the table. 

Accordingly, the hydrogen production 

facility and the electricity generating 

facility are in the same region for 

purposes of proposed § 1.45V– 

4(d)(2)(vi) (now renumbered as § 1.45V– 

4(d)(2)(ix) and (3)(iii)(A). 

While the map shown in the 45VH2– 

GREET User Manual may be a useful 

visual guide, it is the table and the 

balancing authority (or authorities) to 

which the hydrogen production facility 

and electricity generating source are 

electrically interconnected that defines 

the section 45V region. The MISO 

balancing authority is split between 

MISO North/Central and MISO South, 

as described in the table published in 

these final regulations and as shown in 

the map in the 45VH2–GREET User 

Manual. Alaska, Hawaii, and each U.S. 

territory are treated as separate regions. 

To the extent modifications to the 

balancing authorities and their 

corresponding regions are made in the 

future based on additional analysis by 

the DOE, taxpayers may continue to use 

the table published in these final 

regulations. In addition, the Treasury 

Department and the IRS intend to issue 

a safe harbor that would be published in 

the Internal Revenue Bulletin that 

would allow taxpayers to use a modified 

table of balancing authorities and their 

corresponding regions instead of the 

table published in these final 

regulations. 

As described in the proposed 

regulations, the DOE has advised that 

these regions provide reasonable 

assurances of deliverability of electricity 

because they were developed by the 

DOE in consideration of transmission 

constraints and congestion and, in many 

cases, match power-systems operational 

regions. The DOE has also advised that 

they reasonably match market and 

transmission planning regional 

boundaries (for example, Southeastern 

Regional Transmission Planning, and 

PJM Interconnection), in line with many 

suggestions from comments. Because of 

this, these regions remain the best 

geographic representation of 

deliverability for purposes of the 

qualifying EAC requirements. 

The Treasury Department and the IRS 

recognize that transmission limitations 

also exist within these specified regions 

but are not aware of readily 

administrable options to reflect those 

grid constraints in a consistent fashion. 

The DOE Needs Study found that 

interregional transmission constraints 

tend to be greater than within-region 

constraints. With respect to establishing 

larger regions, whether based on the six 

NERC regions or otherwise, the DOE has 

advised that such regions would not 

reflect important transmission 

constraints and also do not reflect the 

primary geographic scope of current 

regional transmission planning 

processes. The DOE Needs Study 

regions more accurately reflect both 

considerations. 

Regarding the comments to treat 

MISO as one region, the DOE has 

advised that there are significant 

transmission constraints between the 

southern part of the MISO footprint and 

the central and northern parts; the DOE 

Needs Study regions track that reality. 

Accordingly, were a hydrogen producer 

located in the southern part of MISO to 

rely on EACs sourced from an electricity 

generating facility located in the 

northern part of MISO, for example, 

there is a significant risk that the 

hydrogen production would 

significantly increase induced grid 

emissions in the southern part of MISO 

that may not be offset by emissions 

reductions to the northern part of MISO. 

Regarding the comments on 

transmission planning and availability 

in the western U.S., the DOE has 

advised that the DOE Needs Study 

better reflects regions than do other 

stakeholder proposals. Use of market 

structures like the WEIS/WEIM are not 

currently recommended by the DOE 

because these boundaries are based on 

market operations—such as setting the 

wholesale price of energy production— 

that do not necessarily reflect 

transmission planning and availability. 

Furthermore, current WEIS/WEIM 

boundaries change year-to-year, with 

substantial changes also anticipated in 

the coming years based on voluntary 

utility participation decisions that are 

not centered on transmission 

availability. Although these comments 

are not adopted, the final regulations 

allow interregional delivery in certain 

circumstances, as described in § 1.45V– 

4(d)(3)(iii)(B) and part III.D.3.d.iii of this 

Summary of Comments and Explanation 

of Revisions, which should address 

some of the concerns expressed in the 

comments. 

At least one comment noted possible 

inaccuracies in the 45VH2–GREET User 

Manual map, for example, a portion of 

Florida is shown as being in the 

Southeast region and not the Florida 

region. While the map contained in the 

45VH2–GREET User Manual may be a 

useful visual guide, the table published 

in these final regulations is the 

authoritative source regarding the 

geographic regions used to determine 

satisfaction of the deliverability 

requirement. Further, the Treasury 

Department and the IRS emphasize that 

the location of an electricity generating 

source and the location of a hydrogen 

production facility is based on the 

balancing authority to which each is 

electrically interconnected (not the 

geographic location), with all but one 

balancing authority linked to a single 

region. In addition, the regions in the 

DOE Needs Study were used to derive 

the deliverability regions, but are not 

precisely those employed by these final 

regulations; the DOE Needs Study 

should therefore not be referenced for 

determining compliance with the 

deliverability requirement. 

Finally, some comments noted the 

discrepancy between the regions used in 

45VH2–GREET for the default grid 

emission factors and those proposed for 

the deliverability requirement. The 

Treasury Department and the IRS 

acknowledge that discrepancy and 

understand that the DOE is planning to 

update the default grid emissions values 

in 45VH2–GREET in the near future to 

align with the regions required for 

deliverability. 

ii. Dynamic Deliverability Regions 

Several comments offered ideas about 

dynamic deliverability rules. A few 

comments proposed using up-to-date 

locational marginal prices to infer 

deliverability and modify the 

deliverability region boundaries over 

time accordingly. One of these 

comments asked that market price 

differentials and coordination with ISOs 

and RTOs be used to create and 

administer smaller deliverability regions 

that can be adjusted over time. One 

comment requested that utilities be 

allowed to use utility-specific GHG 

emissions information as an alternative 

to the balancing authority region 

approach. One comment proposed using 

contemporaneous balancing authorities 

as the deliverability regions. Another 

comment asked for locational marginal 

emissions to be used to establish 

deliverability. Another comment 

requested that deliverability regions be 

continually updated using the ongoing 

DOE Needs Study. One comment wrote 

that deliverability region boundaries 

should account for market expansion. 

Finally, one comment requested that 

deliverability regions be regularly 


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adjusted to reflect changes in 

transmission capacity and to resolve 

conceptual differences with EU 

deliverability rules. 

The deliverability regions are defined 

in these final regulations based on the 

balancing authorities they include and 

were derived from the DOE Needs 

Study. The Treasury Department and 

the IRS recognize that it may be 

appropriate to revise these regions in 

the future. For example, the geographic 

reach of a balancing area may change, or 

transmission expansion may lead to 

fewer constraints between the current 

regions. Comments to the proposed 

regulations expressed a desire to 

understand how regional boundaries 

might change in the future. 

To allow for reasonable changes to 

geographic regions, the Treasury 

Department and the IRS, in consultation 

with the DOE, intend to revise the 

regions in future safe harbor 

administrative guidance published in 

the Internal Revenue Bulletin. Updates 

to geographic regions would occur at 

most once each year, and likely less 

frequently. The types of changes that 

could occur through future updates 

include, for example, movements of 

individual balancing authorities that 

might modestly increase or decrease the 

footprint of affected deliverability 

regions. Taxpayers could continue to 

utilize the table published in these final 

regulations, or, alternatively, taxpayers 

potentially could utilize an updated 

table provided in guidance published in 

the Internal Revenue Bulletin, subject to 

any requirements contained in such 

guidance. In the event of more 

fundamental changes to the 

deliverability regions, the Treasury 

Department and the IRS would propose 

amendments to these final regulations. 

Regarding comments to use locational 

marginal prices, the Treasury 

Department and the IRS note that 

locational marginal prices are not 

available on a nationwide basis and vary 

considerably from one year to the next— 

and even one hour to the next. Use of 

locational marginal prices would likely 

lead to incomplete and unstable region 

definitions. It is therefore unclear how 

the Treasury Department and the IRS 

could administer such a process, and 

how hydrogen producers could then use 

the resulting regions. Regarding the 

comment to use utility-specific GHG 

emissions information, a consistent 

method for how to map generator 

facilities’ emissions to the transmission 

system would be needed to implement 

this solution. While there are examples 

of this mapping in both industry 

research and practice, those methods are 

nascent and not widely applied across 

all transmission regions. Furthermore, 

the use of these techniques in 

establishing geographic boundaries for 

transmission deliverability have not 

been tested. Other comments suggesting 

various dynamic deliverability region 

benchmarks raise similar 

administrability concerns, for example, 

to automatically revise regions in 

certain circumstances (such as ISO 

expansion or publication of a new DOE 

Needs Study). For these reasons, the 

final regulations do not adopt these 

comments. To the extent needed, the 

Treasury Department and the IRS will 

announce revisions only after careful 

consideration and as informed by the 

DOE’s technical expertise, to ensure that 

such revisions are appropriately 

measuring deliverability. 

iii. Interregional Connections 

Many comments asked for means of 

satisfying the deliverability requirement 

so that certain cases where the 

electricity generator and the hydrogen 

production facility are located in 

separate deliverability regions would 

still be deemed deliverable. Some of 

these comments proposed instituting a 

process allowing individual hydrogen 

producers to make a showing of actual 

deliverability across regions, such as 

through a direct, interregional 

connection between generator and 

hydrogen production facility, generation 

that has secured ‘‘firm or non-firm 

transmission’’ or ‘‘firm transmission 

rights,’’ or that a ‘‘direct contract’’ 

between generator and hydrogen 

producer should suffice for 

deliverability. Along similar lines, 

several comments requested loosening 

the deliverability requirement such that 

EACs from electricity generators located 

in regions adjacent to the hydrogen 

producer’s region should also satisfy 

deliverability or that deliverability 

exemptions should be granted for 

projects located on the boundaries of 

deliverability regions. One comment 

wrote that deliverability rules should 

accommodate interregional transfers by 

allowing transfer of EACs between the 

deliverability regions in proportion to 

the annual, quarterly, or monthly 

capacity available on those interregional 

lines. Another comment said that a 

generator-producer pairing spanning 

multiple regions should satisfy 

deliverability when the project’s 

location reduces transmission need. 

Finally, a few comments requested that 

deliverability rules permit the use of 

EACs from outside the United States, 

with a few comments mentioning 

Canada and Mexico. 

As noted by comments, transmission 

often exists across regional boundaries. 

The DOE has advised that electricity 

trade across regions (and from Canada 

and Mexico to the United States) is 

common, with the level of trade varying 

regionally. The DOE has also advised 

that if such delivery of electricity and 

related EACs can be verified on a 

granular basis, there is no substantive 

reason to limit such transactions of 

qualified EACs. The DOE and the EPA 

have also advised that several EAC 

registries already have mechanisms to 

track near-real-time electricity and 

related EACs that cross regions and are 

using those methods to reliably track 

imports. The fact that several EAC 

registries already validate cross-border 

transactions for electricity and related 

EACs on an hourly basis demonstrates 

administrability. Other EAC registries 

may also develop the capabilities to 

validate such cross-region electricity 

and EAC transactions, in concert with 

relevant grid system operators. Finally, 

the EPA has advised that there may be 

heightened risk of double sale or use of 

otherwise qualifying EACs in cases of 

international imports from Canada and 

Mexico. 

Based on these considerations, these 

final regulations adopt the suggestions 

of many comments by amending 

proposed § 1.45V–4(d)(3)(iii) to allow an 

eligible EAC to meet the deliverability 

requirement in certain instances of 

actual cross-region delivery where the 

deliverability of such generation can be 

tracked and verified. See § 1.45V– 

4(d)(3)(iii)(B). First, such EACs will only 

qualify if the underlying electricity 

generation has transmission rights from 

the generator location to the region of 

the clean hydrogen producer and that 

generation is delivered to (that is, 

scheduled and then dispatched and 

settled in) such producer’s region. Such 

electricity delivery must be 

demonstrated on an hour-to-hour or 

more frequent basis, with no direct 

counterbalancing reverse transactions, 

and must be verified with NERC E-tags 

or the equivalent. Second, tracking of 

transmission rights and electricity 

delivery must occur via the relevant 

EAC registry; if the relevant EAC 

registry lacks this capability, such crossregion transactions are not allowed. 

Third, and finally, imports from Canada 

and Mexico must additionally include 

an attestation from the generator that the 

attributes included in the eligible EACs 

are not being used for any other 

purpose, with that attestation included 

as an attachment to the verification 

report submitted with the taxpayer’s 

return. These requirements collectively 

ensure delivery of qualifying EACs and 

electricity to the importing region, thus 


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2274 Federal Register / Vol. 90, No. 6 / Friday, January 10, 2025 / Rules and Regulations 

ensuring local displacement of other 

generation consistent with the 

producer’s load, accurate verification of 

delivery through EAC registries, and 

low risk of double counting or multiple 

use of EACs and their generation 

attributes. 

Some comments sought an 

individualized process that would allow 

hydrogen producers to make showings 

of deliverability on a case-by-case basis, 

to use transmission rights or direct 

contracts as an alternative basis for 

establishing deliverability, to use 

locational pricing differentials to 

demonstrate deliverability, or to 

demonstrate deliverability in other 

ways. Another comment suggested 

allowing delivery across regions based 

on available transmission capacity. 

Given administrability concerns, these 

final regulations do not include an 

individualized process to make a 

showing of deliverability. Additionally, 

the Treasury Department and the IRS 

note that the multiple criteria in 

§ 1.45V–4(d)(3)(iii)(B) to determine 

interregional deliverability are 

necessary to ensure that cross-region 

transactions involve the delivery of 

actual electricity and related EACs, and 

several EAC registries already employ 

such criteria to validate cross-region 

transactions. These final regulations, 

therefore, adopt the standardized 

process and interregional deliverability 

criteria in § 1.45V–4(d)(3)(iii)(B), which 

ensure delivery of electricity and EACs 

as validated by EAC registries. 

Another comment asked for 

clarification as to how electricity 

generators located in one balancing 

authority area but treated operationally 

and financially as if in a different 

balancing authority area, are treated 

under the deliverability rules. As 

described in the Explanation of 

Provisions of the proposed regulations, 

the location of an electricity generating 

source and the location of a hydrogen 

production facility are based on the 

balancing authority to which each is 

electrically interconnected (not its 

geographic location), with each 

balancing authority (except MISO) 

linked to a single region. If the 

electricity generator is electrically 

connected to the receiving region, then 

such a project would be assigned to that 

region. If not electrically connected, it 

would need to meet the interregional 

deliverability requirements. As such, if 

there is a direct, single-use connection 

(for example, a high-voltage direct 

current transmission line) between an 

electricity generator and a hydrogen 

producer’s region (or the hydrogen 

producer itself) such that the generator 

is electrically connected to the receiving 

region, then EACs reflecting the 

hydrogen production facility’s use of 

this electricity would meet the 

deliverability requirement. 

Finally, one comment opined that the 

deliverability requirement is 

counterproductive to the interregional 

transmission goals of the DOE Needs 

Study. The Treasury Department and 

the IRS disagree with this comment but 

note that the allowance for cross-region 

delivery in these final regulations 

addresses this comment. 

iv. Phase-In and Legacy Rules 

Several comments requested phase-in 

or legacy rules. Some comments 

suggested that projects beginning 

construction before 2030 should only be 

required to source EACs from within the 

same NERC region. Another comment 

proposed exempting the first 10 

gigawatts placed in service before 2031 

from the deliverability requirement. 

Another comment advocated for 

exempting all hydrogen facilities 

beginning construction before 2033 from 

the deliverability requirement. A 

comment that had proposed the use of 

tracking systems like WECC in setting 

deliverability region boundaries 

requested that, if tracking systems will 

not be used, then a transition rule 

should allow projects that have 

commercial agreements in place to 

acquire electricity from outside the 

project’s region to meet deliverability 

until 2032. As described in part III.D.3.a 

of this Summary of Comments and 

Explanation of Revisions, the three 

qualifying EAC requirements, inclusive 

of deliverability, are necessary to reduce 

the risk of induced grid emissions in 

line with the statutory lifecycle 

emissions requirement, and phase-in or 

legacy rules would increase the risk of 

such emissions. 

Several comments expressed concern 

that regional boundaries might change 

in the future and asked for rules 

allowing reliance on the deliverability 

region boundaries as they are provided 

at the time a hydrogen production 

facility is either placed in service or its 

construction begins. The Treasury 

Department and the IRS agree with the 

comments that certainty regarding 

deliverability regions is important. 

Therefore, these final regulations adopt 

the table of regions in § 1.45V– 

4(d)(2)(ix) for the duration of the section 

45V credit. If, in the future the Treasury 

Department and the IRS publish a 

revised table as a safe harbor in the 

Internal Revenue Bulletin, a clean 

hydrogen producer would be able to 

instead employ such regions 

prospectively, subject to requirements 

that may be contained in such guidance. 

Some comments sought various 

phase-in rules, whereby regions are, in 

effect, larger in the near term but 

become narrower over time. Multiple 

variants on this concept were proposed. 

These final regulations do not provide 

such a phase in. As previously 

discussed, the three qualifying EAC 

requirements, inclusive of 

deliverability, are necessary to reduce 

the risk of induced grid emissions in 

line with the statutory lifecycle 

emissions requirement. Accepting a 

phased-in approach with respect to 

deliverability would undermine this 

objective. By contrast to the temporal 

matching requirement, comments have 

not identified any technical or 

administrative reason why the 

deliverability requirement must be 

phased in. The Treasury Department 

and the IRS note, however, that several 

additional flexibilities are allowed in 

this final regulation that were not 

included in the proposed regulations, 

including allowance of interregional 

delivery and the ability to utilize the 

table of regions published in these final 

regulations over the life of the credit. 

Such additional flexibilities may 

partially ameliorate the concerns of 

some stakeholders. 

v. Other Deliverability Comments 

Finally, comments described certain 

overarching concerns with the 

deliverability requirement. One 

comment expressed concern that, since 

deliverability regions do not align with 

EAC registry boundaries, deliverability 

could be incompatible in some way 

with temporality. The Treasury 

Department and the IRS do not agree 

with this comment. EAC registries will 

need to develop new capabilities to 

fully meet the qualifying EAC 

requirements, but overlapping or 

imperfect geographic coverage of the 

EAC registries should not be an issue. 

Two EAC registries will operate outside 

of their native regions, so even if a 

specific EAC registry is not able to meet 

all the qualifying EAC requirements, 

these other EAC registries are available 

to taxpayers. 

One comment asked that projects 

drawing power from zero- or near-zero 

emissions grids be exempted from the 

deliverability requirements. Projects 

drawing power from zero- or near-zero 

emissions grids may use the grid 

average lifecycle GHG emissions rate in 

determining their section 45V credit 

eligibility and amount; the deliverability 

requirement only applies in the event 

the taxpayer is using EACs instead of 

the grid average emissions rate. If a 

taxpayer is using EACs, as described in 

part III.D.1 of this Summary of 


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Comments and Explanation of 

Revisions, the Treasury Department and 

the IRS agree with comments that 

certain states have enacted policies that 

may address the risk of induced grid 

emissions. However, these state policies 

will only satisfy the incrementality 

requirement; temporal matching and 

deliverability requirements must still be 

met. Deliverability requirements ensure 

that the electricity generation that 

creates the EACs occurs in the same grid 

region or is otherwise physically 

deliverable to the EAC buyer’s load, 

even where that generation is 

incremental or otherwise will not lead 

to induced grid emissions. Accordingly, 

these final regulations do not adopt this 

comment. 

E. Underlying Substance of 45VH2– 

GREET 

1. In General 

As described in the preamble to the 

proposed regulations, certain 

parameters in 45VH2–GREET are fixed 

assumptions, referred to as ‘‘background 

data’’ in this document. Background 

data, such as upstream methane loss 

rates, emissions associated with power 

generation from specific generator types, 

and emissions associated with regional 

electricity grids, may not be changed by 

users of 45VH2–GREET. Many 

comments either requested or 

recommended changes to certain 

background data and requested 

clarification with respect to certain 

background data parameters. 

Additionally, many comments 

recommended the inclusion of more 

background data parameters not 

currently in 45VH2–GREET. Some 

comments requested or recommended 

that certain background data parameters 

become foreground data (that is, 

parameters that must be input by the 

user), or alternatively, that all 

background data parameters become 

foreground data. 

The Treasury Department and the IRS, 

in consultation with the DOE, reaffirm 

the importance of maintaining 

parameters as background data in cases 

where idiosyncratic values are difficult 

to estimate or verify. Examples of such 

scenarios include the carbon intensity of 

specific types of electricity generation, 

such as solar, wind, or nuclear 

generation. The 45VH2–GREET 

supporting documentation clearly 

defines each type of generator currently 

represented in the model and allows for 

user inputs in scenarios where 

independent verification of such inputs 

is realistically feasible. Certain types of 

electricity generation like solar and 

wind do not have emissions within the 

well-to-gate system boundary, regardless 

of how they are operated. Such types of 

generation have been assigned a carbon 

intensity of zero within 45VH2–GREET. 

Other types of generation have non-zero 

emissions, but such emissions will not 

be transparent to a third-party verifier. 

For example, well-to-gate emissions 

from light-water nuclear reactors are 

largely due to the manner in which 

uranium is enriched and the countries 

from which it is sourced. Beyond the 

sector-wide trends already used to 

inform 45VH2–GREET, differentiation 

of such information at a facility-level 

and associated verification is likely to 

be infeasible. In other cases, traits of 

certain types of generation are likely to 

be verifiable and have therefore been 

incorporated as foreground data in 

45VH2–GREET. One example is the rate 

of CCS integrated with a natural gas 

combined cycle turbine used for power 

generation. Supporting documentation 

for 45VH2–GREET provides information 

on how this rate must be calculated, and 

all aspects of the calculation (for 

example, the amount of CO2 

sequestration reported to the EPA’s 

Greenhouse Gas Reporting Program 

(GHGRP), and the amount of CO2 

generated by the facility) are expected to 

be verifiable. If a taxpayer utilizes a 

method of electricity generation that is 

not yet represented in 45VH2–GREET, 

then such taxpayer’s pathway is not 

considered to be represented in the 

model, and the taxpayer may be eligible 

to petition the DOE for a PER (subject 

to the requirements of the PER petition 

process). 

Other than background data, aspects 

of 45VH2–GREET that users may not 

change include the calculation methods 

embedded within the model, for 

example, co-product accounting 

techniques, and assumptions of global 

warming potential that are used to 

calculate lifecycle emissions. The 

approaches for accounting used in 

45VH2–GREET are essential features 

that define the model itself; if these 

methods were subject to modifications 

by a user, different taxpayers with 

identical hydrogen production 

pathways could achieve different 

lifecycle GHG rates. Such inconsistency 

would violate fair administration of 

section 45V. Consistent with advice 

received from the DOE, the 

methodologies and assumptions 

embedded in 45VH2–GREET are 

necessary and appropriate for the 

accurate and fair administration of the 

section 45V credit. 

The Treasury Department and the IRS 

had solicited feedback on conditions, if 

any, under which the methane loss rate 

may in future releases become 

foreground data (such as certificates that 

verifiably demonstrate different 

methane loss rates for natural gas 

feedstocks). In response, one comment 

recommended the use of MiQ 

certificates, which evidence the 

emissions intensity of gas production, 

including methane loss rates. Further, 

the comment noted that the EPA also 

has methods available to assess methane 

loss rates. The DOE had previously 

indicated in the 45VH2–GREET User 

Manual that methane emissions 

monitoring and mitigation is quickly 

changing. The DOE also had 

acknowledged certain relevant EPA 

reporting requirements that could be 

helpful in mitigating methane 

emissions, alongside DOE-funded 

research on mitigation approaches, and 

together, had indicated that it expected 

the quality of upstream data to improve 

and methane emissions rates to change 

in future versions of 45VH2–GREET. 

Methane emissions that occur 

upstream of the hydrogen production 

facility can materially affect the well-togate emissions associated with hydrogen 

production. Comments have noted that 

rates of upstream methane emissions 

within distinct supply chains vary 

widely, depending on parameters such 

as mitigation measures within the basin 

that natural gas is sourced from, length 

of pipeline transmission, number of leak 

sources, and leakage rates from 

individual point sources. Comments 

also noted that because of this variation, 

the default national average leakage rate 

for natural gas contained as background 

data in 45VH2–GREET in many cases 

likely underestimates actual methane 

emissions associated with producing 

hydrogen and that the default rate 

should be updated based on improved 

science and empirical data. 

Additionally, the DOE has advised that 

supply chains and contractual 

agreements for natural gas are complex 

and varied, such that some taxpayers 

may be capable of identifying all 

upstream suppliers while others may 

not. The DOE has also advised that 

measurement, monitoring, reporting, 

and verification (MMRV) capabilities of 

upstream methane losses are rapidly 

advancing. 

The EPA’s recently updated GHGRP 

rule in 40 CFR part 98 Subpart W (89 

FR 42062, May 14, 2024) prescribes 

methods that facilities in the natural gas 

supply chain must use to account for 

their methane emissions for reporting 

under the GHGRP and ensures that the 

reporting of methane emissions to the 

GHGRP is based on empirical data and 

accurately reflects total methane 

emissions from applicable facilities, as 

required by section 136(h) of the Clean 


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2276 Federal Register / Vol. 90, No. 6 / Friday, January 10, 2025 / Rules and Regulations 

39The DOE also expects to update 45VH2–GREET 

to similarly allow differentiated reporting of other 

upstream emissions associated with the natural gas 

supply chain to the extent these are similarly 

reported in the GHGRP and verified by EPA. 

40The determination that the current Subpart W 

and section 111 rules are adequate to support 

facility-specific upstream methane leakage 

calculations is based on the following rules: 

Greenhouse Gas Reporting Rule: Revisions and 

Confidentiality Determinations for Petroleum and 

Natural Gas Systems, 89 FR 42062 (May 14, 2024), 

as corrected by 89 FR 71838 (Sept. 4, 2024); 

Standards of Performance for New, Reconstructed 

and Modified Sources and Emissions Guidelines for 

Existing Sources: Oil and Natural Gas Sector 

Climate Review, 89 FR 16820 (Mar. 8, 2024), as 

corrected by 89 FR 62872 (Aug. 1, 2024). 

Amendments to the Subpart W rule and Standards 

of Performance and Emissions Guideline rule made 

pursuant to specific grants of reconsideration 

announced for Subpart W in December 2024 and for 

the section 111 rule in May 2024, will not be 

considered a rescission or revision as described 

herein. 

Air Act. Among these recent updates to 

the GHGRP are updates to calculation 

methodologies and the addition of 

several new emissions sources, 

including one referred to as ‘‘other large 

release events,’’ to capture emission 

events that had not been accounted for 

under the prior version of the program. 

The GHGRP also collects data related to 

GHG emissions from combustion of 

natural gas under Subpart C and 

production of hydrogen under Subpart P 

of 40 CFR part 98. The EPA’s recently 

finalized regulations for methane 

emissions from the oil and gas sector 

under section 111 of the Clean Air Act, 

including the creation of the Super 

Emitter Program and its corresponding 

publication and notification 

requirements, expanded leak detection 

and repair requirements, and flare 

efficiency measurement and monitoring 

requirements, will directly inform 

methane emissions reported to the 

GHGRP under Subpart W and provide 

for improved assessments of supply 

chain methane emissions associated 

with hydrogen production. See 

Standards of Performance for New, 

Reconstructed, and Modified Sources 

and Emissions Guidelines for Existing 

Sources: Oil and Natural Gas Sector 

Climate Review, 89 FR 16820 (March 8, 

2024). 

Applicable natural gas supply chain 

facilities are required to report to the 

GHGRP under the revised Subpart W 

rules beginning in 2026 for emissions 

occurring in calendar year 2025. As 

advised by the DOE and the EPA, the 

accuracy of lifecycle GHG emissions 

rates for purposes of section 45V will 

improve once data from the updated 

GHGRP Subpart W reporting are 

available from and have been verified by 

the EPA and incorporated into the 

determination of such rates for methane. 

Once these data are available, the DOE 

will update 45VH2–GREET to allow 

differentiated methane emissions rate 

reporting, subject to the requirements 

described in the following paragraphs.39

Until 45VH2–GREET is updated to 

include user-defined emissions based 

on Subpart W reporting, the DOE has 

advised the Treasury Department and 

the IRS that it anticipates keeping the 

national average upstream methane 

emissions rate in 45VH2–GREET 

consistent with the value used in the 

initial 2023 release of the model. 

Giving taxpayers discretion to 

selectively use either the default 

national average estimate or a 

differentiated rate depending on which 

is more taxpayer favorable would 

systematically understate the actual 

upstream production and transportation 

emissions from methane used to 

produce hydrogen. Therefore, when 

45VH2–GREET is updated to enable 

input of differentiated upstream 

methane rates, it will require taxpayers 

to use data from all relevant subparts of 

GHGRP for all facilities in the taxpayer’s 

natural gas supply chain that are 

required to report under Subpart W, 

while prescribing the use of default 

segment-specific emissions rates for 

petroleum and natural gas systems not 

otherwise reporting their GHG 

emissions under the revised rules under 

the GHGRP to more accurately reflect 

leakage rates of these facilities. These 

default segment-specific emissions rates 

will be developed by the DOE and the 

EPA based on data for each segment 

reported to the GHGRP, as well as peerreviewed scientific literature. 

To ensure the accuracy and integrity 

of the information used to claim the 

section 45V credit, taxpayers must meet 

the requirements of section 45V and 

these final regulations, including the 

requirement to obtain verification from 

an accredited third-party verifier. In 

particular, consistent with § 1.45V–5(c), 

verification is required for the data the 

taxpayer enters into the 45VH2–GREET 

Model to determine the lifecycle GHG 

emissions rate, which in the case of 

differentiated methane rates must 

include identification of all facilities in 

the natural gas supply chain, 

identification of the facilities in the 

natural gas supply chain that are 

required to report to the GHGRP, 

accurate reporting of verified GHGRP 

data for these facilities, accurate 

throughput data, and appropriate 

application of any segment-specific 

default rates. 

The EPA’s revised Subpart W and 

Clean Air Act section 111 rules, 

together, are essential to the 

determination that differentiated 

upstream methane rates are appropriate 

and robust because they provide 

accurate, detailed, and particularized 

data on a facility’s natural gas supply 

chain methane emissions. To maintain 

accuracy in determining the section 45V 

credit, upstream methane emissions 

rates must be maintained as background 

data in 45VH2–GREET until the verified 

GHGRP data collected under the revised 

GHGRP rules are available. 

Additionally, if those rules are 

rescinded, or revised in a manner that 

reduces the scope, stringency, accuracy, 

or reliability of emissions reporting 

under Subpart W, Subpart C, or Subpart 

P, if the EPA does not maintain the 

current requirements of the Super 

Emitter Program or does not take 

necessary implementation steps— 

including continuing to receive data on 

super emitters from third party notifiers, 

publishing that data on the web, and 

sending notifications of super emitter 

events to responsible owners and 

operators 40—then upstream methane 

emissions rates would need to be 

maintained as background data in 

45VH2–GREET to maintain accuracy in 

determining the section 45V credit. 

As stated in the Explanation of 

Provisions to the proposed regulations, 

future versions of 45VH2–GREET may 

include additional hydrogen production 

pathways, such as geologic hydrogen, as 

sufficient technical information 

becomes available to provide consistent 

treatment in 45VH2–GREET. Numerous 

comments either requested or 

recommended that certain hydrogen 

production pathways be included in or 

excluded from future versions of 

45VH2–GREET. Similarly, many 

comments also either requested or 

recommended that future versions of 

45VH2–GREET modify existing 

feedstocks and include additional 

feedstocks and power sources for 

hydrogen production. 

The Treasury Department and the IRS 

understand, based on feedback received 

from the DOE, that some technologies 

and feedstocks were not included in the 

initial version of 45VH2–GREET 

because they required further analyses. 

The Treasury Department and the IRS 

anticipate 45VH2–GREET will be 

updated on at least an annual basis and 

that such updates are expected to 

include additional technologies and 

feedstocks. Finally, several comments 

expressed a desire for more 

transparency with respect to the initial 

development and implementation of 

45VH2–GREET, as well as future 

updates to the model, including 

requests that future updates to 45VH2– 

GREET be submitted for notice and 

comment. For purposes of determining 


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lifecycle GHG emissions as generally 

defined in section 45V(c)(1)(A), the 

Treasury Department and the IRS have 

relied extensively on the DOE, which 

has the scientific expertise necessary to 

develop GREET models, and through 

the Argonne National Laboratory 

developed 45VH2–GREET pursuant to 

section 45V(c)(1)(B). The comments’ 

request that all future updates to 

45VH2–GREET be put through notice 

and comment is not applicable to these 

final regulations, which are limited to 

focusing on the Treasury Department’s 

designation of 45VH2–GREET as the 

operative model for the purposes of the 

section 45V credit. The Treasury 

Department and the IRS have shared 

these comments with the DOE to 

determine the best way to address 

comments related to future updates to 

45VH2–GREET. 

2. Valorized Co-Products 

As noted in the Explanation of 

Provisions to the proposed regulations, 

45VH2—GREET allows users to input 

the quantity of valorized co-products 

(that is, co-products from the hydrogen 

production process that are separately 

productively utilized or sold) and 

allocate emissions to those co-products 

(rather than to the hydrogen 

production). The Explanation of 

Provisions to the proposed regulations 

also described that 45VH2–GREET 

utilizes the ‘‘system expansion’’ 

approach for all co-products, if possible, 

but restricts the amount of steam coproducts that producers can claim based 

on the quantity of steam that an 

optimally designed reformer is expected 

to be capable of producing according to 

modeling from the National Energy 

Technology Laboratory (NETL). 

The Treasury Department and the IRS 

had solicited feedback on this approach, 

including whether alternative 

conventions for co-product accounting, 

such as physical allocation or allocation 

based on other characteristics, would 

better ensure that well-to-gate carbon 

intensity of hydrogen production is 

robustly represented. Comments 

received in response to this request 

were generally supportive of the 

restriction on steam co-products 

described above. Some comments, 

however, expressed concern that 

45VH2–GREET fails to account for 

steam co-products if a reformer is 

capturing and sequestering the CO2 it 

produces. 

The DOE has advised that steam coproducts were not represented for 

reformers with CCS in the initial release 

of 45VH2–GREET because the model 

did not yet represent CCS technologies 

wherein steam co-products were 

feasible. The DOE has advised that 

cryogenic CCS technologies have been 

included in the forthcoming January 

2025 release of 45VH2–GREET, and that 

steam co-products can be represented 

from reformers with cryogenic CCS. The 

DOE intends to continue to expand 

45VH2–GREET with additional CCS 

technologies, and to allow for steam coproducts to be represented if it is 

feasible with such technologies. 

However, 45VH2–GREET will not allow 

reformers (with or without CCS) 

claiming steam co-products to claim coproducts in excess of 17.6 percent of the 

total energy content of all steam and 

hydrogen produced (using the lower 

heating value of hydrogen). This limit of 

17.6 percent is based on independent 

modeling of optimally designed 

reformers from the NETL and is 

described further in the 45VH2–GREET 

User Manual. 

Additionally, the DOE has advised 

that system expansion may not be an 

appropriate accounting approach for all 

co-products that may be produced at 

hydrogen production facilities, and that 

physical allocation should be utilized 

where system expansion is 

inappropriate. Specifically, system 

expansion may be inappropriate if it 

yields artificially low lifecycle GHG 

emission values for hydrogen in 

scenarios that include but are not 

limited to scenarios where incumbent 

methods of co-product generation have 

highly variable or uncertain lifecycle 

GHG emission values or scenarios 

where the market for the co-product is 

sufficiently small that the magnitude of 

the co-product generated by hydrogen 

producers is likely to expand the market 

size of the co-product rather than 

displacing an incumbent technology. 

Therefore, in scenarios wherein system 

expansion may not be appropriate, 

45VH2–GREET will utilize physical 

allocation. 

As previously noted, 45VH2–GREET 

allows users to allocate emissions to coproducts, rather than to the hydrogen 

production. The DOE has also advised 

that a co-product under 45VH2–GREET 

does not include a gas or output that is 

not separate from (that is, is mixed in 

with) the hydrogen gas stream, even if 

the mixed gas is valorized as part of the 

stream. Nor does it include an output 

that has been separated from a hydrogen 

gas stream if the taxpayer or a customer 

downstream of the taxpayer will later 

mix such output back into the hydrogen 

gas stream. In such cases, the user must 

evaluate the emissions of the hydrogen 

production process before the output 

was separated out, and account for the 

output as a mixed gas or impurity. 

An example where output may not be 

treated as a co-product is the scenario 

where a taxpayer uses natural gas to 

produce a hydrogen gas stream that 

includes carbon monoxide, and 

separates the carbon monoxide from the 

hydrogen gas stream. The taxpayer sells 

the carbon monoxide to Customer A, 

sells the hydrogen to Customer B, and 

intends to account for the carbon 

monoxide in 45VH2–GREET as a coproduct. Later, Customer A sells the 

carbon monoxide to Customer B, and 

Customer B combines such carbon 

monoxide with the hydrogen to produce 

methanol. Because the carbon monoxide 

will be reintroduced to the hydrogen 

after it is separated, the carbon 

monoxide may not be treated as a coproduct. 

F. Non-Zero-Emitting Sources of 

Electricity 

In the Explanation of Provisions to the 

proposed regulations, the Treasury 

Department and the IRS requested 

comments with respect to sources of 

electricity other than zero GHG-emitting 

electricity, including minimal-emitting 

and non-minimal-emitting sources. The 

Treasury Department and the IRS 

received comments in support of the use 

of such sources, many of which 

proposed extensive verification 

requirements. On the other hand, one 

comment stated that the final 

regulations should require that minimalemitting electricity generating facilities 

submit a full lifecycle analysis before 

any EACs with respect to such facilities 

are allowed to be issued to hydrogen 

producers because the qualifying EAC 

requirements generally are not reflected 

in the attributes of the EACs of such 

facilities. In consultation with the DOE, 

the Treasury Department and the IRS 

intend to allow the use of EACs with 

respect to sources of electricity other 

than zero GHG-emitting electricity. 

Hydrogen produced using minimalemitting electricity sources may qualify 

for the section 45V credit if the lifecycle 

GHG emissions rate of the process by 

which the hydrogen was produced 

satisfies statutory requirements. 

Moreover, the Treasury Department and 

the IRS intend for the EAC framework 

and the qualifying EAC requirements 

that apply to these electricity sources to 

provide one framework for the 

determination of when electricity from 

a specific electricity generating facility 

can be taken into account for purposes 

of 45VH2–GREET or a PER. These final 

regulations amend the definition of 

‘‘eligible EAC’’ in § 1.45V–4(d)(2)(iii) to 

require attributes that are required by 

45VH2–GREET or in the determination 

of a PER to accurately reflect the 


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emissions associated with the source of 

electricity. 

In addition, the Treasury Department 

and the IRS, in consultation with the 

DOE, note that 45VH2–GREET currently 

includes certain minimal-emitting 

electricity source options, including 

allowing hydrogen production facilities 

to account for electricity generation 

using CCS, and it may include 

additional minimal-generating options 

in the future. These final regulations 

also include requirements limiting 

when carbon capture may be taken into 

account, which are discussed in part 

III.G of this Summary of Comments and 

Explanation of Revisions. Hydrogen 

production facilities using types of 

electricity generation not represented in 

45VH2–GREET will be eligible to 

submit petitions for PERs. To the extent 

that a non-zero, minimal-emitting 

electricity source is used to power 

hydrogen production, the direct and 

significant indirect emissions from the 

minimal-emitting source of electricity 

must be reflected in 45VH2–GREET or 

as part of an Emissions Value Request 

Application. Foreground data 

parameters relevant to electricity 

sources (for example, the amount of 

CCS) must be verified by a third-party 

verifier. The Treasury Department and 

the IRS expect that verifiers will 

develop tools to verify the feedstock 

sources and related energy attributes 

represented by the EACs. 

