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DEPARTMENT OF THE TREASURY
Internal Revenue Service
26 CFR Part 1
[TD 10024]
RIN 1545–BR17

Section 45Y Clean Electricity
Production Credit and Section 48E
Clean Electricity Investment Credit
Internal Revenue Service (IRS),
Treasury.
ACTION: Final regulations.
AGENCY:

This document sets forth final
regulations regarding the clean
electricity production credit and the
clean electricity investment credit
established by the Inflation Reduction
Act of 2022. These final regulations
provide rules for determining
greenhouse gas emissions rates resulting
from the production of electricity;
petitioning for provisional emissions
rates; and determining eligibility for
these credits in various circumstances.
The final regulations affect all taxpayers
that claim the clean electricity
production credit with respect to a
qualified facility or the clean electricity
investment credit with respect to a
qualified facility or energy storage
technology, as applicable, that is placed
in service after 2024.
DATES:
Effective date: These regulations are
effective on January 15, 2025.
Applicability dates: For dates of
applicability, see §§ 1.45Y–1(e), 1.45Y–
2(d), 1.45Y–3(d) 1.45Y–4(e), 1.45Y–5(j),
1.48E–1(e), 1.48E–2(h), 1.48E–3(f),
1.48E–4(j), and 1.48E–5(l).
FOR FURTHER INFORMATION CONTACT:
Maksim Berger, John M. Deininger,
Martha M. Garcia, Boris Kukso,
Nathaniel Kupferman, and Alexander
Scott at (202) 317–6853 (not a toll-free
number).
SUPPLEMENTARY INFORMATION:
SUMMARY:

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Authority
This Treasury decision amends the
Income Tax Regulations (26 CFR part 1)
to implement the statutory provisions of
sections 45Y and 48E of the Internal
Revenue Code (Code). The regulations
contained in this Treasury decision are
issued by the Secretary of the Treasury
or her delegate (Secretary) pursuant to
the authority granted under sections
45Y(f), 48E(i) and 7805(a) of the Code
(final regulations).
Section 45Y(f) provides an express
delegation of authority to the Secretary
to prescribe rules to implement section
45Y, ‘‘including calculation of

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greenhouse gas emissions rates for
qualified facilities and determination of
clean electricity production credits
under section 45Y.’’ Section 48E(i)
provides an express delegation of
authority to prescribe rules ‘‘regarding
implementation of [section 48E].’’
Finally, section 7805(a) authorizes the
Secretary ‘‘to 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
On August 30, 2023, the Treasury
Department and the IRS published a
notice of proposed rulemaking and a
notice of public hearing (REG–100908–
23) in the Federal Register (88 FR
60018), corrected in 88 FR 73807 (Oct.
27, 2023), and 89 FR 25550 (April 11,
2024), providing guidance on the
Prevailing Wage and Apprenticeship
(PWA) requirements under sections
30C, 45, 45L, 45Q, 45U, 45V, 45Y, 45Z,
48, 48C, 48E, and 179D (PWA proposed
regulations).
On November 22, 2023, the Treasury
Department and the IRS published a
notice of proposed rulemaking and a
notice of public hearing (REG–132569–
17) in the Federal Register (88 FR
82188), corrected in 89 FR 2182
(January 12, 2024), proposing rules that
would provide guidance under section
48 (section 48 proposed regulations). On
February 22, 2024, the Treasury
Department and the IRS published a
second correction to the proposed
regulations in the Federal Register (89
FR 13293) that re-opened the comment
period through March 25, 2024. Among
other matters, the section 48 proposed
regulations withdrew and reproposed
§ 1.48–13 of the PWA proposed
regulations addressing the PWA
requirements under section 48, the rules
under section 48(a)(9)(B)(i) related to an
energy project with a maximum net
output of less than one megawatt of
electrical (as measured in alternating
current) or thermal energy (One
Megawatt Exception), and the recapture
rules under section 48(a)(10)(C) related
to the prevailing wage requirements.
Although the section 48 proposed
regulations withdrew certain portions of
the PWA proposed regulations, the
section 48 proposed regulations
incorporated the preamble to the PWA
proposed regulations for generally
applicable rules.
On June 3, 2024, a notice of proposed
rulemaking (REG–119283–23) relating to
the clean electricity production credit
determined under section 45Y (section
45Y credit) and the clean electricity

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investment credit determined under
section 48E (section 48E credit) was
published in the Federal Register (89
FR 47792) proposing amendments to 26
CFR part 1 (proposed regulations). See
the Background and Explanation of
Provisions sections of the preamble to
the proposed regulations, which is
incorporated in this preamble to the
extent consistent with the following
Summary of Comments and Explanation
of Revisions. Additionally, the Treasury
Department and the IRS requested
comments on the proposed definition of
a qualified facility with a maximum net
output of less than one megawatt (as
measured in alternating current) for
purposes of the One Megawatt
Exception under section 45Y(a)(2)(B)(i).
The proposed regulations incorporated
the preamble to the PWA proposed
regulations for generally applicable
rules.
On June 25, 2024, the Treasury
Department and the IRS published final
regulations (T.D. 9998) in the Federal
Register (89 FR 53184) adopting the
PWA proposed regulations (PWA final
regulations) with certain modifications
and revisions in response to public
comments on the PWA proposed
regulations. Comments received on
generally applicable rules in response to
the PWA proposed regulations,
including rules that merely referenced
section 48 or 48E, are addressed in the
PWA final regulations. The preamble to
the PWA final regulations explained
that comments received regarding the
specific PWA requirements related to
the One Megawatt Exception under
sections 45Y, 48, and 48E, and the
recapture rules in section 48(a)(10)(C),
whether received in response to the
PWA proposed regulations or the
section 48 proposed regulations, would
be addressed in future guidance.
Because proposed § 1.48E–3 of the PWA
proposed regulations generally
incorporated the rules of proposed
§ 1.48–13, the PWA final regulations did
not include final regulations under
section 48E. Proposed § 1.48E–3 of the
PWA proposed regulations and the
provisions relating to section 48E of the
proposed regulations would be
addressed in future guidance.
On December 12, 2024, the Treasury
Department and the IRS published final
regulations (T.D. 10015) in the Federal
Register (89 FR 100598) adopting the
section 48 proposed regulations,
including the rules for the PWA
requirements in § 1.48–13 (section 48
final regulations). The Treasury
Department and the IRS addressed the
comments related to the PWA
requirements with respect to section 48
including the One Megawatt Exception

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under section 48(a)(9)(B)(i), the
recapture rules under section
48(a)(10)(C), and the definition of an
energy project in the section 48 final
regulations.
As described in the Summary of
Comments and Explanation of
Revisions, this Treasury decision adopts
the proposed regulations with certain
modifications after full consideration of
all comments received, including
comments pertaining to the One
Megawatt Exception under section
45Y(a)(2)(B)(i) and to issues related to
the PWA requirements under section
48E and proposed § 1.48E–3.

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Summary of Comments and
Explanation of Revisions
I. Overview
The Treasury Department and the IRS
received over 1,800 written comments
timely submitted by the August 2, 2024,
comment submission deadline, in
response to the proposed regulations,
which are available for public
inspection at https://
www.regulations.gov or upon request. A
public hearing was held in person on
August 12, 2024, and telephonically on
August 13, 2024, at which 36 speakers
provided testimony over the two days.
After careful consideration of the
comments and testimony, the proposed
regulations are adopted with
modifications as described in this
Summary of Comments and Explanation
of Revisions.
Comments summarizing the statute or
the proposed regulations,
recommending statutory revisions to
sections 45Y and 48E or other statutes,
or addressing issues that are outside the
scope of this rulemaking (such as
revising other Federal regulations and
recommending changes to IRS forms)
are generally not described in this
Summary of Comments and Explanation
of Revisions or adopted in these final
regulations. In addition to modifications
described in this Summary of
Comments and Explanation of
Revisions, the final regulations also
include non-substantive grammatical or
stylistic changes to the proposed
regulations. Unless otherwise indicated
in this Summary of Comments and
Explanation of Revisions, provisions of
the proposed regulations with respect to
which no comments were received are
adopted without substantive change.
The Treasury Department and the IRS
consulted extensively with scientific
and technical experts from across the
Federal government, including
personnel from the Department of
Energy (DOE), the Environmental
Protection Agency (EPA), and the

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Department of Agriculture (USDA), in
developing and drafting these final
regulations. The Treasury Department
and the IRS had regular working group
meetings with these experts from the
time that sections 45Y and 48E were
enacted by the Inflation Reduction Act
(IRA) through the drafting and
publication of the proposed and final
regulations. These meetings included
discussions on the full range of issues
related to determining greenhouse gas
emissions rates for the production of
electricity, petitioning for provisional
emissions rates, and determining
eligibility for the section 45Y and 48E
credits in various circumstances. These
meetings also included comprehensive
briefing and full consideration of the
issues raised in the comments received
on the proposed regulations and
proposed § 1.48E–3 of the PWA
proposed regulations. In addition,
experts from the DOE, the EPA, and the
USDA reviewed multiple drafts of the
proposed and final regulations in their
entirety. The conclusions reached in
these final regulations and explained in
this Summary of Comments and
Explanation of Revisions were deeply
informed by these working group
meetings and the scientific and
technical expertise that was shared in
those meetings.
For purposes of this preamble, a
provision of the proposed regulations,
for example, § 1.45Y–1 of the proposed
regulations, is referred to as ‘‘proposed
§ 1.45Y–1.’’
II. Rules Specific to Section 45Y
Proposed § 1.45Y–1 provided an
overview of proposed §§ 1.45Y–1
through 1.45Y–5 and definitions of
terms for purposes of proposed
§§ 1.45Y–1 through 1.45Y–5, including
the terms ‘‘combined heat and power
system (CHP) property,’’ ‘‘metering
device,’’ ‘‘related person,’’ ‘‘unrelated
person,’’ and ‘‘qualified facility.’’
A. Metering Device
Proposed § 1.45Y–1(a)(5)(i) through
(iii) defined, for purposes of section
45Y(a)(1)(A)(ii)(II), the term ‘‘metering
device;’’ provided standards for
maintaining and operating a metering
device for purposes of section
45Y(a)(1)(A)(ii)(II) and proposed
§ 1.45Y–1(a)(5), including by providing
that a metering device should meet
certain standards and be properly
calibrated, and provided rules related to
monitoring and locating the metering
device. Proposed § 1.45Y–1(a)(5)(iv)
provided examples illustrating the rules
provided by proposed § 1.45Y–1(a)(5).
Commenters provided feedback on
the definition of ‘‘metering device.’’

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Two commenters noted that the
proposed regulations defined a
‘‘metering device’’ related to ‘‘energy
revenue metering,’’ and asserted that
metering devices typically measure
energy production, not revenue. The
commenters recommended revising the
term ‘‘energy revenue metering’’ to
‘‘energy production metering’’ in the
final regulations.
The Treasury Department and the IRS
have determined that, because energy
revenue metering encompasses energy
production measurement as part of its
function, the commenters’ concern is
addressed by the proposed regulations.
Therefore, these final regulations adopt
the definition of metering device as
proposed.
Another commenter requested that
the final regulations provide
clarifications regarding third-party
metering requirements. The commenter
requested that the Treasury Department
and the IRS clarify whether operation of
the metering device by a third party
could be fully remote, or if the meter
owner must be granted access to the
site. The commenter further requested
that the final regulations clarify whether
the meter can be located prior to energy
delivery to storage, or whether it must
be located at the point of
interconnection. Finally, the commenter
requested clarification regarding
whether the section 45Y credit amount
is determined at the point of sale or
where the electricity is metered.
Section 45Y(a)(1)(A) provides, in part,
that the amount of the credit is the
kilowatt hours of electricity produced
by the taxpayer at a qualified facility
and in the case of a qualified facility
which is equipped with a metering
device which is owned and operated by
an unrelated person, sold, consumed or
stored by the taxpayer during the
taxable year. Proposed § 1.45Y–
1(a)(5)(ii) required a metering device to
meet the requirements of the American
National Standards Institute C12.1–2022
standard, or subsequent revisions, be
revenue grade with a +/¥0.5%
accuracy, and be properly calibrated
and maintained in proper working order
according to the instructions of its
manufacturer. If a metering device
satisfies the requirements in § 1.45Y–
1(a)(5)(ii), the statutory language of
section 45Y(a)(1)(A) would not prevent
operation by a third party to be fully
remote. As to whether the metering
device can be located prior to energy
delivery to storage or whether it must be
located at the point of interconnection,
the location of the meter should not
matter provided the meter meets the
requirements in § 1.45Y–1(a)(5)(ii).
Accordingly, the final regulations adopt

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proposed § 1.45Y–1(a)(5) without
change, and do not impose a specific
location requirement for such metering
device based on the lack of such a
requirement in the statutory language.
B. Related and Unrelated Persons
Proposed § 1.45Y–1(a)(7) provided a
definition of the term ‘‘related person’’
and special rules for the treatment of
corporations that are members of a
consolidated group (as defined in
§ 1.1502–1(h)).
Proposed § 1.45Y–1(a)(11) provided a
definition of the term ‘‘unrelated
person;’’ rules for the sales of electricity
to individual consumers; and an
example illustrating the application of
these rules.
A commenter requested clarification
regarding the sale to an unrelated
person requirement. The commenter
pointed to Notice 2008–60, 2008–30
I.R.B. 178, which provides guidance on
the section 45 credit by clarifying that
the requirement of a sale to an unrelated
person will be treated as satisfied if the
producer of electricity sells electricity to
a related person for resale by the related
person to a person that is not related to
the producer. The commenter requested
that the Treasury Department and the
IRS likewise confirm that under section
45Y, a sale to a related person for the
purposes of resale to an unrelated
person will also be treated as a sale to
an unrelated person if there is no
metering device owned and operated by
a third party.
The Treasury Department and the IRS
disagree that the rule in Notice 2008–60
that is applicable to the section 45
credit, under which the sale of
electricity to a related party with a
subsequent sale to an unrelated party is
treated as a sale to an unrelated party,
should apply to the section 45Y credit.
Section 45 does not include a provision
similar to section 45Y(a)(1)(A)(ii), which
provides that either (I) a taxpayer must
sell the electricity to an unrelated party,
or (II) the taxpayer’s qualified facility
must be equipped with a metering
device owned and operated by an
unrelated person, and the electricity
must be sold, consumed or stored by the
taxpayer during the taxable year. The
inclusion of section 45Y(a)(1)(A)(ii)
demonstrates that Congress intended to
allow the section 45Y credit for related
party sales only if the taxpayer produces
electricity at a qualified facility that has
a metering device owned and operated
by an unrelated person. Congress did
not carve out an exception for related
party sales for purposes of resale to
unrelated persons and the final
regulations cannot create one. To allow
taxpayers to apply the concepts

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provided in Notice 2008–60 to the
section 45Y credit for sales to unrelated
parties would undermine the metering
obligation in section 45Y(a)(1)(A)(ii)(II).
Accordingly, the Treasury Department
and the IRS cannot adopt the
commenter’s recommendation and the
rule will be adopted as proposed.
C. Credit Phase Out
Proposed § 1.45Y–1(c) provided rules
for calculating the amount of the credit
under section 45Y(a) and the applicable
phase-out percentages; defined the term
‘‘applicable year’’ and provided rules for
determining the applicable year,
including rules regarding the use of
certain datasets in determining the
applicable year. The definition of
‘‘applicable year’’ also applies for
purposes of the section 48E credit
phase-out rules. In the preamble to the
proposed regulations, the Treasury
Department and the IRS requested
comments on which datasets are most
appropriate to determine the applicable
year and why.
Commenters generally agreed with the
Treasury Department and the IRS that
the Energy Information Administration’s
(EIA) Electric Power Annual and
Monthly Energy Review, the EPA
Inventory of U.S. Greenhouse Gas
Emissions and Sinks (GHGI), the EPA
Greenhouse Gas Reporting Program
(GHGRP), and the Emissions and
Generation Resource Integrated
Database (eGrid) are suitable datasets to
determine the applicable year and
recommended the final rules adopt one
or more of these dataset(s) as providing
the timeliest assessment of emissions to
minimize potential confusion. One
commenter suggested using a single
annually published government data
source, and recommended the EIA
Monthly Energy Review that delineates
electricity sector greenhouse gas (GHG)
emissions for 2022 and the following
years.
Review of the comments confirmed
that the EIA Electric Power Annual and
the EPA GHGI are well-established data
sources that are representative of the
annual GHG emissions from the
production of electricity in the United
States. Moreover, the requirement in
§ 1.45Y–1(c)(4) that both the EIA
Electric Power Annual and the EPA
GHGI must be assessed separately
increases certainty that emissions from
the power sector meet the required
levels.
Another commenter requested that
the Treasury Department and the IRS
consider whether a single year drop in
GHG emissions of less than the
applicable year threshold followed by
GHG emissions increases in subsequent

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years should trigger the phase-out of the
credits.
Section 45Y(d)(3) describes the term
‘‘applicable year’’ as the later of 2032, or
the calendar year in which the Secretary
determines that the annual GHG
emissions from the production of
electricity in the United States are equal
to or less than 25 percent of the annual
GHG emissions from the production of
electricity in the United States for
calendar year 2022. Section 45Y(d)(2)
provides that the section 45Y credit
phases out over a four-year period
subsequent to the applicable year. The
statutory language describes the
applicable year as a single year, and the
credit phase-out begins subsequent to
the applicable year. Based on the
statutory language, the phase-out period
is a continual period. Therefore, the
statutory language does not grant the
Treasury Department and the IRS
authority to reverse a determination that
GHG emissions were at a sufficient level
to meet the definition of the applicable
year. For this reason, the comment is
not adopted.
D. Qualified Facility
The proposed regulations adopted the
statutory definition of a ‘‘qualified
facility.’’ Section 45Y(b)(1)(A) provides,
in part, that a qualified facility is a
facility for which the GHG emissions
rate is not greater than zero. The GHG
emissions rate is further defined in
section 45Y(b)(2). Section 45Y(b)(1)(B)
provides that a facility is only treated as
a qualified facility during the 10-year
period beginning on the date the facility
was originally placed in service.
A commenter asked for clarification
regarding changes to a facility that
impact its GHG emissions rate from
electricity generation and whether such
changes impact a qualified facility’s
credit eligibility. The commenter
requested confirmation that a facility
that initially operates with greater than
zero GHG emissions but later operates
with not greater than zero GHG
emissions can still be considered a
qualified facility under section 45Y. The
commenter suggested clarifying that in
the case of such a facility, the 10-year
credit period begins when the facility
first becomes a ‘‘qualified facility’’
operating at commercial scale with not
greater than zero GHG emissions. The
commenter asserted that providing a
different interpretation would
disincentivize facilities that are built
with the capacity to produce power
with greater than zero GHG emissions
from undertaking such investment.
The Treasury Department and the IRS
note that section 45Y(b)(1)(B) treats a
facility as a qualified facility only

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during the 10-year period beginning on
the date the facility was originally
placed in service. Generally, a qualified
facility is considered placed in service
in the earlier of (i) the taxable year in
which, under the taxpayer’s deprecation
practice, the period for depreciation
with the respect to such property
begins; or (ii) the taxable year in which
the qualified facility is placed in a
condition or state of readiness and
availability to produce electricity,
whether in a trade or business or in the
production of income. Accordingly, a
facility that initially operates with
greater than zero GHG emissions may
later be treated as a qualified facility if
it meets the requirements under section
45Y(b) in a taxable year, but only during
the 10-year period beginning on the date
the facility was originally placed in
service. For example, taxpayer places in
service a facility in year 1 that has GHG
emission that are greater than zero. In
year 6, the facility has GHG emissions
that are not greater than zero and is a
qualified facility under section 45Y. If
the facility continues to have not greater
than zero GHG emissions, the facility
continues to be a qualified facility under
section 45Y and taxpayer may claim the
section 45Y credit until year 10 (years
6 through 10), provided the facility
continues to have not greater than zero
GHG emissions for each of the
remaining years. The Treasury
Department and the IRS cannot adopt
the commenter’s recommendation and
the rule will be adopted as proposed.
A commenter asserted that a facility
qualifying for a section 45Y credit
should not cease to be a qualified
facility if, for a limited time or in a
limited amount, it has a GHG emissions
rate above zero (for example, as a result
of a temporary change in fuel or
feedstock). The commenter referenced
Notice 2008–60, which it described as
allowing the use of minimal fossil fuels
for flame startup and stabilization in an
open-loop biomass facility that qualifies
under section 45. The commenter stated
that zero-carbon fuels are not always
available. The commenter emphasized
that the proposed regulations under
section 48E, in contrast to those under
section 45Y, provide flexibility for
purposes of recapture for those facilities
that produce 10 grams of CO2e per kWh.
As a result, the commenter requested
that the final regulations allow a facility
to claim the section 45Y credit for the
days or months of the year during which
the facility produces electricity with a
GHG emissions rate of zero. The
commenter asserted that flexibility is
needed for de minimis emissions or
periods during the tax year.

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Section 45Y(b)(1)(A) defines a
qualified facility as having a GHG
emissions rate from the production of
electricity of not greater than zero. The
statute does not provide a de minimis
exception and the final regulations
cannot create one. Accordingly, a
facility cannot qualify for the section
45Y credit in a taxable year during the
10-year credit period after such facility
is originally placed in service if such
facility has a GHG emissions rate from
the production of electricity of greater
than zero, even if for a limited time or
in a limited amount. However, the
Treasury Department and the IRS note
that a facility’s failure to qualify for the
section 45Y credit in one or more
taxable years does not prevent such
facility from qualifying for the section
45Y credit in any other taxable years
during the 10-year credit period after
such facility is originally placed in
service. The statute allows a facility a
10-year credit period from the date the
facility is originally placed in service,
and a facility can be considered a
qualified facility for any taxable year
during such 10-year credit period in
which it satisfies the requirements of
the section 45Y credit.
E. Combined Heat and Power (CHP)
Property
Proposed § 1.45Y–1(a)(2) defined
‘‘combined heat and power (CHP)
property.’’ Proposed § 1.45Y–1(d) set
forth the credit eligibility requirements
for CHP property; provided rules for
determining the energy efficiency
percentage of CHP property and for
calculating electricity produced by CHP
property; and defined the term ‘‘heat
rate’’ and provided rules for its
calculation.
Section 45Y(g)(2) generally provides
special rules for the calculation of the
credit with respect to CHP property.
Section 45Y(g)(2)(A)(i) states that ‘‘the
kilowatt hours of electricity produced
by a taxpayer at a qualified facility shall
include any production in the form of
useful thermal energy by any combined
heat and power system property within
such facility.’’ Section 45Y(g)(2)(A)(i)
requires the thermal energy output from
a CHP property to be included in
determining the energy that qualifies for
the credit in contrast to a non-CHP
facility, for which only the electricity
generation should be credited. For
example, if a CHP property produces 1
kWh of electricity output and 1 kWh of
thermal output, then the taxpayer that
owns the CHP property may compute a
credit based on production of 2 kWh of
electricity.
Section 45Y(g)(2)(B) provides that the
term ‘‘combined heat and power

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property’’ has the same meaning given
such term by section 48(c)(3) (without
regard to subparagraphs (A)(iv), (B), and
(D) thereof). Section 48(c)(3)(C)(i) and
proposed § 1.45Y–1(d)(2) define the
energy efficiency percentage for
purposes of a CHP property as a
fraction—(I) the numerator of which is
the total useful electrical, thermal, and
mechanical power produced by the
system at normal operating rates, and
expected to be consumed in its normal
application, and (II) the denominator of
which is the lower heating value of the
fuel sources for the system. Section
45Y(g)(2)(C)(ii) provides that the term
‘‘heat rate’’ means the amount of energy
used by the qualified facility to generate
1 kilowatt hour of electricity, expressed
as British thermal units per net kilowatt
hour generated. Proposed § 1.45Y–
1(d)(3)(ii) addressed how to determine
the ‘‘heat rate’’ for a qualified facility
that includes CHP property that uses
combustion. In the preamble to the
proposed regulations, the Treasury
Department and the IRS requested
comments regarding the application of
the energy efficiency percentage
requirements to CHP property for which
there is no combustion and whether the
statutory definition of ‘‘heat rate’’ for
this property should be further clarified
in the final regulations.
One commenter addressed the
application of the energy efficiency
percentage requirements to CHP
property involving nuclear power and
recommended the final regulations
adopt the EIA’s definition of ‘‘heat
content’’ as a substitute for the lower
heating value used to calculate the
energy efficiency of a CHP property. The
commenter emphasized that the lower
heating value usually applies to
combustion fuels, not fuels such as
uranium that are non-combustible, and
for non-combustion fuels the lower
heating value should be the same as the
heat content. Another commenter made
a similar request that the final
regulations permit the use of a nuclear
reactor’s maximum licensed thermal
output to serve as the functional
equivalent of the lower heating value of
fuel sources, in recognition that nuclear
fission does not involve combustion.
A separate commenter requested the
final regulations establish a
methodology for taxpayers to determine
the energy efficiency percentage for CHP
property using non-combustible fuel
sources for which there is no lower
heating value. With respect to the
definition of heat rate, the commenter
asserted that the methodology in
proposed § 1.45Y–1(d)(3)(ii)(B) to
calculate heat rate does not take into
account that there is no lower heating

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value for CHP property using noncombustible fuel sources. The
commenter further questioned the
accuracy of the formula for converting
from BTU to kWh to calculate electricity
produced by CHP property because the
formula relies upon a definition of heat
rate that does not account for CHP
property using non-combustion fuel
sources. The commenter recommended
providing a conversion formula in the
final regulations for CHP property using
non-combustion fuel sources.
The Treasury Department and the IRS
recognize there is a gap in the current
guidance regarding how to calculate the
energy efficiency percentage and heat
rate for fuels without lower heating
values as referenced in section
48(c)(3)(C)(i)(II) and the proposed
methodology in proposed § 1.45Y–
1(d)(3)(ii)(B). The lower heating value is
intended to provide a measure for the
energy released when a fuel is
combusted under certain conditions.
Fuels that are not combusted will not
have a lower heating value, but the
amount of energy such fuels could
release under certain conditions can
still be measured.
The Treasury Department and the IRS
agree with commenters that the final
regulations should permit the use of a
nuclear reactor’s thermal output to serve
as the functional equivalent of the lower
heating value of fuel sources, in
recognition that nuclear fission does not
involve combustion. The final
regulations are amended accordingly.
With respect to other technologies, the
Treasury Department and the IRS will
continue to consult with experts in
order to develop additional approaches
that are either generally applicable or
appropriate for other particular
technologies. The final regulations are
therefore also amended to reflect this
continuing consideration and to provide
flexibility to prescribe these additional
approaches in guidance published in
the Internal Revenue Bulletin. Section
1.45Y–1(d)(2) and (d)(3)(ii)(B) of the
final regulations are revised
accordingly.
In addition, for organizational
purposes, the definition under proposed
§ 1.45Y–1(a)(2) of a unit of a qualified
facility for purposes of CHP property,
has been moved within the definition of
a unit of a qualified facility under
§ 1.45Y–2(b)(2)(i).
F. 80/20 Rule
The 80/20 Rule is designed to broaden
the availability of investment and
production tax credits by providing a
new original placed in service date for
a qualified facility that includes some
components of property previously

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placed in service, rather than requiring
the qualified facility to be composed
entirely of new components of property.
In the context of section 45Y, the 80/20
Rule applies at the qualified facility
level to the components of property
within the unit of qualified facility.
Proposed § 1.45Y–4(d)(1) provided that
for purposes of section 45Y(b)(1)(B), a
facility may qualify as originally placed
in service even if it contains some used
components of property within the unit
of qualified facility, provided the fair
market value of the used components of
the unit of qualified facility is not more
than 20 percent of the total value of the
unit of qualified facility (that is, the cost
of the new components of property plus
the fair market value of the used
components of property within the unit
of qualified facility).
Although this section focuses on the
80/20 Rule in the section 45Y context,
section III.E. of this Summary of
Comments and Explanation of Revisions
describes some comments received on
both sections 45Y and 48E. This
includes discussion of the interaction
between the rule for addition of a new
unit or an addition of capacity
(Incremental Production Rule) and the
80/20 Rule. As described in that section,
the Treasury Department and the IRS
agree that the statutory provisions
allowing for new units and additions of
capacity provided in sections
45Y(b)(1)(C) and 48E(b)(3)(B)(i) are
separate and distinct from the 80/20
Rule. If a retrofitted facility satisfies the
80/20 Rule, the final regulations provide
that the facility will be treated as newly
placed in service even if the taxpayer
also satisfies the provisions regarding
new units and additions of capacity.
These final regulations provide an
additional example, in § 1.45Y–
4(c)(5)(v) that specifically addresses
decommissioned and restarted facilities.
In response to a comment, the Treasury
Department and the IRS removed the
reference to a decommissioned nuclear
facility in Example 3 in § 1.45Y–
4(c)(6)(iii) to avoid referring to
decommissioned and restarted nuclear
facilities in the additions of capacity
rule and the 80/20 Rule. Additionally,
§ 1.45Y–4(d)(1) is clarified to confirm
that a qualified facility that meets the
requirements of section 45Y(b)(1)(A)
may claim the full section 45Y credit
rather than the credit resulting from the
addition of a new unit or an addition of
capacity.
While commenters generally
supported the need for the 80/20 Rule
for the section 45Y credit, commenters
also asked for clarity regarding the
application of the 80/20 Rule. A
commenter requested clarification that a

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facility that previously qualified for a
credit under section 45 or 48 and is later
retrofitted may be eligible for a section
45Y or 48E credit if it satisfies the 80/
20 Rule. The Treasury Department and
the IRS agree that if a qualified facility
under section 45 or an energy property
under section 48 is later retrofitted in a
manner that satisfies the 80/20 Rule, it
will be considered a new qualified
facility and may be eligible for a section
45Y or 48E credit so long as the
qualified facility meets all requirements
of section 45Y or 48E.
Another commenter generally stated
that under Notice 2018–59, 2018–28
I.R.B. 196, the 80/20 Rule applies at the
property level and not the project or
system level. The commenter requested
that the 80/20 Rule similarly only apply
at the property level for the section 45Y
credit. In response to this comment, the
Treasury Department and the IRS
confirm that for purposes of the section
45Y credit, the 80/20 Rule does not
apply to a project or system but instead
to a qualified facility. Proposed § 1.45Y–
4(d)(1) set forth the 80/20 Rule for
purposes of the section 45Y credit and
applies the rule to a retrofitted qualified
facility. The 80/20 Rule applies at the
qualified facility level to the
components of property within the unit
of qualified facility. The final
regulations retain this application of the
80/20 Rule to the section 45Y credit.
Another commenter requested
clarification regarding how the 80/20
Rule is applied for purposes of section
45Y by comparing its application to
section 48E. The commenter pointed out
that proposed § 1.48E–4(c)(4) looked
only to functionally interdependent
components of property (and not
integral property) to determine what is
considered new components of the unit
of qualified facility, while proposed
§ 1.45Y–4(d) did not. This commenter
requested clarification regarding which
components are included in the
determination under the 80/20 Rule for
purposes of the section 45Y credit.
Similarly, another commenter
recommended that the final regulations
define a ‘‘unit of qualified facility’’ as
the specific components necessary for
the production of electricity and not the
integral property essential to the
completeness of that function. With
respect to dam-based hydropower
facilities, another commenter supported
proposed § 1.45Y–4(d) permitting
existing dam-based hydroelectric
facilities to qualify for the 80/20 Rule.
The commenter asked to confirm that
the 80/20 Rule is applied on a turbineby-turbine basis and not the whole
facility, because individual turbines
may be repowered separately. As noted

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earlier, the 80/20 Rule applies at the
qualified facility level to the
components of property within the unit
of qualified facility and therefore in the
context of a hydropower facility the 80/
20 Rule cannot be applied on a turbineby-turbine basis.
The Treasury Department and the IRS
decline to modify the proposed rule in
response to these requests for specific
applications to particular technologies.
Proposed § 1.45Y–2(b)(2)(i) provided
that for purposes of the section 45Y
credit, the unit of qualified facility
includes all functionally interdependent
components of property (as defined in
proposed § 1.45Y–2(b)(2)(ii)) owned by
the taxpayer that are operated together
and that can operate apart from other
property to produce electricity.
Proposed §§ 1.45Y–4(d)(2) and 1.48E–
4(c)(3) both provided that the cost of
new components of the unit of qualified
facility includes all costs properly
included in the depreciable basis of the
new components of property of the unit
of qualified facility. Under both
proposed §§ 1.45Y–2(b)(2) and 1.48E–
2(b)(2), a unit of qualified facility only
includes functionally interdependent
components of property and not integral
property. Thus, the Treasury
Department and the IRS agree with the
commenter that only functionally
interdependent property is taken into
account to determine whether a
retrofitted qualified facility satisfies the
80/20 Rule for purposes of sections 45Y
and 48E. Proposed § 1.48E–4(c)(4)
provided a rule allowing costs for
integral property to be included in
determining the section 48E credit after
it has been determined that the qualified
facility has satisfied the 80/20 Rule.
Because the section 45Y credit is a
production tax credit calculated based
on electricity produced and not the
amount of investment in the qualified
facility, there is no need for a rule
similar to proposed § 1.48E–4(c)(4) in
the final regulations under section 45Y.

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III. Rules Specific to Section 48E
Proposed § 1.48E–1(b)(1) provided
rules for determining the amount of the
credit; defined the term ‘‘applicable
percentage;’’ and explained how to
determine the applicable percentage for
a qualified facility. Proposed § 1.48E–
1(c) provided the credit phase-out rules
and proposed § 1.48E–1(c)(3) defined
applicable year for purposes of the
credit phase-out rules by reference to
proposed § 1.45Y–1(c)(3). See section
II.C. of this Summary of Comments and
Explanation of Revisions for a
discussion of those rules.

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A. Organization of Proposed § 1.48E–2
Proposed § 1.48E–2(a) defined a
qualified facility for purposes of section
48E. Proposed § 1.48E–2(b) described
the property included in a qualified
facility for purposes of section 48E,
defined the terms ‘‘unit of qualified
facility’’ as well as ‘‘functionally
interdependent’’ and ‘‘integral part’’
(both as they apply to a qualified
facility), and provided several examples
to illustrate the rules. Proposed § 1.48E–
2(c) provided rules for the coordination
of the section 48E credit with certain
other Federal income tax credits with
respect to qualified facilities. Proposed
§ 1.48E–2(d) provided rules for
determining the qualified investment
with respect to a qualified facility.
Proposed § 1.48E–2(e) defined the term
‘‘qualified property.’’ Proposed § 1.48E–
2(f) defined certain terms related to
requirements for qualified property,
including ‘‘tangible personal property,’’
‘‘other tangible property,’’
‘‘construction, reconstruction, or
erection of qualified property,’’
‘‘acquisition of qualified property,’’
‘‘original use of qualified property,’’
‘‘depreciation allowable,’’ ‘‘placed in
service’’ and ‘‘claim.’’ Proposed § 1.48E–
2(g) provided rules for energy storage
technology (EST).
The Treasury Department and the IRS
determined that the organization of
proposed § 1.48E–2, as it related to
qualified facilities, did not adhere to the
organization of section 48E. The final
regulations reorganize § 1.48E–2 to more
clearly follow the organization of
section 48E. The Treasury Department
and the IRS do not intend for the
reorganization of § 1.48E–2 to create any
substantive differences from the rules as
they were provided in the proposed
regulations.
As reorganized, § 1.48E–2(a) of these
final regulations provides the rules for
determining the qualified investment
with respect to a qualified facility.
Section 1.48E–2(b) defines the term
‘‘qualified facility’’ as it relates to
section 48E, as well as the term ‘‘placed
in service.’’ Section 1.48E–2(c) defines
the term ‘‘qualified property.’’ Section
1.48E–2(d) provides the rules for
property included in a qualified facility,
including a description of ‘‘unit of
qualified facility’’ and ‘‘integral part,’’
and provides examples illustrating these
rules. Section 1.48E–2(e) provides
definitions related to the requirements
for qualified property. Section 1.48E–
2(f) provides rules for the coordination
of the section 48E credit with certain
other Federal income tax credits with
respect to qualified facilities and
includes examples to illustrate those

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rules. Section 1.48E–2(g) provides rules
relating to EST. Finally, the definition of
the term ‘‘claim’’ for both a qualified
facility and EST is moved to § 1.48E–
1(a)(2) and is modified to also apply to
the other Federal income tax credits
described in section 48E(b)(3)(C).
B. Qualified Investment With Respect to
a Qualified Facility and Qualified
Property
Proposed § 1.48E–2(d) described a
qualified investment with respect to any
qualified facility. Proposed § 1.48E–2(e)
defined ‘‘qualified property’’ for
purposes of proposed § 1.48E–2(a).
A commenter requested that the final
regulations clarify that the qualified
property included in a qualified
investment in a qualified hydropower
facility includes all the components and
property identified as qualified property
in prior guidance under section 48, up
through and including the substation at
which the electrical voltage is stepped
up to transmission voltage. Similarly,
another commenter asked whether the
scope of qualified property under
section 48E(b)(2) includes all property
identified as energy property under
section 48(a)(3), unless explicitly
excluded under section 48E.
The Treasury Department and the IRS
recognize that some technologies may
be creditable under both sections 48 and
48E. Although the rules for eligibility
differ between the two sections, they
share many overlapping concepts (for
example, functional interdependence
and integral property). For those
facilities that generate electricity and for
EST that are eligible for both the section
48 and 48E credits, the Treasury
Department and the IRS expect similar
property to be eligible. However, the
application of these concepts to a
specific facility or EST is ultimately a
fact-specific determination.
That said, unlike section 48, these
final regulations are technology neutral,
and the rules are meant to apply to all
qualified facilities. A definitive
response to these comments would
require the Treasury Department and
the IRS to conduct a complete factual
analysis of the property in question,
which may include information beyond
that which was provided by the
commenters. Because more information
is needed to make the determinations
requested by the commenters, the
requested clarifications are not
addressed in these final regulations.
C. Energy Storage Technology Overview
1. In General
Proposed § 1.48E–2(g) provided rules
defining a unit of EST. Section 48E(c)(2)

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defines the term ‘‘energy storage
technology’’ by reference to section
48(c)(6) (noting that the beginning of
construction requirement in section
48(c)(6)(D) does not apply). A
commenter suggested clarifying that
EST may include either ‘‘property . . .
which receives, stores, and delivers
energy for conversion,’’ or ‘‘thermal
energy storage property,’’ by reading the
‘‘and’’ between sections 48(c)(6)(A)(i)
and (ii) as disjunctive. The Treasury
Department and the IRS confirm that the
term ‘‘and’’ between sections
48(c)(6)(A)(i) and (ii) is disjunctive for
purposes of section 48E(c)(2) and
property described in section
48(c)(6)(A)(i) or (ii) are included as EST.
2. Functionally Interdependent
Proposed § 1.48E–2(g)(2)(i) provided
that, for purposes of the section 48E
credit, a unit of EST includes all
functionally interdependent
components of property (as defined in
proposed § 1.48E–2(g)(2)(ii)) owned by
the taxpayer that are operated together
and that can operate apart from other
property to perform the intended
function of the EST. Proposed § 1.48E–
2(g)(2)(ii) provided that components are
functionally interdependent if the
placing in service of each of the
components is dependent upon the
placing in service of each of the other
components to perform the intended
function of the EST.
A commenter requested that the
Treasury Department and the IRS
explicitly clarify that the section 48E
credit can be claimed with respect to
EST that is co-located and used in
conjunction with electricity generation
equipment for which the section 45 or
45Y credits are claimed, without regard
to whether the EST would be
considered a functionally
interdependent component or an
integral part of the electricity generation
equipment under other rules or whether
the EST and electricity generation
equipment are owned by the same or
different taxpayers.
Section 48E(a) provides that the clean
electricity investment credit is
determined separately with respect to
any qualified facility and any EST. This
statutory text establishes an important
categorical distinction between
qualified facilities and ESTs. While
integral property may be shared by a colocated qualified facility and an EST, a
unit of qualified facility and a unit of
EST cannot share components for
purposes of section 48E. Further, the
Treasury Department and the IRS
confirm that an EST is eligible for the
section 48E credit if it satisfies the
requirements of section 48E, even if the

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EST is co-located with a qualified
facility that has claimed the section 45
or 45Y credits. See section III.C.6. of this
Summary of Comments and Explanation
of Revisions for additional discussion of
comments on co-located, or ‘‘hybrid,’’
projects that include an EST and
qualified facility.
3. Qualified Investment With Respect to
Energy Storage Technology
Proposed § 1.48E–2(g)(4) provided
that the qualified investment with
respect to any EST for a taxable year is
the basis of any EST placed in service
by the taxpayer during such taxable
year. Commenters requested
clarification that the entire cost basis of
EST property that converts energy to
electricity is eligible for the section 48E
credit, even if some functionally
interdependent property is used to
produce heat. The commenters asserted
that there is no statutory requirement
that the energy stored be exclusively
converted to electricity and that the
Code is silent about any minimum
percentage requirement of energy being
converted to electricity.
Proposed § 1.48E–2(g)(6)(i) described
electrical energy storage property as
property (other than property primarily
used in the transportation of goods or
individuals and not for the production
of electricity) that receives, stores, and
delivers energy for conversion to
electricity and has a nameplate capacity
of not less than 5 kWh. This definition
is adopted from section 48E(c)(2), which
defines ‘‘energy storage technology’’
including electrical energy storage
property by reference to section 48(c)(6).
Because the purpose of an electrical
energy storage property is to receive,
store and deliver energy for conversion
to electricity, not to produce thermal
energy, components of property of an
energy storage property used to produce
thermal energy would be subject to the
incremental cost rule discussed in
section III.G. of this Summary of
Comments and Explanation of
Revisions.
4. Placed in Service
Proposed § 1.48E–2(g)(5)(i) provided
rules for determining when an EST has
been placed in service for purposes of
the section 48E credit. Notwithstanding
the general rules provided in proposed
§ 1.48E–2(g)(5)(i), an EST with respect
to which an election is made under
section 50(d)(5) of the Code and § 1.48–
4 to treat the lessee as having purchased
such EST is considered placed in
service by the lessor in the taxable year
in which possession is transferred to
such lessee.

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Commenters suggested expanding the
definition of placed in service for EST
because ‘‘energy storage may charge and
discharge prior to being ready for
commercial operation.’’ Specifically, a
commenter suggested that EST property
should be treated as placed in service
when (i) such property has all licenses,
permits, and approval required to store
and dispatch power, (ii) pre-operational
testing is complete, (iii) the taxpayer has
title to the property, and (iv) the
property is available to store and
discharge power on a regular,
commercial basis.
Instead of providing specific indicia
of when an EST is treated as being
placed in service, the rule in proposed
§ 1.48E–2(g)(5)(ii) provided general
principles for a taxpayer to determine
when an EST has been placed in service
that are broadly applicable to all types
of EST. These principles are based upon
the placed in service rules provided by
§ 1.48–9(b)(5), which generally adopt
the placed in service rules of § 1.46–
3(d)(1). The general principles under
§ 1.46–3(d)(1) have applied to the
section 48 credit since its enactment.
These principles are well-understood,
general standards for determining when
property is placed in service, and they
are widely relied upon by industry. The
Treasury Department and the IRS view
the general principles provided by the
proposed rule as adequate for
determining when EST is placed in
service, and as sufficiently broad to
address these commenters’ concerns.
Therefore, the final regulations adopt
the placed in service rules as proposed.
5. Electrical Energy Storage Property
Proposed § 1.48E–2(g)(6)(i) described
electrical energy storage property as
property (other than property primarily
used in the transportation of goods or
individuals and not for the production
of electricity) that receives, stores, and
delivers energy for conversion to
electricity and has a nameplate capacity
of not less than 5 kWh. For example,
subject to the exclusion for property
primarily used in the transportation of
goods or individuals, electrical energy
storage property includes but is not
limited to rechargeable electrochemical
batteries of all types (such as lithiumion, vanadium redox flow, sodium
sulfur, and lead-acid); ultracapacitors;
physical storage such as pumped storage
hydropower, compressed air storage,
and flywheels; as well as reversible fuel
cells.
Commenters asked for clarification
regarding what constitutes property
‘‘primarily used’’ in the transportation
of goods or individuals. One commenter
suggested that the final regulations

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Federal Register / Vol. 90, No. 9 / Wednesday, January 15, 2025 / Rules and Regulations
provide a bright line rule and clarify
that property that receives, stores, and
delivers energy for conversion to
electricity and is intended to be used for
less than 35 percent of its hours of use
in a calendar year for transporting goods
or individuals is not considered
‘‘primarily used in the transportation of
goods or individuals.’’ In this
commenter’s view, property, including a
school bus, that receives, stores, and
delivers energy for conversion to
electricity that is used less than 35
percent of its hours of use in a calendar
year for transporting goods or
individuals is not primarily used for
transportation. However, the commenter
clarified that if electric school buses
paired with a bidirectional vehicle-togrid (V2G) charger are permitted to
qualify as EST, then the charger itself
should not be considered part of the
electrical energy storage property.
The final regulations mirror the
language of section 48E(c)(2), which
adopts the definition of EST provided in
section 48(c)(6)(A), and excludes
property primarily used in the
transportation of individuals or goods.
The Treasury Department and the IRS
consider school buses as primarily used
in transportation because the primary
reason for a taxpayer to acquire school
buses is to transport individuals, not
store energy, notwithstanding the
overall amount of time buses are used
to actually transport individuals. A
‘‘bright line’’ test requested by the
commenter is not feasible because any
given situation and determination is fact
dependent.
In addition, there are other IRA tax
incentives intended to benefit some
technologies for which these
commenters seek section 48E credit
eligibility. For instance, section 45W of
the Code provides a tax credit for
vehicles such as electric school buses.
Furthermore, a notice of proposed
rulemaking (REG–118269–23) published
in the Federal Register (89 FR 76759) on
September 19, 2024, regarding the
section 30C alternative fuel vehicle
refueling property credit (September
2024 proposed regulations) proposed a
definition for property primarily used in
the transportation of goods or
individuals and not for the production
of electricity for purposes of sections 48
and 48E. In particular, proposed
§ 1.48E–2 provided that energy storage
property is primarily used in the
transportation of goods or individuals
and not for the production of electricity,
and therefore is not EST eligible for the
section 48E credit, if a credit is claimed
under section 30C for such property.
Comments regarding this proposed
definition will be further addressed in

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the Treasury decision that finalizes the
September 2024 proposed regulations.
The Treasury Department and IRS note
that energy storage property for which
the section 30C credit is not claimed
may be creditable as EST under sections
48 and 48E if that property meets the
requirements of those tax credits.
6. Hybrid Systems (Qualified Facility +
EST)
Several commenters addressed the
treatment of qualified facilities, such as
solar generation facilities, and EST that
are co-located, or so-called ‘‘hybrid’’
projects. At least one commenter
supported treating a qualified facility
and EST as separate for purposes of the
section 48E credit. The commenter
emphasized that such an approach is
critical for the long-term success of the
section 45Y and 48E credits, and
importantly, will align with the goal of
the domestic content bonus credit
amount to reshore clean energy supply
chains.
Other commenters requested that
taxpayers be able to elect a single
section 48E credit for hybrid systems,
consisting of a qualified facility and an
EST, and sought clarification of whether
property included in a unit of EST may
be included in a unit of qualified
facility. A commenter noted that for
purposes of rooftop solar and storage
hybrid systems, the EST and the solar
energy property are dependent upon
each being placed in service because
both are essential to the completeness of
the intended function of the hybrid
system. Commenters asserted that
including EST in the definition of
‘‘integral part’’ of a qualified facility and
providing examples of dual eligibility
for section 48 and 48E credits during the
transition period would help maintain
consistency and reduce administrative
burdens. One commenter recommended
modifying proposed § 1.48E–2(b) to
clarify that EST may (but is not required
to) be considered an integral part of a
qualified facility. Commenters stated
that such a clarification would align
with current guidance for the domestic
content bonus credit amount and the
test for determining whether multiple
energy properties will be considered an
energy project under the section 48
proposed regulations. Another
commenter stated that this approach
would allow for increased technological
flexibility for purposes of the section
48E credit and would allow residential
solar energy developers to continue
claiming a single credit for hybrid
systems. A commenter claimed that
adding EST as an integral part of a
qualified facility would allow utility
scale solar energy developers the option

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to claim separate credits for the EST and
the qualified facility under the section
48E proposed regulations.
Another commenter suggested
permitting a taxpayer developing a
hybrid system and claiming the section
48E credit on both the qualified facility
and EST to elect to treat them as a single
energy project. Other commenters
requested that the final regulations
clarify that even if qualified facilities
and EST are separate categories under
section 48E, a taxpayer developing a
hybrid system that incorporates both
may file a single Form 3468, Investment
Credit, and register only once for
purposes of section 6418 of the Code
relating to transfer elections for eligible
credits (section 6418 credit transfer
elections).
As noted earlier in section III.C.2. of
this Summary of Comments and
Explanation of Revisions, the statutory
framework of section 48E does not
support treating a qualified facility and
EST as a single creditable property.
Instead, the text of section 48E
repeatedly treats a qualified facility and
EST as separately creditable properties.
Accordingly, there is no statutory basis
to allow taxpayers an option to claim a
single credit for hybrid systems that
include both qualified facilities and
EST. In addition, although beyond the
scope of these final regulations, the
Treasury Department and the IRS note
that, because a hybrid system would be
considered two separate eligible credit
properties, a taxpayer would need to
register them separately for purposes of
making section 6418 credit transfer
elections. See §§ 1.6418–1(d) and
1.6418–4.
Some commenters also requested that
the final regulations provide an option
to claim a single credit for a hybrid
system rather than two credits, one for
the EST and one for the qualified
facility, in part, because those
commenters currently enter into a single
leasing agreement with customers for
both a solar qualified facility and an
EST. These commenters expressed
concern about whether, under the
proposed regulations, they would need
to enter into separate contracts for the
solar qualified facility and the EST.
These commenters noted that if they are
able to use a single contract, the contract
will need to have separate term lengths
for the solar qualified facility and the
EST to satisfy the leasing rules for tax
purposes. These commenters raised the
issue that since a solar qualified facility
and an EST generally have different
useful lives the leasing rules could not
cover both the solar qualified facility
and the EST if they claimed separate
credits.

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The Treasury Department and the IRS
are not aware of any case law or
guidance related to leasing rules that
would require a taxpayer to break up the
scope of a lease into components before
analyzing whether there is a true lease
for tax purposes regardless of the useful
life of different assets included in the
lease. In order to claim section 48E
credits for both the solar qualified
facility and an EST that are part of a
combined solar qualified facility and
EST, a taxpayer must retain ownership
of both at the time such property is
placed in service. This is true regardless
of whether there are separate credits or
separate credit calculations required for
a solar qualified facility and an EST.
While the final regulations define a unit
of property as a qualified facility or an
EST for purposes of section 48E, the
final regulations are not intended to
apply more broadly to define what
comprises a unit of property for any
other purpose of the Code.
Another commenter requested that
the section 48E credit be made available
for pumped storage hydropower
property, including if such property
overlaps or shares property with a
qualified hydropower facility that has
claimed or will claim the credit under
section 45 or 45Y, and that no allocation
of costs is required with respect to such
overlapping property.
The Treasury Department and the IRS
confirm that an EST is eligible for a
separate section 48E credit if it satisfies
the requirements of section 48E and the
section 48E regulations. A taxpayer that
makes a qualified investment with
respect to a qualified facility or an EST
is eligible for the section 48E credit only
to the extent of the taxpayer’s eligible
investment in the qualified facility or
EST. As described in proposed § 1.48E–
2(b)(3)(vi), multiple qualified facilities
(whether owned by one or more
taxpayers), including qualified facilities
with respect to which a taxpayer has
claimed a credit under section 48E, 45,
or 45Y or another Federal income tax
credit, may include shared property that
may be considered part of a qualified
investment for each qualified facility so
long as the cost basis for the shared
property is properly allocated to each
qualified facility and the taxpayer only
claims a section 48E credit with respect
to the portion of the cost basis properly
allocable to the qualified facility for
which the taxpayer is claiming a section
48E credit. The proposed rule addresses
the commenter’s concerns and will be
adopted as proposed.
7. Thermal Energy Storage Property
Proposed § 1.48E–2(g)(6)(ii) defined
thermal energy storage property as

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property comprising a system that is
directly connected to a heating,
ventilation, or air conditioning (HVAC)
system; removes heat from, or adds heat
to, a storage medium for subsequent use;
and provides energy for the heating or
cooling of the interior of a residential or
commercial building. Thermal energy
storage property includes equipment
and materials, and parts related to the
functioning of such equipment, to store
thermal energy for later use to heat or
cool, or to provide hot water for use in
heating a residential or commercial
building. Thermal energy storage
property does not include a swimming
pool, CHP property, or a building or its
structural components.
Several commenters requested
additional examples of thermal energy
storage property and asked whether
specific property would be considered
part of thermal energy storage. For
example, a commenter recommended
including an example of thermal energy
storage property that includes phase
change materials operating as a battery
in place of a refrigeration cycle to
reduce energy consumption in cold
storage. Several commenters requested
an example allowing for solar thermal
systems to be treated as thermal energy
storage property and noted that solar
thermal systems are explicitly eligible
under the section 48 credit. A
commenter specifically contended that
solar thermal systems that collect energy
from the sun to heat a storage medium
(for example, water) and then provide
energy through an HVAC system for a
residential or commercial building
should be treated as thermal energy
storage systems under section 48E.
Another commenter suggested
clarifying that energy storage technology
includes property capable of
discharging both heat and electricity
regardless of how the facility’s heat is
utilized as long as the facility has an
electrical nameplate capacity of at least
5 kWh and the taxpayer claims a section
48E credit only on the parts of the
facility that are essential to receiving,
storing, and delivering energy for the
conversion to electricity (that is,
excluding components related to
discharging heat). A different
commenter suggested clarifying that
thermal energy storage property
includes property directly connected to
a refrigeration system given that
refrigeration systems are a subset of
HVAC systems. Another commenter
requested clarifying that otherwisequalifying property that operates
squarely within an HVAC ecosystem, or
directly in connection with such a
system, and that directly impacts the
temperature of air being conditioned by

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an HVAC system, is ‘‘directly
connected’’ to such system within the
meaning of section 48E (and section 48);
and non-structural, energy-saving,
portable products that are incorporated
into building elements specifically
because of their energy-saving
properties are not themselves ‘‘a
building or its structural components,’’
and remain non-structural even if
integrated into a ceiling.
Another commenter suggested
providing examples of thermal energy
storage property that include thermal
ice or chilled water storage systems that
use electricity to run a refrigeration
cycle to produce ice or chilled water
that is later connected to the HVAC
system as an exchange medium for air
conditioning the building, heat pump
systems that store thermal energy in an
underground tank or borehole field to be
extracted for later use for heating and/
or cooling, and electric furnaces that use
electricity to heat bricks to high
temperatures and later use this stored
energy to heat a building through the
HVAC system. Similarly, a commenter
recommended several modifications to
the examples of thermal energy storage
in proposed § 1.48E–2(g)(6)(ii): (i)
replace the reference to ‘‘thermal ice
storage systems’’ with ‘‘chilled water or
ice storage systems,’’ (ii) acknowledge
that tanks could be above or below
ground, and (iii) include ‘‘electric
boilers that use electricity to heat water
and later use this stored energy to
provide heat and/or domestic hot water
to a building through the HVAC
system.’’ Several other commenters
suggested clarifying whether the phrase
‘‘directly connect to’’ in proposed
§ 1.48E–2(g)(6)(ii) means that thermal
storage systems that function as selfcontained heating or cooling systems
qualify as thermal energy storage
property.
The Treasury Department and the IRS
agree that the definition of thermal
energy storage property requires
clarification. Proposed § 1.48E–
2(g)(6)(ii) defined thermal energy
storage property, in part, as a system
which ‘‘removes heat from, or adds heat
to, a storage medium for subsequent
use.’’ The Treasury Department and the
IRS understand the phrase ‘‘adds heat
to’’ as including equipment that is
involved in adding, or transferring,
already-existing heat from one medium
to the storage medium, but not
equipment involved in transforming
other forms of energy into heat in the
first instance. Equipment that just adds
(or removes) heat includes technologies,
like heat pumps, that draw heat from
the ambient air or other stores of heat
and adds that heat to a storage medium.

