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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
Internal Revenue Service (IRS),
Treasury.
ACTION: Final regulations.
AGENCY:

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:
SUMMARY:

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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

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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

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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
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.

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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

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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
1 The 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.
2 Section 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.
3 See §§ 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.

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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.
4 Under § 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.

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

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

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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
5 Section 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.

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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

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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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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).

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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

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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

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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
6 A 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.

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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.

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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

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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

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‘‘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

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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

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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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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.

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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.

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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

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‘‘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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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
7 Regulatory 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.

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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

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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.
8 See generally GREET, Office of Energy
Efficiency & Renewable Energy, U.S. Department of
Energy, available at https://www.energy.gov/eere/
greet.

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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 GREET 9).
Implementation of the section 45V
9 Summary of Expansions and Updates in R&D
GREET 2023 (2023), Argonne National Laboratory,
available at https://greet.anl.gov/files/greet-2023summary (R&D GREET Supporting Documentation).

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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
10 For 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

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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
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.

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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.’’

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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

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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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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

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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

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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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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

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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

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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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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

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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
11 Process, 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).

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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

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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

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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

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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

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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 10year 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

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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 10year 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 10year 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

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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.

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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

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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.

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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

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§ 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

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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)

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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

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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

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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

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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

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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.

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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

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

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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

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2245

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 10year 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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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,
13 2022–52

I.R.B. 560.
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.
15 See Notice 2020–12, 2020–11 I.R.B. 495.
16 See Notice 2018–59, modified by Notice 2019–
43 and by Notice 2020–41, and then clarified and
modified by Notice 2024–41.

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14 See

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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

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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

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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

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§ 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

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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

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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

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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.

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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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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
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§ 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

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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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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

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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
17 Double Counting, U.S. Environmental
Protection Agency, available at https://
www.epa.gov/green-power-markets/doublecounting (last updated Jan. 15, 2024).

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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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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

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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

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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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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.
18 WREGIS 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).

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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

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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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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

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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

19 See 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).

20 See 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’’).

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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
21 DOE

Technical Paper supra note 20.
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).
23 Wilson 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),

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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
available at https://energyinnovation.org/wpcontent/uploads/Smart-Design-Of-45V-HydrogenProduction-Tax-Credit-Will-Reduce-Emissions-AndGrow-The-Industry.pdf.
25 The 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/.
26 See EPA December 2023 Letter supra note 19.

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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,

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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)

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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

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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

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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

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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

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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 fuel-

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fired 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

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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

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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,

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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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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
27 Because this is an alternative pathway only to
the incrementality requirement, the deliverability
and temporal matching requirements still apply.

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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

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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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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

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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.
28 California 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.
29 See Morgan Browning, et al., Net-Zero CO by
2
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.

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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
30 Preliminary 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/.

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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
31 See

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).

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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 rate32 For

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.

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cases 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
33 For 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.

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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 long-

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term 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

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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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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

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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

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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 broad-

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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 36month 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

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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

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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
34 See 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.

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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

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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
35 National Renewable Energy Laboratory,
Regional Energy Deployment System (ReEDS)
Model Documentation (2021), available at https://
www.nrel.gov/docs/fy21osti/78195.pdf.

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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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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

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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
36 Rachael 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.
37 See DOE Technical Paper supra note 20.

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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

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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

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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 minimal-

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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

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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
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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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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.

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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

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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
38 U.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’’).

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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.

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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

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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

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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.

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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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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

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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.

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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.

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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

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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
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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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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
39 The 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.

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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

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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
40 The 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.

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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

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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.

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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

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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

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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.

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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

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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,

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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

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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

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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

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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

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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

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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

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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

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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

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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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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

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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
41 LMOP 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.
43 AgSTAR 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.

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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

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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

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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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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

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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,
46 U.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.
47 Non-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.
48 Reconsideration 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=2060AU24.

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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
49 U.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.

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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
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.

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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

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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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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
52 Active 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.

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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

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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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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

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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
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).
54 Aaron 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/.

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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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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

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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).
55 U.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.

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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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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

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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
56 See, for example, Waste Prevention, Production
Subject to Royalties, and Resource Conservation, 89
FR 25378 (Apr. 10, 2024).

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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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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

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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

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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

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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

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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

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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

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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

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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
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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

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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
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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

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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

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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.

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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

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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.

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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,

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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

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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

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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)

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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

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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.

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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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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.

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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

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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.

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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

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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

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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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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).

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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

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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

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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

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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

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2305

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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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,

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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

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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.

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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

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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

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2307

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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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.

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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

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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

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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

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 * * *

*

*

*

*

*

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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).

*

*

*

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*

*

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*

*
*
*
*
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.

*

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.

■

Section 1.48–15 also issued under 26
U.S.C. 48(a)(15)

*

§ 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.

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§ 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

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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.

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(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

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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.

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(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

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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

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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.