G. Carbon Capture and Sequestration 

Hydrogen production facilities may 

employ carbon capture equipment and 

engage in CCS. Several comments 

stressed the importance of verification 

of carbon capture rates reported by 

hydrogen producers claiming the 

section 45V credit. One comment asked 

that requirements for the verification of 

CO2 capture rates and the permanence 

of CO2 sequestration be as rigorous as 

those of the California Air Resource 

Board’s (CARB) Carbon Capture and 

Sequestration Protocol for the CA LCFS. 

Another comment requested (1) that 

verification requirements for carbon 

oxide transport, permanent storage or 

use, or monitoring under section 45V be 

at least as stringent as those under 

section 45Q; (2) that proof of at least 

three years of injection site monitoring 

by an independent geologist or 

petroleum engineer should be required 

in the case of CO2 sequestered or used 

for enhanced oil recovery; and (3) that 

the final regulations include provisions 

specifying proper verification of carbon 

management, including sequestration 

and prevention of CO2 leaks, and also 

include a clawback mechanism in the 

case of CO2 leaks. In cases where 

electricity, fuel, or a feedstock is used to 

produce hydrogen, the issue of carbon 

capture rate verification also arises if the 

source of electricity, fuel, or feedstock is 

engaged in CCS. Thus, in response to 

these comments, the final regulations 

add § 1.45V–4(e), which provides that 

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 

CCS 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, 

pursuant to section 45Q(f)(2) and any 

regulations established thereunder, 

disposed of in secure geological storage, 

or utilized in a manner described in 

section 45Q(f)(5) and any regulations 

established thereunder. Such CCS 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. Any CCS that does 

not meet such section 45Q requirements 

will appropriately be considered to be 

emissions from the production of 

hydrogen within the well-to-gate system 

boundary and be attributed to the 

lifecycle GHG emissions of such 

hydrogen. Because CCS rates are 

reported and verified on an annual basis 

for purposes of section 45Q or reporting 

under the EPA’s GHGRP program, the 

annual average CCS rate at a given 

electricity generating plant can be 

applied to any EACs that are sourced 

from that generating resource when it is 

represented in 45VH2–GREET or an 

Emissions Value Request Application. 

Power sourced from facilities with CCS 

must meet all other requirements for 

qualifying EACs in these final 

regulations. 

In addition, the Treasury Department 

and the IRS note that the amount of CO2 

sequestered by an electricity source 

generator or by a hydrogen production 

facility using carbon capture equipment 

is foreground data within 45VH2– 

GREET and therefore also is subject to 

third-party verification. 

H. Use of Natural Gas Alternatives 

The Treasury Department and the IRS 

announced in the preamble to the 

proposed regulations an intent to 

provide final regulations addressing 

hydrogen production pathways that use 

biogas, renewable natural gas (RNG), 

and fugitive sources of methane 

(collectively, natural gas alternatives), 

for purposes of the section 45V credit. 

The assessment of lifecycle GHG 

emissions with respect to such natural 

gas alternatives presents a complex set 

of technical questions. Thus, the 

preamble to the proposed regulations 

described various rules related to the 

use of natural gas alternatives in the 

production of hydrogen that the 

Treasury Department and the IRS were 

considering for inclusion in these final 

regulations. The preamble to the 

proposed regulations also included 

detailed comment requests about 

various aspects of the use of natural gas 

alternatives to inform the development 

of these final regulations. After careful 

consideration of the numerous 

comments submitted in response to 

these proposals and the proposed 

regulations’ specific requests for 

comment, the final regulations provide 

rules in § 1.45V–4(f) related to the use 

of natural gas alternatives in the 

production of hydrogen and the 

assessment of lifecycle GHG emissions 

with respect to natural gas alternatives. 

As further described in part III.H.2.c of 

this Summary of Comments and 

Explanation of Revisions, rather than 

provide rules that would specify a 

single, generic alternative fate for all 

natural gas alternatives (for example, 

capture and flaring), the Treasury 

Department and the IRS have, in 

consultation with interagency technical 

experts from the DOE and the EPA, 

considered the technical characteristics 

of types of sources of natural gas 

alternatives and sought to apply the 

approach most appropriate for each type 

of source to provide an administrable 

and robust alternative fate for each 

sector. 

1. Definitions 

a. Alternative Fate 

The preamble to the proposed 

regulations asked for comments on what 

counterfactual assumptions and data 

should be used to assess the lifecycle 

GHG emissions of hydrogen production 

pathways that rely on natural gas 

alternatives. The preamble to the 

proposed regulations did not offer a 

definition of the term ‘‘counterfactual,’’ 

which is referred to in these final 

regulations as an ‘‘alternative fate.’’ In 

the interest of completeness and clarity, 

§ 1.45V–4(f)(2)(i) clarifies that the term 

‘‘alternative fate’’ means a set of 

informed assumptions (for example, 

production processes, material 

outcomes, and market-mediated effects) 


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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). 

b. Biogas 

The preamble to the proposed 

regulations noted that the term biogas 

means ‘‘gas resulting from the 

decomposition of organic matter under 

anaerobic conditions, and the principal 

constituent is methane (50–75 

percent).’’ Some comments noted that 

biogas may contain a percentage of 

methane that is outside of the range 

noted in the proposed regulations. In 

order to be inclusive of all gases that 

may be considered biogas, § 1.45V– 

4(f)(2)(ii) does not specify a range of 

percentages of methane that a gas must 

contain to be considered biogas. These 

final regulations define biogas as gas 

containing methane that results from the 

decomposition of organic matter under 

anaerobic conditions. 

c. Coal Mine Methane 

The preamble to the proposed 

regulations did not offer a definition of 

the term ‘‘coal mine methane,’’ but, in 

the interest of completeness and clarity, 

§ 1.45V–4(f)(2)(iii) clarifies that 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. 

For the purpose of these regulations, the 

term coal mine methane does not 

include methane removed from virgin 

coal seams (for example, coal bed 

methane). 

d. Fugitive Methane 

The preamble to the proposed 

regulations would have defined the term 

‘‘fugitive methane’’ to mean the release 

of methane through, for example, 

equipment leaks, or venting during the 

extraction, processing, transformation, 

and delivery of fossil fuels to the point 

of final use, such as coal mine methane. 

Comments did not recommend 

alternatives to this definition. The 

proposed definition is adopted in these 

final regulations without substantive 

change in § 1.45V–4(f)(2)(iv). One 

comment asserted that the proposed 

definition creates a distorted baseline 

assumption that methane would have 

been leaked or vented, such that the 

captured methane could improperly be 

assessed as having negative lifecycle 

GHG emissions. The Treasury 

Department and IRS understand this 

concern and note that the baseline and 

alternative fates relevant to certain 

sources of fugitive methane are further 

discussed at part III.H.2.c of this 

Summary of Comments and Explanation 

of Revisions. 

e. Renewable Natural Gas 

The preamble to the proposed 

regulations would have defined the term 

‘‘renewable natural gas’’ (RNG) to mean 

‘‘biogas that has been upgraded to be 

equivalent in nature to fossil natural 

gas.’’ One comment asserted that the 

term ‘‘renewable natural gas’’ is 

misleading and should be replaced with 

the term ‘‘biomethane.’’ This comment 

noted that referring to biomethane as a 

‘‘renewable’’ resource falsely implies 

that it is easily replaced although 

biomethane is scarce and its supplies 

are often depleted upon use. Although 

the Treasury Department and the IRS 

recognize these concerns, § 1.45V– 

4(f)(2)(iv) does not adopt the suggested 

change in terminology because the term 

‘‘renewable natural gas’’ is sufficiently 

clear, is a commonly used term in other 

regulatory programs and in commerce, 

and is unlikely to result in confusion. 

The term ‘‘renewable natural gas’’ and 

its proposed definition is therefore 

adopted without substantive change. 

2. Considerations Regarding the 

Lifecycle GHG Emissions Associated 

With the Production of Hydrogen Using 

Methane From Natural Gas Alternatives 

The preamble to the proposed 

regulations explained that the rules 

provided in the final regulations 

regarding natural gas alternatives would 

apply to all natural gas alternatives used 

for purposes of the section 45V credit 

and would provide conditions that must 

be met before certificates for natural gas 

alternatives (that is, representations of 

the energy and emissions attributes of 

the methane) and the attributes they are 

meant to represent may be taken into 

account in determining lifecycle GHG 

emissions rates for purposes of the 

section 45V credit. The preamble to the 

proposed regulations indicated that 

such conditions would be logically 

consistent with, but not identical to, the 

incrementality, temporal matching, and 

deliverability requirements for 

electricity-derived EACs, in that the 

conditions would be designed to reflect 

the ways in which additional demand 

for natural gas alternatives can impact 

lifecycle GHG emissions and also to 

address the differences between 

electricity and methane, including, but 

not limited to, the different sources of 

emissions, markets, infrastructure, 

available tracking and verification 

methods, and potential for perverse 

incentives. 

The preamble to the proposed 

regulations described and requested 

comment on several provisions the 

Treasury Department and the IRS were 

considering adopting in the final 

regulations to address the risk of 

significant indirect emissions and 

induced emissions from the use of 

natural gas alternatives in the 

production of hydrogen. This risk of 

significant indirect emissions and 

induced emissions can arise when 

natural gas alternatives are diverted 

from another productive use. In these 

situations, such productive uses may be 

backfilled with a different source that is 

not a natural gas alternative, such as 

fossil natural gas, which could result in 

associated emissions. For example, a 

facility that previously used its biogas 

for heat and power generation may opt 

to import grid electricity and/or fossil 

natural gas to satisfy its on-site energy 

needs. There is also a risk of significant 

indirect emissions or induced emissions 

or inappropriate claims of the section 

45V credit with respect to hydrogen that 

does not meet statutory emissions 

requirements, if the incentives provided 

by the section 45V credit result in the 

creation of new or expanded methane or 

other GHG sources that would not have 

existed otherwise, or additional 

methane that would not have been 

created or would have remained 

sequestered, which could increase 

lifecycle GHG emissions. By reference to 

section 211(o)(1)(H) of the Clean Air 

Act, section 45V(c)(1)(A) requires 

consideration of direct and significant 

indirect emissions. 

a. Lifecycle GHG Emissions Associated 

With the Use of Natural Gas 

Alternatives 

The accurate assessment of lifecycle 

GHG emissions is vital to determining 

both eligibility for and the amount of 

the section 45V credit. Lifecycle GHG 

emissions assessments that 

underestimate the emissions associated 

with different hydrogen production 

pathways would mean that the section 

45V credit could be claimed even if 

lifecycle GHG emissions in fact exceed 

the statutory eligibility threshold or 

credit tier thresholds established by 

Congress. In order to ensure that 

hydrogen producers claiming the 

section 45V credit are using processes 

with lifecycle GHG emissions that do 

not exceed the statutorily prescribed 

eligibility threshold or credit tier 

thresholds, the final regulations 

necessarily include certain guardrails to 

address the risk of such credit claims. 


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The preamble to the proposed 

regulations requested comments on the 

lifecycle analysis considerations for 

methane derived from natural gas 

alternatives. To account for direct and 

significant indirect emissions, these 

considerations include, among other 

things, appropriate alternative fate 

scenarios and the assessment of current 

feedstock management practices. The 

preamble to the proposed regulations 

noted that the requested comments may 

inform future versions of the 45VH2– 

GREET model. After consideration of 

the comments received, the final 

regulations address certain aspects of 

the lifecycle GHG emissions analysis for 

natural gas alternatives used in the 

production of hydrogen. Parts III.H.2.b. 

and c. of this Summary of Comments 

and Explanation of Revisions address 

first productive use and general 

alternative fate assumptions ranging 

from venting to responsible avoidance 

of methane. 

The Treasury Department and the IRS 

agree with comments that assert that 

accurately estimating lifecycle GHG 

emissions rates for processes that rely 

on methane from natural gas 

alternatives to produce hydrogen 

requires taking a wide range of factors 

into account in establishing the 

alternative fate against which the use of 

methane to produce hydrogen should be 

assessed. Section 45V(c)(1)(A) requires 

any lifecycle GHG emissions analysis 

under section 45V to address direct and 

significant indirect emissions associated 

with the use of methane for the 

production of hydrogen, including 

emissions resulting from the diversion 

of methane from a prior alternative 

productive use or from the expansion of 

existing sources or creation of new 

sources of natural gas alternatives. 

b. First Productive Use 

The preamble to the proposed 

regulations provided notice that the 

Treasury Department and the IRS 

intended to require that, for natural gas 

alternatives to receive an emissions 

value consistent with that gas (and not 

fossil natural gas), the natural gas 

alternative used during the hydrogen 

production process must originate from 

the first productive use of the relevant 

methane. The preamble to the proposed 

regulations further noted that for any 

specific source, productive use would 

generally be defined as any valuable 

application of the relevant methane (for 

example, providing heat or cooling, 

generating electricity, or upgrading to 

RNG). In addition, the preamble noted 

that productive use would specifically 

exclude venting to the atmosphere or 

capture and flaring. The preamble 

further proposed to define ‘‘first 

productive use’’ as the time when a 

producer of the relevant methane first 

begins using or selling it for productive 

use in the same taxable year as (or after) 

the relevant hydrogen production 

facility was placed in service. Under 

this proposal, RNG produced from any 

source of methane, where the methane 

had been productively used in a taxable 

year prior to the taxable year in which 

the relevant hydrogen production 

facility was placed in service, would not 

have received an emission value 

consistent with biogas-based RNG, for 

example, but would instead have 

received a value consistent with fossil 

natural gas. This proposal was intended 

to address emissions associated with the 

diversion of natural gas alternatives 

from other productive uses and the risk 

of emissions associated with creation of 

new or expansion of existing sources of 

natural gas alternatives. 

The preamble to the proposed 

regulations noted that, for existing 

biogas or fugitive methane sources that 

typically productively use or sell a 

portion of the biogas and flare or vent 

the remainder, the flared or vented 

portion may be eligible for first 

productive use as described earlier if the 

flaring or venting volume can be 

adequately demonstrated and verified. 

The Treasury Department and the IRS 

requested comment on these and other 

potential conditions on the use of 

natural gas alternatives in the 

production of hydrogen. 

After full consideration of the 

comments and as further explained in 

this part III.H.2.b. of the Summary of 

Comments and Explanation of 

Revisions, these final regulations do not 

impose a first productive use 

requirement. Although a first productive 

use requirement could effectively 

address important considerations in the 

determination of a lifecycle GHG 

emissions rate, the Treasury Department 

and the IRS acknowledge that the 

requirement may be difficult for 

taxpayers to substantiate and to verify 

independently. Establishing compliance 

with a first productive use requirement 

could involve obtaining detailed, often 

unavailable, historical documentation of 

the operations of the methane source, 

including historical production levels, 

material changes in waste source 

composition and volume, use of capture 

equipment and capture rates, sales or 

uses of captured methane, and waste 

management practices. Moreover, 

challenges in the administration of a 

first productive use requirement raise 

questions about the practical ability of 

a first productive use requirement to 

address the risk of direct or significant 

indirect emissions effectively. Instead of 

a first productive use requirement, for 

determining emission rates associated 

with the use of methane from natural 

gas alternatives, the more appropriate 

approach is to take the likelihood of 

alternative productive use into account 

in assessing the alternative fate of such 

gas, as discussed in part III.H.2.c. of this 

Summary of Comments and Explanation 

of Revisions. 

The Treasury Department and the IRS 

received many comments addressing the 

first productive use requirement. Many 

comments questioned the legal and 

technical basis of a first productive use 

requirement. Several comments asserted 

that a first productive use requirement 

is not authorized by statute, overly 

restricts otherwise eligible biogas and 

RNG feedstocks that could support 

clean hydrogen production and ignores 

the fact that there are numerous reasons 

an existing biogas facility may switch 

productive uses, including, but not 

limited to, the expiration of existing 

contracts, like power purchase 

agreements. Other comments asserted 

that there is no evidence that RNG-tohydrogen pathways will result in the 

induced emissions that appear to 

underlie the first productive use 

requirement and that such emissions are 

not included in the 45VH2–GREET 

model, which the comments asserted is 

the only basis allowed for assessing 

lifecycle GHG emissions. 

One comment contended that 

industry data suggests that domestic 

production of biogas and RNG can 

support both new hydrogen production 

and current end uses like compressed 

natural gas (CNG) transportation 

vehicles; thus, within the timeframe that 

section 45V credit will be available, 

there is ample capacity to serve demand 

in many sectors, without causing 

induced emissions. Similarly, several 

comments stated that much of the RNG 

produced in the United States is used in 

the transportation sector for compliance 

with the RFS and/or State clean fuel 

programs like the CA LCFS. These 

comments explain that since these 

programs drive deployment of a specific 

amount of compliant fuels, if an existing 

RNG supplier leaves these 

transportation markets to supply RNG as 

a feedstock to a new hydrogen 

production facility, the prior end use of 

such RNG will be backfilled with other 

compliant fuels (for example, those that 

meet the RFS’s GHG requirements). 

In response to these comments, the 

Treasury Department and the IRS 

acknowledge that these existing 

transportation fuel programs, chiefly the 

RFS and the CA LCFS, have been the 

primary drivers for deployment of RNG 


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domestically. The Treasury Department 

and the IRS agree that the existence of 

these programs mitigates the risk that 

RNG currently produced for such 

programs will be redirected to hydrogen 

production, although there could be 

incentives for such use if any such 

hydrogen could itself qualify to claim 

credits under these programs. Despite 

this, there still remains a risk that RNG 

(or biogas) could be redirected to 

hydrogen production from other current 

uses, such as heat and power 

generation. Additionally, because RNG 

currently comprises the vast majority of 

cellulosic biofuel credits generated 

under the RFS program, it is not 

necessarily the case that RNG 

previously used in this program would 

be backfilled with other compliant fuels 

should insufficient RNG be available for 

use as U.S. transportation fuel. As 

discussed previously, however, these 

final regulations do not impose a first 

productive use requirement at this time, 

but instead take an alternate approach to 

addressing these concerns. 

One comment suggested that the 

Treasury Department could adopt a 

mid-program ‘‘check-in’’ to evaluate 

whether clean hydrogen produced using 

RNG is leading to unintended increases 

in emissions. Facilities that have 

achieved commercial operation during 

this period could qualify as 

‘‘additional’’ for purposes of tax credit 

eligibility. Moreover, any biogas sources 

that are newly converted from 

electricity generation to RNG 

production should be credit-eligible 

regardless of whether the agency adopts 

the proposed ‘‘first productive use’’ 

requirement. Several comments 

suggested that a robust assessment of 

any induced emissions associated with 

redirecting RNG from its prior use to 

hydrogen production would 

demonstrate that such consideration 

would not result in an increase in the 

emissions rate and, therefore, such 

emissions need not be considered due to 

the speculative nature of the initial 

premise. Some comments noted that a 

potential alternative would be to add an 

indirect emission charge equal to the 

emissions associated with the 

extraction, processing, and delivery of 

fossil natural gas to backfill the prior 

demand for such gas. Another comment 

stated that while the intent of the first 

productive use requirement is logical, it 

would be more efficient and cost 

effective to assign production values to 

the RNG inputs used in hydrogen 

production because this would allow 

hydrogen producers to factor output 

costs given the RNG feedstocks used to 

create the hydrogen they offer to the 

marketplace. Several comments stated 

that fugitive methane should not be 

considered incremental if such methane 

comes from the fossil fuel system, as 

this is already accounted for under the 

current GREET model. 

In response to these comments, the 

Treasury Department and the IRS 

acknowledge that the first productive 

use requirement, which is not required 

as part of these final regulations due to 

the difficulties in proving and verifying 

first productive use, would address two 

aspects of lifecycle GHG emissions 

assessments, both of which must be 

considered under section 45V(c)(1)(A). 

First, a first productive use requirement 

would mitigate the risk of emissions 

associated with the diversion of natural 

gas alternatives from a productive use 

other than the production of hydrogen. 

Although methane from natural gas 

alternatives could be used for different 

productive uses, the potential emissions 

associated with changes in use are 

nonetheless relevant in the 

determination of a lifecycle GHG 

emissions rate. Second, a first 

productive use requirement aids in the 

determination of the appropriate 

alternative fate of natural gas 

alternatives used in the production of 

hydrogen. Comments questioning a first 

productive use requirement because of a 

lack of evidence of induced emissions 

arising from shifts in behavior due to 

the availability of the section 45V credit 

are not dispositive. Section 45V(c)(1)(A) 

does not require empirical evidence of 

direct and significant indirect emissions 

associated with a newly available 

incentive like the section 45V credit 

before the likelihood of such emissions 

may be considered, and such a 

restriction would systematically 

underestimate such emissions. As 

further explained below, it is necessary 

for a lifecycle GHG emissions 

assessment that is consistent with the 

statutory definition of lifecycle 

emissions in 45V(c)(1)(A) to reflect the 

emissions effects that can be reasonably 

expected to occur based on current or 

future market trends and drivers, 

inclusive of incentives and regulation. 

Some comments suggested that a first 

productive use requirement should not 

be imposed for purposes of the section 

45V credit because there already exist 

established frameworks for other 

incentive programs involving methane 

from natural gas alternatives, which 

may be relied upon to determine 

lifecycle GHG emissions. One comment 

stated that producers should be allowed 

to use the emissions data collection 

methods and book-and-claim framework 

that have been established under the 

RFS program to incorporate Renewable 

Identification Numbers (RINs) in the 

natural gas supply chain and 

demonstrate CO2 reduction. Another 

comment asserted that the first 

productive use rule must be eliminated 

because RNG is already regulated under 

the RFS program, which should 

continue to serve as the regulatory 

authority for RNG. In response to these 

comments, the Treasury Department 

and the IRS note that the RFS program 

does not regulate the use of RNG. 

Rather, the RFS program allows RNG 

used as transportation fuel to generate 

RINs under certain conditions. The 

Treasury Department and the IRS 

acknowledge that programs such as the 

RFS program have considered and 

established frameworks for addressing 

issues relevant to the implementation of 

section 45V, but section 45V has its own 

statutory requirements that diverge from 

those of other programs. 

Key distinguishing features include 

the structures of these incentive 

programs, which influence how 

lifecycle analysis is conducted. The RFS 

program, for example, determines credit 

values based on whether a given 

renewable fuel achieves a threshold 

reduction of GHG emissions relative to 

petroleum, where the threshold is 

defined by the statute that enacted the 

RFS program. For this reason, the RFS 

program is not designed to estimate 

specific lifecycle GHG emissions values, 

which is statutorily required to 

determine eligibility for and the amount 

of the section 45V credit. In addition, 

section 45V requires that emissions be 

accounted for on a well-to-gate basis 

(versus the well-to-wheel basis for the 

RFS program), and the statute does not 

permit accounting for the emissions of 

the fuel being displaced by hydrogen 

use. These final regulations, therefore, 

do not adopt any of those frameworks 

for other incentive programs involving 

methane. 

Many comments raised concerns 

about the effect a first productive use 

requirement would have on deployment 

of hydrogen production technologies 

that rely on natural gas alternatives and 

suggested it could also have other 

undesirable effects on the market for 

certain methane sources. Several 

comments suggested the first productive 

use rule limits RNG pathways by 

creating a de facto strict additionality 

requirement that is even more onerous 

than that proposed for electricity and 

EACs. Several comments suggested the 

first productive use rule should be 

eliminated to incentivize raw biogas to 

be upgraded to RNG, which ensures that 

harmful air pollutants are not released 

into the atmosphere by burning raw 

biogas (as in electricity production from 


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biogas, for example). Another comment 

argued a first productive use 

requirement is not feasible because RNG 

is delivered through national and 

interstate common carrier pipelines 

from multiple sources. One comment 

stated that the first productive use 

requirement is overly burdensome and 

will unnecessarily restrict opportunities 

to decarbonize hydrogen production as 

well as curtail methane abatement at 

scale. Several comments contended that 

the proposed ‘‘first productive use’’ 

requirement would cause a significant 

value discrepancy for new projects 

creating a market distortion, greater risk 

of stranded gas for existing projects, 

added complexity, and higher prices for 

end-consumers. Several comments 

cautioned that adding a first productive 

use rule creates potential unintended 

consequences of RNG plants sitting idle 

if hydrogen production facilities do not 

coincide with the RNG plant completion 

dates. One comment noted that one 

possible scenario is if a hydrogen 

production facility is initially 

conservatively sized and cannot use the 

full amount of RNG being produced at 

a specific project until a later date, the 

excess RNG would either sit idle so as 

to not trigger a first productive use or 

would have to enter less lucrative 

markets, which could put the project in 

jeopardy. Another comment stated that 

there are limited options for large-scale 

RNG production in certain areas and 

that requiring a hydrogen production 

facility to be the first productive use of 

a RNG facility, and have a pipeline 

connection, presents a significant 

logistical barrier to the development of 

a clean hydrogen project in certain 

areas. One comment asserted that the 

proposed first productive use 

requirement would effectively prevent 

section 45V credit eligibility for 

hydrogen projects using RNG. The 

comment noted that even if a project 

uses RNG in a low- to no-carbon way, 

if that RNG was previously used 

productively or sold at any time, the 

proposed rules imply that it could not 

be used in a project that would result in 

a lower carbon intensity. 

Assuming the implementation of the 

first productive use requirement, many 

comments requested modifications, 

changes to, or transitional relief to the 

first productive use requirement 

outlined in the preamble to the 

proposed regulations. One comment 

suggested that the first productive use 

rule may be overly restrictive and that 

it could be beneficial to relax the first 

productive use requirement, so long as 

the new use of the RNG delivers overall 

lower net emissions than its original 

fate. Another comment suggested that if 

the first productive use requirement is 

not eliminated, then a legacy reliance 

rule and a transitional period through 

2032 should be included in these final 

regulations. Several comments 

suggested there should be no 

restrictions on RNG; however, if the first 

productive use rule is implemented, 

then it should apply a look-back period 

of 36 months, not by taxable year but by 

when the hydrogen is produced. 

Another comment argued that there 

should not be a default fossil-based 

carbon intensity score for RNG that had 

been productively used before being 

used to produce hydrogen because 

doing so fails to recognize the carbon 

intensity reduction benefit of RNG 

compared to fossil natural gas that is 

realized regardless of whether the 

methane was previously captured and 

used at the project host. One comment 

requested that ‘‘first productive use’’ be 

defined as RNG that is produced based 

on an offtake agreement signed within 

48 months of the beginning of hydrogen 

production, rather than within the same 

or later taxable year as the relevant 

hydrogen production facility’s placed in 

service date. Several comments stated 

the first productive use requirement 

should be eliminated as it relates to the 

production of clean hydrogen with coal 

mine methane. Several comments 

supported that each individual borehole 

for coal mine methane be seen as 

additional and as a first productive use 

of supply due to each of them being a 

unique investment decision requiring 

incremental capital expenditure to 

mitigate leaking methane. Several 

comments stated that the definition of 

first productive use was unclear, and 

that the definition should focus on 

ensuring that RNG used for hydrogen is 

not displacing a previous productive 

use. One comment argued that ‘‘lowcarbon’’ gas should also qualify as first 

productive use if it is from additional 

methane abatement, even if it is 

conditioned at a pre-existing facility. In 

other words, any gas from newly 

constructed capture infrastructure for 

fugitive methane, a newly covered 

lagoon, newly constructed digester, or 

newly contracted feedstock source for 

RNG production should count as first 

productive use, since these are all 

individual investment decisions that 

lead to incremental methane abatement. 

One comment asserted that the presence 

or use of flaring in appropriate 

circumstances (for example, safety or 

compliance with State or local 

regulations) should not disqualify a 

facility from eligibility, especially in 

light of the fact that commercial 

operations must comply with 

mandatory but potentially conflicting 

Federal, State, and local regulatory 

requirements. Several comments 

recommended that if the first productive 

use requirement is adopted, the final 

regulations should allow existing gas 

sources to qualify through 2030 to 

ensure adequate supply. These 

comments further noted that after 2030 

any induced emissions that occurred 

could be quantified and, if applicable, 

included in the lifecycle GHG emissions 

assessment of existing low-carbon gas 

facilities, as opposed to being grounds 

for disqualification from the section 45V 

credit. A comment asserted that if the 

first productive use requirement is 

adopted, it must be applied to each 

methane source—that is, at the digester 

or lagoon-level for RNG and boreholelevel for coal mine methane—so as to 

reflect how investment decisions are 

made. Once a low-carbon gas source is 

accepted as meeting a first productive 

use requirement (if adopted) under the 

program, it should not be exclusively 

tied to a particular hydrogen production 

facility, according to the comments. 

As explained in part III.H.2.c. of this 

Summary of Comments and Explanation 

of Revisions, these final regulations are 

taking into account the lack of a first 

productive use requirement in the 

development of alternative fates for 

certain sources of natural gas 

alternative, so modifications, changes 

to, and transitional relief are not 

necessary. The Treasury Department 

and the IRS will continue to consider 

these recommendations raised by these 

comments in evaluating whether 

imposing a first productive use 

requirement, with potential 

modifications, may be appropriate in 

future guidance under section 45V. 

Many comments supported imposing 

a first productive use requirement. One 

comment stated that the proposed first 

productive use rule would help direct 

biomethane that is otherwise vented (or, 

in some cases, flared) to hydrogen 

production, rather than creating an 

additional demand for methane by 

taking from other sources that may meet 

that demand through dirtier sources of 

energy. According to the comment, a 

first productive use requirement is 

important to avoid significant indirect 

emissions associated with hydrogen 

produced from biomethane. The 

comment noted that avoiding significant 

indirect emissions is especially 

important for agricultural methane 

emissions, which have risen over the 

last few decades despite overall declines 

in national methane emissions. Several 

comments supported the proposed 

regulations and argued that enforcing 


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the first productive use rule and 

narrowly tailoring the definition of first 

productive use are critical to prevent the 

significant amount of RNG production 

today shifting to producing ostensibly 

clean hydrogen. The comments posited 

that diversion of currently produced 

and used RNG to hydrogen production 

would be backfilled with fossil natural 

gas and contended this is especially true 

for existing RNG heat applications and 

CNG powered vehicles. Thus, any 

existing RNG diverted to hydrogen 

production would be filled on a one-forone basis with fossil natural gas. One 

comment stated that the proposed rule 

requiring the first productive use be 

matched to the same taxable year as (or 

after) the hydrogen production facility is 

placed in service would help to limit 

any diversion of biogas or RNG from 

other pre-existing uses, which might 

otherwise increase overall emissions. 

One comment stated that the first 

productive use rule is logically 

consistent with incrementality 

requirements imposed for EACs 

representing electricity generation to be 

considered qualifying. Several 

comments supported prohibiting 

crediting of biomethane or fugitive 

methane that has previously been put to 

productive use and stated that a first 

productive use requirement would 

ensure emissions reductions claimed 

under section 45V are indeed additional 

to the climate system overall. The 

Treasury Department and the IRS agree 

with many of the observations made in 

these comments. While these final 

regulations do not adopt a first 

productive use requirement for the 

reasons stated earlier in this Summary 

of Comments and Explanation of 

Revisions, the Treasury Department and 

the IRS have considered these 

observations regarding alternative 

productive use of natural gas 

alternatives when establishing the 

alternative fates. 

c. Alternative Fates 

These final regulations establish 

general requirements for lifecycle GHG 

emissions determinations for processes 

that use methane derived from natural 

gas alternatives to produce hydrogen, 

requiring such determinations to 

consider the alternative fates of that 

methane, including avoided emissions 

and alternative productive uses of that 

methane, the risk that the availability of 

section 45V credits creates incentives to 

produce 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. The emissions risks that would 

have been addressed by a first 

productive use requirement are 

addressed in the development of the 

appropriate alternative fates for certain 

sources of natural gas alternatives, 

thereby reflecting an accurate 

assessment of lifecycle GHG emissions 

pursuant to section 45V(c)(1)(A). The 

factors considered in establishing the 

appropriate alternative fate are 

interrelated and must account for other 

aspects of these final regulations. For 

example, because these final regulations 

do not impose a first productive use 

requirement, there may be a greater 

likelihood that the appropriate 

alternative fate for certain sources of 

natural gas alternatives should be 

productive use. 

As discussed previously, analytical 

decisions regarding the alternative fate 

of natural gas alternatives are critical in 

the assessment of their carbon intensity. 

Comments suggested a range of broadly 

applicable alternative fate assumptions 

for methane from natural gas 

alternatives used in hydrogen 

production. Recommendations included 

venting, flaring, productive use, and 

responsible avoidance of waste-streamgenerated methane. 

Rather than adopting a single 

alternative fate for all natural gas 

alternatives, these final regulations 

instead address specific considerations 

for each major source of natural gas 

alternatives. This part III.H.2.c of this 

Summary of Comments and Explanation 

of Revisions addresses comments 

recommending broadly applicable 

alternative fates, while comments 

addressing alternative fates for specific 

sources of methane are discussed in 

parts III.H.2.c.i through vi of this 

Summary of Comments and Explanation 

of Revisions. 

Comments supported and opposed a 

venting alternative fate (that is, 

assuming the methane in question 

would have been released directly to the 

atmosphere rather than flared or 

productively used) for a range of 

reasons. One comment recommended 

that avoided emissions crediting should 

be allowable for fugitive methane 

feedstocks. The comment stated that, in 

most instances, alternative fates are not 

necessary as these are not hypothetical 

emissions, but measurable real-world 

fugitives and valuing abatement is 

straightforward. The comment posited 

that if a base case is needed, it should 

be venting or uncontrolled release of 

100 percent of the methane potential of 

the feedstock to the atmosphere. Several 

comments recommended that 

biomethane should not receive a 

negative carbon intensity score by 

claiming a ‘‘business-as-usual case’’ of 

venting methane. The comments 

suggested that, at the most generous, 

this methane should be considered to be 

captured and flared, which would make 

the use of this methane for hydrogen 

production—with the waste stream of 

carbon dioxide—receive at best a carbon 

intensity score of zero. One comment 

stated that there is ample evidence that 

pre-IRA policies already support the 

capture of vented methane where 

possible, for both RNG and fossil gas, 

and that remaining methane emissions 

are likely to be mitigated even in the 

absence of hydrogen projects supported 

by the section 45V credit. The comment 

further suggested that allowance of 

venting as an alternative fate for the 

purposes of calculating net hydrogen 

carbon intensity would incentivize 

hydrogen producers to claim offsets 

based on an inaccurate assumed 

alternative fate against real emissions 

from production and upstream methane 

leakage in order to establish eligibility 

for the most generous section 45V credit 

tier. As a result, the comment 

recommended that requiring flaring be 

used as the baseline condition for all 

pathways including RNG is a simple 

way to prevent crediting of pathways 

with GHG reductions based on 

unrealistic alternative fate scenarios. 

Several comments stated that venting is 

not an appropriate alternative fate 

assumption for biomethane because it is 

an irresponsible practice and would 

result in the greatest credit value with 

respect to gas producers who are 

investing the least in the environmental 

quality and emissions reduction 

technologies at their facilities. Several 

comments stated that lifecycle analysis 

should be used to compare the overall 

environmental impacts of using biogas 

and fugitive emissions for hydrogen 

production versus current flaring 

practices; alternative fates assumptions 

should be updated to reflect the given 

tax year’s regulatory requirements so, 

for example, if venting is prohibited, 

then it is no longer a valid alternative 

fate scenario. 

A number of comments recommended 

that capture and flaring would be an 

appropriate alternative fate for certain 

sources of natural gas alternatives, such 

as methane from landfills and 

wastewater treatment plants. 

Several comments suggested using 

conservative assumptions, alternative 

fates and formulas, and allowing 

taxpayers to propose and prove 

alternatives. Many comments requested 

the adoption of conservative approaches 

to determining alternative fates. Several 

comments recommended that any 

methane that can be captured should, at 


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41LMOP Landfill and Project Database, U.S. 

Environmental Protection Agency, available at 

https://www.epa.gov/lmop/lmop-landfill-andproject-database (last updated Sept. 20, 2024). 42 Id. 43AgSTAR Data and Trends, Biogas Data and 

Trends, U.S. Environmental Protection Agency, 

available at https://www.epa.gov/agstar/agstardata-and-trends#biogasfacts (last updated Nov. 27, 

2024). 44 Id. 45 Id. 

minimum, be assigned a baseline 

alternative fate of being captured and 

flared. One reason provided by the 

comments was that flaring appropriately 

reflects a consistent treatment of 

pollution sources, recognizing the cost 

of methane pollution and thus the need 

for methane abatement. 

In response to these comments, the 

Treasury Department and the IRS agree 

that venting is not an appropriate 

alternative fate to apply across all 

sources of natural gas alternatives, 

because it does not account for the 

prevalence of flaring and productive 

use, nor does it address the risk of 

induced emissions due to the incentives 

provided by the section 45V credit. The 

Treasury Department and the IRS also 

anticipate that a venting baseline would 

become increasingly inappropriate over 

time, due to anticipated changes in 

regulations and operational practices. 

The section 45V credit is in effect for 

facilities beginning construction 

through 2032 and remains available for 

a 10-year period after the hydrogen 

production facility is originally placed 

in service. The final regulations also 

generally allow taxpayers to rely for the 

duration of a hydrogen production 

facility’s 10-year credit period on the 

version of the 45VH2–GREET model 

that is available on the date the facility 

began construction, as is further 

discussed in part III.B of the Summary 

of Comments and Explanation of 

Revisions. Therefore, the final 

regulations provide that the lifecycle 

GHG emissions rate of a process (as 

defined in § 1.45V–1(a)(11)) that uses 

methane derived from biogas, RNG, or 

coal mine methane as a feedstock 

molecule to produce hydrogen, must 

take into account anticipated changes in 

waste disposal practices or use of that 

methane over the relevant timeframe. 

In the case of venting, the Treasury 

Department and the IRS expect venting 

prohibitions to expand in future years, 

as local, State, and Federal policy 

restrictions on venting are becoming 

increasingly common. 

While the policy landscape for 

specific methane sources is discussed in 

parts III.H.2.c.i. through vi. of this 

Summary of Comments and Explanation 

of Revisions, a range of current and 

prospective State policies limiting 

venting of different RNG sources or 

encouraging more responsible methane 

management practices indicates the 

trajectory of State action in this area. For 

example, California, Colorado, 

Maryland, Michigan, Oregon, and 

Washington have all recently taken or 

imminently plan to take action to 

restrict venting and require more 

responsible methane management 

practices, in some cases beyond the 

Federal standards currently in place. 

As discussed in more detail regarding 

the specific sources of natural gas 

alternatives, there are also significant 

voluntary Federal incentives to 

encourage responsible methane 

management practices. There is also 

evidence of ongoing growth in methane 

capture through proliferation of landfill 

gas capture and anaerobic digesters. For 

example, as shown in updated project 

database files from EPA’s Landfill 

Methane Outreach Program (LMOP), as 

of September 2024 there were 1,245 

landfills with operational gas collection 

and control systems, as compared to 

1,187 in 2014.41 Additionally, LMOP 

data shows growth in the number of 

landfill gas energy projects upgrading 

landfill gas to RNG. As of September 

2024, there are 110 operational RNG 

projects (as compared to 63 projects in 

2019) and 102 planned or under 

construction.42 In addition, as 

subsequently discussed in this 

Summary of Comments and Explanation 

of Revisions, there has been rapid 

growth in the construction of animal 

waste digesters, largely as a result of 

policy incentives, with data from 

AgSTAR showing an additional 172 

operational anaerobic digesters 

accepting livestock manure in 2024 

relative to 2019 (267 digesters).43

AgSTAR data also demonstrates rapid 

growth in RNG projects (including 

pipeline injection and CNG for vehicle 

fuel or other uses), with 191 RNG 

projects in 2024 compared to 32 in 

2019, and only 8 in 2017.44 As of 2023, 

CNG has surpassed Combined Heat and 

Power (CHP) as the most common end 

use of biogas from manure-based 

anaerobic digestion systems in 

AgSTAR.45 In light of all these trends, 

a methane venting baseline across all 

natural gas alternatives is inaccurate 

today, and, over time, the assumptions 

and inputs will likely become 

increasingly erroneous as regulations, 

markets, and resource management 

practices evolve during the period over 

which the section 45V credit is 

available. This supports the use of 

reasonably conservative alternative fates 

in the face of uncertainty to provide 

greater assurance that statutory 

emissions thresholds provided in 

section 45V(b)(2) will not be exceeded, 

as described in more detail 

subsequently in this Summary of 

Comments and Explanation of 

Revisions. 