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By contrast, equipment that transforms
other forms of energy into heat in the
first instance, for example through
combustion or electric resistance, is not
property that ‘‘removes heat from, or
adds heat to’’ a storage medium and is
therefore not an eligible component of a
thermal energy storage property. For
example, a conventional gas boiler with
an integrated storage tank would not
generally be thermal energy storage
property, as it would generate new heat
in the first instance through combustion
and subsequently add that heat to the
storage medium, rather than merely
adding existing heat to the storage
medium. While the gas boiler elements
would not be part of such property, the
integrated storage tank, may be thermal
energy storage property if it otherwise
meets the thermal energy storage
property definition. Further, an air-towater heat pump with a thermal storage
tank, for example, would generally be
thermal energy storage property
provided it otherwise meets the
definition of thermal energy storage.
This could be the case even if the heat
pump also serves a purpose in the
connected HVAC system’s real-time
heating or cooling of a building. In that
case, the thermal storage tank would be
thermal energy storage property and the
heat pump may also qualify as part of
the thermal energy storage property to
the extent the taxpayer’s costs exceed
the cost of an HVAC system without
thermal storage capacity that would
meet the same functional heating or
cooling needs as the heat pump system
with a storage medium, other than time
shifting of heating or cooling. See
section III.G. of the Summary of
Comments and Explanation of Revisions
for discussion of the Incremental Cost
Rule.
Proposed § 1.48E–2(g)(6)(ii) included
an example of electric furnaces that use
electricity to heat bricks to high
temperatures and later use this stored
energy to heat a building through the
HVAC system. The Treasury
Department and the IRS acknowledge
that this example needs to be refined to
more precisely delineate the scope of
eligible thermal energy storage property.
Whereas the heated bricks and
equipment that adds heat generated by
the furnace to those bricks, or removes
heat from the bricks, is eligible thermal
energy storage property, the electric
furnace equipment that transforms
energy into the thermal energy via
electrical resistance in the first instance
is not. Section 1.48E–2(g)(6)(ii) of the
final regulations provides that thermal
energy storage property does not
include property that transforms other

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forms of energy into heat in the first
instance.
With respect to subsequent use, the
Treasury Department and the IRS also
agree that additional clarity is
warranted. The statute requires that
thermal energy storage property must be
able to perform certain functions, not
simply perform heat transfer. Any heat
transfer may take some amount of time
and heat does not immediately dissipate
even if no effort is made to store it.
While some commenters asserted that
such heat transfer is subsequent use, the
Treasury Department and the IRS
disagree. A plain reading of the statute
supports the conclusion that thermal
energy storage property does not
include property that simply engages in
heat transfer. The thermal energy
storage property must be able to store
the thermal energy. The Treasury
Department and the IRS find that a
minimum time interval for subsequent
use provides certainty for taxpayers and
sound tax administration.
Accordingly, the final regulations
clarify that property that ‘‘removes heat
from, or adds heat to, a storage medium
for subsequent use’’ is property that is
designed with the particular purpose of
substantially altering the time profile of
when heat added to or removed from
the thermal storage medium can be used
to heat or cool the interior of a
residential or commercial building. The
final regulations also provide a safe
harbor for thermal energy storage
property. If the thermal energy storage
property can store energy that is
sufficient to provide heating or cooling
of the interior of a residential or
commercial building for a minimum of
one hour, it is deemed to have the
purpose of substantially altering the
time profile of when heat added to or
removed from the thermal storage
medium can be used to heat or cool the
interior of a residential or commercial
building.
These final regulations also add that
thermal energy storage property may
store thermal energy in an artificial pit,
an aqueous solution, or a solid-liquid
phase change material, in addition to
the underground tank or a borehole field
already included in the proposed
regulations, in order to be extracted for
later use for heating and/or cooling. The
final regulations clarify that sources of
thermal energy that transform other
forms of energy into heat, such as
electric boilers, are not thermal energy
storage property.
The Treasury Department and the IRS
clarified the definition of thermal
energy storage property and the
examples in the final regulations to
illustrate what constitutes thermal

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energy storage property. The final
regulations provide revised examples of
thermal energy storage property, and
those examples are intended to be a
non-exhaustive list. The Treasury
Department and the IRS have also
determined that the revised description
of thermal energy storage property in
§ 1.48E–2(e)(6)(ii) provides taxpayers
with a sufficient means to determine
whether specific property qualifies as
thermal energy storage property. To the
extent that commenters asked whether
additional systems, configurations, or
technologies would qualify as thermal
energy storage property, such a
determination would require the
Treasury Department and the IRS to
conduct a complete factual analysis of
the system, configuration, or
technology, which may include
information beyond that which was
provided by the commenters. Because
more information is needed to make any
such determinations requested by the
commenters, the final regulations do not
provide such additional requested
clarifications.
Several commenters recommended
clarifying that thermal energy storage
property includes property providing
energy for the heating or cooling of the
interior of an industrial building, or
other types of buildings. A commenter
asserted that a wide variety of buildings
are served by thermal energy storage,
such as city halls, libraries, and jails,
and that the definition of thermal energy
storage property should not be limited
to residential or commercial settings.
Commenters requested that property
used to convey stored energy and
deliver it to building spaces (such as
pipes and pumps), used to distribute
stored thermal energy for heating or
cooling or to supply domestic hot water
for consumption in a residential or
commercial building, be included
within the definition of thermal energy
storage property. One commenter
recommended defining thermal energy
storage property to include equipment,
including pipes and pumps, used to
distribute stored thermal energy to and
within buildings. The commenter noted
that such a clarification would
necessitate incorporation of a dual use
rule consistent with § 1.48–14(b),
because thermal energy storage may use
pipes to distribute stored thermal energy
to and within buildings that are also
used by non-qualifying sources.
One commenter requested clarifying
whether thermal energy storage property
includes liquid desiccant storage
systems that use electricity to store
energy in liquid desiccants that remove
latent heat from the air for use in a
connected HVAC system. Another

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commenter noted that most solar
thermal systems are combination or
hybrid systems that provide thermal
storage in the form of water or another
fluid for a variety of applications.
Regarding such combination systems,
other commenters recommended
clarifying that thermal energy property
includes water heating applications and
providing an example of such
applications.
Section 48E(c)(2) defines EST as
having the same meaning as under
section 48(c)(6), and section 48(c)(6)
defines EST to include thermal energy
storage property. The statutory
definition of thermal energy storage
property under section 48(c)(6)(C)
provides that such property is directly
connected to a HVAC, removes heat
from, or adds heat to, a storage medium
for subsequent use, and provides energy
for the heating or cooling of the interior
of a residential or commercial building.
To maintain consistency with the
statutory text, the final regulations
maintain the wording regarding eligible
building applications set forth in section
48(c)(6)(C)(i)(III). With respect to
property used to distribute stored
thermal energy, such as pipes and
pumps, the final regulations provide a
function-oriented method to evaluate
whether property is a functionally
interdependent or an integral part of
thermal energy storage property. Beyond
the examples included in the proposed
regulations and additional examples
added here, commenters have described
a number of additional innovative
technologies that might qualify as
thermal energy storage property.
However, application of the functional
definition of thermal energy storage
property provided at section 48E(c)(2)
(by reference to section 48(c)(6)) would
be necessary to determine if these
technologies are, in fact, examples of
qualifying thermal energy storage
property. Moreover, the examples
contained in proposed § 1.48E–
2(g)(6)(ii) are a non-exhaustive list.
Therefore, the final regulations do not
adopt all the recommended additional
examples.
Because section 48E(c)(2) provides
that the term ‘‘energy storage
technology’’ has the meaning given such
term in section 48(c)(6), the final
regulations incorporate modifications
made to the section 48 proposed
regulations by the section 48 final
regulations to clarify the definition of
EST, including with respect to thermal
energy property.
8. Hydrogen Energy Storage Property
Proposed § 1.48E–2(g)(6)(iii) provided
that hydrogen energy storage property is

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property (other than property primarily
used in the transportation of goods or
individuals and not for the production
of electricity) that stores hydrogen and
has a nameplate capacity of not less
than 5 kWh, equivalent to 0.127 kg of
hydrogen or 52.7 standard cubic feet
(scf) of hydrogen. Proposed § 1.48E–
2(g)(6)(iii) also provided that hydrogen
energy storage property must store
hydrogen that is solely used as energy
and not for other purposes, such as for
the production of end products (for
example, fertilizer), and set forth
examples of hydrogen energy storage
property.
A commenter stated that property
storing hydrogen should be at least 1
GWh in capacity (which is equivalent to
96,554 gallons of liquid hydrogen
storage capacity or about 25.4 metric
tons) in order to qualify as hydrogen
energy storage property. The Treasury
Department and the IRS note that
section 48E(c)(2) defines ‘‘energy storage
technology’’ as having the meaning
given such term in section 48(c)(6)
(without the application of the
beginning of construction deadline).
Section 48(c)(6) defines ‘‘energy storage
technology’’ as, in part, having a
nameplate capacity of not less than 5
kilowatt hours. Accordingly, the final
regulations do not adopt the
commenter’s suggestion, as doing so
would be inconsistent with the statute.
a. End Use Requirement
Numerous commenters disagreed
with the requirement that hydrogen
energy storage property must store
hydrogen that is solely used as energy
and not for other purposes, which the
commenters referred to as the ‘‘end use
requirement.’’ Commenters noted that
the end use requirement is not
statutorily prescribed and asserted that
it would be difficult, if not impossible,
to implement. Commenters asserted that
a single industrial customer may have
multiple uses for hydrogen, sometimes
for energy and sometimes for other
purposes such as stripping pollutants
from flue gas streams, and that
customers are not generally willing to
restrict their use in order to indemnify
the hydrogen energy storage property
against investment credit recapture risk.
Commenters also pointed out that
hydrogen storage projects may sell to
intermediaries in which case the end
use of hydrogen is not necessarily
known, and ensuring that the end use
requirement is respected by export
markets would be impossible. A
commenter contended that the limited
number of examples and use cases
offered in the proposed regulations raise

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several questions for taxpayers and
hydrogen storage developers.
Some commenters also maintained
that the end use requirement would be
inconsistent with the Biden
Administration’s U.S. National Clean
Hydrogen Roadmap. One of these
commenters stated that a major buildout of hydrogen storage facilities
targeting exclusively power sector end
use makes little sense from a strategic
perspective. A commenter asserted that
the definition of EST in section
48(c)(6)(A)(i), which includes
‘‘hydrogen, which stores energy,’’
simply recognizes that hydrogen is
inherently a form of energy itself. A
commenter also claimed that section
48(c) only sets out affirmative
requirements for EST and that,
therefore, hydrogen storage property
that is not primarily used in the
transportation of goods or individuals
should qualify for the section 48E credit
regardless of where the stored hydrogen
ends up. Commenters further noted that
some energy uses may be indirect (for
example, via intermediary molecules),
further complicating application of an
end use requirement.
Commenters also asserted that an end
use requirement would bifurcate and
adversely affect the hydrogen market,
and that additional uses for hydrogen,
such as feedstock for industrial
processes, could present significant
decarbonization opportunities. A
commenter asserted that disallowing the
section 48E credit for hydrogen storage
from serving applications such as steel
production and iron refining would be
a significant disservice to America and
delay or prevent massive reductions in
carbon emissions while hindering U.S.
manufacturing of essential construction
materials. Commenters noted that a
hydrogen end use requirement would
disadvantage large-scale hydrogen
storage facilities relative to smaller ones.
Commenters expressed concern that
hydrogen energy storage is being
unfairly singled out for disadvantageous
treatment as compared to other EST,
noting that the proposed regulations do
not place an end use restriction on
electricity stored within and discharged
from batteries or other storage
technologies; noting that energy
withdrawn from batteries may be used
for any purpose without losing its
eligibility status. Commenters
contended that the end use requirement
would unduly push potential customers
towards using battery-focused solutions
instead of letting batteries and hydrogen
solutions compete on equal footing, or
in cases in which no alternative exists,
would continue to extend the use of

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existing technologies, fuels, and
processes.
Some commenters supported the
principle of an energy-based end use
requirement for hydrogen energy storage
property. One commenter sought
clarification that ‘‘energy’’ was not
limited to electricity production.
Another commenter supported the
principle of an energy-based end use
limitation by comparing the statutory
text of section 48(c)(6) from three
legislative bills, including the version
ultimately enacted by Congress, but
opposed the ‘‘solely’’ criteria and cited
practical challenges including
administrability. Commenters generally
requested that if an end use requirement
is maintained that it be clarified and
altered, and safe harbors provided. For
example, a commenter suggested
providing a rebuttable presumption of
meeting the end use requirement if a
taxpayer can demonstrate that it stored
hydrogen predominantly for energy use.
Commenters also suggested creating a
safe harbor as long as the facility itself
uses some of the stored hydrogen for
energy or the facility is an open access
facility. A commenter requested flexible
rules for determining the end use of
hydrogen, including permitting
taxpayers to assign withdrawn hydrogen
based on commercial sales
arrangements, or, alternatively, being
able to rely on a mass balance approach
based on the inputs and outputs to the
storage property during the year.
Commenters also suggested that the end
use requirement conclude with the end
of the 5-year recapture period provided
by section 50. Several commenters
suggested inverting the end use
requirement to only disqualify property
used to store hydrogen that is solely
used for non-energy end products, or to
exempt common carrier infrastructure
from the end use requirement. Another
commenter recommended a rule under
which a facility that uses ‘‘qualified
clean hydrogen’’ as defined under
section 45V of the Code is deemed to
qualify under section 48E if such
hydrogen is used to create electricity.
Several commenters recommended
implementing a dual use safe harbor to
permit a taxpayer to claim a reduced
section 48E credit when a portion of
stored hydrogen is used for a purpose
other than energy. Commenters noted
that a dual use safe harbor could apply
if at least half of the hydrogen in
hydrogen energy storage property is
used for energy purposes. In contrast,
other commenters were opposed to any
dual use approach to the end use
limitation and asserted that such an
approach would be unworkable,

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requiring ‘‘unknowable, unprovable,
unmonitorable, unauditable facts.’’
Commenters asked for clarification
regarding what constitutes energy use of
stored hydrogen and what
documentation is needed to
demonstrate such energy use. Several
commenters were opposed to any
recordkeeping requirements related to
the end use of hydrogen and contended
that such requirements would be
unduly burdensome to taxpayers given
the fungibility of hydrogen. Another
commenter noted that there are
currently no recordkeeping or
documentation precedents available for
a taxpayer to efficiently demonstrate the
final end use of hydrogen stored in such
taxpayer’s hydrogen energy storage
property. The commenter asserted that,
as there is no available documentation
pathway for tracking hydrogen
molecules through to their end use, it
would be both impractical and
prohibitively costly for a taxpayer to
develop and implement such
recordkeeping practices.
After consideration of the comments
received, the Treasury Department and
the IRS agree that section 48(c)(6)(A)(i)
does not require that hydrogen energy
storage property store hydrogen that
will be used for the production of
energy. The Treasury Department and
the IRS recognize commenters’ concerns
regarding the administrative challenges
the end use requirement could present
for taxpayers and agree that it should be
removed. The final regulations therefore
do not adopt the requirement that
hydrogen energy storage property store
hydrogen that is solely used as energy
and not for other purposes such as for
the production of end products like
fertilizer.
b. Hydrogen Storage Media
Many commenters provided feedback
regarding the qualifying types of
hydrogen storage media. Specifically, a
commenter requested expanding the
definition of hydrogen energy storage to
include storage of ammonia and
electrolytic hydrogen derivative e-fuels.
A commenter also requested that the
Treasury Department and the IRS
recognize and clarify that, unlike
electricity, hydrogen is a chemical
building block for other molecules that
are capable of more efficiently carrying
hydrogen. According to the commenter,
this means that hydrogen can be stored
as a physical material medium such as
a metal hydride. The commenter also
requested confirmation that the
examples of hydrogen storage mediums
provided in the preamble to the
proposed regulations are non-exhaustive

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and that the type of storage medium is
intentionally unlimited.
The Treasury Department and the IRS
decline to adopt comments requesting
that the final regulations provide that
chemical storage (that is, equipment
used to store hydrogen carriers (such as
ammonia and methanol)) is hydrogen
energy storage property. Section
48E(c)(2) provides that the term ‘‘energy
storage technology’’ has the meaning
given to such term in section 48(c)(6).
Section 48(c)(6)(A)(i) defines ‘‘energy
storage technology’’ as property (other
than property primarily used in the
transportation of goods or individuals
and not for the production of electricity)
which receives, stores, and delivers
energy for conversion to electricity (or,
in the case of hydrogen, which stores
energy), and has a nameplate capacity of
not less than 5 kilowatt hours. Section
48(c)(6)(A) references hydrogen, but not
compounds containing hydrogen.
c. Hydrogen Storage Components and
Equipment
Several commenters requested
clarifications regarding the components
included in the definition of hydrogen
energy storage. Commenters generally
requested that the final regulations
expand the list of integral and
functionally interdependent equipment
to be more inclusive of existing and
future hydrogen energy storage property
technologies. One commenter noted that
while the functional interdependence
test provided by the proposed
regulations is helpful, specifying further
what components are considered part of
hydrogen energy storage is paramount.
The commenter requested additional
examples that address specific
components including equipment
needed to functionally store hydrogen,
equipment used to change the phase of
matter, equipment used to liquify
hydrogen prior to storage, equipment
used to convert stored hydrogen to
ammonia to be used as a carrier of that
stored hydrogen, equipment used to
store electrolytic hydrogen derivative efuels, and any related and necessary
pipelines. Similarly, commenters
requested that additional components
and equipment be specifically identified
as eligible parts of hydrogen energy
storage property, including hydrogen
liquefaction and related equipment and
other equipment required to operate
underground hydrogen storage property.
A commenter requested that the final
regulations demarcate between
equipment used for hydrogen
production, conditioning,
transportation, and storage. The
commenter emphasized that a clear
demarcation is necessary to prevent

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gaming the system if storage property
would qualify for the section 48E credit
under section 48(c)(6) and the
production equipment will, in many or
most cases, be associated with the
production tax credit under section 45V.
The commenter suggested that the
proper demarcation between hydrogen
production and conditioning,
transportation, or storage equipment is
the point at which any post-production
conditioning to remove impurities or to
put the hydrogen into a saleable form is
completed. The commenter stated that,
in distinguishing hydrogen production
equipment from storage equipment, the
associated conditioning equipment
should include all equipment necessary
to treat, process, compress, pump, or
perform other physical action on
hydrogen prior to its storage or delivery.
The commenter noted that equipment
used to convert hydrogen into ammonia,
methanol, or another hydrogen carrier
also should be associated with postproduction processing of hydrogen and
not eligible for the section 48E credit.
Similarly, the commenter asserted that
equipment, such as compressors, used
to liquify hydrogen (liquefaction) to put
it into a deliverable and salable form
should not qualify as hydrogen energy
storage property, including the
equipment necessary for liquefaction,
conversion to ammonia, methanol, or
other hydrogen carrier, and dissociation
or cracking equipment necessary to
convert a hydrogen carrier back into
hydrogen. The commenter emphasized
that if compressors are used in direct
connection with storage devices, rather
than to change the form of the hydrogen
(for example, from gas to liquid),
compressors are integral to the storage
equipment and should qualify for the
section 48E credit. Another commenter
stated that the definition of hydrogen
storage property should be limited to
tanks and caverns of scale, and the
associated equipment necessary to fill or
discharge hydrogen from those tanks or
caverns.
Commenters also requested further
guidance on the eligibility of pipelines
as hydrogen energy storage property
noting that there are specific cases in
which hydrogen pipelines that are
directly connected to an energy storage
facility can operate as hydrogen storage,
by providing additional volumes that
can adjust pressure in direct
coordination with the storage facility
compression system. One commenter
requested clarification of the term
‘‘primarily’’ in the phrase ‘‘other than
property primarily used in the
transportation of goods or individuals’’
as applied to pipelines that can be used

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to store hydrogen. Another commenter
suggested clarifying the scope of
hydrogen storage property with respect
to transportation, customer delivery,
and use.
One commenter that opposed the
inclusion of pipelines, rail cars, and
truck trailers in the definition of
hydrogen storage property, noted that if
hydrogen has been stored in qualified
storage property, such as tanks or
underground storage salt caverns, the
energy storage property should end at
the valve where the stored hydrogen is
delivered into a pipeline system.
Additional commenters recommended
limiting the treatment of hydrogen
pipelines as integral or interdependent
to hydrogen storage property.
Commenters pointed to Federal Energy
Regulatory Commission (FERC) rulings
and applicable case law, such as
Hawaiian Independent Refinery, Inc. v.
U.S., 697 F.2d 1063 (Fed. Cir. 1983),
which delineate the circumstances
under which pipeline systems would be
considered part of the storage facility.
One commenter recommended only
including pipelines directly linked to
storage facilities and further
recommended that the final regulations
more precisely define the boundary
between storage and transportation
infrastructure. This commenter’s
proposed guideline would define the
boundary between storage and
transportation infrastructure by only
considering specific interconnected
pipeline segments as part of the storage
system: point-to-point lines starting
from the storage facility and ending at
the first intersection point with explicit
compression equipment. Commenters
also requested a safe harbor for
interconnecting pipelines whereby the
pipelines would be deemed integral or
interdependent to a hydrogen storage
facility if (i) the complex is conceived
and designed concurrently, and all
offsite interconnecting pipeline
components are placed into service
within twenty four months of the date
on which the first such component is
placed into service, and (ii) the offsite
interconnecting components are within
100 miles of the storage facility or
within the same State as the storage
facility.
Commenters proposed the inclusion
of additional examples that would
provide additional specific eligible
components and provide capitalization
rules; establish eligibility of pipelines
connecting storage facilities if exclusive
to use of those facilities; and establish
eligibility of purification equipment
intended to return the purity of
hydrogen post-storage to its purity level
upon entering storage.

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A commenter suggested allowing
tanks and associated equipment for the
storage of ammonia when used as a
hydrogen carrier to qualify for the
section 48E credit but stated that
equipment used to disassociate
ammonia into hydrogen (referred to as
cracking) is a separate function from
hydrogen storage and should not be
treated as hydrogen energy storage
property.
The Treasury Department and the IRS
agree that clarifying the definition of
hydrogen energy storage property is
warranted. Hydrogen liquefaction
equipment may prepare hydrogen for
storage in the hydrogen energy storage
property, making such property an
integral part of hydrogen energy storage
property. The final regulations provide
that property that is an integral part of
hydrogen energy storage property
includes, but is not limited to, hydrogen
liquefaction equipment.
Section 48E(c)(2) generally defines
‘‘energy storage technology’’ as having
the meaning given such term in section
48(c)(6). Section 48(c)(6)(A)(i) defines
‘‘energy storage technology’’ as
excluding property primarily used in
the transportation of goods or
individuals and not for the production
of electricity. In general, whether
property is ‘‘primarily’’ used in the
transportation of goods or individuals
and not for the production of electricity,
is dependent on the facts and
circumstances. Pipelines, trailers, and
railcars are property primarily used in
the transportation of goods or
individuals and not for the production
of electricity. Accordingly, such
property generally would not be
considered part of hydrogen energy
storage property for purposes of section
48E.
The Treasury Department and the IRS
recognize that there are specific cases in
which hydrogen pipelines that are
directly connected to an energy storage
facility can operate as hydrogen storage.
Hydrogen energy storage property may
have hydrogen pipelines that are used
as gathering and distribution lines to
transport hydrogen within the hydrogen
energy storage property, making such
hydrogen pipelines an integral part of
the hydrogen energy storage property.
These gathering and distribution lines
are not pipelines used to transport
hydrogen outside of the hydrogen
energy storage property. The final
regulations clarify that property that is
an integral part of hydrogen energy
storage property includes, but is not
limited to, gathering and distribution
lines within a hydrogen energy storage
property.

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The Treasury Department and the IRS
decline to provide additional examples
of integral equipment and functionally
interdependent equipment in the
context of hydrogen energy storage
property. The final regulations provide
a function-oriented method to
determine whether a technology is EST
that is broad enough to encompass
nascent technologies without rendering
the regulations quickly obsolete. It is
impossible to enumerate every
technology that may be eligible for the
section 48E credit given the everchanging nature of the industry and
pace of technological development.
Although these regulations do not list
all technologies that may qualify for the
section 48E credit, the final regulations
provide adequate guidance and
examples to illustrate the application of
the rules for taxpayers to analyze a
particular technology. The Treasury
Department and the IRS, therefore, do
not adopt commenters’ requests
concerning specific technologies.
9. Modification of Energy Storage
Technology
Proposed § 1.48E–2(g)(7) provided
that with respect to electrical energy
storage property and hydrogen energy
storage property, modified as set forth in
proposed § 1.48E–2(g)(7), such property
will be treated as an electrical energy
storage property (as described in
proposed § 1.48E–2(g)(6)(i)) or a
hydrogen energy storage property (as
described in proposed § 1.48E–
2(g)(6)(iii)), except that the basis of the
existing electrical energy storage
property or hydrogen energy storage
property prior to such modification is
not taken into account for purposes of
proposed § 1.48E–2(g)(7) and section
48E.
Commenters noted that taxpayers
often replace energy storage equipment
to manage the natural degradation of
storage assets over time and to prolong
the useful life of these projects, even if
such improvements do not meet a 5kWh capacity threshold. One
commenter therefore contended that
references to nameplate capacity in
section 48E are best read to disregard
any degradation of the EST between
when it is placed in service and when
capacity is added. The same commenter
contended that modifications to EST
should be eligible for the section 48E
credit if one of the 5kWh nameplate
measurement tests under proposed
§ 1.48E–2(g)(7)(i) and (ii) are met,
regardless of any degradation that has
occurred to the EST’s nameplate
capacity since its original in-service
date. The commenter requested
clarifying that the nameplate capacity

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after a modification is the nameplate
capacity of such property before the
modification plus the capacity added by
the modification. Another commenter
suggested permitting a ‘‘modification
that leads to a demonstrated increase in
capacity (measured and recorded
immediately before such modifications)
of not less than 5kWh,’’ to be eligible for
the section 48E credit.
Another commenter explained that
nameplate capacity of EST is typically
defined when initial interconnection is
approved, meaning that taxpayers who
wish to claim the estimated
expenditures of storage augmentation
under section 48E will need to modify
the original interconnection agreement
or oversize their assets before placing
them into service. The commenter
requested that the section 48E rules
recognize the eligibility of storage
augmentation beyond nameplate
capacity and suggested that the
estimated expenditures associated with
augmentation of qualifying EST be fully
eligible for the section 48E credit.
Another commenter suggested clarifying
that augmentation of EST over time is
eligible for the section 48E credit, either
by treating estimated future
augmentation costs at the time the EST
is originally placed in service as
eligible, with recapture provisions if
estimated costs are not realized, or by
treating any costs related to
augmentation that are incurred as part
of the upfront investment to construct
an energy storage site as eligible. The
commenter described augmentation as
the periodic upgrade to capacity over a
project’s lifetime by either adding new
inverters and enclosures or recycling
batteries to old enclosures and adding
new batteries behind an existing
inverter.
Section 48E(c)(2) defines EST by
reference to section 48(c)(6). Proposed
§ 1.48E–2(g)(7)(i) and (ii) applied the
rules for modification of EST described
in section 48(c)(6)(A)(i). In defining
EST, section 48(c)(6)(A)(i) uses the term
‘‘nameplate capacity.’’ Accordingly, the
rules for modification of EST apply with
respect to the nameplate capacity of
EST, and do not take into account
potential degradation of the EST prior to
its modification. The final regulations
clarify that for purposes of the
modification rules, the increase in
nameplate capacity is equal to the
difference between nameplate capacity
immediately after the modification and
nameplate capacity immediately prior to
the modification. To maintain
consistency with the statute, the final
regulations do not adopt commenters’
suggestions to measure an increase in

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nameplate capacity in a different
manner.
A commenter also suggested
clarifying that a modification is taken
into account whether the increase in
capacity is within an existing enclosure,
the existing enclosure is expanded, a
new enclosure is added for the
increased capacity, or a new enclosure
is constructed to include both the
existing capacity and the added
capacity.
Section 48(a)(6)(B) defines
modifications of EST without any
reference to physical space limitations.
Proposed § 1.48E–2(g)(7) also does not
address limiting modifications of EST
based on physical space. The Treasury
Department and the IRS conclude that a
modification of EST is not limited by
the physical space occupied by the EST
before or after the modification and
adopt the proposed regulations without
change.
D. Rules for Certain Lower-Output
Qualified Facilities
Proposed § 1.48E–4(a)(1) provided
rules for qualified facilities with a
maximum net output of not greater than
5 megawatts to include qualified
interconnection costs in the basis of an
associated qualified facility. Proposed
§ 1.48E–4(a)(1) provided that the
qualified investment for a qualified
facility includes amounts paid or
incurred by the taxpayer for qualified
interconnection property in connection
with the installation of a qualified
facility that has a maximum net output
of not greater than 5 MW (as measured
in alternating current) (Five-Megawatt
Limitation). Proposed § 1.48E–4(a)(1)
also provided that the qualified
interconnection property must provide
for the transmission or distribution of
the electricity produced by a qualified
facility and must be properly chargeable
to the capital account of the taxpayer as
reduced by the rules in proposed
§ 1.48E–4(a)(6). Proposed § 1.48E–4(a)(2)
defined the term ‘‘qualified
interconnection property.’’ Proposed
§ 1.48E–4(a)(2) further provided that
qualified interconnection property is
not taken into account to determine if a
qualified facility meets the requirements
for the increase in credit rate for energy
communities or domestic content
because qualified interconnection
property is not part of a qualified
facility. Proposed § 1.48E–4(a)(3)
described the Five-Megawatt Limitation
as a measurement taken at the qualified
facility level. Proposed § 1.48E–4(a)(3)(i)
provided that the maximum net output
of a qualified facility is measured only
by the nameplate generating capacity of
the unit of qualified facility, which does

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not include the nameplate capacity of
any integral property, at the time that
the qualified facility is placed in
service. Proposed § 1.48E–4(a)(3)(i)
additionally provided that the
nameplate generating capacity of the
unit of qualified facility is measured
independently from any other qualified
facilities that share the same integral
property. Proposed § 1.48E–4(a)(3)(ii)
provided how the nameplate capacity at
a qualified facility is measured.
Proposed § 1.48E–4(a)(4) defined the
term ‘‘interconnection agreement’’ and
proposed § 1.48E–4(a)(5) defined the
term ‘‘utility.’’ Proposed § 1.48E–4(a)(6)
provided that expenses paid or incurred
for qualified interconnection property
and amounts otherwise chargeable to
capital account with respect to such
expenses must be reduced under rules
similar to the rules contained in section
50(c). Proposed § 1.48E–4(a)(6) provided
that the taxpayer must pay or incur the
interconnection property costs, and
therefore, any reimbursement, including
by a utility, must be accounted for by
reducing the taxpayers’ expenditure to
determine eligible costs. The preamble
to proposed § 1.48E–4(a)(6) explained
that a taxpayer that is reimbursed for
these costs may not include such
reimbursed costs in the amount paid or
incurred by the taxpayer for qualified
interconnection property. In the case of
a utility reimbursing a taxpayer for costs
the taxpayer pays or incurs for qualified
interconnection property, the utility
should provide the taxpayer with
information regarding such costs by the
date on which the project is placed in
service.
The preamble to the proposed
regulations explained that the Treasury
Department and the IRS are aware of
common situations in which a taxpayer
could ultimately receive a payment,
credit, or service from another entity,
including a utility, related to the costs
the taxpayer pays or incurs for qualified
interconnection property. For example,
one taxpayer may place in service a
qualified facility and make payments to
a utility with respect to qualified
interconnection property involving the
addition, modification, or upgrade to
the utility’s transmission system related
to such qualified facility. Subsequently,
a different taxpayer may, at a later date,
place in service a qualified facility and
make payments to the same utility
related to the same additions,
modifications, or upgrades to the
utility’s transmission system that were
made in response to the first taxpayer’s
interconnection. The utility may pay,
credit, or provide services to the first
taxpayer in an amount related to the

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costs paid by the second taxpayer. The
likely amount or timing of any such
payment, credit, or service would be
unknown at the time the first taxpayer
interconnects to the utility’s
transmission system.
Additionally, in the preamble to the
proposed regulations, the Treasury
Department and the IRS requested
comments on several issues related to
reimbursements. The Treasury
Department and the IRS requested
comment on whether such payment,
credit, or service received by the first
taxpayer, as a result of subsequent
payments made to a utility by other
parties, should be treated as a
reimbursement to the first taxpayer and
impact the amount of the costs of
qualified interconnection property that
the first taxpayer may include in its
basis for purposes of the section 48E
credit. The Treasury Department and
the IRS also requested comment on
whether the costs paid by the second
taxpayer should be treated as amounts
paid or incurred for qualified
interconnection property in connection
with the installation of the second
taxpayer’s qualified facility. The
Treasury Department and the IRS
requested comment on industry
practices relevant to the determination
of costs paid or incurred for qualified
interconnection property, including the
accounting treatment of costs paid or
incurred for qualified interconnection
property. The Treasury Department and
the IRS also requested comment on
whether any clarifications are needed
regarding the tax treatment of amounts
paid or incurred for qualified
interconnection property, including
reimbursement of costs paid or incurred
by a taxpayer for qualified
interconnection costs.
In addition to updates discussed in
Sections III.D.1 through 6, the final
regulations clarify the definition of an
interconnection agreement in § 1.48E–
4(a)(4) by stating that in the case of the
election provided under section 50(d)(5)
(relating to certain leased property), the
term includes an agreement regarding a
qualified facility leased by such
taxpayer.
1. Qualified Interconnection Property
Some commenters requested
clarification on whether certain costs
are considered amounts paid or
incurred for qualified interconnection
property. A commenter requested that
the final regulations confirm that
equipment required to modify and
upgrade transmission or distribution
systems beyond the point of
interconnection would be considered
qualified interconnection property.

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Section 48E(b)(4) provides that the
term ‘‘qualified interconnection
property’’ has the meaning given such
term in section 48(a)(8)(B). Section
48(a)(8)(B) defines, in relevant part, the
term ‘‘qualified interconnection
property’’ to mean, with respect to an
energy project that is not a microgrid
controller, any tangible property that is
part of an addition, modification, or
upgrade to a transmission or
distribution system that is required at or
beyond the point at which the energy
project interconnects to such
transmission or distribution system in
order to accommodate such
interconnection. Proposed § 1.48E–
4(a)(2) adopted this definition. The
Treasury Department and the IRS
confirm that under this definition,
tangible property required to modify
and upgrade transmission or
distribution systems beyond the point of
interconnection would (provided the
property satisfies the other requirements
of section 48(a)(8)(B)) be considered
qualified interconnection property and
eligible for inclusion in basis for
purposes of the section 48E credit.
Another commenter requested that
the final regulations expand the
definition of qualified interconnection
property to include grid-enhancing
property. A definitive response to this
comment would require the Treasury
Department and the IRS to conduct a
complete factual analysis of the
property in question, which would
include information beyond that which
was provided by the commenter.
Because more information is needed to
make the determinations requested by
the commenter, the requested
clarifications are not addressed in these
final regulations.
A commenter requested that, in
instances in which the taxpayer funds
network upgrades and is then later
reimbursed by the transmission owner,
taxpayers not be required to account for
any reimbursements of interconnectionrelated expenses paid in later years to
the taxpayer. Another commenter
requested that in such a scenario, the
final regulations should disregard
reimbursements to the extent that the
reimbursement is includable in the
taxpayer’s gross income. The
commenter also asserted that in
circumstances in which the taxpayer
receives a later payment from a
customer utilizing the qualified
interconnection property, the taxpayer
be permitted to treat the payments as
revenue, rather than reimbursement.
One of the commenters also requested
confirmation that taxpayers can include
in their basis qualifying interconnection
costs recovered through ‘‘Transmission

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Owner Initial Funding.’’ According to
the commenters, in certain regional
markets, the transmission owner funds
the costs of interconnection upgrades
for which a taxpayer is responsible, and
the taxpayer then reimburses the
transmission owner over a certain
period, typically 20 years. The
commenters requested that a taxpayer
with such an arrangement be allowed to
include the full amount of
interconnection costs that it will
ultimately pay over that period in
calculating their section 48E credit for
the taxable year that the qualified
facility is placed in service.
The Treasury Department and the IRS
note that the statute limits qualified
interconnection property to tangible
property. In the case of a taxpayer that
pays costs over 20 years, the
commenters do not describe whether
these amounts paid may include
amounts that are not tangible property.
To the extent commenters are asking
generally about the inclusion of the full
allocated cost of interconnection
upgrades and, therefore, any amounts
paid or incurred by the taxpayer for
qualified interconnection property, the
Treasury Department and the IRS
recognize these payments could include
a number of markups that the utility
that builds and owns the relevant
interconnection property might charge
for that property (whether currently or
over a later reimbursement period), such
as the markup for a rate of return or
other costs (for example, a tax gross-up).
Whether specific costs are allowable
would be a fact-specific inquiry related
to, among other things, whether such
costs are incurred with respect to
eligible tangible property. Therefore, the
final regulations do not adopt
commenters’ suggestion to provide that
the full allocated cost of interconnection
upgrades is always eligible, although in
many cases it may be. However, the
Treasury Department and the IRS clarify
that it is not determinative whether
such costs are charged upfront or over
time.
The final regulations under § 1.48E–
4(a)(2) also clarify that for purposes of
determining the original use of
interconnection property in the context
of a sale-leaseback or lease transaction,
the principles of section 50(d)(4) must
be taken into account, as applicable,
with such original use determined on
the date of the sale-leaseback or lease.
2. Interaction With Other Bonus Credit
Amounts
Commenters requested that the final
regulations clarify the interaction
between the rules for qualified
interconnection costs and the

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computation of the domestic content
bonus credit amount and the increased
credit amount for energy projects
located in an energy community since
this clarification was provided in
section 48.
Section 48E(b)(4) provides that the
term ‘‘qualified interconnection
property’’ has the meaning given such
term in section 48(a)(8)(B). Section
48(a)(8)(B) defines qualified
interconnection property as distinct
from the definition of ‘‘energy property’’
provided in section 48(a)(3).
Additionally, section 48(a)(8)(A)
includes amounts paid or incurred for
qualified interconnection property
meeting certain requirements for
purposes of determining the credit
under section 48(a). Similarly, section
48E(b)(1) includes expenditures paid or
incurred by the taxpayer for qualified
interconnection property meeting
certain requirements for purposes of
determining a qualified investment
under section 48E(a) and defines
qualified interconnection property
discretely from a qualified facility
eligible under section 48E(a)(1). Given
that qualified interconnection property
is not part of a qualified facility,
§ 1.48E–4(a)(2) provides that qualified
interconnection property is not taken
into account to determine if a qualified
facility meets the requirements for the
increase in credit rate for energy
communities or domestic content.
Therefore, no further clarification is
needed in the final regulations.
Additionally, because the credit
under section 48E(a) is calculated by
multiplying the applicable percentage—
which includes any domestic content
bonus credit amount—by the basis of
the qualified facility—which includes
amounts paid or incurred by the
taxpayer for qualified interconnection
property, qualified interconnection
costs are taken into account in
calculating the domestic content bonus
credit amount and the increased credit
amounts for energy projects located in
an energy community and for certain
facilities placed in service in connection
with low-income communities.
3. Basis Reduction
For purposes of section 48E(b), the
term ‘‘qualified interconnection
property’’ has the meaning given such
term in section 48(a)(8)(B). There are no
additional references to section 48(a)(8)
other than section 48(a)(8)(B). As a
result, the basis reduction language in
section 48(a)(8)(E), which provides that
in the case of expenses paid or incurred
for interconnection property, amounts
otherwise chargeable to capital account
with respect to such expenses are to be

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reduced under rules similar to the rules
of section 50(c), is not explicitly
incorporated. However, the Treasury
Department and the IRS determined that
the section 50(c) basis reduction rules
apply because section 50(c) provides for
basis adjustments to investment credit
property generally. Section 50(c) has
two basis adjustment rules that could
apply to interconnection property,
section 50(c)(1) or (3). Although
interconnection property is not part of
a qualified facility as provided in
proposed § 1.48E–4(a)(2), qualified
interconnection costs are included in
the basis used to calculate the section
48E credit. Therefore, the Treasury
Department and the IRS confirm the
special rule in section 50(c)(3)(A),
which provides for a basis reduction of
50 percent in the case of any section 48E
credit, applies to qualified
interconnection property that is
properly chargeable to capital account
of the taxpayer which is the amount
included in the basis used to calculate
the section 48E credit.
4. Reimbursements and Other Cost
Reductions
The proposed regulations requested
comment on several issues related to
reimbursement. Generally, the proposed
regulations requested feedback on
treatment of reimbursements in
common situations in which a taxpayer
could ultimately receive a payment,
credit, or service from another entity,
including a utility, related to the costs
the taxpayer pays or incurs for qualified
interconnection property. The proposed
regulations also requested comments on
the outcome when a different taxpayer
makes payments to a utility for the same
additions, modifications, or upgrades of
another taxpayer. Comments were also
requested on industry practices and tax
implications of reimbursements. In
response to these requests, a commenter
requested the final regulations clarify
that a taxpayer is not required to reduce
its section 48E credit on account of any
reimbursement of interconnection costs
in the absence of a fixed right (that is
specific in amount and time) to receive
the reimbursement at the time the
taxpayer incurs the interconnection
costs. This commenter recommended
that the final regulations include rules
that are administrable and provide only
a single credit on qualified
interconnection costs (for example, a
case in which another possible section
48E claimant reimburses directly or
indirectly a first claimant).
Other commenters requested
clarification of the reimbursement rules
under specific scenarios. One
commenter suggested that for cases in

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which the taxpayer funds network
upgrades and is later reimbursed by the
transmission owner, the final
regulations should avoid accounting for
any reimbursements of interconnectionrelated expenses paid in later years to
the taxpayer.
Another commenter suggested that
including reimbursed interconnection
costs in the credit basis should be based
on whether the amounts are includible
in gross income. The commenter stated
that in circumstances in which a utility
reimburses a qualified facility owner
under a set schedule, the final rule
should disregard the utility’s
reimbursements to the extent that the
reimbursement is includable in a
taxpayer’s gross income. The
commenter added that if a subsequent
interconnection customer’s use of the
qualified interconnection property
results in a later payment or credit to
the taxpayer, the payment or credit
should be treated as revenue rather than
reimbursement. The commenter also
requested clarification that in
circumstances in which a qualified
facility owner pays for qualified
interconnection property without
reimbursement, the owner should be
able to utilize the full cost of those
facilities in determining its investment
tax credit.
The Treasury Department and the IRS
recognize that situations may arise in
which the initial amount paid or
incurred for qualified interconnection
property is reduced after the taxable
year in which the taxpayer claims the
section 48E credit. The Treasury
Department and the IRS also recognize
that other complicated situations may
arise in determining whether a taxpayer
has paid or incurred qualified
interconnection costs. The comments
received confirmed that these questions
are not unique to the reimbursement of
qualified interconnection costs and may
also arise in the context of other tax
credits. Therefore, the determination of
whether qualified interconnection costs
have been paid or incurred by the
taxpayer and whether such amounts are
reduced by virtue of transactions with
the utility or with a third party should
be based on generally applicable Federal
tax principles.
In consideration of the comments, the
final regulations revise the rule under
§ 1.48E–4(a)(6) regarding reduction to
amounts chargeable to capital account
to reflect the application of Federal tax
principles to such transactions in
determining the amount a taxpayer paid
or incurred for qualified interconnection
costs. The final regulations at § 1.48E–
4(a)(1) explain that if the costs borne by
the taxpayer are reduced by utility or

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non-utility payments, Federal tax
principles may require the taxpayer to
reduce the amount treated as paid or
incurred for qualified interconnection
property to determine a section 48E
credit. The final regulations at § 1.48E–
4(a)(7) also include two additional
examples related to reducing costs
borne by the taxpayer.
5. Five-Megawatt Limitation
Some commenters provided feedback
on the measurement rule for the FiveMegawatt Limitation provided at
proposed § 1.48E–4(a)(3). Two
commenters suggested that the FiveMegawatt Limitation be modified to
clarify the relevant measurement is
performed at the point of output (that is,
5 MW AC at the inverter) rather than
nameplate generation capacity to better
align with section 48E(b)(1)(B). As
described by one of the commenters, the
text of section 48E(b)(1)(B) does not
contain the words ‘‘nameplate’’ or
‘‘capacity’’ and instead it specifically
refers to the 5 MW limit by reference to
‘‘output . . . measured in alternating
current’’ which, for solar photovoltaic
systems can only be read to refer to
post-inverter measurement. Another
commenter recommended that the final
regulations refer only to output
measured in alternating current, without
presuming that the direct current
nameplate capacity is identical.
Additionally, this commenter requested
that the final regulations specifically
clarify that qualified facilities be
defined at the inverter level for the
limited purpose of evaluating if they
meet the Five-Megawatt Limitation, as
this is the source of any alternating
current output.
Measuring output with accuracy and
consistency must be done using a
defined standard. The Treasury
Department and the IRS conclude that
nameplate generating capacity is the
best and most practical measure of the
maximum net output of a unit of
qualified facility. Nameplate generating
capacity is an objective and identifiable
standard that can be accurately
measured with consistency. Therefore,
the Treasury Department and the IRS do
not adopt the comment suggesting
changes to the use of nameplate
capacity. The final regulations at
§ 1.48E–4(a)(3)(ii) retain the rule that the
determination of whether a qualified
facility has a maximum net output of
not greater than 5 MW (as measured in
alternating current) is based on the
nameplate capacity of the unit of
qualified facility.
Regarding measurement of the FiveMegawatt Limitation in alternating or
direct current, the Treasury Department

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and the IRS understand the
commenter’s concerns and agree that
the rule provided in the proposed
regulations should be revised. Section
48E(b)(1)(B)(i)(I) refers to a maximum
net output of not greater than five
megawatts (as measured in alternating
current). Proposed § 1.48E–4(a)(3)(ii)
provided for nameplate capacity in
alternating current, without addressing
types of qualified facilities, such as solar
facilities, that generate electricity in
direct current. Nameplate capacity for
these types of qualified facilities is
measured before the facility’s output is
converted to alternating current by an
inverter. Because an inverter would be
considered property that is an integral
part of the qualified facility and not part
of the unit of qualified facility itself,
measuring the nameplate capacity of a
qualified facility that generates
electricity in direct current would be
difficult under the proposed regulations.
However, in response to comments,
the final regulations provide a method
of measuring nameplate capacity for a
qualified facility that generates
electricity in direct current. The final
regulations at § 1.48E–4(a)(3)(iii)
provide that, for qualified facilities that
generate electricity in direct current, the
taxpayer determines whether a qualified
facility has a maximum net output of
not greater than 5 MW (in alternating
current) by using the lesser of: (i) the
sum of the nameplate generating
capacities within the unit of qualified
facility in direct current, which is
deemed the nameplate generating
capacity of the unit of qualified facility
in alternating current; or (ii) the
nameplate capacity of the first
component of the qualified facility that
inverts the direct current electricity
generated into alternating current. This
rule provides flexibility for taxpayers
while ensuring that the maximum net
output (in alternating current) of a
qualified facility can be determined in
an administrable and reasonably
accurate manner for qualified facilities
that generate electricity in direct
current.
A few commenters suggested
providing additional examples to
illustrate output rules for
interconnection property. Another
commenter recommended finalizing
Example 1 in proposed § 1.48E–4(a)(7)(i)
which specified that two section 48E
facilities, each with a maximum output
of 5 MW AC, can share—and treat as
qualified interconnection property—a
step-up transformer, which is integral to
both properties.
In response to commenters that
requested additional clarification of the
Five-Megawatt Limitation, the final

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regulations add an additional example
under § 1.48E–4(a)(7) as well as provide
clarifications to the existing examples.
These clarifications illustrate the
revised method of measuring nameplate
capacity for a qualified facility that
generates electricity in direct current.
The clarifications also demonstrate the
application of the Five-Megawatt
Limitation in cases in which the
nameplate capacity differs from the
maximum output provided in the
interconnection agreement. Specifically,
the newly added example describes the
application of the Five-Megawatt
Limitation to separate interconnection
agreements for a single qualified facility
made up of units of a qualified facility
owned by a single taxpayer. In that
example, although the taxpayer has
interconnection agreements with the
utility that each allow for a maximum
output of 10 MW (as measured in
alternating current), the taxpayer may
include the costs taxpayer paid or
incurred for qualified interconnection
property, subject to the terms of the
interconnection agreement, to calculate
the taxpayer’s section 48E credits for
each of the qualified facilities because
each has a maximum net output of not
greater than 5 MW (alternating current).
6. Energy Storage Technology
Two commenters suggested that the
final regulations permit interconnection
costs for stand-alone EST. Both
commenters explained that although
sections 48E(b) and (c) do not mention
eligible interconnection costs in the
context of stand-alone EST, the term
‘‘qualified interconnection property’’ is
defined by reference to section 48(a)(8).
Therefore, according to the commenters,
this result is supported because the
statutory text of that section expressly
includes ‘‘amounts paid or incurred by
the taxpayer for qualified
interconnection property . . . to
provide for the transmission or
distribution of the electricity produced
or stored by such property.’’ These
commenters also added that this result
would reconcile sections 48 and 48E
and would advance the IRA’s express
policy of encouraging storage
deployment.
Based on the explicit language of
section 48E, the Treasury Department
and the IRS disagree that including
costs for qualified interconnection
property for a standalone EST is
supported by the statute. Section
48E(c)(1), which describes the qualified
investment with respect to EST, does
not refer to qualified interconnection
property.
Section 48E(b)(1) generally provides,
in part, that the qualified investment

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with respect to any qualified facility for
any taxable year includes the amount of
any expenditures which are both paid or
incurred by the taxpayer for qualified
interconnection property in connection
with a qualified facility which has a
maximum net output of not greater than
5 megawatts (as measured in alternating
current), and placed in service during
the taxable year of the taxpayer. The
amount of any expenditures which are
paid or incurred by the taxpayer for
qualified interconnection property must
also be properly chargeable to capital
account of the taxpayer. Section
48E(b)(4) defines qualified
interconnection property by reference to
section 48(a)(8)(B). While commenters
are correct that the reference to qualified
interconnection property in section
48(a)(8)(A) also refers to ‘‘electricity
stored,’’ the cross-reference applicable
for qualified facilities is to section
48(a)(8)(B) (the definition of qualified
interconnection property) and there is
no similar cross-reference in section 48E
to support including the costs of
qualified interconnection property for
an EST. The overt omission of a
reference to qualified interconnection
property in section 48E(c), which
provides rules for determining qualified
investment with respect to an EST is
instructive. The clear exclusion of
qualified interconnection property for
EST under section 48E(c)(1),
particularly when compared to its
inclusion in section 48E(b)(1)(B)(i)(I),
demonstrates Congressional intent.
Therefore, the final regulations do not
adopt commenters’ recommendation
that expenditures paid or incurred by
the taxpayer for qualified
interconnection property are includible
in the section 48E credit for EST.
As discussed earlier, the Treasury
Department and the IRS understand that
some hybrid systems (such as those for
a solar qualified facility and EST)
operate under a single interconnection
agreement.1 In these situations, while
expenditures paid or incurred by a
taxpayer for qualified interconnection
property are not includible in the
section 48E credit for an EST, those
expenditures paid or incurred for
qualified interconnection property that
are properly allocated to the qualified
facility (for example, the solar qualified
facility) may be included in the credit
base for the qualified facility’s qualified
investment for the section 48E credit.
1 In some configurations, the addition of EST to
a qualified facility may have no or limited impact
on the interconnection costs of that hybrid facility.

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E. 80/20 Rule
As noted earlier, the 80/20 Rule is
designed to broaden the availability of
the investment credit by providing a
new original placed in service date for
a qualified facility that includes some
components of property previously
placed in service, rather than requiring
the qualified facility to be composed
entirely of new components of property.
In the context of section 48E, the 80/20
Rule applies at the qualified facility
level to the components of property
within the unit of qualified facility or
unit of EST.
Proposed § 1.48E–4(c)(1) provided
that for purposes of section
48E(b)(3)(A)(ii), a facility may qualify as
originally placed in service even if it
contains some used components of
property within the unit of qualified
facility, provided that the fair market
value of the used components of the
unit of qualified facility is not more
than 20 percent of the unit of qualified
facility’s total value (that is, the cost of
the new components of property plus
the value of the used components of
property within the unit of qualified
facility). In addition to providing a new
placed in service date for a qualified
facility that includes some components
of property that have previously been
placed in service, the 80/20 Rule also
encourages investment in the retrofitting
of existing facilities.
Although this section focuses on the
80/20 Rule in the section 48E context,
section II.F. of this Summary of
Comments and Explanation of Revisions
describes comments received on both
sections 45Y and 48E. As described in
that section, the Treasury Department
and the IRS confirm that if a qualified
facility under section 45 or energy
property or EST under section 48 is later
retrofitted in a manner that satisfies the
80/20 Rule, it will be considered a new
qualified facility or a new EST and may
be eligible for a section 48E credit so
long as the qualified facility or EST
meets all requirements of section 48E.
Additionally, the Treasury Department
and the IRS confirm that section 48E
does not refer to a project or system but
in the case of section 48E to a qualified
facility and an EST.
1. Relevance of Prior Section 48
Guidance
Prior guidance and regulations under
section 48 are not binding for purposes
of section 48E. However, several
commenters stated that application of
the 80/20 Rule as proposed violated
longstanding precedent under section
48. These commenters stated that under
section 48 as previously applied,

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taxpayers would be allowed to claim the
section 48E credit for capital
improvements as well as additions or
modifications to existing property
without regard to the 80/20 Rule.
Further, some commenters suggested
that the 80/20 Rule as originally applied
in the section 48 context was only
relevant for addressing the ‘‘original use
requirement’’ for property and was not
intended to prevent additions of new
property from qualifying for a credit.
These commenters pointed to Example
2 in § 1.48–2(b)(7) and Examples 4 and
5 in § 1.48–2(c), to illustrate that, in the
context of the section 48 credit, the 80/
20 Rule was intended to address the
‘‘original use requirement.’’ Consistent
with this view, several commenters
asserted that the prohibition against
claiming the section 48E credit for
additions that do not meet the 80/20
Rule (Excluded Costs Rule) is
inconsistent with the statute and
regulations and should be removed.
One commenter, like many others that
asserted that the application of the 80/
20 Rule for purposes of section 48E is
contrary to historical precedent, also
focused on the negative economic
impact. The commenter stated that the
proposed regulations would negatively
impact the economics of both existing
and future development of clean energy
projects and that existing project
investments were based on reasonable
reliance that future capital
improvements would be eligible for the
section 48E credit without regard to the
80/20 Rule. Similarly, another
commenter stated it did not see a policy
rationale for application of the 80/20
Rule in the manner provided in the
proposed regulations, as it would lead
to uneconomic decisions, such as
favoring demolition and rebuilding
instead of capital expenditures to
modify an existing energy property and,
like others, pointed to what they view
as inconsistency with more than 60
years of prior investment tax credit
(ITC) precedent.
The Treasury Department and the IRS
understand the concerns raised by
commenters. However, prior guidance
and regulations based on section 48 are
not binding for purposes of section 48E.
Section 48E provides a credit only for a
qualified investment with respect to a
qualified facility or an EST and not for
components of property within a
qualified facility or an EST. For the
reasons provided here, the Treasury
Department and the IRS believe that the
best interpretation of ‘‘qualified
investment with respect to a qualified
facility or an EST’’ is that if a taxpayer
does not place in service a qualified
facility or an EST, a taxpayer is not

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eligible for a credit. Therefore, the
application of the 80/20 Rule to the
section 48E credit in the proposed
regulations benefits taxpayers by
providing a path to access the section
48E credit when less than an entirely
new qualified facility or EST is placed
in service.
Section 48E contains several features
that require the credit to be analyzed at
the level of a qualified facility or an
EST. The PWA requirements are applied
to a qualified facility or an EST under
section 48E(a)(2)(A) and (B). Likewise,
determining whether the increased
credit amounts for domestic content and
energy communities also apply to a
qualified facility or an EST. Finally,
determining whether a taxpayer may
include qualified interconnection
property expenditures is tied to the
maximum net output of a qualified
facility. These determinations cannot be
made with respect to individual
components of property. This statutory
construction clearly contemplates
calculating the credit on the basis of an
entire qualified facility or EST.
Applying the 80/20 Rule for purposes of
section 48E provides taxpayers with an
opportunity for additions of property to
an existing facility or an EST to be
eligible for the section 48E credit if the
rule is satisfied.
Other commenters pointed to what
they describe as longstanding rules that
otherwise ITC-eligible improvements
made to existing energy property may
qualify for the ITC. One commenter
stated that the IRA did not change this
rule in any way. According to this
commenter, application of the 80/20
Rule has always uniquely been relevant
for purposes of the production tax credit
(PTC) and is simply not relevant for
purposes of the ITC. The Treasury
Department and the IRS affirm the role
of the 80/20 Rule in the ITC context to
allow for additions of new property to
an existing facility or EST to be eligible
for the section 48E credit if the rule is
satisfied.
2. Excluded Costs
Several commenters asserted that
section 48E allows a credit for adding
components or making capital additions
to a qualified facility. One commenter
concluded that capital improvements
should not be penalized under the 80/
20 Rule. According to the commenter,
owners of a qualified facility, such as a
solar qualified facility, should be
allowed to upgrade or replace
components and claim new section 48E
credits. The commenter pointed to two
examples in the existing Treasury
Regulations under section 48 that the
commenter stated illustrate the proper

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interpretation of the original use
requirement in § 1.48–2(b)(7) and the
difference between a reconditioned or
rebuilt unit of property previously
placed in service and/or the use of
‘‘some used parts,’’ on the one hand,
and the addition of new property or
capital improvements, on the other.
Another commenter stated that the
excluded costs described in proposed
§ 1.48E–4(c)(5) are unclear because a
taxpayer is always adding new
components to used components, and it
should be reworded to clarify that it
does not imply that the taxpayer must
exclude the cost of new components
when a taxpayer adds them to used
components.
Some of these commenters requested
that the 80/20 Rule and the Excluded
Costs Rule provided at proposed
§ 1.48E–4(c)(5) not apply for section 48E
purposes to additions of otherwise
eligible new components of property
added to an existing qualified facility on
which a PTC was not claimed. As an
example, the commenter asserted that
the owner of a solar qualified facility
should be able to make capital
improvements to upgrade or replace
existing solar modules or inverters and
claim a new section 48E credit without
regard to the 80/20 Rule on such capital
improvements. This commenter stated
that the 80/20 Rule should only apply
when a new category of components is
added to an existing qualified facility
comprised of different categories of
components (such as wind being added
to solar), then that new category of
component should be treated as a
separate ‘‘unit of qualified facility.’’ The
commenter stated that this result is also
consistent with the IRA generally,
which does not prevent a taxpayer from
claiming both a PTC with respect to the
output of a qualified facility and an ITC
with respect to any associated EST. The
commenter stated that this is also
consistent with Notice 2018–59.
Another commenter explained that
the 80/20 Rule has its origins under the
section 48 credit and in the context of
the section 48 regulations the phrase,
‘‘some used parts,’’ that has been the
focus of the IRS’s administrative
practice for almost 60 years. According
to the commenter, Rev. Rul. 68–111,
1968–1 C.B. 29, reflects the proper
application of the 80/20 Rule albeit
under a prior version of the section 48
credit. The commenter asserted that the
Excluded Costs Rule in proposed
§ 1.48E–4(c)(5) distorts the 80/20 Rule
by shifting the focus from the use of
‘‘used parts’’ at the time the unit of
property is originally placed in service
to ‘‘new’’ property and capital
improvements that are added later.