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§ 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

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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

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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

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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

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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

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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

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2315

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—

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(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

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

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Balancing Authority

Region

Balancing Authority of Northern California ....................................................................................................................
California Independent System Operator (Balancing Authority) ...................................................................................
Imperial Irrigation District ...............................................................................................................................................
Los Angeles Dept of Water & Power ............................................................................................................................
Turlock Irrigation District ................................................................................................................................................
Midcontinent ISO (Balancing Authority): South .............................................................................................................
Duke Energy Florida Inc ................................................................................................................................................
Florida Municipal Power Pool ........................................................................................................................................
Florida Power & Light ....................................................................................................................................................
Gainesville Regional Utilities .........................................................................................................................................
Homestead (City of) .......................................................................................................................................................
JEA ................................................................................................................................................................................
New Smyrna Beach Utilities Commission .....................................................................................................................
Reedy Creek Improvement District ...............................................................................................................................
Seminole Electric Coop Inc ...........................................................................................................................................
Tallahassee FL (City of) ................................................................................................................................................
Tampa Electric Co .........................................................................................................................................................
East Kentucky Power Coop Inc .....................................................................................................................................
LG&E & KU Services Co ...............................................................................................................................................
Ohio Valley Electric Corp ..............................................................................................................................................
PJM Interconnection ......................................................................................................................................................
Associated Electric Coop Inc .........................................................................................................................................
Electric Energy Inc .........................................................................................................................................................
Gridliance Heartland ......................................................................................................................................................
Midcontinent ISO (Balancing Authority): North and Central ..........................................................................................
NaturEner Power Watch LLC (GWA) ............................................................................................................................
NaturEner Wind Watch LLC ..........................................................................................................................................
Nevada Power Co .........................................................................................................................................................
Northwestern Energy .....................................................................................................................................................
PacifiCorp East ..............................................................................................................................................................
Public Service Co of Colorado ......................................................................................................................................
WAPA Rocky Mountain Region .....................................................................................................................................
WAPA Upper Great Plains West ...................................................................................................................................
New England ISO (Balancing Authority) .......................................................................................................................
Northern Maine ..............................................................................................................................................................
New York ISO (Balancing Authority) .............................................................................................................................
Avangrid Renewables LCC ...........................................................................................................................................
Avista Corp ....................................................................................................................................................................
Bonneville Power Administration ...................................................................................................................................
Gridforce Energy Management LLC ..............................................................................................................................
Idaho Power Co .............................................................................................................................................................
PacifiCorp West .............................................................................................................................................................
Portland General Electric ...............................................................................................................................................
PUD No 1 of Chelan County .........................................................................................................................................
PUD No 1 of Douglas County .......................................................................................................................................
PUD No 2 of Grant County ...........................................................................................................................................
Puget Sound Energy Inc ...............................................................................................................................................
Seattle City Light ...........................................................................................................................................................
Tacoma Power ...............................................................................................................................................................
Southwest Power Pool (Balancing Authority) ................................................................................................................
Southwestern Power Administration ..............................................................................................................................
Alcoa Power Generating Inc Yadkin Division ................................................................................................................

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California.
California.
California.
California.
California.
Delta.
Florida.
Florida.
Florida.
Florida.
Florida.
Florida.
Florida.
Florida.
Florida.
Florida.
Florida.
Mid-Atlantic.
Mid-Atlantic.
Mid-Atlantic.
Mid-Atlantic.
Midwest.
Midwest.
Midwest.
Midwest.
Mountain.
Mountain.
Mountain.
Mountain.
Mountain.
Mountain.
Mountain.
Mountain.
New England.
New England.
New York.
Northwest.
Northwest.
Northwest.
Northwest.
Northwest.
Northwest.
Northwest.
Northwest.
Northwest.
Northwest.
Northwest.
Northwest.
Northwest.
Plains.
Plains.
Southeast.

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TABLE 1 TO PARAGRAPH (d)(2)(ix)—Continued
Balancing Authority

Region

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Duke Energy Carolinas LLC ..........................................................................................................................................
Duke Energy Progress East ..........................................................................................................................................
Duke Energy Progress West .........................................................................................................................................
PowerSouth Energy Coop .............................................................................................................................................
South Carolina Electric & Gas Co .................................................................................................................................
South Carolina Public Service Authority .......................................................................................................................
Southeastern Power Administration (Southern) ............................................................................................................
Southern Co Services Inc ..............................................................................................................................................
Tennessee Valley Authority ...........................................................................................................................................
Arizona Public Service Co .............................................................................................................................................
Arlington Valley LLC ......................................................................................................................................................
El Paso Electric .............................................................................................................................................................
Gila River Power LLC ....................................................................................................................................................
Griffith Energy LLC ........................................................................................................................................................
New Harquahala Generating Co LLC ...........................................................................................................................
Public Service Co of New Mexico .................................................................................................................................
Salt River Project ...........................................................................................................................................................
Tucson Electric Power Co .............................................................................................................................................
WAPA Desert Southwest Region ..................................................................................................................................
ERCOT ISO (Balancing Authority) ................................................................................................................................

(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

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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

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Southeast.
Southeast.
Southeast.
Southeast.
Southeast.
Southeast.
Southeast.
Southeast.
Southeast.
Southwest.
Southwest.
Southwest.
Southwest.
Southwest.
Southwest.
Southwest.
Southwest.
Southwest.
Southwest.
Texas.

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

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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

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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

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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

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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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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
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(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

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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.

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§ 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);

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(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

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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

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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

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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.

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§ 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

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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

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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 10year 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 10year 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:

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§ 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

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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

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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

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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.

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(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.

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(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

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2327

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

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(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).

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(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

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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

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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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