The Treasury Department and the IRS 

also agree that conservative approaches 

to assessing alternative fates of natural 

gas alternatives may be an appropriate 

response to challenges in documenting 

and verifying alternative fates 

applicable to specific sources of natural 

gas alternatives in order to better ensure 

compliance with the statutory emissions 

thresholds in section 45V. However, 

such conservative approaches should 

consider the distinct characteristics of 

each source or type of source, to the 

extent reasonably practicable. Thus, 

although a capturing and flaring 

alternative fate may be generally 

appropriate for some categories of 

sources of natural gas alternatives, it is 

not appropriate for all sources of natural 

gas alternatives. 

Some comments suggested that the 

alternative fate assumption for all 

methane derived from waste streams 

should be alternative productive use. 

One comment recommended that an 

alternative fate approach should address 

the risk of indirect emissions by taking 

into account the alternative fate and the 

emissions associated with replacing this 

fate. The comment further suggested 

that if the hydrogen producer has data 

and evidence of the alternative fate, for 

example from the RNG supplier, this 

should always be used in the first 

instance, in preference to a market or 

average assumption provided by the 

DOE. In addition, the comment stated 

that venting may be the appropriate 

alternative fate in some instances, but 

that it is unlikely to be the appropriate 

primary alternative fate due to the 

adverse effects RNG venting has on the 

climate. The Treasury Department and 

the IRS note that the recommendations 

in these comments would significantly 

increase the complexity in estimating 

lifecycle GHG emissions associated with 

the use of natural gas alternatives in the 

production of hydrogen. Permitting 

taxpayers to apply bespoke alternative 

fates for each source of natural gas 

alternative would increase the burden 

on taxpayers and on tax administration 

because substantiation and verification 

of such bespoke alternative fates would 

be challenging. As further explained 

later in this Summary of Comments and 

Explanation of Revisions, the significant 

and in some cases growing rates of 

productive use of methane from certain 

waste streams is an important 

consideration in establishing alternative 

fate assumptions for estimating lifecycle 


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GHG emissions rates. Because not all 

methane from waste streams is used 

productively, however, the comment’s 

suggested assumption that the 

alternative fate assumption for all 

methane derived from waste streams 

should be alternative productive use 

would understate the potential 

emissions benefits of using such gas in 

hydrogen production. The final 

regulations, therefore, do not adopt 

these comments. 

Some comments suggested that the 

alternative fate assumption for all waste 

stream-generated methane should be 

responsible avoidance of such methane 

production by applying practices that 

minimize its production. These 

comments highlighted the risk that 

incentives created by the section 45V 

credit would lead to the production of 

more, new methane than would have 

otherwise occurred. The Treasury 

Department and the IRS agree that this 

is an important consideration. 

For new methane that would not have 

been produced in the absence of the 

section 45V credit, use of such methane 

for hydrogen production must not be 

reflected as avoided methane emissions 

in the lifecycle GHG emissions 

assessment. For certain waste streams, 

the volumes of waste-stream-generated 

methane produced by a certain practice 

can be affected by operator actions, such 

as a change in manure management 

practices from land disposal to lagoon 

disposal, or heating an anaerobic 

digester to increase the amount of 

methane produced. Moreover, in some 

cases, the cost of generating additional 

methane may be small compared to the 

value of the section 45V credit. Several 

comments asserted that fugitive 

methane and methane from animal 

lagoon-based manure are both examples 

of avoidable waste streams that exist 

solely because of discretionary industry 

practices; as a result, these comments 

asserted that methane streams are 

always GHG positive. Comments 

asserted that treating this methane 

consistent with fossil natural gas is a 

generous approach because biomethane 

production is associated with higher 

methane leakage rates. One comment 

stated that allowing previously flared or 

vented biogas to be considered as 

‘‘incremental’’ as a first productive use 

also brings significant emissions risks 

by encouraging the expansion of 

facilities’ waste methane streams over 

prior years to qualify that methane 

waste for hydrogen production in the 

future. The comment argued that for 

landfill gas, considering an ‘‘above 

average’’ approach for incrementality 

when considering a facility that has no 

established energy project could be one 

way of encouraging investment in 

greater capture rates. 

As these comments note, the 

availability of the section 45V credit 

may lead to generation of methane in 

the form of natural gas alternatives for 

the purpose of producing qualified 

clean hydrogen that is eligible for the 

section 45V credit. In those instances, 

the appropriate alternative fate is that 

the methane generated from waste 

streams, or increments of it, would not 

have been created in the first place or 

that it would have remained 

sequestered. In such scenarios, it would 

be inappropriate to credit hydrogen 

production with avoided emissions 

because the analysis must address 

methane leakage and combustion 

emissions that otherwise would not 

have occurred, and crediting these 

scenarios with avoided emissions would 

likely result in providing a section 45V 

credit for the production of hydrogen 

that is ineligible for the credit based on 

the statutory emissions requirements. 

This is a particularly important 

consideration for certain types of 

methane-producing practices and 

materials and for determining the 

appropriateness of alternative fates that 

can result in highly negative lifecycle 

GHG emissions rate estimates if 

emissions from additional methane 

generation are not accounted for, which 

would create potentially large 

incentives for additional waste 

production (potentially resulting in 

highly inaccurate lifecycle emissions 

assessments). 

In light of the substantial venting and 

flaring of methane that currently occurs, 

an alternative fate of avoidance would 

in many instances understate the 

emissions benefits of capturing such gas 

and using it to produce hydrogen. In 

order to meet statutory requirements, 

however, incentives for methane 

creation must be considered in the 

determination of a lifecycle GHG 

emissions rate. 

It is not possible for the Treasury 

Department and the IRS to ascertain 

which specific waste-stream-generated 

methane would not exist absent the 

incentives provided by section 45V 

credit, nor is it possible to precisely 

estimate the market-mediated emissions 

of such an incentive effect. In order to 

ensure that these emissions are not 

merely ignored, which would not be 

permissible under the statute, and also 

that the approach is both administrable 

and appropriate, after consultation with 

the DOE, these final regulations take the 

economic incentives for additional 

waste production into account in 

establishing the alternative fates that 

apply in general to particular 

feedstocks. Specifically, in settings 

where a significant but non-identifiable 

share of methane from some sources 

could be produced in response to 

incentives provided by the section 45V 

credit or other programs, alternative fate 

assumptions that result in highly 

negative emissions estimates are likely 

to be inaccurate and understate the realworld lifecycle GHG emissions. These 

final regulations require that 

determinations of alternative fates for 

methane derived from biogas, RNG, or 

fugitive methane consider the risk that 

the availability of tax credits creates 

incentives to produce additional 

methane. 

i. Alternative Fate Considerations for 

Methane From Certain Waste Streams 

Informed by the considerations 

discussed earlier, § 1.45V–4(f)(3)(ii) 

through (vi) specifically addresses the 

alternative fate considerations for 

methane from landfill sources, 

wastewater, coal mine methane, animal 

waste sources, and fugitive methane 

other than coal mine methane. The 

following parts of this Summary of 

Comments and Explanation of Revisions 

address these specific types of sources 

of natural gas alternatives in further 

detail. These final regulations have 

developed alternative fates on a sectorby-sector basis because determining and 

validating alternative fates on an entityby-entity basis would not be 

administrable. As discussed earlier, 

identifying an appropriate alternative 

fate for specific sources of natural gas 

alternatives would depend not only on 

the specific facts and circumstances (for 

example, whether methane from the 

source was already being productively 

used), but would also require an entityby-entity assessment of the applicability 

of alternative fate scenarios with many 

complex factors potentially relevant to 

that assessment (for example, financial 

incentives absent the section 45V credit, 

regulatory considerations, or trends in 

waste management or disposal 

practices). It would be highly 

burdensome for taxpayers to 

demonstrate, and impractical to confirm 

as a matter of tax administration, that a 

specific methane source had certain 

historic practices and whether in the 

future that source would have had a 

certain disposition of relevant materials 

other than the one that actually 

occurred. Quantities of methane from an 

individual source could even have 

different alternative fates. For example, 

assuming a situation where, absent tax 

incentives, a source capturing and using 

methane would have produced a lesser 

amount of methane and vented it, the 

alternative fate for that amount of 


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2286 Federal Register / Vol. 90, No. 6 / Friday, January 10, 2025 / Rules and Regulations 

46U.S. Environmental Protection Agency, 

Inventory of U.S. Greenhouse Gas Emissions and 

Sinks: 1990–2022 (2024), at 725, available at https:// 

www.epa.gov/system/files/documents/2024-04/usghg-inventory-2024-main-text_04-18-2024.pdf. 47Non-regulatory Public Docket: Municipal Solid 

Waste Landfills, U.S. Environmental Protection 

Agency, available at https://www.epa.gov/ 

stationary-sources-air-pollution/non-regulatorypublic-docket-municipal-solid-waste-landfills (last 

updated Dec. 9, 2024); Press Release, The White 

House, Fact Sheet: Biden-Harris Administration 

Announces New Actions to Detect and Reduce 

Climate Super Pollutants (Jul. 23, 2024), available 

at https://www.whitehouse.gov/briefing-room/ 

statements-releases/2024/07/23/fact-sheet-bidenharris-administration-announces-new-actions-todetect-and-reduce-climate-super-pollutants; Keaton 

Peters, Is the EPA About to get Serious About 

Methane Pollution from Landfills?, Canary Media 

(Jul. 10, 2024), available at https://

www.canarymedia.com/articles/methane/is-theepa-about-to-get-serious-about-methane-pollutionfrom-landfills. 

48Reconsideration of Standards of Performance 

and Emissions Guidelines for Municipal Solid 

Waste Landfills (RIN 2060–AU24) available at 

https://www.reginfo.gov/public/do/ 

eAgendaViewRule?pubId=202404&RIN=2060- 

AU24. 

49U.S. Environmental Protection Agency, Final 

Updates to Performance Standards for New, 

Modified and Reconstructed Landfills, and Updated 

to Emission Guidelines for Existing Landfills: Fact 

Sheet (Sept. 2016), available at https://

www.epa.gov/sites/default/files/2016-09/ 

documents/landfills-final-nsps-eg-factsheet.pdf. 

methane (venting) would differ 

dramatically from the alternative fate of 

the additional methane produced due to 

the tax incentive (no methane produced 

or emitted). Moreover, these 

administrative challenges are even 

greater for situations where hydrogen 

producers are seeking to use a book-andclaim system to assign attributes to 

natural gas alternatives purchased from 

an intermediary, such as a common 

carrier pipeline. In such situations, 

book-and-claim registries would in 

theory need to verify and track not only 

the type of natural gas alternative source 

but also any additional information 

relevant to assessing the alternative fate 

of the methane from the specific source. 

Given these significant administrative 

challenges, the alternative fates are 

assessed and applied on a sector-bysector basis in these final regulations. 

ii. Alternative Fate Considerations for 

Methane from Landfill Gas 

The preamble to the proposed 

regulations recognized a pathway 

within 45VH2–GREET for determining a 

lifecycle GHG emissions rate using an 

alternative fate of flaring for the 

production of hydrogen using RNG 

derived from landfill gas. The final 

regulations continue to recognize a 

hydrogen production pathway in 

45VH2–GREET that applies an 

alternative fate of flaring in assessing 

the use of RNG produced from landfill 

gas in the production of hydrogen. 

A number of comments highlighted 

competing considerations in 

determining the appropriate alternative 

fate for methane from landfill gas. One 

comment stated that venting is the 

correct alternative fate for landfill gas in 

some instances, such as jurisdictions 

without flaring regulations in place. 

Several comments recommended 

conservative default parameters paired 

with alternative fate assumptions that 

would reflect a high potential of leakage 

at landfills, given that landfills can 

generate super-emitting plumes and 

studies suggest collection efficiency can 

be overestimated. Several comments 

noted the 45VH2–GREET model 

properly includes avoided emissions 

with respect to landfill gas. The 

comments state that the RNG industry 

supports and agrees that any 

methodology assessing RNG’s lifecycle 

emissions must measure avoided 

emissions. Several comments proposed 

that for purposes of calculating the 

emissions rate for RNG from municipal 

solid waste landfills, the 45VH2–GREET 

model must utilize the correct and latest 

scientific data from the EPA, which the 

comment asserted shows the national 

average landfill methane capture rate is 

39 percent. However, the EPA data for 

2022 shows significantly higher 

methane recovery rates.46 Moreover, 

regulations increasingly require flaring 

of landfill gas, and, as discussed 

previously, anticipated changes in 

regulatory requirements and operational 

practice are an important consideration 

in determining appropriate alternative 

fates. 

The EPA currently regulates 

emissions (in the form of landfill gas 

using non-methane organic compound 

(NMOC) emissions as a surrogate) from 

landfills under section 111 of the Clean 

Air Act. EPA regulations under the 

Solid Waste Disposal Act (commonly 

known as the Resource Conservation 

and Recovery Act, or RCRA) mandate 

certain landfill management practices 

that also affect methane emissions from 

landfills. As noted elsewhere in this 

Summary of Comments and Explanation 

of Revisions, several States have 

adopted additional more stringent 

requirements for landfill methane 

emissions. The EPA has also announced 

that it intends to update and strengthen 

its existing landfill regulations under 

section 111 of the Clean Air Act in 

2025.47 The current rules for landfill gas 

emissions were finalized in 2016. 

Pursuant to the EPA’s regulatory plan, 

the EPA plans to revisit the rule to 

understand how new technologies and 

approaches could be incorporated into 

updated New Source Performance 

Standards (NSPS) and Emissions 

Guidelines to reduce emissions from 

municipal solid waste landfills and to 

protect the environment and the health 

of people that live nearby.48

In particular, certain landfills are 

subject to NSPS (40 CFR part 60, 

subpart XXX) and Emissions Guidelines 

(40 CFR part 60, subpart Cf) under 

section 111 of the Clean Air Act 

(collectively, NSPS/EG Rules). The 

listed regulated pollutant under these 

regulations is ‘‘landfill gas.’’ The EPA 

has also promulgated National 

Emissions Standards for Hazardous Air 

Pollutants (40 CFR part 63, subpart 

AAAA) in 2020 that regulate the 

emissions of Hazardous Air Pollutants 

(HAP) from landfills. The NESHAP 

regulates HAP emissions by requiring 

landfills that exceed the size and NMOC 

emission thresholds to install and 

operate a landfill gas collection and 

control system (GCCS). As in the NSPS/ 

EG, the GCCS is required to include a 

control device capable of reducing 

NMOC emissions by 98 percent. This 

system will also reduce emissions of 

methane since methane makes up 

approximately 50 percent of the landfill 

gas. 

The EPA’s current Clean Air Act 

section 111 NSPS provide emissions 

control requirements for new (since 

2014) municipal solid waste landfills. 

See 40 CFR part 60 subpart WWW and 

subpart XXX. The section 111 emissions 

guidelines (EG) cover existing (pre2014) municipal solid waste landfills 

through requirements that are adopted 

by States through State plans, or by the 

EPA in the event a State does not submit 

an approvable plan. See 40 CFR part 60 

subpart Cf. Both new and existing 

landfills that exceed specified size and 

emissions thresholds must install 

landfill gas GCCS and use, sell, or flare 

(combust) the gas. The EPA estimated 

that 846 landfills would be required to 

collect and control landfill gas under 

these regulations by 2025.49 In addition, 

landfills covered by these regulations 

and that have GCCS installed must 

conduct quarterly surface monitoring for 

leaks. In the States with more stringent 

State requirements, the requirements 

commonly apply to smaller landfills, 

landfills with lower emissions levels, 

and/or apply more stringent emissions 

control measures compared to the 

Federal requirements. A number of 

other landfills that are not subject to 

emissions control regulations 

nevertheless have installed landfill 

GCCS and are either flaring, combusting 

the gas for energy generation, or 

upgrading it and injecting it in the 


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Federal Register / Vol. 90, No. 6 / Friday, January 10, 2025 / Rules and Regulations 2287 

50 Landfill Methane Outreach Program (LMOP), 

U.S. Environmental Protection Agency, available at 

https://www.epa.gov/lmop (last updated Dec. 5, 

2024). 

51 In addition to upcoming EPA regulations, 

additional states are also contemplating regulations. 

See, for example, Landfill Methane Reductions in 

Colorado, Colorado Department of Public Health 

and Environment, available at https://

cdphe.colorado.gov/landfill-methane-reductions-incolorado; New York Department of Environmental 

Conservation et al., Methane Reduction Plan (May 

2017), available at https://extapps.dec.ny.gov/docs/ 

administration_pdf/mrpfinal.pdf. 

pipeline system for sale.50 The LMOP 

tracks voluntary GCCS installation 

based on available data reported by 

program partners. As of 2024, at least 

450 landfills operate a GCCS without 

being required by regulation. Many of 

the landfills that are not currently 

regulated or voluntarily collecting gas 

may be required to collect and control 

landfill gas emissions during the 

timeframe in which the section 45V 

credit is available, as additional 

regulation is expected at both the 

Federal and State level.51

Given that landfill gas collection and 

use or flaring is widespread, as it is 

required by regulation for an increasing 

number of landfills and often supported 

by GHG credit programs when not 

required, an assumption that absent the 

section 45V credit the typical practice 

would be uncontrolled venting is not 

supportable. Although landfill gas is 

increasingly put to productive use, and 

there are some landfills where capture 

and flaring or productive use is not yet 

occurring, since collection and flaring is 

required by law for the largest sources 

of landfill gas and is increasingly being 

required for smaller sources as well, 

collection and flaring is the most 

appropriate alternative fate assumption 

for the sector as a whole given its 

prevalence. Although a flaring 

alternative fate will result in an 

underestimate of lifecycle GHG 

emissions for landfills with current 

productive use, the fact that there are 

some landfills where capture and flaring 

or productive use is not yet occurring, 

in combination with the prevalence of 

flaring, makes a flaring alternative fate 

the most robust approach for the sector 

as a whole. Based on all the 

considerations noted previously, 

§ 1.45V–4(f)(3)(ii) of the final 

regulations provides that, for purposes 

of determining the lifecycle greenhouse 

gas emissions rate of a process (as 

defined § 1.45V–1(a)(11)) that uses 

methane derived from landfill sources, 

flaring of such gas using an efficiency 

determined in 45VH2–GREET must be 

used as the alternative fate. Flaring 

efficiency is specified as background 

data in 45VH2–GREET because bespoke 

values are likely to be unavailable or 

inaccurate, since it is not common 

practice to measure the flare gas 

chemical composition or to have 

continuous monitoring of flares at 

landfills. 

iii. Alternative Fate Considerations for 

Methane From Wastewater 

The proposed regulations did not 

recognize a pathway for determining a 

lifecycle GHG emissions rate for the 

production of hydrogen using methane 

produced from wastewater, but the 

preamble to the proposed regulations 

sought comment on the treatment of 

various sources of RNG. These final 

regulations support providing a 

pathway in 45VH2–GREET to determine 

the lifecycle GHG emissions rate for the 

production of hydrogen that applies a 

flaring alternative fate for biogas and 

related RNG from wastewater sources in 

concert with default wastewater 

treatment practices defined in the 

forthcoming, January 2025 version of 

45VH2–GREET and described in this 

part III.H.2.c.ii of these Summary of 

Comments and Explanation of 

Revisions. 

Several comments stated that it would 

be incorrect to presume that most 

wastewater treatment plants have 

operational biogas/anaerobic digester 

systems and that operational biogas 

systems are flaring their gas. At least 

one comment asserted that, based on the 

American Biogas Council’s database of 

wastewater facilities maintained under a 

memorandum of understanding with the 

Water Environment Federation, the vast 

majority of operational digester systems 

at wastewater plants are using such 

biogas to produce renewable electricity, 

RNG, or heat, which, according to the 

comment, offsets fossil fuel use and its 

related emissions. Another comment 

opposed a venting baseline for instances 

like wastewater treatment on the basis 

there is no administrable system that 

credibly enables producers to 

distinguish the gas that would be vented 

if not for the existence of the section 

45V credit. 

National-level data on anaerobic 

digestion at wastewater treatment plants 

and the use of biogas produced is 

limited. There are more than 16,000 

wastewater treatment plants in the U.S. 

While most wastewater treatment plants 

in the U.S. serve small populations and 

do not process sufficiently large 

wastewater flows to justify the 

installation of anaerobic digesters, 

which are capital-intensive, anaerobic 

digesters are very prevalent among the 

smaller number of large wastewater 

treatment facilities that process the large 

majority of wastewater: the largest 8 

percent of facilities (1,132 facilities that 

each handle greater than 5 million 

gallons per day) process 77 percent of 

total national wastewater flow, 

according to Argonne National 

Laboratory. Among the 1,100 generally 

large wastewater treatment plants that 

have anaerobic digesters, 860 have the 

equipment to use their biogas on site, 

according to the DOE’s Alternative 

Fuels Data Center. Additionally, nearly 

all biogas-producing wastewater 

treatment plants surveyed in 2018 

reported flaring at least some of their 

biogas, based on the Nationwide Survey 

of WRRF Biosolids Programs released in 

2022. Venting practices are not reported 

in any national datasets, although vents 

are required to prevent 

overpressurization events in biogas 

storage systems and local regulators may 

require facilities to track and report 

venting events. Some facilities combust 

biogas to heat their digesters and some 

also take advantage of the additional 

heat availability for use in on-site 

biosolids drying. 

Given that use or flaring of methane 

from wastewater is generally applied to 

the majority of wastewater generated 

domestically, an assumption that absent 

the section 45V credit the typical 

practice would be uncontrolled venting 

is not supportable. Section 1.45V– 

4(f)(3)(i) of the final regulations 

therefore provides that, for purposes of 

determining the lifecycle greenhouse 

gas 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. 

For the large majority of biogas from 

wastewater treatment plants, this is 

either consistent with current practice, 

or modestly overestimates avoided 

emissions in cases where the portion of 

biogas not needed to satisfy on-site heat 

requirements would otherwise have 

been productively used. Although a 

flaring alternative fate for this additional 

biogas will result in an over-estimate of 

avoided lifecycle GHG emissions for 

wastewater treatment plans with current 

productive use beyond satisfying on-site 

heat demands, this potential 

overestimation of GHG emissions 

avoidance is counterbalanced by the 

existence of wastewater treatment plants 

where capture and flaring or productive 

use is not yet occurring, thus making 

default wastewater treatment practices 

the most appropriate approach for the 

sector as a whole. 


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2288 Federal Register / Vol. 90, No. 6 / Friday, January 10, 2025 / Rules and Regulations 

52Active underground mines that liberate more 

than 36,500,000 actual cubic feet of methane per 

year report annually to GHGRP on whether their 

drainage gas is vented or destroyed. 

iv. Alternative Fate Considerations for 

Coal Mine Methane 

The proposed regulations did not 

recognize a pathway within 45VH2– 

GREET for determining lifecycle GHG 

emissions rates for the production of 

hydrogen using coal mine methane 

(CMM), but the preamble to the 

proposed regulations invited comment 

on the treatment of various sources of 

fugitive methane. The final regulations 

support providing a pathway in 45VH2– 

GREET to determine the lifecycle GHG 

emissions rate for the production of 

hydrogen that applies a flaring 

alternative fate for CMM. 

The Treasury Department and the IRS 

recognize that fossil sources of fugitive 

methane can be utilized for hydrogen 

production. Many comments 

specifically noted the feasibility of 

transforming CMM into hydrogen and 

identified venting as a common 

alternative fate. One comment noted 

concerns associated with allowing for 

the use of fugitive methane from sources 

such as coal mines until robust lifecycle 

analysis, verifiability, incrementality, 

and other principles related to the 

emissions impacts of this gas are 

demonstrated. 

The DOE has advised that drainage 

gas is the subset of CMM that can be 

used for hydrogen production, due to its 

high methane content. Drainage systems 

are a mechanism of recovering methane 

from underground mines to maintain 

safe operating conditions.52 These 

systems are typically installed when 

ventilation systems are insufficient to 

maintain underground methane 

concentrations within permissible 

limits. Unlike drainage gas, ventilation 

gas is typically dilute in methane 

content and therefore cannot be used for 

hydrogen production. 

Based on consultation with the DOE 

and the EPA, the Treasury Department 

and the IRS understand that the EPA’s 

GHGRP is the only national public 

database with historical information 

provided annually by large active 

underground mines regarding their 

treatment of drainage gas. Review of 

data submitted by coal mines to GHGRP 

under section 98.326 of Subpart FF 

indicates that, while the majority of 

ventilation gas liberated by coal mines 

over the past decade has been vented, 

the majority of drainage gas has been 

productively used or flared. Mine 

practices have fluctuated, with some 

mines transitioning from predominantly 

venting drainage gas to predominantly 

using or destroying such gas. Factors 

that can affect the extent to which a 

mine vents, flares, and/or productively 

uses such gas in a given year include the 

amount of methane required by onsite 

equipment (for example, engines); 

proximity to offsite infrastructure (for 

example, pipelines); and the 

lucrativeness of programs incentivizing 

the capture of CMM. Incentives for 

CMM destruction and utilization that 

are currently available include State 

offset programs, State renewable 

portfolio standards, and voluntary 

offsets, some of which specifically do 

not allow for pipeline injection. 

The DOE and the EPA have advised 

that there is considerable uncertainty 

associated with establishing the 

appropriate alternative fate scenarios for 

CMM for the 10-year duration over 

which a hydrogen production facility 

may be able to claim the section 45V 

credit. Coal mines that are currently 

injecting CMM into pipelines may 

transition to flaring if natural gas prices 

fall or may exercise flaring at future 

boreholes if those boreholes are distant 

from existing pipeline infrastructure. 

Mines that are currently predominantly 

venting may transition to productive use 

if pipeline infrastructure is built in their 

vicinity. A flaring baseline is therefore 

the most appropriate approach for CMM 

given the uncertainty with respect to 

these emissions and because it reduces 

the risk of inappropriately attributing 

extremely negative lifecycle emissions 

rates to the capture of CMM which 

would have already been captured and 

productively used. 

Accordingly, § 1.45V–4(f)(3)(iv) of 

these final regulations provides that 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. This 

alternative fate accounts for the 

uncertainties associated with future 

practices, as described above, while 

recognizing that most drainage gas is 

destroyed today. 

v. Alternative Fate Considerations for 

Animal Waste 

The proposed regulations did not 

recognize a pathway to determine 

lifecycle GHG emissions rates for 

hydrogen production processes that use 

RNG produced from biogas from animal 

waste and invited comment on the 

treatment of various sources of RNG. 

The final regulations support providing 

a pathway in 45VH2–GREET to 

determine the lifecycle GHG emissions 

rate for the production of hydrogen that 

applies an alternative fate derived from 

the national average of current animal 

waste management practices. 

Comments suggested a variety of 

alternative fate assumptions for 

purposes of estimating lifecycle 

greenhouse gas emissions for these 

sources of RNG, including venting, 

alternative productive use, and 

responsible waste management, with 

some comments recommending a single 

alternative fate for RNG produced from 

these sources and others recommending 

differentiated alternative fates. There is 

no national database that tracks farmlevel methane emissions, capture, and 

usage in the agricultural sector. 

Additionally, there are no nationally 

applicable reporting requirements for 

animal waste management practices at 

livestock and poultry farms, which 

differ substantially on a farm-to-farm 

basis, and state-level reporting animal 

waste management reporting 

requirements vary. Therefore, lack of 

data and heterogeneity of animal waste 

management practices are limiting 

factors in establishing a single specific 

alternative fate for methane generated 

from animal waste. 

Many comments highlighted 

competing considerations in 

determining the appropriate alternative 

fate for methane derived from animal 

waste. Several comments recommended 

the 45VH2–GREET model calculate the 

avoided emissions from anerobic 

digestion and the associated RNG 

project using site-specific baseline 

manure management practices. The 

comments suggested the model could be 

modified to offer a menu that enables 

the user to identify what fraction of the 

manure was handled using each of these 

pre-project practices. The comments 

noted that each RNG project’s emissions 

reduction benefit may vary significantly 

based on the pre-existing manure 

management practices, and therefore it 

is crucial to have a drop-down selection 

in order to accurately calculate the 

lifecycle GHG emissions. Several 

comments suggested that for biogas 

produced from livestock manure, the 

alternative fate should be that methane 

would continue venting from manure 

handling facilities until such time as 

that venting is no longer permissible by 

law or regulation. The comments note 

that this alternative fate is similar to 

what the comments assert is appropriate 

for the landfill gas industry, where once 

regulations are in place that require 

landfill gas to be captured and 

destroyed, then flaring becomes the 

appropriate alternative fate. One 

comment recommended that a 

minimum utilization or flare rate of 80 

percent of recoverable methane 

emissions be adopted as the basis in the 


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Federal Register / Vol. 90, No. 6 / Friday, January 10, 2025 / Rules and Regulations 2289 

53 Values were calculated using data from the 

AgSTAR Digester Database. Livestock Anaerobic 

Digester Database, U.S. Environmental Protection 

Agency, available at https://www.epa.gov/agstar/ 

livestock-anaerobic-digester-database (last updated 

Oct. 1, 2024). The sum of dairy cattle reported as 

feeding operational digesters in the AgSTAR 

database as of June 2024 was calculated to be 1.55 

million. The sum of swine reported as feeding 

operational digesters was calculated to be 1.68 

million. The total values including digesters that 

are under construction are 1.87 million dairy cattle 

and 2.08 million swine. Percentages are calculated 

by dividing these values by the most up-to-date data 

on dairy cattle and swine head: total dairy cattle 

head in 2022 (18.6 million) and swine head (73.4 

million) as reported in the EPA GHG Inventory. See 

also U.S. Environmental Protection Agency, 

‘‘Inventory of U.S. Greenhouse Gas Emissions and 

Sinks,’’ available at https://www.epa.gov/ 

ghgemissions/inventory-us-greenhouse-gasemissions-and-sinks (Last updated November 22, 

2024). 

54Aaron Smith, How Much Should Dairy Farms 

Get Paid for Trapping Methane?, Energy Institute at 

Haas, Energy Institute Blog (Oct. 14, 2024), 

available at https://energyathaas.wordpress.com/ 

2024/10/14/how-much-should-dairy-farms-getpaid-for-trapping-methane/. 

alternative fate case for determining the 

carbon intensity of RNG that is utilized 

in the production of clean hydrogen. 

One comment noted that although the 

primary precedent for crediting avoided 

methane emissions is the CA LCFS’s 

treatment of biomethane from manure 

lagoons, this precedent serves to 

illustrate the inappropriateness of its 

adoption in section 45V. The comment 

stated that it is widely understood that 

the avoided methane calculation was 

specifically incorporated within the 

LCFS as a means of subsidizing 

investments in anaerobic digesters to 

address pollution from California’s 

dairies, not to reduce emissions from 

transportation fuel. Several comments 

noted that R&D GREET recognizes 

avoided emissions benefits in its 

lifecycle modeling for RNG where the 

manure and other wastes would 

otherwise release GHGs into the 

atmosphere. The comments state that 

the RNG industry agrees that any 

methodology assessing RNG’s lifecycle 

emissions must measure avoided 

emissions. 

Determining the appropriate 

alternative fate and emissions intensity 

for RNG produced from animal waste 

sources presents several challenges. 

First, the emissions intensity of biogas 

and ensuing RNG produced from animal 

waste can vary widely based on the 

specific waste practices used by 

individual producers. These practices 

are not comprehensively tracked and, in 

many cases, would be extremely 

difficult to effectively verify. Different 

waste disposal practices produce very 

different quantities of methane per unit 

of manure, as methane generation is 

much higher in wet anaerobic 

conditions. As one example, EPA GHG 

Inventory data indicates that uncovered 

anaerobic lagoons produce roughly one 

hundred times the amount of methane 

as daily spread. Even among farms 

credited with methane venting 

counterfactuals under the CA LCFS, the 

resulting RNG GHG emissions 

intensities vary widely depending on 

specific practices. Factors impacting the 

emissions intensity calculations for that 

program include, but are not limited to, 

the type of animals producing waste for 

the digester, type(s) of feed provided for 

the animals, the digester technology, 

and ambient conditions at the digester. 

As discussed further below, none of 

these practices are comprehensively 

tracked or reported at a national level. 

Comments also noted the further 

uncertainty and variation introduced by 

a range of leakage rates from operations 

capturing and upgrading manurederived methane, including the high 

likelihood that there are ‘‘super emitter’’ 

sources (consistent with the patterns 

seen in other fugitive methane streams). 

This could introduce additional 

uncertainty and risk of over crediting in 

estimating a GHG emissions rate. 

Second, there is substantial and 

growing alternative productive use of 

methane from animal waste. There are 

400 operational animal waste anaerobic 

digesters in the U.S. and 73 additional 

digesters under construction as of 2024, 

according to the AgSTAR Digester 

Database. Based on data from the 

AgSTAR Digester Database on the 

number of livestock (by head) feeding 

anaerobic digesters as of 2024, it is 

estimated that the waste from roughly 8 

percent of dairy cattle and 2 percent of 

swine (by head) is currently sent to 

anaerobic digesters and these numbers 

increase to 10 percent and 3 percent, 

respectively, if digesters currently under 

construction are included.53 The 

percentage of waste being sent to 

anaerobic digesters has been rising 

rapidly since 2019, with 400 operational 

projects and 73 under construction, and 

with the majority of new projects 

upgrading their biogas to RNG, due, in 

part, to incentives provided by the RFS, 

LCFS, and a California grant program. 

The digesters listed as newly 

operational and under construction as of 

2023–2024 in the AgSTAR database 

represent a 28 percent increase in the 

dairy cattle waste and 50 percent 

increase in swine waste (by head) sent 

to anaerobic digesters relative to 2022 

levels. While there has been some 

variation in the profitability of installing 

anaerobic digesters as credit values have 

fluctuated,54 the financial incentives 

provided by the RFS and LCFS 

programs appear to be sufficient to 

incentivize some installations of 

anaerobic digesters at existing lagoons, 

which reduces emissions without any 

additional incentive from the section 

45V credit. There are also other possible 

sources of revenue from anaerobic 

digester systems including net-metering 

in the case of electricity generation, 

tipping fees from local food production, 

or the sale of secondary products such 

as digestate-based fertilizer or 

phosphorus pellets. 

Complementing these incentives are a 

range of other voluntary programs that 

encourage capture and productive use of 

methane emissions from animal waste. 

For example, the United States 

Department of Agriculture (USDA) is 

leveraging its authority under a variety 

of existing programs to encourage 

farmers and ranchers to install or 

upgrade equipment and adopt new 

practices that improve manure 

management and can substantially 

reduce methane emissions. One such 

program, AgSTAR, is a collaborative 

program sponsored by the EPA and 

USDA that promotes the use of biogas 

recovery systems, such as anaerobic 

digester systems, to reduce methane 

emissions from animal waste. Likewise, 

USDA Natural Resources Conservation 

Service programs—including the 

Environmental Quality Incentives 

Program (EQIP) and the Conservation 

Stewardship Program (CSP)—provide 

incentives for upgrading existing 

anaerobic lagoons, anaerobic digesters, 

and solid separators and covers to 

collect methane for use or destruction; 

installing solid separators that reduce 

methane-producing slurries; and 

providing conservation assistance for 

transitions to alternative manure 

management systems, such as deep pits, 

composting, transitions to pasture, or 

other practices that have a lower GHG 

emissions profile. The Rural Energy for 

America Program (REAP) has offered 

more than $160 million in grants and 

loans to incentivize anaerobic digesters 

and biogas projects to control methane 

and biogas from dairy and other farms. 

Given rapid recent and continuing 

growth and multiple existing incentive 

programs, it is reasonable to assume 

continued growth in the share of large 

dairies and confined animal feeding 

operations with anaerobic digesters, 

even absent an additional incentive 

under the section 45V credit. 

Redirecting biogas and ensuing RNG 

that comes from these sources to 

hydrogen production will mean less 

displacement of natural gas elsewhere 

in the economy, and could therefore 

result in significant indirect emissions 


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2290 Federal Register / Vol. 90, No. 6 / Friday, January 10, 2025 / Rules and Regulations 

55U.S. Department of Energy, A Generic 

Counterfactual Greenhouse Gas Emissions Factor 

for Life-Cycle Assessment of Manure-Derived Biogas 

and Renewable Natural Gas, Washington, DC 

(2025), available at https://www.energy.gov/ 

45vresources. 

that must be taken into account under 

the section 45V(c)(1)(A) and (B). 

Third, the magnitude of the incentive 

provided by the section 45V credit itself 

creates a significant risk of additional 

waste production in response to the 

credit, with emissions that must be 

accounted for in the LCA. Additional 

waste production could result in 

additional emissions; moreover, even if 

emissions from additional production 

are captured, crediting the additional 

waste with avoided emissions would 

result in inaccurate credit 

determinations. For RNG produced from 

animal waste, there are several potential 

routes that may increase methane 

production: 

• Shifting management practices for 

existing quantities of manure from land 

application to lagoon, thereby 

significantly increasing methane 

generation; 

• On the margin, making new or 

expanded concentrated animal feeding 

operations (CAFOs) more profitable 

(whether by increasing the overall 

numbers of animals raised, or by 

consolidating smaller existing 

operations) and thereby inducing 

additional manure and methane 

generation; and 

• Using management practices at 

biodigesters to produce more methane 

than would have been produced 

otherwise (for example, increasing the 

temperature at an anaerobic digester). 

To the extent producers adopt these 

practices in response to incentives 

created by the section 45V credit, failure 

to take this into account could lead to 

allocating the section 45V credit to 

hydrogen that does not meet statutory 

GHG emissions requirements. This 

would be a particular concern with a 

venting alternative fate because it would 

result in a very negative estimated 

lifecycle GHG emissions rate, creating 

strong incentives to produce additional 

methane that is used by hydrogen 

producers to claim the section 45V 

credit inappropriately. 

In light of these challenges and in 

consultation with the DOE regarding the 

most appropriate approach to 

determining the GHG intensity of biogas 

and ensuing RNG derived from animal 

waste, these final regulations use an 

alternative fate for the sector as a whole 

that is derived from the national average 

of all animal waste management 

practices. The rule provided in § 1.45V– 

4(f)(3)(v) uses a best estimate of the 

nationwide average methane emissions 

from manure based on currently 

available data. As detailed in a technical 

analysis from the DOE, this results in a 

carbon intensity score of ¥51g 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. This emissions attribute for 

the methane contained in biogas from 

animal waste can be subsequently used 

to calculate the carbon intensity of RNG 

by accounting for the lifecycle GHG 

emissions associated with the biogas 

upgrading, transportation, and 

compressing process. 

As further explained in the DOE’s 

analysis of animal waste sources, this 

carbon intensity of RNG derived from 

methane contained in biogas from 

animal waste has been calculated using 

a weighted average of U.S. manure 

management practices across manure 

from all types of livestock and poultry.55

Averaging over the full set of animalwaste management practices nationwide 

is an administrable way to take into 

account the range of existing waste 

management practices and represent 

emissions reductions that result from 

additional methane capture and use. It 

is a reasonable and administrable 

representation of the carbon intensity of 

RNG from manure-based sources in light 

of the significant limitations of available 

data and verification mechanisms, the 

uncertainties associated with estimation 

of the GHG emissions, the benefits of 

different manure management systems, 

and the risks of perverse incentives. At 

the same time, it provides taxpayers 

certainty and clarity regarding the 

carbon intensity of methane from 

certain animal waste sources. 