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The Treasury Department and the IRS
note that the application of the 80/20
Rule clarifies that expenditures for
components of property that are not a
unit of qualified facility can only qualify
if the 80/20 Rule is satisfied, and thus
any new property and capital
improvements added later that are not a
unit of qualified facility are ineligible
for a section 48E credit unless the 80/
20 Rule is satisfied. In response to the
commenters that asserted that section
48E allows a credit for a component of
property rather than a qualified facility,
the Treasury Department and the IRS
disagree with commenters’
interpretation of the statutory language.
The Treasury Department and the IRS
also emphasize that existing regulations
under § 1.48–2 do not reflect the current
version of section 48 and are not
applicable to section 48E. Additionally,
a taxpayer who makes a capital
improvement to an existing facility
should consider the application of the
Incremental Production Rule provided
in § 1.45Y–4(d). Similarly, a taxpayer
that makes modifications to an EST
should consider the application of the
rule provided at § 1.48E–2(g)(7).
Another commenter suggested that
the purpose of the 80/20 Rule is to allow
a facility that was placed in service
prior to January 1, 2025, to nevertheless
satisfy the requirement in section
48E(b)(3)(A)(ii) that a qualified facility
be placed in service after December 31,
2024, if a substantial portion of the
facility is reconstructed after 2024.
The Treasury Department and the IRS
disagree that the 80/20 Rule is tied to a
particular year. The 80/20 Rule allows
a taxpayer to treat an existing facility as
originally placed in service at a later
date by adding new components of
property that represent at least 80
percent of the value of the unit of
qualified facility. A retrofitted qualified
facility or EST will be eligible for the
section 48E credit if it meets the
requirements of the 80/20 Rule before
the section 48E credit phases out.
3. Recapture
A commenter stated that if the
Treasury Department and the IRS retain
the Excluded Costs Rule as written, the
final regulations should further clarify
that investment tax credit recapture
rules will not apply to additions of
property that do not satisfy the 80/20
Rule. Generally, recapture under section
48E is governed by section 50(a)(1)(A),
which provides for recapture of the
credit if property ceases to be
investment credit property. Additions of
property that do not satisfy the 80/20
Rule and that are thus subject to the
Excluded Costs Rule are not included in

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the calculation of the section 48E credit.
Accordingly, there is no credit to
recapture with respect to such additions
of property.
4. Original Use Requirement
Some commenters asserted that the
original use requirement applies only to
acquired property, and therefore, the
80/20 Rule is unnecessary for other
types of property. These commenters
pointed to section 48E(b)(2)(C), which
provides, in part, that qualified property
means property (i) the construction,
reconstruction, or erection of which is
completed by the taxpayer, or (ii) which
is acquired by the taxpayer if the
original use of such property
commences with the taxpayer. This
language was incorporated at proposed
§ 1.48E–2(f)(3) through (5). The
commenters cited this language to
support their view that the original use
requirement applies only to acquired
property. Therefore, according to the
commenters, the ‘‘original use’’
requirement applies to property
acquired by a taxpayer, but does not
apply to property the construction,
reconstruction, or erection of which is
completed by the taxpayer. The
commenters concluded that this
statutory language supports the position
that capital additions to an existing
qualified facility or EST qualify for the
section 48E credit.
The Treasury Department and the IRS
disagree with the commenters’
interpretation of the statutory language
and corresponding language in the
proposed regulations. The commenters
are correct that section 48E(b)(2)(C)(ii)
requires original use for acquired
property, whereas section 48E(b)(2)(C)(i)
does not mention original use with
respect to property that is constructed,
reconstructed, or erected by or for the
taxpayer, however, that is because an
original use requirement is unnecessary
in the latter context. The taxpayer that
is claiming a credit for property that it
constructed, reconstructed, or erected
by or for such taxpayer will necessarily
be the original user of such property.
Although some commenters suggested
the 80/20 Rule has historically been
applied in the section 48 context with
respect to the original use requirement,
the Treasury Department and the IRS
emphasize that the 80/20 Rule was first
applied to the section 48 credit through
guidance issued in the Internal Revenue
Bulletin providing beginning of
construction guidance. The Treasury
Department and the IRS reiterate that for
section 48E purposes, the 80/20 Rule
allows a taxpayer that retrofits an
existing facility to treat such facility as
a new qualified facility or EST.

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5. EST
In the context of section 48E, the
proposed regulations discussed the 80/
20 Rule for purposes of retrofitting a
qualified facility but did not specifically
address the application of the 80/20
Rule to EST. Some commenters asked if
the 80/20 Rule applied to EST.
Commenters requested that the final
regulations clarify that the 80/20 Rule
also applies to EST, including battery
energy storage systems and pumped
storage hydropower. Another
commenter stated that new component
categories, like EST, added to existing
facilities should be treated as separate
units of qualifying facility and
exempted from the 80/20 Rule.
In response to these comments, the
Treasury Department and the IRS note
that the 80/20 Rule applies to EST. The
80/20 Rule, as it is applied to EST, is a
separate rule from the modification of
EST provided by the section 48E(c)(2)
reference incorporating section
48(c)(6)(B) (modifications of EST). The
final regulations adopt the application
of the 80/20 Rule for EST, and this
Summary of Comments and Explanation
of Revisions addresses EST in regard to
the 80/20 Rule. With respect to the
addition of EST to a site with an
existing qualified facility, the Treasury
Department and the IRS note that an
EST is separate from a qualified facility
as discussed in section III.C.2. of this
Summary of Comments and Explanation
of Revisions. As a result, merely adding
an EST to a site with an existing
qualified facility does not require
application of the 80/20 Rule.
6. Specific Technologies
Some commenters asked for specific
clarifications regarding the 80/20 Rule
and particular technologies. A
commenter suggested that in the case of
a hydropower facility combined with a
pumped storage hydropower facility,
each powerhouse generating unit
(turbine or pump turbine, generator and
controls) should be considered a unit of
qualified facility for purposes of the
final regulations. Additionally, this
commenter asserted, that, in the case of
a wind facility, the functionally
interdependent components of a unit of
qualified facility should be the turbine,
tower, and foundation pad. In both
cases, the commenter requested that the
80/20 Rule apply to the functionally
interdependent components of the unit
of qualified facility.
For purposes of the section 45Y and
section 48E credits, the unit of qualified
facility includes all functionally
interdependent components of property
(as defined in proposed § 1.48E–

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2(d)(2)(ii)) owned by the taxpayer that
are operated together and that can
operate apart from other property to
produce electricity. The final
regulations adopt these rules, which
provide a function-oriented approach to
determine if property is considered part
of the qualified facility that generates
electricity, to ensure that the final
regulations are broad enough to
encompass nascent technologies
without rendering the regulations
quickly obsolete. After consideration of
the comments, an example of the
application of the 80/20 Rule to a
qualified hydropower production
facility has been added to the final
regulations under § 1.48E–4(c)(6)(v).
Additionally, the Treasury Department
and the IRS made revisions to Example
3 of § 1.48E–4(c)(6)(iii), similar to those
made for § 1.45Y–4(d)(3)(iii), that
removed the reference to a
decommissioned nuclear facility to
avoid referring to decommissioned and
restarted nuclear facilities in the
Incremental Production Rule and the
80/20 Rule.
Another commenter specifically asked
that the 80/20 Rule be eliminated for
certain types of facilities such as power
generation, thermal generation, or CHP
facilities upgraded to be carbon neutral.
To support this request, the commenter
noted that the 80/20 Rule discourages
the use of existing infrastructure in CHP
applications. While the Treasury
Department and the IRS appreciate the
concerns raised for particular
technologies, as described in the
preamble to the proposed regulations, a
qualified facility generally does not
include equipment that is an addition or
modification to an existing qualified
facility or EST. However, see § 1.48E–
4(b) regarding the Incremental
Production Rule.

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7. Interaction Between the Incremental
Production Rule and the 80/20 Rule
Some commenters were concerned
about the interaction of the Incremental
Production Rule and the 80/20 Rule and
the provided at proposed §§ 1.45Y–4(c)
and 1.48E–4(b). One commenter
requested that the Treasury Department
and the IRS make clear that the
provision for retrofitted facilities is
separate and distinct from the
requirements for the Incremental
Production Rule, and that if there is any
overlap between the two, the 80/20 Rule
should control. The commenter stated
that a retrofitted facility that results in
the addition of capacity should be
treated as newly placed in service if it
meets the 80/20 Rule (rather than
requiring the retrofitted facility to

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follow the Incremental Production
Rule).
Another commenter recommended
clarifying when to apply one rule or the
other in situations in which both the 80/
20 and Incremental Production rules
could apply. A commenter also asserted
that the statutory text under sections
45Y(b)(1)(C) and 48E(b)(3)(B)(i),
regarding the Incremental Production
Rule, is without regard to the 80/20 Rule
or the facility’s original placed in
service date, and that, therefore,
Congress sought to incentivize
investment in existing facilities without
requiring taxpayers to meet the 80/20
Rule. Similarly, commenters
recommended providing an example of
a decommissioned facility without any
reference to the 80/20 Rule, and to
revise Example 3 in proposed § 1.45Y–
4(d)(3)(iii), regarding the 80/20 Rule, to
remove the reference to
decommissioning.
The Treasury Department and the IRS
agree that the Incremental Production
Rule provided in sections 45Y(b)(1)(C)
and 48E(b)(3)(B)(i) are separate and
distinct from the 80/20 Rule. If a
retrofitted facility satisfies the 80/20
Rule, the final regulations provide that
the facility will be treated as newly
placed in service even if the taxpayer
also satisfies the Incremental Production
Rule. Separately, these final regulations
provide an additional example, in
§ 1.48E–4(b)(5), which specifically
addresses decommissioned and
restarted facilities. Additionally,
§ 1.48E–4(c)(1) is clarified to confirm
that a qualified facility or EST may
claim the full available credit rather
than the credit resulting from an
addition of capacity. Finally, Example 3
in § 1.45Y–4(d)(3)(iii) is modified to
remove the reference to
decommissioning.
Another commenter requested
clarification that even if a facility placed
in service before 2025 (pre-2025 facility)
fails the 80/20 Rule, property that is
added to the facility may still qualify for
the section 48E credit under the
Incremental Production Rule in section
48E(b)(3)(B)(i). Proposed § 1.48E–4(b)(1)
provided, in part, that the term qualified
facility includes either a new unit or an
addition of capacity placed in service
after December 31, 2024, in connection
with a facility described in section
48E(b)(3)(A) (without regard to section
48E(b)(3)(A)(ii)), which was placed in
service before January 1, 2025, but only
to the extent of the increased amount of
electricity produced at the facility by
reason of such new unit or addition of
capacity. Thus, a pre-2025 facility that
fails the 80/20 Rule may still qualify for
the section 48E credit under the

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Incremental Production Rule.
Additionally, the Treasury Department
and the IRS confirm that this rule will
apply to a pre-2025 facility regardless of
whether it satisfies the 80/20 Rule.
8. Other Comments
While the majority of commenters
that opposed the 80/20 Rule suggested
eliminating it, particularly the Excluded
Costs Rule, one commenter provided an
additional recommendation. This
commenter recommended that the
proposed regulations be revised to
permit taxpayers to elect either the 80/
20 Rule or a rule based on the original
cost of the qualified facility (Original
Cost Rule). Under the Original Cost Rule
as proposed by the commenter, a
qualified facility would be treated as
originally placed in service, even
though it contains some used
components of property, provided the
cost of the new components of the unit
of qualified facility is at least 50 percent
of the original cost of the unit of
qualified facility. Original cost would be
defined as the unadjusted GAAP book
basis at the time the qualified facility
was originally placed in service. The
commenter also explained that this new
rule could be limited in its application
and stated that outside of sections 45
and 48 an 80/20 Rule currently applies
to determine eligibility for bonus
depreciation under section 168(k)(7)
and the carbon oxide sequestration
credit under section 45Q of the Code.
Therefore, the commenter requested that
the final regulations adopt an optional
Original Cost Rule limited to section
45Y and section 48E qualified facilities,
which would limit the effect to the
section 45Y and 48E credits and permit
the 80/20 Rule adopted in other
contexts to remain in place.
The Treasury Department and the IRS
understand the commenter’s desire for a
less restrictive standard than what the
proposed 80/20 Rule provides, but the
Treasury Department and the IRS think
the 80/20 Rule strikes the appropriate
balance between allowing taxpayers
flexibility and creating an incentive for
new investment. Therefore, the final
regulations do not adopt the
commenter’s proposal.
After consideration of all comments
expressing opposition to the 80/20 Rule
in the context of section 48E, the
Treasury Department and the IRS
decline to modify or abandon the 80/20
Rule as requested. Section 48E(b)(1)
provides that the section 48E credit is
available for the qualified investment
with respect to any qualified facility for
any taxable year that includes the basis
of any qualified property placed in
service by the taxpayer during such

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taxable year which is part of a qualified
facility. Section 48E(c)(1) provides that
a credit for the qualified investment
with respect to an EST for any taxable
year is the basis of any EST placed in
service by the taxpayer during such
taxable year. The 80/20 Rule is designed
to broaden the availability of the section
48E credit to provide a new original
placed in service date for a qualified
facility or EST that includes some
components of a qualified facility or
EST that have already been placed in
service, rather than requiring the entire
unit of qualified facility or EST to be
composed of only new property. The
80/20 Rule also encourages retrofitting
an existing qualified facility or EST
provided there is sufficient new
investment. As described earlier in this
section on the 80/20 Rule, if a qualified
facility under section 45 or energy
property under section 48 is retrofitted
in a manner that satisfies the 80/20
Rule, it will be considered a new
qualified facility and may be eligible for
the section 45Y or 48E credits if the
qualified facility meets all of the
sections 45Y and 48E requirements.
Section 48E(c)(2) incorporates the
lone express rule for modification of
existing energy property that is found in
section 48(c)(6)(B). This special rule is
limited to modifications of existing EST.
The inclusion of this specific provision
suggests that modifications of existing
EST that do not meet the 80/20 Rule or
the Incremental Production Rule are
ineligible for the section 45Y or 48E
credits. Adopting the 80/20 Rule for the
section 48E credit is favorable to
taxpayers and encourages substantial
additional investment in existing
qualified facilities and EST.
As discussed in section IV.G. of this
Summary of Comments and Explanation
of Revisions, the ownership rules
provided that the section 45Y and 48E
credits are available for an entire unit of
qualified facility or unit of EST and not
for individual components of property.
The 80/20 Rule is consistent with the
ownership rules because it ensures that
a qualified facility or EST that is
retrofitted to a sufficient extent is
considered a new qualified facility or
EST, whereas the addition of mere
components is not eligible for the
section 48E credit.
F. Qualified Progress Expenditures
Section 48E(d)(1) provides that rules
similar to the rules of former section
46(c)(4) and (d) (as in effect on the day
before the date of the enactment of the
Revenue Reconciliation Act of 1990)
apply for purposes of section 48E(a).
Footnote 5 of the proposed regulations
explained that the rules provided by

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§ 1.46–5 related to qualified progress
expenditures apply for purposes of
section 48E(a).
Several commenters requested that
the final regulations provide additional
clarifications related to whether
qualified progress expenditures are
allowable for purposes of elective
payment elections under section 6417
(section 6417 elective payment
elections). Commenters requested
clarifying the application of qualified
progress expenditure payments to
‘‘applicable entities,’’ as defined in
section 6417(d)(1), and confirming that
progress expenditures permitted by
section 48E are allowable for purposes
of section 6417 elective payment
elections. Commenters noted that, while
section 6418(g)(4) provides an explicit
statutory prohibition on using the
section 6418 credit transfer election
provisions for progress expenditures, a
similar prohibition was not included for
section 6417 elective payment elections
and that, therefore, permitting
applicable entities to use the section
48E credit for purposes of section 6417
elective payment elections is consistent
with the statutory text of section 6417.
Given the statutory language under
section 48E(d)(1), a taxpayer can make
a qualified progress expenditure
election, as provided in § 1.46–5, to
increase its qualified investment with
respect to a qualified facility or EST for
the taxable year by any qualified
expenditures made during such taxable
year. Section 6417(b)(12) provides that
the section 48E credit is an applicable
credit for purposes of making an
elective payment election. The statutory
text of sections 48E(d)(1) and
6417(b)(12), when read in tandem,
permit a taxpayer to make an elective
payment election with respect to a
section 48E credit determined pursuant
to a qualified progress expenditure
election. Therefore, the Treasury
Department and the IRS confirm that for
the section 48E credit, qualified
progress expenditures are allowable for
purposes of section 6417 elective
payment elections but have determined
that no change is necessary in the final
regulations. The final regulations at
§ 1.48E–4(g) adopt language similar to
footnote 5 from the proposed
regulations, that the rules provided by
§ 1.46–5 related to qualified progress
expenditures apply for purposes of
section 48E(a).
G. Incremental Cost Rule
One commenter requested that the
final regulations ‘‘clarify the application
of the ‘incremental cost’’’ concept to
section 48E. Incremental cost is the
excess of the total cost of equipment

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4027

over the amount that would have been
expended for the equipment if the
equipment were not used for a
qualifying purpose. The regulations
under former § 1.48–9(k) provided the
incremental cost rule. The preamble to
the Treasury Decision (TD 7765, 46 FR
7291) that implemented this rule noted
that in many instances one item of
property can be used in part for a
qualifying energy purpose and in part
for non-qualifying functions. The
preamble to TD 7765 explained that the
Treasury Department and the IRS
approached this situation by
considering whether to deny the credit,
provide partial credit, or allow a full
credit. The preamble stated that simply
denying the credit entirely would
discourage investments, but that, on the
other hand, property which incidentally
serves an energy function should not
receive the subsidy of a full energy
credit. For these reasons, the Treasury
Department and the IRS viewed the
incremental cost rule as the most fair
approach.
The Treasury Department and the IRS
have determined that a similar approach
should be taken in these final
regulations. Section 1.48E–4(h)(1)
provides that for purposes of section
48E, if a component of qualified
property of a qualified facility or a
component of property of an EST is also
used for a purpose other than the
intended function of the qualified
facility or EST, only the incremental
cost of such component is included in
the basis of the qualified facility or EST.
This section also defines the term
‘‘incremental cost’’ to mean the excess
of the total cost of a component over the
amount that would have been expended
for the component if that component
were used for a non-qualifying purpose.
Section 1.48E–4(h)(2) provides an
example to illustrate this rule.
H. Application of Normalization OptOut
Proposed § 1.48E–4(g)(4) referred
taxpayers to section 50(d)(2) for
application of the normalization rules to
the section 48E credit in the case of
certain regulated companies, including
rules regarding the election not to apply
the normalization rules to EST (as
defined in section 48(c)(6) of the Code).
Several commenters requested that the
final regulations clarify that the
normalization opt-out election provided
in section 50(d)(2) is available for the
section 48E credit claimed with respect
to an EST, without regard to the date on
which construction of such EST begins.
After consideration of the comments,
the requested clarification has been
adopted in § 1.48E–4(i)(4).

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IV. Combined Qualified Facilities
(Sections 45Y and 48E)
This section covers issues that impact
both sections 45Y and 48E and includes
the topics: beginning of construction,
property included in a qualified facility,
qualified facilities and specific
technologies, coordination with other
credits, integral part, shared integral
property, ownership, the Incremental
Production Rule, and the dual use rule.
Proposed § 1.45Y–2(a) defined a
‘‘qualified facility’’ to mean a facility
owned by the taxpayer that is used for
the generation of electricity, is placed in
service after December 31, 2024, and has
a GHG emissions rate of not greater than
zero (as determined under rules
provided in proposed § 1.45Y–5).
Proposed § 1.48E–2(a) defined a
‘‘qualified facility’’ to mean a facility
that is used for the generation of
electricity, is placed in service by the
taxpayer after December 31, 2024, and
has a GHG emissions rate of not greater
than zero (as determined under rules
provided in § 1.45Y–5).

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A. Beginning of Construction
Notice 2022–61, 2022–52 I.R.B. 560,
provides guidance regarding the
prevailing wage and apprenticeship
(PWA) requirements and provides
guidance for determining the beginning
of construction of a facility for the
section 45Y and 48E credits. Section 5
of the Notice provides that, to determine
when construction begins for purposes
of sections 30C, 45V, 45Y, and 48E,
principles similar to those under Notice
2013–29, 2013–20 I.R.B. 1085, regarding
the Physical Work Test and Five Percent
Safe Harbor apply, and taxpayers
satisfying either test will be considered
to have begun construction.
Section 5 of Notice 2022–61 also
provides that principles similar to those
provided in certain IRS Notices 2
regarding the Continuity Requirement
for purposes of sections 30C, 45V, 45Y,
and 48E apply. Section 5 further
provides that whether a taxpayer meets
the Continuity Requirement under
either test is determined by the relevant
facts and circumstances. Additionally,
section 5 states that principles similar to
those under section 3 of Notice 2016–
2 Notice 2013–29, 2013–20 I.R.B. 1085; clarified
by Notice 2013–60, 2013–44 I.R.B. 431; clarified
and modified by Notice 2014–46, 2014–36 I.R.B.
520; updated by Notice 2015–25, 2015–13 I.R.B.
814; clarified and modified by Notice 2016–31,
2016–23 I.R.B. 1025; 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; modified by
Notice 2020–41, 2020–25 I.R.B. 954; clarified and
modified by Notice 2021–5, 2021–3 I.R.B. 479;
clarified and modified by Notice 2021–41, 2021–29
I.R.B. 17.

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31, 2013–44 I.R.B. 431, regarding the
Continuity Safe Harbor also apply for
purposes of sections 30C, 45V, 45Y, and
48E. Section 5 also provides that
taxpayers may rely on the Continuity
Safe Harbor provided the facility is
placed in service no more than four
calendar years after the calendar year
during which construction began. For
purposes of the section 45Y and 48E
credits, Notice 2022–61 continues to
apply.
A commenter requested that final
regulations clarify that projects failing to
qualify for the section 45 or 48 credits
due to a failure to satisfy continuity
requirements may still qualify for the
section 45Y or 48E credits, assuming all
other requirements for the section 45Y
or 48E credit are satisfied. The
commenter contended that a taxpayer
may meet the January 1, 2025, beginning
of construction requirement to qualify
for the section 45 and 48 credits, but
may not be able to satisfy continuity
requirements under existing IRS
guidance by placing the facility in
service within four years after
construction began. The Treasury
Department and the IRS confirm that a
facility that fails to satisfy the
requirements (including beginning of
construction requirements) for the
section 45 or 48 credit, is not
disqualified from claiming either
section 45Y or 48E so long as the facility
meets all requirements under those
Code sections.
The commenter also noted that
sections 45Y and 48E employ a ‘‘start of
construction’’ metric for purposes of
determining whether a qualified facility
is eligible for the increase in credit rates
for satisfying the domestic content or
energy communities bonus, and for
assessing the applicable credit phaseout
amounts. The commenter recommended
resolving what they characterized as
uncertainty related to application of
beginning of construction rules under
existing IRS guidance to sections 45Y
and 48E by adopting modified
continuity safe harbor requirements for
determining the beginning of
construction. One such modified safe
harbor would permit a taxpayer to apply
whatever rules were applicable to the
‘‘commence construction’’ year that
corresponds to the earliest year that
would still meet a continuity safe harbor
based on when the facility was
ultimately placed in service.
The Treasury Department and the IRS
have determined that the existing
Internal Revenue Bulletin guidance
(referred to as the IRS Notices)
adequately addresses the beginning of
construction rules applicable to sections
45Y and 48E. Additionally,

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modifications to the beginning of
construction guidance provided by the
IRS Notices for sections 45 and 48 are
beyond the scope of these final
regulations.
B. Property Included in Qualified
Facility
Proposed § 1.45Y–2(b) provided a
description of the property included in
a qualified facility. Proposed § 1.45Y–
2(b)(1) provided that a qualified facility
includes a unit of qualified facility,
defined in proposed § 1.45Y–2(b)(2)(i),
and also includes qualified property
owned by the taxpayer that is an
integral part of a qualified facility,
defined in proposed § 1.45Y–2(b)(3).
Section 45Y is silent regarding the
credit eligibility of components that are
part of a qualified facility but located in
different locations. Accordingly,
proposed § 1.45Y–2(b)(1) clarified that
any property that meets the
requirements of a qualified facility
described in proposed § 1.45Y–2(b) is
part of a qualified facility, regardless of
where such property is located.
Proposed § 1.48E–2(b) provided that a
qualified facility includes a unit of
qualified facility, defined in proposed
§ 1.48E–2(b)(2)(i), and also includes
property owned by the taxpayer that is
integral to the unit of qualified facility,
which is defined in proposed § 1.48E–
2(b)(3). For purposes of section 48E, a
qualified facility does not include any
electrical transmission equipment, such
as transmission lines and towers, or any
equipment beyond the electrical
transmission stage, and generally does
not include equipment that is an
addition or modification to an existing
qualified facility. However, the
proposed regulations provided two
specific exceptions to that rule: the
Incremental Production Rule, and the
80/20 Rule.
A commenter stated that there are
inconsistencies between the definitions
of a ‘‘property included in a qualified
facility’’ in proposed § 1.45Y–2(b)(1)
and ‘‘unit of qualified facility’’ in
proposed § 1.45Y–2(b)(2). The
commenter stated that the first
definition provides that the qualified
facility equals the ‘‘unit of qualified
facility’’ plus the ‘‘integral property’’,
however, the second definition provides
that a ‘‘unit of qualified facility’’ equates
to ‘‘functionally interdependent
components of property.’’ The
commenter stated that proposed
§ 1.48E–2 had similar inconsistencies.
The commenter suggested that the final
regulations include an example to more
clearly define a qualified facility. The
commenter also referred to the
coordination with other credits in

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proposed § 1.45Y–2(c) and stated that a
taxpayer must assume that what
constitutes a ‘‘qualified facility’’ under
section 45Y, namely, all functionally
interdependent components of property
as well as any integral property, is the
same with respect to all other Federal
income tax credits that reference a
qualified facility, but that this definition
needs to be made consistent across all
the other Code sections.
The Treasury Department and the IRS
do not agree that an ambiguity exists
between the references to a qualified
facility. For both sections 45Y and 48E,
the unit of qualified facility is the
narrower definition and includes only
the functionally interdependent
components of property. A qualified
facility is this ‘‘unit of qualified facility’’
plus integral property. Multiple
examples in the proposed regulations
illustrate these concepts.
The Treasury Department and the IRS
also do not agree that taxpayers must
assume that the definition of a
‘‘qualified facility’’ under sections 45Y
and 48E is the same in all other Federal
income tax credits. Each Code section
has its own unique definition of a
facility that must be considered;
addressing definitions in other Code
sections is beyond the scope of these
final regulations. In response to
commenters’ concerns, though, the final
regulations add additional examples to
illustrate the interaction of Federal
income tax credits in §§ 1.45Y–2(c)(3)
and 1.48E–2(f)(3). The final regulations
at §§ 1.45Y–2(b)(3)(vii) and 1.48E–
2(b)(3)(vii) also change the term
‘‘qualified property’’ in proposed
§ 1.45Y–2(b)(1) to ‘‘property’’ as
‘‘qualified property’’ is not a term used
in section 45Y.
C. Qualified Facilities and Specific
Technologies for Purposes of Sections
45Y and/or 48E

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1. Biogas
Commenters stated that the energy
feedstock production property
comprising a feedstock processing and
treatment system, when owned by the
same taxpayer that owns the electric
generation facility placed in service
after December 31, 2024, is either a
functionally interdependent component
property operated together with the
electric generation facility or an integral
part of that facility. Commenters
asserted that anaerobic digester and gas
conditioning components are used
directly in the intended function of the
facility and that, without this feedstock
treatment, the electricity production
component would not be able to
produce zero or negative GHG

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electricity. Accordingly, commenters
requested that the final regulations
recognize all components of an
electricity production facility, including
the anaerobic digester and gas
conditioning equipment as part of a
qualified facility. The final regulations
do not adopt these comments because
while the energy feedstock production
property described is generally used to
produce fuel that may be used by a
qualified facility to generate electricity,
it is not part of such qualified facility
based on the definition of qualified
facility for purposes of the section 45Y
and 48E credits.
2. Solar
A commenter encouraged the
Treasury Department and the IRS to
explicitly define solar photovoltaic
panels used to generate electricity for an
automated shading system as a qualified
facility. The commenter noted that the
example in proposed § 1.45Y–5(c)(1)(iii)
already describes the GHG emissions
rate for qualified facilities that produce
electricity using solar photovoltaic
properties as not greater than zero and
that proposed § 1.45Y–5(c)(2)(iv) also
describes solar photovoltaic power as a
type of non-C&G facility.
The Treasury Department and the IRS
have determined that the example in
proposed § 1.45Y–5(c)(1)(iii) and the list
of non-C&G facilities in proposed
§ 1.45Y–5(c)(2)(iv) are sufficient to
address commenter’s request as the
rules adequately provide that facilities
using solar photovoltaic property to
produce electricity are eligible for the
section 45Y and 48E credits assuming
the taxpayer satisfies the other statutory
requirements. Accordingly, the final
regulations adopt the proposed rule
without change.
3. Nuclear
A commenter requested that the final
regulations confirm that nuclear
structures, components, and fuel are
part of qualified property for purposes
of section 48E. Similarly, another
commenter requested confirmation that
specific components, such as reactor
cores, are included in the qualified
investment in a qualified facility under
section 48E. Another commenter
suggested adding language to the
definition of integral part with respect
to buildings to specifically address a
building used for nuclear fusion or
fission. The commenter specifically
requested the final regulations describe
a structure or building that is integral to
the intended function of a qualified
facility because it is needed to comply
with or maintain required radiological

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health and safety conditions as required
by a qualified facility’s regulator.
Section 48E(b)(1) generally provides
that the section 48E credit is available
for a taxpayer’s qualified investment
with respect to a qualified facility,
which is the sum of the basis of any
qualified property placed in service by
the taxpayer during such taxable year
that is part of such qualified facility and
if applicable, qualified interconnection
costs. Section 48E(b)(2)(A) provides, in
relevant part, that qualified property is
property which is tangible personal
property or other tangible property (not
including a building or its structural
components), but only if such property
is used as an integral part of the
qualified facility. Therefore, tangible
property, including structures (other
than buildings or their structural
components), components, and fuel,
that meets the definition of qualified
property may be included in the credit
base of a qualified facility. As provided
in § 1.48E–2(d)(3)(v), generally
buildings are not integral parts of a
qualified facility because they are not
integral to the intended function of the
qualified facility. Due to the exclusion
of a building or its structural
components, this would exclude, for
example, buildings that house nuclear
reactor control rooms.
However, as the proposed regulations
acknowledged, not all structures are
considered ‘‘buildings’’ for the purpose
of excluding buildings and their
structural components. Proposed
§ 1.48E–2(b)(3)(v)(A) and (B) provided
that a structure is not considered a
building if it is essentially an item of
machinery or equipment, or if it houses
components of property that are integral
to the intended function of the qualified
facility and if the use of the structure is
so closely related to the use of the
housed components of property therein
that the structure clearly can be
expected to be replaced if the
components of property it initially
houses are replaced. The Treasury
Department and the IRS confirm that
nuclear containment structures fall
within the exception provided in
proposed § 1.48E–2(b)(3)(v)(A) and (B),
which has been adopted and moved to
§ 1.48E–2(d)(3)(v)(A) and (B) of the final
regulations. Like hydropower dams, but
unlike control room buildings, nuclear
containment structures are integral to
the intended function of the qualified
facility. Moreover, given their
complexity, technical requirements,
Nuclear Regulatory Commissionmandated testing requirements, severe
limits on the time workers and other
personnel can spend inside the
structure, and purpose, nuclear

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containment structures are essentially
pieces of specialized equipment. They
ensure the fulfillment of several safety
functions at a nuclear power plant,
including: (i) confinement of radioactive
substances in operational states and in
accidental conditions; (ii) protection of
the reactor against natural external
events and human induced events; and
(iii) radiation shielding in operational
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4. Hydropower
A commenter requested that the final
regulations provide additional examples
illustrating the scope of a ‘‘qualified
investment credit facility’’ and
‘‘qualified property’’ with respect to
hydropower. Another commenter asked
that the final regulations confirm that
components of project works as
identified in FERC licenses (referred to
by the commenter as physical structures
of a project) are integral property to a
hydropower facility and therefore
eligible for the section 48E credit.
Specifically, the commenter suggested
adopting principles from the section 48
proposed regulations regarding qualified
offshore wind facilities, whereby all
FERC-licensed components of any kind,
including remote islanded hydropower
generation components, including the
switchgear or substation housed in an
onshore substation, are either
functionally interdependent
components of a unit of the qualified
facility or integral parts of a qualified
facility.
A definitive response to these
comments would require the Treasury
Department and the IRS to conduct a
complete factual analysis of the
hydropower property in question,
which may include information beyond
that which was provided by the
commenters. Because more information
is needed to make the determinations
requested by the commenters, the final
regulations do not provide these
requested clarifications. However,
further discussion of relevant
components of hydropower facilities is
provided in section IV.E. of this
Summary of Comments and Explanation
of Revisions.
5. Section 48 Energy Properties
A commenter suggested that, for
purposes of the qualified investment
calculation in section 48E(b), the final
regulations should clarify that the term
‘‘qualified property’’ includes any
energy property defined in section
48(a)(3), unless it is specifically
excluded. The Treasury Department and
the IRS reiterate that the determination
of whether a qualified facility is eligible
for the section 48E credit depends, in

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part, on the anticipated GHG emissions
of the facility as determined under
section 48E(b)(3)(B)(ii) and § 1.48E–5 of
these regulations rather than the
technology used. This is distinct from
section 48(a)(3), which identified
specific types of energy property that
are eligible for the section 48 credit. See
the discussion of qualified property for
section 48E in section III.B. of this
Summary of Comments and Explanation
of Revisions. Accordingly, the Treasury
Department and the IRS cannot adopt
the commenter’s recommendation and
the rule will be adopted as proposed.
6. Facilities That Are Not Used for the
Generation of Electricity
A commenter requested that the final
regulations provide flexibility to ensure
that the following thermal energy
technologies would not be prohibited
from qualifying for the section 45Y and
48E credits: alternative water thermal
sourcing, heat recovery systems for
ventilation air, simultaneous heat
recovery, and air source heat pumps.
Similarly, another commenter suggested
that thermal production from non-waste
energy recovery should be eligible for
the section 45Y credit and provided
sample regulatory language to that
effect. Another commenter suggested
that technologies such as air-source heat
pumps and building efficiency retrofits
should be eligible for the section 45Y
and 48E credits. Other commenters
stated that microgrid controllers, which
are energy property under section 48,
should be eligible for the section 48E
credit.
Sections 45Y(b)(1)(A)(i) and
48E(b)(3)(A)(i) define a qualified facility
as a facility which is used for the
generation of electricity. A facility
cannot be considered a qualified facility
under either section 45Y or 48E if it
does not meet this requirement.
However, the Treasury Department and
the IRS note that the section 48E credit
applies to both qualified facilities and
EST. Section III.C.1. of this Summary of
Comments and Explanation of Revisions
discusses the definition of EST for
purposes of the section 48E credit.
Given the earlier-described
comments, and a few comments on
other topics that indirectly suggested
that EST that are net consumers of
electricity were nonetheless ‘‘used for
the generation of electricity,’’ the
Treasury Department and the IRS have
determined that additional clarification
of the phrase ‘‘used for the generation of
electricity’’ is warranted. The final
regulations at §§ 1.45Y–2(a)(1) and
1.48E–2(b)(1)(i) clarify that, for a facility
to meet the requirements of sections
45Y(b)(1)(A)(i) and 48E(b)(3)(A)(i), the

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facility must be a net generator of
electricity, taking into account any
electricity consumed by the facility.
D. Coordination With Other Credits
Proposed §§ 1.45Y–2(c) and 1.48E–
2(c) provided rules for coordination of
the section 45Y and 48E credits with
other Federal income tax credits,
including those determined under
sections 45, 45J, 45Q, 45U, 48, and 48A.
Proposed § 1.45Y–1(c)(1) provided, in
part, that a taxpayer that owns a
qualified facility that is eligible for both
a section 45Y credit and another Federal
income tax credit is eligible for the
section 45Y credit only if the other
Federal income tax credit was not
allowed with respect to the qualified
facility.
A commenter suggested clarifying that
the reference in proposed § 1.45Y–
2(c)(1) to ‘‘another Federal income tax
credit’’ does not extend beyond those
credits specifically listed in section
45Y(c)(1). The commenter stated that,
although the reference to ‘‘another
Federal income tax credit’’ follows a
specific reference to specific sections of
the Code, the general reference is
ambiguous and may inadvertently
preclude claiming the section 45Y or
48E credits when a taxpayer claims a
non-energy credit such as the credit for
increasing research activities under
section 41 of the Code or the advanced
manufacturing production credit under
section 45X of the Code.
A commenter requested modifying
§ 1.45Y–2(c)(1) to permit a taxpayer to
claim the section 45Y credit with
respect to a qualified facility that is colocated with another facility for which
a credit determined under section 45V
or 45Z of the Code is allowed. Another
commenter requested that the final
regulations clarify that the carbon
capture portion of a bioenergy and
carbon sequestration facility is a section
45Q facility separate from the electricity
generating portion of a qualified facility
under section 45Y.
A commenter asked whether the
‘‘anti-abuse provision’’ in the section
45V proposed regulations would bar a
taxpayer from claiming the section 45V
credit in addition to either the section
45Y or 48E credits. Similarly,
commenters requested clarifying
whether taxpayers claiming the section
48E credit in a taxable year would be
unable to claim the section 45Q credit
in any subsequent year. The
commenters asserted that section
48E(b)(3)(C) only specifically prohibits a
taxpayer from claiming a section 48E
credit for a facility for which a section
45Q credit was claimed ‘‘for the taxable
year or any prior taxable year,’’ but does

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not directly state that a taxpayer cannot
claim a section 45Q credit for that
facility in a future taxable year.
Some commenters requested that the
final regulations prevent taxpayers from
claiming multiple Federal or State tax
incentives based on the same
investment in or for the production of
clean energy. By contrast, another
commenter requested confirmation that
claiming the section 45Y and 48E
credits would not impact a taxpayer’s
ability to qualify for other subsidies,
grants, or loans from DOE’s Loans
Program Office.
In accordance with the statutory
language under section 45Y(b)(1)(D), the
Treasury Department and the IRS
confirm that the phrases ‘‘another
Federal income tax credit’’ and ‘‘other
Federal income tax credit’’ in proposed
§ 1.45Y–2(c)(1) refer solely to the credits
claimed under sections 45, 45J, 45Q,
45U, 48, 48A, and 48E. Similarly, in
accordance with section 48E(b)(3)(C),
the phrases ‘‘another Federal income tax
credit’’ and ‘‘other Federal income tax
credit’’ in proposed § 1.48E–2(c)(1) refer
solely to those credits claimed under
sections 45, 45J, 45Q, 45U, 45Y, 48, and
48A. Moreover, the provisions under
sections 45Y(b)(1)(D) and 48E(b)(3)(C)
do not impact the ability of a taxpayer
to claim a credit for a qualified facility
that is co-located with a facility for
which a credit under any Code section
is claimed. In general, a taxpayer may
claim a section 45Y or 48E credit for a
qualified facility that is co-located with
another facility, irrespective of any
credit that the co-located facility
claimed.
The determination of what constitutes
a qualified facility for purposes of
section 45Q is addressed in regulations
under section 45Q and thus is beyond
the scope of these final regulations.
However, as described earlier, a
taxpayer may not claim the section 45Y
credit and the section 45Q (or sections
45, 45J, 45U, 48, 48A, and 48E) credit
with respect to the same qualified
facility for the taxable year or any prior
taxable year. Nor may a taxpayer claim
the section 48E credit and the section
45Q (or sections 45, 45J, 45U, 45Y, 48,
and 48A) credit with respect to the same
qualified facility for the taxable year or
any prior taxable year. An examination
of the whether the regulations under
section 45Q prohibit a taxpayer from
claiming the section 45Q credit with
respect to a qualified facility for which
the taxpayer has claimed a section 45Y
or section 48E credit in any prior
taxable year is beyond the scope of these
final regulations. Finally, an
examination of the application of the
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proposed regulations, or an analysis of
Federal or State tax incentives,
including subsidies, grants, or loans
from DOE’s Loans Program Office, are
also beyond the scope of these final
regulations. The final regulations add
examples to §§ 1.45Y–2(c)(3) and 1.48E–
2(f)(3) to further illustrate the
interaction of sections 45Y and 48E with
other Federal income tax credits.
E. Integral Part
Proposed § 1.45Y–2(b)(3)(i) provided
that for purposes of the section 45Y
credit, a component of property owned
by a taxpayer is an integral part of a
qualified facility if it is used directly in
the intended function of the qualified
facility and is essential to the
completeness of such function. Property
that is an integral part of a qualified
facility is part of the qualified facility.
Proposed § 1.45Y–2(b)(3)(ii) through (v)
applied this rule to different types of
property.
Proposed § 1.48E–2(b)(3)(i) similarly
provided that for purposes of the section
48E credit, a component of property
owned by a taxpayer is an integral part
of a qualified facility if it is used
directly in the intended function of the
qualified facility and is essential to the
completeness of the intended function.
Property that is an integral part of a
qualified facility is part of the qualified
facility. A taxpayer may not claim the
section 48E credit for any property that
is an integral part of a qualified facility
that is not owned by the taxpayer.
Proposed § 1.48E–2(b)(3)(ii) through (v)
applied this rule to different types of
property.
Proposed § 1.48E–2(g)(3) provided
that for purposes of the section 48E
credit, property owned by a taxpayer is
an integral part of EST owned by the
same taxpayer if it is used directly in
the intended function of the EST and is
essential to the completeness of such
function. Property that is an integral
part of an EST is part of an EST. A
taxpayer may not claim the section 48E
credit for any property that is an integral
part of an EST that is not owned by the
taxpayer.
A commenter supported the facilityby-facility approach that section 48E
uses and sought confirmation that
taxpayers can determine section 48E
credits on this basis, rather than under
the ‘‘energy project’’ definition used in
section 48 by which multiple energy
properties would be treated as one
energy project if, at any point during
their construction, they are owned by a
single taxpayer and meet two or more of
seven factors set forth the in section 48
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Section 48 was amended by the IRA
to, among other things, provide a
definition of the term ‘‘energy project’’
and provide increased credit amounts
for energy property if that property is
part of an energy project that satisfies
specified conditions. While sections
45Y and 48E provide for similar
increased credit amounts, the sections
45Y and 48E apply the increased credit
amounts at the level of a qualified
facility rather than an energy project. As
a result, taxpayers can only determine
section 48E credits on the facility-byfacility approach described in the
statute and the proposed regulations.
Commenters requested expanding the
scope of power conditioning equipment
that is considered an integral part of a
qualified facility to include software
that optimizes or automates the function
of power conditioning equipment.
Commenters also requested that the
final regulations clarify that software
performing similar functions to other
integral parts of the qualified facility,
such as energy management systems,
battery management systems, data
acquisition systems, and optimization
software, are all considered ‘‘power
conditioning equipment.’’
Section 48E(b)(2) defines qualified
property, in part, as property that is
tangible personal property, or other
tangible property (not including a
building or its structural components),
but only if such property is used as an
integral part of the qualified facility.
Software is not tangible property and
therefore cannot be integral property
included in the qualified investment of
a section 48E qualified facility. Because
the statutory definition limits ‘‘qualified
property’’ to tangible property, the final
regulations modify the language in
proposed § 1.48E–2(b)(3)(ii) to remove
any reference to software. The same
language regarding software that was
included in proposed § 1.48E–2(b)(3)(ii)
was also included in proposed § 1.45Y–
2(b)(3)(ii). The Treasury Department and
the IRS note that, while the inclusion or
exclusion of software does not impact
the calculation of the section 45Y credit,
in order to provide uniform definitions
that are consistent with the statutory
structure governing both credits, the
final regulations also remove the
references to software in § 1.45Y–
2(b)(3)(ii).
Commenters requested retaining the
treatment of offshore wind power
conditioning and transfer equipment as
an integral part of an offshore wind
facility if it is owned by the same
taxpayer that owns the unit of qualified
facility. In addition, commenters stated
that the examples in proposed § 1.48E–
2(b)(3)(ii) were useful in illustrating the

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project components that are integral
parts of an offshore wind facility.
Commenters stated that full eligibility is
critically important, as power
conditioning and transfer equipment
represents a significant portion (up to 40
percent) of the total cost of an offshore
wind facility. The final regulations
adopt the proposed rule without change.
A commenter expressed concern that
special-purpose buildings or buildinglike structures that have long been
considered integral property under
section 48 may be inadvertently
excluded under the section 48E final
regulations. For example, the
commenter noted that the IRS
previously issued revenue rulings (Rev.
Rul. 72–223, 1972–1 C.B. 17; Rev. Rul.
72–96, 1972–1 C.B. 67; Rev. Rul. 84–40,
1984–12 I.R.B. 4) holding that specialpurpose property such as hydroelectric
power plant structures, reservoirs to be
used with steam turbine generating
plants, and dams were eligible for the
section 48 credit as other tangible
property rather than being considered
buildings or their structural
components. The commenter noted that
in only one of the revenue rulings was
the property not considered a building
based on the idea that replacement of
the turbine and support have to be
undertaken at the same time. Similarly,
commenters requested verification that
the definition of integral property
includes canopies for solar carports,
racking structures specific to
commercial and industrial solar
projects, rooftop specialized battery
housing structures, enclosures for
densely populated urban environments,
and similar components. In contrast, a
commenter recommended clarifying
that containers for utility-scale battery
energy storage systems, inverter
housing, and transformer housing are
specifically considered buildings or
equivalents.
As an alternative, some commenters
suggested modifying the rule for
buildings to generally include structures
but exclude buildings of particular
concern to the IRS (for example,
housing or offices for maintenance
equipment or regular operations staff). A
commenter requested that, similar to
proposed § 1.48E–2(b)(3)(v), the final
regulations include a permanent
building or structure as an integral part
of an EST to the extent it can be
demonstrated that (i) the construction of
such building or structure would not
have occurred but for placing the EST
in service and (ii) the design and cost of
such structure is consistent with the
requirements of the EST. According to
the commenter, such a rule would treat
the portion of the building or structure

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used to house the EST as an integral
part of the EST, whether or not
permanent in nature. The commenter
noted that in harsh environments, the
taxpayer must construct a permanent
structure for housing the EST and the
applicable HVAC equipment needed to
regulate the temperature of the structure
so that the EST will function properly.
The commenter also explicitly
requested that HVAC equipment needed
to regulate the temperature of the
structure so that the EST will function
properly be considered an integral part
of the EST. Another commenter
requested modifying proposed § 1.48E–
2(b)(3)(v) to allow for structures or
buildings integral to the intended
function of the qualified facility if such
building or structure is required to
comply with or maintain required
health and safety conditions required by
the qualified facility’s regulator.
Another commenter requested
confirmation that devices used to
manage load served by EST, such as
critical loads panels or load controllers,
are integral parts of EST. The
commenter noted that backup batteries
need load management devices to
function correctly during grid failures or
for off-grid power.
The definition of qualified property in
section 48E(b)(2)(A)(ii) includes tangible
property that is used as an integral part
of a qualified facility, but explicitly
excludes buildings or their structural
components. Proposed § 1.48E–
2(b)(3)(v) provides that while buildings
are generally not integral parts of a
qualified facility because they are not
integral to the intended function of the
qualified facility (to generate
electricity), the following structures are
not treated as buildings for this purpose:
(A) a structure that is essentially an item
of machinery or equipment; and (B) a
structure that houses components of
property that is integral to the intended
function of the qualified facility if the
use of the structure is so closely related
to the use of the housed components of
property therein that the structure
clearly can be expected to be replaced
if the components of property it initially
houses are replaced.
Although the proposed regulations do
not list particular buildings that may
qualify as an integral part of a qualified
facility, the Treasury Department and
the IRS have concluded that the
guidance and examples included are
adequate to illustrate the intended
application of the rules. The revenue
rulings raised by a commenter with
respect to special-purpose buildings or
building-like structures involved
specific situations arising under section
48. A definitive response regarding the

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situations in the revenue rulings or
other specific situations described by
the previous comments would require
the Treasury Department and the IRS to
conduct a complete factual analysis of
the property in question, which may
include information beyond that which
was provided by the commenters.
Because more information is needed to
make the determinations requested by
the commenters, the requested
clarifications are not addressed in these
final regulations.
In the case of hydropower facilities, a
commenter stated that it is critical that
final regulations confirm that costs
incurred for new property with respect
to a hydropower facility qualify for the
section 48E credit even though certain
portions of a hydropower project may be
owned by Federal agencies. This
commenter explained that in some
cases, the U.S. Army Corps of Engineers
may own all or a portion of the dam and
associated property but asserted that
this circumstance should not affect the
credit eligibility of other qualified
property (the electric-generating assets)
within the qualified facility owned by
the taxpayer.
While a taxpayer may not claim the
section 48E credit for any property that
is not owned by the taxpayer even if it
is an integral part of a qualified facility,
the inverse is not true. A taxpayer is not
required to own all the other tangible
property that is an integral part of a
qualified facility to claim a credit for the
qualified facility. In the case of a
hydropower facility, the qualified
facility consists of a unit of qualified
facility including water intake, water
isolation mechanisms, turbine, pump,
motor, and generator. The associated
impoundment (dam) and power
conditioning equipment are integral
property to the unit of qualified facility.
Therefore, in response to the
commenter’s example, the final
regulations incorporate a new example
in §§ 1.45Y–2 and 1.48E–3 illustrating
that property such as a dam being
owned by a Federal agency would not
prevent a taxpayer that owns the
hydropower facility from qualifying for
a section 45Y or 48E credit.
F. Shared Integral Property
Proposed § 1.45Y–2(b)(3)(vi) provided
that multiple qualified facilities
(whether owned directly by one or more
taxpayers), including qualified facilities
with respect to which a taxpayer has
claimed a credit under section 48E or
another Federal income tax credit, may
include shared property that can be
considered an integral part of each
qualified facility. A component of
property that is shared by a qualified

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facility as defined in section 45Y(b)
(45Y Qualified Facility) and a qualified
facility as defined in section 48E(b)(3)
(48E Qualified Facility) that is an
integral part of both qualified facilities
will not affect the eligibility of the 45Y
Qualified Facility for the section 45Y
credit or the 48E Qualified Facility for
the section 48E credit. Proposed
§ 1.45Y–2(b)(3)(vii) provides examples
illustrating proposed § 1.45Y–2(b)(3).
Proposed § 1.48E–2(b)(3)(vi) provided
that multiple qualified facilities
(whether owned by one or more
taxpayers), including qualified facilities
with respect to which a taxpayer has
claimed a credit under section 48E or
another Federal income tax credit, may
include shared property that may be
considered an integral part of each
qualified facility so long as the cost
basis for the shared property is properly
allocated to each qualified facility and
the taxpayer only claims a section 48E
credit with respect to the portion of the
cost basis properly allocable to a
qualified facility for which the taxpayer
is claiming a section 48E credit. The
total cost basis of such shared property
divided among qualified facilities may
not exceed 100 percent of the cost of
such shared property. Property that is
shared by a 48E Qualified Facility and
a 45Y Qualified Facility that is an
integral part of both qualified facilities
will not affect the eligibility of the 48E
Qualified Facility to claim the section
48E credit or the 45Y Qualified Facility
to claim the section 45Y credit. To
better illustrate the treatment of shared
integral property, these final regulations
add an additional example to § 1.48E–
4(d)(5) regarding related taxpayers.
A commenter expressed confusion
with what is meant by ‘‘another facility’’
in proposed § 1.45Y–2(c)(1), in the
context of defining a qualified facility
co-located with another facility.
Additionally, as explained in section
IV.B. of this Summary of Comments and
Explanation of Revisions, each Code
section has its own unique definition of
a facility that must be considered.
Proposed § 1.45Y–2(c)(3) (Examples 1
and 2) involve fact patterns addressing
the ability of one or more taxpayers to
claim a section 45Y credit for a solar
farm and a section 48E credit for a colocated EST. The Treasury Department
and the IRS view these examples as
adequately addressing this comment.
G. Ownership
1. Qualified Facility
Proposed § 1.48E–4(d) provided rules
related to the ownership of a qualified
facility or EST. In addition to the
ownership rules in proposed § 1.48E–

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4(d), proposed § 1.48E–2(b)(3)(i)
provided a taxpayer may not claim the
section 48E credit for any property that
is an integral part of the taxpayer’s
qualified facility that is not owned by
the taxpayer.
Some commenters opposed the
proposed rule that only the taxpayer
that owns a unit of qualified facility is
eligible for a section 48E credit with
respect to property that is an integral
part of that qualified facility. These
commenters asserted that property that
is treated as an integral part of a
qualified facility should be eligible for
the section 48E credit regardless of
whether the taxpayer also owns any
interest in the unit of qualified facility.
As an example, one commenter
described a qualified facility in which
generation assets and transfer
equipment are constructed together but
owned by separate taxpayers and
suggested that both taxpayers should be
able to claim a section 48E credit on the
basis of their respectively owned
portions. This commenter similarly
suggested that if a unit of qualified
facility is constructed and placed in
service by a taxpayer, and another
taxpayer later constructs and places in
service an integral part of such qualified
facility, both taxpayers should be able to
claim section 48E credits on their
respective property.
A commenter opposed to the
ownership requirement suggested that,
under their reading of the proposed
regulations and the existing section 48
regulations, different components
treated as ‘‘integral parts’’ would still be
energy property and, thus, should still
qualify for the section 48E credit when
separately owned. According to this
commenter, under section 48 taxpayers
have the flexibility to own and claim
credit for separate ‘‘integral parts.’’ The
commenter stated that this flexibility in
ownership is essential for many projects
because it may be impractical (if not
impossible) for one taxpayer to own all
components of a larger system. The
commenter stated that the limitation in
the proposed regulations that a taxpayer
may not claim the section 48E credit for
any property that is an integral part of
a qualified facility that is not owned by
the taxpayer is not found in the
statutory text and could have an
unnecessary chilling effect on
investment.
Raised in the context of offshore
wind, commenters requested that the
final regulations eliminate the
requirement that the generating facility
and the integral power conditioning and
transfer equipment be owned by the
same taxpayer. In the commenters’
view, this would allow owners of

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offshore wind power conditioning and
transfer equipment that do not own an
interest in the offshore turbines to claim
the section 48E credit. A commenter
stated that the ownership rules, as
proposed, would result in the buildout
of more equipment and cables at a
greater total expense, be more disruptive
of the environment, and cause more
interference with coastal communities,
while at the same time failing to achieve
the desired resiliency, reliability,
flexibility, and ability to plan for future
expansion of offshore wind. A comment
submitted jointly by seven states
requested that the Treasury Department
and the IRS reconsider the rule to
require that the owner of integral power
conditioning and transfer equipment to
also own the offshore wind facility to
claim the section 48E credit. This
comment expressed similar concerns
regarding potential impacts of the
ownership rules.
A commenter proposed that the
Treasury Department and the IRS revise
the proposed rule to allow owners of
integral property that do not own an
interest in the associated unit of
qualified facility to claim a section 48E
credit if the integral property is used in
the trade or business of furnishing or
selling electrical energy and if a
regulatory authority determines that
ownership of integral property separate
from ownership of the underlying unit
of qualified facility is in the public
interest.
The Treasury Department and the IRS
have determined that the ownership
rules provided in the proposed
regulations are appropriate. Although
commenters asserted that property that
is treated as an integral part of a
qualified facility should be eligible for
the credit regardless whether the
taxpayer also owns any interest in the
unit of qualified facility (as defined in
proposed § 1.48E–2(b)(2)), such an
approach would conflict with the
statutory requirement that a credit only
be available for a qualified facility, that
is, a facility that generates electricity
and for which the anticipated GHG
emissions rate is not greater than zero.
Integral property alone does not
constitute a qualified facility. Adopting
the commenters’ recommendation that a
taxpayer be able claim the section 48E
credit for integral property alone would
conflict with the application of several
other provisions in the statute that
apply to an entire qualified facility
rather than individual components of
property (including the PWA
requirements, certain bonus credit
amounts, and certain rules applicable to
lower-output qualified facilities to

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include expenditures for qualified
interconnection property).
The Treasury Department and the IRS
conclude that no section 48E credit may
be determined with respect to a
taxpayer’s ownership of integral
property which is a separate component
of a qualified facility (or EST) if the
same taxpayer does not own the
components that constitute a unit of
qualified facility (as defined in
proposed § 1.48E–2(b)(2)) or unit of EST
(as defined in proposed § 1.48E–2(g)(2)).
Additionally, based on similar
considerations, the Treasury
Department and the IRS maintain that
no section 48E credit may be allowed
unless a taxpayer directly owns at least
a fractional interest in the entire unit of
qualified facility or unit of EST. Thus,
in the case of an offshore wind farm, a
taxpayer directly owning power
conditioning and transfer equipment
would only be able to claim a section
48E credit on that equipment if the same
taxpayer also directly owned a
fractional interest in at least one
qualified facility (wind turbine, tower,
and pad) for which such power
conditioning and transfer equipment in
is integral property.
In response to the comment that
retaining the common ownership
requirement will result in the buildout
of more equipment and cables at a
greater total expense, more disruption of
the environment, and more interference
with coastal communities, the Treasury
Department and the IRS acknowledge
the commenters’ concerns. However, as
explained later, retaining the rule is
necessary based on legal and
administrability concerns.
Section 48E provides an investment
credit equal to a specified percentage of
the taxpayer’s qualified investment with
respect to a qualified facility or EST.
Section 48E(b)(1) defines a qualified
investment with respect to a qualified
facility as the sum of ‘‘the basis of any
qualified property placed in service by
the taxpayer during such taxable year
which is part of a qualified facility, plus
the amount of any expenditures which
are paid or incurred by the taxpayer for
qualified interconnection property . . .’’
Section 48E(b)(2) provides, in part, that
the term qualified property means
property which is tangible personal
property or other tangible property (not
including a building or its structural
components) but only if such property
is used as an integral part of the
qualified facility.
While the language in section
48E(b)(1) and 48E(b)(2), on its own,
could be read to suggest that a taxpayer
may claim a section 48E credit with
respect to any property that does not

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constitute a unit of qualified facility,
section 48E must be read holistically to
give effect to its provisions. The statute
provides a credit with respect to a
qualified facility, which is a facility that
generates electricity and that has a GHG
emissions rate not greater than zero.
Only once it has been determined that
a facility is a qualified facility that is
eligible for a section 48E credit may the
amount on which the credit will be
calculated—the qualified investment in
that qualified facility—be determined
under section 48E(b)(1) and (2). Section
48E(b)(1) identifies what items comprise
that qualified investment—the basis of
any qualified property that is part of the
qualified facility plus certain qualified
interconnection costs. Section 48E(b)(2)
specifies what types of property are
considered qualified property—tangible
personal property or, only if used as an
integral part of the qualified facility,
other tangible property (not including a
building or its structural components).
The term ‘‘integral part’’ specifically
modifies the term ‘‘other tangible
property.’’ It serves to include or
exclude items like fencing that are not
directly related to the function of the
qualified facility. The statutory language
thus provides that any property that
does not meet the definition of
‘‘qualified property,’’ or any property
that is not part of the qualified facility,
is not part of the qualified investment.
Once the qualified investment has
been determined, the credit rate by
which that qualified investment will be
multiplied to calculate the credit
amount must be determined. The credit
rate is the applicable percentage under
section 48E(a)(2)(A), which is either 6
percent or 30 percent depending on
whether the qualified facility satisfies
any of the three tests for the alternative
rate set forth in section 48E(2)(A)(ii).
The requirements of section 48E apply
to the qualified facility (rather than
components of property comprising
such qualified facility): a qualified
facility is a facility that generates
electricity and that has a GHG emissions
rate not greater than zero; the applicable
percentage depends on whether the
qualified facility meets the various
requirements for PWA, or the domestic
content and energy communities bonus
credit amounts. Within this statutory
structure, section 48E(a)(1)(A) and
(2)(A) operate to identify what is
included and what is excluded from the
credit base. Accordingly, the statute
requires ownership of a qualified
facility rather than mere components of
property.
Section 48E provides a credit for an
investment in a qualified facility that
satisfies the definition of ‘‘qualified

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facility’’ provided at section 48E(b)(3).
The statute defines a ‘‘qualified
facility’’, in part, by requiring that the
facility be used for the generation of
electricity and that the anticipated GHG
emissions rate is not greater than zero.
The Treasury Department and the IRS
view the concepts of qualified
investment and qualified property as
inextricably tied to the statutory
definition of a qualified facility. As
discussed throughout this Summary of
Comments and Explanation of
Revisions, the section 48E credit is
available for a qualified facility that
generates electricity for which the
anticipated GHG emissions rate is not
greater than zero. Electricity can only be
generated by, and GHG emissions can
only be determined with respect to, a
unit of qualified facility. Integral
property, by itself, does not satisfy this
statutory definition because integral
property is not property used for the
generation of electricity, nor can the
GHG emissions of a qualified facility be
determined solely on the basis of
integral property.
Furthermore, a taxpayer who owns
only property that is an integral part of
a qualified facility may not be able to
establish the anticipated GHG emissions
rate for the entire qualified facility. For
the determination of the anticipated
GHG emissions rate of a qualified
facility, section 48E mandates rules
similar to those in section
45Y(b)(2)(C)(ii), which requires that
‘‘[i]n the case of any facility for which
an emissions rate has not been
established by the Secretary, a taxpayer
which owns such facility may file a
petition with the Secretary for
determination of the emissions rate with
respect to such facility’’ (emphasis
added). The statute does not appear to
permit a taxpayer who does not own a
unit of qualified facility, but instead
only owns property that is integral to a
unit of qualified facility, to petition for
a determination of the emissions rate.
This further bolsters the conclusion that
ownership interest in a qualified
facility, not in mere integral part, is
required for the credit to operate.
Several other key provisions of
section 48E are only applicable to a
qualified facility: the placed in service
date; the applicable percentage;
application of the PWA requirements,
eligibility for the domestic content and
energy communities bonus credit
amounts; and inclusion of qualified
interconnection expenditures for loweroutput qualified facilities. These
provisions apply at the level of a
qualified facility, not to components of
property within such qualified facility
or components of property that are an

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integral part of such qualified facility.
For example, the owner of a component
of property within a qualified facility
cannot claim a domestic content bonus
credit amount if another owner of
components of property included
within the unit of qualified facility does
not satisfy the domestic content
requirements with respect to its
components. The determination
requires an analysis of the entire
qualified facility.
Unless a taxpayer directly owns at
least a fractional interest in the entire
unit of qualified facility, the taxpayer
cannot effectively claim the section 48E
credit or the bonus or increase credit
amounts. The availability of the section
48E credit for the taxpayer who owns
only integral property would depend on
whether another taxpayer’s qualified
facility meets the GHG emission
requirements. The availability of any
bonus or increased credit amounts for
the taxpayer who owns only integral
property would also depend on whether
other taxpayers who invested in the
qualified facility satisfy all the adder
requirements. Similarly, in cases in
which one taxpayer’s tangible property
ceases to be eligible for the credit,
recapture under sections 48E(g) and
50(a) would implicate all other
taxpayers who invest in the qualified
facility. All these cases further support
the conclusion that the statutory scheme
applies at the level of a qualified
facility, and that the owner of only
integral property cannot effectively
claim the credit or the bonus or
increased credit amounts.
Finally, taxpayers would need access
to information about all other property
that is part of the qualified facility to
properly determine whether the
taxpayer’s specific investment in
integral property is eligible for a section
48E credit and to determine the amount
of that credit. This would impose a high
burden of information sharing on the
taxpayers and increase uncertainty, as
one taxpayer’s choices would impact
another taxpayer’s eligibility for the
credit and bonus or increased credit
amounts. It would also create
corresponding administrative problems
for the IRS to effectively analyze and, if
necessary, adjust multi-party credit
claims.
Some commenters pointed to Internal
Revenue Bulletin guidance, caselaw,
and other guidance to support their
position that a taxpayer that owns
property that is an integral part of a
qualified facility should not be required
to also own the qualified facility to be
eligible for a section 48E credit.
Commenters cited Rev. Rul. 78–268,
1978–2 C.B. 10, PLR 201536017, PLR

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201208035, and FAQ 35 of guidance
from the Treasury Department regarding
payments under section 1603 of the
American Recovery and Reinvestment
Act of 2009 3 (Section 1603 Grant
Program) to support the premise that
ownership of an entire qualified facility
is not required to be eligible to claim a
section 48E credit.
The commenters’ reliance on Revenue
Ruling 78–268, which addressed a prior
version of the section 48 credit, is
misplaced. In Revenue Ruling 78–268,
four parties, two of which were taxexempt, owned an electric generating
facility through a tenancy in common.
In other words, each taxpayer owned a
fractional interest in the entire energy
property. Revenue Ruling 78–268 held
that the presence of the tax-exempt
owners did not disqualify the other
owners from claiming a section 48
credit because the fractional interests in
the tenancy in common were treated as
separate assets. Because the fractional
ownership arrangement in Revenue
Ruling 78–268 is consistent with the
fractional ownership rule in proposed
§ 1.48E–4(d)(2), the Treasury
Department and the IRS disagree with
commenters that the holding of Revenue
Ruling 78–268 supports their position.
Commenters’ reliance on PLR
201536017 is also misplaced. Private
letter rulings (PLR) are not precedential
and cannot be relied upon by a taxpayer
other than the one addressed in the
letter (see section 6110(k)(3) of the
Code). Furthermore, this PLR involved
the section 25D credit, which, in
relevant part, provides a credit for
‘‘qualified solar electric property
expenditures,’’ rather than the section
48E credit. Regardless, like Revenue
Ruling 78–268, the PLR involves credit
eligibility through fractional ownership
of an entire energy property, not
ownership of just certain components.
The PLR addresses a factual scenario in
which a taxpayer purchased solar PV
panels in an offsite array (that also
contains other solar PV panels owned
by other individuals) as well as a partial
ownership in racking equipment,
inverter equipment, and wiring and
other equipment and installation
services required for the integration of
the panels in the array and the
interconnection of the array to a local
utility’s electric distribution system.
The PLR concludes that the taxpayer
made a ‘‘qualified solar electric property
expenditure’’ under section 25D(d)(2)
and is eligible to claim a section 25D
3 Payment for Specified Energy Property in Lieu
of Tax Credits Under the American Recovery and
Reinvestment Act of 2009, Frequently Asked
Questions and Answers.

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4035

credit. To the extent this PLR provides
any helpful analysis to a section 48E
credit, it involves partial ownership in
all the equipment necessary to integrate
the solar PV panels into the array and
interconnect the array to a local utility’s
electric distribution system. It does not
apply the section 25D credit to just
certain components of property. Like
Revenue Ruling 78–268, the PLR
involves credit eligibility through
fractional ownership of a unit of
property analogous to a qualified facility
under section 48E rather than
ownership of mere components of
property.
Similarly, commenters’ reliance on
PLR 201208035 for the proposition that
taxpayers should be permitted to claim
the section 48E credit on any portion of
eligible property owned by such
taxpayer is inapposite. The factual
scenario in that PLR involved a taxpayer
seeking to add energy storage property
to an existing wind facility for which
section 48 credits had been claimed
with respect to certain phases of the
facility and a Section 1603 Grant
Program payment had been received
with respect to another phase of the
facility. Because the same taxpayer
owned the existing wind facility and the
later added energy storage property
(which was treated as property integral
to the wind facility under the relevant
version of section 48), the cited PLR
does not establish that a taxpayer who
has no ownership of a unit of a qualified
facility is entitled to the section 48E
credit for ownership of integral parts
only.
Finally, commenters also relied on
FAQ 35 of the Section 1603 Grant
Program guidance to support their
contention that ownership of an entire
qualified facility is not required to claim
the section 48E credit. Under the
Section 1603 Grant Program, the
Treasury Department made payments in
lieu of section 45 and 48 credits to
eligible applicants for specified energy
property. FAQ 35 addressed the
procedural requirements of the Section
1603 Grant Program in a situation in
which an open-loop biomass facility
was owned by one party that uses offsite feedstock conversion equipment
owned by another party. FAQ 35
provided that the party that owns the
conversion equipment and the party
that owns the open-loop biomass facility
must each submit an application in
order to receive Section 1603 Grant
Program payments. While the Section
1603 Grant Program guidance borrowed
important concepts from the section 45
and 48 credits, it is not based on any
specific income tax provisions and is

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not precedential for purposes of the
section 48E credit.
Moreover, FAQ 35 required the
multiple parties that owned the
different components of property to join
in each separate application for the
Section 1603 Grant Program payment
and agree to the terms and conditions.
The Treasury Department would then
review those applications together and
make any determination regarding
eligibility for a Section 1603 Grant
Program payment for the entire facility
based on information provided with
respect to the entire facility rather than
each party’s respective components.
This is very different from the
commenters’ requests to allow taxpayers
to claim and substantiate separate
section 48E credits claimed by separate
taxpayers on Federal income tax
returns. This type of tax filing has
significantly fewer guardrails than
Treasury’s advance review of Section
1603 Grant Program applications. And,
as discussed earlier, the statute requires
ownership of a qualified facility, rather
than ownership of mere components of
property to claim the credit.
Other commenters cited Cooper v.
Comm’r, 88 T.C. 84 (1987), to support
allowing a taxpayer to claim a section
48E credit with respect to components
of property they own that are an integral
part of a qualified facility owned by a
different taxpayer. Cooper, which was
decided under prior versions of sections
46 and 48 and the regulations
thereunder, does not directly support
the commenters’ contention. In Cooper,
the taxpayer asserted that owning
specific components of solar water
heating system was sufficient to claim
the section 48 credit for solar energy
property. Acknowledging that the
taxpayer did not own the entire working
solar water heating system, the Tax
Court held that the definition of a solar
energy property provided by the
regulations under former section 48(l)(4)
were sufficiently broad to provide a
credit for component parts of a solar
water heating system. In a subsequent
case, the Tax Court distinguished
Cooper, explaining that ‘‘the property in
Cooper consisted of integrated waterheating systems that were ready for
installation to discharge their
designated function.’’ Olsen v.
Commissioner, T.C. Memo 2021–41,
*14, aff’d, 52 F.4th 1039 (10th Cir.,
2022). Conversely, in the Olsen case, the
taxpayer owned certain solar lenses that
the Tax Court described as ‘‘mere
components of a system’’ that were
‘‘intended to operate as part of a
complicated solar energy system and
were incapable of performing any useful
function in isolation.’’ Id. at 13–14. The

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Tax Court held that the solar lenses
‘‘were not ‘placed in service’ because
the solar energy system as a whole was
not ‘in a condition or state of readiness
and availability for a specifically
assigned function.’’’ Id. at 13. Thus, the
taxpayer was not entitled to claim a
section 48 credit.
Finally, the IRS has no authority to
compel taxpayers to coordinate tax
credit claims or share tax return
information with other taxpayers.
Accordingly, the rules as provided in
proposed §§ 1.48E–4(d) and 1.48E–
2(b)(3)(i) that require a taxpayer to
directly own at least a fractional interest
in the entire unit of qualified facility or
unit of EST and that deny a credit for
owners of integral property alone are
adopted and moved to § 1.48E–1(c) of
the final regulations.
However, while the final regulations
maintain the overall structure of the
proposed ownership rules, after further
consideration, the Treasury Department
and the IRS have determined that
certain modifications to proposed
§ 1.48E–2 are required to more closely
reflect the statutory language. The final
regulations adopt those modifications.
2. Ownership of EST
A commenter requested clarification
that the section 48E credit can be
claimed with respect to an EST that is
co-located and used in conjunction with
a qualified facility for which the section
45 or 45Y credit is claimed even if the
EST could be considered a functionally
interdependent or an integral part of
that qualified facility and whether the
EST and the facility may be owned by
different taxpayers. Proposed § 1.48E–
2(g)(3) provides that a taxpayer may not
claim the section 48E credit for any
property that is an integral part of an
EST that is not owned by the taxpayer.
Commenters expressed concern that this
rule prohibits the owner of an EST from
claiming a section 48E credit if that EST
is an integral part of a qualified facility
that is owned by another taxpayer.
This commenter’s concerns are
misplaced. Section 48E(a) describes the
clean electricity investment credit
generally as determined separately with
respect to any qualified facility and any
EST. Accordingly, an EST cannot be
included in a unit of qualified facility
under either the integral part or
functional interdependence rules for
purposes of section 48E. Therefore, the
Treasury Department and the IRS
confirm that an EST is eligible for the
section 48E credit if it satisfies the
requirements of section 48E, even if the
EST is co-located with a qualified
facility that has claimed the section 45
or 45Y credits. Assuming all statutory

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and regulatory requirements are
satisfied, a qualified facility owned by
one taxpayer and an EST owned by
another taxpayer may each be eligible
for a separate section 48E credit. From
the perspective of credit eligibility, EST
is not an integral part of a qualified
facility.
H. Incremental Production Rule
Proposed § 1.45Y–4(c)(1) provided,
solely for purposes of proposed § 1.45Y–
4(c), that the term ‘‘qualified facility’’
includes either a new unit or an
addition of capacity placed in service
after December 31, 2024, in connection
with a facility described in section
45Y(b)(1)(A) (without regard to clause
(ii) of such paragraph), which was
placed in service before January 1, 2025,
but only to the extent of the increased
amount of electricity produced at the
facility by reason of such new unit or
addition of capacity. Proposed § 1.45Y–
4(c)(1) also provided that a new unit or
an addition of capacity will be treated
as a separate qualified facility. Proposed
§ 1.45Y–4(c)(1) provided, for purposes
of proposed § 1.45Y–4(c), that a new
unit or an addition of capacity requires
the addition or replacement of
components of property, including any
new or replacement integral property,
added to a facility necessary to increase
capacity. Proposed § 1.45Y–4(c)
provided that, if applicable, taxpayers
must use modified or amended facility
operating licenses or the International
Standard Organization (ISO) conditions
to measure the maximum electrical
generating output of a facility to
determine its nameplate capacity.
Additionally, proposed § 1.45Y–4(c)(1)
provided that for purposes of section
45Y(a)(2)(B)(i) (that is, the One
Megawatt Exception), the capacity for a
new unit or an addition of capacity is
the sum of the nameplate capacity of the
added qualified facility and the
nameplate capacity of the facility to
which the qualified facility was added.
Proposed § 1.45Y–4(c)(2) provided
that, solely for purposes of proposed
§ 1.45Y–4(c), a facility that is
decommissioned or in the process of
decommissioning and restarts can be
considered to have increased capacity if
certain conditions are met. Proposed
§ 1.45Y–4(c)(3) described how to
compute the increased amount of
electricity produced as a result of a new
unit or an addition of capacity.
Proposed § 1.45Y–4(c)(4) illustrated the
application of these rules to determine
the increased amount of electricity
attributable to a new unit or an addition
of capacity described in proposed
§ 1.45Y–4(c).

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Proposed § 1.48E–4(b)(1) provided,
solely for purposes of proposed § 1.48E–
4(b), that the term ‘‘qualified facility’’
includes either a new unit or an
addition of capacity placed in service
after December 31, 2024, in connection
with a facility described in section
48E(b)(3)(A) (without regard to clause
(ii) of such paragraph), which was
placed in service before January 1, 2025,
but only to the extent of the increased
amount of electricity produced at the
facility by reason of such new unit or
addition of capacity. A new unit or an
addition of capacity will be treated as a
separate qualified facility. For purposes
of proposed § 1.48E–4(b), a new unit or
an addition of capacity requires the
addition or replacement of qualified
property (as defined in proposed
§ 1.48E–2(e)), including any new or
replacement integral property added to
a facility necessary to increase capacity.
Proposed § 1.48E–4(b) provided that, if
applicable, taxpayers must use modified
or amended facility operating licenses
or ISO conditions to measure the
maximum electrical generating output
of a facility to determine its nameplate
capacity. Additionally, proposed
§ 1.48E–4(b)(1) provided that for
purposes of section 48E(a)(2)(A)(ii)(I)
(that is, the One Megawatt Exception),
the capacity for a new unit or an
addition of capacity is the sum of the
nameplate capacity of the added
qualified facility and the nameplate
capacity of the facility to which the
qualified facility was added.
Proposed § 1.48E–4(b)(2) provided
that, solely for purposes of proposed
§ 1.48E–4(b), a facility that is
decommissioned or in the process of
decommissioning and restarts can be
considered to have increased capacity if
certain conditions are met. Proposed
§ 1.48E–4(b)(3) described how to
compute the qualified investment for a
new unit or an addition of capacity.
Proposed § 1.48E–4(b)(4) illustrated the
application of the rules described in
proposed § 1.48E–4(b).
1. General Rules
A commenter noted that proposed
§§ 1.45Y–4(c)(1) and 1.48E–4(b)(3) both
reference ‘‘components of property,’’
whereas proposed § 1.48E–4(b)(1)
references ‘‘qualified property,’’ and
requested that the final regulations use
a consistent reference to property
included in the qualified facility. The
final regulations at § 1.48E–4(b)(4)
change the term ‘‘components of
property’’ in proposed § 1.48E–4(b)(3) to
‘‘components of qualified property’’ to
align with the requirement of section
48E(b)(1)(A) that the qualified
investment (as defined in proposed

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§ 1.48E–1(a)(6)) in a qualified facility is
the basis of any qualified property (as
defined in proposed § 1.48E–2(e))
placed in service by the taxpayer which
is part of a qualified facility. However,
the term ‘‘components of property’’ in
proposed § 1.45Y–4(c)(1) remains
unchanged in these final regulations,
because the term ‘‘qualified property’’ is
not used in section 45Y.
Several commenters recommended
permitting modifications to a facility to
qualify as an addition of capacity, and
specifically requested that the final
regulations define additions of capacity
as ‘‘modifications to the facility,
including any new or replacement
integral property added to a facility
necessary to increase the capacity of the
facility by replacing or modifying, in
whole or in part, the existing capacity
of the facility. . .’’ (emphasis added).
Several commenters also requested that
the final regulations clarify whether
such modifications could be to existing
components, physical or digital, or
whether existing components need to be
replaced or new components added.
Other commenters asked whether any
uprate, upgrade, or efficiency
improvement to an existing facility that
results in an incremental increase in the
electric-generating output based on the
actual productive capacity of the facility
would qualify as an addition of
capacity. A commenter noted that
sometimes components, including
software, are modified or adjusted to
increase electrical generating output.
Another commenter stated that the
example related to an addition of
capacity in proposed § 1.45Y–4(c)(4)(ii)
does not represent a typical fact pattern.
In response to these comments, the
Treasury Department and the IRS
confirm that the Incremental Production
Rule is based on the increased amount
of electricity produced at a facility as a
result of a new unit or an addition to
capacity. For purposes of the section
45Y credit, a new unit or an addition of
capacity requires an addition or
replacement of components of property,
including any new or replacement
integral property, added to a facility
necessary to increase capacity. For
purposes of the section 48E credit, a
new unit or addition of capacity
requires the addition or replacement of
qualified property (as defined in
§ 1.48E–2(e)), including any new or
replacement integral property, added to
the facility necessary to increase
capacity.
Several commenters asked whether
there is a minimum capital expenditure
necessary to qualify as a new unit or an
addition of capacity. Additionally, a
commenter suggested that the final

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regulations list the types of new units
that would be considered to increase the
amount of electricity produced. In
response to these comments, the
Treasury Department and the IRS note
there is no minimum capital
expenditure that would satisfy the
Incremental Production Rule for either a
new unit or an addition to capacity.
Additionally, to provide greater clarity
regarding what would qualify as a new
unit or an addition to capacity,
additional examples are included in
proposed §§ 1.45Y–4(c)(4) and 1.48E–
4(b)(4), and moved to §§ 1.45Y–4(c)(5)
and 1.48E–4(b)(5), respectively, in the
final regulations. These additional
examples illustrate the range and
diversity of types of investments that
can result in an addition of capacity.
Another commenter requested that
each stage of a multi-staged expansion
be eligible for the section 45Y credit
even if the larger, overall program for
improvement and expansion has not yet
been completed. A commenter
requested permitting multiple additions
of capacity or new units added to the
same facility over time to separately
qualify for the section 45Y credit. The
commenter noted that, in this case, a
taxpayer would measure the electricity
production attributable to each new
addition by reducing earlier additions’
proportionate share of total energy
production. Another commenter
recommended that taxpayers should be
permitted to aggregate all components
added to a facility and placed in service
in the same tax year as a single new unit
or addition of capacity.
In response to comments that
taxpayers should be able to aggregate all
components of property added to a
facility and placed in service in the
same tax year as a single new unit or
addition of capacity, the Treasury
Department and the IRS note that
proposed §§ 1.45Y–4(c)(1) and 1.48E–
4(b)(1) both provided, in part, that a
new unit or an addition of capacity that
meets the requirements of the
Incremental Production Rule will be
treated as a separate qualified facility. In
response to the commenters’ request
that a series of additions to capacity
should be eligible for the Incremental
Production Rule, the Treasury
Department and the IRS interpret
section 45Y(b)(1)(C) (and by reference,
section 48E(b)(3)(B)) to mean that if a
single facility includes multiple new
units or additions to capacity, the
taxpayer must apply the Incremental
Production Rule to each of the new
units or additions to capacity to
determine whether such property meets
the Incremental Production Rule.

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A commenter also suggested treating
new units as qualified facilities that are
distinct and separate from the existing
qualified facility to which they are
added and clarifying that all energy
produced by the new unit would qualify
for the section 45Y credit. In response
to this comment, the Treasury
Department and the IRS confirm that the
Incremental Production Rule is only
applicable to additions of capacity and
new units that would not otherwise
qualify as a separate qualified facility as
defined in section 45Y(b)(1)(A) (or by
reference section 48E(b)(3)) and
therefore clarify this in the final
regulations at § 1.45Y–4(c)(1) and
§ 1.48E–4(b)(1).
2. Application to Hydropower Facilities
Commenters noted that FERC
guidance has described ‘‘additions of
capacity’’ to mean any increase in
generating capacity other than an
addition resulting from an efficiency
improvement or an addition resulting
from an operational change.
Commenters noted that FERC has
provided guidance generally indicating
that efficiency improvements
encompass additional generation from
existing equipment in the form of
upgrades to generators or turbines.
Commenters also noted that FERC
guidance provides examples of
efficiency improvements that include
rewinding generators, replacing turbines
with more efficient units, and
computerizing control of turbines and
generators to optimize regulation of
flows for generation.
A commenter requested that the final
regulations define an ‘‘addition of
capacity’’ for purposes of a hydropower
facility and referenced a FERC
certification procedure required by
section 45(c)(8), which provides a
production tax credit for certain
incremental hydropower production.
While the commenter acknowledged
that section 45(c)(8) does not define the
term ‘‘additions of capacity,’’ the
commenter noted that FERC has
provided guidance related to
certification required under section
45(c)(8) in which FERC describes
‘‘additions of capacity’’ as ‘‘any increase
in generating capacity other than an
addition resulting from an efficiency
improvement or an addition resulting
from an operational change.’’
Commenters also requested that
efficiency improvements and upgrades
to a hydropower facility consisting of
refurbished or modified existing
components, but not the addition or
replacement of existing components,
may qualify as an addition of capacity.
Commenters specifically noted that

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upgrades to generators or turbines,
rewinding generators, replacing turbines
with more efficient units, and
computerizing control of turbines and
generators to optimize regulation of
flows for generation should be treated as
efficiency improvements and upgrades
that should qualify as additions of
capacity.
Similarly, another commenter noted
that the requirements for establishing
incremental hydropower are wellestablished and well-understood, and
provide precedent for modifications and
changes to a hydropower facility that
result in incremental hydropower
production. The commenter asserted
that the final regulations should take
those precedents into account in
establishing rules for determining an
increase in capacity for purposes of
sections 45Y and 48E.
The Treasury Department and the IRS
acknowledge that section 45(c)(8)
provides that incremental hydropower
production attributable to ‘‘efficiency
improvements’’ or ‘‘additions of
capacity’’ are eligible for the section 45
credit. However, section 45(c)(8) does
not define the terms ‘‘efficiency
improvements’’ nor ‘‘additions of
capacity.’’ While section 45(c)(8)(B)
allows for a determination of
incremental hydropower production at
an existing facility attributable to the
efficiency improvements or additions of
capacity, section 45Y(b)(1)(C) (and by
reference section 48E(b)(3)(B)(i))
provides a credit for a new unit or any
additions of capacity, but only to the
extent of the increased amount of
electricity production at the facility.
Notably, section 45Y(b)(1)(C) does not
provide for a credit for efficiency
improvements. As a result, the relevant
determination is whether a facility’s
electrical generation capacity increased
as a result of an addition or replacement
of components or property (including
any new or replacement integral
property) to a facility necessary to
increase capacity. Accordingly, these
final regulations do not adopt the
recommendation that any efficiency
improvement could meet the
requirements of the Incremental
Production Rule. However, efficiency
improvements that are an addition or
replacement of components of property
(including integral property) that result
in an addition to capacity could meet
the requirements of the Incremental
Production Rule.
The final regulations add an
additional example at §§ 1.45Y–4(c)(5)
and 1.48E–4(b)(5) to illustrate the
application of the Incremental
Production Rule to a hydropower
facility.

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3. Method of Measuring Increased
Amount of Electricity Produced at the
Facility by Reason of New Units or
Additions of Capacity
As noted earlier, the Incremental
Production Rule is based on the
increased amount of electricity
produced at a facility as a result of a
new unit or an addition to capacity. The
Incremental Production Rule is focused
on measuring the amount of the
capacity increase. In response to
commenters, the final regulations
permit the measurement of increased
capacity in several ways, including: (i)
modified or amended facility operating
licenses from the Federal Energy
Regulatory Commission (FERC) or the
Nuclear Regulatory Commission (NRC),
or related reports prepared by FERC or
NRC as part of the licensing process (as
described in section IV.H.4. of this
Summary of Comments and Explanation
of Revisions); (ii) the ISO conditions to
measure the nameplate capacity of the
facility consistent with the definition of
nameplate capacity provided in 40 CFR
96.202; or (iii) a measurement standard
prescribed by the Secretary in guidance
published in the Internal Revenue
Bulletin (see 26 CFR 601.601). The final
regulations also clarify that taxpayers
able to use the measurement standard
described in § 1.45Y–4(c)(2)(i) or
§ 1.48E–4(b)(2)(i) may not use the
method described in § 1.45Y–4(c)(2)(ii)
or § 1.48E–4(b)(2)(ii) (permitting use of
the ISO conditions to measure the
maximum electrical generating output
of a facility to determine its nameplate
capacity).
A commenter asserted that all energy
produced by a new unit should be
eligible for the section 45Y credit
regardless of the degree to which that
new unit and its electricity replaced
existing electricity production at that
facility. The Treasury Department and
the IRS disagree with this comment, as
the statute limits the application of the
Incremental Production Rule to the
increased amount of electricity
produced at the facility by reason of the
new unit or an addition of capacity.
As proposed, the Incremental
Production Rule provided that if
applicable, taxpayers must use modified
or amended facility operating licenses
or the ISO conditions to measure the
maximum electrical generating output
of a facility to determine its nameplate
capacity. Several commenters supported
the use of the ISO conditions to measure
the maximum electrical generating
output of a facility to determine
nameplate capacity. Additionally, a
commenter noted that the proposed
regulations properly focus on measuring

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the maximum generating output, rather
than measuring increases in annual
generation that do not impact the
maximum output.
Conversely, several commenters
expressed concern with the proposed
rule requiring the use of nameplate
capacity to measure the increased
amount of electricity produced at a
facility because section 45Y(b)(1)(C)
does not mention the term ‘‘nameplate
capacity’’ and only provides that the
credit is available to the extent of the
increased amount of electricity
produced at a facility without additional
elaboration. A commenter also raised
the importance of consistency when
referring to a facility’s ‘‘electrical
generating output,’’ ‘‘electrical
generating capacity,’’ ‘‘nameplate
capacity,’’ and ‘‘additions of capacity.’’
Several commenters contended that
using nameplate capacity would not be
an accurate way to measure additions of
capacity and emphasized that not every
addition of capacity results in a new
nameplate issued by the manufacturer.
Additional commenters noted that
manufacturer-stamped nameplate
capacity is, by design, the maximum
theoretical output of the facility and
differs from a facility’s actual electric
generating capacity. The ISO conditions
generally require that this measurement
be done by the manufacturer and would
normally occur when the facility is
originally placed in service. As a result,
several commenters noted that
measurement of nameplate capacity
using the ISO conditions would not take
into account physical depreciation,
degradation, and other factors that may
significantly reduce the maximum
generating output and safe operating
conditions of the facility over time
when compared to the facility’s original
nameplate capacity. The Treasury
Department and the IRS acknowledge
that using the ISO conditions to
determine nameplate capacity may limit
nameplate capacity to the nameplate
capacity of the facility on the original
placed in service date, or to a revised
nameplate capacity of the facility based
on major upgrades that would result in
a revised nameplate capacity rating.
Commenters noted that the proposed
regulations only define nameplate
capacity by adopting the definition at 40
CFR 96.202 in reference to the FiveMegawatt Limitation while noting that
the final regulations did not adopt the
same definition for the Incremental
Production Rule. In response, the
Treasury Department and the IRS have
modified the Incremental Production
Rule at §§ 1.45Y–4(c)(2)(ii) and 1.48E–
4(b)(2)(ii) to clarify that the definition of
nameplate capacity for the Incremental

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Production Rule is consistent with the
definition of nameplate capacity
provided in 40 CFR 96.202.
A commenter requested additional
flexibility in demonstrating incremental
generation, including through the use of
actual baseline generation data reported
to government and quasi-government
agencies such as independent system
operators, regional transmission
organizations, or other balancing
authorities where the generator is
connected. Additionally, several
commenters stated that ISO standards
are not widely used in the industry and
that other standards more widely used
by the industry would be more effective
at determining true capacity additions.
Several commenters that recommended
other standards for measuring increased
capacity noted that geothermal facilities,
hydropower facilities, and other clean
energy facilities would be
disadvantaged by relying on nameplate
capacity to satisfy the Incremental
Production Rule. Several commenters
provided options for alternative
measurements standards, including the
American Society of Mechanical
Engineers (ASME) Performance Tests,
IEC standards, and NERC procedures,
and other comparable technical
standard conditions. Additionally, a
commenter suggested permitting
taxpayers to use an accredited
measurement method, such as the
ASME Performance Test, suitable for the
particular circumstances associated
with the facility modification or
addition, provided that the accredited
method can be used to reasonably
measure electrical generating capacity,
can be consistently applied to measure
electrical generation capacity before and
after the modification or addition, and
can be clearly documented by a thirdparty engineering report specific to the
project.
Other commenters proposed
measuring additional capacity based on
changes in output compared to the
facility’s historical baseline output. A
commenter proposed permitting
taxpayers to measure by themselves the
amount by which all components of
property added to the facility in a
taxable year increases the generating
capacity of the facility, relative to a
baseline in which the components of
property are not added to the facility.
Several commenters also noted that
measurements should be adjusted as
reasonably practicable to ensure a likefor-like comparison pre- and postaddition. Conversely, a commenter
noted that additional capacity
measurements should not rely on
monthly or annual output of a facility
prior to and after a project or

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modification because other factors, such
as weather, demand, and outages will
affect a facility’s output from one period
to another. The Treasury Department
and the IRS have determined that
increased capacity should not be based
on a measurement methodology that
simply compares electricity production
before the increase in capacity to
electricity production after the increase
in capacity because such measurement
methodologies involve seasonal or other
fluctuations that are too easily
manipulated to show a greater increase
in capacity than the actual increase.
The Treasury Department and the IRS
considered the comments regarding
different methods for measuring
increased capacity and found that many
of the proposed measurement standards
were not broadly applicable across
technologies. Additionally, many were
not sufficiently objective. The Treasury
Department and the IRS recognize,
though, that different methods may exist
that are broadly applicable across
technologies and sufficiently objective.
The Treasury Department and the IRS
will continue to consult with experts on
potential additional measurement
standards that could apply. The final
regulations are amended to reflect this
continuing consideration and to provide
flexibility by permitting the Secretary to
prescribe additional measurement
standards in guidance published in the
Internal Revenue Bulletin.
The Treasury Department and the IRS
recognize the limitations of measuring
increased capacity with nameplate
capacity. As a result, the Treasury and
the IRS have provided additional
measurement options in the final
regulations. Measurement options in the
final rule include: modified or amended
facility operating licenses from FERC or
NRC, or related reports prepared by
FERC or NRC as part of the licensing
process (as described in section IV.H.4.
of this Summary of Comments and
Explanation of Revisions); and any
measurement standard prescribed by the
Secretary in guidance published in the
Internal Revenue Bulletin (see 26 CFR
601.601). The final regulations also
clarify that taxpayers that are able to use
the measurement standard described in
§ 1.45Y–4(c)(2)(i) or § 1.48E–4(b)(2)(i)
may not use the method described in
§ 1.45Y–4(c)(2)(ii) or § 1.48E–4(b)(2)(ii)
(permitting use of the ISO conditions to
measure the maximum electrical
generating output of a facility to
determine its nameplate capacity).
Additionally, the final regulations add
an additional example at §§ 1.45Y–
4(c)(5) and 1.48E–4(b)(5) to illustrate the
application of the Incremental
Production Rule to a geothermal facility.

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4. Documentation Used To Demonstrate
Increased Capacity
As proposed, the Incremental
Production Rule allowed taxpayers to
use modified or amended facility
operating licenses to measure capacity
and changes therein. Several
commenters noted that nuclear facilities
are unable to use modified or amended
facility operating licenses to measure an
addition of capacity, because a NRC
operating license lists a reactor’s
maximum power level in megawatts
thermal, rather than maximum electric
generating capacity, and changes can be
made to improve a plant’s thermal
efficiency (and thus electric generating
capacity) without altering the reactor’s
thermal power or necessitating a
modified or amended operating license.
Nonetheless, the Treasury Department
and the IRS understand that, under
certain circumstances, FERC and NRC
modified or amended licenses and
reports related to those modified or
amended licenses do report electrical
capacity and changes therein.
For example, the NRC reports the
electric capacity of nuclear power plants
before and after uprates involving
amendments to NRC licenses. Electric
generating capacity is not typically
included in NRC operating licenses, as
operating licenses do not condition or
limit the electric power output.
However, electric capacity can be
included in related NRC-authored safety
evaluation reports, which are a required
element of the license amendment
process. These reports typically express
power output in MW thermal but can
also provide information related to
capacity in MW electric. The final
regulations at §§ 1.45Y–4(c)(2)(i) and
1.48E–4(b)(2)(i) allow taxpayers to use
the electric capacity, and changes
therein, presented in safety evaluation
reports that are part of a modified or
amended operating license to
demonstrate an increased amount of
electricity produced at the facility by
reason of a new unit or addition of
capacity, and to calculate the amount of
that increase. Similarly, the final
regulations at §§ 1.45Y–4(c)(2)(i) and
1.48E–4(b)(2)(i) also allow taxpayers to
use electrical capacity and changes
therein as reported in FERC modified or
amended licenses, and reports related to
those modified or amended licenses.
The final regulations clarify, though,
that taxpayers that are able to use the
measurement standard described in
§ 1.45Y–4(c)(2)(i) or § 1.48E–4(b)(2)(i)
may not use the method described in
§ 1.45Y–4(c)(2)(ii) or § 1.48E–4(b)(2)(ii)
(permitting use of the International
Standard Organization (ISO) conditions

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to measure the maximum electrical
generating output of a facility to
determine its nameplate capacity).
Several commenters proposed various
additional methods for documenting an
increase in capacity including the use of
a third-party engineering report. The
Treasury Department and the IRS
determined that without a specific
measurement standard and certification
requirements, an independent thirdparty engineering report alone does not
provide an adequate method to
substantiate a facility’s increased
capacity.
5. Measurement of Eligible Basis for a
New Unit or an Addition of Capacity
Under Section 48E
Several commenters recommended
that the cost of any uprates, upgrades,
efficiency, or other improvements that
result in additional generation capacity
at a facility be considered a qualified
investment for purposes of the section
48E credit. Specifically, commenters
asserted that the qualified investment
with respect to a qualified facility
should include the entire cost of a new
unit or any additions of capacity, rather
than a proportionate share of those costs
reflective of the extent to which the
electricity produced attributable to a
new unit or addition of capacity
increased (as opposed to replaced) the
existing facility’s production.
Commenters supported this
recommendation by noting a similar
treatment of basis was used in the
Section 1603 Grant Program for
improvements to hydropower facilities.
Commenters also noted that the
proposed regulations allow for the full
basis of a qualified investment in a new
unit to be eligible for the credit, but not
for additions of capacity. A commenter
emphasized that this approach creates
challenges for administrability, and
application of the rule based on
measuring fractional additions of
capacity. As an example, the commenter
indicated that some replacement parts
do not have a nameplate capacity but
are essential to the total nameplate
capacity of the overall facility. Several
commenters recommended an
alternative rule that prorates an
investment between qualified and nonqualified property when the investment
is a discretionary replacement of
existing capacity but suggested that the
entire amount of an investment should
be treated as eligible for the credit if the
investment would not have occurred but
for increasing capacity.
In response to the comments, the
Treasury Department and the IRS
acknowledge that a qualified investment
for an addition of capacity would not be

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paid or incurred but for the increase in
electricity generation capacity and agree
that the rules for computing the
qualified investment for an addition of
capacity should be modified. Therefore,
the final regulations at § 1.48E–4(b)(4)
are amended to make the rule for an
addition of capacity equivalent to that of
a new unit by providing that a
taxpayer’s qualified investment during
the taxable year that resulted in an
increased capacity of a facility by reason
of a new unit or an addition of capacity
is its total qualified investment in
components of qualified property that
result in the new unit or addition of
capacity.
6. Special Rule for Restarted Facilities
A few commenters requested further
guidance specific to decommissioned
facilities. These commenters suggested
treating the capacity of decommissioned
facilities before restarting as zero and
clarifying that facilities meeting the
special rule for restarted facilities under
proposed §§ 1.45Y–4(c)(2) and 1.48E–
4(b)(2) can treat their entire capacity as
an addition of capacity. One commenter
noted that a decommissioned facility
ceases operations and is not legally
permitted to produce electricity due to
a lack of operating license. Another
commenter requested that, instead of
requiring a period without a valid
operating license, the final regulations
cover the typical situation for
decommissioning a hydropower facility
in which the licensee maintains an
operating license that no longer
authorizes the operation of the facility.
Another commenter similarly asserted
that a nuclear facility must maintain its
operating license until
decommissioning is concluded. The
commenter stated that a nuclear
facility’s operating license (issued by
the NRC) generally does not authorize
operation and electricity production
after the licensee submits a written
certification to the NRC that they have
determined to permanently cease
operations and once fuel has been
permanently removed from the reactor
vessel. Accordingly, both commenters
suggested revising proposed §§ 1.45Y–
4(c)(2)(ii) and 1.48E–4(b)(2)(ii) to treat a
facility that is decommissioned or in the
process of decommissioning and restarts
to have increased capacity if the facility
shuts down for at least one calendar
year, during which it was not
authorized to operate by its respective
Federal Agency or did not generate
more than 0 megawatt-hours, while
holding a license from the FERC or
NRC.
An additional commenter
recommended expanding the special

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rule for restarted facilities to include
continuous operation in the case of a
facility that obtains a renewed operating
license and enters an initial or
subsequent period of extended
operation under the renewed operating
license after December 31, 2024. The
commenter suggested treating such a
scenario as an addition of capacity equal
to the full capacity of the facility.
In contrast, a commenter raised
concerns regarding the special rule for
restarted facilities, pointing to abuse by
certain taxpayers and noting that the
rule strays from the intention of the tax
credits to deploy new resources. The
commenter further highlighted a
potential lack of readiness by implicated
government agencies, noting specifically
that the NRC does not have regulations
governing license reinstatement. The
commenter recommended removing the
special rule for restarted facilities from
the final regulations or, in the
alternative, engaging in further fact
finding before finalizing such a rule. If
a special rule for restarted facilities is
implemented, the commenter requested
that additional requirements be
incorporated to raise the bar to entry for
decommissioned facilities to prevent
abuse of loopholes.
In response to these comments, the
final regulations make four changes to
proposed §§ 1.45Y–4(c)(2) and 1.48E–
4(b)(2) and moved them to §§ 1.45Y–
4(c)(3) and 48E–4(b)(3), respectively.
First, the final regulations modify the
language in proposed §§ 1.45Y–
4(c)(2)(ii) and 1.48E–4(b)(2)(ii) to state
that ‘‘[t]he 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
FERC or the NRC).’’ (Emphasis added.)
Second, the final regulations modify the
language in proposed §§ 1.45Y–
4(c)(2)(iii) and 1.48E–4(b)(2)(iii) to state
that the restarted facility must be
eligible to restart based on an operating
license issued by either FERC or NRC.
Third, the final regulations are modified
to reflect the Treasury Department and
the IRS’ agreement with the
commenter’s concerns regarding
potential abuse by certain taxpayers
related to the decommissioning and
shutdown steps in the proposed
regulations. In order to limit this
potential abuse, the final regulations
add an anti-abuse rule to §§ 1.45Y–
4(c)(3) and 1.48E–4(b)(3) that provides
that a facility may not cease operation
for the purpose of qualifying for the
special rule for restarted facilities.
Finally, the final regulations reflect that
the addition of capacity in the case of
a restarted facility is the total capacity

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of the facility after it is restarted by
modifying the language to state that a
facility that is decommissioned or in the
process of decommissioning and restarts
can be considered to have increased
capacity from a base of zero if certain
conditions are met. The final regulations
add an additional example at §§ 1.45Y–
4(c)(5) and 1.48E–4(b)(5) to illustrate the
application of the Incremental
Production Rule to a restarted facility.
I. Dual Use Rule
A commenter requested clarifying the
applicability of the ‘‘dual use’’ concept
to sections 45Y and 48E. Specifically,
the commenter suggested clarifying that
the ‘‘75 percent cliff’’ for energy
property with integrated storage does
not apply. A previous version of § 1.48–
9 included a Dual Use Rule, referred to
as the ‘‘75-percent cliff,’’ which
provided that a solar energy property,
wind energy property, or geothermal
equipment is eligible for the section 48
credit to the extent of the energy
property’s basis or cost allocable to its
annual use of energy from a qualified
source if the use of energy from ‘‘nonqualifying’’ sources does not exceed 25
percent of the total energy input of the
energy property during an annual
measuring period.
Historically, the Dual Use Rule was
used in the section 48 regulations to
address the treatment of energy storage
property that stored energy from a
qualified source and a non-qualified
source. This was necessary because
prior to the IRA amendments to section
48, energy storage property was only
allowed for the section 48 credit as part
of an energy property. After the IRA
amendments, energy storage property
became a separate type of energy
property, referred to as ‘‘energy storage
technology,’’ and the need for the Dual
Use Rule changed. Similar to the
treatment of EST in section 48, a
separate credit is provided under
section 48E. Accordingly, the Treasury
Department and IRS clarify that the
Dual Use Rule contained in a prior
version of § 1.48–9 is not applicable to
the section 45Y and 48E credits.

4041

To the extent consistent with this
Summary of Comments and Explanation
of Revisions, the Explanation of
Revisions described in the PWA final
regulations is incorporated in these final
regulations. Therefore, general
comments addressed in the preamble to
the PWA final regulations are not
readdressed in this Summary of
Comments and Explanation of
Revisions.
Increased credit amounts are
generally available under section
45Y(a)(2)(B) for qualified facilities and
section 48E(a)(2)(A)(ii) for qualified
facilities and EST if beginning of
construction of the qualified facility or
EST occurs before January 29, 2023
(BOC Exception). Under the relevant
BOC Exception in sections 45Y and 48E,
taxpayers may claim the amount of the
increased credit without satisfying the
PWA requirements if construction
‘‘begins prior to the date that is 60 days
after the Secretary publishes guidance
with respect to the [PWA
requirements].’’ On November 30, 2022,
the Treasury Department and the IRS
published Notice 2022–61, 2022–52
I.R.B. 560, providing initial guidance
with respect to the PWA requirements
and starting the 60-day period described
in those sections. To qualify for the BOC
Exception, a taxpayer must begin
construction before January 29, 2023.
Additionally, increased credit
amounts are generally available under
sections 45Y and 48E with respect to
qualified facilities with a maximum net
output (or capacity for EST under
section 48E) of less than one megawatt
(One Megawatt Exception). If a taxpayer
satisfies the PWA requirements, meets
the BOC Exception, or meets the One
Megawatt Exception, the amount of
section 45Y credit or section 48E credit
determined is equal to the otherwise
determined amounts multiplied by five.

B. Application of the PWA
Requirements to Section 45Y
Section 45Y(g)(9) provides that rules
similar to the rules of section 45(b)(7)
apply with respect to the prevailing
wage requirements (Prevailing Wage
Requirements). Section 45Y(g)(10)
V. Rules Relating to the Increased Credit provides that rules similar to the rules
Amount for Satisfying Certain Prevailing of section 45(b)(8) apply with respect to
Wage and Apprenticeship Requirements the apprenticeship requirements
(Apprenticeship Requirements). Section
A. In General
1.45Y–3(b)(3) adopted by crossThe PWA final regulations provide
reference the rules in the PWA final
generally applicable rules on the PWA
regulations promulgated under section
requirements. Comments on the general 45(b)(7) and (8); specifically, §§ 1.45–7
PWA requirements (including
(Prevailing Wage Requirements), 1.45–8
comments that referenced section 45Y
(Apprenticeship Requirements), and
or 48E but addressed the PWA
1.45–12 (recordkeeping and reporting).
As previously explained, the PWA
requirements more generally) were
addressed in the PWA final regulations. final regulations addressed general

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Federal Register / Vol. 90, No. 9 / Wednesday, January 15, 2025 / Rules and Regulations

1. In General

to the prevailing wage requirements.
Section 48(a)(10) provides rules with
respect to the prevailing wage
requirements under section 48,
including the special recapture
provision under section 48(a)(10)(C).
Section 48(a)(10)(B) provides that the
correction and penalty procedures
under section 45(b)(7)(B) for a failure to
satisfy the prevailing wage requirements
generally apply prior to a recapture
event under section 48(a)(10)(C).
Section 48E(d)(4) provides that rules
similar to the rules of section 45(b)(8)
apply with respect to the apprenticeship
requirements. Proposed § 1.48E–3
would adopt by cross-reference those
rules in the section 48 final regulations
promulgated under section 48(a)(10)
and the PWA final regulations
promulgated under section 45(b)(7) and
(8); specifically, §§ 1.48–13(c)
(Prevailing Wage Requirements), 1.45–8
(Apprenticeship Requirements), and
1.45–12 (recordkeeping and reporting).
These rules are generally adopted by
cross-reference in § 1.48E–3 with
additional clarifications to reflect
§§ 1.48–13, 1.45–8, and 1.45–12 and
these final regulations.
At least one commenter requested that
C&G facilities fueled by woody biomass
feedstocks be eligible to qualify for the
domestic content bonus credit amount
and increased credit amount for
satisfying PWA requirements. As
discussed in section IV.A. of this
Summary of Comments and Explanation
of Revisions, a facility that meets the
definition of a qualified facility may
qualify for the relevant section 45Y and
48E credits. Accordingly, a qualified
facility may also qualify for an increased
credit amount under sections 45Y and
48E provided that the facility satisfies
the relevant domestic content bonus or
PWA requirements.
A commenter praised the PWA final
regulations for using restraint in
incorporating elements of the DavisBacon Act and suggested that the
Treasury Department and the IRS
exercise the same restraint in drafting
these regulations. The Treasury
Department and the IRS generally agree
with the commenter that the final
regulations for section 48E should apply
a similar approach as in the PWA final
regulations in order to ensure
consistency across different Code
sections, provide taxpayer certainty, and
further tax administration. These final
regulations reflect such an approach.

The PWA requirements in section 48E
cross-reference both sections 45 and 48
for operative rules. Section 48E(d)(3)
provides that rules similar to the rules
of section 48(a)(10) apply with respect

2. Transition Rules
As stated in the preamble to the PWA
final regulations and reiterated in the
preamble to the section 48 final
regulations, the Treasury Department

application of the PWA requirements
and provided the rules (except the One
Megawatt Exception) applicable for
section 45Y in § 1.45Y–3. To provide
consistent descriptions and
terminology, non-substantive, technical
updates have been made to § 1.45Y–3 to
reflect these final regulations. As
revised, § 1.45Y–3 also includes a new
applicability date. These final
regulations make no substantive change
regarding application of the general
PWA requirements, notwithstanding the
new applicability date, apart from the
amendments made to address the One
Megawatt Exception. Taxpayers that
began construction after June 25, 2024,
and taxpayers that begin construction
after the publication of the final
regulations continue to follow the same
general rules with respect to the PWA
requirements.
Taxpayers also have the option to
apply these final regulations to qualified
facilities that began construction before
the publication of the final regulations,
provided that taxpayers follow these
final regulations in their entirety and in
a consistent manner. Likewise,
taxpayers that choose to apply these
final regulations must also follow the
PWA final regulations, consistent with
prior § 1.45Y–3. There are no changes to
the application of the transition rules
provided for in the PWA final
regulations for taxpayers choosing to
apply these final regulations for
construction that began before the
publication of the final regulations as
the general PWA requirements did not
change between prior § 1.45Y–3 in the
PWA final regulations and § 1.45Y–3 in
these final regulations.
The Treasury Department and the IRS
understand that taxpayers may need
additional time to comply with the
amendments made by these final
regulations to the One Megawatt
Exception. Therefore, the amendments
made to § 1.45Y–3 with respect to the
One Megawatt Exception have a delayed
applicability date that is 60 days after
publication of the final regulations.
Comments received regarding the One
Megawatt Exception under section 45Y
are addressed in these final regulations
and explained in section V.D. of this
Summary of Comments and Explanation
of Revisions.

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C. Application of the PWA
Requirements to Section 48E

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and the IRS have determined that given
the complexity of the PWA
requirements, the uncertainty regarding
the potential retroactive effects of the
PWA requirements, and the benefits to
tax administration gained with
consistency across the various Code
sections containing PWA requirements,
that a transition rule is appropriate. The
PWA final regulations provide that any
work performed before January 29, 2023
(that is, the date that is 60 days after the
publication of Notice 2022–61) is not
subject to the PWA requirements,
regardless of whether there is an
applicable BOC Exception. This
transition rule also applies for taxpayers
that may initially satisfy the BOC
Exception, but later fail to meet the BOC
Exception (for example, by failing to
meet certain continuity requirements).
These taxpayers must satisfy the PWA
requirements for construction,
alteration, or repair (as applicable) that
occurs on or after January 29, 2023, but
do not need to meet the PWA
requirements for work that occurred
prior to that date. For similar reasons,
this transition rule also applies to the
PWA requirements under section 48E
and is incorporated by cross-reference to
§§ 1.48–13 and 1.45–8 in these final
regulations.
The section 48 final regulations (and
as described in the PWA final
regulations) also provide a limited
transition waiver for the penalty
payment with respect to the correction
and penalty procedures described in
section 45(b)(7)(B) for a failure to satisfy
the Prevailing Wage Requirements. The
PWA final regulations provide that the
penalty payment is waived with respect
to a laborer or mechanic who performed
work in the construction, alteration, or
repair of a qualified facility on or after
January 29, 2023, and prior to June 25,
2024, if the taxpayer relied upon Notice
2022–61 or the PWA proposed
regulations for determining when the
obligation to pay prevailing wages
began, provided the taxpayer makes the
appropriate correction payments to the
impacted workers within 180 days of
June 25, 2024. These final regulations
clarify that this limited transition
waiver applies to section 48E (by
incorporation of the cross-reference to
section 48(a)(10)) provided the taxpayer
makes the appropriate correction
payments to the impacted workers
within 180 days of the publication of
these final regulations.
Similarly, these final regulations also
allow taxpayers to use Notice 2022–61
for determining when construction
begins for purposes of the applicable
percentage of labor hours performed by
qualified apprentices required under

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section 45(b)(8) in satisfying the labor
hours requirement described in § 1.45–
8. These transition rules are further
explained in the preamble to the PWA
final regulations.