The Treasury Department and the IRS 

considered alternative approaches, in 

particular whether to provide 

differentiated alternative fates, for 

example based on a producer’s prior 

waste management practices and 

methane production levels or the mix of 

animal types used to generate biogas. 

Differentiated alternative fates, however, 

is not feasible because it would not be 

administrable or practicable to set up a 

reporting and verification system to 

determine the prior practices and 

quantities of manure and biogas at each 

individual participating livestock and 

poultry operation that generates and 

sends biogas to an RNG upgrader. Such 

an approach would be infeasible given 

the large number of such operations and 

the lack of nationally applicable 

reporting requirements regarding 

numbers of animals or manure 

management practices by livestock and 

poultry operation (and wide variation in 

State reporting requirements). 

Additionally, 104 of the 473 digesters 

operational or under construction in the 

AgSTAR database report co-digesting 

their primary manure type with one or 

more other wastes, including other 

types of manure, food waste, 

agricultural residues, and dairy/food 

processor waste. These tracking and 

verification challenges are of particular 

concern because differences in waste 

disposal practices or specific waste 

sources can result in large differences in 

avoided emissions, meaning that highly 

specific prior waste management 

practices would need to be consistently 

reported and verified to support 

accurate differentiated alternative fates. 

In addition, as discussed previously, 

differentiated alternative fates that allow 

for highly negative emissions values 

raise concerns about incentives for 

additional waste production that could 

result in inappropriate claims of the 

section 45V credit. The Treasury 

Department and the IRS, in consultation 

with the DOE, will continue to monitor 

reporting and tracking systems and 

study the feasibility of introducing 

differentiated pathways in the future. 

The Treasury Department and the IRS 

also considered whether the emissions 

values for RNG produced from animal 

waste should be adjusted to reflect the 

risk of additional waste production in 

response to the incentives provided by 

the section 45V credit. While the 

emissions values resulting from the DOE 

technical analysis could provide 

incentives to generate new waste, this 

concern is ameliorated to a degree by 

the requirement in these final 

regulations to assess each hydrogen 

production process by grouping major 

inputs with similar attributes, rather 

than allowing blends of feedstocks with 

different attributes to be evaluated as a 

single production process. The Treasury 

Department and the IRS will continue to 

study this issue to determine whether 

adjustments are needed in the future. 

vi. Alternative Fate Considerations for 

Fugitive Methane From Fossil Fuel 

Activities Other Than Coal Mining 

The proposed regulations did not 

recognize a pathway within 45VH2– 

GREET for determining lifecycle GHG 

emissions rates for the production of 

hydrogen using fugitive methane, but 

the preamble to the proposed 

regulations invited comment on the 

treatment of various sources of fugitive 

methane. In consultation with the DOE 

and the EPA and considering that fossil 

fuel activities other than coal mining are 

overwhelmingly comprised of oil and 

gas operations, these final regulations 

use productive use as the applicable 


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56See, for example, Waste Prevention, Production 

Subject to Royalties, and Resource Conservation, 89 

FR 25378 (Apr. 10, 2024). 

alternative fate for fugitive methane 

from these activities. 

While some comments viewed the 

alternative fate of fugitive emissions to 

be venting, others noted the extensive 

existing regulatory requirements and 

additional incentives for avoiding 

fugitive emissions from oil and gas 

operations and argued that productive 

use is the appropriate alternative fate for 

this source of methane. The Treasury 

Department and the IRS note that the 

EPA’s regulations under section 111 of 

the Clean Air Act seek to limit volatile 

organic compounds and methane 

emissions from oil and gas operations 

through a variety of requirements 

including performance standards as 

well as operational practices and leak 

detection and repair programs. See 40 

CFR part 60 (Subparts OOOO, OOOOa, 

OOOOb, and OOOOc). For example, the 

EPA’s latest rules for new sources 

require use of zero emitting process 

controllers in most scenarios. The EPA’s 

previous rules allowed low bleed and 

intermittent bleed controllers, which 

emit pollutants to the atmosphere by 

discharging natural gas. The EPA’s new 

rules keep that gas in the system instead 

of allowing it to be released. The EPA’s 

new rules also phase out routine flaring 

of associated gas from most new oil 

wells, establish strong performance 

standards for emissions from storage 

tanks, include requirements for the 

efficiency of flares, and strengthen 

requirements for regular leak monitoring 

and deadline for repairs at well sites. 

The EPA’s leak detection and repair 

program at well sites requires frequent 

monitoring of oil and gas equipment 

with approved technology and methods 

to look for leaks. If a leak is found, then 

it must be repaired quickly so that the 

equipment stops leaking fugitive 

emissions to the atmosphere. This 

program will reduce the amount of 

emissions coming from leaking 

components. The EPA’s rules also 

require owners and operators of new 

wells to use best management practices 

to minimize or eliminate venting of 

emissions from gas well liquids 

unloading. 

As discussed in part III.E.1, while 

some of the compliance deadlines under 

each of the updated regulations under 

section 111 of the Clean Air Act and 

updated reporting requirements in 40 

CFR part 98 Subpart W have not yet 

passed, operators must plan for timely 

compliance with those requirements 

and must already comply with other 

requirements such as the new source 

requirements under section 111. Thus, 

operators have significant incentives to 

make certain compliance investments 

now and are required to do so well 

within the period of the section 45V 

credit. In addition, the Bureau of Land 

Management and most oil and gas 

producing States also regulate the waste 

of gas through venting and flaring, and 

some, such as New Mexico and 

Colorado, have regulations equally or 

more stringent than EPA requirements 

in many respects.56 As a consequence, 

the majority of the actions that an oil or 

gas operator could take to avoid fugitive 

emissions are already, or during the life 

of the section 45V credit will be, 

required by law. 

Given the extensive regulatory 

environment already in place requiring 

oil and gas operators to minimize GHG 

emissions from oil and gas operations, 

and the strong incentive and existing 

infrastructure to sell gas that is not lost 

through venting or flaring, the generally 

applicable alternative fate for fugitive 

emissions from fossil fuel activities 

other than coal mining is productive 

use. Accordingly, the final regulations 

provide that for purposes of determining 

the lifecycle GHG emissions rate of a 

process 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. For example, 

the production of methane from virgin 

coal seams, which is commonly referred 

to as ‘‘coalbed methane,’’ (CBM) may be 

for the purpose of natural gas 

production or may result from premining activities. Since it is typically of 

a comparable methane content as other 

natural gas sources, it is commonly sold 

for use. Nationwide, emissions that 

result from CBM extraction are currently 

reported to EPA’s Greenhouse Gas 

Reporting Program under Subpart W, 

which informs background estimates of 

upstream methane emissions for the 

natural gas supply chain in 45VH2– 

GREET. Accordingly, lifecycle GHG 

emissions analyses conducted for 

purposes of section 45V would 

represent CBM with a carbon intensity 

that is equivalent to that of other 

sources of fossil natural gas. 

d. Book and Claim 

The Explanation of Provisions to the 

proposed regulations noted that 

hydrogen producers using natural gas 

alternatives would be required to 

acquire and retire corresponding 

attribute certificates through a bookand-claim system that can verify in an 

electronic tracking system that all 

applicable requirements are met. 

Hydrogen producers would also be 

required to have a pipeline 

interconnection and measurement using 

a revenue grade meter. These rules 

would apply to the use of certificates 

with both direct and indirect claims of 

use of natural gas alternatives. Direct 

use would involve the production of 

hydrogen with a direct exclusive 

pipeline connection to a facility that 

generates RNG or from which fugitive 

methane is being sourced, while nondirect use would involve producing 

hydrogen using RNG or fugitive 

methane sourced from a commercial or 

common-carrier natural gas pipeline. In 

all cases, attribute certificates would 

need to document the RNG or fugitive 

methane procurement for qualified 

clean hydrogen production claims and 

ensure that the environmental attributes 

of the RNG or fugitive methane being 

used are not sold to other parties or 

used for compliance with other policies 

or programs. 

The Explanation of Provisions to the 

proposed regulations stated that before 

final regulations addressing the section 

45V credit are issued, taxpayers will use 

45VH2–GREET or the PER process to 

determine a lifecycle GHG emissions 

rate for hydrogen production facilities 

that rely on direct use of landfill gas or 

any fugitive methane feedstock, 

provided they meet the requirement that 

the gas being used results from the first 

productive use of methane from the 

landfill source or fugitive methane 

source. The term ‘‘direct use’’ means 

that there is a direct, exclusive pipeline 

connection between the hydrogen 

production facility and the source of the 

gas that is procured (for example, the 

upgrading or processing facility that 

produces RNG from landfill gas). 

Relative to a book-and-claim system, the 

direct connection between a gas 

supplier and a hydrogen production 

facility can reduce the uncertainty of 

pipeline leakage, tracking, and 

verification. 

The Explanation of Provisions to the 

proposed regulations explained that the 

Treasury Department and the IRS are 

considering providing a rule that 

taxpayers would need to provide and 

maintain documentation to substantiate 

that (i) the gas being used results from 

the first productive use of the methane 

at the landfill source and is not 

displacing a previous productive use; 

and (ii) the environmental attributes of 

the gas being used, including those of 

the underlying biogas, are not sold to 

other parties or used for compliance 

with other policies or programs. When 

additional conditions addressing 


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2292 Federal Register / Vol. 90, No. 6 / Friday, January 10, 2025 / Rules and Regulations 

hydrogen production pathways that use 

natural gas alternatives for purposes of 

the section 45V credit are determined, 

taxpayers would also be required to 

maintain documentation that the natural 

gas alternative being used meets those 

requirements and to acquire and retire 

any certificates that are established. The 

proposed regulations further explained 

that the Treasury Department and IRS 

were also considering providing rules 

for using certificates and documentation 

required in the event additional 

conditions for use of natural gas sources 

are later imposed. 

The Explanation of Provisions to the 

proposed regulations further noted that 

tracking and verification mechanisms 

for RNG or fugitive methane specific to 

the needs of the section 45V credit are 

not yet available, and existing systems 

have limited capabilities for tracking 

and verifying pathways for natural gas 

alternatives, especially in the part of the 

production process before the methane 

has been reformed to RNG. The 

Explanation of Provisions to the 

proposed regulations indicated that 

existing tracking and verification 

systems do not clearly distinguish 

between inputs, verify or require 

verification of underlying practices 

claimed by RNG production sources, 

require proof of generator 

interconnection or revenue-quality 

metering, provide validation of 

generation methodology, include 

exclusively United States basedgeneration, verify generator registration, 

and track the vintage of generator 

interconnection. In the proposed 

regulations, the Treasury Department 

and IRS indicated that they were 

considering providing rules to address 

whether or how book-and-claim systems 

with sufficient tracking and verification 

mechanisms may be used to attribute 

the environmental benefits of RNG or 

fugitive methane to hydrogen producers 

in the final regulations. Additional 

certainty was also needed to accurately 

account for emissions from pathways 

that do not yet exist in 45VH2–GREET 

and from gas from natural gas 

alternatives that is injected into a 

commercial or common-carrier pipeline. 

A range of comments advocating in 

favor of or against allowing the use of 

book-and-claim systems for natural gas 

alternatives were received in response 

to the proposed regulations. Several 

comments discussed how book-andclaim systems were commonplace 

within the RNG industry. In addition, 

several comments expressed concern 

about the viability of the RNG industry 

if the use of book-and-claim were not 

permitted under section 45V. Several 

comments stated that, because sources 

of natural gas alternatives are unevenly 

distributed throughout the United States 

and may not be located near prospective 

hydrogen projects, book-and-claim 

allows entities that do not have access 

to regional RNG sources to participate in 

the clean hydrogen economy. Several 

comments suggested there was clear 

Congressional intent to allow book-andclaim. One comment suggested that a 

‘‘mass balance’’ model or an ‘‘identity 

preservation’’ model could be adopted if 

a book-and-claim system were 

disallowed. 

Some comments expressed concerns 

about allowing book-and-claim. One 

comment suggested that there would be 

a mismatch between the support offered 

by the section 45V credit and the clean 

hydrogen-specific investment required 

of producers using a book-and-claim 

system; allowing section 45V credits for 

new or recently constructed hydrogen 

production facilities claiming 

production of qualifying hydrogen 

solely on the basis of RNG certificates, 

despite no meaningful change in 

operations compared to current 

‘‘business as usual’’ practice, would not 

contribute to the development of new 

clean hydrogen technology and would 

therefore be contrary to the intention of 

the IRA. Several comments noted that 

any tracking system would not ensure 

that biomethane is not produced for the 

purpose of meeting demand for the 

biomethane market. 

In response to these comments, after 

consultation with the DOE and the EPA, 

the Treasury Department and the IRS 

agree that, subject to certain conditions, 

safeguards, and requirements described 

later, a book-and-claim system is an 

acceptable mechanism for establishing 

claims to certain attributes of RNG or 

coal mine methane that is used in a 

hydrogen production process. Similar 

systems have been used in other 

programs for similar purposes. Although 

certificates that are acquired and retired 

in a book-and-claim system may not 

necessarily reflect the feedstocks in fact 

used by a hydrogen production facility, 

such systems can serve as an effective 

proxy for the use of certain feedstocks 

if certain conditions are required, and 

the acquisition and retirement of 

certificates would contribute to the 

development of the hydrogen 

production market. Both EPA’s RFS and 

the CA LCFS employ a form of bookand-claim (sometimes referred to as 

‘‘mass balance’’), and the DOE has 

advised that both programs have driven 

methane capture and productive use. 

The DOE has also advised that EACs 

used for electricity have demonstrably 

supported new clean power plants. 

When such systems meet the conditions 

and requirements described later, bookand-claim systems can be appropriate 

tools for RNG and coal mine methane 

verification, supporting the 

establishment of lifecycle emissions as 

required under section 45V and these 

final regulations. The acquisition and 

retirement of certificates meeting certain 

requirements establishes claims to the 

attributes represented by such 

certificates that are considered part of 

the hydrogen production process and 

the lifecycle GHG emissions associated 

with the process. 

Some comments highlighted design 

challenges that should be addressed if 

the use of a book-and-claim system is 

allowed for purposes of section 45V. 

Several comments recommended that if 

a book-and-claim system were allowed, 

then such system should take measures 

to avoid double-counting of the same 

environmental attributes. Other 

comments suggested that any tracking 

system should be able to allocate 

emissions based on different levels of 

gas blending from different feedstocks, 

enable the differentiation of carbon 

capture rates to those different feedstock 

production pathways, and determine 

credit values based on these 

evaluations. 

The Treasury Department and the IRS 

agree with many of these comments and 

have taken them into account in 

establishing the requirements for a 

book-and-claim system that taxpayers 

may use for purposes of section 45V. 

Before a tracking system is suitable for 

use for purposes of section 45V, it must 

be capable of robustly tracking claims to 

the use of attributes and protecting 

against double counting. In consultation 

with the DOE and the EPA, the Treasury 

Department and the IRS agree that bookand-claim systems must enable users to 

distinguish between feedstocks as 

relevant to determining lifecycle GHG 

emissions rates for purposes of section 

45V, but the Treasury Department and 

the IRS do not view it as appropriate to 

require tracking systems to allocate 

emissions or otherwise calculate 

emissions associated with the RNG or 

coal mine methane represented by a 

certificate. The carbon intensity 

associated with the RNG or coal mine 

methane used to produce hydrogen may 

be determined in 45VH2–GREET or a 

PER using the attributes represented by 

certificates for such feedstocks. 

Following consultation with the DOE 

and the EPA, and in consideration of the 

comments received and the 

requirements specified in these 

regulations regarding RNG and coal 

mine methane, these final regulations 

define in § 1.45V–4(f)(2)(vi) a ‘‘gas 

energy attribute certificate’’ (gas EAC) to 


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mean a tradeable contractual 

instrument, issued through a qualified 

gas EAC registry or accounting system 

(as defined in in § 1.45V–4(f)(2)(viii)), 

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. These final regulations in 

§ 1.45V–4(f)(2)(vii) define the term 

‘‘eligible gas EAC’’ to mean a gas EAC 

that represents the quantity of RNG or 

coal mine methane that is produced by 

a facility that is registered on only one 

qualified gas EAC registry or accounting 

system (as defined in § 1.45V– 

4(f)(2)(viii)) and that, with respect to the 

RNG or coal mine methane to which the 

gas EAC relates, provides, at a 

minimum, the information specified in 

§ 1.45V–4(f)(2)(vii)(A) through (F). The 

information specified in § 1.45V– 

4(f)(2)(vii)(A) through (F) will enable the 

attributes of the RNG or coal mine 

methane represented by a gas EAC to be 

appropriately evaluated in determining 

a lifecycle GHG emissions rate for 

purposes of section 45V. For example, 

the requirement in § 1.45V– 

4(f)(2)(vii)(E) for gas EACs to reflect the 

source or sources of the gas that 

comprises the RNG or coal mine 

methane associated with each gas EAC 

and any attributes required by 45VH2– 

GREET, or in the determination of a 

PER, to accurately determine the 

emissions associated with such RNG or 

coal mine methane is intended to 

require gas EACs in a book-and-claim 

system to form the basis for any material 

distinctions that are relevant to the 

determination of a lifecycle GHG 

emissions rate as those distinctions are 

reflected in 45VH2–GREET and may 

evolve over time. 

In consultation with the DOE and the 

EPA, and in consideration of the 

comments received and the 

requirements specified in these 

regulations regarding RNG and coal 

mine methane, these final regulations 

provide that a qualified gas EAC registry 

or accounting system for RNG or coal 

mine methane is 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. Such a qualified book-andclaim system would need to be 

accompanied by a robust third-party 

verification system or systems of the 

related production processes. 

e. Qualifying Gas EAC Requirements 

The Explanation of Provisions to the 

proposed regulations indicated that the 

temporal matching and deliverability 

requirements as applied to RNG and 

coal mine methane would be logically 

consistent with but not identical to the 

temporal matching and deliverability 

requirements for electricity-derived 

EACs. The Explanation of Provisions to 

the proposed regulations further 

indicated that any such requirements 

would be designed to reflect the ways in 

which additional RNG or demand for 

fugitive methane can impact lifecycle 

GHG emissions and also to address the 

differences between electricity and 

methane, including but not limited to 

the different sources of emissions, 

markets, available tracking and 

verification methods, and potential for 

perverse incentives. 

A wide range of comments were 

received on temporal matching and 

deliverability requirements for natural 

gas alternatives. As relates to temporal 

matching, comments expressed differing 

views on whether to include a temporal 

matching requirement and, if so, over 

what timeframe the matching should be 

required. One comment argued against 

requiring temporal matching because 

the natural gas pipeline system operates 

on a displacement basis, where all 

injections are balanced with 

consumption and storage. The comment 

noted that physical volumes do not 

necessarily move but rather balance. 

Several comments noted that, unlike 

electricity, RNG has more steady flow 

year-round and has substantial storage 

available that can be used to address 

seasonal differences in demand. One 

comment also noted that, unlike 

electricity, natural gas and RNG 

production does not instantaneously 

rise and fall with natural gas and RNG 

demand. Therefore, the comment 

asserted that increased demand for RNG 

does not necessarily yield an 

immediate, simultaneous increase in 

natural gas production and related 

emissions. 

Many comments discussed the 

appropriate timeframe for matching if a 

temporal matching requirement is 

included in the final regulations. One 

comment argued that biogas, RNG, and 

fugitive methane production are not 

weather dependent on a minute, hourly, 

daily, weekly, monthly, or quarterly 

basis, and therefore should be matched 

on an annual basis. Others noted that 

hourly time matching would be 

unworkable because the industry 

typically balances supply and demand 

on at least a monthly basis, and 

hydrogen production is often tracked 

quarterly. One comment stated that due 

to the large storage capacity for gas in 

the United States, it would be 

appropriate to allow use of any RNG 

produced in the same year or one year 

prior to the year the clean hydrogen was 

produced. Another comment requested 

that if an hourly matching requirement 

was put in place to consider 

grandfathering in facilities that begin 

construction prior to December 31, 

2029, allowing such facilities to use 

annual temporal matching. One 

comment noted that temporally 

matching RNG production and RNG use 

does little to improve the accuracy of 

carbon intensity scores, that time 

matching with a period shorter than 

monthly would create an arbitrary 

burden with little benefit, and that 

matching on a monthly basis would 

make sense after a transition period. 

Other comments also supported 

monthly matching. 

With respect to deliverability, the 

comments included a range of opinions 

about the size of the geographic regions 

under a deliverability requirement. One 

comment noted that the United States’ 

natural gas pipeline network is 

sufficiently interconnected and has the 

proper infrastructure to permit interregional trade of natural gas, thus 

justifying either not having a matching 


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requirement or having one equivalent to 

the size of the contiguous United States. 

Another comment noted that such a 

requirement would be appropriate so as 

not to disadvantage specific regions of 

the country. One comment noted that 

book-and-claim accounting combined 

with an attestation requirement obviates 

the need for strict geographic or 

deliverability requirements. One 

comment noted that the risk of 

undesirable indirect emissions effects 

from geographic or temporal 

mismatches between sources and uses is 

very low for RNG because the marginal 

source of gas on the natural gas grid is 

the same at all times of the day, in all 

seasons of the year and in all regions of 

North America. 

Other comments disagreed with 

treating the entire United States as a 

single, interconnected system. Some 

comments noted that any RNG claimed 

by a hydrogen producer should be 

required to be delivered into the same 

natural gas transmission network as the 

hydrogen producer claiming the 

utilization of the RNG in alignment with 

the deliverability requirement for 

electricity. One comment noted that a 

national approach fails to reckon with 

real-world system constraints that result 

in differentiated pricing, uneven 

emissions rates, and pipeline capacity 

limits, all of which can shape 

investment decisions in the broader 

energy system. Another comment stated 

that any RNG fed into the gas grid to be 

utilized by hydrogen producers should 

be fed into the same local gas 

distribution system where the clean 

hydrogen facility operates to fulfill the 

deliverability requirement. The 

comment asserted that such a measure 

could help ensure that GHG emissions 

from transport of the RNG or fugitive 

methane feedstock to the hydrogen 

production facility can be accounted for 

with some degree of certainty. Another 

comment noted that any biomethane 

claimed for hydrogen production for 

purposes of section 45V compliance 

should be physically deliverable to the 

hydrogen production plant to ensure a 

robust book and claim system with 

climate integrity, and that while much 

of the North American gas system is 

considered connected, there are key 

considerations to consider when 

designing rules for qualifying gas 

pathways. Several other comments 

requested that book-and-claim 

accounting include deliverability 

constraints that are consistent with 

accounting for the direct and indirect 

emissions of producing hydrogen with 

methane feedstocks. Likewise, some 

comments noted that the Treasury 

Department should further research the 

need for geographic boundary 

requirements on RNG book-and-claim to 

confirm whether there would be 

different emissions impacts across 

geographies. 

Section 45V requires a determination 

of lifecycle GHG emissions rates to 

address direct and significant indirect 

emissions, and this requirement applies 

to the use of RNG or coal mine methane 

in a hydrogen production process. Other 

requirements applied to RNG and coal 

mine methane included in these final 

regulations address some of these 

emissions. As relates to deliverability 

and temporal matching, many 

comments indicate that, unlike 

electricity EACs, temporal matching and 

deliverability requirements for RNG and 

coal mine methane have less direct 

salience because of their different nature 

and market characteristics. The DOE has 

advised, for example, that while 

electricity markets are highly 

regionalized with marginal emissions 

varying substantially over space and 

time, the same is not as true for the 

delivery infrastructure related to natural 

gas. Natural gas travels over regional 

and inter-regional pipelines and, while 

constraints exist on that network, as 

does methane leakage, there are fewer 

obvious regional boundaries to those 

pipelines as compared to the electricity 

grid. Additionally, the DOE has advised 

that the marginal emissions rate of using 

natural gas from the interstate pipeline 

network does not vary dramatically over 

time, and certainly not on an hourly 

basis. In part, this is because there is 

considerable storage in the natural gas 

delivery infrastructure, again unlike 

electricity networks. 

In light of all these considerations, the 

final regulations provide in § 1.45V– 

4(f)(4)(iii)(B) that deliverability requires 

geographic matching within the 

pipeline network in a region. For this 

purpose, the pipeline network in the 

contiguous United States is treated as a 

single region. Hydrogen producers 

located in and connected to a natural 

gas pipeline in the contiguous United 

States must purchase an eligible gas 

EAC for RNG or coal mine methane that 

was injected into the pipeline network 

in the contiguous United States for such 

eligible gas EAC to be considered a 

qualifying gas EAC. Alaska, Hawaii, and 

each U.S. territory will be treated as 

separate regions for this purpose. A 

hydrogen producer located in and 

connected to a natural gas pipeline in 

any of these regions is required to 

purchase and retire gas EACs from RNG 

or coal mine methane producers whose 

pipeline injection is located in the same 

region to meet the requirement provided 

in § 1.45V–4(f)(4)(iii)(B). The DOE has 

advised that delivery can occur within 

the national natural gas pipeline 

network. These final regulations further 

confirm that the deliverability 

requirement is met 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. 

With respect to temporal matching, in 

consultation with the DOE, these final 

regulations in § 1.45V–4(f)(4)(iii)(A) 

require monthly matching. Eligible gas 

EACs used to document RNG or coal 

mine methane inputs by a qualified 

hydrogen producer need to be timestamped such that the calendar month 

of the pipeline injection is the same 

calendar month in which the qualified 

hydrogen producer uses the underlying 

gas. As with electricity EACs, the thirdparty verifier is required to validate the 

matching requirement. A monthly 

matching requirement is appropriate for 

at least three reasons. First, the DOE has 

advised that pipeline flow and 

embedded storage in the natural gas 

delivery infrastructure means that the 

flow of gas from source to sink is 

variable but that one month is a 

reasonable approximation. A monthly 

matching requirement therefore ensures 

that temporal matching approximates 

the physics of actual delivery. Second, 

the DOE has advised that there would 

be little or no benefit in terms of 

mitigating the risk of significant indirect 

emissions if the temporal matching 

requirement were to be more granular, 

for example daily or hourly. Third, 

unlike renewable sources of electricity, 

the volume of RNG or coal mine 

methane produced by a specific source 

is unlikely to vary substantially over the 

course of a day but may vary seasonally 

over the course of a year. A monthly 

matching requirement will 

appropriately capture these potential 

seasonal differences in the quantity of 

RNG and coal mine methane 

production. These final regulations 

further confirm that the temporal 

matching requirement is met 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. 

Section 1.45V–4(f)(4)(iii) requires 

both temporal and deliverability 

requirements to be met for an eligible 

gas EAC to be considered a qualifying 

gas EAC that establishes a claim to the 


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attributes of the eligible gas EAC for 

purposes of section 45V. 

Several comments suggested that 

existing systems, such as M–RETS, the 

EPA’s RFS program, or the CA LCFS 

program, might have sufficient 

capabilities to enable book and claim 

accounting for purposes of section 45V. 

The EPA has advised that the tracking 

system used for the RFS is purpose-built 

for that program and would not be 

appropriate for use in the 

implementation of section 45V. Further, 

the EPA’s RFS tracking system is not 

designed to differentiate among types of 

RNG by carbon intensity score and 

would not be usable for such a purpose 

even if it were otherwise appropriate to 

do so. The CA LCFS program uses what 

some stakeholders call a ‘‘mass balance’’ 

approach to tracking RNG, which is 

focused on tracking chain of custody 

based on review of contracts and related 

attestations, not via an electronic 

registry. The Treasury Department and 

the IRS, in consultation with the DOE, 

are concerned that a mass balance 

approach similar to the one employed 

by the CA LCFS program would be 

difficult to administer and is therefore 

not well suited for administration of the 

section 45V credit. M–RETS were 

identified by a number of stakeholders 

as an electronic registry that tracks RNG 

and that has been approved by several 

States in the administration of their 

programs. 

In consultation with the DOE and the 

EPA, the Treasury Department and the 

IRS confirm that, under these final 

regulations, hydrogen producers using 

RNG or coal mine methane will be 

allowed to acquire and retire 

corresponding attribute certificates 

through a book-and-claim system that 

can verify in an electronic tracking 

system that all applicable requirements 

are met. As discussed further below, 

such an electronic tracking system must 

be robust, establish unique claims to the 

attributes of RNG and coal mine 

methane, and utilize a qualified thirdparty registry that meets certain 

requirements after such registries 

become available. 

These final regulations establish 

requirements for certificates associated 

with RNG and coal mine methane, as 

well as qualification criteria for 

electronic book-and-claim registries. 

These requirements will help ensure 

that registries understand and will be 

capable of meeting the specific needs of 

these final regulations in a comparable 

fashion as qualified EACs, ensuring 

credible claims and no double counting 

while enabling assessments of certain 

emissions associated with RNG and coal 

mine methane. The Treasury 

Department and the IRS recognize, 

however, that the final regulations 

establish and announce specific 

requirements for gas EACs for the first 

time, and it may take time for systems 

and practices to adjust to meet these 

requirements. The Treasury Department 

and the IRS further note that experience 

with electronic registries for natural gas 

alternatives is less extensive than with 

EACs for electricity. The Treasury 

Department and the IRS are particularly 

concerned with the ability of systems to 

develop sufficient capability to robustly 

verify the waste sources generating 

biogas from which RNG is derived 

because such sources must be separately 

evaluated within 45VH2–GREET or in 

the determination of a PER. For 

example, use of RNG derived from 

biogas generated by animal waste and 

wastewater would be treated as distinct 

processes under these final regulations. 

Thus, tracking systems must verify the 

distinct upstream sources of biogas for 

RNG in a manner that allows the 

attributes of each source to be assessed 

in separate processes. 

Based on the comments received and 

in consultation with the DOE, the 

Treasury Department and the IRS 

understand that book-and-claim 

registries will, in the future, be able to 

meet the requirements provided in these 

final regulations. While the Treasury 

Department and the IRS cannot predict 

precisely when one or more electronic 

registries will be able to fully meet the 

requirements provided by these 

regulations, upon consultation with the 

DOE, the Treasury Department and the 

IRS expect that two years after the date 

the requirements for such systems have 

been announced will allow time for an 

entity or entities to modify existing 

systems, or design and build new 

systems, sufficient to meet the 

requirements specified in these final 

regulations. If and when systems that 

can meet the requirements of these final 

regulations become available, but no 

earlier than January 1, 2027, the 

Secretary will determine whether an 

existing system meets the requirements 

established in these final regulations, 

and that such system may then be used 

to acquire and retire qualifying gas 

EACs under these final regulations. The 

use of book-and-claim accounting for 

RNG and coal mine methane will not be 

permitted until the Secretary makes this 

determination. 

Until the use of book-and-claim 

accounting for RNG and coal mine 

methane is permitted, taxpayers will be 

required to substantiate their use of 

RNG and coal mine methane in the 

production of hydrogen through a direct 

pipeline connection to a supplier of 

natural gas alternatives or 

documentation of other physical 

methods of exclusive delivery. In such 

cases of direct physical delivery, the 

attributes of the RNG and coal mine 

methane must be conveyed to the 

qualified hydrogen producer in a way 

that ensures no double counting of such 

attributes. 

Once book-and-claim is allowed via 

qualified tracking registries, electronic 

certificates issued by such registries will 

be required for both direct and indirect 

claims of use of RNG and coal mine 

methane. Direct use involves the 

production of hydrogen with a direct 

exclusive pipeline connection to a 

facility that generates RNG or from 

which coal mine methane is being 

sourced (or other physical method of 

exclusive delivery), while non-direct 

use would involve producing hydrogen 

using RNG and coal mine methane 

sourced from a natural gas pipeline. In 

the latter case, hydrogen producers 

would be required to have a pipeline 

interconnection and would need to 

measure pipeline injections via a 

revenue grade meter. In all cases, 

qualifying gas EACs would need to be 

acquired and retired pursuant to these 

final regulations to document the RNG 

and coal mine methane procurement for 

qualified clean hydrogen production 

claims and that the attributes of the 

RNG and coal mine methane being used 

are not sold to other parties. 

IV. Verification 

Section 45V(c)(2)(B)(ii) provides that 

no hydrogen is qualified clean hydrogen 

unless its production and sale or use is 

verified by an unrelated party. 

Proposed § 1.45V–5 would have 

provided the procedures necessary for 

section 45V credit claimants to fulfill 

the statutory verification requirement of 

section 45V(c)(2)(B)(ii). Comments 

addressed many aspects of these 

proposed rules, which are discussed in 

this part IV of the Summary of 

Comments and Explanation of 

Revisions. These final regulations adopt 

the rules as proposed, with the 

modifications described in this part IV. 

A. In General 

Proposed § 1.45V–5(a) would have 

provided that a verification report must 

be attached to a taxpayer’s Form 7210 

for each qualified clean hydrogen 

production facility and for each taxable 

year in which the taxpayer claims the 

section 45V credit. 

One comment argued that qualified 

verifiers should be required to directly 

report their verification findings to the 

IRS, saying it is necessary for public 


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confidence in the administration of 

section 45V. 

While drafting both the proposed 

regulations and these final regulations, 

the Treasury Department and the IRS, in 

consultation with the DOE and the EPA, 

considered adopting a verification 

regime that would require such direct 

reporting. The final regulations do not 

adopt this provision because direct 

reporting by verifiers to the IRS is not 

reasonably administrable. 

Another comment requested the 

creation of a ‘‘streamlined’’ verification 

process that small businesses that 

engage in self-use of produced hydrogen 

could elect into. Section 45V does not 

make any distinction based on the size 

of the hydrogen producer, and the 

importance of verification is the same 

regardless of producer’s size. 

Accordingly, no additional, 

‘‘streamlined’’ verification process is 

needed or appropriate. 

A few comments requested that the 

verification report requirement be 

suspended for the 2023 tax year. 

Because the verification requirement is 

statutory and begins in 2023, these final 

regulations do not adopt this comment. 

Some comments recommended that 

taxpayers be permitted to obtain 

verification reports on a quarterly 

instead of annual basis. While unclear, 

these comments appear to be 

recommending that the section 45V 

credit be determined on a quarterly 

basis. The period of time for which the 

credit is determined and for which the 

taxpayer must obtain a verification 

report is established by statute. Section 

45V(a) provides that the section 45V 

credit is determined for ‘‘any taxable 

year,’’ meaning that the credit is 

determined on an annual basis. 

Allowing taxpayers to determine the 

credit on a quarterly basis would 

contravene the statute, and therefore 

this recommendation is not adopted. 

The final regulations amend § 1.45V– 

5(a), however, to clarify that the 

taxpayer’s Form 7210, or any successor 

form(s), are filed with the taxpayer’s 

Federal income tax return or 

information return, which is consistent 

with the instructions to that form, and 

also make clarifying edits to the text of 

the regulation to eliminate redundant 

text. 

B. Requirements for Verification Reports 

Proposed § 1.45V–5(b) would have 

provided the general rule that a 

verification report specified in 

paragraph (a) of the same section must 

be prepared by a qualified verifier under 

penalties of perjury and must contain a 

production attestation, a sale or use 

attestation, a conflict attestation, a 

qualified verifier statement, certain 

general information about the taxpayer’s 

hydrogen production facility, and any 

documentation necessary to substantiate 

the verification process given the 

standards and best practices of the 

qualified verifier’s accrediting body and 

the taxpayer’s circumstances and its 

hydrogen production facility. 

Comments addressed many aspects of 

the specific rules governing the contents 

of the verification report, and these are 

addressed in the succeeding paragraphs 

of this Summary of Comments and 

Explanation of Revisions. Comments 

did not address the general rule of 

proposed § 1.45V–5(b), but these final 

regulations include an additional 

requirement that a verification report 

must include any other information 

required by IRS forms or instructions. 

This additional requirement ensures 

that the IRS is able to effectively 

administer the section 45V credit and 

meet the statutory requirement of 

section 45V(c)(2)(B)(ii). 

C. Requirements for the Production 

Attestation 

Proposed § 1.45V–5(c) would have 

provided the rules dictating the content 

of the production attestation within a 

verification report. Proposed § 1.45V– 

5(c)(1) would have provided that the 

production attestation must be an 

attestation that the qualified verifier 

performed a verification sufficient to 

determine that the operation of the 

taxpayer’s hydrogen production facility 

and any EACs applied pursuant to 

§ 1.45V–4(d) are accurately reflected in 

the amount of qualified clean hydrogen 

claimed on the taxpayer’s Form 7210 

and either the data the taxpayer entered 

into the most recent GREET model to 

determine the emissions rate claimed on 

the taxpayer’s Form 7210, or the data 

the taxpayer submitted in the PER 

petition relating to the taxpayer’s 

hydrogen and which was provided to 

the DOE to obtain the emissions value 

provided in the PER petition. 

Some comments requested that the 

final regulations provide specific rules 

for verification of facility-specific data, 

including in the PER process, to ensure 

that emissions data is independently 

collected using objective quantification 

methods and that the data trail is 

immutable, auditable, transparent, and 

accessible by third parties. 

The Treasury Department and the IRS 

agree that clarification is needed 

regarding verification of data specific to 

the facility. Accordingly, § 1.45V–5(c)(1) 

is modified to reflect that a verification 

report must reflect ‘‘reasonable 

assurance’’ in the operation of the 

hydrogen production facility and any 

EACs applied. The ‘‘reasonable 

assurance’’ standard is defined within 

the ISO 14064–3, and is reflected in 

other greenhouse gas regulations, such 

as the CA LCFS. Additionally, as 

discussed in part IV.H of this Summary 

of Comments and Explanation of 

Revisions, § 1.45V–5(h) is modified to 

reflect that a qualified verifier 

accredited under the American National 

Standards Institute National 

Accreditation Board must be accredited 

to conduct validation and verification in 

accordance with the requirements of 

ISO 14065:2020 and ISO 14064–3:2019. 

This clarifies that the verification report 

must be performed in accordance with 

those standards, or similar standards in 

the case of a verifier accredited under 

the CA LCFS program. 

In addition, the production attestation 

requirements are modified to include an 

additional requirement in the case of 

any EACs applied pursuant to § 1.45V– 

4(d). Under this modification, verifiers 

must confirm that the electricity 

generator or generators associated with 

such EACs are not registered on 

multiple qualifying EAC registries, or, in 

the event such generators are registered 

on multiple qualifying EAC registries, 

each EAC undergoing verification from 

each such generator registered on 

multiple qualifying EAC registries is 

being issued by only one qualifying EAC 

registry. See § 1.45V–5(c)(2). Because 

qualifying EAC registries must provide 

a publicly accessible view of all 

currently registered generators in the 

tracking system to prevent the 

duplicative registration of generators, 

this verification requirement provides 

further guardrails against the risk of 

double counting EACs. The final 

regulations also make corresponding 

modifications to § 1.45V–5(b)(1) and 

(c)(1) regarding the accuracy of the 

inputs used to determine the lifecycle 

GHG emissions rate of hydrogen 

production processes. 

Proposed § 1.45V–5(c)(2) and (3) 

would have required production 

attestations to specify the emissions rate 

and amount of qualified clean hydrogen 

produced that are claimed on the 

taxpayer’s Form 7210, as well as the 

emissions value received from the DOE 

during the EVRP, if applicable. No 

comments addressed these provisions, 

so these final regulations adopt them as 

proposed, with renumbering. 

D. Requirements for the Sale or Use 

Attestation 

Proposed § 1.45V–5(d) would have 

provided rules governing the content of 

the sale or use attestation within a 

verification report. Proposed § 1.45V– 

5(d)(1) would have provided that the 


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sale or use attestation must be an 

attestation that the qualified verifier 

performed a verification sufficient to 

determine that the amount of qualified 

clean hydrogen that is specified in the 

production attestation and that is 

claimed on the taxpayer’s Form 7210 

has been sold, or has been used by a 

person who makes a verifiable use of 

such hydrogen. 

Proposed § 1.45V–5(d)(2) would have 

provided a definition of verifiable use 

indicating that a verifiable use can occur 

within or outside the U.S., can be made 

by the taxpayer or another person; 

includes tolling arrangements; and does 

not include the generation of electricity 

for subsequent rounds of hydrogen 

production, venting, or flaring. 

The proposed regulations requested 

comments on whether the regulations 

could adopt additional safeguards to 

prevent the use of hydrogen to generate 

electricity that is then directly or 

indirectly used to produce more 

hydrogen, the venting or flaring of 

hydrogen, and similar types of abusive 

section 45V credit claims, including 

claims from circular arrangements 

coordinating among multiple parties. 

Comments construable as responding 

to this request focused on the anti-abuse 

rule of proposed § 1.45V–2(b), so these 

comments are addressed in part II.B of 

this Summary of Comments and 

Explanation of Revisions. 

One comment asked for the final 

regulations to include broadly 

applicable examples of verifiable use, 

such as usage that replaces natural gas 

in production facilities or other 

industrial uses, or to specify what 

constitutes a verifiable use. Another 

comment recommended that the 

verifiable use rule not address indirect 

use of electricity generated from 

produced hydrogen to produce further 

hydrogen, citing the recycling of waste 

heat as a benign example of such 

indirect use. 

The Treasury Department and the IRS 

agree that the operation of the verifiable 

use rule should be clarified and should 

not apply to the use to which 

byproducts of hydrogen use are put. 

Accordingly, these final regulations 

provide a clarifying modification to the 

text of the verifiable use rule in § 1.45V– 

5(d)(2)(i) and an example in renumbered 

§ 1.45V–5(d)(3), which illustrates the 

application of § 1.45V–5(d)(2). 

One comment asked that binding 

written offtake agreements be construed 

as sales for purposes of the sale or use 

attestation. However, in the absence of 

a regulatory definition of sale for section 

45V purposes alone, whether a 

particular agreement constitutes a sale 

would be determined under general tax 

principles. There is insufficient 

justification for an exception to this 

result and thus these final regulations 

do not adopt the proposal. To the extent 

such an agreement is a sale for Federal 

income tax purposes, the taxpayer 

would not be eligible to claim the 

section 45V credit with respect to the 

hydrogen it sold until all relevant 

requirements, including the verification 

requirement, have been satisfied. 

With respect to the comment’s request 

for examples, or a specific definition of, 

verifiable use, these final regulations do 

not provide specific examples or specify 

a definition of verifiable use. The 

verifiable use rule is intended to 

prohibit abusive or wasteful uses of 

hydrogen that do not further the 

purpose of section 45V while providing 

flexibility in what constitutes a 

verifiable use. It is not meant to limit 

the universe of creditable uses of 

qualified clean hydrogen, and defining 

verifiable use could lead to that 

unintended result. However, to clarify 

some verifiable uses of qualified clean 

hydrogen, examples could include using 

qualified clean hydrogen in a fuel cell 

to produce electricity, or using qualified 

clean hydrogen to manufacture steel, 

among many other uses. 

E. Requirements for the Conflict 

Attestation 

Proposed § 1.45V–5(e) would have 

provided rules governing the content of 

the conflict attestation within a 

verification report. Proposed § 1.45V– 

5(e)(1) would have provided five 

representations the verifier must make 

in the conflict attestation, while 

proposed § 1.45V–5(e)(2) would have 

provided a special rule in the elections 

made under section 6418(a) with respect 

to the section 45V credit. 

One comment expressed concern that 

the verifier conflict attestation, 

specifically the language at proposed 

§ 1.45V–5(e)(1)(iii) reading, ‘‘[t]he 

qualified verifier is not related, within 

the meaning of section 267(b) or 

707(b)(1) of the Code, to, or an employee 

of, the taxpayer[,]’’ appears to require 

hydrogen producers to test for conflict 

attribution with every employee of the 

qualified verifier, given the definition of 

‘‘related’’ in sections 267(b) and 

707(b)(1). 

These final regulations do not adopt 

this comment. The language of proposed 

§ 1.45V–5(e)(1)(iii) only requires testing 

whether the qualified verifier is related, 

within the meaning of section 267(b) or 

707(b)(1), to the taxpayer, and whether 

the qualified verifier is an employee of 

the taxpayer. Proposed § 1.45V– 

5(e)(1)(iii) does not require application 

of any attribution or constructive 

ownership rules. 

Proposed § 1.45V–5(e)(2) would have 

provided a special rule in the case of 

taxpayers making an election to transfer 

the credit under section 6418 to require 

the conflict attestation to attest that the 

verifier is independent of both the 

eligible taxpayer and the transferee. 

Because the identity of the transferee 

might not be known in time for the 

verifier to complete the conflict 

attestation, this special rule could create 

issues with timely preparing the conflict 

attestation. Proposed § 1.45V–5(e)(2) is 

therefore removed from these final 

regulations, and accordingly, §§ 1.45V– 

5(e)(1)(i) through (v) are renumbered as 

§ 1.45V–5(e)(1) through (5). Correlative 

edits have also been made to proposed 

§ 1.48–15(e)(2). 

F. Requirements for the Qualified 

Verifier Statement 

Proposed § 1.45V–5(f) would have 

provided rules governing the content of 

the qualified verifier statement within a 

verification report. No comments 

addressed this provision, so these final 

regulations adopt it as proposed. 

G. General Information on the 

Taxpayer’s Hydrogen Production 

Facility 

Proposed § 1.45V–5(g) would have 

required certain information regarding 

the hydrogen production facility 

undergoing verification to be included 

in the verification report. No comments 

addressed this provision, so these final 

regulations adopt it as proposed. 

H. Qualified Verifier 

Proposed § 1.45V–5(h) would have 

defined a qualified verifier as any 

individual or organization with active 

accreditation as a validation and 

verification body from the American 

National Standards Institute National 

Accreditation Board (ANAB), or as a 

verifier, lead verifier, or verification 

body under the CA LCFS. 

Some comments, including one from 

one of the accreditation bodies named 

in the proposed regulations, suggested 

that the final regulations specify the 

type of accreditation needed from the 

two named accreditation bodies to 

include International Organization for 

Standardization (ISO) standard 14065 

and 14064–3. One of these comments 

noted that the CA LCFS program, one of 

the two named accreditation bodies, 

draws from ISO 14065 and 14064–3. 

The Treasury Department and the IRS 

agree that, in the case of ANABaccredited validation and verification 

bodies, the proposed regulations lack 

needed specificity. Accordingly, these 


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final regulations adopt the proposed 

regulations with a modification to limit 

the pool of ANAB-accredited qualified 

verifiers to those accredited under the 

ANAB Accreditation Program for 

Greenhouse Gas Validation and 

Verification Bodies. 

I. Unrelated Party 

Proposed § 1.45V–5(i) would have 

defined, for purposes of section 

45V(c)(2)(B)(ii), the term ‘‘unrelated 

party’’ to mean a qualified verifier who 

meets the requirements of proposed 

§ 1.45V–5(e). No comments addressed 

this provision, so these final regulations 

adopt it as proposed. 

J. Requirements for Taxpayers Claiming 

Both the Section 45V Credit and the 

Section 45 Credit or the Section 45U 

Credit 

Section 45(e)(13) provides that 

electricity produced by the taxpayer 

shall be treated as sold by such taxpayer 

to an unrelated person during the 

taxable year if such electricity is used 

during such taxable year by the taxpayer 

or a person related to the taxpayer at a 

qualified clean hydrogen production 

facility to produce qualified clean 

hydrogen, and such use and production 

is verified (in such form or manner as 

the Secretary may prescribe) by an 

unrelated third party. 

Section 45U(c)(2) provides, among 

other things, that rules similar to the 

rules of section 45(e)(13) shall apply for 

purposes of section 45U. 

Proposed § 1.45V–5(j) would have 

provided requirements for taxpayers 

claiming the section 45V credit 

concurrently with either the section 45 

credit or the section 45U credit. No 

comments addressed this provision, so 

these final regulations adopt it as 

proposed with a minor clarification to 

§ 1.45V–5(j)(3) that electricity 

represented by an EAC must be both 

acquired and retired. 

K. Timely Verification Report 

Proposed § 1.45V–5(k) would have 

provided that a verification report must 

be signed and dated by the qualified 

verifier no later than (i) the due date, 

including extensions, of the Federal 

income tax return or information return 

for the taxable year during which the 

hydrogen undergoing verification is 

produced; or (ii) in the case of a section 

45V credit first claimed on an amended 

return or AAR, the date on which the 

amended return or AAR is filed. 

Some comments expressed concern 

that a late verification report, filed with 

a taxpayer’s return after the extended 

return filing due date for the taxable 

year of hydrogen production, would 

preclude taxpayers from making an 

elective payment election under section 

6417 or a transferability election under 

section 6418. These comments were 

addressed in part I.C of this Summary 

of Comments and Explanation of 

Revisions. 

One comment said the final 

regulations should allow for a late 

verification report to be filed with an 

amended return, reading the proposed 

regulations as allowing this in the first 

year only. While not entirely clear, the 

comment appeared to be requesting 

clarification that, for purposes of section 

45V, a taxpayer may submit a late 

verification report with an amended 

return or AAR for any taxable year 

during the 10-year credit period, and 

not just the first year. 

The Treasury Department and the IRS 

agree that further clarification is needed. 

As written, the proposed regulations 

could be read to suggest that a taxpayer 

may only file a late verification report 

on an amended return in the first 

taxable year of production. That result 

was not intended. Accordingly, § 1.45V– 

5(k)(2) is modified to provide that, in 

the case of a credit first claimed for the 

taxable year on an amended return or 

AAR, the verification report must be 

filed by the date on which the amended 

return or AAR is filed. This 

modification is intended to clarify that 

a late-filed verification report may be 

filed on an amended return for any 

taxable year during the 10-year credit 

period and not just the first taxable year 

of production. 

V. Rules for Determining the Placed in 

Service Date for an Existing Facility 

That is Modified To Produce Qualified 

Clean Hydrogen 

A. Modification of an Existing Facility 

Under section 45V(d)(4), in the case of 

any facility that was originally placed in 

service before January 1, 2023, and, 

prior to the modification (described in 

section 45V(d)(4)(B)), did not produce 

qualified clean hydrogen, and after the 

date the facility was originally placed in 

service (i) is modified to produce 

qualified clean hydrogen, and (ii) 

amounts paid or incurred with respect 

to the modification are properly 

chargeable to the taxpayer’s capital 

account, the facility will be deemed to 

have been originally placed in service as 

of the date the property required to 

complete the modification is placed in 

service. The rule in section 45V(d)(4) for 

modification of existing facilities 

applies to modifications made after 

December 31, 2022. See § 13204(a)(5)(C) 

of the IRA. 

Proposed § 1.45V–6(a)(1) would have 

incorporated the statutory provisions of 

section 45V(d)(4). Proposed § 1.45V– 

6(a)(2) would have provided that an 

existing facility will not be deemed to 

have been originally placed in service as 

of the date the property required to 

complete the modification is placed in 

service unless the modification is made 

for the purpose of enabling the facility 

to produce qualified clean hydrogen and 

the taxpayer pays or incurs an amount 

with respect to such modification that is 

properly chargeable to the taxpayer’s 

capital account for the facility. Proposed 

§ 1.45V–6(a)(2) would also have 

provided that a modification is made for 

the purpose of enabling the facility to 

produce qualified clean hydrogen if the 

facility could not produce hydrogen 

with a lifecycle GHG emissions rate that 

is less than or equal to 4 kilograms of 

CO2e per kilogram hydrogen but for the 

modification. Changing inputs to the 

hydrogen production facility, such as 

switching from conventional natural gas 

to renewable natural gas, would not 

qualify as a facility modification for 

purposes of proposed § 1.45V–6(a)(2). 

Proposed § 1.45V–6(c) would have 

provided three examples illustrating the 

application of the rules provided by 

section 45V(d)(4) and § 1.45V–6(a). 

Several comments were received on 

proposed § 1.45V–6(a)(1) and (2). Some 

comments requested that the final 

regulations provide that changing the 

fuel input in the hydrogen production 

process, such as changing from natural 

gas to renewable natural gas, qualifies as 

a facility modification for purposes of 

section 45V(d)(4). These comments 

further suggested that acquiring new 

feedstocks for the purpose of enabling 

the hydrogen production facility to 

produce qualified clean hydrogen 

should constitute a facility 

modification. Several other comments 

suggested that the final regulations 

should clarify that acquiring new 

feedstocks and the associated 

components needed to process such 

feedstocks, or constructing a new 

facility to produce such feedstocks, for 

the purpose of enabling the facility to 

produce qualified clean hydrogen, 

constitutes a facility modification, 

provided the amounts paid or incurred 

with respect to such modification are 

properly chargeable to the capital 

account of the taxpayer. 

It is not appropriate to provide a 

special rule that changing fuel inputs or 

investing in new feedstock production 

technology is a modification under 

section 45V(d)(4). Section 

45V(d)(4)(B)(ii) specifically requires that 

expenditures made with respect to a 

modification must be properly 


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chargeable to the taxpayer’s capital 

account. Changing fuel inputs, without 

more, would not satisfy this statutory 

requirement. However, to the extent 

new components are installed in the 

hydrogen production facility in order to 

enable the facility to consume a 

different type of fuel that would enable 

the facility to produce qualified clean 

hydrogen, and to the extent such 

components are chargeable to the 

capital account of the taxpayer, then the 

installation of such new components 

would qualify as a modification under 

section 45V(d)(4), assuming all other 

requirements of § 1.45V–6(a)(2) are met. 

Regarding investing in new feedstock 

production technology, such investment 

would not constitute a modification 

under section 45V(d)(4) because it is not 

a modification to the hydrogen 

production facility, but instead a 

modification to the feedstock 

production facility. 

Accordingly, these regulations retain 

the proposed approach and have 

clarified in § 1.45V–6(a)(2) that merely 

changing fuel inputs does not constitute 

a modification under section 45V(d)(4). 

Additionally, § 1.45V–1(a)(7)(ii)(B) is 

modified to clarify that feedstock 

production equipment is not part of the 

facility for purposes of section 

45V(c)(3). 

Several other comments requested 

that the final regulations clarify that 

there is no monetary threshold required 

for any capital expenditure paid or 

incurred with respect to modifications 

made to an existing facility originally 

placed in service before January 1, 2023, 

in order to enable the facility to produce 

qualified clean hydrogen, assuming all 

other requirements are met, for such 

facility to qualify under section 

45V(d)(4) for a new deemed originally 

placed in service date. 

These final regulations do not provide 

a rule specifying a monetary threshold. 

The relevant inquiry under section 

45V(d)(4) and §§ 1.45V–6(a)(1) and (2) is 

whether the modification is made for 

the purpose of enabling the facility to 

produce qualified clean hydrogen and 

whether the taxpayer pays or incurs an 

amount with respect to such 

modification that is properly chargeable 

to the taxpayer’s capital account. As set 

forth in § 1.45V–6(a)(2), the taxpayer 

must make a capital expenditure with 

respect to the modification, but there is 

no requirement that such expenditure 

satisfies a certain monetary threshold. 

To the extent the capital expenditure is 

for a modification that enables the 

facility to produce qualified clean 

hydrogen and the facility would not 

otherwise be able to produce qualified 

clean hydrogen but for the modification, 

such expenditure would satisfy the 

requirements of § 1.45V–6(a)(2), 

regardless of amount. Because section 

45V(d)(4) and § 1.45V–6(a)(2) are 

sufficiently clear to enable taxpayers to 

determine whether their expenditure 

satisfies the requirements for the facility 

to receive a new deemed originally 

placed in service date, any further rules 

regarding a monetary threshold beyond 

the statutory text are unnecessary. 

Finally, one comment requested that 

the final regulations provide that an 

existing facility that is modified to 

capture hydrogen that would have been 

flared or released but that is instead put 

to productive use is deemed to have 

been originally placed in service as of 

the date the modifications were placed 

in service. Although unclear, this 

comment appears to be requesting that 

an existing facility that previously 

produced qualified clean hydrogen 

before it was modified to capture such 

hydrogen be entitled to a new originally 

placed in service date under section 

45V(d)(4). It would be inappropriate to 

provide such a rule. To the extent a 

facility produced qualified clean 

hydrogen before it was modified to 

capture such hydrogen, such 

modification would not meet the 

requirements of § 1.45V–6(a)(2) because 

the modification was not for the 

purpose of enabling the facility to 

produce qualified clean hydrogen. If, on 

the other hand, the facility did not 

produce qualified clean hydrogen before 

it was modified to capture hydrogen, 

then such modification could meet the 

requirements of § 1.45V–6(a)(2), 

provided that the modification enables 

the facility to produce qualified clean 

hydrogen. Whether the facility produces 

qualified clean hydrogen would depend 

on the lifecycle GHG emissions rate of 

the hydrogen production process. 

Because such inquiry would depend on 

the lifecycle GHG emissions rate of the 

hydrogen production process and is fact 

specific, these final regulations do not 

include a special rule for this scenario 

in the regulatory text. 

B. Retrofit of an Existing Facility 

Proposed § 1.45V–6(b) would have 

provided that an existing facility may 

establish a new date on which it is 

considered originally placed in service 

for purposes of section 45V, even 

though the facility contains some used 

property, provided the fair market value 

of the used property is not more than 20 

percent of the facility’s total value (the 

cost of the new property plus the value 

of the used property) (80/20 Rule). 

Proposed § 1.45V–6(b) would have 

further provided that for purposes of the 

80/20 Rule, the cost of new property 

includes all properly capitalized costs of 

the new property included within the 

facility. Proposed § 1.45V–6(b) would 

have provided that, if a facility satisfies 

the requirements of the 80/20 Rule, then 

the date on which such facility is 

considered originally placed in service 

for purposes of section 45V(a)(1) is the 

date on which the new property added 

to the facility is placed in service. 

Proposed § 1.45V–6(b) would also have 

provided 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 (before 

application of proposed § 1.45V–6(b)). 

Examples 4 and 5 of proposed § 1.45V– 

6(c) would have provided examples 

illustrating the application of the 80/20 

Rule. 

Several comments were received on 

the 80/20 Rule and proposed § 1.45V– 

6(b). Some comments requested 

clarification on what is included in the 

definition of an ‘‘existing facility’’ for 

purposes of the 80/20 Rule and whether 

the 80/20 Rule applies only to existing 

hydrogen production facilities, or 

whether it applies to all existing 

facilities regardless of whether they 

previously produced hydrogen. 

Similarly, one comment suggested that 

the term ‘‘existing facility’’ could mean 

a purchased facility or an already 

existing facility owned by the taxpayer. 

Other comments requested clarification 

as to whether a facility that otherwise 

meets the modification rule of section 

45V(d)(4) would also be required to 

meet the 80/20 Rule in order to receive 

a new originally placed in service date. 

One comment requested that the 80/20 

Rule only be applied to existing 

hydrogen production facilities. This 

comment further suggested that the final 

regulations should clarify that, for 

purposes of the 80/20 Rule, the unit of 

property to which the 80/20 Rule 

applies is a single production line as 

defined in proposed § 1.45V–1(a)(7)(i). 

For example, with respect to a project 

with multiple production lines that are 

capable of independently producing 

qualified clean hydrogen, this comment 

requested that the final regulations 

clarify that the 80/20 Rule would apply 

separately to each such production line. 

One comment requested clarification 

on the extent to which used components 

of property owned by another person 

that function interdependently with 

components of property owned by the 

taxpayer to produce qualified clean 

hydrogen must be taken into 

consideration for purposes of the 80/20 

Rule. This comment provided the 

example of transmission pipelines not 


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owned by the taxpayer but that are used 

to import methane to the hydrogen 

production facility, and asked whether 

such components would need to be 

taken into consideration for purposes of 

the 80/20 Rule. 

One comment requested clarification 

on the extent to which roads, fences, 

buildings, land, and other ancillary 

property may be considered part of a 

qualified clean hydrogen production 

facility that must be taken into account 

for purposes of the 80/20 Rule. 

Finally, one comment requested that 

proposed § 1.45V–6(b) be modified to 

allow taxpayers to exclude the cost of 

any maintenance, repairs, or upgrades 

when determining the value of used 

property for purposes of the 80/20 Rule. 

The Treasury Department and the IRS 

agree that further clarification of the 80/ 

20 Rule is appropriate. The proposed 

80/20 Rule could have been interpreted 

to apply to all existing facilities, 

including those that satisfy the 

modification requirements of section 

45V(d)(4) to receive a new deemed 

originally placed in service date. This 

was not the intent of proposed § 1.45V– 

6(b). Accordingly, the final regulations 

clarify in § 1.45V–6(a)(3) that a facility 

that satisfies the requirements of section 

45V(d)(4) does not also need to meet the 

80/20 Rule in order to be deemed to be 

originally placed in service as of the 

date that the property required for the 

modification is placed in service. 

Proposed § 1.45V–6(b) is also modified 

to clarify the scope of the 80/20 Rule. 

The final regulations under § 1.45V–6(b) 

now provide that the 80/20 Rule applies 

to retrofitted hydrogen production 

facilities and that the 80/20 Rule applies 

separately to each single production line 

containing used property. 

These final regulations do not provide 

further rules addressing the extent to 

which used property owned by another 

person must be taken into consideration 

for purposes of the 80/20 Rule because 

existing Federal income tax concepts are 

sufficient to address the question posed 

in the comment. Likewise, these final 

regulations do not clarify whether roads, 

fences, buildings, land, or other 

ancillary property are part of the 

qualified clean hydrogen production 

facility for purposes of the 80/20 Rule. 

Existing Federal income tax concepts 

are sufficient to address this question. In 

determining the value of old or existing 

equipment as compared to new 

equipment, the general principles of 

Revenue Ruling 94–31 apply. Revenue 

Ruling 94–31 provides that a facility 

would qualify as originally placed in 

service even though it 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 cost of the new property plus 

the value of the used property). Some 

changes to the definition of ‘‘facility’’ 

are needed to clarify that feedstock 

transportation or feedstock transmission 

equipment, such as electricity 

transmission equipment, is not part of 

the qualified clean hydrogen production 

facility. Accordingly, proposed § 1.45V– 

1(a)(7)(ii)(B) is revised to exclude 

feedstock transmission equipment from 

the definition of ‘‘facility.’’ 

Finally, regarding whether proposed 

§ 1.45V–6(b) should be modified to 

allow taxpayers to exclude the cost of 

maintenance, repairs, or upgrades from 

the value of used equipment for 

purposes of the 80/20 Rule, the final 

regulations do not adopt these 

suggestions because they are 

inconsistent with Federal income tax 

principles underlying the 80/20 Rule. 

VI. Election To Treat Clean Hydrogen 

Production Facility as Energy Property 

A. Overview 

Section 48(a)(15) allows a taxpayer 

that owns and places in service a 

specified clean hydrogen production 

facility (as defined in section 

48(a)(15)(C)) to make an irrevocable 

election to claim the section 48 credit in 

lieu of the section 45V credit for any 

qualified property (as defined in section 

48(a)(5)(D)) that is part of the facility. 

Section 13204(c)(3) of the IRA provides 

that this provision is effective for 

property placed in service after 

December 31, 2022. For any property 

that is placed in service after December 

31, 2022, and the construction of which 

begins before January 1, 2023, 

§ 13204(c)(3) of the IRA provides that 

section 48(a)(15) applies only to the 

extent of the basis of such property that 

is attributable to construction, 

reconstruction, or erection occurring 

after December 31, 2022. 

Proposed § 1.48–15(a) would have 

provided that a taxpayer that owns and 

places in service a specified clean 

hydrogen production facility (as defined 

in section 48(a)(15)(C) and proposed 

§ 1.48–15(b)) can make an irrevocable 

election under section 48(a)(15)(C)(ii)(II) 

to treat any qualified property (as 

defined in section 48(a)(5)(D)) that is 

part of the facility as energy property for 

purposes of section 48. 

Proposed § 1.48–15(b) would have 

defined the term ‘‘specified clean 

hydrogen production facility’’ to mean 

any qualified clean hydrogen 

production facility (within the meaning 

of section 45V(c)(3) and proposed 

§ 1.45V–1(a)(10)): (i) that is placed in 

service after December 31, 2022; (ii) 

with respect to which no section 45V 

credit or section 45Q credit has been 

allowed, and for which the taxpayer 

makes an irrevocable election to have 

section 48(a)(15) apply; and (iii) for 

which an unrelated party has verified in 

the manner specified in proposed 

§ 1.48–15(e) that such facility produces 

hydrogen through a process that results 

in lifecycle GHG emissions that are 

consistent with the hydrogen that such 

facility was designed and expected to 

produce under section 48(a)(15)(A)(ii) 

and proposed § 1.48–15(c). 

Proposed § 1.48–15(c)(1) would have 

provided the energy percentage (used by 

a taxpayer to calculate a section 48 

credit) for a specified clean hydrogen 

production facility that is designed and 

reasonably expected to produce 

qualified clean hydrogen through a 

process that results in a lifecycle GHG 

emissions rate of not greater than 4 

kilograms of CO2e per kilogram of 

hydrogen. Proposed § 1.48–15(c)(2) 

would have further provided that 

‘‘designed and reasonably expected to 

produce’’ means hydrogen produced 

through a process that results in the 

lifecycle GHG emissions rate specified 

in the annual verification report for the 

taxable year in which the section 

48(a)(15) election is made. 

The Treasury Department and the IRS 

solicited feedback on the proposed 

definition of the term ‘‘designed and 

reasonably expected to produce’’ and 

whether there are any challenges to 

using the lifecycle GHG emissions rate 

achieved in the taxable year in which 

the section 48(a)(15) election is made to 

determine the facility’s energy 

percentage for purposes of calculating 

the section 48 credit amount. No 

comment addressed the definition of the 

term ‘‘designed and reasonably expected 

to produce’’ or the challenges of using 

the lifecycle GHG emissions rate 

determined in the year the election 

takes place. However, one comment 

recommended that the final regulations 

allow for taxpayers that make the 

section 48(a)(15) election to determine 

their energy percentage by using a 

lifecycle GHG emissions rate achieved 

in a later taxable year. Section 48(a)(1) 

generally provides that the energy credit 

for any taxable year is the energy 

percentage of the basis of each energy 

property placed in service during such 

taxable year. This means that while a 

taxpayer is required to determine the 

lifecycle GHG emissions rate of the 

hydrogen undergoing verification each 

year of the recapture period specified in 

proposed § 1.48–15(f)(3), the credit 

amount may only be determined based 

on the lifecycle GHG emissions rate of 

the hydrogen produced in the year the 


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specified clean hydrogen production 

facility is placed in service. Allowing 

the use of a lifecycle GHG emissions 

rate achieved in a later taxable year is 

inconsistent with section 48(a)(1), since 

the section 48 credit is claimed only in 

the taxable year in which energy 

property is placed in service. Therefore, 

these final regulations adopt these 

proposed rules without change on these 

issues. 

The proposed regulations would have 

required for each facility an annual 

assessment of the lifecycle GHG 

emissions rate for purposes of 

determining the rate at which a facility 

is designed and reasonably expected to 

produce qualified clean hydrogen, for 

verification purposes, and in 

determining whether a recapture event 

has occurred. In determining the 

amount of the section 45V credit and 

whether hydrogen is qualified clean 

hydrogen, the final regulations require a 

determination of lifecycle GHG 

emissions for each hydrogen production 

process conducted by a facility during a 

taxable year. However, applying a 

process-by-process-based approach to 

determining lifecycle GHG emissions 

rates for hydrogen production in the 

context of the section 48(a)(15) election 

could lead to a facility producing 

hydrogen in processes that result in 

multiple different emissions rates 

within a taxable year, which is 

inconsistent with the statutory scheme 

applicable to specified clean hydrogen 

production facilities and would be 

difficult to administer. Thus, the final 

regulations retain the single annual 

lifecycle GHG emissions rate assessment 

requirement for specified clean 

hydrogen production facilities for 

purposes of the section 48(a)(15) 

election by requiring, in the case of a 

facility that produces hydrogen through 

multiple processes, that the lifecycle 

GHG emissions rate be determined 

using the weighted average of the 

lifecycle GHG emissions rates of all 

hydrogen production processes. An 

annual assessment for each qualified 

clean hydrogen production facility best 

implements the statutory directive in 

section 48(a)(15)(A)(ii)(I) through (IV) 

and (C)(iii) to determine eligibility for 

and the amount of the section 48 credit 

based on the ‘‘lifecycle greenhouse gas 

emissions which are consistent with the 

hydrogen that such facility was 

designed and expected to produce.’’ 

B. Election Procedures 

1. Time and Manner of Making Election 

Proposed § 1.48–15(d)(1) would have 

provided rules for making an election 

under section 48(a)(15)(C)(ii)(II). To 

make such an election, a taxpayer must 

claim the section 48 credit with respect 

to a specified clean hydrogen 

production facility on a Form 3468, 

Investment Credit, or any successor 

form(s), and file the form with the 

taxpayer’s Federal income tax return or 

information return for the taxable year 

in which the specified clean hydrogen 

production facility is placed in service. 

The taxpayer must also attach a 

statement to its Form 3468, or any 

successor form(s), filed with its Federal 

income tax return or information return 

that includes all the information 

required by the instructions to Form 

3468, or any successor form(s), for each 

specified clean hydrogen production 

facility subject to an election. Proposed 

§ 1.48–15(d)(1) would have provided 

that a separate election must be made 

for each specified clean hydrogen 

production facility that meets the 

requirements provided in section 

48(a)(15) to treat the qualified property 

that is part of the facility as energy 

property. 

Proposed § 1.48–15(d)(1) would have 

further provided that, if any taxpayer 

owning an interest in a specified clean 

hydrogen production facility makes an 

election with respect to the facility, then 

that election would be binding on all 

taxpayers that directly or indirectly own 

an interest in the facility. Thus, 

consistent with section 48(a)(15)(B), if a 

taxpayer owning an interest in a 

specified clean hydrogen production 

facility makes an election under section 

48(a)(15)(C)(ii)(II), then no other 

taxpayer owning an interest in the same 

facility will be allowed a section 45V 

credit or section 45Q credit with respect 

to the facility or any carbon capture 

equipment included at such facility. 

The Treasury Department and the IRS 

requested comments on whether, in the 

context of a specified clean hydrogen 

production facility that is directly 

owned through an arrangement properly 

treated as a tenancy-in-common for 

Federal income tax purposes or through 

an organization that has made a valid 

election under section 761(a) of the 

Code, each co-owner’s or member’s 

undivided ownership share of the 

qualified property comprised in the 

facility should be treated for purposes of 

section 48(a)(15)(C)(ii)(II) as a separate 

facility owned by such co-owner or 

member, with each such co-owner or 

member eligible to make a separate 

election under section 48(a)(15)(C)(ii)(II) 

to claim the section 48 credit in lieu of 

the section 45V credit with respect to its 

undivided ownership interest in the 

facility or share of the underlying 

qualified property. No comments were 

received in response to this request. 

One comment requested that the 

Treasury Department and the IRS clarify 

how to allocate costs and benefits of a 

qualified clean hydrogen production 

facility for purposes of determining the 

section 45V and section 48 credit 

amounts. To the extent the comment 

sought clarification on how one 

taxpayer can claim both credits on the 

same facility, the election to claim the 

section 48 credit in lieu of the section 

45V credit is made on the entire 

specified clean hydrogen production 

facility. If a taxpayer makes the election 

with respect to a specified clean 

hydrogen production facility, then no 

section 45V credit is allowed to the 

taxpayer with respect to such facility. 

Therefore, no allocation between the 

two credits for the same facility is 

allowed. Alternatively, to the extent the 

comment sought clarification on how to 

allocate the section 45V credit amount 

to co-owners of the same qualified clean 

hydrogen production facility, sections 

45V(d)(1) and 45(e)(3) provide rules for 

how to allocate the section 45V credit 

amount to co-owners. As set forth in 

section 45(e)(3), in the case of a facility 

in which more than one person has an 

ownership interest, production from the 

facility is allocated among such persons 

in proportion to their ownership 

interests in the gross sales from such 

facility. No clarification is needed under 

proposed § 1.48–15(d)(1) and thus, these 

final regulations adopt this provision 

without change. 

2. Special Rule for Partnerships and S 

Corporations 

Proposed § 1.48–15(d)(2) would have 

provided that, in the case of a specified 

clean hydrogen production facility 

owned by a partnership or an S 

corporation, the election under section 

48(a)(15)(C)(ii)(II) would be made by the 

partnership or S corporation and would 

be binding on all ultimate credit 

claimants (as defined in § 1.50– 

1(b)(3)(ii)). Proposed § 1.48–15(d)(2) 

further provided procedures for a 

partnership or S corporation to make an 

election with respect to a specified 

clean hydrogen production facility 

under section 48(a)(15)(C)(ii)(II). No 

comments were received on proposed 

§ 1.48–15(d)(2), and the final regulations 

adopt this provision without substantive 

change. 

3. Election Revocability 

Proposed § 1.48–15(d)(3) would have 

provided that the election to treat any 

qualified property that is part of a 

specified clean hydrogen production 

facility as energy property would be 

irrevocable. No comments were received 

on proposed § 1.48–15(d)(3), and this 


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2302 Federal Register / Vol. 90, No. 6 / Friday, January 10, 2025 / Rules and Regulations 

provision is adopted without change in 

these final regulations. 

4. Election Availability Date 

Proposed § 1.48–15(d)(4) would have 

provided that the election to treat any 

qualified property that is part of a 

specified clean hydrogen production 

facility as energy property would be 

available for property placed in service 

after December 31, 2022, and, for any 

property that began construction before 

January 1, 2023, only to the extent of the 

basis thereof attributable to the 

construction, reconstruction, or erection 

after December 31, 2022. No comments 

were received on proposed § 1.48– 

15(d)(4), and these final regulations 

adopt this provision without change. 

5. Beginning of Construction Safe 

Harbor 

These final regulations add § 1.48– 

15(d)(5), which provides that a taxpayer 

may, in its discretion, make an 

irrevocable election effective for the 

remaining taxable years within the 

period described in § 1.48–15(f)(3), to 

treat the latest version of 45VH2–GREET 

that was publicly available on the date 

when construction of the specified clean 

hydrogen production 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, § 1.48–15(d)(5) provides that 

taxpayers may make an irrevocable 

election to treat the first publiclyavailable version of 45VH2–GREET (that 

is, the version of 45VH2–GREET 

released in December 2023) as the 

45VH2–GREET Model for the remaining 

taxable years within the period 

described in § 1.48–15(f)(3). In the case 

of a facility that is modified to produce 

qualified clean hydrogen under section 

45V(d)(4) 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. Under 

§ 1.48–15(d)(5)(ii), a taxpayer makes this 

election by attaching a statement to the 

Form 3468 or any successor form(s). The 

taxpayer must make this election no 

later than 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. 

A taxpayer who placed its facility in 

service before January 1, 2024, must 

make the election by no later than the 

close of the period of limitation on filing 

a claim for credit or refund under 

section 6511(a) for the taxable period in 

which such facility is placed in service. 

6. Provisional Emissions Rate 

Neither section 48 nor the proposed 

regulations contain a specific provision 

addressing a PER for energy credit 

purposes, leaving a procedural gap for 

obtaining a PER should a taxpayer that 

owns and places in service a specified 

clean hydrogen production facility (as 

defined in section 48(a)(15)(C) and 

§ 1.48–15) make an irrevocable election 

under section 48(a)(15)(C)(ii)(II) to treat 

any qualified property (as defined in 

section 48(a)(5)(D)) that is part of the 

facility as energy property for purposes 

of section 48. To address this procedural 

gap, these final regulations add § 1.48– 

15(d)(6), which provides the procedures 

for obtaining a PER for such taxpayers. 

This provision largely tracks the PER 

rules of § 1.45V–4(c). 

Section 1.48–15(d)(6)(i) provides that 

a taxpayer files a petition with the 

Secretary for a PER by following the 

procedures stated in § 1.45V–4(c)(3) 

through (5), except, in lieu of attaching 

the PER petition to the Form 7210 in the 

first taxable year of production as 

specified in § 1.45V–4(c)(3), the 

taxpayer must attach the PER petition to 

the Form 3468, Investment Credit, or a 

successor form, attached to the 

taxpayer’s Federal income tax return for 

the taxable year in which the specified 

clean hydrogen production facility is 

placed in service. A taxpayer may use 

such PER to calculate the amount of the 

section 48 credit with respect to a 

specified clean hydrogen production 

facility, provided that (1) the lifecycle 

GHG emissions rate of the hydrogen 

produced at the specified clean 

hydrogen production facility has not 

been determined (for purposes of 

section 45V(c)(2)(C)) under the 45VH2– 

GREET Model, (2) 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 § 1.45V–4(c)(2)(i), and (3) all 

other requirements of section 48(a)(15) 

are met. These final regulations further 

provide that a ‘‘material change’’ means 

any change that would cause a qualified 

verifier (as defined § 1.45V–5(h)) to be 

unable to complete a verification under 

§ 1.48–15(e). 

Further, § 1.48–15(d)(6)(iii) is added 

to provide that a taxpayer may, in its 

discretion, make an irrevocable election, 

effective for the remaining taxable years 

within the period described in § 1.48– 

15(f)(3), to treat the first version of 

45VH2–GREET that includes the 

taxpayer’s specified clean hydrogen 

production facility’s hydrogen 

production pathway (as described in 

§ 1.45V–4(c)(2)(i)) as the 45VH2–GREET 

Model. A taxpayer makes this election 

by attaching a statement to the Form 

3468 or any successor form(s). The 

taxpayer must make this election by no 

later than the due date for filing its 

Federal income tax return or 

information return (including 

extensions) for the taxable period in 

which the taxpayer’s facility is placed in 

service. A taxpayer who placed its 

specified clean hydrogen production 

facility in service before January 1, 

2024, must make this election by no 

later than the close of the period of 

limitation for filing a claim for credit or 

refund under section 6511(a) for the 

taxable period in which such facility is 

placed in service. 

Further, § 1.48–15(d)(6)(iv) is added 

to provide that, notwithstanding the 

requirement of § 1.48–15(d)(6)(i)(A), a 

taxpayer who received an emissions 

value from the DOE with respect to a 

specified clean hydrogen production 

facility (pursuant to § 1.45V–4(c)(2)(i)) 

before the date when construction of the 

facility began may, in its discretion, 

continue to use the PER determined by 

the Secretary and the associated 

emissions value to calculate the 

lifecycle GHG emissions rate of the 

hydrogen produced at the specified 

clean hydrogen production facility for 

the remainder of the period described in 

§ 1.48–15(f)(3), provided that the 

taxpayer continues to satisfy the 

requirements of §§ 1.48–15(d)(6)(i)(B) 

and (C). 

Finally, § 1.48–15(d)(6)(v) is added to 

provide that 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 48 credit is claimed. For 

example, the annual verification report 

submitted under section 48(a)(15)(C)(iii) 

and § 1.48–15(e)(2) 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 48, including 

the cross-references to section 45V, have 

been satisfied for any taxable year. 