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3. Recapture
The section 48 final regulations also
addressed the recapture rules under
section 48(a)(10)(C). The preamble to
the section 48 final regulations contains
detailed discussion of the recapture
rules, and similar rules apply for
purposes of the special recapture rule in
section 48E(d)(3) (by reference to
section 48(a)(10)). The recapture rules in
§ 1.48–13 are incorporated by crossreference in § 1.48E–3. These final
regulations do clarify that if there is no
alteration or repair that occurs during
the relevant year during the five-year
recapture period, the taxpayer is
deemed to satisfy the PWA
requirements with respect to that year.
4. Interconnection Property
Some commenters suggested
clarifying that the PWA requirements do
not apply to the construction, alteration,
or repair of interconnection property.
Section 48E(a)(2)(A)(ii) provides that the
increased credit amount (for satisfying
the PWA requirements) is determined in
the case of a qualified facility. The
qualified investment with respect to a
qualified facility described in section
48E(b) is the sum of the basis of any
qualified property placed in service by
the taxpayer during such taxable year
that is part of a qualified facility, plus
the amount of expenditures that are
paid or incurred by the taxpayer for
qualified interconnection property.
Therefore, interconnection property is
eligible for the increased credit amount.
However, consistent with section
48(a)(8), § 1.48E–4(a)(2) clarifies that
interconnection property is not part of
a qualified facility and therefore is not
subject to the PWA requirements.
In addition to not being part of the
qualified facility, as defined in section
48E(b)(3)(A), interconnection property
generally is also not within the control
of the taxpayer that owns the qualified
facility because it generally is not
owned by the same taxpayer. Instead,
qualified interconnection property is
generally owned by a utility and is part
of an addition, modification, or upgrade
to a transmission or distribution system
that is required at or beyond the point
at which the qualified facility
interconnects to such transmission or
distribution system. It would therefore
be difficult or impossible in such a case
for the taxpayer to control or monitor
whether the construction of the
interconnection property complies with

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the PWA requirements. This may
explain why the statute permits the
increased credit amount for amounts
paid or incurred for qualified
interconnection property, without
subjecting the construction of that
property to the PWA requirements.
With respect to EST, section 48E(c)(1)
describes the qualified investment with
respect to EST without reference to
interconnection property. This differing
treatment of interconnection property
between qualified facilities under
section 48E(b) and EST under section
48E(c) is further supported by section
48E(b)(4), which solely defines
interconnection property ‘‘[f]or
purposes of this paragraph [(b)(4)].’’
Accordingly, the qualified investment
with respect to any EST does not
include qualified interconnection costs
and qualified interconnection property
is not subject to PWA requirements.
Interconnection property with respect to
EST is further discussed in section
III.D.6. of this Summary of Comments
and Explanation of Revisions.
D. One Megawatt Exception Under
Section 45Y
The preamble to the PWA final
regulations explained that the One
Megawatt Exception for purposes of
section 45Y would be addressed in
these final regulations. Comments
pertaining to the technical aspects of
measuring output for the purposes of
the One Megawatt Exception under 45Y
were limited. Commenters stated that
some technologies, such as solar,
generate electricity in direct current not
alternating current, so it is unclear how
to measure such technologies.
The Treasury Department and the IRS
agree that the One Megawatt Exception
under section 45Y(a)(2)(B)(i) requires
clarification. The final regulations under
§ 1.45Y–3(c)(1) provide that the
determination of whether a qualified
facility has a maximum net output of
less than one megawatt of electricity (as
measured in alternating current) is
based on the nameplate capacity of the
qualified facility. The nameplate
capacity for purposes of the One
Megawatt Exception is the maximum
electrical generating output in
megawatts that a qualified facility is
capable of producing on a steady state
basis and during continuous operation
under standard conditions, as measured
by the manufacturer and consistent with
the definition of nameplate capacity
provided in 40 CFR 96.202. If
applicable, taxpayers must use the ISO
conditions to measure the maximum
electrical generating output of a
qualified facility. For qualified facilities
that generate electrical output in direct

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4043

current, the final regulations under
§ 1.45Y–3(c)(2) provide an alternative
nameplate capacity measurement. For
qualified facilities that generate
electricity in direct current, the taxpayer
may choose to determine the maximum
net output (in alternating current) of
each qualified facility for purposes of
the One Megawatt Exception by using
the lesser of: (i) the sum of the
nameplate generating capacities within
the unit of qualified facility in direct
current, which is deemed the nameplate
generating capacity of the unit of
qualified facility in alternating current;
or (ii) the nameplate capacity of the first
component of property that inverts the
direct current electricity into alternating
current.
When evaluating whether the One
Megawatt Exception under section 45Y
applies, the Treasury Department and
the IRS have determined that a
consistent approach should apply for
purposes of sections 48E and 45Y. A
plain reading of the statutory exception
for facilities with a maximum net output
of less than one megawatt demonstrates
Congress’s intent to have only lower
output, small facilities excepted from
the PWA requirements and still be
eligible for the increased credit amount.
For purposes of determining whether a
qualified facility must satisfy the PWA
requirements to obtain an increased
credit amount, the output of any
qualified facility must be evaluated
consistent with its operations. These
final regulations provide, in part, that
the unit of qualified facility includes all
functionally interdependent
components of property owned by the
taxpayer that are operated together and
that can operate apart from other
property to produce electricity. The
Treasury Department and the IRS
intended for the term ‘‘operated
together’’ to be given effect when
considering whether the One Megawatt
Exception applies to the PWA
requirements.
When measuring nameplate capacity
for the purposes of the One Megawatt
Exception under section 45Y, these final
regulations provide parity with the rules
for section 48E and include the same
special rule that if the qualified facility
has integrated operations with one or
more other qualified facilities, then the
aggregate nameplate capacity of the
qualified facilities is used for purposes
of determining whether the One
Megawatt Exception applies to the
qualified facility. Solely for the
purposes of the One Megawatt
Exception, these final regulations
provide that a qualified facility is
treated as having integrated operations
with any other qualified facility of the

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same technology type if the facilities
are: (i) owned by the same or related
taxpayers; (ii) placed in service in the
same taxable year; and (iii) transmit
electricity generated by the facilities
through the same point of
interconnection or, if the facilities 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. The final
regulations also provide a definition for
related taxpayers. For purposes of the
One Megawatt Exception, 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 qualified facility has
integrated operations.
The Treasury Department and the IRS
understand that some taxpayers who
have integrated operations may need
additional time to comply with the
PWA requirements where construction
has already begun, or is imminent,
before publication of these final
regulations. To alleviate these
circumstances, the rule for qualified
facilities with integrated operations has
a delayed applicability date that is 60
days after publication of the final
regulations.
E. Election To Group Qualified
Facilities for Purposes of PWA
Requirements Under Section 45Y
Commenters suggested that the
taxpayers should be allowed to group
facilities as they chose when applying
the PWA requirements for an increased
credit amount. For example, a
commenter suggested that a taxpayer
that owns interrelated facilities should
be allowed elect to combine multiple
interrelated facilities into one
aggregated unit or, alternatively, elect to
treat the facilities individually for the
PWA requirements. Some commenters
asserted that it is difficult to certify
compliance at each qualified facility
level, so taxpayers should be allowed to
certify PWA compliance at an
interrelated facilities level.
To claim an increased credit amount
for satisfying the PWA requirements,
section 45Y requires that each qualified
facility satisfy the requirements. The
statute does not support commenters’
request to allow PWA certification for
qualified facilities based on one
qualified facility. If a taxpayer does not
satisfy the PWA requirements for a
qualified facility, the taxpayer may cure
with correction payments paid to
impacted workers and a penalty paid to
the IRS. The PWA final regulations
provide taxpayers the rules for the

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Prevailing Wage Requirement,
Apprenticeship Requirement, and the
recordkeeping and reporting applicable
to section 45Y.
F. One Megawatt Exception Under
Section 48E
The preamble to the PWA final
regulations explained that the One
Megawatt Exception for purposes of
section 48E would be addressed in these
final regulations. Proposed § 1.48–13
would have provided by cross-reference
that maximum net output is based on
nameplate capacity and proposed
conversion formulas for certain types of
qualified facilities and ESTs.
Some commenters recommended
revisions to the conversion formulas.
For example, one commenter asserted
that by defining the threshold for the
One Megawatt Exception for thermal
systems at about a quarter of the
equivalent output of electrical energy
systems, investors in thermal energy
storage systems will not qualify for the
One Megawatt Exception. The
commenter recommended that the One
Megawatt Exception be measured as the
maximum net output according to a
facility’s electrical equivalent. The
commenter explained this means that
for thermal energy resources, the use of
electricity (in kW) that would be
avoided or offset by each unit of thermal
energy (Btu/h for heat, or Ton of
cooling) provided by the thermal energy
resource. The commenter recommended
that the conversion value for thermal
energy cooling systems for purposes of
measuring the One Megawatt Exception
for qualified facilities be 1,550 tons for
water-cooled systems and 870 tons for
air-cooled systems.
The Treasury Department and the IRS
have concluded that the conversion
formulas in the proposed regulations
provide a direct and accurate
conversion and that no changes are
needed to the conversion factors for
thermal energy storage property. By
providing a broadly applicable rule, the
conversion formulas should provide
accurate results for a broad set of
applications and technologies. The
commenters’ requests for specific
formulas applicable to specific
technologies conflict with the approach
of these final regulations to provide
general, rather than narrow, rules.
Therefore, the final regulations do not
adopt these comments. The final
regulations provide conversion formulas
for thermal energy storage technology in
§ 1.48E–3(c)(3)(iii) and hydrogen storage
technology in § 1.48E–2(g)(6)(iii).
Commenters also stated that certain
technologies generate electricity in
direct current, not alternating current,

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so it is unclear how such qualified
facilities could qualify for the One
Megawatt Exception. The Treasury
Department and the IRS agree that the
One Megawatt Exception under section
48E requires clarification for
technologies that generate output in
direct current.
The final regulations provide that the
determination of whether a qualified
facility has a maximum net output of
less than one megawatt of electricity (as
measured in alternating current) is
based on the nameplate capacity of the
qualified facility. The nameplate
capacity for purposes of the One
Megawatt Exception is the maximum
electrical generating output in
megawatts that a qualified facility is
capable of producing on a steady state
basis and during continuous operation
under standard conditions, as specified
by the manufacturer and consistent with
the definition of nameplate capacity
provided in 40 CFR 96.202. If
applicable, taxpayers must use the ISO
conditions to measure the maximum
electrical generating output of a facility.
Section 48E(a)(2)(B)(ii)(I) describes the
One Megawatt Exception for EST as
based on the capacity of the EST. The
final regulations adopt this general term,
and also clarify that the nameplate
capacity of the for EST is based on the
output of the EST.
For qualified facilities that generate
electrical output in direct current, the
final regulations provide a new
alternative nameplate capacity
measurement. Only for qualified
facilities that generate electricity in
direct current, the taxpayer may choose
to determine the maximum net output
(in alternating current) of each qualified
facility by using the lesser of: (i) the sum
of the nameplate generating capacities
within the unit of qualified facility in
direct current, which is deemed the
nameplate generating capacity of the
unit of qualified facility in alternating
current; or (ii) the nameplate capacity of
the first component of property that
inverts the direct current electricity into
alternating current. The final regulations
also provide these same rules apply for
ESTs that have output in direct current
for the purposes of determining if the
EST One Megawatt Exception applies.
Commenters also stated opposition to
adopting the concept of an ‘‘energy
project’’ or aggregation rule similar to
those in the section 48 proposed
regulations for purposes of claiming the
increased rate for meeting the PWA
requirements under section 48E (as well
as section 45Y). Commenters asserted
that there is no legal basis for using the
definition of an energy project or any
aggregation rule for the section 48E

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Federal Register / Vol. 90, No. 9 / Wednesday, January 15, 2025 / Rules and Regulations
credit. A commenter instead suggested
permitting a taxpayer to elect to
combine multiple interrelated facilities
into one aggregated unit or,
alternatively, elect to treat the facilities
individually for purposes of the PWA
requirements. Another commenter
requested permitting taxpayers to certify
that individual qualified facilities meet
the PWA requirements if interrelated
facilities meet the PWA requirements.
The commenter stated that taxpayers
typically contract with mechanics and
laborers for an entire project, rather than
for an individual qualified facility, and
that it would be difficult to certify
compliance with the PWA requirements
at the qualified facility level.
The Treasury Department and the IRS
do not agree with commenters that there
is no legal basis to incorporate an
aggregation rule into section 48E.
Section 48E(d)(3) provides that ‘‘[r]ules
similar to the rules of section 48(a)(10)
shall apply.’’ Section 48(a)(10) applies
the prevailing wage requirements to
‘‘energy projects,’’ which requires the
aggregation of energy properties under
section 48. Additionally, the reference
in section 48E(d)(3) to the prevailing
wage requirements provided in section
48(a)(10) 4 indicates that the express
delegation of authority in section
48(a)(16) also applies in the context of
section 48E for implementation of the
prevailing wage requirements. Although
the apprenticeship requirements
provided in section 48E(d)(4) applies
rules similar to section 45(b)(8) rather
than section 48(a)(11), an appropriate
reading of the statute is to apply a
consistent interpretation to both of
section 48E’s prevailing wage
requirements and apprenticeship
requirements, as inconsistent
interpretations would frustrate
congressional intent by creating
different standards for the prevailing
wage requirements and apprenticeship
requirements and would be difficult for
the IRS to administer. For the reasons
noted in this Summary of Comments
and Explanation of Revisions,
interpreting the PWA requirements for
section 48E consistently with section
48(a)(10) is the best implementation of
the overall statutory framework because
it results in the PWA requirements
being applied appropriately and
consistently across credits.
The concept of interrelated facilities
raised by commenters is relevant to the
One Megawatt Exception. As discussed
in section IV.B. of this Summary of
Comments and Explanation of
4 Section 48(a)(16) provides the same broad
authority for administering the PWA provisions in
section 48(a).

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Revisions, these final regulations apply
a functional definition to implement the
term ‘‘qualified facility.’’ These final
regulations provide, in part, that the
unit of qualified facility includes all
functionally interdependent
components of property owned by the
taxpayer that are operated together and
that can operate apart from other
property to produce electricity. This
functional definition could result in
some qualified facilities with a
maximum net output that is far greater
than one megawatt being treated as
though they were many separate
facilities each with a maximum net
output of less than one megawatt. This
would have unintended impacts on the
PWA requirements. Accordingly, the
Treasury Department and the IRS intend
to give effect to the term ‘‘operated
together’’ when considering whether
and how the One Megawatt Exception
applies to the PWA requirements.
A plain reading of the statutory
exception for facilities with a maximum
net output of less than one megawatt
demonstrates Congress’s intent to have
only lower output, small facilities
excepted from the PWA requirements
and still be eligible for the increased
credit amount. Any other interpretation
undermines the purpose of the statutory
exception and Congress’s intent to have
PWA requirements apply to the
construction of clean energy facilities.
For purposes of determining whether a
qualified facility must satisfy the PWA
requirements to obtain an increased
credit amount, the output of any
qualified facility must be evaluated
consistent with its operations. This
supports the purpose of the One
Megawatt Exception, provides certainty
for taxpayers seeking increased credit
amounts under section 48E, and furthers
sounds tax administration.
When measuring nameplate capacity
for the purposes of the One Megawatt
Exception, the final regulations provide
a special rule. Solely for the purposes of
the One Megawatt Exception, if the
qualified facility has integrated
operations with one more other
qualified facilities, then the aggregate
nameplate capacity of the qualified
facilities is used for the purposes of
determining if the One Megawatt
Exception applies. The final regulations
under § 1.48E–3(c)(4)(i) provide that
solely for the purposes of the One
Megawatt Exception, a qualified facility
is treated as having integrated
operations with any other qualified
facility of the same technology type, if
the facilities are: (i) owned by the same
or related taxpayers; (ii) placed in
service in the same taxable year; and
(iii) transmit electricity generated by the

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facilities through the same point of
interconnection or, if the facilities 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. The final
regulations under § 1.48E–3(c)(4)(ii)
provide a similar integrated operations
rule for EST.
As discussed in section IV.G. of this
Summary of Comments and Explanation
of Revisions, the final regulations
provide for a generally applicable
related taxpayer rule in § 1.48E–1(c),
including for purposes of the One
Megawatt Exception. 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
qualified facility or EST has integrated
operations.
As with section 45Y, the Treasury
Department and the IRS understand that
some taxpayers who have integrated
operations may need additional time to
comply with the PWA requirements
where construction has already begun,
or is imminent, before publication of
these final regulations. To alleviate
these circumstances, final regulations
for § 1.48–3 have an applicability date
that applies 60 days after publication of
the final regulations.
For the reasons provided herein,
aggregation of the nameplate capacity of
qualified facilities with integrated
operations is applicable only to the One
Megawatt Exception under the PWA
requirements and is not applicable to
other circumstances related to qualified
facilities, such as the Five-Megawatt
Limitation for qualified interconnection
property for Qualified Interconnection
Property, evaluation of eligibility for the
domestic content or energy
communities bonuses.
G. Election To Group Qualified
Facilities or ESTs for Purposes of the
PWA Requirements Under Section 48E
As with section 45Y, commenters
suggested that the taxpayers should be
allowed to group facilities as they chose
when applying the PWA requirements
for an increased credit amount under
section 48E. A commenter suggested
that a taxpayer that owns interrelated
facilities should be allowed to elect to
combine multiple interrelated facilities
into one aggregated unit or,
alternatively, elect to treat the facilities
individually for the PWA requirements.
A commenter suggested that taxpayers
should be allowed to certify compliance
with the PWA requirements for an
individual facility based on compliance
of interrelated facilities. Commenters’

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suggestions to allow elective grouping to
certify compliance with the PWA
requirements or allow taxpayers to
certify for an individual qualified
facility based on compliance of
interrelated facilities are not adopted.
The statute requires that each qualified
facility satisfy the requirements and for
this reason the commenter’s suggestions
cannot be adopted. If a taxpayer does
not satisfy the PWA requirements for a
qualified facility, the taxpayer may cure
with correction payments paid to
impacted workers and a penalty paid to
the IRS. The PWA final regulations
provide taxpayers the rules for the
Prevailing Wage Requirement,
Apprenticeship Requirement, and the
recordkeeping and reporting applicable
to section 48E.
VI. Domestic Content Bonus
The proposed regulations provided
rules related to the increase in credit
rate for qualified facilities (or EST in the
case of section 48E) that meet the
domestic content bonus requirements.
Some commenters supported and
some commenters opposed adopting the
concept of an ‘‘energy project’’ or
aggregation rule similar to those in the
section 48 proposed regulations for
purposes of claiming the domestic
content bonus credit amount under
section 45Y or 48E. Commenters
contended that there is no legal basis for
importing the definition of an energy
project or any aggregation rule for the
section 48E credit. A commenter instead
suggested permitting a taxpayer to elect
to combine multiple interrelated
facilities into one aggregated unit or,
alternatively, elect to treat the facilities
individually for purposes of the
domestic content bonus credit amount.
An aggregation rule is incorporated
into the section 48 final regulations for
purposes of claiming the domestic
content bonus credit amount, because
section 48 applies the domestic content
bonus credit amount to an entire energy
project defined as one or more energy
properties that are part of a single
project. However, section 45Y(g)(11)(A)
defines the domestic content bonus
credit amount in general with respect to
a qualified facility, without reference to
section 48. Although section
48E(a)(3)(B) provides that ‘‘[r]ules
similar to the rules of section 48(a)(12)
shall apply’’ for purposes of the
domestic content bonus credit amount,
section 48(a)(12)(B) dictates that ‘‘[r]ules
similar to the rules of section 45(b)(9)(B)
shall apply.’’ Additionally, even though
section 48(a)(12)(A) describes the
domestic content bonus credit amount
rules ‘‘[i]n the case of any energy
project,’’ sections 45Y and 48E do not

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have the energy project concept like
section 48 to allow grouping. Under
section 45(b)(9)(B), the domestic content
bonus credit amount applies with
respect to a qualified facility.
Accordingly, for purposes of claiming
the domestic content bonus credit
amount, more than one qualified facility
under section 45Y and more than one
qualified facility or EST under section
48E may not be treated as a single
qualified facility or EST. Each qualified
facility under section 45Y and each
qualified facility or EST under section
48E must separately qualify for the
increased credit rate for meeting
domestic content bonus requirements.
VII. Energy Communities
Similar to some commenters’
opposition to aggregation with respect
to the domestic content bonus credit
amounts, some commenters also
opposed adopting the concept of an
‘‘energy project’’ or aggregation rule
similar to those in the section 48
proposed regulations for purposes of the
increase in credit for energy
communities, under section 45Y or 48E.
Commenters contended that there is no
legal basis for importing the definition
of an energy project or any aggregation
rule for the section 48E credit. However,
one commenter instead suggested
permitting a taxpayer to elect to
combine multiple interrelated facilities
into one aggregated unit or,
alternatively, elect to treat the facilities
individually for purposes of the increase
in credit in energy communities.
An aggregation rule is incorporated
into the section 48 regulations for
purposes of claiming the increase in
credit rate in energy communities under
section 48, because section 48 applies
the increase in credit rate to an entire
energy project defined as one or more
energy properties that are part of a
single project. However, section
45Y(g)(7) and section 48E(a)(3)(A)(i)
define an energy community by crossreference to section 45(b)(11)(B), instead
of section 48. Section 45 does not have
the energy project concept like section
48 to allow grouping. Nor do section
45Y or 48E. Accordingly, for purposes
of claiming the increase in credit in
energy communities, more than one
qualified facility under section 45Y and
more than one qualified facility or EST
under section 48E will not be treated as
a single qualified facility or EST. Each
qualified facility under section 45Y and
each qualified facility or EST under
section 48E must separately qualify for
the increased credit rate for a qualified
facility or EST located in an energy
community.

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VIII. Greenhouse Gas Emissions Rates
for Qualified Facilities
Section 45Y(b)(2) provides rules for
determining GHG emissions rates.
Section 48E(b)(3)(B)(ii) provides that
rules similar to the rules of section
45Y(b)(2) regarding GHG emissions rates
apply for purposes of section 48E.5
Proposed § 1.45Y–5 provided rules
pertaining to GHG emissions rates as
well as definitions of terms relevant to
determining GHG emissions rates.
A. Definitions Related to Greenhouse
Gas Emissions Rates
Proposed § 1.45Y–5(b) provided
definitions of terms relevant to
determining GHG emissions rates.
1. CO2e per kWh
Section 45Y(e)(1) defines the term
‘‘CO2e per kWh’’ to mean, with respect
to any GHGs, the equivalent carbon
dioxide (as determined based on global
warming potential (GWP)) per kilowatt
hour of electricity produced. Proposed
§ 1.45Y–5(b)(1) clarified that the
determination must be based on the
100-year time horizon global warming
potential (GWP–100). Proposed § 1.45Y–
5(b)(1) also provided GWP–100 amounts
for certain specific GHGs from the
Intergovernmental Panel on Climate
Change’s (IPCC) Fifth Assessment
Report (AR5).
Commenters presented a range of
views on the proposed definition of
‘‘CO2e per kWh.’’ Some agreed with the
proposed definition, including one
commenter who noted that the proposed
definition aligns with Congressional
intent in enacting sections 45Y and 48E.
Some commenters advocated for
revisions to the proposed definition of
‘‘CO2e per kWh.’’ One commenter stated
that the urgent need for near-term GHG
emissions reductions may justify the use
of different GWP values. Several
commenters suggested that the proposed
definition be revised to use a 20-year
GWP for methane to appropriately
prioritize methane reductions. The
commenters asserted that despite its
prevalence, relying on GWP–100 is
arbitrary and lacks scientific basis. To
support this position, one commenter
further asserted that the IPCC does not
specifically recommend the use of
GWP–100, or any other specific metric
for the conversion of non-CO2 GHG
emissions into CO2 equivalents. The
commenter also noted recent adoptions
of a 20-year GWP by individual States
and asserted that other policymakers
5 Some of the proposed regulations related to
recapture and substantiation are relevant only to
section 48E and not section 45Y. Those rules are
discussed separately later.

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recognize the urgency to incorporate the
use of the 20-year GWP to accelerate
efforts towards reducing methane
emissions.
After consideration of the comments
the Treasury Department and the IRS
decline to modify the proposed
definition of the term ‘‘CO2e per kWh.’’
GWP–100 is a commonly accepted
standard that appropriately captures the
GWP of relevant GHGs and it is the
internationally accepted standard for
reporting GHG emissions. Specifically,
the AR5 GWP–100 is required for all
nations reporting national GHG
emissions inventories to the United
Nations Framework Convention on
Climate Change (UNFCCC).
Additionally, the use of a GWP–100 is
consistent with the use of GWP–100 to
calculate GHG emissions rates reported
to the EPA Inventory of U.S.
Greenhouse Gas Emissions and Sinks
(GHGI). The GHGI is one of the datasets
that proposed § 1.45Y–1(c)(4) requires to
confirm when the applicable year
threshold has been passed as required
by section 45Y(d). The Treasury
Department and the IRS view a uniform
standard for GWP that is consistent
across GHGs as necessary for evaluating
the GWP of different GHGs for purposes
of the section 45Y and 48E credits. An
approach that uses different GWP time
horizons for different types of GHGs
would not provide a consistent basis for
evaluating GHG emissions rates.
Therefore, proposed § 1.45Y–5(b)(1) will
be adopted without change.

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2. Combustion
Section 45Y(b)(2)(B) provides rules
for determining a GHG emissions rate
for a facility that produces electricity
through combustion or gasification.
Proposed § 1.45Y–5(b)(2) provided that
the term ‘‘combustion’’ means a rapid
exothermic chemical reaction,
specifically the oxidation of a fuel that
liberates energy including heat and
light. This proposed definition of
‘‘combustion’’ would include, for
example, burning fossil fuels, but it
would not include the reaction that
produces electricity from hydrogen
inside a hydrogen fuel cell. The
Treasury Department and the IRS
received no comments on the proposed
definition of ‘‘combustion’’ and the
definition will be adopted as proposed.
For discussion of the definition of
Facility which Produces Electricity
through Combustion or Gasification
(C&G Facility) see section VIII.A.4. of
this Summary of Comments and
Explanation of Revisions.

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3. Gasification
Proposed § 1.45Y–5(b)(3) provided
that the term ‘‘gasification’’ means a
thermochemical process that converts
carbon-containing materials into syngas,
a gaseous mixture that is composed
primarily of carbon monoxide, carbon
dioxide, and hydrogen. Commenters
expressed support for this definition
and it will be adopted without change.
For discussion of the definition of
Facility which Produces Electricity
through Combustion or Gasification
(C&G Facility) see section VIII.A.4. of
this Summary of Comments and
Explanation of Revisions.
4. Facility Which Produces Electricity
Through Combustion or Gasification
(C&G Facility)
Building on the definitions of
‘‘combustion’’ and ‘‘gasification’’
provided in the proposed regulations,
proposed § 1.45Y–5(b)(4) defined the
phrase ‘‘facility which produces
electricity through combustion or
gasification’’ (C&G Facility) in section
45Y(b)(2)(B) as a facility that produces
electricity through combustion or uses
an input energy source to produce
electricity, if the input energy source
was produced through a fundamental
transformation, or multiple
transformations, of one energy source
into another using combustion or
gasification. In the preamble to the
proposed regulations, the Treasury
Department and the IRS requested
comment on this proposed definition of
a C&G Facility, including comment on
whether the application of this
proposed interpretation should be
clarified with respect to any type of
fundamental transformation of an
energy source and any related activities
or operations.
Many commenters supported the
proposed definition of a C&G Facility.
Several commenters noted that the
proposed definition is a reasonable
interpretation of section 45Y(b)(2)(B)
because it reflects the reality that
electricity production can drive
combustion and gasification reactions
elsewhere in the production chain even
if those reactions are not occurring
directly at the electricity generation
facility. Other commenters supported
the proposed definition and noted that
section 45Y(b)(2)(B) provides the
appropriate statutory basis for looking at
transformations beyond the generation
facility to determine GHG emissions
from a C&G Facility. The commenters
asserted that this interpretation is
supported by two concepts within the
statutory language. First, the inclusion
of gasification in section 45Y(b)(2)(B)

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supports the proposed interpretation
because ‘‘gasification produces fuel not
electricity,’’ and, therefore, gasification
must be given independent meaning
from the term combustion. Second, the
commenters asserted that it is
appropriate to look at transformations
outside the generation facility because
the statute’s use of the word ‘‘through’’
requires looking at the larger electricity
production process to determine
whether electricity is produced
‘‘through’’ combustion or gasification. In
this context, the commenters noted that
‘‘through’’ means ‘‘because of,’’ ‘‘by
means of,’’ or ‘‘as a result of.’’ Therefore,
the commenters asserted that the plain
meaning of ‘‘through’’ is broad enough
to indicate that all the reactions leading
up to the production of electricity are
relevant in determining whether
electricity is produced through
gasification.
Some commenters questioned or
suggested revisions to the proposed
definition of the term C&G Facility.
Many of these commenters raised
questions and concerns regarding the
application of the proposed definition of
C&G Facility, particularly as applied to
fuel cells. Several commenters asserted
that the proposed definition of a C&G
Facility misinterprets the statute.
Commenters asserted that Congress
intended the determination of whether
a facility should be treated as being
described under section 45Y(b)(2)(B) to
be based on consideration of only the
activities occurring at the facility such
as a fuel cell itself, not a far-removed
process concerning a third-party fuel or
feedstock producer’s production
process, or inputs used in such process.
These commenters further asserted that
the proposed definition of C&G Facility
is not a credible reading of the statutory
reference to a ‘‘facility which produces
electricity through combustion or
gasification,’’ in section 45Y(b)(2)(B)
because that language should be
interpreted narrowly as requiring
consideration of facilities that engage in
combustion or gasification within the
facility itself, such as within a solid
oxide fuel cell. In other words, the
commenters suggested that
consideration of fuel production
processes occurring upstream from the
electricity-generating facility is not
relevant to determining whether a
facility is a ‘‘facility which produces
electricity through combustion or
gasification,’’ as provided in section
45Y(b)(2)(B).
Commenters also asserted that the
proposed definition would result in
most or all fuel cells being categorized
as C&G Facilities. The commenters
asserted that this categorization is

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erroneous and further asserted that fuel
cell GHG emissions are not directly
produced by the fundamental
transformation of the input energy
source into electricity. The commenters
stated that fuel cell systems, including
non-hydrogen fuel cells, use neither
combustion nor gasification to produce
electricity but are electrochemical
devices. Other commenters asserted that
at least a subset of fuel cells should be
unequivocally treated as Non-C&G
Facilities by drawing a comparison to
nuclear facilities. A commenter stated
that nuclear facilities (which are
categorized as Non-C&G Facilities by
proposed § 1.45Y–5(c)(2)) generally use
uranium fuel that is enriched, in part,
using grid electricity generated through
combustion.
Another commenter specifically noted
that fuel cells that directly use biogas or
renewable natural gas (RNG) do not
require combustion or gasification to
produce electricity because combustion
is not necessary to produce biogas or
RNG. As a result, the commenter
asserted that fuel cells utilizing biogas
or RNG should be categorized as NonC&G Facilities. After consultation with
the DOE, the Treasury Department and
the IRS note that in some cases, biogas
or RNG can be produced through
gasification or combustion. Therefore,
categorizing fuel cells that directly use
biogas or RNG as Non-C&G Facilities
would be improper.
Some commenters disagreed with the
proposed definition of C&G Facility
because of its application to hydrogen
fuel cells. These commenters requested
that if the proposed definition is
retained, the GHG emissions
determination for hydrogen used to
operate a fuel cell facility should follow
the carbon intensity standards provided
in section 45V of the Code. The
commenters asserted that this approach
would appropriately result in a
hydrogen fuel cell that uses ‘‘qualified
clean hydrogen’’ as defined in section
45V being considered a Non-C&G
Facility. Another commenter noted that
the proposed definition of combustion
and gasification included the entire
supply chain for hydrogen fuel cells and
recommended an alternative approach
to determining whether hydrogen fuel
cells produce electricity through
combustion. Under this alternative
approach, only transformations
happening at the fuel production and
generation facilities would be
considered and a full examination of the
supply chain would not be required.
The Treasury Department and the IRS
acknowledge that the preamble to the
proposed regulations addressed the
application of the definition of a C&G

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Facility to fuel cells by explaining that,
under proposed § 1.45Y–5(b)(4), a
facility that produces electricity using
any fuel that was produced using
electricity that had been produced, in
whole or in part, from the combustion
of fossil fuels would be considered a
C&G Facility. Thus, because the energy
transformation that produces electricity
in a fuel cell would not be considered
combustion under the definition in
proposed § 1.45Y–5(b)(2), a fuel cell
facility would only be considered a C&G
Facility if the fuel it used to produce
electricity was produced through
combustion or gasification under the
proposed regulations.
The Treasury Department and the IRS
generally agree with the commenters’
rationale for retaining the proposed
definition of the term C&G Facility but
view certain modifications to this
definition as appropriate to address
some of the concerns raised by other
commenters. To appropriately give
effect to the term ‘‘gasification’’ in
section 45Y(b)(2)(B), consideration of
transformations beside the
transformation directly producing
electricity are necessary in determining
the appropriate classification of a
facility as a C&G Facility. Congress’s use
of the word ‘‘through’’ in section
45Y(b)(2)(B) indicates that the steps
leading up to the production of
electricity by a C&G Facility are relevant
in determining whether electricity is
produced through combustion or
gasification. However, requiring an
evaluation of whether a fuel or
feedstock used by an electricitygenerating facility involved combustion
or gasification at any point of the fuel
or feedstock supply chain would be
difficult to administer, particularly
given the complexity of such supply
chains. To enable the section 45Y and
48E credits to be administered, the
Treasury Department and the IRS are
limiting the analysis of production
‘‘through combustion or gasification’’ to
the electricity production itself and the
production of the input energy source.
The Treasury Department and the IRS
continue to view proposed § 1.45Y–
5(b)(4) as reflecting the best
interpretation of the term ‘‘facility that
produces electricity through combustion
or gasification’’ in section 45Y(b)(2)(B).
However, after consideration of the
comments and the administrability
challenges the proposed definition may
pose, the final regulations revise the
definition of the term ‘‘facility that
produces electricity through combustion
or gasification’’ to ‘‘a facility that
produces electricity through combustion
or uses an input energy source to
produce electricity, if the input energy

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source was produced through a
fundamental transformation of one
energy source into another using
combustion or gasification.’’
Under the revised definition in these
final regulations, a hydrogen fuel cell
would still be considered a C&G Facility
if it produced electricity using hydrogen
that was produced through combustion
or gasification, for example through
steam methane reforming. A fuel cell
facility such as a solid oxide fuel cell,
which uses methane as fuel, would also
still be considered a C&G Facility,
because the methane reforming reaction
that produces syngas within the fuel cell
prior to the production of electricity
would be considered a gasification
reaction. In contrast, a hydrogen fuel
cell facility using hydrogen produced
using electrolysis would not be
considered a C&G Facility, because the
input energy source was not produced
through a transformation of one energy
source into another using combustion or
gasification. This modified definition of
C&G Facility is consistent with section
45Y(b)(2)(B) because it gives appropriate
effect to the word ‘‘gasification’’ and
considers whether the facility produces
electricity through combustion or
through the use of a fuel produced using
combustion or gasification in
determining the net GHG emissions rate
for the qualified facility in the
production of electricity. Considering
only the process that produced the
input energy source that is used by a
facility to generate electricity
implements section 45Y(b)(2)(B)’s
directive to assess whether electricity
was produced ‘‘through combustion or
gasification’’ while addressing
significant administrability concerns
posed by the task of tracing complex
fuel and feedstock supply chains
beyond the production of the input
energy source to assess whether they
involved combustion or gasification.
5. Non-C&G Facility
Proposed § 1.45Y–5(b)(7) defined a
‘‘Non-C&G Facility’’ as a facility that
produces electricity and is not described
in proposed § 1.45Y–5(b)(4). Generally,
commenters supported the proposed
definition of a ‘‘Non-C&G Facility.’’
Several commenters requested that the
final regulations remove the terms ‘‘C&G
Facility’’ and ‘‘Non-C&G Facility’’ in
favor of the term ‘‘qualified facility.’’
Section 45Y(b)(2)(A) specifically
provides rules to determine the GHG
emissions rate for a Non-C&G Facility
and section 45Y(b)(2)(B) provides
similar rules for a C&G Facility. As a
result, the Treasury Department and the
IRS view the proposed definitions of a
‘‘Non-C&G facility’’ and a ‘‘C&G

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Facility’’ as required to implement the
distinct requirements provided in
section 45Y(b)(2)(A) and (B). An
electricity-generating facility must be a
qualified facility to be eligible for the
credits provided under section 45Y or
48E but categorizing a facility as a C&G
Facility or a Non-C&G Facility is
required for purposes of section
45Y(b)(2)(A) and (B). The proposed
definition of the term ‘‘Non-C&G
Facility’’ is therefore adopted as
proposed.

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6. Greenhouse Gas Emissions Rate
Proposed § 1.45Y–5(b)(5) provided
that, consistent with section
45Y(b)(2)(A), the term ‘‘greenhouse gas
emissions rate’’ means the amount of
GHGs emitted into the atmosphere by a
facility in the production of electricity,
expressed as grams of CO2e per kWh.
Several commenters requested that the
definition of ‘‘greenhouse gas emissions
rate’’ be expanded to take account of
emitted co-pollutants such as
particulate matter, nitrogen oxides, and
sulfur dioxides. Some commenters
noted that, because of their effect on
local air quality, environmental justice
communities are significantly impacted
in the near term by the co-pollutants of
energy generation in addition to the
impact of GHGs. The commenters
further noted that increased and
prolonged exposure to co-pollutants
results in increased local air pollution
and the development of a plethora of
diseases, from skin conditions to cancer.
The commenters asserted that copollutant emissions must be integrated
into all GHG emissions rate calculations
to view emissions holistically and
understand and account for both climate
impacts and human health impacts. The
commenters further asserted that this
approach would ensure that electricity
production does not contribute to
climate change and global GHG
emissions and does not increase the
levels of local air pollution.
Section 45Y(e)(2) defines the term
‘‘greenhouse gas’’ as having the same
meaning given such term under section
211(o)(1)(G) of the Clean Air Act (CAA)
(42 U.S.C. 7545(o)(1)(G)), as in effect on
August 16, 2022. Pollutants or gases that
are described in 42 U.S.C. 7545(o)(1)(G)
are already treated as GHGs under
sections 45Y and 48E. However,
pollutants or gases that are not
described in 42 U.S.C. 7545(o)(1)(G)
may not be treated as GHGs under
section 45Y or 48E and any requests to
do so cannot be adopted. Therefore,
proposed § 1.45Y–5(b)(5) will be
adopted without change.

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7. Greenhouse Gases Emitted Into the
Atmosphere by a Facility in the
Production of Electricity
Proposed § 1.45Y–5(b)(6) provided
that, for purposes of section
45Y(b)(2)(A), and for both C&G
Facilities and Non-C&G Facilities, the
term ‘‘greenhouse gases emitted into the
atmosphere by a facility in the
production of electricity’’ means
emissions from a facility that directly
occur from the process that transforms
the input energy source into electricity.
Proposed § 1.45Y–5(b)(6)(i) through (vi)
provided a list of certain GHG emissions
associated with a facility and relevant
electricity production process excluded
from the definition in proposed
§ 1.45Y–5(b)(6) (for example, GHG
emissions associated with facility
siting). For Non-C&G Facilities only,
proposed § 1.45Y–5(c)(1)(i) provided
additional types of excluded emissions
associated with a facility and relevant
electricity production process (for
example, emissions occurring due to
activities and operations occurring offsite such as the production and
transportation of fuels used by the
facility). For C&G Facilities only,
proposed § 1.45Y–5(d)(2) provided
additional rules on included and
excluded GHG emissions associated
with a facility and relevant electricity
production processes that apply in order
to conduct a GHG emissions lifecycle
analysis (LCA) as required by section
45Y(b)(2)(B). The Treasury Department
and the IRS received a wide range of
comments in response to the definition
of ‘‘greenhouse gases emitted into the
atmosphere by a facility in the
production of electricity’’ at proposed
§ 1.45Y–5(b)(6).
One commenter suggested that the
final regulations clarify which
emissions (both direct and indirect)
must be included (rather than excluded)
in determining GHG emissions. The
Treasury Department and the IRS note
that the proposed definition would
include emissions that occur from the
processes that transform the input
energy source into electricity. This
definition provides a standard for
determining included emissions that
may be applied to multiple types of
facilities that may be eligible for the
section 45Y and 48E credits. However,
the Treasury Department and the IRS
have made modifications to the
proposed standard for determining
included emissions to further clarify the
principles outlined in the proposed
regulations.
Several commenters requested
additions to the list of excluded
emissions. A commenter requested an

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exclusion for emissions from standby
and auxiliary power for critical
infrastructure that is not used directly
for the production of an input used to
produce electricity. Proposed § 1.45Y–
5(b)(6)(i) and these final regulations
provide that emissions from electricity
production by back-up or auxiliary
generators that are primarily used in
maintaining critical systems in case of a
power system outage or for supporting
restart of a generator after an outage
would be excluded. The Treasury
Department and the IRS would
generally consider standby and
auxiliary power systems to fall within
this exclusion. This commenter also
requested an exclusion for emissions
offset by indirect financial or ‘‘book’’
accounting methods, including but not
limited to, renewable energy certificates
and environmental attribute certificates
that demonstrate a carbon intensity no
greater than 0 kg CO2e per unit of
output. Whether indirect or book-andclaim accounting methods are permitted
is addressed in section VIII.E.4.d. of this
Summary of Comments and Explanation
of Revisions and whether offsets are
permitted is addressed in section
VIII.C.2.d of this Summary of Comments
and Explanation of Revisions.
Another commenter requested that
emissions associated with various
processes related to the production of
electricity from stationary fuel cells be
excluded from the scope of assessed
emissions. The commenter specifically
requested that this exclusion cover
upstream emissions occurring due to the
production of fuels, including hydrogen,
methane, RNG, and other hydrocarbons,
for stationary fuel cell systems; and
emissions related to the production or
refinement of fuel for stationary fuel cell
systems, such as steam reformation,
whether or not such processes are
internal reactions. This commenter also
requested an exclusion for emissions
associated with the distribution of
hydrogen to consumers. The Treasury
Department and the IRS decline to
adopt these requested revisions to the
proposed definition of the term
‘‘greenhouse gases emitted into the
atmosphere by a facility in the
production of electricity.’’ Because the
final regulations provide rules that may
result in fuel cells being categorized as
either a C&G Facility or a Non-C&G
Facility depending on its operations and
the fuel it uses to produce electricity,
which would entail different rules for
assessing emissions, it would not be
appropriate to provide fuel-cell-specific
emissions exclusions applicable to all
categories of fuel cells. In addition,
some of the exclusions requested by the

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commenter would inappropriately
deviate from the requirement in section
45Y(b)(2)(B) to take into account
lifecycle GHG emissions, as described in
42 U.S.C. 7545(o)(1)(H). The final
regulations thus do not adopt the
changes recommended by the
commenter.
Commenters requested other changes
to the list of excluded emissions.
Several commenters supported
excluding emissions from backup
generators, step-up transformers, routine
operational and maintenance activities,
construction, infrastructure, and
distribution associated activities from
the definition. Other commenters voiced
concerned about the breadth of
emissions excluded from the proposed
definition for certain activities. A
commenter asserted that the definition
improperly excluded emissions from the
activities listed in proposed § 1.45Y–
5(b)(6)(i) through (vi). The commenter
noted that each of these activities are
critical steps in electricity generation,
production, and distribution. As an
example, the commenter noted that if
operational and maintenance activities
are disrupted, an energy producing
facility may need to shut down and
pause production. Therefore, the
commenter asserted that routine
maintenance is a vital component to
electricity generation. Additionally,
several commenters specifically
opposed the exclusion of emissions
from infrastructure associated with a
facility, including, but not limited to,
emissions from road construction for
feedstock production. A commenter
noted that road construction generates
substantial emissions from the clearing
of vegetation, ground disturbance, and
equipment operation. Commenters
asserted that GHG emissions from these
activities must be factored into the
definition of the GHG emissions rate.
Several commenters asserted that the
breadth of the exclusions proposed was
too narrow. A commenter specifically
disagreed with the scope of the
exclusion for emissions from electricity
production by back-up generators that
are primarily used in maintaining
critical systems in case of a power
system outage or for supporting restart
of a generator after an outage. The
commenter asserted that the proposed
definition includes emissions from
back-up generators used to avoid system
outages while only excluding emissions
that occur during or after an outage. The
commenter stated that as a result, this
exclusion could significantly limit the
time period during which a qualified
facility could be eligible for the section
45Y and 48E credits.

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The Treasury Department and the IRS
decline to modify the list of excluded
emissions as requested by these
commenters. The excluded emissions
are appropriate in scope because they
address emissions associated with
activities that are ancillary to the
electricity generating operations of a
facility. Excluding emissions from
contingency operations, operations that
are tangentially related to the regular
electricity generating operations of a
facility, or activities that are beyond the
scope of the production of electricity
(for example, emissions from
construction of a facility or distribution
of the electricity) allows for a more
accurate evaluation of the emissions
stemming from a facility’s production of
electricity and related processes.
Although the activities covered by these
exclusions (such as construction,
routine maintenance, or distribution)
may in fact enable a facility to generate
electricity, these activities are ancillary
to the process of generating electricity
and the final regulations retain the list
of excluded emissions as originally
proposed.
B. Determining GHG Emissions Rates for
Non-C&G Facilities
1. General Rules
Proposed § 1.45Y–5(c) provided rules
for determining a GHG emissions rate
for Non-C&G Facilities, including for
determinations by the Secretary when
publishing the table described in section
45Y(b)(2)(C)(i) or by the Secretary when
determining a provisional emissions
rate under section 45Y(b)(2)(C)(ii).
Proposed § 1.45Y–5(c)(1)(i) provided
that, with respect to Non-C&G Facilities
only, GHG emissions that are not
directly produced by the fundamental
transformation of the input energy
source into electricity are excluded from
the emissions accounting. The proposed
regulations excluded emissions that
may relate to a Non-C&G Facility but do
not occur ‘‘in the production of
electricity’’ as specified in section
45Y(b)(2)(A) because such emissions do
not arise directly from the
transformation of the input energy
source into electricity. Proposed
§ 1.45Y–5(c)(2) provided a list of
specific types or categories of facilities
that are Non-C&G Facilities with a GHG
emissions rate that is not greater than
zero. The Treasury Department and the
IRS received a number of comments on
this proposed provision, including
several in support of it.
While one commenter requested that
these Non-C&G Facilities be listed in the
Secretary’s Annual Table as having a
GHG emissions rate that is not greater

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than zero, another recommended that
the Treasury Department and the IRS
confirm that inclusion of these types or
categories of facilities in the Annual
Table or PER certification described in
proposed § 1.45Y–5(f) and (g) are not
required for such listed facilities. The
Treasury Department and the IRS
confirm that taxpayers may rely on the
inclusion of these types or categories of
facilities in these final regulations as
having a GHG emissions rate that is not
greater than zero unless and until the
regulations are amended.
The Treasury Department and the IRS
received a variety of comments
regarding the inclusion of specific
technologies in proposed § 1.45Y–
5(c)(2), which are discussed in sections
VIII.B.2. through 6. of this Summary of
Comments and Explanation of Revisions
by type of technology.
2. Nuclear
Several commenters expressed their
support for the inclusion of nuclear
fission and nuclear fusion facilities as a
type or category of facility that is a NonC&G Facility with a GHG emissions rate
of not greater than zero in proposed
§ 1.45Y–5(c)(2)(vi) and (vii). One
commenter recommended clarification
of why the use of electricity, which may
be produced through combustion and
gasification, to enrich uranium and
produce nuclear fuel would not render
nuclear energy a C&G Facility. Based on
the definition of a facility that produces
electricity through combustion or
gasification provided in § 1.45Y–5(b)(4),
only the fundamental transformations of
energy from one energy source into
another are considered when
determining whether a facility uses
combustion or gasification. In the case
of nuclear fission and nuclear fusion
facilities, the fundamental
transformations of energy are the
conversion of nuclear binding energy in
the nuclear fuel into heat and
electricity. Nuclear fuel often contains
uranium, which may require
enrichment. However, the energy used
to enrich the uranium only increases the
concentration of the isotope needed for
nuclear fuel. It does not transform the
energy in the isotope, and accordingly,
it does not transform one energy source
into another. Therefore, enrichment is
not considered when determining
whether a facility is a C&G Facility.
Because there is no other process in the
production of enriched uranium or
nuclear energy that would involve
combustion or gasification, the final
regulations retain nuclear fission as a
type or category of facility that is a NonC&G Facility.

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Some commenters who supported this
inclusion asked that the final
regulations amend the reference to
‘‘nuclear fusion’’ in proposed § 1.45Y–
5(c)(2)(vii) to reduce confusion with
nuclear fission. These commenters
noted that Congress recently enacted the
ADVANCE Act of 2024, Public Law
118–67, which included a definition of
‘‘fusion energy machine’’ within the
Atomic Energy Act and asked that the
final regulations amend proposed
§ 1.45Y–5(c)(2)(vii) to align with that
terminology. The Treasury Department
and the IRS agree that the term ‘‘nuclear
fusion’’ in proposed § 1.45Y–5(c)(2)(vii)
should be amended and adopt one
commenter’s suggestion that the new
term be ‘‘fusion energy.’’ The final
regulations under § 1.45Y–5(c)(2)(vii)
reflect this change.

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3. Hydropower
Proposed § 1.45Y–5(c)(1)(i)(A) and (B)
provided that in the case of Non-C&G
Facilities, emissions from hydropower
reservoirs due to anoxic conditions and
ebullitive, diffuse, and degassing
emissions from hydropower operations
are not GHGs emitted into the
atmosphere by a facility in the
production of electricity. Proposed
§ 1.45Y–5(c)(1)(i) explained that these
emissions are not directly produced by
the fundamental transformation of the
input energy source into electricity.
Some commenters stated that the
Treasury Department and the IRS erred
in excluding the emissions related to
hydropower as described in proposed
§ 1.45Y–5(c)(1)(i)(A) and (B). These
commenters stated that, because the
language in section 45Y(b)(2)(A)
provides that a GHG emissions rate
means the amount of GHGs emitted into
the atmosphere by a facility in the
production of electricity, the exclusion
of such emissions because they are not
‘‘directly produced by the fundamental
transformation of the input energy
source into electricity’’ by the facility is
flawed. Several commenters noted that
hydropower facilities do in fact result in
GHG emissions that are directly
produced by the fundamental
transformation of the input energy
source into electricity within the
meaning of proposed § 1.45Y–5(c)(1)(i).
The commenters noted that a reservoir,
which is an integral component of a
hydropower facility, is one of the
primary sources of emissions because
they emit GHGs due to the
decomposition of organic matter
through diffusion and ebullition.
Accordingly, the commenters asserted
that such emissions should not be
excluded for hydropower facilities.

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Another commenter stated that
degassing emissions that result from
water passing through a turbine in a
hydropower facility are part of the
‘‘fundamental transformation of [the
input energy source into] electricity,’’
because the kinetic energy of flowing
water passing through turbines is
harnessed to produce electricity. The
GHGs that may be released during
degassing exist before flowing water
passes through turbines that are
harnessed to create electricity. Such
methane is therefore not directly
produced or created by flowing water
passing through turbines. In addition,
the GHGs associated with degassing
may have been emitted passively into
the atmosphere even in the absence of
hydropower electricity generation. For
these reasons, the Treasury Department
and the IRS affirm that GHGs released
during degassing are properly excluded
because they are not directly produced
by the fundamental transformation of
the input energy source into electricity.
The Treasury Department and the IRS
have determined that the proposed
treatment of emissions accounting for
hydropower is appropriate and the best
implementation of section 45Y(b)(2)(A).
A hydropower facility converts the
kinetic energy of flowing water into
electricity with a turbine that spins a
rotor within a generator to produce
electricity. GHGs may be released from
the hydropower reservoir due to
diffusion at the water surface or due to
ebullition, and from degassing from
water passing through a pump house or
turbine. The GHGs that may be released
during degassing exist before flowing
water passes through turbines that are
harnessed to create electricity. Such
GHGs are therefore not directly
produced or created by flowing water
passing through turbines. In addition,
the GHGs associated with degassing
may be emitted passively into the
atmosphere even in the absence of
hydropower electricity generation. It is
not appropriate to treat such emissions
as GHGs emitted into the atmosphere by
a hydropower facility in the production
of electricity because these emissions
are not created by the fundamental
transformation of potential energy in
flowing water into electricity.
Some commenters stated that because
dams and reservoirs are required
components of hydropower facilities in
order for such facilities to generate
energy, GHG emissions associated with
these components should not be
excluded from emissions accounting.
The Treasury Department and the IRS
have determined that GHG emissions
associated with dams and reservoirs are
properly excluded emissions. Emissions

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associated with the construction and
maintenance of such dams and
reservoirs are properly excluded under
proposed § 1.45Y–5(b)(6)(iv), which
states, in relevant part, that emissions
that occur before commercial operations
commence are properly excluded.
Furthermore, emissions associated with
the continued existence of such dams or
reservoirs are properly excluded
because they are not directly produced
by the fundamental transformation of
the input energy source into electricity
within the meaning of proposed
§ 1.45Y–5(c)(1)(i).
Commenters also had varied reactions
to the inclusion of hydropower as a type
or category of Non-C&G Facility with a
GHG emissions rate of not greater than
zero in proposed § 1.45Y–5(c)(2)(ii).
Many commenters supported the
proposed designation of and rationale
for treating hydropower as a type or
category of Non-C&G Facility with a
GHG emissions rate of not greater than
zero. For the reasons summarized earlier
in this section, the Treasury Department
and the IRS agree with these
commenters that the fundamental
energy transformation of kinetic energy
into electricity does not result in GHGs
emitted in the production of electricity.
Some commenters, however,
questioned this proposed treatment of
hydropower by questioning the
excluded emissions rules in proposed
§ 1.45Y–5(c)(1)(i)(A) and (B), citing
aspects of hydropower operations that
they asserted give rise to emissions from
a hydropower facility’s production of
electricity. For the reasons summarized
earlier in this part of the Summary of
Comments and Explanation of
Revisions, the Treasury Department and
the IRS disagree with these commenters.
One commenter opposed to this
proposed treatment of hydropower
stated that hydropower causes adverse
ecological impacts and recommended
that facilities be eligible for the credit
based not only on whether they have a
GHG emissions rate that is not greater
than zero but also on whether they have
an ‘‘environmentally low impact’’ more
generally.
Section 45Y(b)(1) defines a qualified
facility, in relevant part, as a facility
used for the generation of electricity,
placed in service after December 31,
2024, and for which the GHG emissions
rate is not greater than zero. The statute
does not provide the Treasury
Department and the IRS the authority to
consider environmental impacts beyond
GHG emissions rates in determining
eligibility for the section 45Y and 48E
credits. Therefore, the final regulations
do not adopt the commenter’s
suggestion.

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4. Waste Energy Recovery Property
(WERP)
Proposed § 1.45Y–5(c)(2)(viii)
provided that waste energy recovery
property (WERP) that derives energy
from a source described in proposed
§ 1.45Y–5(c)(2)(i) through (vii) is a NonC&G Facility with a GHG emissions rate
that is not greater than zero. The
preamble to the proposed regulations
explained that WERP is property that
generates electricity solely from heat
from buildings or equipment if the
primary purpose of such building or
equipment is not the generation of
electricity. In the preamble to the
proposed regulations, the Treasury
Department and the IRS requested
comment on this proposed definition
and on whether and why it would be
appropriate to revise proposed § 1.45Y–
5(c)(2)(viii) to include additional energy
sources (such as energy from exothermic
chemical reactions or pressure drop
technologies) that do not rely on
combustion or gasification but could
include equipment related to the
transport of fossil fuels (for example,
natural gas).
Some commenters supported the
proposed definition of WERP. One
commenter stated that this longstanding definition is appropriate for
the purpose of the section 45Y and 48E
credits and would provide taxpayers
with strong incentives to install WERP
to produce electricity using heat that
would otherwise be wasted. The
commenter further noted that this
definition would also prevent facilities
whose primary purpose is to generate
electricity from ‘‘double dipping’’ by
taking a tax credit on the original
electricity generated and again on
electricity generated from WERP.
Some commenters requested that
facilities using exothermic reactions or
pressure drop technologies be included
in the definition of WERP for purposes
of the section 45Y and 48E credits.
Additionally, these commenters
asserted that these types of technologies
do not rely on combustion or
gasification and thus could and should
be classified as Non-C&G Facilities. A
commenter further recommended that
GHG emissions that occur with respect
to exothermic reactions or pressure drop
technologies (for example,
turboexpanders on a pipeline) that do
not rely on combustion or gasification
should be treated as Non-C&G Facilities
and any significant direct or indirect
emissions should be accounted for.
Other commenters suggested that the
final regulations revise proposed
§ 1.45Y–5(c)(2)(viii) to include
additional energy sources (such as

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energy from exothermic chemical
reactions or pressure drop technologies)
that do not rely on combustion or
gasification but could include
equipment related to the transport of
fossil fuels (for example, natural gas).
The Treasury Department and the IRS
have determined that the final
regulations should not be revised to
explicitly include these additional types
of facilities as WERP, which is included
as a Non-C&G Facility at § 1.45Y–
5(c)(2)(viii). Because some facilities that
employ exothermic reactions release
energy into the environment in the form
of heat via combustion, it would not be
appropriate to classify all WERP
facilities using exothermic reactions as
Non-C&G Facilities.
Pressure drop technologies are also
not appropriately considered WERP for
purposes of the section 45Y and 48E
credits because they convert pressure,
rather than heat, directly to electricity.
As a result, this type of technology does
not fall within the definition of WERP
provided in the preamble to the
proposed regulations. At this time, this
type of technology is also not included
within the list of certain Non-C&G
Facilities with a GHG emissions rate
that is not greater than zero provided at
§ 1.45Y–5(c)(2). The preamble to the
proposed regulations defined WERP as
property that generates electricity solely
from heat from buildings or equipment
if the primary purpose of such building
or equipment is not the generation of
electricity. This definition of WERP is
appropriate for the purposes of the
section 45Y and 48E credits because it
mirrors the statutory definition
provided in section 48(c)(5)(A). As a
result, these final regulations add the
definition of WERP, as provided in the
preamble to the proposed regulations, to
§ 1.45Y–1(a)(12) and to § 1.48E–1(a)(12).
The Treasury Department and the IRS
also received a number of comments
recommending that the final regulations
provide that all WERP be included in
the list of Non-C&G Facilities with a
GHG emissions rate that is not greater
than zero at § 1.45Y–5(c)(2). The
Treasury Department and the IRS have
determined that because many of the
energy sources for WERP rely on
combustion or gasification, it would not
be appropriate to classify all WERP
facilities as Non-C&G Facilities because
some WERP facilities produce
electricity using an input energy source
that was produced through a
fundamental transformation of one
energy source into another using
combustion or gasification. WERP
facilities that produce electricity
through combustion or gasification
would be considered C&G Facilities and

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can be evaluated for inclusion in the
Annual Table or for a PER as described
later in section VIII.H. of this Summary
of Comments and Explanation of
Revisions.
One commenter recommended that
the definition of WERP be amended to
allow for the use of waste heat to create
thermal energy. However, section
45Y(b)(1)(A)(i) requires a facility to be
‘‘used for the generation of electricity’’
to be considered a qualified facility that
is eligible for the section 45Y and 48E
credits and section 45Y(a)(1)(A)
provides that the credit is granted on the
basis of the electricity produced by a
qualified facility. The facilities
described by the commenter do not
produce electricity, so they would not
qualify on that basis. The Treasury
Department and the IRS do not have
authority under the statute to expand
the scope of eligible facilities as
requested by the commenter. The final
regulations thus adopt the provisions of
proposed § 1.45Y–5(c)(2)(viii) and the
proposed definition of WERP without
modification. To aid taxpayers in
determining whether a specific facility
meets that definition, the final
regulations include examples in
§ 1.45Y–1(a)(12) that illustrate buildings
or equipment the primary purpose of
which is not the generation of
electricity. These examples remain
largely the same as those provided in
the preamble of the proposed
regulations, but, for clarity, pipeline
compressor stations have not been
included in the examples in the final
regulations. While pipeline compressor
stations are buildings or equipment the
primary purpose of which is not the
generation of electricity, they do not
generate electricity solely from heat and
thus are not appropriately considered
WERP.
5. Geothermal
Proposed § 1.45Y–5(c)(2)(v) provided
that facilities using geothermal energy,
including flash and binary plants, were
Non–C&G Facilities with a GHG
emissions rate that is not greater than
zero. The Treasury Department and the
IRS requested comment on whether the
identification of flash geothermal
facilities as Non–C&G Facilities with a
GHG emissions rate that is not greater
than zero in proposed § 1.45Y–5(c)(2)(v)
was appropriate.
Several commenters supported the
inclusion of geothermal facilities in
proposed § 1.45Y–5(c)(2)(v), with some
noting that inclusion of these facilities
on this list is appropriate because the
carbon dioxide emitted by the
geothermal facility is emitted naturally
and passively from geothermal

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reservoirs. Commenters noted that some
emissions often occur even without a
geothermal facility in place.
One commenter stated that the
Treasury Department and the IRS
should consider measuring the
incremental emissions associated with
the production of electricity at flash
geothermal facilities as compared to the
emissions occurring without such
production. The Treasury Department
and the IRS have determined that such
measurement will not be required in the
final regulations. As described in the
preamble to the proposed regulations,
such emissions from flash geothermal
facilities would not be considered GHGs
emitted into the atmosphere by a facility
in the production of electricity under
proposed § 1.45Y–5(c)(1)(i)(C), because
the GHGs are already present in the
underground water and are not created
by the fundamental transformation of
the thermal energy in the water into
electricity, but rather by processes that
are not fundamental to the
transformation of the thermal energy
into electricity. This proposed treatment
of flash geothermal facilities is also
supported by surveys indicating that
underground carbon dioxide in certain
geothermal reservoirs is emitted
passively into the atmosphere even in
the absence of geothermal electricity
generation. Furthermore, such
measurement may not be possible given
the challenges associated with
quantifying emissions from geothermal
sites with and without electricity
production facilities. Therefore,
proposed § 1.45Y–5(c)(2)(v) is adopted
without change.
6. Solar Technologies
Concentrated solar power facilities
may have auxiliary burners that in some
cases use combustion exclusively for the
purposes of cold starts or freeze
protection of thermal working fluids,
but in other cases, may also be used to
generate electricity in hybrid
configurations. The Treasury
Department and the IRS requested
comment on whether the existing
definitions of C&G Facility and NonC&G Facility are sufficient to
distinguish between these two
categories of facilities, or whether
additional clarification is needed.
One commenter requested that the
Treasury Department and the IRS clarify
that the use of auxiliary burners at a
concentrated solar power (CSP) facility
does not necessarily mean that a facility
will be considered a C&G Facility. This
commenter stated that CSP facilities
may have auxiliary burners that in some
cases use combustion exclusively for the
purposes of cold starts or freeze

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protection of thermal working fluids,
but in other cases, may also be used to
generate electricity in hybrid
configurations. As previously indicated
in the preamble to the proposed
regulations and reiterated here, in the
former instance, such use of auxiliary
burners would not mean that a facility
is properly categorized as a C&G
Facility. However, in the latter instance,
a facility would be producing electricity
through combustion within the meaning
of proposed § 1.45Y–5(b)(4) and thus
would be a C&G Facility.
C. GHG Emissions Rates for C&G
Facilities
1. Determining a Greenhouse Gas
Emissions Rate for C&G Facilities
Consistent with section
45Y(b)(1)(A)(iii), proposed § 1.45Y–
2(a)(3) provided that, for purposes of the
section 45Y credit, a qualified facility
must have a GHG emissions rate of not
greater than zero. Proposed § 1.45Y–5(d)
provided the rules applicable to the
Secretary for determining a net GHG
emissions rate for C&G Facilities,
including for publishing a table
described in section 45Y(b)(2)(C)(i) or
determining an emissions rate as
provided in section 45Y(b)(2)(C)(ii).
Proposed § 1.45Y–5(d)(1) provided,
consistent with section 45Y(b)(2)(B),
that the GHG emissions rate for a facility
that produces electricity through
combustion or gasification (C&G
Facility) equals the net rate of GHGs
emitted into the atmosphere by such
facility (taking into account lifecycle
GHG emissions, as described in 42
U.S.C. 7545(o)(1)(H)) in the production
of electricity, expressed as grams of
CO2e per kWh.
The Treasury Department and the IRS
received comments supporting these
proposed regulations and some
comments recommending alternative
approaches for evaluating the GHG
emissions rate of a C&G Facility. One
commenter recommended that the final
regulations apply a standard of
‘‘commercially acceptable practices’’ or
‘‘commercially reasonable practices’’ as
of the date of passage of the section 45Y
and 48E credits for inputs and
considerations in determining the LCA
of GHG emissions from a C&G Facility.
Other commenters recommended that
the final regulations not take into
account lifecycle GHG emissions in the
production of electricity for a C&G
Facility. Some commenters suggested
that the final regulations permit the
GHG emissions rate of a facility to be
greater than zero. The changes requested
by these commenters cannot be adopted
because they are not permitted by the

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statutory mandate to take into account
lifecycle GHG emissions for C&G
Facilities as required by section
45Y(b)(2)(B).
A number of commenters also
requested that certain types of C&G
Facilities be categorically deemed to
have a net GHG emissions rate of not
greater than zero in the final regulations.
Other commenters requested that
certain types of C&G Facilities be
categorically deemed to have a net GHG
emissions rate of greater than zero in the
final regulations. The Treasury
Department and the IRS decline to
adopt this request at this time.
Additional analysis is required to
achieve sufficient certainty that a type
or category of facility has a net GHG
emissions rate that is greater than or not
greater than zero as determined by an
LCA conducted in accordance with the
principles required under section
45Y(b)(2)(B) and these final regulations.
The Treasury Department and the IRS
note that many C&G Facilities using
particular technologies and fuel sources
are highly likely to have GHG emissions
rates that are greater than zero, whereas
other C&G Facilities with similar but
varied technologies or fuels may have
GHG emissions rates that are not greater
than zero. For example, review of
existing scientific and technical
literature indicates that C&G Facilities
that combust natural gas—such as
natural gas-fired boilers and combustion
turbines—are expected to have GHG
emissions rates greater than zero, even
with the use of carbon capture and
sequestration (CCS) technology, because
the LCA must consider emissions in the
fuel lifecycle prior to CCS through the
point of electricity production and the
rate of capture and sequestration of
carbon dioxide produced when
combusting the gas is not technically
capable of reaching 100 percent.6
However, subject to further analysis and
dependent on specific facts and
circumstances, there may be cases in
which a C&G Facility that uses a blend
of natural gas and other feedstocks that
have negative lifecycle emissions and
use CCS could potentially achieve
lifecycle GHG emissions not greater
than zero.
A number of commenters submitted
analyses or referred to studies
supporting their request that certain
6 See, e.g., National Renewable Energy Laboratory
(2021), Life Cycle Greenhouse Gas Emissions from
Electricity Generation: Update, NREL/FS–6A50–
80580, https://www.nrel.gov/docs/fy21osti/
80580.pdf; O’Donoughue, P.R., Heath, G.A., Dolan,
S.L. and Vorum, M. (2014), Life Cycle Greenhouse
Gas Emissions of Electricity Generated from
Conventionally Produced Natural Gas. Journal of
Industrial Ecology, 18: 125–144. https://doi.org/
10.1111/jiec.12084.