C. Third-Party Verification 

Proposed § 1.48–15(e)(1) would have 

provided that, in the case of a taxpayer 

that makes an election under section 

48(a)(15)(c)(ii)(II) to treat any qualified 

property that is part of a specified clean 


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hydrogen production facility as energy 

property for purposes of the section 48 

credit, the taxpayer must obtain an 

annual verification report for the taxable 

year in which the election is made and 

for each taxable year thereafter of the 

recapture period specified in proposed 

§ 1.48–15(f)(3). Proposed § 1.48–15(e)(1) 

would have further provided that the 

taxpayer must also submit the annual 

verification report as an attachment to 

the Form 3468, or any successor form(s), 

for the taxable year in which the 

election is made. 

Proposed § 1.48–15(e)(2) would have 

provided procedures for the annual 

verification report, including where a 

transfer election has been made under 

section 6418(a) of the Code with respect 

to the section 48 credit for a specified 

clean hydrogen production facility. 

No comments were received on 

proposed § 1.48–15(e). These final 

regulations adopt this provision without 

substantive change, other than 

conforming changes to modifications 

previously noted. 

D. Credit Recapture 

Section 48(a)(15)(E) directs the 

Secretary to issue such regulations or 

other guidance as determined necessary 

to carry out the purposes of section 48, 

including regulations or other guidance 

addressing recapture of so much of the 

credit allowed under section 48 as 

exceeds the amount of the credit that 

would have been allowed if the 

expected production were consistent 

with the actual verified production or 

all of the credit so allowed in the 

absence of such verification. 

1. Emissions Tier Recapture Events 

Under Section 48(a)(15)(E) 

Proposed § 1.48–15(f)(1) would have 

provided that, for purposes of section 

48(a)(15)(E), in any taxable year of the 

recapture period specified in proposed 

§ 1.48–15(f)(3) in which an emissions 

tier recapture event (as defined in 

proposed § 1.48–15(f)(2)) occurs, the tax 

imposed on the taxpayer under chapter 

1 of the Code for the taxable year of the 

emissions tier recapture event is 

increased by the recapture amount 

specified in proposed § 1.48–15(f)(4). 

Proposed § 1.48–15(f)(2) would have 

provided that an emissions tier 

recapture event under section 

48(a)(15)(E) occurs during any taxable 

year of the recapture period specified in 

proposed § 1.48–15(f)(3) under the 

following circumstances: (i) the 

taxpayer fails to obtain an annual 

verification report by the deadline for 

filing its Federal income tax return or 

information return (including 

extensions) for any taxable year in 

which an annual verification report was 

required under proposed § 1.48– 

15(e)(1); (ii) the specified clean 

hydrogen production facility actually 

produced hydrogen through a process 

that results in a lifecycle GHG emissions 

rate that can only support a lower 

energy percentage than the energy 

percentage used to calculate the amount 

of the section 48 credit for such facility 

for the year in which the facility is 

placed in service; or (iii) the specified 

clean hydrogen production facility 

actually produced hydrogen through a 

process that results in a lifecycle GHG 

emissions rate of greater than 4 

kilograms of CO2e per kilogram of 

hydrogen. 

No comments were received on 

proposed § 1.48–15(f)(1) and (2). These 

final regulations adopt these provisions 

without substantive change. 

2. Recapture Period Under Section 

48(a)(15)(E) 

Proposed § 1.48–15(f)(3) would have 

provided that the recapture period 

begins on the first day of the first 

taxable year after the taxable year in 

which the facility was placed in service 

and ends on the last day of the fifth 

taxable year after the close of the taxable 

year in which the facility was placed in 

service. For example, if a calendar-year 

taxpayer places in service a specified 

clean hydrogen production facility on 

June 1, 2023, then the last day of the 

fifth taxable year following the close of 

the taxable year in which the facility 

was placed in service is December 31, 

2028. Therefore, the recapture period is 

January 1, 2024, through December 31, 

2028. 

No comments were received on 

proposed § 1.48–15(f)(3). These final 

regulations adopt this provision without 

change. 

3. Recapture Amount 

Proposed § 1.48–15(f)(4) would have 

provided rules for computing the 

amount recaptured under section 

48(a)(15)(E). Proposed § 1.48–15(f)(5) 

would have provided an example 

illustrating the application of proposed 

§ 1.48–15(f)(1) through (4). 

The preamble to the proposed 

regulations provided that, unless 

modified in future guidance, any 

reporting of emissions tier recapture 

under proposed § 1.48–15(f) is made on 

the taxpayer’s annual tax return. The 

preamble further provided that, the 

Secretary may issue future guidance 

and/or prescribe tax forms and 

instructions to address the reporting of 

emissions tier recapture under proposed 

§ 1.48–15(f) and any additional annual 

reporting obligations. The Treasury 

Department and the IRS solicited 

feedback on the reporting of recapture 

and any additional annual reporting 

obligations. No comments were received 

in response to this request, or on 

proposed § 1.48–15(f)(4) or (5) in 

general. These provisions are adopted as 

proposed with minor clarifications to 

the example in § 1.48–15(f)(5) to 

account for, among other things, the 

passage of time. However, as a 

clarification, the reporting of an 

emissions tier recapture event is 

reported using Form 4255, Recapture of 

Investment Credit, or any successor 

form(s), and the associated tax liability 

reported on the taxpayer’s annual 

return. 

4. Coordination With Recapture Rules 

Under Sections 50 and 48(a)(10)(C) 

Proposed § 1.48–15(f)(6) would have 

provided that, during any taxable year 

of the recapture period for any credit 

allowed under section 48(a) with 

respect to qualified property that is part 

of a specified clean hydrogen 

production facility, the recapture rules 

would be applied, if applicable, in the 

following order: (i) section 50(a) 

(recapture in case of dispositions, etc.); 

(ii) section 48(a)(10)(C) (recapture 

relating to the prevailing wage 

requirements); and (iii) section 

48(a)(15)(E) (emissions tier recapture). 

There were no comments received on 

proposed § 1.48–15(f)(6). These final 

regulations adopt the provision without 

substantive change. The final 

regulations also add two examples to 

illustrate the application of § 1.48– 

15(f)(6). 

E. Recordkeeping 

Proposed § 1.48–15(g) would have 

provided that, consistent with section 

6001 of the Code, a taxpayer making the 

election under section 48(a)(15)(C)(ii)(II) 

with respect to a specified clean 

hydrogen production facility must 

maintain and preserve records sufficient 

to establish the amount of the section 48 

credit claimed by the taxpayer. Further, 

proposed § 1.48–15(g) would have 

provided that, at a minimum, those 

records include records to substantiate 

the information required to be included 

in the annual verification report under 

proposed § 1.48–15(e)(2), records 

establishing that the facility meets the 

definition of a specified clean hydrogen 

production facility under section 

48(a)(15)(C) and proposed § 1.48–15(b), 

and records establishing the date the 

specified clean hydrogen production 

facility was placed in service. Finally, 

proposed § 1.48–15(g) would have 

provided that, if the increased section 

48 credit amount was allowed under 


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2304 Federal Register / Vol. 90, No. 6 / Friday, January 10, 2025 / Rules and Regulations 

section 48(a)(9), then the taxpayer must 

also maintain records in accordance 

with § 1.45–12. 

No comments were received with 

respect to proposed § 1.48–15(g). 

However, the intent of proposed § 1.48– 

15(g) was to conform the recordkeeping 

requirements for making the election 

under section 48(a)(15) with the 

recordkeeping requirements for 

claiming the credit under section 45V. 

Some of the recordkeeping requirements 

provided in proposed § 1.45V–2(c) were 

not provided in proposed § 1.48–15(g). 

For example, records of past credit 

claims under section 45Q by any 

taxpayer with respect to carbon capture 

equipment included at the facility, and 

the requirement that taxpayers retain all 

raw data used for submission of a 

request for an emissions value to the 

DOE for at least six years after the due 

date (including extensions) for filing the 

Federal income tax return or 

information return to which the PER is 

ultimately attached, were 

unintentionally omitted from proposed 

§ 1.48–15(g). Accordingly, conforming 

changes have been made to § 1.48–15(g) 

to include these items in the list of 

recordkeeping materials required to be 

maintained for taxpayers making the 

election under section 48(a)(15). 

Additionally, the final regulations add a 

requirement to retain the annual 

verification report required under 

§ 1.48–15(e)(2). 

VII. Additional Comments 

A. Interaction With Other Tax Credits 

Some comments requested 

clarification on the interaction of 

section 45V with other tax credits. One 

comment requested clarification that a 

renewable fuel facility that relies on a 

hydrogen production facility to produce 

renewable fuel is not part of the 

hydrogen production facility under 

proposed § 1.45V–1(a)(7). 

These final regulations do not specify 

the interaction of section 45V with other 

tax credits except as it relates to section 

45V(d)(2) and the prohibition on 

claiming the section 45Q credit. The 

Code sections themselves specify the 

interaction of section 45V with other tax 

credits. To the extent the statutes do not 

specify the interaction, imposing rules 

governing or restricting the section 45V 

credit on account of other tax credits 

whose statutes contain no such 

restriction would also not be applicable 

to this rulemaking. 

Regarding the request for clarification 

on whether a renewable fuel facility that 

relies on a hydrogen production facility 

to produce renewable fuel is not part of 

the hydrogen production facility, this 

comment appears to be requesting 

clarification on the scope of the 

definition of facility under section 45Z. 

The definition of facility under section 

45Z is beyond the scope of this 

rulemaking, and, therefore, is not 

addressed further herein. 

B. Additional Reporting and Disclosure 

Requirements 

Some comments requested that the 

final regulations impose additional 

reporting requirements on section 45V 

credit claimants, including to require 

claimants to publicize that they claimed 

the section 45V credit, the extent to 

which they engaged with the 

community, the amount of any 

emissions reductions associated with 

their section 45V credit claim, and 

various other hydrogen production 

activities such as water withdrawals, 

non-greenhouse gas air pollution, 

hydrogen leaks, and safety incidents. 

Similarly, some comments requested 

that the IRS disclose information about 

section 45V credit claims and the effect 

of section 45V credit claimants’ 

hydrogen production activities. 

Additional reporting and disclosure 

requirements are not incorporated into 

these final regulations. Section 45V does 

not impose any requirements on 

taxpayers to publicly disclose 

information about their section 45V 

credit claims or their hydrogen 

production activities. Further, section 

6103 of the Code prohibits the IRS from 

disclosing information about section 

45V credit claims, except as expressly 

authorized under another provision of 

the Code. Accordingly, imposing such 

additional reporting requirements, or 

disclosing information about section 

45V credit claims, would contravene the 

Code and is not adopted in these final 

regulations. 

Some comments requested that the 

Treasury Department and the IRS 

engage with environmental groups, 

industry participants, and the public in 

the implementation of the section 45V 

credit. Other comments requested that 

the Treasury Department and the IRS 

engage certain population groups, such 

as minorities, women, or veterans, to 

ensure meaningful participation by 

those groups. The Treasury Department 

and the IRS confirm that members of the 

public have been engaged on a broad 

basis through the notice and comment 

process and that public comments have 

been considered in issuing these final 

regulations. 

C. Additional Procedural Requirements 

One comment suggested that the 

Treasury Department and the IRS’s 

identification of 45VH2–GREET as the 

most recent GREET model under section 

45V(c)(1)(B) is an ‘‘incorporation by 

reference’’ and that, as such, 

modifications to 45VH2–GREET should 

be published in the Federal Register for 

notice and comment. This same 

comment noted that incorporation by 

reference generally refers to 

incorporating outside rules or sources 

into government regulations but posited 

that incorporation by reference can also 

apply to 45VH2–GREET. On this point, 

the comment did not request changes to 

the regulatory text. Furthermore, future 

events such as updates to 45VH2– 

GREET will not affect the text of these 

final regulations. 

Regarding incorporation by reference, 

the Secretary’s designation of 45VH2– 

GREET as a successor model under 

section 45V(c)(1)(B) is not an 

incorporation by reference. 

Incorporation by reference derives from 

5 U.S.C. 552(a)(1), which requires 

regulatory rules to be published in the 

Federal Register. Incorporation by 

reference of matters published outside 

of the Federal Register provides an 

exception to this requirement by 

deeming those matters as published in 

the Federal Register. See 5 U.S.C. 

551(a)(1). 

In this case, 45VH2–GREET is not 

required to be published in the Federal 

Register because it is a statutory 

requirement. Section 45V(c)(1)(B) 

provides that lifecycle GHG emissions 

‘‘shall only include emissions through 

the point of production (well-to-gate), as 

determined under the most recent 

Greenhouse gases, Regulated Emissions, 

and Energy use in Transportation model 

(commonly referred to as the ‘GREET 

model’) developed by Argonne National 

Laboratory, or a successor model (as 

determined by the Secretary).’’ As 

described in the Summary of Comments 

and Explanation of Revisions to these 

final regulations, the Secretary 

designated 45VH2–GREET as a 

successor model pursuant to that 

statutory directive, and 45VH2–GREET 

may also be appropriately considered 

the most recent GREET model. Because 

statutes may refer to matters that are not 

published in the Federal Register, the 

statutorily designated use of 45VH2– 

GREET as a successor model by the 

Secretary (or as the most recent GREET 

model) provides authorization, if not a 

direct mandate, to require the model’s 

use and therefore eliminates the need 

for incorporating it by reference. See 

United States v. Jackson, No. 1:07–CR– 

108–ODE–GGB, 2007 WL 9735479, at *3 

(N.D. Ga. Sept. 12, 2007), report and 

recommendation adopted, No. 1:07– 

CR–108–ODE, 2007 WL 9735481 (N.D. 

Ga. Oct. 23, 2007) (incorporation of 


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consumer price index as an inflation 

adjustor was not an APA violation); 

Clarry v. United States, 891 F. Supp. 

105, aff’d 85 F.3d 1041 (2d Cir. 1995) 

(‘‘[T]he APA’s notice requirements 

apply to rules formulated and adopted 

by an agency, not the application [of] a 

statute created by Congress.’’); Malkan 

FM Associates v. FCC, 935 F.2d 1313 

(D.C. Cir. 1991) (agency not required to 

publish in the Federal Register notices 

that radio tower height limit near 

Mexican border was lower than that 

prescribed by Federal Communication 

Commission’s (FCC’s) general rules; 

limit on tower height near border was 

set by international agreement and not 

by ‘‘rule’’ of the FCC). 

D. Comments Regarding Impacts on 

Specific Communities 

The Treasury Department and the IRS 

received several comments on the 

potential impact of the proposed 

regulations on specific communities, 

including Tribal communities, lowincome communities, and other 

communities with environmental justice 

concerns. The Treasury Department and 

the IRS take seriously concerns 

expressed by comments that relate to 

issues of environmental justice, 

consistent with the directives contained 

in previously issued Executive Orders. 

See, for example, E.O. 14096, 

Revitalizing Our Nation’s Commitment 

for Environmental Justice for All, (88 FR 

25251, April 21, 2023) and E.O. 12898, 

Federal Actions to Address 

Environmental Justice in Minority 

Populations and Low-Income 

Populations, (59 FR 7629, February 16, 

1994). 

One comment stated that hydrogen 

projects were often developed without 

consent from or consideration of or 

toward impacted communities, 

including Tribes. The comment 

recommended that the Treasury 

Department and the IRS implement a 

rule that requires taxpayers that claim 

the section 45V credit to show that they 

obtained consent from impacted 

communities, including Tribal nations, 

and that such consent was freely given 

prior to the start of any projects. 

Requiring applicants to show free, prior, 

and informed consent would reduce 

harms and the loss of resources that 

result from such subsidized hydrogen 

production, according to the comment. 

Other comments noted that the 

regulations might affect the hydrogen 

industry in ways harmful to certain 

communities, by incentivizing dirty 

production in those communities, 

increasing demand for water, or by 

failing to provide full incentives to 

hydrogen production that could be 

produced in certain communities, like 

so-called ‘‘blue’’ hydrogen. A comment 

suggested that the U.S. government is 

failing its trust responsibility with a 

particular Tribe by discouraging the 

production of blue hydrogen, which the 

comment states is a Tribal trust asset. 

The final regulations do not adopt 

these comments. Unlike some other IRA 

provisions, section 45V does not 

include rules that target investment in 

particular communities, on Indian land, 

or in any other specified geography. 

Compare section 45(b)(11) (relating to 

an increase in the production tax credit 

for qualified facilities located in energy 

communities), section 48(a)(14) (relating 

to increased investment tax credit rate 

for energy projects placed in service in 

energy communities), section 48(e) 

(relating to special rules for certain solar 

and wind facilities placed in service in 

connection with low-income 

communities), section 45Y(g)(7) 

(relating to an increase in the clean 

energy production credit for qualified 

facilities located in energy 

communities), section 48E(a)(3)(A) 

(relating to an increase in credit rate of 

the clean electricity investment credit 

for qualified facilities or energy storage 

technologies placed in service in energy 

communities), and section 48E(h) 

(relating to special rules for the clean 

electricity investment credit for certain 

facilities placed in service in connection 

with low-income communities). 

Nor does section 45V provide rules to 

specifically require a taxpayer to obtain 

the consent of impacted communities, 

or rules that would provide additional 

incentives for activity in those 

communities. Such regulation of actions 

between private parties related to the 

process for the production of clean 

hydrogen is not specifically authorized 

in section 45V. Moreover, for the 

reasons described in this Summary of 

Comments and Explanation of 

Revisions, these final regulations 

provide appropriate rules for clean 

hydrogen production regarding 

adequate safeguards, emissions 

determinations, and verification, 

consistent with the statute. With respect 

to comments stating concern regarding 

the lower section 45V credit amount for 

the production of certain types of 

qualified clean hydrogen, the statutory 

text of section 45V(b) unambiguously 

provides the applicable amount and 

applicable percentage for the section 

45V credit, which is based on lifecycle 

GHG emissions rates. 

With respect to Tribes, the Treasury 

Department and the IRS will continue to 

consider issues that may affect Tribes 

and Tribal stakeholders, including, for 

example, whether Tribes may regulate 

GHG emissions and how such 

regulations may affect the emissions 

determinations for qualified clean 

hydrogen. 

VIII. Applicability Date 

These final regulations apply to 

taxable years beginning after December 

26, 2023, the date the proposed 

regulations were published in the 

Federal Register. For taxable years 

beginning after December 31, 2022, and 

on or before December 26, 2023, 

taxpayers may choose to apply the rules 

of §§ 1.45V–1, –2, and –4 through –6, 

provided that taxpayers apply the rules 

in their entirety and in a consistent 

manner. 

One comment requested clarification 

on the applicability date of these final 

regulations for facilities that were 

placed in service prior to the effective 

date of these final regulations. As 

provided in the Explanation of 

Provisions to the proposed regulations, 

taxpayers may choose to rely upon the 

proposed regulations for taxable years 

beginning after December 31, 2022, and 

before the date these final regulations 

are published in the Federal Register, 

provided that taxpayers follow the 

proposed regulations in their entirety 

and in a consistent manner. Also, as 

provided in the preceding paragraph, 

taxpayers may choose to apply the final 

rules of §§ 1.45V–1, –2, and –4 through 

–6, provided that taxpayers apply the 

rules in their entirety and in a 

consistent manner. 

IX. Severability 

If any provision in this rulemaking is 

held to be invalid or unenforceable 

facially, or as applied to any person or 

circumstance, it shall be severable from 

the remainder of this rulemaking, and 

shall not affect the remainder thereof, or 

the application of the provision to other 

persons not similarly situated or to 

other dissimilar circumstances. 

Effect on Other Documents 

None. 

Special Analyses 

I. Regulatory Planning and Review 

Pursuant to the Memorandum of 

Agreement, Review of Treasury 

Regulations under Executive Order 

12866 (June 9, 2023), tax regulatory 

actions issued by the IRS are not subject 

to the requirements of section 6 of 

Executive Order 12866, as amended. 

Therefore, a regulatory impact 

assessment is not required. 

II. Paperwork Reduction Act 

The Paperwork Reduction Act of 1995 

(44 U.S.C. 3501–3520) (PRA) generally 


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2306 Federal Register / Vol. 90, No. 6 / Friday, January 10, 2025 / Rules and Regulations 

requires that a Federal agency obtain the 

approval of the Office of Management 

and Budget (OMB) before collecting 

information from the public, whether 

such collection of information is 

mandatory, voluntary, or required to 

obtain or retain a benefit. A Federal 

agency may not conduct or sponsor, and 

a person is not required to respond to, 

a collection of information unless the 

collection of information displays a 

valid control number. 

The collections of information in 

these final regulations contain reporting, 

third-party disclosure, and 

recordkeeping requirements. These 

collections are necessary for taxpayers 

to claim the section 45V credit, or the 

section 48 credit with respect to a 

specified clean hydrogen production 

facility, and for the IRS to validate that 

taxpayers have met the regulatory 

requirements and are entitled to claim 

either credit. 

The recordkeeping requirements in 

these final regulations include the 

requirement that taxpayers claiming the 

section 45V credit, or the section 48 

credit with respect to a specified clean 

hydrogen production facility, need to 

meet the general recordkeeping 

provisions under section 6001 necessary 

to substantiate the amount of the section 

45V credit or section 48 credit claimed 

by the taxpayer as detailed in proposed 

§§ 1.45V–2(c) and 1.48–15(g). These 

recordkeeping requirements are 

considered general tax records under 

§ 1.6001–1(e). For PRA purposes, 

general tax records are already approved 

by OMB under 1545–0074 for 

individuals/sole proprietors, 1545–0123 

for business entities, and 1545–0047 for 

tax-exempt organizations, and 1545– 

0092 for trust and estate filers. 

The final regulations reference the 

DOE’s process for applicants to request 

an emissions value from the DOE that 

can then be used to file a petition with 

the Secretary for a PER determination as 

detailed in proposed § 1.45V–4. The 

petition made to IRS will be performed 

by attaching the emissions value 

obtained from the DOE to the filing of 

Form 7210, Clean Hydrogen Production 

Credit. The burden for these 

requirements is included within the 

Form and Instructions for 7210. Form 

7210 was approved by OMB, in 

accordance with 5 CFR 1320.10, under 

the following OMB Control Numbers: 

1545–0074 for individuals, 1545–0123 

for businesses, 1545–0047 for taxexempt organizations, and 1545–2321 

for trust and estate filers. 

The final regulations mention the 

collection of information associated 

with the process for taxpayers to request 

an emissions value from the DOE, 

which is reflected in the Treasury 

Department and IRS’s Paperwork 

Reduction Act Supplemental NPRM 

dated April 11, 2024 (89 FR 29551), 

relating to such process. The OMB 

approved the DOE’s Submission related 

to the DOE’s emissions value request 

process on September 27, 2024, under 

Control Number 1910–5208. These final 

regulations are not creating or changing 

any of the collection requirements 

approved by OMB under Control 

Number 1910–5208. 

The final regulations include 

reporting requirements that taxpayers 

claiming the section 45V credit provide 

a verification report with their annual 

Federal income tax return or 

information return for each taxable year 

in which they claim the section 45V 

credit as detailed in proposed § 1.45V– 

5. The final regulations also include a 

third-party disclosure requirement that 

a verification report must be certified by 

an unrelated third party. The 

verification report must contain an 

attestation regarding the taxpayer’s 

production of qualified clean hydrogen 

for sale or use, the amount of qualified 

clean hydrogen sold or used by the 

taxpayer, conflicts of interest, the 

verifier’s qualifications, and 

documentation necessary to substantiate 

the verification process. The taxpayer 

must submit the verification report to 

the IRS by attaching it to Form 7210, or 

any successor form(s). The burden for 

these requirements is included within 

the Form and Instructions for Form 

7210. Form 7210 was approved by 

OMB, in accordance with 5 CFR 

1320.10, under the following OMB 

Control Numbers: 1545–0074 for 

individuals, 1545–0123 for businesses, 

1545–0047 for tax-exempt organizations, 

and 1545–2321 for trust and estate 

filers. 

The final regulations include 

reporting, third-party disclosure, and 

recordkeeping requirements that 

taxpayers making the election under 

section 48(a)(15) to claim the energy 

credit under section 48 with respect to 

a specified clean hydrogen production 

facility. The reporting requirement is 

that taxpayers submit an annual 

verification report with their Federal 

income tax return or information return 

for the year in which they claim the 

section 48 credit. The third-party 

disclosure requirement is that the 

annual verification report must be 

certified by an unrelated third-party. 

The annual verification report must 

contain an attestation regarding the 

taxpayer’s production of qualified clean 

hydrogen for sale or use during the 

taxable year, the amount of such 

qualified clean hydrogen sold or used 

by the taxpayer, conflicts of interest, the 

verifier’s qualifications, the lifecycle 

GHG emissions rate of the hydrogen that 

the specified clean hydrogen production 

facility produced, and documentation 

necessary to substantiate the verification 

process. The final regulations also 

include a requirement that the taxpayer 

obtain and retain an annual verification 

report for each taxable year of the 

recapture period. The taxpayer must 

obtain the annual verification report by 

the return filing due date (including 

extensions) for the taxable year to which 

the annual verification report relates. 

The annual verification report for the 

taxable year in which the section 

48(a)(15) election is made will be 

attached to Form 3468, Investment 

Credit. The annual verification report 

for each taxable year of the recapture 

period will be retained by the taxpayer 

for at least six years after the due date 

(including extensions) for filing the 

Federal income tax return or 

information return for the year to which 

the report relates. The burden for these 

requirements is included within the 

Form and Instructions for Form 3468. 

The revisions to Form 3468 have been 

approved by OMB, in accordance with 

5 CFR 1320.10, under the following 

OMB Control Numbers: 1545–0074 for 

individuals, 1545–0123 for businesses, 

1545–0047 for tax-exempt organizations, 

and 1545–0155 for trust and estate 

filers. 

No public comments were received by 

the IRS directed specifically at the PRA 

or on the collection requirements, but 

comments generally articulated the 

burdens associated with the 

documentation requirements in the 

proposed regulations. As described in 

the relevant portions of this preamble, 

the Treasury Department and the IRS 

have determined that the 

documentation requirements are 

necessary to administer the provisions 

of sections 45V and 48(a)(15). 

III. Regulatory Flexibility Act 

The Regulatory Flexibility Act (5 

U.S.C. 601 et seq.) (RFA) imposes 

certain requirements with respect to 

Federal rules that are subject to the 

notice and comment requirements of 

section 553(b) of the Administrative 

Procedure Act (5 U.S.C. 551 et seq.) and 

that are likely to have a significant 

economic impact on a substantial 

number of small entities. Unless an 

agency determines that a proposal is not 

likely to have a significant economic 

impact on a substantial number of small 

entities, section 603 of the RFA requires 

the agency to present a final regulatory 

flexibility analysis (FRFA) of the final 

regulations. The Treasury Department 


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and the IRS have not determined 

whether the final regulations will likely 

have a significant economic impact on 

a substantial number of small entities. 

This determination requires further 

study. Because there is a possibility of 

significant economic impact on a 

substantial number of small entities, a 

FRFA is provided in these final 

regulations. 

Pursuant to section 7805(f) of the 

Code, the proposed regulations were 

submitted to the Chief Counsel of the 

Office of Advocacy of the Small 

Business Administration (SBA) for 

comment on their impact on small 

business, and no comments were 

received. 

A. Need for and Objectives of the Rule 

The final regulations provide 

guidance to taxpayers intending to 

claim the section 45V credit for the 

production of qualified clean hydrogen 

or make the election under section 

48(a)(15) to treat qualified property that 

is part of a specified clean hydrogen 

production facility as energy property 

and claim the section 48 credit. The 

final regulations provide needed 

guidance for taxpayers on use of the 

45VH2–GREET model to determine the 

lifecycle GHG emissions rate resulting 

from the hydrogen production process, 

procedures for petitioning the Secretary 

for a PER determination, requirements 

for the verification of the production 

and sale or use of the hydrogen, 

requirements for modifications to an 

existing hydrogen production facility, 

and procedures for making the election 

under section 48(a)(15). 

B. Affected Small Entities 

The RFA directs agencies to provide 

a description of, and if feasible, an 

estimate of, the number of small entities 

that may be affected by the proposed 

rules, if adopted. The SBA’s Office of 

Advocacy estimates in its 2023 

Frequently Asked Questions that 99.9 

percent of American businesses meet 

the definition of a small business. The 

applicability of these final regulations 

does not depend on the size of the 

business, as defined by the SBA. 

As described more fully in the 

Summary of Comments and Explanation 

of Revisions to this final regulation and 

in this FRFA, sections 45V and 48(a)(15) 

and these final regulations may affect a 

variety of different businesses across 

several different industries. Because the 

potential credit claimants can vary 

widely, it is difficult to estimate at this 

time the impact of these final 

regulations, if any, on small businesses. 

Although there is uncertainty as to the 

exact number of small businesses within 

this group, the current estimated 

number of respondents to these final 

regulations is between 400 and 600 

taxpayers. Based on further analysis of 

announced clean hydrogen projects and 

the number of projects eligible for the 

section 45V credit that have registered 

for elective pay or transferability in the 

IRS Energy Credits Online portal, the 

estimated number of entities claiming 

the section 45V credit has been revised 

from the 800 to 1,000 taxpayers 

estimated in the Special Analyses 

section of the proposed regulations. 

This revision is not based on any 

changes made between the proposed 

regulations and the final regulations. 

The Treasury Department and the IRS 

expect to receive more information on 

the impact on small businesses when 

taxpayers start using the guidance and 

procedures provided in these final 

regulations to claim the section 45V 

credit, or the section 48 credit with 

respect to a specified clean hydrogen 

production facility. 

C. Impact of the Rules 

The final regulations provide rules for 

how taxpayers can claim the section 

45V credit, or the section 48 credit with 

respect to a specified clean hydrogen 

production facility. Taxpayers that 

claim the section 45V credit, or the 

section 48 credit with respect to a 

specified clean hydrogen production 

facility, will have administrative costs 

related to reading and understanding 

the rules as well as recordkeeping and 

reporting requirements because of the 

verification and Federal income tax 

return or information return 

requirements. The costs will vary across 

different-sized entities and across the 

type of project(s) in which such entities 

are engaged. 

To claim a section 45V credit, a 

taxpayer must determine the lifecycle 

GHG emissions rate for all hydrogen 

produced at a qualified clean hydrogen 

production facility during the taxable 

year. If the hydrogen production 

technology or feedstock used by the 

taxpayer to produce hydrogen is 

addressed in 45VH2–GREET, the 

taxpayer must use 45VH2–GREET to 

determine the emissions rate for the 

hydrogen produced during that taxable 

year at the qualified clean hydrogen 

production facility. If the hydrogen 

production technology or feedstock 

used by the taxpayer to produce 

hydrogen is not included in 45VH2– 

GREET, the taxpayer must petition the 

Secretary for a provisional emissions 

rate (PER). As part of the process for a 

taxpayer to petition for a PER, a 

taxpayer must submit an application to 

the DOE for an emissions value that it 

may use to claim the section 45V credit. 

In addition to determining the 

lifecycle GHG emissions rate for 

hydrogen produced by the taxpayer at a 

qualified clean hydrogen production 

facility during the taxable year, before 

claiming the section 45V credit, a 

taxpayer must submit a verification 

report, certified by an unrelated third 

party, attesting to the taxpayer’s 

production of qualified clean hydrogen 

for sale or use, the amount of qualified 

clean hydrogen sold or used by the 

taxpayer, conflicts of interest, the 

verifier’s qualifications, and 

documentation necessary to substantiate 

the verification process. The process for 

claiming the section 48 credit with 

respect to a specified clean hydrogen 

production facility requires a taxpayer 

to submit an annual verification report 

with its Federal income tax return or 

information return for the taxable year 

in which it claims the section 48 credit, 

as well as to obtain an annual 

verification report for the five taxable 

years following the taxable year in 

which the section 48(a)(15) election is 

made. Additionally, the taxpayer would 

need to retain records sufficient to 

establish compliance with these 

proposed regulations for as long as may 

be relevant. 

Although the Treasury Department 

and the IRS do not have sufficient data 

to determine precisely the likely extent 

of the increased costs of compliance, the 

estimated burden of complying with the 

recordkeeping and reporting 

requirements are described in the PRA 

section of the Special Analyses to these 

final regulations. 

D. Alternatives Considered 

The Treasury Department and the IRS 

considered alternatives to these final 

regulations. These final regulations were 

designed to minimize burdens for 

taxpayers while ensuring that the 

statutory requirements of sections 45V 

and 48(a)(15) are met. For example, in 

providing rules related to the 

information required to be submitted to 

claim the section 45V credit, or the 

section 48 credit with respect to a 

specified hydrogen production facility, 

the Treasury Department and the IRS 

considered whether the production and 

sale or use of the hydrogen could be 

verified by an unrelated party without 

requiring the unrelated party to possess 

certain qualifications or conflict of 

interest characteristics. Such an option 

would, however, increase the 

opportunity for fraud or abuse under 

section 45V or section 48. Section 45V(f) 

specifically authorizes the IRS to 

promulgate regulations or other 


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2308 Federal Register / Vol. 90, No. 6 / Friday, January 10, 2025 / Rules and Regulations 

guidance providing for requirements for 

recordkeeping or information reporting 

for purposes of administering the 

requirements of section 45V. As 

described in the preamble to these final 

regulations, these final rules carry out 

that Congressional intent as the 

verification requirements allow the IRS 

to verify the taxpayer’s entitlement to 

the section 45V credit. 

Additionally, the Treasury 

Department and the IRS considered 

whether to require taxpayers to submit 

an annual verification report with their 

Federal income tax returns or 

information returns claiming the section 

45V credit. Section 45V requires the 

taxpayer to obtain an annual verification 

report, and the Treasury Department 

and the IRS determined that requiring 

the taxpayer to attach such a report to 

their Federal income tax return or 

information return is the most efficient 

way of ensuring the completion and 

accuracy of the report. 

Additionally, the Treasury 

Department and the IRS considered 

allowing taxpayers to treat the section 

45V credit as determined in the taxable 

year of hydrogen production or 

verification. However, such an option 

would create administrability issues and 

potentially a mismatch between the 

taxable year in which the hydrogen is 

produced and the taxable year in which 

the section 45V credit for such 

production is claimed. Thus, the final 

regulations would require the credit to 

be determined in the taxable year of 

production. 

E. Duplicative, Overlapping, or 

Conflicting Federal Rules 

The final regulations do not duplicate, 

overlap, or conflict with any relevant 

Federal rules. As discussed above, the 

final regulations merely provide 

procedures and definitions to allow 

taxpayers to claim the section 45V 

credit, or the section 48 credit with 

respect to a specified clean hydrogen 

production facility. The Treasury 

Department and the IRS invite input 

from interested members of the public 

on identifying and avoiding 

overlapping, duplicative, or conflicting 

requirements. 

IV. Unfunded Mandates Reform Act 

Section 202 of the Unfunded 

Mandates Reform Act of 1995 requires 

that agencies assess anticipated costs 

and benefits and take certain other 

actions before issuing a final rule that 

includes any Federal mandate that may 

result in expenditures in any one year 

by a State, local, or Tribal government, 

in the aggregate, or by the private sector, 

of $100 million (updated annually for 

inflation). These final regulations do not 

include any Federal mandate that may 

result in expenditures by State, local, or 

Tribal governments, or by the private 

sector in excess of that threshold. 

V. Executive Order 13132: Federalism 

Executive Order 13132 (Federalism) 

prohibits an agency from publishing any 

rule that has federalism implications if 

the rule either imposes substantial, 

direct compliance costs on State and 

local governments, and is not required 

by statute, or preempts State law, unless 

the agency meets the consultation and 

funding requirements of section 6 of the 

Executive order. These final regulations 

do not have federalism implications and 

do not impose substantial direct 

compliance costs on State and local 

governments or preempt State law 

within the meaning of the Executive 

order. 

VI. Executive Order 13175: 

Consultation and Coordination With 

Indian Tribal Governments 

Executive Order 13175 (Consultation 

and Coordination with Indian Tribal 

governments) prohibits an agency from 

publishing any rule that has Tribal 

implications if the rule either imposes 

substantial, direct compliance costs on 

Indian Tribal governments, and is not 

required by statute, or preempts Tribal 

law, unless the agency meets the 

consultation and funding requirements 

of section 5 of the Executive order. This 

final rule does not have substantial 

direct effects on one or more federally 

recognized Indian tribes and does not 

impose substantial direct compliance 

costs on Indian Tribal governments 

within the meaning of the Executive 

order. 

VII. Congressional Review Act 

Pursuant to the Congressional Review 

Act (5 U.S.C. 801 et seq.), the Office of 

Information and Regulatory Affairs has 

determined that this rule meets the 

criteria set forth in 5 U.S.C. 804(2). 

VIII. Immediate Effective Date 

These final regulations have an 

effective date of January 10, 2025. To 

the extent that a good cause statement 

is necessary, 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. 

Section 45V was added to the Code by 

the IRA, and generally is applicable for 

facilities placed in service after 

December 31, 2022. The provision 

provides a new tax credit for the 

production of clean hydrogen produced 

by a taxpayer at a qualified clean 

hydrogen production facility during the 

10-year period beginning on the date 

such facility is placed in service. The 

credit amount is based on the lifecycle 

GHG emissions rate of the qualified 

clean hydrogen and is increased for 

taxpayers satisfying prevailing wage and 

apprenticeship requirements. The IRA 

also amended section 48 to provide for 

an election to treat qualified property 

which is part of a specified clean 

hydrogen production facility as energy 

property for purposes of claiming the 

section 48 investment tax credit in lieu 

of the section 45V credit. 

Following the enactment of section 

45V, many stakeholders and members of 

Congress expressed the need for prompt 

guidance on section 45V, in particular 

to provide investment certainty given 

that the credit became effective shortly 

after enactment and expires for facilities 

beginning construction after December 

31, 2032. After publication of the 

proposed regulations in December 2023, 

the Treasury Department and the IRS 

received more than 30,000 comments, 

reflecting the high level of interest in 

the provision and the continued 

expression of a need for certainty. In 

addition, hydrogen production facilities 

are capital intensive and require 

significant lead time to address 

financial, regulatory, and other issues 

before such facilities can begin 

construction. At the time of publication 

of these final regulations, more than two 

years have passed from the date that 

section 45V was enacted. For facilities 

that were placed in service prior to 

publication of these final regulations, 

delaying the effective date of these final 

regulations would only further delay or 

hinder their ability to realize the full 

benefit of the credit. In addition, 

taxpayers already have been provided 

notice of the general contents of the 

rules in the proposed regulations and 

their proposed applicability to taxable 

years beginning after December 26, 

2023, the date of publication of the 

proposed regulations. Furthermore, 

taxpayers have been able to rely on the 

proposed regulations for taxable years 

beginning after December 31, 2022, until 

the date of publication of these final 

regulations. For these reasons, the 

Treasury Department and the IRS have 

determined that an immediate effective 

date of the final regulations is 

appropriate to provide certainty to 

taxpayers and that delaying action on 

the provisions would disserve 

taxpayers. 

Consistent with Executive Order 

14008, ‘‘Tackling the Climate Crisis at 

Home and Abroad,’’ (86 FR 7619, 

January 27, 2021), letters from Members 

of Congress urging expeditious 


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publication of final regulations, and 

comments’ request for finalized rules, 

the Treasury Department and the IRS 

have determined that an expedited 

effective date of the final regulations is 

appropriate here to provide certainty to 

taxpayers considering investments to 

build qualified clean hydrogen 

production facilities before eligibility 

for the provisions expires. The final 

regulations provide needed rules on 

what the law requires for taxpayers to 

begin job-generating construction of 

capital-intensive projects qualifying for 

section 45V credits. Accordingly, the 

rules in this Treasury decision will take 

effect on the date of publication in the 

Federal Register. 

Statement of Availability of IRS 

Documents 

Guidance cited in this preamble is 

published in the Internal Revenue 

Bulletin and is available from the 

Superintendent of Documents, U.S. 

Government Publishing Office, 

Washington, DC 20402, or by visiting 

the IRS website at https://www.irs.gov. 

Drafting Information 

The principal authors of these final 

regulations are James Rider, Courtney 

Hutson, Alan Tilley, and Glenn Kats, 

Office of the Associate Chief Counsel 

(Passthroughs and Special Industries), 

IRS. However, other personnel from the 

Treasury Department and the IRS 

participated in their development. 

List of Subjects in 26 CFR Part 1 

Income taxes, Reporting and 

recordkeeping requirements. 

Amendments to the Regulations 

Accordingly, the Treasury Department 

and the IRS amend 26 CFR part 1 as 

follows: 

PART 1—INCOME TAXES 

■ Paragraph 1. The authority citation 

for part 1 is amended by adding entries 

in numerical order for §§ 1.45V–1, 

1.45V–2, 1.45V–4 through 1.45V–6, and 

1.48–15 to read in part as follows: 

Authority: 26 U.S.C. 7805 * * * 

* * * * * 

Section 1.45V–1 also issued under 26 

U.S.C. 45V(c)(1)(B) and 45V(f). 

Section 1.45V–2 also issued under 26 

U.S.C. 45V(c)(1)(B) and 45V(f). 

* * * * * 

Section 1.45V–4 also issued under 26 

U.S.C. 45V(c)(1)(B) and 45V(f). 

Section 1.45V–5 also issued under 26 

U.S.C. 45V(c)(1)(B) and 45V(f). 

Section 1.45V–6 also issued under 26 

U.S.C. 45V(c)(1)(B) and 45V(f). 

* * * * * 

Section 1.48–15 also issued under 26 

U.S.C. 48(a)(15) 

* * * * * 

■ Par. 2. Section 1.45V–0 through 

1.45V–6 are added to read as follows: 

Sec. 

* * * * * 

1.45V–0 Table of contents. 

1.45V–1 Credit for production of qualified 

clean hydrogen. 

1.45V–2 Special rules. 

1.45V–4 Procedures for determining the 

lifecycle greenhouse gas emissions rates 

for qualified clean hydrogen. 

1.45V–5 Procedures for verification of 

qualified clean hydrogen production and 

sale or use. 

1.45V–6 Rules for determining the placed 

in service date for an existing facility 

that is modified to produce qualified 

clean hydrogen. 

* * * * * 

§ 1.45V–0 Table of contents. 

This section lists the captions 

contained in §§ 1.45V–1, 1.45V–2, and 

1.45V–4 through 1.45V–6. 

§ 1.45V–1 Credit for production of clean 

hydrogen. 

(a) Overview. 

(b) Amount of credit. 

(c) Determination of credit. 

(d) Applicability date. 

§ 1.45V–2 Special rules. 

(a) Coordination with credit for carbon 

oxide sequestration. 

(b) Anti-abuse rule. 

(c) Recordkeeping. 

(d) Applicability date. 

§ 1.45V–4 Procedures for determining 

lifecycle greenhouse gas emissions rates 

for qualified clean hydrogen. 

(a) Overview. 

(b) Use of the 45VH2–GREET Model. 

(c) Provisional emissions rate (PER). 

(d) Use of energy attribute certificates 

(EACs). 

(e) Carbon capture and sequestration. 

(f) Use of methane from certain sources to 

produce hydrogen. 

(g) Applicability date. 

§ 1.45V–5 Procedures for verification of 

qualified clean hydrogen production and 

sale or use. 

(a) In general. 

(b) Requirements for verification reports. 

(c) Requirements for the production 

attestation. 

(d) Requirements for the sale or use 

attestation. 

(e) Requirements for the conflict 

attestation. 

(f) Requirements for the qualified verifier 

statement. 

(g) General information on the taxpayer’s 

hydrogen production facility. 

(h) Qualified verifier. 

(i) Unrelated party. 

(j) Requirements for taxpayers claiming 

both the section 45V credit and the section 

45 credit or the section 45U credit. 

(k) Timely verification report. 

(l) Applicability date. 

§ 1.45V–6 Rules for determining the placedin-service date for an existing facility 

that is modified or retrofitted to produce 

qualified clean hydrogen. 

(a) Modification of an existing facility. 

(b) Retrofit of an existing facility (80/20 

Rule). 

(c) Examples. 

(d) Applicability date. 

§ 1.45V–1 Credit for production of clean 

hydrogen. 

(a) Overview—(1) In general. For 

purposes of section 38 of the Internal 

Revenue Code (Code), the clean 

hydrogen production credit is 

determined under section 45V of the 

Code, so much of sections 6417 and 

6418 of the Code that relate to section 

45V, and the section 45V regulations (as 

defined in paragraph (a)(17) of this 

section). Paragraphs (a)(2) through (17) 

of this section provide generally 

applicable definitions of terms that, 

unless otherwise provided, apply for 

purposes of section 45V, the section 45V 

regulations, and any provision of the 

Code or this chapter that expressly 

refers to any provision of section 45V or 

the section 45V regulations. Paragraph 

(b) of this section provides rules for 

determining the amount of the section 

45V credit for any taxable year, which 

generally depends on the kilograms of 

qualified clean hydrogen produced 

during the taxable year and the 

emissions intensity of the process used 

to produce such hydrogen, as well as 

whether certain requirements, including 

the requirements under § 1.45V–3, are 

satisfied. Paragraph (c) of this section 

provides rules regarding the taxable year 

for which a section 45V credit is 

determined. See § 1.45V–2 for special 

rules, including rules to coordinate the 

section 45V credit with the credit for 

carbon oxide sequestration determined 

under section 45Q of the Code, an antiabuse rule, and recordkeeping 

requirements. See § 1.45V–3 for rules 

relating to the increased credit amount 

for satisfying the prevailing wage and 

apprenticeship requirements. See 

§ 1.45V–4 for procedures to determine 

lifecycle greenhouse gas (GHG) 

emissions rates for qualified clean 

hydrogen and § 1.45V–5 for procedures 

for verification of qualified clean 

hydrogen production and sale or use. 

See § 1.45V–6 for rules to determine the 

placed in service date for an existing 

facility that is modified or retrofitted to 

produce qualified clean hydrogen. See 

also § 1.48–15 for procedures to elect to 

treat any qualified property that is part 

of a specified clean hydrogen 

production facility as energy property 

for purposes of section 48 of the Code. 

(2) Applicable amount—(i) In general. 

The term applicable amount means the 


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amount equal to the applicable 

percentage of $0.60, provided that if any 

such amount is not a multiple of 0.1 

cent, such amount is rounded to the 

nearest multiple of 0.1 cent. 

(ii) Inflation adjustment. The $0.60 

amount specified in section 45V(b)(1) 

and paragraph (a)(2)(i) of this section is 

adjusted annually by multiplying such 

amount by the inflation adjustment 

factor (as determined under section 

45(e)(2) of the Code, determined by 

substituting ‘‘2022’’ for ‘‘1992’’ in 

section 45(e)(2)(B)) for the calendar year 

in which the qualified clean hydrogen is 

produced, provided that if any such 

amount as adjusted is not a multiple of 

0.1 cent, such amount is rounded to the 

nearest multiple of 0.1 cent. 

(3) Applicable percentage. The term 

applicable percentage means the 

percentage set forth in paragraphs 

(a)(3)(i) through (iv) of this section, 

which is determined according to the 

lifecycle GHG emissions rate of the 

process by which the qualified clean 

hydrogen is produced: 

(i) In the case of any qualified clean 

hydrogen that is produced through a 

process that results in a lifecycle GHG 

emissions rate of not greater than 4 

kilograms of carbon dioxide equivalent 

(CO2e) per kilogram of hydrogen, and 

not less than 2.5 kilograms of CO2e per 

kilogram of hydrogen, the applicable 

percentage is 20 percent. 

(ii) In the case of any qualified clean 

hydrogen that is produced through a 

process that results in a lifecycle GHG 

emissions rate of less than 2.5 kilograms 

of CO2e per kilogram of hydrogen, and 

not less than 1.5 kilograms of CO2e per 

kilogram of hydrogen, the applicable 

percentage is 25 percent. 

(iii) In the case of any qualified clean 

hydrogen that is produced through a 

process that results in a lifecycle GHG 

emissions rate of less than 1.5 kilograms 

of CO2e per kilogram of hydrogen, and 

not less than 0.45 kilograms of CO2e per 

kilogram of hydrogen, the applicable 

percentage is 33.4 percent. 

(iv) In the case of any qualified clean 

hydrogen that is produced through a 

process that results in a lifecycle GHG 

emissions rate of less than 0.45 

kilograms of CO2e per kilogram of 

hydrogen, the applicable percentage is 

100 percent. 

(4) Claim. With respect to the section 

45V credit determined for qualified 

clean hydrogen produced by the 

taxpayer at a qualified clean hydrogen 

production facility, the term claim 

means the filing of a completed Form 

7210, Clean Hydrogen Production 

Credit, or any successor form(s), with 

the taxpayer’s Federal income tax return 

or annual information return for the 

taxable year in which the credit is 

determined, and includes the making of 

an election under section 6417 or 6418 

and the regulations in this chapter 

under section 6417 or 6418, as 

applicable, with respect to such section 

45V credit on the applicable entity’s or 

eligible taxpayer’s timely filed 

(including extensions) Federal income 

tax return or annual information return. 

(5) Code. The term Code means the 

Internal Revenue Code. 

(6) DOE. The term DOE means the 

U.S. Department of Energy. 

(7) Facility—(i) In general. For 

purposes of the definition of qualified 

clean hydrogen production facility 

provided at section 45V(c)(3) and 

paragraph (a)(14) of this section, unless 

otherwise specified, the term facility 

means a single production line that is 

used to produce qualified clean 

hydrogen. For this purpose, a single 

production line includes all 

components of property that function 

interdependently to produce qualified 

clean hydrogen through a process that 

results in the lifecycle GHG emissions 

rate used to determine the credit. 

Components of property function 

interdependently to produce qualified 

clean hydrogen if the placing in service 

of each component is dependent upon 

the placing in service of each of the 

other components to produce qualified 

clean hydrogen. A facility includes 

carbon capture equipment if such 

carbon capture equipment contributes to 

the lifecycle GHG emissions rate of the 

process by which the qualified clean 

hydrogen for which the credit is 

determined is produced. 

(ii) Treatment of certain indirect 

production and post-production 

equipment. The term facility does not 

include— 

(A) Equipment that is used to 

condition or transport hydrogen beyond 

the point of production; or 

(B) Notwithstanding paragraph 

(a)(7)(iii) of this section, feedstockrelated equipment, including 

production, purification, recovery, 

transportation, or transmission 

equipment; or electricity production 

equipment used to power the hydrogen 

production process, including any 

carbon capture equipment associated 

with the electricity production process. 

(iii) Multipurpose components. 

Components that have a purpose in 

addition to the production of qualified 

clean hydrogen may be part of a facility 

if such components function 

interdependently with other 

components to produce qualified clean 

hydrogen. 

(iv) Example. The following example 

illustrates the definition of facility 

provided in this paragraph (a)(7). 

(A) Facts. Taxpayer owns a hydrogen 

production facility that is equipped 

with carbon capture equipment (as 

defined in § 1.45Q–2(c)), as 

distinguished from the carbon capture 

equipment described in paragraph 

(a)(7)(ii)(B) of this section. One purpose 

of this equipment is the capture of 

carbon oxides. The facility produces 

hydrogen through a process that results 

in a lifecycle GHG emissions rate of less 

than 0.45 kilograms of CO2e per 

kilogram of hydrogen. Without the 

carbon capture equipment, the facility 

could not produce hydrogen through a 

process that results in a lifecycle GHG 

emissions rate of less than 0.45 

kilograms of CO2e per kilogram of 

hydrogen. Taxpayer determines the 

section 45V credit using a lifecycle GHG 

emissions rate of less than 0.45 

kilograms of CO2e per kilogram of 

hydrogen. 

(B) Analysis. Because the carbon 

capture equipment is functionally 

interdependent with other components 

of property to produce qualified clean 

hydrogen through a process that results 

in the lifecycle GHG emissions rate that 

Taxpayer uses to determine the credit, 

the carbon capture equipment is part of 

the facility for purposes of section 

45V(c)(3) and the section 45V 

regulations, along with all other 

components of property that function 

interdependently with the carbon 

capture equipment to produce such 

hydrogen. 

(8) Hydrogen gas stream. The term 

hydrogen gas stream means a flow of 

gases that includes hydrogen, either 

alone or with one or more other gases. 

(9) Lifecycle GHG emissions—(i) In 

general. Subject to section 45V(c)(1)(B) 

and paragraphs (a)(9)(ii) through(iv) of 

this section, and unless otherwise 

specified in the section 45V regulations, 

the term lifecycle GHG emissions has 

the meaning given the term lifecycle 

greenhouse gas emissions by 42 U.S.C. 

7545(o)(1)(H), as in effect on August 16, 

2022. For purposes of section 45V, 

lifecycle GHG emissions include 

emissions only through the point of 

production (well-to-gate), as determined 

under the 45VH2–GREET Model. 

(ii) 45VH2–GREET Model. Unless 

otherwise specified in the section 45V 

regulations, for purposes of the section 

45V credit, the term 45VH2–GREET 

Model means the latest publicly 

available version of 45VH2–GREET 

developed by Argonne National 

Laboratory and published by the DOE, 

as provided in the instructions to the 

latest version of Form 7210, Clean 


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Hydrogen Production Credit, or any 

successor form(s), 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. If a version of 45VH2–GREET 

becomes publicly available after the first 

day of the taxable year of production 

(but still within such taxable year), then 

the taxpayer may, in its discretion, treat 

such later version of 45VH2–GREET as 

the 45VH2–GREET Model. 

(iii) Emissions through the point of 

production (well-to-gate). The term 

emissions through the point of 

production (well-to-gate) means the 

aggregate lifecycle GHG emissions 

related to hydrogen produced at a 

hydrogen production facility during the 

taxable year through the point of 

production. It includes emissions 

associated with growth, gathering, 

extraction, processing, and delivery of 

feedstocks to a hydrogen production 

facility. It also includes the emissions 

associated with the hydrogen 

production process, inclusive of the 

production of a mixed gas or impurity, 

and the electricity used by the hydrogen 

production facility and any capture and 

sequestration of carbon dioxide 

generated by the hydrogen production 

facility. Examples of emissions outside 

of the well-to-gate boundary generally 

include, but are not limited to, 

emissions from the liquefaction, storage, 

or transport of hydrogen. 

(iv) Certain emissions related to 

purification treated as through point of 

production. If the taxpayer knows or has 

reason to know the purification of a 

hydrogen gas stream (that is, removal of 

a mixed gas or impurity) is necessary for 

a hydrogen gas stream to be 

productively used, or to be sold for 

productive use, any lifecycle GHG 

emissions relating to such purification 

(for example, emissions from electricity 

used in purification, or carbon dioxide 

that is separated from a hydrogen gas 

stream and then vented as part of 

purification) are treated as emissions 

through the point of production (wellto-gate). Additionally, if the taxpayer 

knows or has reason to know that a 

hydrogen gas stream contains less than 

99 percent hydrogen and will be 

combusted without purification, any 

lifecycle GHG emissions relating to the 

purification needed to purify the 

hydrogen gas stream to contain 99 

percent hydrogen are treated as 

emissions through the point of 

production (well-to-gate). 

(v) Example. The following example 

illustrates the rule of paragraph (a)(9)(iv) 

of this section. 

(A) Facts. Taxpayer is a C corporation 

that has a calendar year taxable year. In 

2025, Taxpayer places Facility in 

service in the United States. Facility’s 

hydrogen production process produces 

a hydrogen gas stream containing mixed 

gases or impurities, and the stream is 

subsequently sold to Customer without 

removing the mixed gases or impurities. 

Taxpayer knows or has reason to know 

that the purity of the hydrogen gas 

stream is materially different from what 

the Customer requires for productive 

use, and Customer will need to remove 

the mixed gases or impurities in order 

for the hydrogen gas stream to be 

productively used. Because Taxpayer 

refrains from removing the mixed gases 

or impurities at the hydrogen 

production facility, 45VH2–GREET 

reflects a lower lifecycle GHG emissions 

rate for the hydrogen production 

process than it would have reflected had 

the mixed gases or impurities been 

removed at Facility. 

(B) Analysis. The Taxpayer has not 

accurately reflected well-to-gate 

emissions in 45VH2–GREET because the 

emissions associated with purification 

that was necessary for productive use 

have not been reflected. All lifecycle 

GHG emissions relating to the 

purification of the hydrogen gas stream 

to be productively used are emissions 

through the point of production (wellto-gate) and therefore must be taken into 

account as part of the emissions within 

the well-to-gate boundary. 

(10) Mixed gas or impurity. The term 

mixed gas or impurity means a nonhydrogen gas that is part of a hydrogen 

gas stream. 

(11) Process. The term process means 

the operations conducted by a facility to 

produce hydrogen (for example, 

electrolysis or steam methane 

reforming) during a taxable year using a 

primary feedstock. The term primary 

feedstock means a hydrogen-containing 

chemical that is transformed to produce 

hydrogen at a hydrogen production 

facility and has uniform or similar 

attributes distinguished by the source 

from which it is derived, if such source 

materially affects the lifecycle GHG 

emissions associated with use of the 

chemical to produce hydrogen. 

(12) Productive use. The term 

productive use means, with respect to a 

hydrogen gas stream, a consumption of 

the hydrogen gas stream in a manner 

that generates positive economic value, 

which is determined without regard to 

the availability of the section 45V credit. 

The term productive use means, with 

respect to qualified clean hydrogen, a 

consumption of the qualified clean 

hydrogen in a manner that generates 

positive economic value, which is 

determined without regard to the 

availability of the section 45V credit. 

(13) Qualified clean hydrogen—(i) In 

general. The term qualified clean 

hydrogen means hydrogen that is 

produced through a process that results 

in a lifecycle GHG emissions rate of not 

greater than 4 kilograms of CO2e per 

kilogram of hydrogen. Such term does 

not include any hydrogen unless the 

production and sale or use of such 

hydrogen is verified by an unrelated 

party in accordance with, and satisfying 

the requirements of, § 1.45V–5, and 

such hydrogen is produced— 

(A) In the United States (as defined in 

section 638(1) of the Code) or a U.S. 

territory, which, for purposes of section 

45V and the section 45V regulations, 

has the meaning of the term possession 

provided in section 638(2) of the Code; 

(B) In the ordinary course of a trade 

or business of the taxpayer; and 

(C) For sale or use. 

(ii) For sale or use. The term for sale 

or use means for the primary purpose of 

making ready and available for sale or 

use. Storage of hydrogen following 

production does not disqualify such 

hydrogen from being considered 

produced for sale or use. 

(14) Qualified clean hydrogen 

production facility. The term qualified 

clean hydrogen production facility 

means a facility— 

(i) Owned by the taxpayer; 

(ii) That produces qualified clean 

hydrogen; and 

(iii) The construction of which begins 

before January 1, 2033. 

(15) Secretary. The term Secretary 

means the Secretary of the Treasury or 

her delegate. 

(16) Section 45V credit. The term 

section 45V credit means the credit for 

production of clean hydrogen 

determined under section 45V of the 

Code, so much of sections 6417 and 

6418 of the Code that relate to section 

45V, and the section 45V regulations. 

(17) Section 45V regulations. The 

term section 45V regulations means this 

section, §§ 1.45V–2 through 1.45V–6, 

and the regulations in this chapter 

under sections 6417 and 6418 of the 

Code that relate to the section 45V 

credit. 

(b) Amount of credit—(1) In general. 

The amount of the section 45V credit 

determined under section 45V(a) and 

the section 45V regulations for any 

taxable year is the product of the 

kilograms of qualified clean hydrogen 

produced by the taxpayer during such 

taxable year at a qualified clean 

hydrogen production facility during the 

10-year period beginning on the date 

such facility was originally placed in 

service, multiplied by the applicable 

amount with respect to each process 

used to produce such hydrogen. 


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(2) Producer of qualified clean 

hydrogen. For purposes of section 

45V(a)(1) and paragraph (b)(1) of this 

section, the term taxpayer means the 

taxpayer that owns the qualified clean 

hydrogen production facility at the time 

of the facility’s production of hydrogen 

for which the section 45V credit is 

claimed, regardless of whether such 

taxpayer is treated as a producer under 

section 263A of the Code or under any 

other provision of law with respect to 

such hydrogen. 

(3) Increased credit amount for 

qualified clean hydrogen production 

facilities. Pursuant to section 45V(e)(1), 

§ 1.45V–3 provides rules that permit the 

amount of the section 45V credit 

determined under section 45V(a) and 

paragraph (b)(1) of this section to be 

multiplied by five if certain prevailing 

wages and apprenticeship requirements 

are met. See § 1.45V–3(a). 

(c) Determination of credit. Subject to 

any applicable sections of the Code that 

may limit the section 45V credit 

amount, the section 45V credit for any 

taxable year of a taxpayer who produces 

qualified clean hydrogen and claims 

such credit is determined with respect 

to the qualified clean hydrogen 

produced by the taxpayer during that 

taxable year, regardless of whether the 

verification of the production and sale 

or use of that hydrogen occurs in a later 

taxable year. Although the section 45V 

credit is determined with respect to the 

taxable year in which the qualified 

clean hydrogen is produced, a taxpayer 

is not eligible to claim the section 45V 

credit with respect to the production of 

that hydrogen until all relevant 

verification requirements, and the 

verification itself, have been completed 

for both the production of the hydrogen 

and the sale or use of that hydrogen. 

Accordingly, although the sale or use of 

the hydrogen and the verification 

thereof may occur in a taxable year after 

the taxable year of production, the 

section 45V credit is properly claimed 

with respect to the taxable year of 

production and is subject to the general 

period of limitations for filing a claim 

for credit or refund under section 

6511(a) and other applicable provisions 

of the Code. 

(d) Applicability date. This section 

applies to taxable years beginning after 

December 26, 2023. 

1.45V–2 Special rules. 

(a) Coordination with credit for 

carbon oxide sequestration. In the case 

of any qualified clean hydrogen 

produced at a qualified clean hydrogen 

production facility that includes carbon 

capture equipment for which a credit is 

allowed to any taxpayer under section 

45Q of the Code (section 45Q credit) for 

the taxable year or any prior taxable 

year, no section 45V credit is allowed 

under section 45V of the Code. 

However, if the 80/20 Rule provided in 

§ 1.45Q–2(g)(5) is satisfied with respect 

to such carbon capture equipment, and 

no new section 45Q credit has been 

allowed to any taxpayer for such carbon 

capture equipment, then the unit of 

carbon capture equipment (as defined in 

§ 1.45Q–2(c)(3)) for which the 80/20 

Rule is satisfied will not be treated as 

carbon capture equipment for which a 

section 45Q credit was allowed to any 

taxpayer for any prior taxable year for 

purposes of section 45V(d)(2) and this 

paragraph (a). 

(b) Anti-abuse rule—(1) In general. 

The rules of section 45V of the Code 

(and so much of sections 6417 and 6418 

of the Code related to the section 45V 

credit) and the section 45V regulations 

(as defined in § 1.45V–1(a)(17)) must be 

applied in a manner consistent with the 

purposes of section 45V and the section 

45V regulations. A purpose of section 

45V is to provide taxpayers an incentive 

to produce qualified clean hydrogen for 

a productive use. Accordingly, the 

section 45V credit is not allowable if the 

primary purpose of the sale or use of 

qualified clean hydrogen is to obtain the 

benefit of the section 45V credit in a 

manner that is wasteful, such as when 

a taxpayer claims the section 45V credit 

for qualified clean hydrogen that the 

taxpayer knows or has reason to know 

will, in excess of standard commercial 

practices, be vented, flared, used to 

produce heat or power that is then 

directly used to produce hydrogen, or 

otherwise used to produce hydrogen. 

For example, venting or flaring for 

safety or maintenance reasons in the 

ordinary course of business is a nonabusive commercial industry practice. 

While not abusive, such venting or 

flaring is also not a verifiable use under 

§ 1.45V–5(d)(2)(ii), and therefore any 

such hydrogen that is vented or flared 

for safety reasons is not eligible for the 

section 45V credit. A determination of 

whether the sale or use of qualified 

clean hydrogen is inconsistent with the 

purposes of section 45V is based on all 

relevant facts and circumstances. 

(2) Example. The following example 

illustrates the application of paragraph 

(b)(1). 

(i) Example 1—(A) Facts. Taxpayer is 

a C corporation that has a calendar year 

taxable year. In 2031, Taxpayer places 

Facility in service in the United States. 

Facility produces qualified clean 

hydrogen that qualifies for the highest 

applicable amount of the section 45V 

credit at a production cost of $2 per 

kilogram of hydrogen (assuming 

Taxpayer also claims the increased 

credit under section 45V(e), excluding 

any future inflation adjustment, the 

amount of the section 45V credit would 

be $3 per kilogram of qualified clean 

hydrogen). The cost of producing each 

kilogram of qualified clean hydrogen is 

less than the amount of the section 45V 

credit that would be available if 

Taxpayer qualified for the section 45V 

credit. In 2031, Taxpayer sells all the 

qualified clean hydrogen produced at 

Facility that year to Customer at a price 

that is well below the current market 

price. Taxpayer knows or reasonably 

expects that Customer will vent or flare 

the qualified clean hydrogen it 

purchased from Taxpayer, in excess of 

standard commercial practices. In 

addition, Taxpayer intends to obtain the 

benefit of the section 45V credit by 

claiming such credit itself or monetizing 

such credit through an election under 

section 6417 or 6418 of the Code. 

(B) Analysis. Based on all the facts 

and circumstances, the primary purpose 

of Taxpayer’s sale of qualified clean 

hydrogen is to obtain the benefit of the 

section 45V credit in a manner that is 

wasteful. Taxpayer is not eligible for the 

section 45V credit with respect to the 

qualified clean hydrogen that Taxpayer 

produced and sold in 2031 to Customer 

that is subsequently vented or flared by 

Customer. 

(c) Recordkeeping. Consistent with 

section 6001 of the Code, a taxpayer 

claiming the section 45V credit for 

qualified clean hydrogen produced at a 

qualified clean hydrogen production 

facility must maintain and preserve 

records sufficient to establish the 

amount of the section 45V credit 

claimed by the taxpayer. At a minimum, 

those records must include records to 

substantiate the information required to 

be included in the verification report 

under § 1.45V–5, records establishing 

that the facility meets the definition of 

a qualified clean hydrogen production 

facility under section 45V(c)(3) and 

§ 1.45V–1(a)(14), records of past credit 

claims under section 45Q by any 

taxpayer with respect to carbon capture 

equipment included at the facility, and 

records establishing the date the 

qualified clean hydrogen production 

facility was placed in service. If the 

requirements under section 45V(e) and 

§ 1.45V–3(b) for the increased credit 

amount were satisfied, then the taxpayer 

must also maintain records in 

accordance with § 1.45–12. Taxpayers 

must also retain all raw data used for 

submission of a request for an emissions 

value to the DOE for at least six years 

after the due date (including extensions) 

for filing the Federal income tax return 

or information return to which the 


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provisional emissions rate (PER) (as 

defined in § 1.45V–4(c)(1)) petition is 

ultimately attached. 

(d) Applicability date. This section 

applies to taxable years beginning after 

December 26, 2023. 

§ 1.45V–4 Procedures for determining 

lifecycle greenhouse gas emissions rates 

for qualified clean hydrogen. 

(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 


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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 coproduct 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 coproduct 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 publiclyavailable 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 


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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 


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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 instate 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 


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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 Authority Region 

Balancing Authority of Northern California .................................................................................................................... California. 

California Independent System Operator (Balancing Authority) ................................................................................... California. 

Imperial Irrigation District ............................................................................................................................................... California. 

Los Angeles Dept of Water & Power ............................................................................................................................ California. 

Turlock Irrigation District ................................................................................................................................................ California. 

Midcontinent ISO (Balancing Authority): South ............................................................................................................. Delta. 

Duke Energy Florida Inc ................................................................................................................................................ Florida. 

Florida Municipal Power Pool ........................................................................................................................................ Florida. 

Florida Power & Light .................................................................................................................................................... Florida. 

Gainesville Regional Utilities ......................................................................................................................................... Florida. 

Homestead (City of) ....................................................................................................................................................... Florida. 

JEA ................................................................................................................................................................................ Florida. 

New Smyrna Beach Utilities Commission ..................................................................................................................... Florida. 

Reedy Creek Improvement District ............................................................................................................................... Florida. 

Seminole Electric Coop Inc ........................................................................................................................................... Florida. 

Tallahassee FL (City of) ................................................................................................................................................ Florida. 

Tampa Electric Co ......................................................................................................................................................... Florida. 

East Kentucky Power Coop Inc ..................................................................................................................................... Mid-Atlantic. 

LG&E & KU Services Co ............................................................................................................................................... Mid-Atlantic. 

Ohio Valley Electric Corp .............................................................................................................................................. Mid-Atlantic. 

PJM Interconnection ...................................................................................................................................................... Mid-Atlantic. 

Associated Electric Coop Inc ......................................................................................................................................... Midwest. 

Electric Energy Inc ......................................................................................................................................................... Midwest. 

Gridliance Heartland ...................................................................................................................................................... Midwest. 

Midcontinent ISO (Balancing Authority): North and Central .......................................................................................... Midwest. 

NaturEner Power Watch LLC (GWA) ............................................................................................................................ Mountain. 

NaturEner Wind Watch LLC .......................................................................................................................................... Mountain. 

Nevada Power Co ......................................................................................................................................................... Mountain. 

Northwestern Energy ..................................................................................................................................................... Mountain. 

PacifiCorp East .............................................................................................................................................................. Mountain. 

Public Service Co of Colorado ...................................................................................................................................... Mountain. 

WAPA Rocky Mountain Region ..................................................................................................................................... Mountain. 

WAPA Upper Great Plains West ................................................................................................................................... Mountain. 

New England ISO (Balancing Authority) ....................................................................................................................... New England. 

Northern Maine .............................................................................................................................................................. New England. 

New York ISO (Balancing Authority) ............................................................................................................................. New York. 

Avangrid Renewables LCC ........................................................................................................................................... Northwest. 

Avista Corp .................................................................................................................................................................... Northwest. 

Bonneville Power Administration ................................................................................................................................... Northwest. 

Gridforce Energy Management LLC .............................................................................................................................. Northwest. 

Idaho Power Co ............................................................................................................................................................. Northwest. 

PacifiCorp West ............................................................................................................................................................. Northwest. 

Portland General Electric ............................................................................................................................................... Northwest. 

PUD No 1 of Chelan County ......................................................................................................................................... Northwest. 

PUD No 1 of Douglas County ....................................................................................................................................... Northwest. 

PUD No 2 of Grant County ........................................................................................................................................... Northwest. 

Puget Sound Energy Inc ............................................................................................................................................... Northwest. 

Seattle City Light ........................................................................................................................................................... Northwest. 

Tacoma Power ............................................................................................................................................................... Northwest. 

Southwest Power Pool (Balancing Authority) ................................................................................................................ Plains. 

Southwestern Power Administration .............................................................................................................................. Plains. 

Alcoa Power Generating Inc Yadkin Division ................................................................................................................ Southeast. 


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TABLE 1 TO PARAGRAPH (d)(2)(ix)—Continued 

Balancing Authority Region 

Duke Energy Carolinas LLC .......................................................................................................................................... Southeast. 

Duke Energy Progress East .......................................................................................................................................... Southeast. 

Duke Energy Progress West ......................................................................................................................................... Southeast. 

PowerSouth Energy Coop ............................................................................................................................................. Southeast. 

South Carolina Electric & Gas Co ................................................................................................................................. Southeast. 

South Carolina Public Service Authority ....................................................................................................................... Southeast. 

Southeastern Power Administration (Southern) ............................................................................................................ Southeast. 

Southern Co Services Inc .............................................................................................................................................. Southeast. 

Tennessee Valley Authority ........................................................................................................................................... Southeast. 

Arizona Public Service Co ............................................................................................................................................. Southwest. 

Arlington Valley LLC ...................................................................................................................................................... Southwest. 

El Paso Electric ............................................................................................................................................................. Southwest. 

Gila River Power LLC .................................................................................................................................................... Southwest. 

Griffith Energy LLC ........................................................................................................................................................ Southwest. 

New Harquahala Generating Co LLC ........................................................................................................................... Southwest. 

Public Service Co of New Mexico ................................................................................................................................. Southwest. 

Salt River Project ........................................................................................................................................................... Southwest. 

Tucson Electric Power Co ............................................................................................................................................. Southwest. 

WAPA Desert Southwest Region .................................................................................................................................. Southwest. 

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 


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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). Twotwelfths (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 


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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-tohour 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 


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Federal Register / Vol. 90, No. 6 / Friday, January 10, 2025 / Rules and Regulations 2321 

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 


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(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. 

§ 1.45V–5 Procedures for verification of 

qualified clean hydrogen production and 

sale or use. 

(a) In general. A verification report 

must be attached to a taxpayer’s Form 

7210, Clean Hydrogen Production 

Credit, or any successor form(s), with 

the taxpayer’s Federal income tax return 

or information return for each qualified 

clean hydrogen production facility and 

for each taxable year in which the 

taxpayer claims the section 45V credit. 

(b) Requirements for verification 

reports. A verification report specified 

in paragraph (a) of this section must be 

prepared by a qualified verifier under 

penalties of perjury and must contain— 

(1) An attestation from the qualified 

verifier regarding the taxpayer’s 

production of qualified clean hydrogen 

for sale or use, including an attestation 

that the inputs used to determine the 

lifecycle GHG emissions rate of the 

hydrogen production process are 

accurate (production attestation); 

(2) An attestation from the qualified 

verifier regarding the amount of 

qualified clean hydrogen sold or used 

(sale or use attestation); 

(3) An attestation from the qualified 

verifier regarding conflicts of interest 

(conflict attestation); 

(4) Information regarding the qualified 

verifier, including documentation of the 

qualified verifier’s qualifications 

(qualified verifier statement); 

(5) Certain general information about 

the taxpayer’s hydrogen production 

facility where the hydrogen production 

undergoing verification occurred; 

(6) Any documentation necessary to 

substantiate the verification process 

given the standards and best practices 

prescribed by the qualified verifier’s 

accrediting body and the circumstances 

of the taxpayer and the taxpayer’s 

hydrogen production facility; and 

(7) Any other information required by 

IRS forms or instructions. 

(c) Requirements for the production 

attestation. The following requirements 

apply to the production attestation: 

(1) The production attestation must be 

an attestation, made under penalties of 

perjury, that the qualified verifier 

performed a verification sufficient to 

determine that the operation, during the 

applicable taxable year, of the hydrogen 

production facility that produced the 

hydrogen for which the section 45V 

credit is claimed, any lifecycle GHG 

emissions data inputs, and any energy 

attribute certificates (EACs) applied 

pursuant to § 1.45V–4(d) for the purpose 

of accounting for such facility’s 

emissions, are accurately reflected with 

reasonable assurance in— 

(i) The amount of qualified clean 

hydrogen produced by the taxpayer that 

is claimed on the Form 7210, Clean 

Hydrogen Production Credit, or any 

successor form(s), to which the 

verification report is attached; and 

(ii) Either— 

(A) The data the taxpayer entered into 

the 45VH2–GREET Model to determine 

the lifecycle GHG emissions rate that is 

claimed on the Form 7210, Clean 

Hydrogen Production Credit, or any 

successor form(s), to which the 

verification report is attached; or 

(B) The data the taxpayer submitted in 

the PER petition relating to the 

hydrogen for which the section 45V 

credit is claimed, and the data provided 

to the DOE in support of the taxpayer’s 

request for the emissions value provided 

in the PER petition. 

(2) If the production attestation attests 

that qualifying EACs were acquired and 

retired pursuant to § 1.45V–4(d), then 

the production attestation must confirm 

that the electricity generator or 

generators associated with such EACs 

were not registered on multiple 

qualifying EAC registries, or, in the 

event such generators are registered on 

multiple qualifying EAC registries, that 

each EAC undergoing verification from 

each such generator registered on 

multiple qualifying EAC registries is 

being issued by only one qualifying EAC 

registry. 

(3) If the production attestation attests 

to the information specified in 

paragraph (c)(1)(ii)(B) of this section, 

then the production attestation must 

also specify the emissions value 

received from the DOE that was 

calculated using such data, expressed in 

kilograms of carbon dioxide equivalent 

(CO2e) per kilogram of hydrogen. 

(4) The production attestation must 

specify the lifecycle GHG emissions 

rate(s) (expressed in kilograms of CO2e 

per kilogram of hydrogen) and the 

amount of qualified clean hydrogen 

produced by the taxpayer (expressed in 

kilograms), that are claimed on the Form 

7210, Clean Hydrogen Production 

Credit, or any successor form(s), to 

which the verification report is 

attached. 

(d) Requirements for the sale or use 

attestation—(1) In general. The sale or 

use attestation must be an attestation, 

made under penalties of perjury, that 

the qualified verifier performed a 

verification sufficient to determine that 

the amount of qualified clean hydrogen 

that is specified in the production 

attestation pursuant to paragraph 

(c)(1)(i) of this section, and that is 

claimed on the Form 7210, Clean 

Hydrogen Production Credit, or any 

successor form(s), to which the 

verification report is attached, has been 

sold, or has been used by a person who 

makes a verifiable use of such hydrogen. 

(2) Verifiable use. For purposes of 

section 45V(c)(2)(B)(ii) of the Code and 

the section 45V regulations (as defined 

in § 1.45V–1(a)(17)), a person’s 

verifiable use of the hydrogen specified 

in paragraph (d)(1) of this section can 

occur within or outside the United 

States. A verifiable use can be made by 

the taxpayer or a person other than the 

taxpayer. For example, a verifiable use 

includes a tolling arrangement pursuant 

to which a service recipient provides 

raw materials or inputs, such as water 

or electricity, to a toller (that is, a thirdparty service provider that owns a 

hydrogen production facility), and the 

toller produces hydrogen for the service 

recipient using the service recipient’s 

raw materials or inputs in exchange for 

a fee. In such a case, use of the hydrogen 

by the service recipient would be a 

verifiable use. However, a verifiable use 

does not include— 


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(i) Use of hydrogen to generate heat or 

power that is then directly used in the 

production of more hydrogen (except 

when such heat or power is derived 

from a byproduct of hydrogen use); or 

(ii) Venting or flaring of hydrogen. 

(3) The following example illustrates 

the application of paragraph (d)(2) of 

this section. 

(i) Example—(A) Facts. In 2025, 

Taxpayer A produces 100 kilograms of 

hydrogen through a process that results 

in an emissions rate of not greater than 

four kilograms of CO2e per kilogram of 

hydrogen produced. However, 

throughout the year, Taxpayer A feeds 

two kilograms of the hydrogen back into 

its facility’s process train to replace 

what would otherwise be externally 

sourced energy inputs directly 

supplying the hydrogen production 

process. Taxpayer A also flares two 

kilograms of the hydrogen for testing 

and maintenance purposes. Taxpayer A 

puts 96 kilograms of the hydrogen to use 

in a separate facility that produces 

fertilizer. Additionally, Taxpayer A 

recovers waste heat from the fertilizer 

production process to generate 

electricity used to power both facilities. 

(B) Analysis. Taxpayer A has made a 

verifiable use of 96 kilograms of 

qualified clean hydrogen and may claim 

the section 45V credit for that amount, 

assuming all other requirements for 

claiming the section 45V credit are met. 

The two kilograms of hydrogen that are 

flared have not been verifiably used, 

and therefore Taxpayer A may not 

determine the section 45V credit with 

respect to such two kilograms of 

hydrogen. The two kilograms of 

hydrogen that are directly supplied back 

into the hydrogen process have also not 

been verifiably used because the 

hydrogen is being consumed to produce 

heat or power that will then directly be 

used to produce more hydrogen. 