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types of C&G Facilities that burn
biomass be categorically deemed to have
a net GHG emissions rate of not greater
than zero in the final regulations. Some
of these comments state that biomass,
industrial wastes, or manufacturing
residuals used for generating electricity
have negative lifecycle GHG emissions.
The studies submitted in support of this
recommendation rely on studies that (i)
use assumptions that are not adopted in
this final rule, (ii) use assumptions that
are potentially specific to a particular
facility and thus are not appropriate for
use in evaluating the emissions rate for
a type or category of facility as listed in
the Annual Table without further study,
or (iii) do not consistently apply the
requirements for an LCA that are
required by these final regulations
pursuant to the statute. For example,
some of these studies consider grid
electricity displacement or fossil fuel
displacement, neither of which can be
considered in an LCA for electricity
generation from C&G Facilities as it is
outside of the LCA boundary. Moreover,
some studies do not take into account
the direct emissions and significant
indirect emissions outlined in § 1.45Y–
5(d)(2)(v)(A) and (B) or other
requirements finalized in this rule. The
Treasury Department and the IRS will
continue to consider all analysis
submitted by commenters in evaluating
the emissions of the relevant types or
categories of facilities. However, studies
that rely on assumptions or LCA
principles that are inconsistent with the
requirements of this final rule or those
within the underlying statute will be
given less weight. Several commenters
note that any LCA must include
rigorous modeling, carefully consider
assumptions, follow recognized
protocols, as well as apply consistent
principles. The Treasury Department
and the IRS agree that the principles
identified in these comments reflect
appropriate LCA practices.
Furthermore, as stated in the
preamble to the proposed regulations,
the Treasury Department and the IRS
intend to include in the Annual Table
the types or categories of facilities that
are described in the final regulations as
having a GHG emissions rate of not
greater than zero and intend to publish
the first Annual Table after the
publication of the final regulations. In
addition, the Treasury Department and
the IRS intend to include in the Annual
Table the types or categories of facilities
that are described in the final
regulations as having a GHG emissions
rate of greater than zero. Any types or
categories of facilities that are added or
removed from this list in the first

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publication of the Annual Table will be
accompanied by the publication of an
expert analysis of such change as
provided in proposed § 1.45Y–5(f)(2). If
any type or category of C&G Facility is
added to this list in the publication of
the Annual Table, the accompanying
expert analysis of the addition will
explain the basis for the lifecycle GHG
emissions analysis that has been
conducted to determine that a given
type or category of facility has a net
GHG emissions rate of not greater than
zero or greater than zero.
One commenter noted that the
proposed regulations assumed a binary
distinction between C&G Facilities and
Non-C&G Facilities and requested that
the final regulations clarify how the
rules for categorizing facilities would
apply in the case of fuel-switching
facilities such as linear generators. The
Treasury Department and the IRS have
determined that the classification of a
facility, such as a linear generator, that
may or may not produce electricity
through combustion or gasification
depends upon the fuel’s method of
production and whether the facility
does in fact produce electricity through
combustion or gasification, and this
assessment must be made separately for
each taxable year. A facility that uses a
fuel produced via combustion or
gasification in the production of
electricity any time during a given
taxable year is properly classified as a
C&G Facility for the duration of that
taxable year. For example, if a linear
generator exclusively uses hydrogen
produced with electrolysis or other fuels
not produced via combustion or
gasification during a taxable year, then
that linear generator would be a NonC&G Facility for that taxable year.
However, if in the production of
electricity, a facility uses a fuel
produced using combustion or
gasification (for example, steam
methane reforming) during a taxable
year, even if only to produce a portion
of the electricity generated that year,
that facility is a C&G Facility for that
year. Such facility’s status can change
from year to year depending on the fuel
it uses during a taxable year. The
Treasury Department and the IRS view
this scenario as analogous to the
treatment of WERP facilities and fuel
cells.
A few commenters recommended that
the net rate of GHGs emitted into the
atmosphere by a C&G Facility should
not take into account lifecycle GHG
emissions because there is no similar
requirement when calculating the GHG
emissions rate of Non-C&G Facilities.
Section 45Y(b)(2)(B) states that, ‘‘[i]n the
case of a facility which produces

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electricity through combustion or
gasification, the [GHG] emissions rate
for such facility shall be equal to the net
rate of [GHGs] emitted into the
atmosphere by such facility (taking into
account lifecycle GHG emissions, as
described in . . . 42 U.S.C.
7545(o)(1)(H))) in the production of
electricity, expressed as grams of CO2e
per kWh.’’ Because the requirement that
lifecycle GHG emissions be taken into
account for C&G Facilities is statutory
and does not apply to Non-C&G
Facilities, the final regulations cannot
implement this recommendation.
One commenter recommended that
C&G Facilities be subject to an
attributional LCA rather than a
consequential LCA. This commenter
stated that consequential models are
highly dependent on the assumptions
used, are more complex, and have more
uncertainty.
The Treasury Department and the IRS
have determined that a consequential
analysis is required to accurately assess
GHG emissions outcomes under section
45Y(b)(2)(B), which requires taking into
account lifecycle GHG emissions, as
described in 42 U.S.C. 7545(o)(1)(H). As
explained in the preamble to the
proposed regulations, in a 2010 noticeand-comment rulemaking establishing
the regulatory framework for the
updated renewable fuel standard (RFS)
program, the EPA interpreted 42 U.S.C.
7545(o)(1)(H) as requiring the agency to
account for the real-world emissions
consequences of increased production
of biofuels. The EPA determined that, in
the context of the RFS program, the
inclusion of ‘‘direct emissions and
significant indirect emissions such as
significant emissions from land-use
changes’’ in 42 U.S.C. 7545(o)(1)(H)
requires a ‘‘consequential’’ approach to
considering the real-world emissions
associated with biofuel production.
Such an approach includes
consideration of market interactions
induced by expanded biofuel
production and use that may result in
secondary or indirect greenhouse gas
emissions. The Treasury Department
and the IRS have determined it is
appropriate to adopt this interpretation
and overall approach in the context of
the section 45Y and 48E credits. The
Treasury Department and the IRS
further note that attributional analytical
approaches may be part of the broader
consequential analysis in appropriate
cases.
2. LCA Requirements
Proposed § 1.45Y–5(d)(2) provided
certain requirements for conducting an
LCA of GHG emissions for purposes of
the section 45Y and 48E credits. These

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requirements and responsive comments
are discussed in section VIII.C. of this
Summary of Comments and Explanation
of Revisions. See also section VIII.F.
(Carbon Capture and Sequestration) and
section VIII.E.4. (Use of Natural Gas
Alternatives) of this Summary of
Comments and Explanation of Revisions
for a discussion of responsive comments
addressing the requirements of
proposed § 1.45Y–5(d)(2) in relation to
those topics.
a. Starting Boundary
Proposed § 1.45Y–5(d)(2)(i) provided,
for the purposes of the section 45Y and
48E credits, a definition of the starting
boundary for an LCA involving
generation-derived feedstocks (such as
biogenic feedstocks) and for an LCA
involving extraction-derived feedstocks
(such as fossil fuel feedstocks).
One commenter expressed support for
the starting boundaries provided in the
proposed regulations. Another
commenter opposed the proposed
starting boundary, asserting that the
boundaries for a C&G Facility should be
the same as those for a Non-C&G
Facility. Because the statute requires
distinct treatment of a C&G Facility and
a Non-C&G Facility in assessing their
GHG emissions rate, the final
regulations do not adopt this
commenter’s request.
One commenter asserted that section
45Y is ‘‘limited by statute to the
boundaries of the electricity generation
facility (which may include carbon
capture equipment) but excludes
upstream and downstream emissions.’’
The Treasury Department and the IRS
have determined that the change
requested by this commenter would be
contrary to the statute because it would
fail to give effect to the requirement in
section 45Y(b)(2)(B) that the net rate of
GHG emissions for a C&G Facility take
into account lifecycle GHG emissions as
described in 42 U.S.C. 7545(o)(1)(H).
Therefore, the final regulations do not
adopt this commenter’s
recommendation.
Another commenter requested that
the final regulations clarify the activities
that constitute the starting boundary.
The commenter requested that the final
regulations provide a specific example
illustrating that the starting boundary
for biomass feedstock includes the
activities to grow the plant material. The
Treasury Department and the IRS have
determined that such activities are
sufficiently included within the
definition of starting boundary, and no
further examples are required within the
final regulations.
After consideration of all comments,
the Treasury Department and the IRS

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have determined that the final
definition of starting boundary should
be adopted without substantive change.
b. Ending Boundary
Proposed § 1.45Y–5(d)(2)(ii) provided,
for the purposes of the section 45Y and
48E credits, that the ending boundary of
the LCA for electricity that is
transmitted to the grid or electricity that
is used on-site is the meter at the point
of electricity production at a C&G
Facility. The use of such electricity
generated by the C&G Facility (and what
other types of energy sources it
displaces), including emissions from
transmission and distribution, are
outside of the LCA boundary. For the
reasons provided in the preamble to the
proposed regulations, the distribution,
transmission, and use of such electricity
generated by a C&G Facility (and other
types of energy sources it may displace
while in use) are outside of the LCA
boundary, such emissions would not be
taken into account because they do not
occur in the ‘‘production of electricity’’
as described in section 45Y(b)(2)(B) but
rather occur in the distribution and use
of such electricity. The preamble to the
proposed regulations further explained
that this result is consistent with section
45Y(b)(2)(B) (and the term ‘‘ultimate
consumer’’ in 42 U.S.C. 7545(o)(1)(H) as
referenced therein) because it would
treat the C&G Facility as the ultimate
consumer of the fuel used to produce
electricity.
Several commenters supported the
ending boundary of the LCA provided
in the proposed regulations. Other
commenters requested that the ending
boundary of the LCA be extended to
take into the account circumstances in
which the emissions from a C&G
Facility or the emissions related to the
production of electricity available on
the grid are less than they would have
been in the absence of the credits
because of a facility’s use of a different
fuel or feedstock.
The Treasury Department and the IRS
have determined that extending the
ending boundary of the LCA as
requested by these commenters would
impermissibly shift the GHG emissions
rate inquiry from whether electricity
production at a C&G Facility has a net
GHG emissions rate of not greater than
zero to whether such facility has fewer
emissions than either (i) the emissions
the C&G Facility would have or did
have in the absence of the credit or (ii)
the marginal unit emissions of the grid
to which the facility is connected.
Conducting the LCA in such a manner
would conflict with the plain text of the
statute, which requires that the net rate
of GHGs emitted by a C&G Facility,

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considering lifecycle GHG emissions, in
the production of electricity not be
greater than zero.
Furthermore, the Treasury
Department and the IRS have
determined that the meter at the point
of electricity production at a C&G
Facility is an appropriate ending
boundary because eligibility for the
section 45Y and 48E credits depends on
the net rate of GHG emissions associated
with electricity production rather than
use. Extending the boundary beyond the
meter would consider activities that are
beyond the scope of electricity
generation which is beyond the scope of
these provisions. For these reasons and
the reasons further explained in section
VIII.C.2.f. of these Summary of
Comments and Explanation of
Revisions, the final regulations do not
adopt this request, and the definition of
ending boundary is adopted as
proposed. See section VIII.C.2.f. of these
Summary of Comments and Explanation
of Revisions for further discussion of the
interaction between the LCA ending
boundary, avoided emissions, and use
of a particular fuel or feedstock in the
generation of electricity in lieu of a fuel
or feedstock with a greater rate of GHG
emissions.
The Treasury Department and the IRS
further note that the ending boundary of
an LCA, as discussed earlier, is not
intended to limit the rules applicable to
carbon capture and sequestration. See
section VIII.F. of these Summary of
Comments and Explanation of Revisions
for further discussion of these carbon
capture and sequestration rules.
c. Baseline
Proposed § 1.45Y–5(d)(2)(iii) provided
that an LCA must be based on a future
anticipated baseline, which projects
future status quo in the absence of the
availability of the section 45Y and 48E
credits (taking into account anticipated
changes in technology, policies,
practices, and environmental and other
socioeconomic conditions).
The Treasury Department and the IRS
received comments on several aspects of
the proposed rule regarding an LCA
baseline. A number of commenters
recommended that an LCA baseline take
into account the relevant laws and
regulations already in place, including
any mitigation of emissions already
legally required. The Treasury
Department and the IRS have
determined that this recommendation is
already incorporated in the proposed
rule on LCA baselines, which project
the future status quo, including relevant
laws and regulations, in the absence of
the availability of the section 45Y and
48E credits. As such, a baseline would

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necessarily incorporate mitigation of
emissions already required, and the
effects of other law and regulations.
Accordingly, further clarification in the
final rule is unnecessary.
Some commenters supported the
proposed rule, while providing
recommendations on how to approach
the creation of an LCA future
anticipated baseline. For instance, one
commenter recommended considering
historical data and anticipated future
conditions under a business-as-usual
trajectory, incorporating key drivers and
trends to project future emissions; a
second commenter recommended a
dynamic, adaptive baseline that would
account for broader system effects such
as market dynamics; and a third
commenter recommended that the
baseline focus on the geographic
location of the facility to accurately
reflect local conditions and market
dynamics. The Treasury Department
and the IRS appreciate this feedback
and will consider these
recommendations at a later time as
development of LCA baselines
continues.
The Treasury Department and the IRS
also received comments specifically
addressing the approach to LCA
baselines for biomass feedstocks. One
commenter encouraged the use of
historical forest data to inform the
creation of a baseline, taking into
account longer growth cycles of forests,
drivers of regional forest management,
and economic factors. Another
commenter recommended that each
source of woody biomass have its own
LCA baseline. Finally, one commenter
recommended that the LCA baseline
take into account the current use of
pertinent feedstocks and existing
facilities.
The Treasury Department and the IRS
appreciate these recommendations and
have taken them into consideration.
However, given the diversity of fuels
and feedstocks that may be evaluated in
creating LCA baselines for the purposes
of the section 45Y and 48E credits, the
final regulations provide general
requirements for baseline development
but do not specify requirements for
specific fuels or feedstocks. Therefore,
the commenters’ specific
recommendations will not be included
in the final regulations, but they will be
considered in developing LCAs for
purposes of the section 45Y and 48E
credits in the future. Specific
recommendations related to LCA
baselines will be considered and
addressed as their development
continues.
Several commenters recommended
that the final regulations provide an

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LCA scenario design that compares a
future anticipated baseline with biomass
use to one without biomass use. The
Treasury Department and the IRS have
determined that this is not the most
appropriate scenario design with which
to assess GHG emissions pursuant to
45Y(b)(2)(B). Such a scenario would
model a situation in which the entirety
of the feedstock required for additional
electricity production comes from
additional removals of biomass
materials. The commenters’ suggestion
would mean testing impacts from only
one potential outcome at one end of a
range of potential real-world responses.
This contrasts with the scenario design
approach that considers more than one
likely scenario, which more accurately
assesses the various ways that feedstock
is sourced based on the supply options
and markets in a model. This design
approach is more accurate because, in
reality, biomass feedstocks for a facility
could be sourced from a variety of
sources, including being diverted from
other end uses. An LCA should reflect
best estimates of how and from where
biomass may be sourced taking into
account historical and future
anticipated feedstock, region, and
market specific conditions. The
Treasury Department and the IRS
therefore decline to include these
commenters’ recommendation in the
final regulations.
The Treasury Department and the IRS,
in consideration of the comments
received, have determined that certain
additional principles pertaining to LCA
baselines will be provided in the final
regulations. LCA future anticipated
baselines, which project future status
quo in the absence of the availability of
the section 45Y and 48E credits (taking
into account anticipated changes in
technology, policies, practices, and
environmental and other socioeconomic
conditions), will be updated as
necessary to capture material regulatory,
economic, supply chain, or
environmental changes. The baseline
must be updated at least every ten years,
but not more often than every five years.
Such updates will ensure that any LCA
baseline applied for purposes of
determining the net rate of GHG
emissions associated with C&G
Facilities under this rule robustly
reflects the projected future status quo
in the absence of the section 45Y and
48E credits.
d. Offsets and Offsetting Activities
Proposed § 1.45Y–5(d)(2)(iv) provided
that offsets and offsetting activities that
are unrelated to the production of
electricity by the C&G Facility,
including the production and

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distribution of any input fuel, may not
be taken into account in the LCA.
Several commenters supported this
proposed rule. However, one
commenter requested that the final rules
clarify that offsets and offsetting
activities are not the same as accounting
for avoided emissions, as avoided
emissions are directly related to the
electricity production value chain. The
Treasury Department and the IRS have
determined that such clarification is not
necessary given the prohibition on
offsets and offsetting activities provided
in proposed § 1.45Y–5(d)(2)(iv) and the
rule provided in proposed § 1.45Y–
5(d)(2)(vii) that the LCA may consider
alternative fates of feedstocks and fuels
and account for avoided emissions. Both
the prohibition on offsets and offsetting
activities and the rule that the LCA may
consider alternative fates and account
for avoided emissions are retained in
this final rule.
Furthermore, after reviewing the
comments, the Treasury Department
and the IRS have determined that the
proposed regulations were not clear in
the description of offsets and offsetting
activities. In particular, the reference to
offsets and offsetting activities that are
unrelated to the production of
electricity by the C&G Facility could
have been read overly broadly to suggest
that offsets and offsetting activities that
are related to the production of
electricity would be allowed. The
reference was intended to make clear
that offsets and offsetting activities
should not be included because they are
not related to the production of
electricity or the lifecycle of the fuel
used in electricity production rather
than to specify a set of offsets and
offsetting activities that may be
permissible. The statute requires a C&G
Facility’s net GHG emissions rate to
include the facility’s lifecycle emissions
from the production of electricity. To
avoid taxpayer confusion, the Treasury
Department and the IRS have revised
the rule in proposed § 1.45Y–5(d)(2)(iv)
to remove the phrase ‘‘that are unrelated
to the production of electricity by the
C&G Facility, including the production
and distribution of any input fuel.’’
e. Principles for Included Emissions
Proposed § 1.45Y–5(d)(2)(v) provided
that the LCA must take into account
direct emissions, significant indirect
emissions in the United States or other
countries, emissions associated with
market-mediated changes in related
commodity markets, emissions
associated with feedstock generation or
extraction, emissions consequences of
increased production of feedstocks,
emissions at all stages of fuel and

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feedstock production and distribution,
and emissions associated with
distribution, delivery, and use of
feedstocks to and by a C&G Facility. The
preamble to the proposed regulations
explained that this provision interprets
the reference to 42 U.S.C. 7545(o)(1)(H)
as requiring under section 45Y(b)(2)(B)
that an LCA must take into account
these emissions as they are a part of the
full fuel lifecycle through the point of
electricity production. Proposed
§ 1.45Y–5(d)(2)(v)(A) provided that, for
purposes of proposed § 1.45Y–5(d)(2)(v),
direct emissions include, but are not
limited to: (1) Emissions from feedstock
generation, production, and extraction
(including emissions from feedstock and
fuel harvesting and extraction and direct
land use change and management,
including emissions from fertilizers, and
changes in carbon stocks); (2) Emissions
from feedstock and fuel transport
(including emissions from transporting
the raw or processed feedstock to the
fuel processing facility); (3) Emissions
from transporting and distributing fuels
to electricity production facility; (4)
Emissions from handling, processing,
upgrading, and/or storing feedstocks,
fuels and intermediate products
(including emissions from on/offsite
storage and preparation/pre-treatment
for use (for example, torrefaction or
pelletization) and emissions from
process additives); and (5) Emissions
from combustion and gasification at the
electricity generating facility (including
emissions from the combustion and/or
gasification process and emission from
gasification or combustion additives).
Proposed § 1.45Y–5(d)(2)(v)(B) provided
that, for purposes of proposed § 1.45Y–
5(d)(2)(v), examples of significant
indirect emissions include, but are not
limited to, emissions from indirect land
use and land use change and induced
emissions associated with the increased
use of the feedstock for energy
production. The preamble to the
proposed regulations explained that
significant indirect emissions may
include positive or negative emissions,
and that, for biogenic resources,
significant indirect emissions may
include emissions from growth and
regrowth.
The Treasury Department and the IRS
received a range of comments about the
proposal to include these emissions in
the LCA. Most comments were
supportive of this proposed approach. A
few commenters suggested revisions to
the proposal. One commenter
recommended that market effects and
induced land-use change not be
assessed in the emissions included in an
LCA due to what the commenters view

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as limited credible estimates of such
dynamics. Another commenter cited a
lack of Congressional intent to include
market-mediated effects within the
meaning of ‘‘significant indirect
emissions’’ as this term does not appear
in the statute. As explained earlier, the
Treasury Department and the IRS
interpret section 45Y(b)(2)(B) as
requiring these emissions to be
considered in the LCA, which by citing
42 U.S.C. 7545(o)(1)(H) directly
specifies inclusion of ‘‘significant
indirect emissions such as land use
change’’. Estimating the emissions
effects associated with increased
electricity production, including
significant indirect emissions such as
land use change necessarily involves
some amount of uncertainty, but
inclusion of such elements was the clear
Congressional directive. The final
regulations will therefore not include
the revisions requested by commenters.
Another commenter suggested that
the LCA include emissions from ‘‘copollutants’’ such as sulfur dioxide,
nitrogen oxides, and fine particulate
matter, which are not GHG emissions
within the meaning of sections 45Y and
48E. The Treasury Department and the
IRS do not have the authority to adopt
this proposal, as it is contrary to the text
of the statute. Section 45Y(b)(2)(B)
requires that an LCA be conducted to
determine the amount of GHGs emitted
into the atmosphere by a facility in the
production of electricity, expressed in
grams of CO2e per kWh. Section
45Y(e)(1) states that ‘‘CO2e per kWh’’
means, with respect to any greenhouse
gas, the equivalent carbon dioxide (as
determined based on global warming
potential) per kilowatt hour of
electricity produced. Section 45Y(e)(2)
states that ‘‘greenhouse gas’’ has the
same meaning given such term under 42
U.S.C. 7545(o)(1)(G), as in effect on the
date of the enactment of this section. 42
U.S.C. 7545(o)(1)(G) defines greenhouse
gas as ‘‘carbon dioxide,
hydrofluorocarbons, methane, nitrous
oxide, perfluorocarbons, sulfur
hexafluoride.’’ The provision further
states that ‘‘[t]he Administrator may
include any other anthropogenicallyemitted gas that is determined by the
Administrator, after notice and
comment, to contribute to global
warming.’’ Because ‘‘co-pollutants’’
such as sulfur dioxide, nitrogen oxides,
and fine particulate matter are not GHGs
within the meaning of 42 U.S.C.
7545(o)(1)(G), the Treasury Department
and the IRS do not have the authority
to adopt the commenter’s proposal.
The Treasury Department and the IRS
generally adopt § 1.45Y–5(d)(2)(v) as
proposed. The Treasury Department and

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the IRS clarify in § 1.45Y–5(b)(10) that
market-mediated effects are those
resulting from policy interventions and
other factors (for example, technological
advances) that alter the availability of
and demand for marketed goods and
activities and their related GHG
emissions profiles. These effects are
driven by and result in changes in
absolute and relative prices which can
occur at local, national, and global
boundaries. Examples of marketmediated effects include direct and
significant indirect emissions, such as
land use changes or land use
management changes that result from
the production of fuels derived from
biomass and shifts in total market
demand and supply for input fuels,
feedstocks and related commodities,
and other materials, as a result of
changes associated with the policy
intervention.
For further clarity, the final
regulations better distinguish in
§ 1.45Y–5(d)(2)(v) between included
emissions that are direct emissions and
those that are significant indirect
emissions. The final rule also clarifies
that all these emissions are within the
system boundary of the LCA.
f. Principles for Excluded Emissions
Proposed § 1.45Y–5(d)(2)(vi) provided
a list of types of emissions that the LCA
must not take into account. The
Treasury Department and the IRS
received several comments on these
proposed excluded emissions from the
LCA. Several commenters requested that
further items be excluded from
emissions accounting in the LCA. For
instance, a few commenters requested
the exclusion of emissions resulting
from standby auxiliary power for
electrolyzers or emissions from
supplementary ‘‘peaker plants’’. A few
commenters proposed that emissions
resulting from the conditioning and
distribution of hydrogen be excluded
from the LCA. In each of these
instances, the Treasury Department and
the IRS have determined that such
emissions may be considered emitted
into the atmosphere in the production of
electricity within the meaning of section
45Y(b)(2)(B), and thus may not be
appropriately excluded from an LCA.
The Treasury Department and the IRS
therefore decline to adopt these changes
in the final regulations. The final
regulations adopt the principles for
excluded emissions as proposed.
g. Alternative Fates and Avoided
Emissions
Proposed § 1.45Y–5(d)(2)(vii)
provided that an LCA may consider
alternative fates and may account for

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avoided emissions. The preamble to the
proposed regulations defined the term
‘‘alternative fate’’ to mean a set of
informed assumptions (for example,
production processes, material
outcomes, and market-mediated effects)
used to estimate the emissions from the
use of each feedstock were it not for the
feedstock’s new use due to the
implementation of policy (that is, to
produce electricity). The final
regulations adopt this definition of
alternative fate in § 1.45Y–5(d)(2)(vii).
Because the alternative fate for some
feedstocks may be disposal, in the
interest of completeness and clarity,
these final regulations clarify that the
term ‘‘alternative fate’’ may include the
disposal of a feedstock.
The preamble to the proposed
regulations defined the term ‘‘avoided
emissions’’ to mean the estimated
emissions associated with the feedstock,
including the feedstock’s production
and use or disposal, that would have
occurred in the alternative fate (if such
feedstock had not been diverted for
electricity production) but are instead
avoided with the feedstock’s use for
electricity production. The preamble to
the proposed regulations further
explained that, while, in some
circumstances, emissions may be
avoided if compared to the alternative
fate, in other circumstances the new use
of the material (for example, for
electricity production) may involve
additional emissions that were not
emitted in the alternative fate
estimation. Relatedly, in some
circumstances, emissions may be
avoided in one part of the supply chain
only to occur elsewhere along the
supply chain due to the new use. The
final regulations adopt this definition of
avoided emissions in § 1.45Y–
5(d)(2)(vii) without change.
Many commenters generally
supported the proposed rule. Several
commenters opposed allowing the LCA
to consider alternative fates or avoided
emissions because the commenters
asserted that it is not possible to
accurately measure avoided emissions
and hence many claims of avoided
emissions are unreliable.
Finally, a number of commenters
suggested guardrails that might be
implemented in the final regulations or
in the analysis of emissions to enhance
accuracy. One commenter
recommended that the final regulations
set a minimum carbon intensity score of
zero for all fuels and feedstocks. The
Treasury Department and the IRS have
determined that, while this
recommendation may have merit with
respect to certain types of fuels or
feedstocks, such an approach may not

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be appropriate for all fuels and
feedstocks. Thus, this recommendation
will not be adopted in the final
regulations as a generally applicable
rule but will be considered in targeted
cases where the relevant facts and
circumstances support its application.
Another commenter suggested that
analysis of avoided emissions or
alternative fates of fuel or feedstock
employ a geographical limiting element
to address local air pollution and health
issues. However, sections 45Y and 48E
do not authorize the Treasury
Department and the IRS to specifically
take into account local air pollution and
health issues in the assessment of GHG
emissions. Therefore, the Treasury
Department and the IRS decline to
adopt this commenter’s
recommendation in the final
regulations.
Several commenters recommended
that the LCA take into account only
reliable and documented alternative
fates that are supported by data,
including land management records and
market statistics, showing customary
practice for the relevant feedstocks or
fuels. The Treasury Department and the
IRS agree that taking care to assess the
reliability and documentation of any
data elements, including those
concerning alternative fates is good
practice for conducting a GHG LCA.
However, the Treasury Department and
the IRS decline at this time to require
the use of specific forms of
documentation and data sources in the
final regulations given the diversity of
fuels and feedstocks and their
alternative fates that may be evaluated
for the purposes of the section 45Y and
48E credits. Therefore, the commenters’
recommendation will not be adopted in
the final regulations. Specific
substantiation and documentation data
requirements related to alternative fates
or avoided emissions may be identified
for specific fuels or feedstocks in future
guidance.
One commenter further recommended
that prospective claimants of the section
45Y credit be required to support the
alternative fate of a feedstock or fuel
with credible evidence and that
verification of such fate be required to
the maximum extent possible. The
Treasury Department and the IRS view
this request as covered by a taxpayer’s
existing general substantiation
obligations under section 6001 of the
Code so further clarification in the final
regulations is not necessary. Therefore,
the final regulations do not adopt this
commenter’s suggestion.
A number of commenters
recommended that the evaluation of
alternative fates be comprehensive, with

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suggestions including that the LCA
assess multiple alternative fates to
improve the robustness of the analysis,
that such alternative fates account for
emissions related to the full fuel
lifecycle, that alternative fate
assumptions be updated regularly, and
that consideration be given to the
influence of market conditions and
effects.
The Treasury Department and the IRS
agree that ensuring that the LCA
assessment of alternative fates and
avoided emissions is comprehensive
and up to date is critical to ensure
robust estimation of the net GHG
emissions rates for C&G Facilities. These
recommendations will be considered in
the development of future LCA
assessments.
Commenters also opined on whether
the LCA should take into account
emissions ‘‘displacement’’ from
electricity grids. This analytical
framework assumes that, in the absence
of the incentive provided by the section
45Y and 48E credits, fuels or feedstocks
that would otherwise have a greater
GHG emissions rate will be used to
generate electricity, and that the
assumed reduction in emissions due to
the use of fuels or feedstocks with a
lesser GHG emissions rate at a facility
due to this rule should be taken into
account when evaluating the net GHG
emissions rate of a facility using those
fuels or feedstocks. A number of
commenters recommended treating this
displacement as an avoided emission
that could lessen the net GHG emissions
rate of a facility using those fuels or
feedstocks, stating that such treatment
would spur investment in a number of
technologies and reduce net GHG
emissions.
Other commenters recommended
against treating this displacement as an
avoided emission that could lessen the
net GHG emissions rate of a facility
using those fuels or feedstocks, asserting
that to do so would improperly shift the
GHG emissions rate inquiry from
whether a C&G Facility has a net GHG
emissions rate of not greater than zero
to whether the facility has fewer
emissions than the marginal unit
emissions of the grid the facility is on.
The Treasury Department and the IRS
have determined that the proposed rule
in § 1.45Y–5(d)(2)(ii), which states that
energy sources displaced by the
electricity generated by a C&G Facility
are outside of the LCA boundary, should
be retained in the final regulations. This
rule appropriately requires that the net
GHG emissions rate be assessed at the
level of the C&G Facility, with an
ending boundary for assessment for
electricity that is transmitted to the grid

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or electricity that is used on-site is the
meter at the point of electricity
production of the C&G Facility. This
ending boundary is consistent with
section 45Y’s focus on the C&G Facility
and the full fuel lifecycle of any fuel or
feedstock used by the C&G Facility to
produce electricity as the relevant
sources of GHG emissions, rather than
any change to the emissions profile of
the electricity grid.
The Treasury Department and the IRS
agree with commenters that taking into
account potential post-production grid
electricity displacement as an avoided
emission would impermissibly shift the
GHG emissions rate inquiry from
whether electricity production at a
qualified facility has a net GHG
emissions rate of not greater than zero
to whether the facility has fewer
emissions than the marginal unit
emissions of the grid to which the
facility is connected. Conducting the
LCA in such a manner would conflict
with the plain text of the statute, which
requires that the net rate of GHGs
emitted by a C&G Facility, considering
lifecycle GHG emissions, in the
production of electricity not be greater
than zero. In contrast to this distinct
concept of displacement of electricity
production from other more highly
polluting sources on the electricity grid
due to electricity produced by a C&G
Facility, the LCA of electricity
production calculates the net GHG
emissions of the electricity production
by that facility, including by taking into
account alternative fates and avoided
emissions of the fuels or feedstocks that
are themselves used to produce
electricity at such a facility over the
entire lifecycle of that particular fuel or
feedstock or its supply chain. The
statute directs the Treasury Department
to calculate the GHG emissions
associated with electricity production
by a specific facility. The statute does
not direct or authorize the Secretary to
conduct a relative assessment of a
facility’s GHG emissions before and
after earning the tax credit or a relative
assessment of a facility’s electricity
production volumes and related GHG
emissions compared to other facilities
on the grid. For additional clarity, the
Treasury Department and the IRS have
determined that proposed § 1.45Y–
5(d)(2)(vii) should be modified to add
the phrase ‘‘including for the fuels and
feedstocks consumed in the fuel and
feedstock supply chain and at the
electricity generating facility.’’
The Treasury Department and the IRS
also received many comments regarding
the purported alternative fates or
avoided emissions associated with the
use of a particular fuel or feedstock.

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Several commenters requested that an
LCA of municipal solid waste take into
account emissions that may be avoided
by use of such waste to produce
electricity rather than placement in a
landfill. Others shared their views or
research on common alternative fates of
woody biomass, including natural
decay, prescribed burning, wildfire fuel,
and transfer to disposal sites.
The Treasury Department and the IRS
appreciate the information shared by
commenters on these matters and have
taken it into consideration. Because
these assertions make technical claims
that must be evaluated in the context of
an LCA and because they are applicable
to only certain categories of feedstocks,
the Treasury Department and the IRS
have determined that incorporation of
these recommendations in the final
regulations as a broadly applicable rule
would not be appropriate.
Finally, commenters had mixed
reactions to the assertion that the use of
woody biomass in the production of
electricity drives forest regrowth that
might render the use of such feedstock
carbon neutral for purposes of the
section 45Y and 48E credits. Some
commenters asserted that woody
biomass, when used to produce
electricity, has a net GHG emissions rate
of not greater than zero, and that
therefore, facilities using such feedstock
should be included as qualified
facilities in the final regulations and in
the Annual Table.
Because section 45Y(b)(2)(B) requires
taking into account lifecycle GHG
emissions as described in 42 U.S.C.
7545(o)(1)(H), the Treasury Department
and the IRS do not have the authority
to designate such facilities as qualified
facilities before ensuring that an LCA
specific to implementation of sections
45Y and 48E is conducted in accordance
with statutory requirements. The
Treasury Department and the IRS thus
decline to adopt these commenters’
recommendations in the final
regulations. The Treasury Department
and the IRS appreciate commenters’
feedback and note in particular that
certain woody biomass-derived
feedstocks require significant energy
inputs which could make qualification
of facilities using these specific
feedstocks unlikely (for example,
pelletized biomass due to the electricity
used in pelletization processes).
D. Additional Issues Regarding
Greenhouse Gas Emissions Rates for
C&G Facilities
The determination of net GHG
emissions rates for C&G Facilities raises
a range of complex technical questions
that are relevant to determining

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eligibility for the section 45Y and 48E
credits. The Treasury Department and
the IRS requested comment on the
following topics: (i) the treatment of
RNG and fugitive sources of methane;
(ii) analytical LCA parameters,
including spatial scales and time
horizons; (iii) whether and how to
distinguish between co-products,
byproducts, and waste products and
how emissions should be allocated to
each in LCAs; (iv) how to attribute
emissions to the heat produced by
facilities using combined heat and
power systems; (v) how to create and
maintain LCA baselines; and (vi) certain
issues related to LCA modeling.
1. Analytical LCA Parameters, Including
Spatial Scales and Time Horizons
In the preamble to the proposed
regulations, the Treasury Department
and the IRS requested comment on the
analytical LCA parameters that are most
relevant to particular types of categories
of C&G Facilities that may be eligible for
the section 45Y and 48E credits. In
particular, the Treasury Department and
the IRS requested comment regarding
spatial and temporal scales, including
the factors that should be considered in
setting the spatial and temporal scales
for LCAs conducted for the section 45Y
and 48E credits. As noted in the
preamble to the proposed regulations,
spatial scale involves defining the area
over which emissions outcomes will be
evaluated. Temporal scale involves
defining the time period over which
emissions outcomes will be evaluated.
The decision of setting the spatial scale
should be considered in conjunction
with decisions on temporal scale, as the
two can interact in ways that affect
greenhouse gas assessment outcomes.
The Treasury Department and the IRS
received a number of comments on
these topics.
a. Temporal Scales
In the preamble to the proposed
regulations, the Treasury Department
and the IRS requested comment
regarding what factors should be
considered in establishing the
timeframe for the LCA analysis.
Commenters suggested a number of
specific considerations. Multiple
commenters advocated for the LCA to
account for the full timeframe over
which lifecycle emissions can occur,
with some commenters specifically
asking for a ‘‘climate-relevant’’
timeframe. A commenter argued that a
full accounting of the effects of activities
should include the effects of small-scale
projects over long time frames with each
activity assessed individually. Another
commenter argued that the full

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timeframe over which emission effects
persist into the future should be
included. Conversely, a commenter
noted that any approach that requires
use of long-run future marginal grid
emissions projections could be
prohibitively challenging or
problematically inaccurate. Some
commenters advocated for inclusion of
all relevant emissions fluxes on the
same timescale. A commenter suggested
counting any emissions
counterbalanced by the regrowth of
feedstock on the same time scale as the
positive emissions from combustion and
other direct and indirect positive
emissions. A commenter also asked to
match the time horizon with the
economic life of a plant that abates
existing methane or other GHG
emissions. Some commenters argued
that no specific geographic or temporal
requirements were required as long as
the timeframe covered the occurrence of
emissions in the counterfactual
scenario.
In the preamble to the proposed
regulations, the Treasury Department
and the IRS requested comment
regarding what timeframe would
provide confidence that significant
emissions have been accounted for.
Commenters suggested a wide variety of
specific lengths of time, citing a variety
of policy reasons. Some commenters
suggested time horizons of 100 years (or
more), citing the importance of
accounting for potential long-term
changes in emissions in order for certain
feedstocks to qualify. Other commenters
advocated for much shorter time
horizons. One commenter requested that
CHP property which relies on
combustion, such as woody biomass
energy, should be required to show
carbon-neutrality over a short period of
time such as a year. Multiple
commenters advocated for a 10-year
time horizon. Commenters also cited
potential ranges somewhere in the
middle, such as 20 to 50 years or 20 to
25 years.
After thorough review of the
comments the Treasury Department and
the IRS have determined that it is
appropriate to base the selection of
temporal scale on the regulatory
context. This is reinforced by the 2019
recommendations by the Science
Advisory Board (SAB) on EPA’s Draft
2014 Framework for Assessing Biogenic
CO2 Emissions from Stationary Sources.
The SAB recommended ‘‘using the
‘emissions horizon’ that is determined
to be relevant by the specific regulatory
objective,’’ meaning the technical choice
should be contingent upon the specific
policy and regulatory context. The SAB
went further to state that ‘‘the SAB

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favors selecting the time horizon for
calculating the [factor representing the
net atmospheric biogenic CO2
contributions associated with biogenic
feedstock production, processing, and
use at a stationary source] to comport
with the objective under consideration,
which is generally dependent on the
regulation mandating use of that
particular [factor].’’ ISO guidance also
states that an LCA should be conducted
within the context of a specified goal.
The broader regulatory context
requires the Treasury Department and
the IRS to balance multiple
considerations. The statute creates a
pathway for C&G Facilities that have a
net GHG emissions rate of zero or less
as determined via LCA to qualify for the
credit. Setting a relatively short time
horizon would not allow for the
consideration of potential increases or
decreases in emissions that can occur as
the result of electricity production, such
as the regrowth of biogenic feedstocks or
increased emissions from land use or
land use management changes.
However, while biogenic feedstock
regrowth can occur over long
timescales, commenters have raised
significant concerns that longer time
horizons introduce additional
uncertainty about the likelihood that
these theoretical future scenarios and
emissions-offsetting activities will occur
in practice. This uncertainty
significantly decreases the confidence of
the Treasury Department and the IRS
that LCAs with a longer time horizon
will ensure that a facility meets the
requirements of the statute. Moreover,
the broader structure of the IRA and
specific features of sections 45Y and
48E—including the phase-out of the
credit occurring after the later of 2032
or the achievement of specified GHG
emissions reduction target and the
requirement that qualified facilities
have a GHG emissions rate of zero or
less—demonstrate congressional intent
for the section 45Y and 48E credits to
contribute to significant reductions of
GHG emissions in the power sector in
the near- to medium-term. Setting a
temporal scale that allows C&G
Facilities that do not contribute to the
reduction of GHG emissions (or even
increase GHG emissions) in the nearand medium-term would also frustrate
congressional intent.
In the preamble to the proposed
regulations, the Treasury Department
and the IRS asked whether the LCA
should distinguish between an
‘‘emissions horizon’’ (the timeframe
over which emissions effects from the
feedstock use persist into the future)
and an ‘‘assessment horizon’’ (the
timeframe over which the emissions

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effects are included in the analysis), and
how that would be reflected in the
choice of temporal scale. Although some
commenters advocated for applying
different time horizons in different
contexts (for example, for different
electricity production pathways), the
Treasury Department and the IRS have
determined that it furthers the interest
of fairness and administrability in the
tax system to apply consistent rules for
all LCAs under sections 45Y and 48E.
Applying different time horizons,
including different assessment and
emissions horizons, in different contexts
could lead to taxpayer confusion and
disparate treatment for similarly
situated facilities. Moreover, a single
time horizon would allow LCAs to be
conducted as efficiently and accurately
as possible. The Treasury Department
and the IRS further clarify that the final
rules in § 1.45Y–5(d)(2)(viii) adopt the
same assessment horizon and emissions
horizon.
In balancing these considerations and
commenters’ different views, the final
regulations adopt a time horizon for
LCA of 30 years from the year in which
a qualified facility produces electricity
(or, for purposes of the section 48E
credit, the year in which a qualified
facility was placed in service). This 30year time horizon is supported by
several points, including consistency
with the longstanding time horizon for
EPA’s RFS program. This program,
authorized under the Energy Policy Act
of 2005 and expanded under the Energy
Independence and Security Act of 2007,
determined that GHG emissions analysis
for renewable fuels would quantify the
GHG impacts over a 30-year period in a
March 2010 rule (75 FR 14670) (RFS2).
A 30-year analysis time period was
further maintained in the Final
Renewable Fuels Standards Rule for
2023, 2024, and 2025.7 The RFS2 rule
made this determination balancing a
number of considerations, including the
expected life of biofuel production
facilities—and their long-term market
impacts on emissions—and the inherent
uncertainty in estimating GHG
emissions over a longer period of time.
The Treasury Department and the IRS
assess that solely for the purposes of
setting temporal scales in these final
regulations, the section 45Y and 48E
credits and RFS2 are similar regulatory
contexts based on the information
currently available.
A commenter advocated for
modifying the Greenhouse Gases,
7 Regulatory Impact Analysis for Renewable Fuel
Standard (RFS) Program: Standards for 2023–2025
and Other Changes, Section 4.2.2. (pp129–130),
available at https://nepis.epa.gov/Exe/
ZyPDF.cgi?Dockey=P1017OW2.pdf.

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Regulated Emissions, and Energy use in
Transportation model (GREET model) to
capture 20-year and 100-year time
horizons as the GREET model already
uses the GWP metric to capture both
near-term and long-term climate
impacts. The Treasury Department and
the IRS note that the temporal scale of
the LCA is the time period over which
GHG emissions are assessed in the
context of sections 45Y and 48E, rather
than the warming potential of such
emissions. Reliance upon specific GWPs
to determine time horizons or upon the
GREET model, which is a particular
model that does not generally include
explicit temporal considerations when
applying certain assumptions about
what activities and related GHG
emissions to include, is therefore
separate from the issue of temporal
scales. The decision to use GWP–100 is
discussed in section VIII.A.1. of this
Summary of Comments and Explanation
of Revisions.
b. Spatial Scales
Commenters also submitted a wide
range of recommendations pertaining to
spatial scales. A few commenters
recommended that spatial boundaries be
set narrowly around the geographic
location of the facility, which they
stated would more accurately reflect
local conditions. Another commenter
advocated for setting spatial scales such
that they capture the potential impact of
having multiple facilities with a GHG
emissions rate of greater than zero in the
same area. One commenter suggested
that the LCA spatial scales not be
beyond the facility producing the
feedstock.
In the preamble to the proposed
regulations, the Treasury Department
and the IRS asked (i) what factors
should be considered to assess whether
a global scale is necessary for certain
feedstocks to ensure that significant
emissions are captured, and (ii) whether
all feedstock/fuels assessments should
be conducted with the same spatial
scale to determine the extent to which
increased use has estimated global
ramifications. Some commenters had
feedstock-specific suggestions regarding
appropriate spatial scales. Several
commenters recommended that, in the
case of woody biomass, spatial
boundaries be broad to more accurately
represent forest dynamics. A commenter
also suggested that spatial scales not be
limited when taking into account
wastes, including when such wastes are
managed outside of the United States.
After consideration of all comments
and of LCA modeling practices that take
into account the full lifecycle of
emissions as described by 42 U.S.C.

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7545(o)(1)(H), the Treasury Department
and the IRS have determined and
provided in § 1.45Y–(d)(2)(ix) that
spatial scales analysis for LCAs
conducted for the section 45Y and 48E
credits should identify GHG effects from
changes in input fuel or feedstock
production and use, including indirect
emissions effects stemming from
market-related changes in supply and
demand. When estimating the net GHG
emissions outcomes associated with a
fuel or feedstock that has current or
anticipated market uses and thus
potential market-mediated impacts for
the entity-level analysis (that is, for a
Provisional Emissions Rate (PER)) or
generally applicable analysis (that is, for
the Annual Table), the LCA assessment
must start with a qualitative market
analysis to aid with the formation of
parameters and other decisions in the
LCA modeling. This market analysis
serves the purpose of analyzing whether
the prospective fuel or feedstock has
been or is anticipated to be used directly
in or as an input to an activity or
commodity in local markets, is
transported for use in domestic markets
elsewhere, or is traded for use in
international markets, whether use of
the material does or is anticipated to
have significant ramifications on other
markets, and the magnitude of the use
or anticipated use. Findings of this
assessment should inform the decisions
about what spatial scales, such as subregional, regional, national, or
international, are most appropriate for
assessing the market and related GHG
emissions effects associated with the
feedstock and use case under
consideration. The GHG emissions
analysis should then be conducted
using the designated model(s) with the
applicable spatial scales to estimate the
market and GHG emissions implications
of changing supply flows to provide the
feedstock for energy purposes and
sourcing new or additional feedstock
material for electricity generation across
the applicable market and spatial scales
for use in the LCA assessment to
determine the net GHG emissions rate
needed as part of the eligibility
qualification for the section 45Y and
48E credits. If the initial market analysis
concludes that the prospective feedstock
is (i) not currently, has not recently, nor
is anticipated in the future in the
absence of the section 45Y and 48E
credits to be used or sold on the market,
(ii) not used as an input to an activity
or good in local markets, (iii) not
transported for use in domestic markets
elsewhere, (iv) not traded for use in
international markets, or (v) use of the
material does not or is not anticipated

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to have significant ramifications on
other markets, then an analysis of
market-mediated impacts would only
need to apply across the spatial scales
that are applicable to the fuel or
feedstock in the LCA emissions
assessment.
2. Distinguishing Between Co-Products,
Byproducts, and Waste Products and
How Emissions Should Be Allocated to
Each in LCAs
As explained in the preamble to the
proposed regulations, the categorization
and assessment of products as coproducts, byproducts, or waste products
in an LCA may affect the LCA’s results.
The preamble to the proposed
regulations provided potential
definitions to guide the categorization of
co-products, by products or waste
products and further provided that
products, co-products, byproducts, and
wastes may all be produced in the full
fuel cycle or used as inputs to the same.
The preamble to the proposed
regulations further explained that the
categorization of products as coproducts, byproducts, and waste
products may be relevant to an LCA’s
assessment of the GHG emissions
related to the production of inputs to
electricity generation or in the
generation of electricity itself if the LCA
modeling approach or approaches used
for purposes of the section 45Y and 48E
credits have the ability to distinguish
between such categories.
In the preamble to the proposed
regulations, the Treasury Department
and the IRS stated an intent to clarify
the principles for categorizing products
as co-products, byproducts, or waste
input materials and products and
assessing the emissions outcomes for
such products in an LCA for C&G
Facilities in the final regulations for the
section 45Y and 48E credits if such
categorization is relevant to the LCA
model or models used. To inform the
development of these categorization
principles for the final regulations, in
the preamble to proposed regulations
the Treasury Department and the IRS
requested comment on what principles
should be used to distinguish between
co-products, byproducts, and waste
products for the purposes of the section
45Y and 48E credits. The Treasury
Department and the IRS also asked
whether there are common scientific or
industry definitions that can be relied
upon to distinguish between coproducts, byproducts, and waste
products.
The Treasury Department and the IRS
received a large number of comments in
response to these questions. A few
commenters suggested broad principles

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that should be used to distinguish
between co-products, byproducts, or
waste products. One such commenter
recommended that the definitions of coproducts, byproducts, and waste
products be less rigid than those shared
in the preamble to the proposed
regulations and that they reflect the
scientific literature on the lifecycle GHG
emissions of various materials. Another
commenter recommended that the final
regulations adopt simple common-sense
definitions that assign emissions of the
facility to primary products and coproducts. This commenter further
suggested that all materials left over
after the production of any primary
products be deemed waste unless they
have significant value, and that the full
breadth of potential co-product
materials be considered. Another
commenter recommended that the final
regulations provide a broad definition of
residue materials, citing the need to give
industry the ability to respond to local
market forces. Another commenter
recommended using mass-based
allocation to allocate emissions to coproducts, byproducts, and waste
products, stating that such an approach
is straightforward to administer and can
reduce abuse.
A number of commenters opposed
distinguishing between co-products,
byproducts, and waste products for the
purposes of the section 45Y and 48E
credits. Several stated that such
categorization of products would result
in impermissibly failing to associate all
GHG emissions to the feedstock or fuel
that produced the electricity, or that if
such categories do not do so, they are
therefore irrelevant. Some commenters
opposed to such categorization noted its
complexity, with one commenter stating
opposition to including these categories
in the final rule in favor of expert
agencies due to the highly technical
nature of the work. Another commenter,
noting the complexity of the
designations, recommended using
caution in any such categorization
process to avoid rewarding emissions
shifting rather than a true reduction in
emissions.
The Treasury Department and the IRS
have determined that distinguishing
between co-products, byproducts, and
waste products will help facilitate
efficient and consistent LCA taking into
account lifecycle GHG emissions as
described in 42 U.S.C. 7545(o)(1)(H).
Moreover, providing a framework of
categorization will facilitate
communications among stakeholders by
providing a common set of terms. Such
designations were also used in EPA’s
2010 notice-and-comment rulemaking
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for the updated RFS program, in which
EPA interpreted 42 U.S.C. 7545.
The Treasury Department and the IRS
have determined that, as noted in the
preamble to the proposed regulations, it
is appropriate to provide clarifications
to the definitions of products, coproducts, byproducts, and waste and the
principles for categorizing and
informing the assessment of the GHG
emissions associated with such
materials in an LCA for C&G Facilities
in the final regulations under § 1.45Y–
5(d)(2)(x) for the section 45Y and 48E
credits. These clarifications were
informed by consideration of the
comments received on these definitions
and principles in the proposed
regulations. The Treasury Department
and the IRS have also determined that
these clarifications are consistent with
the statutory direction in section 45Y to
determine GHG emissions rates taking
into account lifecycle GHG emissions as
described in 42 U.S.C. 7545(o)(1)(H).
The EPA interpreted 42 U.S.C.
7545(o)(1)(H) as requiring the agency, in
the RFS context, to account for the realworld emissions consequences of
increased production of biofuels,
including consideration of market
interactions that may result in indirect
emissions. The Treasury Department
and the IRS find that the clarifications
to these definitions and principles
therefore appropriately incorporate the
concepts of marketability and market
effects in the context of the designation
and emissions assessment of primary
products, co-products, byproducts, and
waste products.
These clarifications include the
definitions in § 1.45Y–(d)(2)(x)(A)(1)
through (4):
• A ‘‘primary product’’ is an input or
an output with marketability and is the
main driver of the process from which
it is produced.
• A ‘‘co-product’’ is an input or an
output with marketability that is
produced together with another
product, both of which are economic
drivers of the process from which they
are produced.
• A ‘‘byproduct’’ is an input or an
output that is produced together with
another product, and which has a
market recognized economic value of
zero or greater, but the output is not an
economic driver of the process from
which it is produced.
• A ‘‘waste product’’ is an input or an
output with negative economic value,
demonstrated by (1) the absence of a
market in which the product is
purchased and sold and (2) the
existence of a market in which
producers pay for the collection and
removal or disposal of the input or

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output material or the existence of a
predominant operational practice in
which producers themselves collect and
remove, give away, or dispose of the
input or output material as part of
operational processes.
For the purposes of these definitions,
the Treasury Department and the IRS
note that a ‘‘market’’ should be an
established set of transactions between
parties and that whether or not a market
exists—and therefore the categorization
of the same product—may vary by
region. A single or very small number of
local transactions of insignificant
volumes at nominal prices to expedite
disposal generally would not constitute
a market. Moreover, the existence of a
market and therefore the analysis of
market-mediated effects for a particular
product or material does not prejudge
the magnitude of those effects. For
example, a market may have existed in
the past for a particular product or
material, but market analysis may
indicate that this market is anticipated
to not exist in the future, and vice versa.
Relatedly, for the purposes of these
definitions, marketability is defined as
the ability to be consistently sold or
marketed in the regular course of
business.
For example, an input or output
generated as part of operational
processes that would otherwise be
subsequently: (i) given away; (ii) sold at
nominal prices to expedite disposal; or
(iii) disposed of (without creating a
commercial product or generating
electricity) by burning onsite, burying,
piling and burning onsite or leaving to
decompose, or scattering would
generally be considered a waste for the
purposes of these definitions.
Consistent with this approach, the
final regulations also add in § 1.45Y–
5(d)(2)(x)(B)(1) through (6) principles
for categorizing and informing the
assessment of the GHG emissions for
such materials in an LCA for C&G
Facilities for the section 45Y and 48E
credits if such categorization is relevant
to the LCA model or models used. The
principles are as follows:
• All classification of materials and
LCAs should take into account relevant
geospatial variations in supply and
demand (that is, differences across local,
sub-regional, and larger regions), as well
as variations across specific product
types and characteristics, and producer
types as relevant. For example, a
material may meet the previously
described definition of a waste in
certain regions and the definition of a
by-product or co-product in other
regions.
• The LCA should assess whether
there are market-mediated effects and, if

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so, take these into account as part of the
GHG analysis. In some cases, marketmediated effects will be small or
nonexistent.
• Regardless of how a material is
categorized, the LCA should consider
whether the availability of the section
45Y and 48E credits is expected to
result in additional production of that
material or in material changes in the
supply chain, and, if so, should take
into account the direct and indirect
emissions impact of the additional
production or changes in the supply
chain.
• Policy and other interventions (for
example, technological advances) can
alter the availability and demand for
marketed goods and services, which can
alter the treatment of materials once
disposed of. Therefore, reevaluation of
material categorization should occur at
least every ten years, but not more often
than every five years.
• All determinations of marketability,
market-mediated effects, and behavioral
changes must be supported by an
analytical assessment performed by one
or more National Laboratories, in
consultation with other Federal agency
experts as appropriate.
• A material should be considered to
have a market recognized economic
value and an established market if one
existed within the last five years as of
the date of the analysis.
To inform the development of these
categorization principles for the final
regulations, in the preamble to proposed
regulations the Treasury Department
and the IRS requested comment on what
principles should be used to determine
whether a product has sufficient value
to be considered a co-product or
byproduct. Two comments were
received in response. These commenters
stated that if a policy rewards the use of
a waste product, that product has
inherent value, and that that value
could possibly surpass the value of the
ostensible primary product. One such
commenter noted that this would make
these materials co-products. Another
recommended that the Treasury
Department rigorously interrogate the
designation of waste fuels because of the
change in value of such items due to the
section 45Y and 48E credits as well as
any other relevant subsidies. This
commenter further suggested that when
product designation is likely shifted as
a result of these incentives, so should
the associated emissions accounting.
The Treasury Department and the IRS
have considered these comments and
others in evaluating the appropriate
definition and treatment of co-products.
The Treasury Department and the IRS
have determined that the definition of

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‘‘co-product’’ will be amended in the
final regulations under § 1.45Y–
5(d)(2)(x)(A)(2) to reflect that a coproduct not only must be an economic
driver of the production process
alongside another product, but also
must have marketability. However,
regardless of how a material is
categorized, the LCA will consider
whether the availability of the section
45Y and 48E credits can result in
additional production of that material or
changes within the production and
supply chain of that material and take
into account any direct and indirect
GHG emissions outcomes of the
additional production or any such
supply chain changes. Furthermore,
because policy and other interventions
can alter the availability and demand for
marketed goods and services, even
turning waste products into byproducts,
co-products, or even primary products,
the categorization of materials will be
reevaluated and must be updated at
least every ten years, but not more often
than every five years.
In the preamble to the proposed
regulations, the Treasury Department
and the IRS also requested comment
regarding whether the section 45Y and
48E credits may provide additional
economic incentive for the consumption
of a product categorized as waste prior
to the availability of the incentive
provided by the section 45Y and 48E
credits. The Treasury Department and
the IRS also asked how this additional
economic incentive should be
considered to determine if a product is
a waste product, byproduct, or coproduct, and asked whether this
categorization should be reevaluated
and, if so, how often.
The Treasury Department and the IRS
received several comments about the
economic incentive for the consumption
of a product categorized as waste prior
to the availability of the incentive
provided by the section 45Y and 48E
credits. One commenter recommended
that, because of this possible incentive,
the final regulations not distinguish
between co-products, byproducts, and
wastes for the purposes of emissions
allocation. For all materials, the LCA
must consider whether the availability
of the section 45Y and 48E credits can
result in additional production or use of
that material, or changes in the
production of or supply chain to
provide that material and take into
account any direct and indirect
emissions outcomes of the additional
production or use and any supply chain
changes.
Another commenter similarly warned
about the risk of incentivizing the
classification of waste when such

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categorization is not factually justified.
This commenter stated that the
European Union’s Renewable Energy
Directive (RED) waives sustainability
criteria for solid biomass fuels that are
considered industrial residues, but that
to protect against the risk of fraudulent
classification of such fuels as waste, the
RED requires that feedstock auditing
verify such classification. The
commenter recommended that the
Treasury Department adopt similar
measures for the section 45Y and 48E
credits. The Treasury Department and
the IRS have determined that a similar
requirement would be appropriate to
ensure accurate tracking and
verification of any materials determined
to constitute waste materials. If a
qualified facility uses feedstocks that do
not have marketability, but which are
indistinguishable from marketable
feedstocks (for instance, after
processing), the taxpayer will be
expected to maintain documentation
substantiating the origin and original
form of the feedstock. See section VIII.J.
of this Summary of Comments and
Explanation of Revisions for further
discussion of substantiation.
The Treasury Department and the IRS
also received several comments
regarding the possible reevaluation of a
material’s categorization as a waste. A
few commenters were opposed to
recategorizing a material from a waste to
another designation, arguing that such
actions could be damaging to emissions
mitigation efforts or to efforts to find
productive uses for materials previously
disposed of. Another commenter
recommended that any reevaluation of
the classification of waste be conducted
predictably and only to prospective
qualified facilities. The commenter
further recommended that such
reevaluations focus on only major
changes external to the section 45Y and
48E credits or other Federal incentives.
The Treasury Department and the IRS
have determined that reevaluation of
material categorization should occur at
least every ten years, but not more often
than every five years, consistent with
the reevaluation period outlined for
baselines, because policy interventions
and other developments in the market
can alter the availability and demand for
marketed goods and services, and can
sometimes turn waste products into
byproducts, co-products, or even
primary products. This reevaluation is
therefore necessary to ensure robust
estimation of the net GHG emissions
rates for C&G Facilities in a manner
consistent with section 45Y(b)(2)(B).
Regardless of the results of any such
reevaluation, taxpayers may rely on the
Annual Table in effect as of the date a

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facility began construction or the
provisional emissions rate determined
by the Secretary for the taxpayer’s
facility to determine the facility’s
greenhouse gas emissions rate for any
taxable year that is within the 10-year
period described in section 45Y(b)(1)(B),
provided that the facility continues to
operate as a type or category of facility
that is described in the Annual Table or
the facility’s emissions value request, as
applicable, for the entire taxable year. If
the facility changes the type or method
of production of their fuel or feedstock,
this constitutes a potential change in
their provisional emissions rate
determined by the Secretary.
To limit the additional production of
waste, in the preamble to the proposed
regulations, the Treasury Department
and the IRS requested comment
regarding whether the final regulations
should limit eligible waste sources that
existed as of a certain date, or waste or
waste streams that were produced
before a certain date, such as the date
that the IRA was enacted. The Treasury
Department and the IRS also requested
comment regarding how these factual
scenarios could be documented or
verified, including any changes in
volumes of waste and waste capacity at
existing sources, and additional capture
of existing waste or waste streams.
The Treasury Department and the IRS
received several comments in response
to these questions. One commenter
recommended that, to limit the
additional production of waste,
materials be classified as waste only if
the material was created before a
qualified facility begins claiming the
section 45Y and 48E credits. The
Treasury Department and the IRS have
determined that prohibiting
classification of a material used by a
qualified facility as waste after the
qualified facility begins claiming the
section 45Y and 48E credits is
unnecessary in light of the requirements
that the LCA take into account the
emissions impact of any additional
production or use of such material and
the requirements that the LCA be
conducted at the market level. In some
cases, this may result in different
emissions determinations for materials
that make up waste streams that existed
prior to the credits versus for those same
materials produced after and potentially
in response to the credits.
Another commenter responded to this
question with a recommendation that
materials not be classified as wastes
unless disposal or incineration, as
opposed to repurposing, is the only
option for such material. The
commenter offered the ‘‘cascading’’
principle in the European Union’s

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revised RED that prioritize material use,
reuse, and recycling of wood over
burning for energy as a model for how
incentives to burn materials should be
treated under the section 45Y and 48E
credits. The Treasury Department and
the IRS have determined that, for the
purposes of the final regulations, a
waste product is defined as noted
earlier. The requirement that a waste
material lacks marketability for sale but
has a market for disposal is consistent
with this commenter’s recommendation
that materials be classified as waste only
if such material lacks a productive use
beyond such disposal.
In the preamble to the proposed
regulations, the Treasury Department
and the IRS also requested comment
regarding the potential for and
approaches to prevent the intentional
generation of waste or co-products for
the purposes of lowering the allocated
process emissions to electricity. The
Treasury Department and the IRS
received several comments in response
to this question. A few commenters, as
discussed earlier, recommended against
designating materials as wastes, coproducts, or byproducts to avoid
intentional generation of waste. Another
commenter recommended use of a
dynamic LCA that incorporates every
product, flow, and material use when
accounting for emissions, including
assessing the environmental impact of
production processes such as generation
of waste or co-products. This
commenter stated that this practice
would prevent intentional generation of
waste because the dynamic LCA would
accurately reflect the potential benefit of
not intentionally generating the waste.
As discussed earlier, the Treasury
Department and the IRS have
determined that distinguishing between
these products will facilitate efficient
and consistent evaluation of GHG
emissions rates taking into account
lifecycle GHG emissions as described in
42 U.S.C. 7545(o)(1)(H). However,
regardless of how a material is
categorized, the LCA must consider
whether the availability of the section
45Y and 48E credits will result in
additional production or use of that
material or changes in the supply chain
of that material resulting in GHG
emissions effects and take into account
any direct and indirect emissions
impact of the additional production or
use and such changes.
Another commenter stated that, in the
case of municipal solid waste facilities,
intentional generation of waste is
unlikely because the cost of waste
disposal will be greater than the value
of the credit. The Treasury Department
and the IRS appreciate this commenter

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feedback and have taken it into
consideration. Because this is a
technical claim that must be evaluated
in the context of an LCA and is
applicable to only certain categories of
feedstock, it would not be appropriate to
incorporate these recommendations in
the text of the final regulations as a
generally applicable rule.
In the preamble to the proposed
regulations, the Treasury Department
and the IRS also requested comment on
whether the classification of feedstocks
as products, co-products, byproducts, or
waste change depending on the
technology. Specifically, the Treasury
Department and the IRS asked whether
products, co-products, byproducts, and
waste should be described and
accounted for differently if derived from
biogenic sources.
The Treasury Department and the IRS
received a wide range of comments in
response to this question. A number of
commenters requested that either all or
a subset of woody biomass feedstocks be
designated as waste or residue, with
many pointing to woody biomassspecific industry definitions of terms
like waste, residue, co-product, and
byproduct. Some commenters requested
that woody biomass feedstocks be
designated as waste or residue if the
feedstock is not intentionally grown and
harvested for wood energy applications
or if the feedstock is grown in a
particular region where woody biomass
has an alternative fate that is typically
high in GHG emissions. One commenter
requested that woody biomass feedstock
that is left over from the manufacturing
and repair of wood pallets be classified
as a residue.
One commenter suggested that
products, co-products, byproducts, and
waste be accounted for differently if
derived from biogenic sources by using
ASTM D6866 Method B to determine
and report their biogenic content. This
commenter noted this standard’s use in
Canada’s Clean Fuels Regulation.
Other commenters recommended
against classifying woody biomass
feedstocks as waste or residue. Some
stated that the definition of these terms
as used in the forest industry is broadly
defined and does not sufficiently
consider alternative uses of the
feedstock. Some further expressed
concern that the appropriate designation
of woody biomass as a residue or a
waste is not verifiable after its initial
processing by foresters.
One commenter asked that the final
regulations clarify whether the LCA will
recognize treatment of residue materials
as distinct from waste. The commenter
further recommended that forestry and
logging residues should be defined as

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‘‘materials generated by some other
process, where the alternative fate is
decomposition or burning without
energy recovery.’’ The commenter
suggested that such materials should not
be designated as residues if their most
likely alternative fate is decay because
it is less carbon intensive than burning
the materials for electricity.
One commenter recommended that
trees harvested for the forest biomass
industry that come from land harvested
entirely (or almost entirely) to satisfy
wood pellet or bioenergy demand not be
designated as byproducts. The
commenter stated that because the trees
would not have been harvested but for
demand from the forest biomass
industry, they are therefore the primary
economic driver of the harvest and thus
not a byproduct. The commenter further
recommended that the final regulations
clarify what it means for a material to
be the primary economic driver of a
process.
The Treasury Department and the IRS
also received a comment about the
designation of materials used by a
WERP facility. A commenter
recommended that the final regulations
treat such waste heat as a waste product.
The Treasury Department and the IRS
appreciate these commenters’ feedback
and have taken it into consideration.
Because technical and fact-specific
suggestions regarding designation or
emissions accounting for a particular
feedstock must be evaluated in the
context of an LCA, the suitability of
these recommendations requires further
consideration of their application to
specific cases and these
recommendations are not included in
these final regulations at this time.
The Treasury Department and the IRS
have also determined that
distinguishing between residues and
wastes in the final regulations is
unnecessary. The principles for
categorizing and evaluating the GHG
emissions of materials that are provided
in these final regulations require an
assessment of their associated uses or
removal or disposal processes, as
applicable, and associated GHG
emissions. This requirement mitigates
the need to address a distinction
between residues and wastes as a
residue may be categorized within one
of the categories defined earlier.
The Treasury Department and the IRS
have further determined that further
clarification of the term ‘‘the primary
economic driver of the process’’ within
the previously described definitions is
not necessary in the final regulations
because this concept provides sufficient
clarity in conducting an LCA.

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3. LCA Modeling Topics
a. Certain Issues Related to LCA
Baselines and Modeling
The preamble to the proposed
regulations posed twelve questions
related to factors that must be
considered to assess the net GHG
emissions associated with the
production of electricity by a C&G
Facility in the context of the section 45Y
and 48E credits. This list included
questions on six subtopics, including
about: (1) the creation and maintenance
of LCA baselines; (2) existing models
and data sources that could be used for
modeling; (3) how to account for
incentives created by the section 45Y
and 48E credits; (4) how to establish
feedstock categories; (5) how to assess
shocks; and (6) how to account for
variation and uncertainty in models.
Responses to comments received about
the creation and maintenance of LCA
baselines can be found in section
VIII.C.2.c. of this Summary of
Comments and Explanation of
Revisions. Responses to comments
received about how to account for
incentives created by the section 45Y
and 48E credits can be found in section
VIII.D.2. of this Summary of Comments
and Explanation of Revisions. This
section contains responses to the
comments received on the other four
sub-topics listed earlier.
i. Feedstock Categorization
The preamble to the proposed
regulations requested comment on
feedstock classification and posed a
series of questions. The Treasury
Department and the IRS received a
number of comments in response to
these questions. One comment
expressed support generally for the idea
of differentiating between subcategories
of feedstock in the LCA, and another
comment recommended subcategorizing
feedstocks to the greatest extent
possible.
The Treasury Department received a
number of comments on the topic of
whether to subcategorize biomass
feedstocks to differentiate between
feedstock that is waste and feedstock
that is not. Several commenters
expressed support for this idea, while
several others expressed opposition to
it. See section VIII.D.2. of this Summary
of Comments and Explanation of
Revisions for further discussion of
categorizing some feedstock as waste.
The Treasury Department and the IRS
received comments that provided a
range of suggestions regarding how best
to categorize woody biomass feedstocks.
A few opposed subcategorization of
woody biomass feedstocks. One

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commenter recommended that forest
biomass feedstocks be considered one
type or category of facility to avoid
unduly burdensome complex analysis.
Another who opposed subcategorizing
feedstock altogether urged that, in the
event that forest biomass feedstocks are
subcategorized, the Treasury
Department require reliable, verifiable
bases for each sub-categorization as a
means of reducing uncertainty. Several
commenters endorsed the idea of
creating subcategories of woody biomass
feedstock and provided various
recommendations about how to do so.
One commenter recommended that trees
be categorized based upon species and
upon management practices such as
clear cutting or thinning to most
accurately capture ‘‘carbon debt
payback times.’’ Another recommended
that woody biomass forest feedstock be
categorized based on use, with at least
five categories, including saw timber,
low-grade roundwood or pulpwood,
forestry or harvesting residues, sawmill
and other woody industry residues, and
post-consumer waste wood. A different
commenter suggested creating feedstock
categories that are further divided by the
feedstock’s potential alternative fates.
Several commenters provided
information or recommendations on
how blends of fuels or feedstocks
should be treated in the LCA or the
annual publication of emissions rates.
One commenter suggested that
precaution is warranted to ensure that
facilities using a blend of fuels are not
deemed to have a net GHG emissions
rate of not greater than zero if they do
in fact have a positive net GHG
emissions rate. Another commenter
recommended that the LCA
accommodate site specific feedstock
use, which may include mixed
feedstocks or blending with RNG.
Finally, one commenter stated that there
are several options for providing an
emissions rate to facilities that use a mix
of feedstocks. This commenter further
stated that the Secretary could provide
a formula by which taxpayers can use
the published emissions rates in the
Annual Table to calculate their facility’s
rate; that all facilities using a blend of
fuels could be required to obtain an
emissions rate via the provisional
emissions rate (PER) process; or that
facilities using multiple fuels could be
deemed to be multiple separate facilities
for the purposes of the credit and a rate
calculated for each facility.
The Treasury Department and the IRS,
appreciate these recommendations and
have taken them into consideration.
However, given the diversity of fuel and
feedstock blends that may be evaluated
for the purposes of the section 45Y and

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48E credits, incorporating specific
requirements suggested by these
commenters in the text of the final
regulations would be inappropriate as a
generally applicable rule. Therefore, the
commenters’ recommendations will not
be included in the text of the final
regulations.
ii. Shocks
In the preamble to the proposed
regulations, the Treasury Department
and the IRS posed several questions
about the treatment of shocks in
modeling. One such question solicited
comment regarding what factors should
be considered to determine the
appropriate scale(s) of feedstock
demand changes or other shocks to
evaluate the extent to which the
production, processing, and use of the
feedstocks used for electricity
production results in net greenhouse gas
emissions. One commenter
recommended that the scale of demand
be assessed in the context of what types
of feedstocks are most likely to be used,
which the commenter recommends
projecting based on current practice.
In the preamble to the proposed
regulations, the Treasury Department
and the IRS further requested comment
on whether shocks should reflect a
small incremental increase in the use of
the feedstock to reflect the marginal
impact or a large increase to reflect the
average effect of all potential users. One
commenter recommended that both
approaches be used to provide a
comprehensive understanding of the
potential impacts of the change.
Another commenter suggested that
incremental increases may not
accurately reflect the consequences of a
policy because large demand shocks can
have qualitatively different effects than
incremental shocks. This commenter
further stated that a shock that reflects
all users can be a poor tool in cases in
which local markets are important. This
commenter recommended estimating
regional factors before averaging to find
the effect on all users and suggested that
model testing be similarly applied to
evaluate differences between marginal
increases in feedstock demand and
absolute demand provided in the region.
In the preamble to the proposed
regulations, the Treasury Department
and the IRS also requested comment on
what the general increment of the shock
could be and whether it should be
specified as an absolute or relative
increase. One commenter suggested that
when demand is not pre-determined,
scenario modeling could be used to
evaluate potential effects. The
commenter recommended
complementing this analysis with a

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series of marginal model runs to
evaluate how an increase in demand
impacts model results.
Finally, in the preamble to the
proposed regulations, the Treasury
Department and the IRS requested
comment on what factors should be
considered to determine whether shocks
for different feedstocks should be
implemented in isolation (separate
model runs), in aggregate (for example,
as an across-the-board increase in
biomass usage endogenously allocated
by the model across feedstocks), or
something in between (for example,
separately model agriculture-derived
and forest-derived feedstocks, but
endogenously allocate within each
category). A commenter recommended
that similar feedstocks that offer
comparable results in model testing be
implemented in aggregate. Another
commenter suggested that in a
regulatory framework, it is likely most
appropriate to model at the asset level,
such as by modeling a shock applied to
the surrounding landscape based on
anticipated demand for feedstock of a
new bioenergy investment.
The Treasury Department and the IRS
appreciate these recommendations and
have taken them into consideration.
However, given the complexity of
modeling shocks in the LCA and the
diversity of fuels and feedstocks that
may be evaluated for the purposes of the
section 45Y and 48E credits,
incorporating the specific requirements
suggested by these commenters in the
final regulations would be inappropriate
as a generally applicable rule. Therefore,
the commenters’ recommendations will
not be included in the final regulations.
iii. Variation and Uncertainty in Models
In the preamble to the proposed
regulations, the Treasury Department
and the IRS posed a number of
questions about the treatment of
variation and uncertainty in evaluating
model estimates. Commenters provided
a range of recommendations in response
to these questions. Some suggested that
modeling multiple outcomes is an
important factor in reducing the
uncertainty of modeled GHG emissions
changes. One commenter further
recommended that Treasury be
transparent about the assumptions made
when modeling, ensure that biomass
feedstock utilization assumptions are
backed by robust traceability and a
supply chain of custody to ensure that
the biomass modeled in the LCA is the
biomass transported across the supply
chain, and use conservative estimates.
Another commenter recommended a
similarly precautionary approach in
situations in which a given assumption

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could ‘‘fully flip’’ an outcome from
being calculated as a net climate benefit
to being calculated as a net climate
harm.
One commenter noted their support
for the use of consequential modeling,
stating that their recommendation is ‘‘in
part’’ because land sector modeling is
frequently subject to large uncertainties
that are better addressed by effective
policy design than by embedding
quantified impacts within the regulatory
framework. The commenter stated that
this is especially true when applying
complex econometric modeling to
scenarios relying on large temporal and
spatial boundaries.
Another commenter similarly noted
that longer assessment horizons increase
uncertainties and asserted that using an
assessment horizon that constrains the
compounding effects of uncertainties is
an essential component to limit
uncertainty. This commenter further
recommended against the use of
economic models, stating that they
generate unacceptable levels of
uncertainty.
The Treasury Department and the IRS
appreciate these recommendations and
have taken them into consideration.
However, given the complexity of
considering variation and uncertainty in
evaluating model estimates and the
diversity of fuels and feedstocks that
may be evaluated for the purposes of the
section 45Y and 48E credits,
incorporating the specific requirements
suggested by these commenters in these
final regulations would be inappropriate
as a generally applicable rule. Therefore,
although the considerations that
commenters raise—such as the
importance of verification and the
uncertainty inherent to modeling—have
been incorporated in concept in other
aspects of the LCA and substantiation
requirements, the commenters’ specific
recommendations will not be included
in these final regulations.
b. Recommended Models and Modeling
Sources
i. Recommended LCA Models
In the preamble to the proposed
regulations, the Treasury Department
and the IRS requested comment
regarding what existing model or suite
of models are capable of completing an
LCA consistent with the section
45Y(b)(2)(B) and proposed § 1.45Y–5(d)
and (e) and asked for additional
information regarding suggested models.
Commenters provided a wide range of
views. Several commenters requested a
consistent and technology-neutral
approach be adopted for LCA
assessment of all renewable energy

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technology and from all feedstocks.
Another commenter emphasized that
whatever model is employed, it is
critical that it reflects current peer
reviewed literature and is well
supported by available data and science.
Most commenters strongly advocated
for the use of a version of the GREET
model to complete an LCA consistent
with requirements of the section 45Y
and 48E credits. Several commenters
noted that the GREET model is
thorough, widely accepted, and the
ideal model to be used for tax incentives
in the IRA. These commenters further
asserted that allowing the GREET model
as the assessment tool for the section
45Y and 48E credits (in addition to the
section 40B and 45V credits) would
further bring all the emission
calculations required under the IRA tax
credit provisions under a single
verification regime, which could be
controlled by U.S. Federal agencies
responsible for implementing the IRA
2022 tax incentives. A commenter
emphasized that methodological
consistency between IRA tax credits is
important to avoid unintended market
effects, particularly if credited products
under sections 45Y and 48E, 40B, and
45V have overlapping accounting
boundaries (for example, RNG lifecycle
emissions are relevant under all four).
Notably, most commenters
overwhelmingly supported the use of
the GREET model for the emissions
assessment required by sections 45Y
and 48E without specifying a specific
version of the GREET model.
While supporting the use of the
GREET model, a commenter noted that
the GREET model is still an
approximation of reality and must be
regularly updated to reflect real-world
trends and the latest research. Several
commenters recommended that the
Treasury Department and the IRS
leverage both the existing GREET model
and EPA modeling to inform feedstockspecific GHG emissions rates and
associated avoided emissions.
Other commenters specifically
requested that the former ANL–GREET
model, (now referred to as the R&D
GREET model) be used. Specially, these
commenters asserted that the Treasury
Department and the IRS adopt the 2023
R&D GREET model (or a successor) for
emissions assessments for the section
45Y and 48E credits. These commenters
note that this would assist the Treasury
Department and the IRS in timely
providing a model and allow for
efficiencies going forward as the R&D
GREET model is already regularly
updated. These commenters also assert
that using the R&D GREET model (or a
successor) will make the LCA process

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clearer, more certain, and more
effective, consistent with congressional
intent to encourage the deployment of
zero-emission technologies. Other
commenters suggested the use of the
R&D GREET model because it takes
methane leakage and counterfactual
assumptions into account. A commenter
noted that using the R&D GREET model
will reduce the prospect of relying on
the PERs process because the R&D
GREET model allows for site-specific
RNG carbon intensity scores. Another
commenter noted that the R&D GREET
model is another publicly available
model which has incorporated a process
model for estimating emissions from
landfills. However, the commenter
noted that the current version of the
GREET R&D model needs several
updates and modifications to properly
reflect the latest peer-reviewed
information.
Several commenters opposed the use
of the GREET model. A commenter
noted that the GREET model lags
deployment and so favors longer
established technologies like wind and
solar to the detriment of technologies
such as biomass gasification with CCS.
This commenter noted that relying on
the GREET model would certainly
disadvantage and perhaps disqualify
new technologies that are the most
carbon-negative, while simultaneously
favoring projects which would use a
fuel such as municipal solid waste,
which is not climate friendly, yet is
considered by the model to be carbonnegative. This commenter also asserted
that such a perverse incentive is not a
desired outcome and yet is possible
with the application of a static model to
a dynamic industry deploying novel and
first-of-kind technologies. Other
commenters opposed the use of the
GREET model by asserting that the
GREET model underestimates avoided
methane emissions from diverting waste
from a landfill. The Treasury
Department and the IRS do not believe
that the R&D GREET model is the
appropriate model for determining GHG
emissions rates for the section 45Y and
48E credits because it does not conform
to the principles and requirements for
LCA analysis provided in this final
regulation.
Several commenters suggested the use
of alternate models for a specific type of
feedstock. For municipal solid waste
(referred to as MSW), several
commenters recommended the use of
the MSW–DST and the EPA’s WARM
models, which are publicly available
waste management-focused lifecycle
models. The MSW–DST is an LCA
model tailored directly for the waste
sector that has been used by the DOE’s

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National Renewable Energy Laboratory
(NREL) for previous analyses. The
WARM model is provided by the EPA
and specifically built to allow high-level
comparisons of potential greenhouse gas
emissions reductions, energy savings,
and economic impacts when
considering different materials
management practices.
A commenter expressed concern that
both the MSW–DST and the WARM
models require further refinements to
ensure they are accurately quantifying
the GHG emissions outcomes associated
with diverting post-recycled waste from
landfills to waste-to energy (WTE)
facilities. The commenter noted that
these models are not equipped to model
emissions for other energy generation
technologies and acknowledges that the
use of these models for wastes, while
potentially using the GREET model to
evaluate other technologies, could pose
challenges.
For biomass, several commenters
recommended the use of the California
Biomass Residue Emissions
Characterization (C–BREC) model.
These commenters note that the C–
BREC model provides a robust LCA for
forest residues used for electricity
generation, which enables detailed and
transparent accounting for GHG and air
pollutant emissions and evaluates
emissions across different project
profiles, including the reference fate of
unutilized biomass. The commenter
noted that although the C–BREC model
results show that the emissions
associated with wildfire risk are
significant for biomass residues left in
the forest, the wildfire probability
factors used in the model are outdated
and the real risk is much higher.
Therefore, the commenter asserts that
C–BREC likely underestimates the
actual risk of wildfires in California,
leading to potential underestimation of
emissions from biomass residues left in
forests.
Several commenters suggested models
related to forest-related feedstocks. A
commenter suggested the use of the
published C–ROADS and En-ROADS
models to calculate forest ecosystem
and harvested carbon estimates. The
commenter noted that these dynamic
models represent the carbon cycle,
budgets and stocks of GHGs, radiative
forcing, and the heat balance of the
Earth. The commenter also noted that
both models are freely available and
fully documented.
Another commenter supported the
use of timber projection models like
ATLAS (Aggregate Timberland
Assessment System), which is managed
and updated by the U.S. Forest Service,
providing projections at regional and

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national scales. This commenter noted
that ATLAS models different timber
yield scenarios, and their respective
implications for carbon stocks.
Additionally, a commenter supported
the use of the Landscape Carbon Factor
Tool, developed by the American Forest
Foundation, to calculate net carbon
stock changes in forest regions of
variable sizes using the USFS Forest
Inventory Assessment (FIA) data. The
commenter noted that this tool can
provide important data on the current
state of carbon stocks in a sourcing area
that can be used to inform a full
consequential LCA, which will also
predict future changes in carbon stocks.
The commenter pointed out that this
tool could be used as an initial screen
to determine whether biomass will meet
the ‘‘not greater than zero’’ emissions
rate criterion provided that net forest
stocks in the region of consideration are
maintained or increased.
While no commenters suggested using
the Forestry and Agricultural Sector
Optimization Model with Greenhouse
Gases (FASOM–GHG) Model to assess
GHG emissions for purposes of the
section 45Y and 48E credits, several
commenters specifically asserted that
the Treasury Department and the IRS
should not adopt it for this purpose.
These commenters noted that the
FASOM–GHG model is not a credible
source of estimates of wood harvest
emissions due to a lack of global
analysis, poor performance for this
purpose, lack of reasonable cost data
and contradiction with known
estimates, and structural bias.
The Treasury Department and the IRS
appreciate the thoughtful responses
provided by commenters. After taking
into account the wide variety of
different mechanisms for generating
electricity through combustion or
gasification that would require an LCA,
the Treasury Department and the IRS
have determined that there is not a clear
or obvious single model or models that
would be appropriate for all situations.
After consideration of these comments,
the Treasury Department and the IRS
will coordinate with Federal agency
scientific and technical experts on the
selection and development of a model
or models to assess net GHG emissions
for purposes of the section 45Y and 48E
credits.
ii. Recommended Data Sources and
Peer-Reviewed Studies
In the preamble to the proposed
regulations, the Treasury Department
and the IRS requested comments
regarding what data sources and peerreviewed studies provide information
on different feedstock production

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systems that would be most important
to consider for gathering data for LCA
modeling. The Treasury Department and
the IRS also noted that these sources
and studies should provide information
on the feedstock production process
(ideally, beginning with the extraction
or generation of the feedstock and
ending at the electrical meter) and on
markets related to the feedstock
production process.
The commenters recommended a
wide range of data sets to provide
information on different feedstock
production systems. A commenter noted
that feedstock production systems vary
by industry and should be assessed on
an industry-by-industry basis. However,
the same commenter also noted that the
same principles can be used to make
decisions on feedstock production
system irrespective of the industry.
For biomass, a commenter
recommended the use of forest
inventories that characterize the stocks
of carbon in different forests. This
commenter noted the USDA Forest
Service’s Forest Inventory and Analysis
(FIA) Program as an open-source,
nationally consistent inventory of forest
resources that is regularly updated.
Further, the commenter noted that the
FIA database provides comprehensive
information on forest stand
characteristics, growth rates, and carbon
stocks across different regions of the
United States. It employs direct
measurements from a network of
permanent sample plots, offering highquality, empirical data at both regional
and national scales.
For MSW, several commenters noted
that the EPA should be referenced as a
primary source of information on the
physical properties of MSW and
specifically pointed to the EPA’s
emission factor database, AP–42: A
Compilation of Emissions Factors from
Stationary Sources (AP–42), based on
data from 40 landfills, U.S. EPA Landfill
Gas Emission Model (LandGEM) default
L0 for inventory purposes. Additionally,
a commenter noted that the importance
of data reported from the combustion of
MSW at existing WTE facilities to the
EPA’s GHGRP. These commenters
asserted that given the extensive
monitoring employed at WTE facilities,
they can serve as a critical source of
lifecycle data, including for biogenic
carbon fraction and total carbon content
both for WTE emissions and to serve as
a possible resource for data on process
inputs used for the baseline scenario of
landfilling.
The Treasury Department and the IRS
appreciate the data sources provided by
commenters. Given the extensive range
of feedstocks and types of facilities, and

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the fact that no data source seems to
address all use cases, the Treasury
Department and the IRS are continuing
to evaluate and consider the utility of
the data sources identified by
commenters. The Treasury Department
and the IRS will coordinate with
Federal agency scientific and technical
experts on the use of data sets in the
development of a model or models to
assess GHG emissions for purposes of
the section 45Y and 48E credits.
E. Treatment of Specific Types of
Facilities and Feedstocks
1. Combined Heat and Power (CHP)
Property
Section 45Y(g)(2)(A) provides that the
kWh of electricity produced by a
taxpayer at a qualified facility includes
any production in the form of useful
thermal energy by any CHP property
within such facility, and the amount of
GHGs emitted into the atmosphere by
such facility in the production of such
useful thermal energy will be included
for purposes of determining the GHG
emissions rate for such facility. The
inclusion of thermal energy productionrelated emissions in an LCA for a CHP
property introduces additional
considerations, such as how to set an
appropriate baseline for useful energy
production-related emissions and what
rules should govern the attribution of
emissions for thermal energy
production. In the preamble to the
proposed regulations, the Treasury
Department and the IRS indicated an
intention to clarify the principles for
assessing the emissions related to the
generation of useful thermal energy by
a CHP property in an LCA in the final
regulations for the section 45Y and 48E
credits and posed a number of
questions.
Several commenters requested that
CHP property be categorized as nonC&G Facilities. A commenter requested
that CHP property that derives its
energy from facilities on the
‘‘categorically non-C&G’’ list should also
be included on that list. However, the
statute does not alter the definition of a
‘‘qualified facility’’ for CHP property,
and the Treasury Department and the
IRS therefore do not have the authority
to treat CHP property that produce
electricity through combustion or
gasification any differently from other
facilities (that is, the same rules for
classifying facilities and determining
emissions rates apply). However, the
Treasury Department and the IRS note
that certain types of CHP facilities may
meet the definition of a Non-C&G
Facility if they do not produce
electricity and heat through combustion.

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Under the statute, to determine the
amount of GHGs emitted by a C&G CHP
property, the LCA must include the net
GHG emissions emitted by that facility
in the production of useful thermal
energy. For purposes of an LCA for a
CHP property, the Treasury Department
and the IRS asked what principles
should govern how GHG emissions from
the production of useful thermal energy
are calculated. In response, several
commenters advocated for the use of an
output-based standard for emissions
calculation for a CHP property. An
output-based standard is based on
emissions per unit of energy generated
rather than amount of fuel used, which
is addressed in an input-based standard.
Commenters asserted that an outputbased standard is appropriate to govern
an LCA for a CHP property because it
produces two useful outputs (electrical
and thermal energy) that are each fully
credited under this analysis.
Additionally, several commenters
recommended that the final regulations
adopt LCA principles similar to those
incorporated by the 2023 R&D GREET
model (or a successor), which includes
inputs for ‘‘equivalent electric efficiency
using fuel allocated to power
generation’’ and ‘‘overall plant
conversion efficiency.’’ These
commenters supported this
recommendation by noting that this
LCA approach would incorporate
principles similar to the LCA principles
used for the section 40B and 45V
credits. A commenter noted that an LCA
for natural gas-fired CHP property
should account for lower emission gas
supplies, or use assumptions for projectspecific leakage rates, to encourage
suppliers to reduce methane leakages.
The Treasury Department and the IRS
appreciate this feedback and will
consider these recommendations as LCA
development for CHP property
continues.
In the preamble to the proposed
regulations, the Treasury Department
and the IRS requested comment
regarding what principles should be
used to determine the baseline for
useful thermal energy production by a
CHP property. In response, several
commenters noted that fossil fuel
displacement should be the baseline for
an LCA for a CHP property. The
commenters asserted that to quantify the
GHG emissions savings of a CHP
property, the emissions from the CHP
property should be subtracted from the
fuel use that would normally occur
without the CHP property in place—
normally generating heat from an onsite
natural gas boiler and using power from
offsite generation powering the grid.
The commenters suggested establishing

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a baseline emissions profile and then
quantifying expected GHG emission
reductions and providing methods for
accounting for the displacement of
marginal grid resources to account for
energy efficiency improvements. To
support this recommendation, the
commenters generally cited common
LCA practice, ISO guidance, and the
plain language of the CAA for
calculating GHG emissions.
A commenter recommended that an
LCA assess GHG emissions from the
production of useful thermal energy in
a CHP property by using a baseline
emissions rate composed of (i) an
electric-only plant using the same prime
mover design (make/model of the steam
turbine, combustion turbine or
reciprocating engine plant) producing
the same net quantity of electricity
generation as produced in the CHP
property; and (ii) a natural gas boiler
producing the same net quantity of
useful thermal energy produced in the
CHP property. The GHG emissions from
the production of useful thermal energy
in the CHP property would then be
calculated by subtracting the emissions
of the CHP property (based on LCA
emissions per unit of fuel consumed)
and the net generation of electrical and
thermal energy (net of energy produced
and used within the facility before
energy is exported from the facility)
from the baseline emissions.
Similarly, a commenter noted that
following the GHG Protocol for Project
Accounting, the typical baseline for
C&G projects would include the current
fate of the residue, the current emissions
associated with the grid where the
project would be located, and the
current energy source for thermal energy
when looking at a CHP property. The
commenter recommended that an LCA
is conducted for the baseline, and an
LCA is conducted for the proposed
project. The difference between these
two is the ‘‘net’’ GHG emissions rate for
the project.
Additionally, several commenters
supported the adoption of displacement
principles by noting that biologic carbon
(such as wood) would enter the
atmosphere regardless of whether it is
combusted or through the ecological
process of decomposition once a tree
dies. Conversely, these commenters
noted that fossil fuels are sources of
geologic carbon that would otherwise
not enter the atmosphere if not for their
combustion. Therefore, the commenters
asserted that wood utilized for
cogeneration releases no additional net
carbon to this cycle and can even reduce
emissions when used as a substitute for
fossil fuels.

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While supporting the adoption of
displacement principles in an LCA,
several commenters also advocated for
the final regulations to give credit for
avoided GHG emissions from the
alternative fate of the biomass which
include being piled and burned with
uncontrolled criteria pollutants and
GHG emissions; masticated and left onsite, increasing fuels for future fires; or
transported long distances to available
disposal sites, incurring high costs and
associated emissions. These
commenters also noted that an LCA
must credit emissions offsets by biomass
generated energy when compared to the
emissions from alternative replacement
power. These commenters noted that if
these two considerations are allowed,
utilization of woody biomass will easily
be shown to be carbon neutral or likely
negative, with net GHG emissions at an
acceptable level. The issues raised by
these comments are addressed in
section VIII.C. of this Summary of
Comments and Explanation of
Revisions.
Section 45Y(g)(2)(A) provides a
special rule for CHP property, which
explicitly includes any production in
the form of useful thermal energy in the
calculation of the credit as well as the
amount of GHG emissions from the
facility in the production of such useful
thermal energy. After consideration of
the comments, the Treasury Department
and the IRS have determined that the
best reading of section 45Y(g)(2)(A) is
that thermal energy produced by a CHP
property is accounted for with the
electricity produced by the facility in
assessing the GHG emissions from the
facility. As a result, the baseline for
GHG emissions from thermal energy
produced by a CHP property are zero,
which is consistent with LCA
accounting for electricity and provides a
consistent baseline between electrical
and thermal energy. Even though it is a
departure from some of the LCA
methods typically used within the CHP
industry, this treatment is an option
within LCA accounting methodology
that is consistent with the principles
and requirements for an LCA used to
determine a GHG emissions rate for
purposes of sections 45Y and 48E.
Additionally, the preamble to the
proposed regulations noted that there
may be scenarios in which a facility
generates electricity that is used (i) by
the electricity generation facility in the
production of electricity; or (ii) in the
production of fuel ultimately consumed
by that facility to generate electricity.
For example, a wastewater treatment
plant’s post-processing materials are
digested to produce biogas; this biogas
is then used in a CHP property that

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produces electricity; and this electricity
is consumed by the wastewater
treatment facility. The Treasury
Department and the IRS requested
comment on what principles should be
used to determine how GHG emissions
from the consumption of electricity in
the production of electricity or in the
production of the fuel consumed by the
facility are calculated. In response, a
commenter noted they were not aware
of any circumstances in which any CHP
property host would consume electricity
from the CHP property for the sole or
primary purpose of generating
electricity. The commenter also noted
that generally facilities hosting CHP
property use the electricity and thermal
energy onsite to meet the needs of host
facility or export that energy via the grid
or district energy system respectively.
The commenter asserted that to the
extent such facilities support the
production of useful biogas from the
wastewater stream that can be used for
future fuel for the CHP property, the
Treasury Department and the IRS
should not craft rules that would
discourage productive use of byproducts
as fuel.
The Treasury Department and the IRS
confirm that the rules provided in these
final regulations are not intended to
encourage or discourage certain fuels or
feedstocks for electricity production but
to outline LCA principles such that
LCAs of C&G Facilities, including CHP
property, result in impartial and robust
assessments of net GHG emissions
across feedstocks, fuels, and facility
types to determine eligibility.
The preamble to the proposed
regulations similarly noted that there
may be scenarios in which a facility
self-consumes thermal energy that it
produces, for example, if a facility
generates steam as a byproduct that is
used (a) by the facility to turn a turbine
that generates electricity or (b) to clean
or compress fuel ultimately consumed
by that facility to generate electricity.
The Treasury Department and the IRS
requested comment regarding what
principles should be used be used to
determine GHG emissions from the selfconsumption of thermal energy by the
CHP property. In response, a commenter
proposed that facilities should not be
assessed based on the purposes for
which the useful energy is used,
including both electricity and the heat
in the case of a CHP property. Proposed
§ 1.45Y–5(d)(2)(ii) provided that the
ending boundary ‘‘for electricity that is
transmitted to the grid or electricity that
is used on-site is the meter at the point
of production of the C&G Facility’’
therefore the use of the electricity does
not impact the LCA assessment as it is

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outside of the LCA system boundary.
See section VIII.C. of this Summary of
Comments and Explanation of Revisions
for additional discussion of comments
pertaining to the LCA ending boundary.
The anticipated future baseline
scenario as described in § 1.45Y–
5(d)(2)(iii) will not be impacted by
whether the electricity is sold to the grid
or used onsite. Therefore, whether the
electricity generated from any type of
facility, including a CHP property, is
supplementing or replacing an existing
power source onsite or grid electricity
for the host facility (for example, a
wastewater treatment plant) will not
impact the LCA of the generating
facility.
2. Biomass
The Treasury Department and the IRS
received a number of comments
pertaining to the use of biomass as a
feedstock in the production of
electricity. While these comments and
their responses are addressed
throughout this Summary of Comments
and Explanation of Revisions, the
following paragraphs address comments
regarding the substantiation of
eligibility for the section 45Y and 48E
credits for taxpayers whose C&G Facility
uses biomass as a feedstock.
In the preamble to the proposed
regulations, the Treasury Department
and the IRS requested comment on the
types of documentation that taxpayers
should be required to maintain to
substantiate eligibility for the section
45Y and 48E credits. Specifically,
comment was requested on the types of
documentation or substantiation a
taxpayer should maintain to establish
that an input in the supply chain of a
fuel or feedstock used for electricity
production has the energy attributes or
other relevant characteristics that were
taken into account in determining a
GHG emissions rate; what existing
systems, industry standards, or practices
may be used to substantiate that a
facility’s operations and supply chain
for such inputs resulted in a GHG
emissions rate that is not greater than
zero; how to develop such tracking and
verification systems if they do not
currently exist and how long
development of such systems may take;
and what supply chain tracing systems
or verification bodies address fuels or
feedstocks that may be commonly used
by facilities that may be eligible for the
section 45Y and 48E credits.
The Treasury Department and the IRS
received a number of comments about
whether taxpayers should be required to
maintain documentation or provide
third-party verification of fuels or
feedstocks in order for their qualified

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biomass facility to be eligible for the
section 45Y and 48E credits. While
some noted the importance of oversight
and independent means of verification
to properly substantiate that inputs to
fuel or feedstock have the energy
attributes or other relevant
characteristics that were taken into
account in determining a GHG rate,
others disagreed. Some commenters
requested that taxpayers whose
qualified facilities have less than one
megawatt of capacity not be required to
maintain or provide any documentation
to be eligible for the section 45Y and
48E credits. These commenters further
recommended that taxpayers be
required only to self-attest to the volume
of biogenic feedstock received under a
given category for that year, total
generation, and percentage of fuel usage,
similar to the procedure that currently
exists for biomass facilities participating
in the California Bioenergy Market
Adjusting Tariff (BioMAT).
Other commenters suggested
verification bodies or tools for use in
confirming the GHG emissions rate of
qualified biomass facilities. One
commenter suggested a tool in
development that they have
commissioned to calculate net carbon
stock changes in forest regions. Other
commenters suggested existing thirdparty certifications, such as those
provided by the Sustainable Forestry
Initiative (SFI), the Forest Stewardship
Council (FSC), the Sustainable Biomass
Program (SBP), and the International
Sustainability and Carbon Certification
System (ISCC). However, some
commenters critiqued the design of
these certifications, asserting that they
provide inadequate monitoring and
enforcement.
The Treasury Department and the IRS
appreciate the information shared by
commenters on these matters and have
taken it into consideration. Woody
biomass can pose unique issues
warranting verification because wood
sourced from different types and parts
of trees may have very different LCA
profiles but appear uniform after
processing and upon delivery to an
electricity production facility. The
Treasury Department and the IRS intend
to provide additional information in
future guidance about how taxpayers
should substantiate compliance with the
statute’s requirements. See section
VIII.J. of this Summary of Comments
and Explanation of Revisions for more
information about substantiation. To
ensure that C&G Facilities that utilize
biomass feedstocks meet the statutory
requirement of a net GHG emissions rate
not greater than zero, the Treasury
Department and the IRS anticipate that

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it may be appropriate to require or
encourage taxpayers to maintain thirdparty certification that verifies that these
facilities meet the criteria that the LCA
has found are necessary for a facility to
meet this statutory requirement.

been assessed and confirmed through an
LCA that satisfies all the requirements
of section 45Y(b)(2)(B) and these final
regulations. The final regulations will
therefore not reflect these commenters’
suggestions.

3. Waste-to-Energy (WTE) Facilities
The Treasury Department and the IRS
received many comments pertaining to
the use of WTE facilities in the
production of electricity. While these
comments and their responses are
addressed throughout this preamble,
including in section VIII.C. (LCA
Requirements), the following paragraphs
address comments regarding the
eligibility for the section 45Y and 48E
credits for taxpayers that use WTE
facilities (such as landfills and waste
incinerators) in the production of
electricity.
Commenters have sharply divergent
views regarding the eligibility of WTE
facilities for the section 45Y and 48E
credits. Many commenters requested
that the production of electricity from
WTE facilities be specifically excluded
from qualifying for the credits. To
support this view, several commenters
noted that WTE facilities are significant
emitters of GHG emissions, and as it
was clearly not the intent of Congress to
allow GHG producing industries to be
eligible for the credits, WTE facilities
should not be eligible. These
commenters also asserted that WTE
facilities should not be eligible for the
credits because WTE facilities are
disproportionately located in lowincome and marginalized communities
and can endanger a community’s health.
Conversely, several commenters
strongly advocated for the eligibility of
WTE facilities for the section 45Y and
48E credits. These commenters noted
that WTE facilities would have
traditionally fit into the category of
landfill or trash facilities once eligible
for the section 45 credit and therefore,
should be eligible for the section 45Y
and 48E credits. Several commenters
requested that WTE facilities be
included as Non-C&G Facilities on the
Annual Table that will be published by
the Treasury Department and the IRS.
The Treasury Department and the IRS
appreciate the input shared by
commenters and have taken it into
consideration. Because WTE facilities
produce electricity through combustion,
they are C&G Facilities, and whether a
WTE facility is eligible for the section
45Y or 48E credits must be assessed
through an LCA. Accordingly,
categorically excluding or including
WTE facilities as eligible for the section
45Y and 48E credits is not appropriate
unless and until their eligibility has

4. 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
electricity production that uses biogas,
RNG, and fugitive sources of methane
(collectively, natural gas alternatives),
for purposes of the section 45Y and 48E
credits. The assessment of 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 electricity 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 rules.
The Treasury Department and the IRS
received many comments regarding the
treatment of natural gas alternatives.
While specific recommendations are
addressed later in this section,
commenters broadly emphasized the
importance and complexity of
establishing appropriate alternative fates
for these feedstocks. For example, some
commenters noted that it is critical for
the Treasury Department and the IRS to
provide clear rules to enable RNG to be
used in the production of clean
electricity. Other commenters warned
that failure to specify appropriate
guardrails in this area could lead to
incorrect emissions assessments and
substantial claims under sections 45Y
and 48E for C&G Facilities that in fact
have net rates of GHG emissions that are
greater than zero, which would
undermine the purpose of sections 45Y
and 48E.
The Treasury Department and the IRS
agree with commenters that the
determination of alternative fates for
natural gas alternatives is both complex
and important for accurately
determining eligibility under sections
45Y and 48E. GHG emissions rates for
C&G Facilities generally must be
determined consistent with section
45Y(b)(2)(B) and the rules provided in
§ 1.45Y–5(d) and (f). Within this
statutory and regulatory framework, the
Treasury Department and the IRS have
determined that specifically addressing

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the assessment of alternative fates for
natural gas alternatives will help ensure
accurate lifecycle GHG emissions
determinations and prevent improper
credit claims, advance sound tax
administration, and increase certainty
for taxpayers. Therefore, § 1.45Y–5(e)(3)
applies the rules in § 1.45Y–5(d) and (f)
to establish alternative fates for natural
gas alternatives from certain sources
that are used by a C&G Facility in the
production of electricity. In assessing
the alternative fates for certain sources
of natural gas alternatives that may be
used by a C&G Facility in the
production of electricity, as provided in
§ 1.45Y–5(e)(3), the Treasury
Department and the IRS consulted
extensively with interagency technical
experts, including technical experts
from the National Laboratories, to
ensure that the requirements of the
section 45Y and 48E credits, as well as
the rules in § 1.45Y–5(d) and (f), were
applied consistent with sound scientific
principles.
The use of natural gas alternatives and
the assessment of lifecycle GHG
emissions (as defined in section 42
U.S.C. 7545(o)(1)(H)) associated with
such use is relevant beyond the section
45Y and 48E credits. For example, for
purposes of the section 45V credit,
§ 1.45V–4(f)(3) establishes alternative
fates for certain natural gas alternatives
used in the production of hydrogen. The
Treasury Department and the IRS have
concluded that it will provide taxpayer
certainty and advance sound tax
administration to require that
alternative fates for natural gas
alternatives be addressed consistently
across sections 45V, 45Y, and 48E, to
the extent possible consistent with the
requirements of each statute and
incorporating consideration of
comments.
After careful consideration of the
numerous comments submitted in
response to the proposed regulations’
specific requests for comment, the final
regulations provide rules in § 1.45Y–5(e)
related to the use of natural gas
alternatives in the production of
electricity and the assessment of GHG
emissions with respect to natural gas
alternatives. 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 considered the technical
characteristics of different 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.

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a. Definitions
i. Biogas
The preamble to the proposed
regulations did not define the term
‘‘biogas,’’ but, in the interest of
completeness and clarity, § 1.45Y–
5(e)(2)(i) clarifies that the term ‘‘biogas’’
means gas containing methane that
results from the decomposition of
organic matter under anaerobic
conditions.