Consumption of hydrogen in this 

manner (to generate heat or power that 

is then directly used to produce 

hydrogen) is not a verifiable use under 

paragraph (d)(2) of this section. 

(e) Requirements for the conflict 

attestation. The conflict attestation must 

include attestations, made under 

penalties of perjury, that— 

(1) The qualified verifier has not 

received a fee based to any extent on the 

value of any section 45V credit that has 

been or is expected to be claimed by any 

taxpayer and no arrangement has been 

made for such fee to be paid at some 

time in the future; 

(2) The qualified verifier has not been 

a party to any transaction in which the 

taxpayer sold qualified clean hydrogen 

it had produced or in which the 

taxpayer purchased inputs for the 

production of such hydrogen; 

(3) The qualified verifier is not 

related, within the meaning of section 

267(b) or 707(b)(1) of the Code, to, or an 

employee of, the taxpayer; 

(4) The qualified verifier is not 

married to an individual described in 

paragraph (e)(3) of this section; and 

(5) If the qualified verifier is acting in 

his or her capacity as a partner in a 

partnership, an employee of any person, 

whether an individual, corporation, or 

partnership, or an independent 

contractor engaged by a person other 

than the taxpayer, the attestations under 

paragraphs (e)(1) through (4) of this 

section must also be made with respect 

to the partnership or the person who 

employs or engages the qualified 

verifier. 

(f) Requirements for the qualified 

verifier statement. The qualified verifier 

statement must include the following— 

(1) The qualified verifier’s name, 

address, and taxpayer identification 

number; 

(2) The qualified verifier’s 

qualifications to conduct the 

verification, including a description of 

the qualified verifier’s education and 

experience and a photocopy of the 

qualified verifier’s certificate received 

from their accrediting body; 

(3) If the qualified verifier is acting in 

his or her capacity as a partner in a 

partnership, an employee of any person, 

whether an individual, corporation, or 

partnership, or an independent 

contractor engaged by a person other 

than the taxpayer, the name, address, 

and taxpayer identification number of 

the partnership or the person who 

employs or engages the qualified 

verifier; 

(4) The signature of the qualified 

verifier and the date signed by the 

qualified verifier; and 

(5) A statement that the verification 

was conducted for Federal income tax 

purposes. 

(g) General information on the 

taxpayer’s hydrogen production facility. 

The verification report must include the 

following information for the taxpayer’s 

hydrogen production facility where the 

hydrogen production undergoing 

verification occurred: 

(1) The location of the hydrogen 

production facility; 

(2) A description of the hydrogen 

production facility, including its 

method of producing hydrogen; 

(3) The type(s) of feedstock(s) used by 

the hydrogen production facility during 

the taxable year of production; 

(4) The amount(s) of feedstock(s) used 

by the hydrogen production facility 

during the taxable year of production; 

and 

(5) A list of the metering devices used 

to record any data used by the qualified 

verifier to support the production 

attestation under paragraph (c) of this 

section along with a statement that the 

qualified verifier is reasonably assured 

that the device(s) underwent industryappropriate quality assurance and 

quality control, and the accuracy and 

calibration of the device has been tested 

in the last year. 

(h) Qualified verifier. The term 

qualified verifier means any individual 

or organization with active 

accreditation— 

(1) From the American National 

Standards Institute National 

Accreditation Board to conduct 

validation and verification in 

accordance with the requirements of 

ISO 14065:2020 and ISO 14064–3:2019; 

or 

(2) As a verifier, lead verifier, or 

verification body under the California 

Air Resources Board Low Carbon Fuel 

Standard program. 

(i) Unrelated party. For purposes of 

section 45V(c)(2)(B)(ii), the term 

unrelated party means a qualified 

verifier who meets the requirements of 

paragraph (e) of this section. 

(j) Requirements for taxpayers 

claiming both the section 45V credit and 

the section 45 credit or the section 45U 

credit. In the case of a taxpayer who 

produces electricity for which either the 

section 45 or section 45U credit is 

claimed and the taxpayer or a related 

person uses such electricity to produce 

hydrogen for which the section 45V 

credit is claimed, the verification report 

must also contain attestations that the 

qualified verifier performed a 

verification sufficient to determine 

that— 

(1) The electricity used to produce 

such hydrogen was produced at the 

relevant facility for which a section 45 

or section 45U credit is claimed; 

(2) The given amount of electricity (in 

kilowatt hours) used to produce such 

hydrogen at the relevant hydrogen 

production facility is reasonably assured 

of being accurate; and 

(3) The electricity for which a section 

45 or section 45U credit was claimed is 

represented by EACs that are acquired 

and retired in connection with the 

production of such hydrogen. 

(k) Timely verification report. A 

verification report must be signed and 

dated by the qualified verifier no later 

than— 

(1) The due date, including 

extensions, of the Federal income tax 

return or information return for the 


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taxable year during which the hydrogen 

undergoing verification is produced; or 

(2) In the case of a credit first claimed 

for the taxable year on an amended 

return or administrative adjustment 

request, the date on which the amended 

return or administrative adjustment 

request is filed. 

(l) Applicability date. This section 

applies to taxable years beginning after 

December 26, 2023. 

§ 1.45V–6 Rules for determining the placed 

in service date for an existing facility that 

is modified or retrofitted to produce 

qualified clean hydrogen. 

(a) Modification of an existing 

facility—(1) In general. Under section 

45V(d)(4) of the Code, in the case of an 

existing facility that— 

(i) Was originally placed in service 

before January 1, 2023, and, prior to the 

modification described in this 

paragraph (a), did not produce qualified 

clean hydrogen, and after the date such 

facility was originally placed in 

service— 

(A) Is modified to produce qualified 

clean hydrogen; and 

(B) Amounts paid or incurred with 

respect to such modification are 

properly chargeable to the taxpayer’s 

capital account for the facility, 

(ii) Such facility will be deemed to 

have been originally placed in service as 

of the date the property required to 

complete the modification described in 

this paragraph (a) is placed in service. 

(2) Modification requirements. For 

purposes of section 45V(d)(4) and 

paragraph (a)(1) of this section, an 

existing facility will not be deemed to 

have been originally placed in service as 

of the date the property required to 

complete the modification is placed in 

service unless the modification is made 

for the purpose of enabling the facility 

to produce qualified clean hydrogen and 

amounts paid or incurred with respect 

to the modification are properly 

chargeable to the taxpayer’s capital 

account. A modification is made for the 

purpose of enabling the facility to 

produce qualified clean hydrogen if the 

facility could not produce hydrogen 

with a lifecycle GHG emissions rate that 

is less than or equal to 4 kilograms of 

carbon dioxide equivalent (CO2e) per 

kilogram of hydrogen but for the 

modification. For example, if a taxpayer 

solely pays or incurs capital expenses to 

modify existing components of a 

hydrogen production facility that are 

not necessary for the production of 

hydrogen with a lifecycle GHG 

emissions rate that is less than or equal 

to 4 kilograms of CO2e per kilogram of 

hydrogen, such modification does not 

entitle the facility to a new placed in 

service date. A modification does not 

include changing fuel inputs to the 

hydrogen production facility. For 

example, changing from using 

conventional natural gas to using 

renewable natural gas as a feedstock, is 

not a modification under this paragraph. 

(3) Interaction with 80/20 Rule. An 

existing facility that satisfies the 

requirements of section 45V(d)(4) and 

paragraphs (a)(1) and (2) of this section 

is deemed to be originally placed in 

service as of the date that the property 

required to complete the modification 

described in section 45V(d)(4)(B) is 

placed in service regardless of whether 

such facility satisfies the requirements 

of paragraph (b) of this section. 

(b) Retrofit of an existing facility (80/ 

20 Rule). For purposes of section 

45V(a)(1), a retrofitted hydrogen 

production facility may establish a new 

date on which it is considered originally 

placed in service, even though the 

facility contains some used components 

of property of a single production line, 

provided the fair market value of the 

used property is not more than 20 

percent of the facility’s total value, 

calculated by adding the cost of the new 

property to the value of the used 

property (80/20 Rule). For purposes of 

the 80/20 Rule, the cost of new property 

includes all properly capitalized costs of 

the new property included within the 

facility. If a facility satisfies the 

requirements of the 80/20 Rule, then the 

date on which such facility is 

considered originally placed in service 

for purposes of section 45V(a)(1) is the 

date on which the new property added 

to the facility is placed in service. 

(c) Examples. The following examples 

illustrate the application of paragraphs 

(a) and (b) of this section: 

(1) Example 1: Modification of an 

existing facility—(i) Facts. Facility X, a 

hydrogen production facility that was 

originally placed in service on January 

1, 2018, could not produce qualified 

clean hydrogen as described in section 

45V(c)(2). After January 1, 2023, Facility 

X was modified to produce qualified 

clean hydrogen, and all amounts paid or 

incurred with respect to such 

modifications were properly chargeable 

to the taxpayer’s capital account for 

Facility X. The property required to 

complete the modification was placed 

in service on June 1, 2023. 

(ii) Analysis. Under section 45V(d)(4) 

and paragraph (a) of this section, 

because Facility X was originally placed 

in service before January 1, 2023, and 

before the modification could not 

produce qualified clean hydrogen, it is 

deemed to be originally placed in 

service as of the date the property 

required to complete the modification is 

placed in service. Accordingly, for 

purposes of section 45V(a)(1) and (d)(4), 

Facility X is deemed to have been 

originally placed in service on June 1, 

2023. 

(2) Example 2: Modification of an 

existing facility; coordination with the 

section 45Q credit previously allowed— 

(i) Facts. The facts are the same as in 

paragraph (c)(1) of this section (Example 

1), except that taxpayer was allowed a 

section 45Q credit with respect to 

carbon capture equipment (CCE) 

included at Facility X before June 1, 

2023. 

(ii) Analysis. Under paragraph (a) of 

this section and § 1.45V–2(a), although 

Facility X is deemed to have been 

originally placed in service on June 1, 

2023, because taxpayer had previously 

been allowed a section 45Q credit with 

respect to the CCE included at Facility 

X, no section 45V credit is allowable for 

qualified clean hydrogen produced at 

Facility X, despite the modification. The 

result would be the same if the section 

45Q credit with respect to the CCE 

included at Facility X were allowed to 

a person other than the taxpayer. 

(3) Example 3: Modification of an 

existing facility and coordination with 

section 45Q credit not previously 

allowed—(i) Facts. Facility Y, a 

hydrogen production facility that was 

originally placed in service on February 

1, 2020, could not previously produce 

qualified clean hydrogen as described in 

section 45V(c)(2). On February 1, 2026, 

Facility Y was modified to produce 

qualified clean hydrogen by adding new 

CCE to allow Facility Y to capture, 

process, and prepare carbon dioxide for 

transport for disposal, injection, or 

utilization. All amounts paid or 

incurred with respect to such 

modifications were properly chargeable 

to the taxpayer’s capital account for 

Facility Y. The property required to 

complete the modification of Facility Y 

was placed in service on February 1, 

2026, and as a result, Facility Y, 

including the new CCE, is deemed to be 

originally placed in service on February 

1, 2026, for purposes of sections 45V 

and 45Q. No section 45Q credit has 

been allowed to any taxpayer with 

respect to the new CCE located at 

Facility Y. 

(ii) Analysis. Under paragraph (a) of 

this section and § 1.45V–2(a), because 

no section 45Q credit has been allowed 

to any taxpayer with respect to the new 

CCE located at Facility Y, a section 45V 

credit is allowable for the qualified 

clean hydrogen produced at Facility Y, 

assuming all other requirements of 

section 45V are met. 

(4) Example 4: Retrofit of an existing 

facility (80/20 Rule)—(i) Facts. Facility 


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Z, a hydrogen production facility that 

was originally placed in service on 

February 1, 2023, does not produce 

qualified clean hydrogen as described in 

section 45V(c)(2). On January 1, 2026, 

Facility Z was retrofitted to produce 

qualified clean hydrogen. After the 

retrofit, the cost of the new property 

included in Facility Z is greater than 80 

percent of Facility Z’s total value. 

(ii) Analysis. Even though Facility Z 

does not satisfy the requirements of 

section 45V(d)(4) because Facility Z was 

not originally placed in service before 

January 1, 2023, under paragraph (b) of 

this section, Facility Z is deemed to be 

originally placed in service on January 

1, 2026, because Facility Z meets the 80/ 

20 Rule. Thus, a section 45V credit is 

allowable for qualified clean hydrogen 

produced at Facility Z during the 10- 

year period beginning on January 1, 

2026, assuming all other requirements 

of section 45V are met. 

(5) Example 5: Retrofit of an Existing 

Facility (80/20 Rule) and coordination 

with section 45Q credit previously 

allowed—(i) Facts. The facts are the 

same as in paragraph (c)(4) of this 

section (Example 4), except that before 

the retrofit, Facility Z included CCE for 

which a section 45Q credit was allowed 

to a taxpayer. 

(ii) Analysis. Under paragraph (b) of 

this section and § 1.45V–2(a), Facility Z 

is deemed to be originally placed in 

service on January 1, 2026, because 

Facility Z meets the 80/20 Rule. 

However, a section 45V credit is not 

allowable for qualified clean hydrogen 

produced at Facility Z during the 10- 

year period beginning on January 1, 

2026, because a section 45Q credit has 

been allowed to a taxpayer with regard 

to the CCE included in Facility Z. 

(d) Applicability date. This section 

applies to taxable years beginning after 

December 26, 2023. 

■ Par. 3. Section 1.48–15 is added to 

read as follows: 

§ 1.48–15 Election to treat clean hydrogen 

production facility as energy property. 

(a) In general. Under section 48(a)(15) 

of the Internal Revenue Code (Code), a 

taxpayer that owns and places in service 

a specified clean hydrogen production 

facility (as defined in section 

48(a)(15)(C) and paragraph (b) of this 

section) can make an irrevocable 

election under section 48(a)(15)(C)(ii)(II) 

to treat any qualified property (as 

defined in section 48(a)(5)(D)) that is 

part of the facility as energy property for 

purposes of section 48. 

(b) Specified clean hydrogen 

production facility. The term specified 

clean hydrogen production facility 

means any qualified clean hydrogen 

production facility— 

(1) That is placed in service after 

December 31, 2022; 

(2) With respect to which no credit 

has been allowed under section 45V or 

45Q of the Code, and for which the 

taxpayer makes an irrevocable election 

to have section 48(a)(15) apply; and 

(3) For which an unrelated party has 

verified in the manner specified in 

paragraph (e) of this section that such 

facility produces hydrogen through a 

process or processes that results in 

lifecycle GHG emissions that are 

consistent with the hydrogen that such 

facility was designed and expected to 

produce under section 48(a)(15)(A)(ii) 

and paragraph (c) of this section. 

(c) Energy percentage—(1) In general. 

In the case of a specified clean hydrogen 

production facility that is designed and 

reasonably expected to produce 

qualified clean hydrogen through a 

process or processes that results in a 

lifecycle GHG emissions rate of: 

(i) Not greater than 4 kilograms of 

carbon dioxide equivalent (CO2e) per 

kilogram of hydrogen, and not less than 

2.5 kilograms of CO2e per kilogram of 

hydrogen, the energy percentage is 1.2 

percent; 

(ii) Less than 2.5 kilograms of CO2e 

per kilogram of hydrogen, and not less 

than 1.5 kilograms of CO2e per kilogram 

of hydrogen, the energy percentage is 

1.5 percent; 

(iii) Less than 1.5 kilograms of CO2e 

per kilogram of hydrogen, and not less 

than 0.45 kilograms of CO2e per 

kilogram of hydrogen, the energy 

percentage is 2 percent; and 

(iv) Less than 0.45 kilograms of CO2e 

per kilogram of hydrogen, the energy 

percentage is 6 percent. 

(2) Designed and reasonably expected 

to produce. Hydrogen that a facility is 

designed and reasonably expected to 

produce means hydrogen produced 

through a process or processes that 

result in the lifecycle GHG emissions 

rate specified in the annual verification 

report described in paragraph (e)(2) of 

this section for the taxable year in 

which the election is made. In the case 

of a facility that is designed and 

reasonably expected to produce 

hydrogen through multiple processes, 

the lifecycle GHG emissions rate must 

be determined using the weighted 

average of the lifecycle GHG emissions 

rates of all hydrogen production 

processes. 

(d) Time and manner of making the 

election—(1) In general. To make an 

election under section 

48(a)(15)(C)(ii)(II), a taxpayer must 

claim the section 48 credit with respect 

to a specified clean hydrogen 

production facility on a completed Form 

3468, Investment Credit, or any 

successor form(s), and file the form with 

the taxpayer’s Federal income tax return 

or information return for the taxable 

year in which the specified clean 

hydrogen production facility is placed 

in service. The taxpayer must also 

attach a statement to its Form 3468, or 

any successor form(s), filed with its 

Federal income tax return or 

information return that includes the 

information required by the instructions 

to Form 3468, or any successor form(s), 

for each specified clean hydrogen 

production facility subject to an 

election. A separate election must be 

made for each specified clean hydrogen 

production facility that meets the 

requirements provided in section 

48(a)(15) to treat the qualified property 

that is part of the facility as energy 

property. If any taxpayer owning an 

interest in a specified clean hydrogen 

production facility makes an election 

under section 48(a)(15)(C)(ii)(II) with 

respect to the specified clean hydrogen 

production facility, then that election is 

binding on all taxpayers that directly or 

indirectly own an interest in the 

specified clean hydrogen production 

facility. 

(2) Special rule for partnerships and 

S corporations. In the case of a specified 

clean hydrogen production facility 

owned by a partnership or an S 

corporation, the election under section 

48(a)(15)(C)(ii)(II) is made by the 

partnership or S corporation and is 

binding on all ultimate credit claimants 

(as defined in § 1.50–1(b)(3)(ii)). The 

partnership or S corporation must file a 

Form 3468, or any successor form(s), 

with its partnership or S corporation 

return for the taxable year in which the 

specified clean hydrogen production 

facility is placed in service to indicate 

that it is making the election, and attach 

a statement that includes all the 

information required by the instructions 

to Form 3468, or any successor form(s), 

for each specified clean hydrogen 

production facility subject to the 

election. The ultimate credit claimant 

must claim the section 48 credit on a 

completed Form 3468, or any successor 

form(s), and file such form on a timely 

filed (including extensions) Federal 

income tax return for the taxable year in 

which the ultimate credit claimant’s 

distributive share or pro rata share of 

the section 48 credit is taken into 

account under section 706(a) of the 

Code or section 1366(a) of the Code, 

respectively. The partnership or S 

corporation making the election must 

provide the ultimate credit claimants 

with the necessary information to 


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complete Form 3468, or any successor 

form(s), to claim the section 48 credit. 

(3) Election irrevocable. The election 

to treat qualified property that is part of 

a specified clean hydrogen production 

facility as energy property is 

irrevocable. 

(4) Election availability date. The 

election to treat qualified property that 

is part of a specified clean hydrogen 

production facility as energy property is 

available for property placed in service 

after December 31, 2022. In the case of 

any property placed in service after 

December 31, 2022, for which 

construction began before January 1, 

2023, the election under section 

48(a)(15)(C)(ii)(II) applies only to the 

extent of the basis of such property that 

is attributable to construction, 

reconstruction, or erection occurring 

after December 31, 2022. 

(5) 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 paragraph (f)(3) of this 

section, to treat the latest version of 

45VH2–GREET that was publicly 

available on the date when construction 

of the specified clean hydrogen facility 

began as the 45VH2–GREET Model. In 

the case of a facility owned by a 

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 paragraph (f)(3) of 

this section, to treat the first publiclyavailable version of 45VH2–GREET (that 

is, the version of 45VH2–GREET that 

was released in December 2023) as the 

45VH2–GREET Model. For purposes of 

this paragraph (d)(5), in the case of a 

facility that is modified to produce 

qualified clean hydrogen under section 

45V(d)(4) 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 (d)(5)(i) 

relates to the version of 45VH2–GREET 

and does not alter any other rules 

provided in this section. 

(ii) Time and manner of making 

election—(A) In general. The taxpayer 

makes the election described in 

paragraph (d)(5)(i) of this section with 

respect to a specified clean hydrogen 

production facility by attaching a 

statement to the Form 3468 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 the taxable period in 

which such facility is placed in service. 

(B) Special rule for facilities placed in 

service prior to January 1, 2024. In the 

case of a taxpayer that places in service 

a specified clean hydrogen production 

facility prior to January 1, 2024, the 

taxpayer must make the election 

described in paragraph (d)(5)(i) of this 

section by no later than the period of 

limitation on filing a claim for credit or 

refund under section 6511(a) for the 

taxable period in which such facility is 

placed in service. 

(6) Provisional emissions rate—(i) In 

general. A taxpayer files a petition with 

the Secretary for a provisional emissions 

rate (PER) by following the procedures 

stated in § 1.45V–4(c)(3) through (5), 

except, in lieu of attaching the PER 

petition to the Form 7210 in the first 

taxable year of production as specified 

in § 1.45V–4(c)(3), the taxpayer must 

attach the PER petition to the Form 

3468, or a successor form(s), attached to 

the taxpayer’s Federal income tax return 

for the taxable year in which the 

specified clean hydrogen production 

facility is originally placed in service. A 

taxpayer may use such PER to calculate 

the amount of the section 48 credit with 

respect to a specified clean hydrogen 

production facility, provided— 

(A) The lifecycle GHG emissions rate 

of the hydrogen produced at the 

specified clean hydrogen production 

facility 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 

§ 1.45V–4(c)(5); and 

(C) All other requirements of section 

48(a)(15) are met. 

(ii) Material change. For purposes of 

paragraph (d)(6)(i)(B), 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 

verification under paragraph (e) of this 

section. 

(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 paragraph (f)(3) of 

this section, to treat the first version of 

45VH2–GREET that includes the 

taxpayer’s specified clean hydrogen 

production facility’s hydrogen 

production pathway, as described in 

§ 1.45V–4(c)(2)(i), as the 45VH2–GREET 

Model. 

(B) Time and manner of making 

election. The taxpayer makes the 

election described in paragraph 

(d)(6)(iii) of this section with respect to 

a specified clean hydrogen production 

facility by attaching a statement to the 

Form 3468 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 the taxable period in 

which such facility is placed in service. 

(C) Special rule for facilities placed in 

service prior to January 1, 2024. In the 

case of a taxpayer that places in service 

a specified clean hydrogen production 

facility prior to January 1, 2024, the 

taxpayer must make the election 

described in paragraph (d)(6)(iii)(A) of 

this section by no later than the close of 

the period of limitation for filing a claim 

for credit or refund under section 

6511(a) for the taxable period in which 

such facility is placed in service. 

(iv) Special rule for facilities that 

receive an emissions value prior to the 

beginning of construction. 

Notwithstanding the requirement of 

paragraph (d)(6)(i)(A) of this section, a 

taxpayer who received an emissions 

value from the DOE with respect to a 

specified clean hydrogen production 

facility (pursuant to § 1.45V–4(c)(5)) 

before the date when construction of the 

facility began, may, in its discretion, 

continue to use the PER determined by 

the Secretary and the associated 

emissions value to calculate the 

lifecycle GHG emissions rate of the 

hydrogen produced at the specified 

clean hydrogen production facility for 

the remainder of the period described in 

paragraph (f)(3) of this section, provided 

that the taxpayer continues to satisfy the 

requirements of paragraphs (d)(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 48 credit is claimed. For 

example, the annual verification report 

submitted under section 48(a)(15)(C)(iii) 

and paragraph (e)(2) of this section 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 48(a)(15), 


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including the cross-references to section 

45V, have been satisfied for any taxable 

year. 

(e) Third-party verification—(1) In 

general. In the case of a taxpayer that 

makes an election under section 

48(a)(15)(C)(ii)(II) to treat any qualified 

property that is part of a specified clean 

hydrogen production facility as energy 

property for purposes of the section 48 

credit, the taxpayer must obtain an 

annual verification report for the taxable 

year in which the election under section 

48(a)(15)(C)(ii)(II) is made for the facility 

and for each taxable year thereafter 

during the recapture period specified in 

paragraph (f)(3) of this section. The 

taxpayer must also submit the annual 

verification report as an attachment to 

the Form 3468, or any successor form(s), 

for the taxable year in which the 

election under section 48(a)(15)(C)(ii)(II) 

is made for the facility. 

(2) Annual verification report—(i) In 

general. For purposes of paragraph (e)(1) 

of this section, the annual verification 

report must be signed under penalties of 

perjury by a qualified verifier (as 

defined in § 1.45V–5(h)) and contain an 

attestation providing all of the 

following— 

(A) The information specified in 

§ 1.45V–5(b) and (d) through (h); 

(B) A statement attesting to the 

lifecycle GHG emissions rate of the 

hydrogen produced through a process 

(determined under section 45V(c) and 

§ 1.45V–4), or the weighted average of 

the lifecycle GHG emissions rate of the 

hydrogen produced through processes, 

by which all hydrogen was produced at 

the specified clean hydrogen production 

facility for the taxable year to which the 

annual verification report relates and 

that the operation, during such taxable 

year, of the specified clean hydrogen 

production facility, and any qualifying 

energy attribute certificates applied 

pursuant to § 1.45V–4(d) for the purpose 

of accounting for such facility’s 

emissions, are accurately reflected in 

the data that the taxpayer entered into 

the 45VH2–GREET Model (as defined in 

§ 1.45V–1(a)(9)(ii)) (or that the taxpayer 

provided to the Department of Energy 

(DOE) in support of the taxpayer’s 

request for an emissions value), to 

determine the lifecycle GHG emissions 

rate of the hydrogen undergoing 

verification; and 

(C) A statement attesting that the 

facility produced hydrogen through a 

process or processes that results in a 

lifecycle GHG emissions rate that is 

consistent with, or lower than, the 

lifecycle GHG emissions rate of the 

hydrogen that such facility was 

designed and expected to produce. 

(ii) Inconsistent lifecycle GHG 

emissions. In the event the facility 

produces hydrogen through a process 

(or processes) that results in a lifecycle 

GHG emissions rate that is greater than 

the lifecycle GHG emissions rate that 

such facility was designed and expected 

to produce (and thus the qualified 

verifier cannot provide the attestation 

specified in paragraph (e)(2)(i)(C) of this 

section), resulting in a reduced energy 

percentage under section 48(a)(15)(A)(ii) 

with respect to such facility, an 

emissions tier recapture event under 

paragraph (f)(2) of this section will 

occur. 

(iii) Designed and expected to 

produce. Hydrogen that the facility was 

designed and expected to produce 

means hydrogen specified in paragraph 

(c)(2) of this section. 

(iv) Timely annual verification report. 

The annual verification report must be 

signed and dated by the qualified 

verifier no later than the due date, 

including extensions, of the Federal 

income tax return for the taxable year in 

which the hydrogen undergoing 

verification was produced. 

(v) Records retention. In addition to 

the recordkeeping requirements set forth 

in paragraph (g) of this section, the 

taxpayer must retain the annual 

verification report for at least six years 

after the due date, with extensions, for 

filing the Federal income tax return for 

the taxable year in which the hydrogen 

undergoing verification was produced. 

(f) Recapture—(1) In general. 

Pursuant to of section 48(a)(15)(E), in 

any taxable year of the recapture period 

specified in paragraph (f)(3) of this 

section in which an emissions tier 

recapture event (as defined in paragraph 

(f)(2) of this section) occurs, the tax 

imposed on the taxpayer under chapter 

1 of the Code for the taxable year of the 

emissions tier recapture event is 

increased by the recapture amount 

specified in paragraph (f)(4) of this 

section. 

(2) Emissions tier recapture event. For 

purposes of paragraph (f)(1) of this 

section, an emissions tier recapture 

event is any of the following 

occurrences— 

(i) The taxpayer fails to obtain an 

annual verification report by the 

deadline for filing its Federal income 

tax return or information return 

(including extensions) for any taxable 

year in which an annual verification 

report is required under paragraph (e)(1) 

of this section; 

(ii) The specified clean hydrogen 

production facility actually produced 

hydrogen through a process (or 

processes) that results in a lifecycle 

GHG emissions rate that can only 

support a lower energy percentage than 

the energy percentage used to calculate 

the amount of the section 48 credit for 

the facility for the taxable year in which 

the facility is placed in service; or 

(iii) The specified clean hydrogen 

production facility actually produced 

hydrogen through a process (or 

processes) that results in a lifecycle 

GHG emissions rate of greater than 4 

kilograms of CO2e per kilogram of 

hydrogen. 

(3) Recapture period. For purposes of 

paragraph (f) of this section, the 

recapture period begins on the first day 

of the taxable year after the taxable year 

in which the facility was placed in 

service and ends on the close of the fifth 

taxable year following the close of the 

taxable year in which the facility was 

placed in service. 

(4) Recapture amount—(i) In general. 

In the case of an emissions tier 

recapture event under paragraph (f)(2) of 

this section, the recapture amount for 

the taxable year in which the emissions 

tier recapture event occurred is equal to 

20 percent of the excess of the section 

48 credit allowed to the taxpayer for the 

specified clean hydrogen production 

facility for the taxable year in which the 

facility was placed in service, over the 

section 48 credit that would have been 

allowed to the taxpayer for the facility 

if the taxpayer had used the energy 

percentage supported by the actual 

production to calculate the amount of 

the section 48 credit. 

(ii) Carrybacks and carryovers. In the 

case of any emissions tier recapture 

event described in paragraph (f)(2) of 

this section, the carrybacks and 

carryovers under section 39 must be 

adjusted by reason of the emissions tier 

recapture event. 

(iii) Recapture amount in case of 

recapture events under paragraph 

(f)(2)(i) or (iii) of this section. For 

purposes of paragraph (f)(4)(i) of this 

section, in the case of an emissions tier 

recapture event under paragraph (f)(2)(i) 

or (iii) of this section, the amount of the 

section 48 credit that would have been 

allowed to the taxpayer for the specified 

clean hydrogen production facility if the 

taxpayer had used the energy percentage 

supported by the actual production is 

zero. Accordingly, the recapture amount 

in the taxable year of an emissions tier 

recapture event under paragraph (f)(2)(i) 

or (iii) of this section, is 20 percent of 

the section 48 credit allowed to the 

taxpayer for such specified clean 

hydrogen production facility. 

(5) Example. The following example 

illustrates the application of paragraphs 

(f)(1) through (4) of this section. 

(i) Facts. On June 1, 2024, Taxpayer, 

a calendar-year taxpayer, originally 


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places in service Facility X, a specified 

clean hydrogen production facility. At 

such time, Taxpayer’s basis in qualified 

property that is part of Facility X is 

$100,000,000. In the taxable year in 

which Facility X was originally placed 

in service (taxable year 2024), Facility X 

produces qualified clean hydrogen 

through a process that results in a 

lifecycle GHG emissions rate of 0.44kg 

of CO2e per kilogram of hydrogen. 

Taxpayer submits with its 2024 Federal 

income tax return an annual verification 

report attesting that, for the taxable year 

2024, Facility X produced hydrogen 

through a process that resulted in a 

lifecycle GHG emissions rate of 0.44kg 

of CO2e per kilogram of hydrogen, 

which is consistent with the lifecycle 

GHG emissions rate of the hydrogen that 

the facility was designed and expected 

to produce. Taxpayer makes a valid 

election under section 48(a)(15)(C)(ii)(II) 

with respect to Facility X on its Federal 

income tax return for the taxable year 

2024. In the first year of the recapture 

period (taxable year 2025), Taxpayer 

fails to obtain an annual verification 

report by the deadline (including 

extensions) for filing its 2025 Federal 

income tax return. In the second year of 

the recapture period (taxable year 2026), 

Facility X produces qualified clean 

hydrogen through a process that results 

in a lifecycle GHG emissions rate of 

1.4kg of CO2e per kilogram of hydrogen 

and obtains an annual verification 

report attesting to such lifecycle GHG 

emissions rate. In the third, fourth, and 

fifth years of the recapture period 

(taxable years 2027, 2028, and 2029), 

Facility X produces qualified clean 

hydrogen through a process that results 

in a lifecycle GHG emissions rate of 

0.44kg of CO2e per kilogram of 

hydrogen and obtains an annual 

verification report attesting to such 

lifecycle GHG emissions rate, and 

attesting that such lifecycle GHG 

emissions rate is consistent with the 

lifecycle GHG emissions rate of the 

hydrogen that the facility was designed 

and expected to produce, by the 

deadline (including extensions) for 

filing its 2027, 2028, and 2029 Federal 

income tax returns, respectively. 

(ii) Analysis. Facility X is designed 

and reasonably expected to produce 

hydrogen through a process that results 

in a lifecycle GHG emissions rate of 

0.44kg of CO2e per kilogram of 

hydrogen, which is the rate specified in 

Taxpayer’s annual verification report 

submitted with Taxpayer’s Federal 

income tax return for the taxable year in 

which the election under section 

48(a)(15)(C)(ii)(II) with respect to 

Facility X was made. Under paragraph 

(c)(1)(iv) of this section, Facility X’s 

energy percentage is therefore 6 percent. 

For the taxable year 2024, the year in 

which Taxpayer places in service 

Facility X, Taxpayer claims a section 48 

credit for its basis in qualified property 

that is part of Facility X in the amount 

of $6,000,000 (6 percent of 

$100,000,000). In taxable year 2025 

there is an emissions tier recapture 

event under paragraph (f)(2)(i) of this 

section because Taxpayer failed to 

obtain an annual verification report. 

Under paragraph (f)(4)(i) of this section, 

the amount of the section 48 credit 

recaptured in 2025 is $1,200,000. This 

reflects 20 percent of the section 48 

credit allowed ($6,000,000) for Facility 

X. In taxable year 2026, there is an 

emissions tier recapture event under 

paragraph (f)(2)(ii) of this section 

because Facility X produced hydrogen 

through a process that resulted in a 

lifecycle GHG emissions rate that could 

only support an energy percentage of 2 

percent, which is lower than the energy 

percentage used to calculate the amount 

of the section 48 credit for Facility X. 

Under paragraph (f)(4)(i) of this section, 

the amount of the section 48 credit 

recaptured in 2026 is $800,000. This 

reflects 20 percent of the difference 

between the amount of the section 48 

credit allowed ($6,000,000) and the 

amount of the section 48 credit that 

would have been allowed for Facility X 

if Taxpayer had used the energy 

percentage supported by the actual 

production ($2,000,000). There is no 

emissions tier recapture event in taxable 

years 2027, 2028, or 2029 because, in 

those years, Facility X produced 

hydrogen through a process that 

resulted in a lifecycle GHG emissions 

rate that was consistent with the 

lifecycle GHG emissions rate of the 

hydrogen that Facility X was designed 

and expected to produce, and Taxpayer 

obtained an annual verification report 

attesting to such by the deadline (with 

extensions) for filing its Federal income 

tax return for each of those taxable 

years. 

(6) Coordination with sections 50(a) 

and 48(a)(10)(C) of the Code—(i) In 

general. In each taxable year of the 

recapture period specified in paragraph 

(f)(3) of this section for any credit 

allowed under section 48 with respect 

to a specified clean hydrogen 

production facility, the recapture rules, 

if applicable, apply in the following 

order: 

(A) Section 50(a); 

(B) Section 48(a)(10)(C), as provided 

in § 1.48–13; and 

(C) Section 48(a)(15)(E). 

(ii) The following examples illustrate 

the application of paragraph (f)(6) of this 

section. 

(A) Example 1—(1) Facts. The facts 

are the same as in paragraph (f)(5)(i) of 

this section (Example), except that, in 

addition to failing to obtain an annual 

verification report by the deadline 

(including extensions) for filing its 2025 

Federal income tax return, on August 1, 

2025, Taxpayer disposes of Facility X. 

Taxpayer has not been allowed any 

other credits under section 38. 

(2) Analysis. For taxable year 2025, 

under section 50(a)(1)(B)(ii), because the 

period of time between when Facility X 

was placed in service is more than 1, 

but less than 2 full years, the applicable 

recapture percentage is 80 percent. 

Taxpayer has an increase in tax for 

taxable year 2025 under section 50(a) of 

$4,800,000 ($6,000,000 aggregate 

decrease in credit allowed multiplied by 

0.80). Under paragraph (f)(6) of this 

section, because the credit was 

recaptured under section 50(a), no 

further amounts would be recaptured 

under either section 48(a)(10)(C) (had 

Taxpayer claimed the increased credit 

amount under section 48(a)(9)) or 

section 48(a)(15)(E) (on account of 

Taxpayer’s failure to obtain an annual 

verification report). 

(B) Example 2—(1) Facts. The facts 

are the same as in paragraph (f)(5)(i) of 

this section (Example), except that, in 

taxable year 2025, Facility X produces 

qualified clean hydrogen through a 

process that results in a lifecycle GHG 

emissions rate of 1.4 kilograms of CO2e 

per kilogram of hydrogen and obtains an 

annual verification report attesting to 

such lifecycle GHG emissions rate. On 

August 1, 2026, Taxpayer disposes of 

Facility X. Taxpayer has not been 

allowed any other credits under section 

38. 

(2) Analysis. In taxable year 2025, 

there is an emissions tier recapture 

event under paragraph (f)(2)(ii) of this 

section because Facility X produced 

hydrogen through a process that 

resulted in a lifecycle GHG emissions 

rate that could only support an energy 

percentage of 2 percent, which is lower 

than the energy percentage used to 

calculate the amount of the section 48 

credit for Facility X. Under paragraph 

(f)(4)(i) of this section, the amount of the 

section 48 credit recaptured in 2025 is 

$800,000. In taxable year 2026, under 

section 50(a)(1)(B)(iii), because the 

period of time between when Facility X 

was placed in service is more than 2, 

but less than 3 full years, the applicable 

recapture percentage is 60 percent. 

Taxpayer has an increase in tax under 

section 50(a) of $3,120,000 ($5,200,000 

aggregate decrease in credit allowed 


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($6,000,000 credit allowed minus 

$800,000 amount recaptured under 

paragraph (f)(2)(ii) of this section in 

taxable year 2025) multiplied by 0.60). 

(g) Recordkeeping. Consistent with 

section 6001 of the Code, a taxpayer 

making the election under section 

48(a)(15)(C)(ii)(II) with respect to a 

specified clean hydrogen production 

facility must maintain and preserve 

records sufficient to establish the 

amount of the section 48 credit claimed 

by the taxpayer. At a minimum, those 

records include the annual verification 

report required under paragraph (e)(2) of 

this section, records to substantiate the 

information required to be included in 

the annual verification report, records 

establishing that the facility meets the 

definition of a specified clean hydrogen 

production facility under section 

48(a)(15)(C) and paragraph (b) of this 

section, records of past credit claims 

under section 45Q by any taxpayer with 

respect to carbon capture equipment 

included at the facility, and records 

establishing the date the specified clean 

hydrogen production facility was placed 

in service. If the increased section 48 

credit amount was allowed under 

section 48(a)(9), then the taxpayer must 

also maintain records in accordance 

with § 1.45–12. Taxpayers must also 

retain all raw data used for submission 

of a request for an emissions value to 

the DOE for at least six years after the 

due date (including extensions) for 

filing the Federal income tax return or 

information return to which the 

provisional emissions rate (PER) (as 

defined in § 1.45V–4(c)(1)) petition is 

ultimately attached. 

(h) Applicability date. This section 

applies to taxable years beginning after 

December 26, 2023. 

Douglas W. O’Donnell, 

Deputy Commissioner. 

Approved: December 25, 2024. 

Aviva R. Aron-Dine, 

Deputy Assistant Secretary of the Treasury 

(Tax Policy). 

[FR Doc. 2024–31513 Filed 1–3–25; 8:45 am] 

BILLING CODE 4830–01–P 


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