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ii. 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,
§ 1.45Y–5(e)(2)(ii) provides 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 (CMM) 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).
iii. 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 CMM. Commenters
noted that this definition was broad but
did not recommend alternatives. The
proposed definition is adopted in these
final regulations without substantive
change in § 1.45Y–5(e)(2)(iii). One
commenter asserted that under no
circumstances should methane from oil
and gas operations be treated as fugitive
methane because methane from oil and
gas operations should be attributed the
emissions profile of oil and natural gas
production. 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 sections VIII.E.4.c.i.C. and E. of this
Summary of Comments and Explanation
of Revisions.
iv. Renewable Natural Gas
The preamble to the proposed
regulations would have defined the term
‘‘renewable natural gas’’ to mean
‘‘biogas that has been upgraded to be

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equivalent in nature to fossil natural
gas.’’ Some commenters suggested that
the term ‘‘renewable’’ is misleading in
this context because the production and
use of such gas results in significant
adverse impacts on public health and
welfare. Although the Treasury
Department and the IRS recognize these
concerns, § 1.45Y–5(e)(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.
b. Considerations Regarding GHG
Emissions Assessments of the
Production of Electricity 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 sections 45Y and 48E.
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 electricity. 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 may opt to import fossil natural
gas to satisfy its on-site energy needs.
There is also a risk of significant
indirect emissions, induced emissions,
or inappropriate claims of the section
45Y and 48E credits with respect to
facilities that do not meet the statutory
emissions requirements, if the
incentives provided by sections 45Y and
48E result in the creation of new or
expanded sources of methane or other
GHGs that otherwise would not have
existed, or the creation of additional
methane that would not have been
created or would have remained
sequestered. Section 1.45Y–5(e)(3)(i)
implements section 45Y(b)(2)(B), which,
by reference to 42 U.S.C. 7545(o)(1)(H)
requires consideration of direct and
significant indirect emissions in the

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determination of the net rate of lifecycle
GHG emissions into the atmosphere by
a C&G Facility in the production of
electricity.
i. GHG Emissions Associated With the
Use of Natural Gas Alternatives
The accurate assessment of GHG
emissions is vital to determining
eligibility under sections 45Y and 48E.
GHG emissions assessments that
underestimate the emissions associated
with the production of electricity would
mean that the section 45Y and 48E
credits could be claimed for a facility
even if its GHG emissions rates in fact
exceed the zero-emissions eligibility
threshold established by Congress.
Because the Treasury Department and
the IRS lack authority under sections
45Y and 48E to allow a facility that
produces electricity with a GHG
emissions rate (or, in the case of section
48E, an anticipated rate) that is greater
than zero to be a qualified facility under
section 45Y(b) and section 48E(b),
guardrails are needed in the final
regulations to address the risk of such
credit claims.
The preamble to the proposed
regulations requested comments on the
LCA 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. After
consideration of the comments received,
the final regulations address aspects of
the GHG emissions analysis for natural
gas alternatives used in the production
of electricity. The following sections 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 commenters who assert that
accurately measuring GHG emissions
rates for facilities that rely on methane
from natural gas alternatives to produce
electricity requires taking into account a
wide range of factors to establish the
alternative fate against which the use of
methane to produce electricity should
be assessed. Consistent with the
reference to 42 U.S.C. 7545(o)(1)(H), the
Treasury Department and the IRS
interpret section 45Y(b)(2)(B) as
requiring any LCA of a C&G Facility to
address direct and significant indirect
emissions. For a facility using methane
as a fuel or feedstock for the production
of electricity, that means accounting for
direct and significant indirect emissions
associated with the methane including

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emissions resulting from the diversion
of methane from an alternative
productive use or from the expansion of
existing sources or creation of new
sources of natural gas alternatives.
Consideration of such emissions is
required under the principles for
included emissions specified in
§ 1.45Y–5(d)(2)(v).
ii. First Productive Use
The preamble to the proposed
regulations provided that the Treasury
Department and the IRS intended to
require that in order for natural gas
alternatives to receive an emissions
value consistent with that gas (and not
fossil natural gas), the natural gas
alternative used in the production of
electricity 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) and productive use would
specifically exclude venting to the
atmosphere or capture and flaring. The
preamble to the proposed regulations
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 electricity-generating
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 electricity-generating
facility was placed in service, would not
have received an emission value
consistent with biogas-based RNG, 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 the 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, provided 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

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natural gas alternatives in the
production of electricity.
After full consideration of the
comments and as further explained
elsewhere in this section, 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
GHG emissions rate, the Treasury
Department and the IRS acknowledge
that the requirement may be difficult for
taxpayers to substantiate and to
independently verify. Establishing
compliance with a first productive use
requirement could involve taxpayers
needing to obtain detailed, often
unavailable, historical documentation of
the operations of the methane source,
including historical production levels,
material changes in waste source
composition and volume, use of capture
equipment and capture rates, sales or
uses of captured methane, and waste
management practices.
Moreover, challenges in the
administration of a first productive use
requirement raise questions about the
practical ability of a first productive use
requirement to address the risk of direct
or significant indirect emissions
effectively. Instead of a first productive
use requirement, for determining GHG
emissions rates associated with the use
of 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.
The Treasury Department and the IRS
received many comments addressing the
first productive use requirement. Many
commenters questioned the legal and
technical basis of a first productive use
requirement. Several commenters
asserted that a first productive use
requirement is not authorized by statute,
overly restricts otherwise eligible biogas
and RNG feedstocks that could support
clean electricity 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 commenters asserted
that there is no evidence that using RNG
to generate electricity will result in the
induced emissions that appear to
underlie the first productive use
requirement.
Several commenters argued that
industry data suggests that domestic
production of biogas and RNG can
support both new electricity production
and current end uses like compressed
natural gas (CNG) transportation
vehicles; thus, within the timeframe

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within which the section 45Y and 48E
credits will be available there is ample
capacity to serve demand in many
sectors, without causing induced
emissions. Similarly, several
commenters 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 California
Low Carbon Fuel Standard (LCFS).
Further, these commenters suggested
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
an electricity-generating 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 California’s LCFS, have been
the primary drivers for deployment of
RNG 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
electricity production. Despite this,
there still remains a risk that RNG (or
biogas) could be redirected to electricity
production from other current uses.
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.
Several commenters suggested the
Treasury Department adopt a midprogram 5-year ‘‘check-in’’ to evaluate
whether electricity 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. Several
commenters suggested that a robust
assessment of any induced emissions
associated with redirecting RNG from its
prior use 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. One commenter

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noted that a potential alternative is 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.
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 45Y(b)(2)(B).
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 electricity.
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 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 electricity. 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 45Y and 48E
credits are not dispositive. Section
45Y(b)(2)(B) does not require empirical
evidence of direct and significant
indirect emissions associated with a
newly available incentive like the
section 45Y and 48E credits before the
likelihood of such emissions may be
considered, and such a restriction
would systematically underestimate
such emissions. As further explained
elsewhere in this section, it is necessary
for a GHG emissions assessment that is
consistent with the statutory definition
of lifecycle GHG emissions in
45Y(b)(2)(B) 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.
Many commenters raised concerns
about the effect a first productive use
requirement would have on deployment
of RNG production technologies 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 unnecessary. Several
commenters stated that the first
productive use requirement is overly

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burdensome and will unnecessarily
curtail methane abatement at scale.
Several commenters argued 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 commenters
argued that adding a first productive use
rule creates potential unintended
consequences of RNG plants sitting idle
if the deployment of a facility does not
coincide with the RNG plant completion
dates.
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 commenter
recommended the first productive use
requirement be satisfied by any use that
is more productive than the prior use.
This commenter suggested that the first
productive use rule may be overly
restrictive and that it could be beneficial
to relax the first productive use
requirement, so long as the new use of
the RNG delivers overall lower net
emissions than its original fate. One
commenter suggested there should be
no restrictions on RNG; however, if a
first productive use rule is
implemented, then it should apply a
look-back period of 36 months. Several
commenters stated the first productive
use requirement should be eliminated or
modified as it relates to production
using CMM. Several comments
recommended that each individual
borehole for CMM 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
commenters 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 borehole-level
for CMM so as to reflect how investment
decisions are made. Several commenters
noted that once a low-carbon gas source
is accepted as meeting a first productive
use requirement (if adopted), it should
not be exclusively tied to a particular
electricity-generating facility.
For the reasons previously discussed,
these final regulations do not impose a
first productive use requirement, and so
modifications, changes, and transitional
relief are not necessary. The Treasury
Department and the IRS will continue to
consider the recommendations raised by
these comments in evaluating whether

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imposing a first productive use
requirement, with potential
modifications, may be appropriate in
future guidance under sections 45Y and
48E.
Many commenters supported
imposing a first productive use
requirement and some recommended
additional guardrails. One commenter
asserted that the proposed first
productive use rule would help direct
biomethane that is otherwise vented (or,
in some cases, flared) to electricity
generation, 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 commenter, a
first productive use requirement is
important to avoid significant indirect
emissions associated with electricity
generation from biomethane. The
commenter 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 commenters supported the
proposed regulations and argued that
enforcing 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 electricity
generation. The commenters posited
that diversion of currently produced
and used RNG to electricity generation
would be backfilled with fossil natural
gas and contended that this is especially
true for existing RNG heat applications
and CNG-powered vehicles. One
commenter stated that the proposed rule
requiring the first productive use be
matched to the same taxable year as (or
after) the electricity-generating 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.
Several comments supported
prohibiting crediting 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 the section 45Y and 48E
credits 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

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alternative productive use of natural gas
alternatives when establishing the
alternative fates.
c. Alternative Fates
Section 1.45Y–5(d)(2)(vii) clarifies
that an LCA of a C&G Facility may
consider alternative fates and account
for avoided emissions, including for the
fuels and feedstocks consumed in the
fuel and feedstock supply chain and at
the electricity generating facility.
These final regulations establish
general requirements for lifecycle GHG
emissions determinations for facilities
that use methane derived from natural
gas alternatives to produce electricity,
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
tax credits creates incentives to produce
additional methane or otherwise
induces additional emissions; and
observable trends and anticipated
changes in waste management and
disposal practices over time as they are
applicable to methane generation and
uses. The emissions risks that would
have been addressed by a first
productive use requirement are
addressed in the development of the
appropriate alternative fates for certain
sources of natural gas alternatives,
thereby reflecting an accurate
assessment of GHG emissions pursuant
to section 45Y(b)(2)(B). 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 previously discussed, analytical
decisions regarding the alternative fate
of natural gas alternatives are critical in
the assessment of their carbon intensity.
Commenters suggested a range of
broadly applicable alternative fate
assumptions for methane from natural
gas alternatives. Recommendations
included venting, flaring, productive
use, and responsible avoidance of
waste-stream-generated 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
section of this Summary of Comments
and Explanation of Revisions addresses
comments recommending broadly
applicable alternative fates, while

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comments addressing alternative fates
for specific sources of methane are
discussed in section VIII.E.4.c.i. of this
Summary of Comments and Explanation
of Revisions.
Several commenters stated that it is
only appropriate to compare alternative
fates against a suite of alternative best
practices. The commenters noted that
only comparing utilization emissions
against a limited scope of alternatives
may exclude practices that offer the
greatest potential climate and
environmental justice benefits. For
example, one commenter asserted that
any methane that can be captured
should be assigned a baseline
counterfactual of capture and flare,
which would acknowledge the cost of
methane pollution and other economic
and regulatory factors already driving
abatement. Several commenters
suggested that the assessment of an
alternative fate should consider
practices that offer the best climate and
environmental justice benefits. The
Treasury Department and the IRS
understand these comments but
emphasize that an alternative fate must
reflect the appropriate assumptions that
are relevant to estimating emissions
impacts that would have occurred in the
absence of the implementation of
policy.
One commenter stated that specificity
should be critical in designating
alternative fates because, for example,
while RNG, biogas, or fugitive methane
may be chemically the same, they may
have very different emissions. Several
commenters stated that any alternative
fate must assume that relevant laws
would have been followed if the tax
credits did not exist. For example,
according to one commenter, emissions
should not be based on a venting
alternative fate, if venting would have
been illegal.
Commenters 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
that are discussed further in the
discussion of specific sources of natural
gas alternatives that follow. In response
to these commenters, the Treasury
Department and the IRS note 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 45Y
and 48E credits. The Treasury
Department and the IRS also anticipate
that a venting baseline would become

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increasingly inappropriate over time,
due to ongoing and anticipated changes
in regulations and operational practices.
The section 45Y and 48E credits are
available for facilities that begin
construction before these credits are
phased out under sections 45Y(d) and
48E(e). These final regulations also
permit taxpayers to rely on the Annual
Table that was in effect when a facility
began construction or a PER determined
with respect to a facility for the duration
of the facility’s 10-year credit period,
provided the facility continues to
operate as a type of facility that is
described in the Annual Table or in the
facility’s emissions value request.
Therefore, consistent with the
requirement in § 1.45Y–5(d)(2)(iii) to
apply a future anticipated baseline,
§ 1.45Y–5(e)(3) provides that the GHG
emissions rate of a C&G Facility that
uses methane derived from biogas, RNG,
or CMM (or any hydrogen derived from
methane from these sources) as a fuel or
feedstock to produce electricity must
take into account anticipated changes in
waste disposal practices or use of that
methane over the relevant timeframe.
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 later in
this section, a range of current and
prospective state policies limiting
venting of different RNG sources or
encouraging more responsible methane
management practices indicates the
trajectory of state action in this area. For
example, California, Colorado,
Maryland, Michigan, Oregon, and
Washington have all recently taken or
imminently plan to take action to
restrict venting and require more
responsible methane management
practices, in some cases beyond the
Federal standards currently in place.
As discussed in more detail regarding
specific sources of natural gas
alternatives, there are 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 are 1,245
landfills with operational gas collection
and control systems, as compared to

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1,187 in 2014.8 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.9 In addition, as
subsequently discussed, 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).10
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 2017.11 As of 2023,
CNG has surpassed CHP property as the
most common end use of biogas from
manure-based anaerobic digestion
systems in AgSTAR.12 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 45Y and
48E credits are available. This supports
the use of reasonably conservative
alternative fates in the face of
uncertainty to provide greater assurance
that facilities will comply with the
statutory emissions requirements.
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
requirements of sections 45Y and 48E.
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
8 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).
9 Id.
10 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).
11 Id.
12 Id.

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alternatives, it is not appropriate for all
sources of natural gas alternatives.
Some commenters suggested that the
alternative fate assumption for all
methane derived from waste streams
should be alternative productive use. As
explained subsequently, the Treasury
Department and the IRS have concluded
that 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 measuring GHG emissions rates.
Because not all methane from waste
streams is used productively, however,
applying an alternative fate of
productive use as a general rule for
natural gas alternatives would
understate the potential emissions
benefits of using such gas in the
production of electricity in some
contexts. The final regulations, therefore
do not adopt these comments.
Some commenters 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
commenters highlighted the risk that
incentives created by the section 45Y
and 48E credits would lead to the
production of more methane than would
have otherwise occurred. The Treasury
Department and the IRS agree that this
is an important consideration that must
be addressed pursuant to § 1.45Y–
5(d)(2)(v)(A) and (B).
For new methane that would not have
been produced in the absence of the
section 45Y and 48E credits, use of such
methane for electricity production must
not be reflected as avoided methane
emissions in an LCA for a C&G Facility.
For example, 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 45Y and 48E
credits.
The availability of the section 45Y
and 48E credits may lead to generation
of methane in the form of natural gas
alternatives for the purpose of supplying
feedstocks or fuel that would be used to
produce electricity by a facility seeking
to claim a credit under sections 45Y and
48E. In those instances, the appropriate
alternative fate is that the methane
generated from waste streams, or
increments of it, would not have been

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created in the first place or that it would
have remained sequestered. In such
scenarios, it would be inappropriate to
credit electricity 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 allowing a section
45Y or 48E credit with respect to a
facility 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 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
GHG 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 electricity. To
meet statutory requirements, however,
incentives for methane creation must be
considered in the determination of a
GHG emissions rate.
It is not practicable for the Treasury
Department and the IRS to ascertain
which specific waste-stream-generated
methane would not exist absent the
incentives provided by the section 45Y
and 48E credits, nor is it practicable to
precisely estimate the market-mediated
emissions of such an incentive effect. To
ensure that these emissions are
accounted for, as is required under the
statute, the Treasury Department and
the IRS have concluded that the most
administrable and appropriate way to
take into account the economic
incentives for additional waste
production is in the establishment of the
alternative fates that generally apply to
particular feedstocks. Specifically, in
settings where a significant but nonidentifiable share of methane from some
sources could be produced in response
to incentives provided by the section
45Y and 48E credits or other programs,
alternative fate assumptions that result
in highly negative emissions estimates
are likely to be inaccurate and
understate the real-world GHG
emissions. The 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

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i. Alternative Fate Considerations for
Methane From Certain Sources
Informed by the considerations
discussed previously, § 1.45Y–5(e)(3)(ii)
through (vi) specifically address the
alternative fate considerations for
methane from landfill gas, wastewater,
CMM, animal waste sources, and
fugitive methane other than CMM. The
following sections of this Summary of
Comments and Explanation of Revisions
address these specific sources of natural
gas alternatives in further detail. These
final regulations have developed
alternative fates on a sector-by-sector
basis because determining and
validating alternative fates on an entityby-entity basis would not be practicable.
As discussed previously, 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 entity-by-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 45Y and
48E credits, 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 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 less methane and vented
it, the alternative fate for that amount of
methane (venting) would differ
dramatically from the alternative fate of
the additional methane produced due to
the tax incentive (no methane produced
or emitted). Given these significant
administrative challenges, alternative
fates are assessed and applied on a
sector-by-sector basis in these final
regulations.
A. Alternative Fate Considerations for
Methane From Landfill Gas
A number of commenters highlighted
competing considerations in
determining the appropriate alternative
fate for methane from landfill gas.
Several commenters stated that venting

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is the correct alternative fate for landfill
gas. Several commenters stated that a
venting alternative fate is not
appropriate where relevant laws and
regulations require a landfill to capture
biogas. Several commenters stated that
capture and flare is the correct
alternative fate for methane and that, in
the case of landfills, the uncaptured
portion of methane gas should be part
of the lifecycle analysis. One commenter
specified the appropriate alternative fate
is flaring at a 95–98 percent destruction
efficiency. Another commenter noted
the GREET model does not currently
include fugitive methane emissions at a
landfill in the LCA, even though fugitive
methane emissions can negate the
climate and environmental benefits of
biomethane projects. One commenter
stated that landfills do not deliberately
generate additional biogas in order to
qualify for a tax credit.
The Treasury Department and the IRS
note that regulations increasingly
require flaring of landfill gas, and
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 CAA;
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 later, several states have adopted
additional more stringent requirements
for landfill methane emissions. Also, the
EPA has announced that it intends to
update and strengthen its existing
landfill regulations under section 111 of
the CAA in 2025 (the current rules for
landfill gas emissions were finalized in
2016).13 Pursuant to the EPA’s
regulatory plan, the EPA plans to revisit
the rule to understand how new
technologies and approaches could be
13 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.canary
media.com/articles/methane/is-the-epa-about-toget-serious-about-methane-pollution-from-landfills.

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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.14
In particular, certain landfills are
subject to NSPS (40 CFR part 60,
subpart XXX) and Emissions Guidelines
(40 CFR part 60, subpart Cf) under
section 111 of the CAA (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
(NESHAP) (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 CAA section 111
NSPS provides emissions control
requirements for new (since 2014)
municipal solid waste landfills. 40 CFR
part 60, subparts WWW and XXX. The
section 111 emissions guidelines (EG)
cover existing (pre-2014) 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. 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 2025.15 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
14 Reconsideration of Standards of Performance
and Emissions Guidelines for Municipal Solid
Waste Landfills (RIN 2060–AU24) available at
https://www.reginfo.gov/public/do/eAgendaView
Rule?pubId=202404&RIN=2060-AU24.
15 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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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
pipeline system for sale.16 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 45Y and
48E credits are available, as additional
regulation is expected at both the
Federal and state level.17
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 it is not
otherwise required, an assumption that
absent the section 45Y and 48E credits
the typical practice would be
uncontrolled venting is not supportable.
The Treasury Department and the IRS
have determined that 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. Section 1.45Y–5(e)(3)(ii) of
the final regulations provides that, for
purposes of determining the GHG
emissions rate of a C&G Facility (as

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16 Landfill

Methane Outreach Program (LMOP),
U.S. Environmental Protection Agency, available at
https://www.epa.gov/lmop (last updated Dec. 5,
2024).
17 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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defined in § 1.45Y–5(b)(4)) that
produces electricity through combustion
or gasification using methane derived
from landfill sources as a fuel or
feedstock, the alternative fate of such
gas must be flaring.
B. Alternative Fate Considerations for
Methane From Wastewater
Several commenters stated that the
R&D GREET 2023 model provides a
reasonable baseline assumption that
should be applied for all wastewater
sludge projects. These commenters
noted that a digester would be present
on site and the biogas would be flared
or consumed on site, and this should
inform the baseline in establishing the
alternative fate of the methane. Another
commenter stated that it would be
incorrect to presume both that most
wastewater treatment plants have
operational biogas/anaerobic digester
systems and that operational biogas
systems are flaring their gas. The
commenter further 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
commenter, offsets fossil fuel use and its
related emissions.
National-level data on anaerobic
digestion at wastewater treatment plants
and the use of biogas produced is
limited. There are more than 16,000
wastewater treatment plants in the U.S.
While most wastewater treatment plants
in the U.S. serve small populations and
do not process sufficiently large
wastewater flows to justify the
installation of anaerobic digesters,
which are capital-intensive, anaerobic
digesters are very prevalent among the
smaller number of large wastewater
treatment facilities that process the large
majority of wastewater: the largest 8
percent of facilities (1,132 facilities that
each handle greater than 5 million
gallons per day) process 77 percent of
total national wastewater flow,
according to Argonne National
Laboratory.18 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 U.S.
Department of Energy Alternative Fuels
Data Center.19 Additionally, nearly all
18 Ha, Miae, et al. ‘‘Opportunities for Recovering
Resources from Municipal Wastewater.’’, Jul. 2022.
https://doi.org/10.2172/1876441.
19 See https://afdc.energy.gov/fuels/natural-gasrenewable.

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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 2022.20
Venting practices are not reported in
any national datasets, although vents are
required to prevent over-pressurization
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 onsite 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 45Y and 48E credits the
typical practice would be uncontrolled
venting is not supportable. Section
1.45Y–5(e)(3)(iii) of the final regulations
therefore provides that, for purposes of
determining the GHG emissions rate of
a C&G Facility (as defined in § 1.45Y–
5(b)(4)) that produces electricity through
combustion or gasification using
methane derived from wastewater
sources as a fuel or feedstock, the
alternative fate of such gas must be
flaring of gas not 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 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 the
specified alternative fate the most
appropriate approach for the sector as a
whole.
C. Alternative Fate Considerations for
Coal Mine Methane
The Treasury Department and the IRS
recognize that fossil sources of fugitive
methane can be utilized for the
production of electricity. Many
commenters specifically noted the
feasibility of producing electricity from
20 National Biosolids Data Project, Nationwide
Survey of WRRF Biosolids Programs https://
www.biosolidsdata.org/downloads/nationwide-wrrfsurvey-cleaned-data-spreadsheet.

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Federal Register / Vol. 90, No. 9 / Wednesday, January 15, 2025 / Rules and Regulations
CMM and identified venting as a
common alternative fate. One
commenter 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.
Another commenter recommended that
the emissions associated with coal mine
methane be determined consistent with
the GREET model maintained by
Argonne National Laboratory.
Drainage gas is the subset of CMM
that is most likely to be used for
electricity generation, due to its high
methane content. Drainage systems are
a mechanism of recovering methane
from underground mines to maintain
safe operating conditions.21 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 is not widely used
for electricity production.
Based on consultation with
interagency experts, 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 40 CFR part 98, subpart
FF, indicates that, while the majority of
ventilation gas liberated by coal mines
over the past decade has been vented,
the majority of drainage gas has been
productively used or flared. Mine
practices have fluctuated, with some
mines transitioning from predominantly
venting drainage gas to predominantly
using or destroying such gas. Factors
that can affect the extent to which a
mine vents, flares, and/or productively
uses such gas in a given year include the
amount of methane required by onsite
equipment (for example, engines);
proximity to offsite infrastructure (for
example, pipelines); and the
lucrativeness of programs incentivizing
the capture of CMM. Incentives for
CMM destruction and utilization that
are currently available include state
offset programs, state renewable
portfolio standards, and voluntary
offsets, some of which specifically do
not allow for pipeline injection.
21 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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There is considerable uncertainty
associated with establishing the
appropriate alternative fate scenarios for
CMM for the period over which a
facility may be able to claim the section
45Y and 48E credits. 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 sourced
from drainage systems given the
uncertainty with respect to these
emissions in particular in the United
States, and 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, § 1.45Y–5(e)(3)(iv) of
these final regulations provides that for
purposes of determining the GHG
emissions rate of a C&G Facility (as
defined in § 1.45Y–5(b)(4)) that
produces electricity through combustion
or gasification using coal mine methane
that is drainage gas as a fuel or
feedstock, the alternative fate of such
gas must be flaring. This alternative fate
accounts for the uncertainties associated
with future practices, as previously
described, while recognizing that most
drainage gas is destroyed today.
D. Alternative Fate Considerations for
Animal Waste
Commenters suggested a variety of
alternative fate assumptions for
purposes of estimating GHG emissions
for biogas derived from animal waste
sources, including venting, alternative
productive use, and responsible waste
management, with some commenters
recommending a single alternative fate
for biogas produced from these sources
and others recommending differentiated
alternative fates. There is no national
database that tracks farm-level 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
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.

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Many commenters highlighted
competing considerations in
determining the appropriate alternative
fate for methane derived from animal
waste. Several commenters
recommended that the R&D GREET
2023 model be used to calculate the
avoided emissions from anerobic
digestion and the associated biogas
using site-specific baseline manure
management practices. The commenters
suggested that the correct alternative
fates could be entered into the model
manure management categories and
practices to accurately quantify baseline
emissions prevented by a biogas project.
Several commenters 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
consequence of the commenters’
suggestion is that any biogas utilized
would be associated with avoided GHG
emissions. The commenters noted that
this alternative fate is similar to what
the commenters assert is appropriate for
the landfill gas industry, where once
regulations are in place requiring
landfill gas to be captured and
destroyed, then flaring becomes the
appropriate alternative fate. One
commenter noted that although the
primary precedent for crediting avoided
methane emissions is the California
LCFS’s treatment of biomethane from
manure lagoons, this precedent is not
appropriate for purposes of the section
45Y and 48E credits. The commenter
stated that the avoided GHG emissions
calculation was specifically
incorporated within the LCFS as a
means of subsidizing investments in
anaerobic digesters to address pollution
from California’s dairies rather than as
a reflection of the best available science.
Determining the appropriate
alternative fate and emissions intensity
for biogas produced from animal waste
sources presents several challenges.
First, the emissions intensity of biogas
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, the EPA’s
GHG Inventory data indicates that
uncovered anaerobic lagoons produce
roughly one hundred times the amount

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of methane as daily spread. Even among
farms credited with methane venting
counterfactuals under the California
LCFS, the resulting GHG emissions
intensities for biogas 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 later in this section,
none of these practices are
comprehensively tracked or reported at
a national level. Commenters also noted
the further uncertainty and variation
introduced by a range of leakage rates
from operations capturing and
upgrading manure-derived methane,
including the high likelihood that there
are ‘‘super emitter’’ sources (consistent
with the patterns seen in other fugitive
methane streams). This could introduce
additional uncertainty and risk of over
crediting in measuring 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 regarding 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.22 The
22 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 underconstruction digesters 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); U.S. Department of Energy, ‘‘A Generic
Counterfactual Greenhouse Gas Emission Factor for
Life-Cycle Assessment of Manure-Derived Biogas
and Renewable Natural Gas’’ (2025), available at
www.energy.gov/45vresources.

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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,23 the financial incentives
provided by the RFS and LCFS
programs appear to be sufficient to
incentivize some installations of
anaerobic digesters at existing lagoons,
which reduces emissions without any
additional incentive from the section
45Y and 48E credits. There are also
other possible sources of revenue from
anaerobic digester systems including
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, 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; install solid separators that
reduce methane-producing slurries; and
providing conservation assistance for
transitions to alternative manure
management systems, such as deep pits,
23 How Much Should Dairy Farms Get Paid for
Trapping Methane?—Energy Institute Blog,
available at https://energyathaas.wordpress.com/
2024/10/14/how-much-should-dairy-farms-getpaid-for-trapping-methane/.

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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 concentrated animal feeding
operations with anaerobic digesters,
even absent an additional incentive
under the section 45Y and 48E credits.
Redirecting biogas that comes from
these sources to electricity production
will mean less displacement of natural
gas elsewhere in the economy, and
could therefore result in significant
indirect emissions that must be taken
into account under section 45Y(b)(2)(B).
Third, the magnitude of the incentive
provided by the section 45Y and 48E
credits itself creates a significant risk of
additional waste production in response
to the credit, with emissions that must
be accounted for in the LCA. While
some commenters noted that the EPA
did not find that its RFS program’s
incentivization of anaerobic digesters
had driven a proliferation of
concentrated animal feeding operations
or other large-scale animal agriculture,
other commenters disagreed, stating that
the availability of these credits may
incentivize the operation of new or
larger farming units and the deliberate
production of methane. Commenters
noted that, even with use of anaerobic
digesters, GHG emissions may still
result from leakage, use of digestate, and
the need to use venting to accommodate
fluctuating gas levels. Additional waste
production could thus 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 biogas 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

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• 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 45Y and 48E
credits, failure to take this into account
could lead to allowing facilities that do
not meet statutory GHG emissions
requirements to be treated as qualified
facilities under section 45Y and 48E.
This would be a particular concern with
a venting alternative fate because it
would result in a significantly negative
estimated GHG emissions rate, creating
strong incentives to produce additional
methane for use by facilities to claim the
section 45Y and 48E credits
inappropriately.
In light of these challenges, the
Treasury Department and the IRS have
determined that the most appropriate
approach to determining the carbon
intensity of biogas and ensuing RNG
derived from animal waste is to 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 § 1.45Y–
5(e)(3)(v) requires 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,24 this results in
a carbon intensity score of ¥51 gCO2e/
MJ, where the MJ basis refers to the
lower heating value of the methane
contained in the biogas. This emissions
attribute for the methane contained in
biogas from animal waste can be
subsequently used to calculate the
carbon intensity of electricity and RNG
by accounting for the GHG emissions
associated with onsite electricity
generation from biogas or for upgrading,
transportation, and compressing into
RNG.
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.
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
24 U.S. Department of Energy, ‘‘A Generic
Counterfactual Greenhouse Gas Emission Factor for
Life-Cycle Assessment of Manure-Derived Biogas
and Renewable Natural Gas’’ (2025), available at
www.energy.gov/45vresources.

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additional methane capture and use.25 It
is a reasonable and administrable
representation of the carbon intensity of
biogas 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
suggested by commenters, 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 biogas. Such an
approach would be infeasible given the
large number of such operations and the
lack of nationally applicable reporting
requirements regarding numbers of
animals or manure management
practices by livestock and poultry
operation (and wide variation in state
reporting requirements). Additionally,
104 of the 473 digesters operational or
under construction in the AgSTAR
database report co-digesting their
primary manure type with one or more
other wastes, including other types of
manure, food waste, agricultural
residues, and dairy/food processor
waste. These tracking and verification
challenges are of particular concern
because differences in waste disposal
practices or specific waste sources can
result in large differences in avoided
emissions, meaning that highly specific
prior waste management practices
would need to be consistently reported
and verified to support accurate
differentiated alternative fates. In
addition, as discussed previously,
differentiated alternative fates that allow
for highly negative emissions values
raise concerns about incentives for
additional waste production that could
result in inappropriate claims of the
section 45Y and 48E credits. The
Treasury Department and the IRS will
continue to monitor reporting and
tracking systems and study the
25 Id.

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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 45Y and 48E credits. The
Treasury Department and IRS expect the
modestly negative emissions values
established in these rules will provide,
at most, only modest incentives to
generate new methane or other GHGs
from animal waste. However, the
Treasury Department and the IRS will
continue to study this issue to
determine whether adjustments are
needed in the future.
E. Alternative Fate Considerations for
Fugitive Methane From Fossil Fuel
Activities Other Than Coal Mining
The Treasury Department and the IRS
have considered the alternative fate of
fugitive methane from fossil fuel
activities other than coal mining, which
are overwhelmingly comprised of oil
and gas operations, and determined that
the generally applicable alternative fate
for fugitive methane from these
activities is productive use.
While some commenters 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. Some
commenters stated that any program
that would incentivize the capture of
fugitive methane from oil and gas
sources would be ineffective and
inefficient because of the combination
of: (i) variable emissions, (ii) the
technical challenge of measuring
emissions, and (iii) the
counterproductive incentives the
baseline setting process would create.
Another commenter stated that, to avoid
double counting methane emissions
abatement, the final regulations must
explicitly state that fugitive sources of
methane arising from oil and gas
activities are to be treated equivalently
to fossil methane.
The Treasury Department and the IRS
note that EPA regulations under section
111 of the CAA seek to limit volatile
organic compound (VOC) 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,

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EPA’s latest rules for new sources of
VOC and methane emissions require use
of zero emitting process controllers in
most scenarios. EPA’s previous rules
allowed low bleed and intermittent
bleed controllers, which emit pollutants
to the atmosphere by discharging
natural gas. EPA’s new rules keep that
gas in the system instead of allowing it
to be released. 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 the deadline for
repairs at well sites. 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. 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 section VIII.4.c.i.A. of
this Summary of Comments and
Explanation of Revisions, while some of
the compliance deadlines under each of
the updated regulations under section
111 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 currently
comply with other requirements such as
the new source requirements under
section 111. Thus, operators have
significant incentives to make certain
compliance investments now and are
required to do so well within the period
of the tax 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.26 As a
consequence, the majority of the actions
that an oil or gas operator could take to
avoid fugitive emissions are already
required by law or will be during the
period in which the section 45Y and
48E credits will be available.
Given the extensive regulatory
environment already in place requiring
26 See, for example, Waste Prevention, Production
Subject to Royalties, and Resource Conservation, 89
FR 25378 (Apr. 10, 2024).

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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, § 1.45Y–5(e)(3)(vi)
provides that for purposes of
determining the GHG emissions rate of
a C&G Facility (as defined in § 1.45Y–
5(b)(4)) that produces electricity through
combustion or gasification using
fugitive methane other than coal mine
methane as a fuel or feedstock, such as
fugitive methane from oil and gas
operations, the alternative fate of such
gas must be productive use, 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 ‘‘coal
bed methane’’ (CBM), may be for the
purpose of natural gas production or
may result from pre-mining 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 40 CFR part 98, subpart
W, which informs background estimates
of upstream methane emissions for the
natural gas supply chain. Accordingly,
GHG emissions analyses conducted for
purposes of sections 45Y and 48E would
represent CBM with a carbon intensity
that is equivalent to that of other
sources of fossil natural gas.
d. Book-and-Claim
Book-and-claim accounting has been
used in some contexts to track the
attributes associated with the
production of a unit of energy in a
manner that prevents double counting.
In such a system, producers of energy
are required to acquire and retire
corresponding attribute certificates
through a book-and-claim system that
can verify, generally in an electronic
tracking system, that all applicable
requirements are met. The preamble to
the proposed regulations requested
comment on whether book-and-claim
accounting may be suitable for use in
substantiating and verifying claims to
the energy attributes of fuels and
feedstocks used by a facility to generate
electricity. Examples of the relevant
fuels and feedstocks for which bookand-claim accounting may be
considered include natural gas
alternatives or other feedstocks such as
hydrogen. The preamble to the proposed
regulations further noted that the

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Treasury Department and the IRS are
considering providing rules that may
permit the use of book-and-claim
accounting for the section 45Y and 48E
credits in the final regulations if there
are sufficient assurances that the energy
attributes claimed under such system
are verifiable and not susceptible to
double counting. The preamble to the
proposed regulations further noted that
tracking and verification mechanisms
for natural gas alternatives specific to
the needs of the section 45Y and 48E
credits 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.
A wide range of comments arguing in
favor of and against allowing the use of
book-and-claim systems for natural gas
alternatives were received in response
to the proposed regulations. Several
commenters discussed how book-andclaim systems were commonplace
within the RNG industry. In addition,
several commenters expressed concern
about the ability of the RNG industry to
take advantage of the section 45Y and
48E credits if a book-and-claim
approach was not adopted. Several
commenters stated that, because sources
of natural gas alternatives are unevenly
distributed throughout the United States
and may not be located near prospective
electricity-generating facilities, bookand-claim allows entities that do not
have access to such sources to be
eligible for the section 45Y and 48E
credits. One commenter suggested that a
mass balance model or an ‘‘identity
preservation’’ model could be adopted if
a book-and-claim system was
disallowed.
Several commenters suggested that
existing systems, such as the Midwest
Renewable Energy Tracking Systems
(M–RETS), the EPA’s RFS, or the
California LCFS, might have sufficient
capabilities to enable book-and-claim
accounting for purposes of the section
45Y and 48E credits. Other commenters
argued that these systems do not have
sufficient tracking capabilities and that
the Treasury Department and the IRS
should disallow book-and-claim given
these limitations. Several commenters
recommended that if a book-and-claim
system were allowed, then such system
should take measures to avoid doublecounting of the same environmental
attributes. Several commenters
suggested that any tracking system
should be able to allocate emissions
based on different levels of gas blending
from different feedstocks and enable the
differentiation of carbon capture rates to

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those different feedstock production
pathways. Several commenters noted
that any tracking system would not
address the issue on which proposed
regulations invited comment, such as
ensuring that biomethane is not
produced for the purpose of meeting
demand for the biomethane market. In
response to these comments, the
Treasury Department and the IRS note
that existing tracking and verification
systems have limited capabilities for
tracking and verifying RNG pathways
and that there is no sufficiently
accurate, nationally available, auditable
and reliable third-party tracking system
(or registry) in place today.
Several commenters suggested there
was clear Congressional intent to allow
book-and-claim. However, other
commenters suggested that allowing the
section 45Y and 48E credits solely on
the basis of RNG certificates would be
contrary to requirements of the statute.
These commenters argued that the
requirement to assess the emissions
rates of the facility precludes the use of
book-and-claim in the specific context
of the section 45Y and 48E credits.
These commenters asserted that the use
of a book-and-claim system was not
statutorily authorized because such use
would not comply with the requirement
of section 45Y(b)(2)(A) and (B) and
section 48E(b)(3)(ii) to assess the
emissions emitted by a facility in the
production of electricity. Commenters
also argued that the result of allowing
book-and-claim would be to allow
facilities to claim the credits with no
meaningful change in operations,
contrary to the intended purpose of the
section 45Y and 48E credits.
In response to these comments, the
Treasury Department and the IRS have
examined whether book-and-claim
accounting is permissible under the
statutes. As further explained later in
this section, the final regulations do not
permit the use of book-and-claim
accounting for purposes of the section
45Y and 48E credits because the use of
book-and-claim accounting would
conflict with the statutory directive to
assess the GHG emissions specific to a
facility.
Congress set the statutory boundaries
for determining greenhouse gas
emissions rates for the section 45Y and
48E credits in section 45Y(b)(2). Section
45Y(b)(2)(A) defines ‘‘greenhouse gas
emissions rate’’ as ‘‘the amount of
greenhouse gases emitted into the
atmosphere by a facility in the
production of electricity, expressed as
grams of CO2e per kWh.’’ This general
rule for determining emissions rates
requires an analysis of the emissions
associated with a facility’s production of

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electricity. Section 45Y(b)(2)(B) clarifies
that for facilities that produce electricity
through combustion or gasification, the
GHG emissions rate for such facilities is
equal to ‘‘the net rate of greenhouse
gases emitted into the atmosphere by
such facility (taking into account
lifecycle greenhouse gas emissions, as
described in 42 U.S.C. 7545(o)(1)(H) in
the production of electricity, expressed
as grams of CO2e per kWh.’’ Section
45Y(b)(2)(C) provides the rules for
specifying a GHG emissions rate for a
particular facility. Section
45Y(b)(2)(C)(i) requires the Secretary to
annually publish a table (Annual Table)
that sets forth the GHG emissions rates
‘‘for types or categories of facilities.’’
Taxpayers must use this Annual Table
to determine the GHG emissions rate of
any facility for which the Annual Table
provides a rate. Section 45Y(b)(2)(C)(ii)
provides that if the Annual Table does
not provide a rate for a facility, the
taxpayer that owns such facility may
petition the Secretary for a provisional
emissions rate. Finally, section
45Y(b)(2)(D) requires the amount of
GHGs emitted into the atmosphere ‘‘by
a facility in the production of
electricity’’ to not include any qualified
carbon dioxide that is captured by the
taxpayer and sequestered pursuant to
certain requirements. Taken together,
these statutory rules provide the
framework to assess the GHG emissions
of a facility based on the facility’s
operations.
Sections 45Y(b)(2)(C) and (f) provide
the Secretary authority to specify and
clarify how GHG emissions rates are
determined within this framework.
Section 45Y(b)(2)(C) directs the
Secretary to publish an Annual Table or
consider petitions for provisional
emissions rates. Section 45Y(f) directs
the Secretary to ‘‘issue guidance
regarding implementation of [section
45Y], including calculation of
greenhouse gas emission rates for
qualified facilities and determination of
clean electricity production credits
under this [section 45Y].’’ To establish
the GHG emissions rates as directed by
the statute, the Secretary must first
establish a process to calculate these
rates. Because of this broad statutory
mandate, the emissions rate
determination process must account for
the varied production methods that are
currently viable or those that may be
devised in the future, the idiosyncrasies
of each facility’s electricity-generating
process, and scientific advancements
and uncertainty associated with
lifecycle analysis.
Upon consideration of the comments
submitted regarding book-and-claim, the
Treasury Department and the IRS have

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determined that the statute requires a
facility’s eligibility for the section 45Y
and 48E credits to be determined by the
electricity-generating operations
undertaken by the facility itself to
produce electricity and that book-andclaim, by its nature, cannot establish
what fuel or feedstock is physically
used within a facility to produce
electricity or the actual fundamental
transformations of energy that are used
to produce a facility’s input energy
source. Sections 45Y(b)(1)(A) and
48E(b)(3)(A)(iii) provide that ‘‘qualified
facility’’ means a facility that is owned
by the taxpayer and is used for the
generation of electricity, placed in
service after December 31, 2024, and for
which the GHG emissions rate or, for
purposes of section 48E, the anticipated
GHG emissions rate, is not greater than
zero.
For both the determination of whether
a facility produces electricity through
combustion or gasification and the
determination of the emissions
associated with a facility’s production of
electricity, Congress directed the
Secretary to assess the activities of a
given facility in the course of electricity
production, rather than, for example,
the process used to produce the
electricity. The use of book-and-claim
could misrepresent the activities taking
place in the facility or the actual
fundamental transformations of energy
that are used to produce a facility’s
input energy source, resulting in
inaccurate determinations both with
respect to whether the facility is
producing electricity through
combustion and gasification and with
respect to the emissions associated with
the facility’s production of electricity.
Book-and-claim accounting may
appropriately be used in contexts other
than the section 45Y and 48E credits to
substantiate claims to the energy
attributes of certain fuels and
feedstocks. However, such claims do not
necessarily correspond to the actual
physical use of the relevant fuels and
feedstocks. For example, where fuel is
delivered through a common pipeline,
the acquisition and retirement of
certificates representing the attributes a
particular fuel or feedstock may not
(and are in fact unlikely to) reflect the
physical delivery of fuel or feedstock
with those attributes and its use by a
facility in the production of electricity.
In addition, the statutory authorization
for credits other than the section 45Y
and 48E credits may provide broader
authority to support the use of a bookand-claim system, but the Treasury
Department and the IRS agree with the
commenters that such authority is not

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available with respect to the section 45Y
and 48E credits.
Whether a facility produces electricity
through combustion or gasification is an
inherently factual question that requires
an assessment of (i) a facility’s
operations that produce electricity and
(ii) the operations that produced the
fuel, if any, used by that facility in the
production of electricity. The emissions
assessment for a facility that produces
electricity through the combustion of a
particular set of fuels must be based on
the fuels in fact used by the facility, as
well as any emissions from the full
lifecycle of those fuels through the point
of electricity production. The
acquisition and retirement of certificates
representing the attributes of certain
types of fuel on behalf of this facility
would have no bearing on which fuels
it in fact used to produce electricity or
the operations or feedstocks used to
produce such fuel. As a result,
permitting a facility to use book-andclaim accounting for this purpose could
result in treating a facility that produced
electricity through combustion or
gasification as if it did not do so. For
example, a hydrogen fuel cell that
produces electricity using hydrogen
produced entirely by steam methane
reforming would be considered under
the final regulations to have produced
electricity through combustion or
gasification. If the fuel or feedstock used
by such facility were allowed to be
determined using book-and-claim
accounting, that facility could acquire
and retire the attributes of hydrogen
produced through electrolysis to be
classified as a facility that did not
produce electricity through combustion
or gasification even though its
operations did not support such a
determination. This result would be
inappropriate because section
45Y(b)(2)(B) requires consideration of
the actual operations at a facility to
produce electricity and the actual
fundamental transformations of energy
that are used to produce the facility’s
input energy source. The final
regulations, therefore, cannot permit
book-and-claim accounting in
determining whether a facility produces
electricity through combustion or
gasification.
For the reasons explained previously,
book-and-claim accounting also cannot
establish the characteristics of the fuels
used in a specific facility to produce
electricity. Both sections 45Y(b)(2)(A)
and (B) require an assessment of the
greenhouse gases emitted into the
atmosphere by the facility. The statute
thus requires this inquiry to be based on
the facility’s actual operations and the
emissions associated with it, both of

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which could be misrepresented by bookand-claim accounting. The final
regulations, therefore, also cannot
permit book-and-claim accounting in
determining the amount of greenhouse
gases emitted into the atmosphere by a
facility in the production of electricity.
Thus, after consideration of the
comments, §§ 1.45Y–5(e)(4) and 1.48E–
5(e) of these final regulations do not
permit the use of a book-and-claim
accounting system to determine or claim
the energy attributes of biogas, RNG,
coal mine methane, any other methane
used in the production of electricity, or
any other input or feedstock. A facility
that produces electricity through the
combustion of RNG, for example, may
substantiate its use of RNG by having a
direct connection to an RNG source or
records establishing exclusive, physical
delivery of the RNG from that source to
the facility for use in generating
electricity. Because book-and-claim
accounting of RNG energy attributes is
not permitted for purposes of section
48E, such substantiation must address
the actual anticipated operations of the
qualified facility.
F. Carbon Capture and Sequestration
Section 45Y(b)(2)(D) provides that for
purposes of section 45Y(b), the amount
of GHGs emitted into the atmosphere by
a facility in the production of electricity
does not include any qualified carbon
dioxide that is captured by the taxpayer
and (i) pursuant to any regulations
established under section 45Q(f)(2),
disposed of by the taxpayer in secure
geological storage, or (ii) utilized by the
taxpayer in a manner described in
paragraph (5) of such section. The
Treasury Department and the IRS
interpret this statutory language to mean
that, for the calculation of the GHG
emissions rate, the GHG emissions of a
qualified facility in the production of
electricity must be reduced by the
amount of qualified carbon dioxide that
is captured by the taxpayer at the
qualified facility, and disposed of in
secure geological storage; used in an
enhanced oil and gas recovery (EOR)
project and then disposed of in secure
geological storage; or utilized (as
defined in section 45Q(f)(5)).
Proposed § 1.45Y–5(e) provided that
for purposes of paragraphs (c) and (d) of
the section, a GHG emissions rate for a
Non-C&G Facility or C&G Facility must
exclude any qualified carbon dioxide (as
defined in section 45Y(c)(3)) that is
produced in such facility’s production
of electricity, captured by the taxpayer,
and pursuant to any regulations
established under section 45Q(f)(2),
disposed of by the taxpayer in secure
geological storage, or utilized by the

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taxpayer in a manner described in
section 45Q(f)(5) and any regulations
established under such section. Several
commenters requested that the final
regulations more closely track the
statutory language with respect to
treatment of qualified carbon dioxide
within the meaning of section 45Q by
changing the language in proposed
§ 1.45Y–5(e) from ‘‘must exclude’’ to
‘‘shall not include.’’ The Treasury
Department and the IRS acknowledge
that the proposed regulatory text created
ambiguity and have revised the final
rule accordingly.
Additionally, in the preamble to the
proposed regulations, the Treasury
Department and the IRS requested
comments regarding what requirements
should apply to substantiate and verify
that carbon dioxide that is captured by
the taxpayer is (a) disposed of by the
taxpayer in secure geological storage
pursuant to any regulations established
under section 45Q(f)(2), disposed of by
the taxpayer in secure geological
sequestration, or (b) utilized by the
taxpayer in a manner described in
section 45Q(f)(5). Commenters almost
universally recommended adopting the
requirements for substantiation and
verification of CCS provided by
regulations and Internal Revenue
Bulletin guidance under section 45Q,
referred to collectively as ‘‘the section
45Q rules.’’ The commenters cited
support for adopting the requirements
for substantiation and verification
provided by the section 45Q rules
because they provide taxpayer certainty,
particularly as industry has already
adopted these procedures. Other
commenters supported adopting the
rules because these commenters view
the rules as appropriately stringent.
Several commenters provided specific
recommendations regarding the
adoption of requirements for
substantiation and verification provided
by the section 45Q rules. The
commenters requested that the final
regulations adopt the requirements for
secure geological storage provided
under § 1.45Q–3, which include
allowing the taxpayer to contract with a
third party for secure geological storage
activities consistent with the
requirements under § 1.45Q–1(h)(2) and
providing documentation to verify
secure geological storage in accordance
with 40 CFR part 98, subparts RR and
VV (GHGRP), and the CSA/ANSI ISO
27916:2016 pathway. Several
commenters also requested that the final
regulations adopt the utilization
requirements provided under § 1.45Q–4,
including providing a written LCA
report in conformity with ISO
14040:2006 and 14044:2006, third-party

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independent review, and technical
review by the DOE. Commenters also
recommended imposing reporting
requirements consistent with those
imposed on taxpayers that claim the
section 45Q credit on IRS Form 8933.
Other commenters asserted that
verification and substantiation
requirements must include detailed
records of the CCS process, third-party
verification, and compliance with
GHGRP reporting standards.
Several commenters recommended
the adoption of a less stringent version
of the requirements for substantiation
and verification provided by the section
45Q rules. A commenter recommended
that taxpayers not be required to obtain
pre-approval of LCA reports, which is
required for utilization under the
section 45Q regulations and Notice
2024–60, 2024–34 I.R.B. 515. Instead,
the commenter suggested that the final
regulations provide an option for
taxpayers that claim the section 45Y or
48E credits for capturing and utilizing
carbon dioxide to use different LCA
parameters than currently apply under
the section 45Q rules. Another
commenter requested that in addition to
procedures provided by the section 45Q
rules, that the final regulation provide
that taxpayers may use other workable
methods and protocols for verifying
secure geological storage. After
consideration of the comments, the
Treasury Department and the IRS have
determined that based on the explicit
statutory direction in section
45Y(b)(2)(D) to rely upon the regulations
established under section 45Q(f)(2) for
secure geological storage and the
reference to the requirements for
utilization provided in section 45Q(f)(5),
the final regulations adopt the
requirements for substantiation and
verification provided by regulations and
Internal Revenue Bulletin guidance
under section 45Q.
The Treasury Department and the IRS
also asked whether it would be
appropriate to limit the carbon dioxide
that may be considered as qualified
carbon dioxide (as defined under
section 45Y(e)(3)), and thus excluded
under section 45Y(b)(2)(D), to carbon
dioxide that has been reported to the
EPA’s GHGRP, and if so, which GHGRP
subpart or subparts should be used.
Several commenters supported limiting
the qualified carbon dioxide excluded
from the GHG emissions of a qualified
facility based on the amount of qualified
carbon dioxide reported by the taxpayer
to the GHGRP. A commenter also
recommended that 40 CFR part 98,
subpart RR (GHGRP), be used to verify
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Another commenter asserted that the
GHGRP procedures are not stringent
enough to be the basis for excluding
qualified carbon dioxide from the GHG
emissions rate of a qualified facility for
purposes of the section 45Y or 48E
credits. This commenter noted that the
current methodology for the GHGRP
does not accurately track emissions to
conduct LCAs and determine emissions
from C&G Facilities. The commenter
also noted that measurements of carbon
dioxide that is captured, sequestered, or
injected into an EOR project are based
on volumetric and mass flow-related
mathematical and engineering
calculations once a quarter, whereas
calculations within the GHGRP assume
that operations and measurement are
consistent, excluding any
considerations of site-specific
equipment, operations, or malfunctions.
The commenter asserted that this
assumption may lead to inaccurate
reporting to the GHGRP.
After consideration of the comments,
the final regulations at § 1.45Y–5(e)(2)
provide that the requirements for
substantiation and verification of carbon
capture and sequestration provided by
regulations and Internal Revenue
Bulletin guidance under section 45Q
must be satisfied for qualified carbon
dioxide to be taken into account to
compute the GHG emissions rate of a
qualified facility. Further, all taxpayers
must comply with applicable GHGRP
requirements under 40 CFR part 98,
subpart PP (for carbon capture), subpart
RR (for geological storage), and subpart
RR or VV (for geological storage through
enhanced oil recovery). In addition to
the section 45Q rules, taxpayers using
the ISO 27916 standard for EOR must
report information to GHGRP under 40
CFR part 98, subpart VV. Additionally,
a taxpayer claiming the section 45Y
credit while conducting carbon capture
and sequestration must also include
their applicable GHGRP ID number(s)
on any applicable IRS Form when
claiming the section 45Y credit, with
the exception of taxpayers claiming the
section 45Y credit by performing carbon
capture and utilization. The GHGRP
does not provide a reporting mechanism
for utilization.
In the preamble to the proposed
regulations, the Treasury Department
and the IRS provided an example in
which carbon dioxide that was captured
and sequestered as required by section
45Y(e)(3) subsequently escapes into the
atmosphere after such carbon dioxide
was taken into account by a taxpayer
that claimed a section 45Y or 48E credit.
The Treasury Department and the IRS
asked what enforcement mechanisms or
regulatory regimes should be used to

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identify when such emissions leakages
have occurred. The Treasury
Department and the IRS also requested
comment regarding how such emissions
leakages should be taken into account in
determining compliance with the GHG
emissions rate requirements under
sections 45Y and 48E.
Several commenters endorsed using
recapture concepts from the section 45Q
rules to address instances in which
qualified carbon dioxide taken into
account for the section 45Y or 48E
credits later leaks. Other commenters
recommended that for cases in which
captured and sequestered carbon
dioxide subsequently escapes into the
atmosphere, enforcement mechanisms
should include regular monitoring and
reporting requirements outlined in 40
CFR part 98, subpart RR, or CSA/ANSI
ISO 27916:2019, as referenced in
§ 1.45Q–5(c). A commenter noted that
stricter standards of measurement and
reporting, and accounting for leakages
are required to accurately determine if
a facility’s carbon capture and
sequestration adequately accounts for
leaked emissions. Another commenter
suggested that for purposes of the
section 45Y and 48E credits, treatment
of emissions leakages must be adjusted
from the section 45Q rules to require
recalculation of the emissions rate of the
qualified facility if the recalculated GHG
emissions rate exceeds the required
threshold.
After consideration of the comments
the Treasury Department and the IRS
have determined that the provisions of
the section 45Q rules will apply to
qualified carbon dioxide taken into
account by a taxpayer for purposes of
the section 45Y or 48E credits. These
provisions include rules and standards
for quantifying, certifying, and verifying
when metric tons of qualified carbon
dioxide have leaked into the
atmosphere.
Further, the Treasury Department and
the IRS also asked whether the existing
recapture provisions under section 45Q
are sufficient to address emissions
leakages. Several commenters
recommended that the final regulations
incorporate the recapture requirements
provided under § 1.45Q–5 to address
captured and sequestered carbon oxide
that later escapes into the atmosphere
when a taxpayer has taken that carbon
dioxide into account for purpose of the
section 45Y or 48E credits. The section
45Q rules provide for a 3-year recapture
period using a LIFO method and
provide that for each year during the
recapture period the amount of qualified
carbon dioxide that is injected into
secure geological storage is netted
against the amount of qualified carbon

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dioxide that may leak from such secure
geological storage.
A commenter noted that the
mechanics of attributing leakage events
across years must be adapted for the
section 45Y and 48E credits, with the
effect of disqualifying a facility for the
credit in years for which the
recalculated GHG emissions rate
exceeds the threshold. While most
commenters endorsed adopting the
concepts of the section 45Q recapture
rule to the section 45Y and 48E credits,
a commenter requested that the
recapture rules not apply to taxpayers
that use carbon capture and utilization
to claim the section 45Y or 48E credits.
The Treasury Department and the IRS
have determined that the provisions of
the section 45Q rules will apply to
qualified carbon dioxide taken into
account by a taxpayer for purposes of
the section 45Y or 48E credits. These
provisions include rules and standards
for quantifying, certifying, and verifying
when metric tons of qualified carbon
dioxide have leaked into the
atmosphere.
In the preamble to the proposed
regulations, the Treasury Department
and the IRS also requested comment
regarding whether carbon capture and
sequestration that occurs in the
production of fuel that is used by a
facility to produce electricity should be
taken into account under proposed
§ 1.45Y–5(e) and section 45Y(e)(3) and,
if so, how should such use of carbon
capture and sequestration be assessed in
an LCA. Several commenters asserted
that fuel production is within the
boundaries of an LCA for a C&G Facility
and the determination of the GHG
emissions rates for the qualified facility,
and therefore, emissions captured and
sequestered in the production of fuel for
the qualified facility should be taken
into account. Additionally, several
commenters recommended that for
carbon capture and sequestration
occurring in the production of fuel used
by a qualified facility to produce
electricity, the LCA should account for
emissions from the entire carbon
capture and sequestration process,
including capture, purification,
compression, transportation, and
injection because these processes all
require energy input and will
potentially result in further fugitive
emissions and leaks. These commenters
noted that a contrary approach would
ignore a large portion of GHG emissions
in the LCA. As a result, the commenters
assert that the GHG emissions from
these stages should be included in
determining the net GHG emissions rate
of a C&G Facility.

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Other commenters asserted that if
carbon capture and sequestration occurs
in the production of a fuel used as a
feedstock for a qualified facility, such
emissions should be excluded from the
GHG emissions of the qualified facility.
A commenter noted that where fuel is
produced from a process that involves
carbon capture and sequestration (such
as natural gas steam methane reforming,
or gasification of biomass), the entity
producing that fuel would claim any
carbon removal credits. Therefore, the
commenter asserted that the carbon
dioxide captured and sequestered from
the production of the fuel should not be
accounted for by the qualified facility
that uses such the fuel to produce
electricity.
After consideration of the comments,
the Treasury Department and the IRS
have determined that for purposes of
determining a net GHG emissions rate of
a qualified facility, the section 45Q rules
will apply only to qualified carbon
dioxide subject to CCS at such qualified
facility during the production of
electricity. While the section 45Q rules
are applicable to a taxpayer that uses
CCS at a qualified facility during the
production of electricity, there currently
is no known administrable method to
apply those provisions to third parties
that produce fuel used by a qualified
facility. Accordingly, the final
regulations do not adopt the
commenters’ recommendation that CCS
that occurs in the production of fuel that
is used by a qualified facility to produce
electricity should be taken into account
for purpose of determining the net GHG
emissions rate of such qualified facility.
G. Annual Publication of Emissions
Rates
Proposed § 1.45Y–5(f)(1) provided
that, as required by section
45Y(b)(2)(C)(i), the Secretary will
annually publish a table that sets forth
the GHG emissions rates for types or
categories of facilities (Annual Table),
which a taxpayer must use for purposes
of section 45Y. Proposed § 1.45Y–5(f)(1)
further provided that, except as
provided in proposed § 1.45Y–5(h), a
taxpayer that owns a facility that is
described in the Annual Table on the
first day of the taxpayer’s taxable year
in which the section 45Y or section 48E
credit is determined with respect to
such facility must use the Annual Table
as of such date to determine an
emissions rate for such facility for such
taxable year.
Types or categories of facilities must
be added or removed from the Annual
Table consistent with, for Non-C&G
Facilities, a technical assessment of the
fundamental energy transformation into

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electricity as provided in proposed
§ 1.45Y–5(c)(1)(ii), and, for C&G
Facilities, an LCA that complies with
proposed § 1.45Y–5(d) and (e). Proposed
§ 1.45Y–5(f)(2) also provided that in
connection with the publication of the
Annual Table, the Secretary must
publish an accompanying expert
analysis that addresses any types or
categories of facilities added or removed
from the Annual Table since its last
publication. Such analysis must be
prepared by one or more of the National
Laboratories, in consultation with other
Federal agency experts, such as experts
from DOE, the Treasury Department, the
United States Department of Agriculture
(USDA), and the EPA, as appropriate,
and must address whether the addition
or removal of types or categories of
facilities from the Annual Table
complies with section 45Y(b)(2)(A) and
(B) (which refers to the definition of
lifecycle GHG emissions in 42 U.S.C.
7545(o)(1)(H)) of the Code and proposed
§ 1.45Y–5. The Treasury Department
and the IRS view the requirement to
publish an expert analysis prepared by
the National Laboratories of changes to
the Annual Table as essential to
ensuring public accountability and
adherence to sound scientific
principles. This requirement would also
ensure that the Secretary has a robust
record to inform any changes to the
Annual Table.
The Treasury Department and the IRS
intend to include in the Annual Table
the types or categories of facilities that
are described in the final regulations as
having a GHG emissions rate that is not
greater than zero. To provide clarity and
certainty to taxpayers regarding
eligibility, the Treasury Department and
the IRS may also include in the Annual
Table the types or categories of facilities
that have a GHG emissions rate that is
greater than zero and therefore do not
meet the definition of a qualified
facility. The Treasury Department and
the IRS intend to publish the first
Annual Table after the publication of
the final regulations. Until the first
publication of the Annual Table,
taxpayers may treat the types or
categories of facilities that are listed in
proposed § 1.45Y–5(c)(2)(i) through
(viii) as being described in an Annual
Table as having a GHG emissions rate
that is not greater than zero. Further,
any types or categories of facilities that
are added or removed from this list in
the first publication of the Annual Table
or any changes to emissions
determinations for any types or
categories of facilities in the Annual
Table must be accompanied by the
publication of an expert analysis of such

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change as provided in proposed
§ 1.45Y–5(f)(2). If there are no changes
to the Annual Table in a given taxable
year, the Treasury Department and the
IRS intend to notify taxpayers
accordingly.
Commenters provided multiple
perspectives on the substance and form
of the Annual Table. Commenters noted
that the Treasury Department and the
IRS are required to publish an Annual
Table that includes ‘‘the GHG emissions
rates for types or categories of
facilities.’’ Some commenters stated that
the Annual Table should include the
emissions rates of components used in
different C&G technologies, that would
be consistent for all facilities under
specific conditions. Other commenters
stated that the Treasury Department and
the IRS should either not list the facility
type in the Annual Table or should be
conservative about the criteria listed for
facilities with zero or negative
emissions.
As noted earlier in this section of this
Summary of Comments and Explanation
of Revisions, section 45Y(b)(2)(C)(i)
requires the Secretary to annually
publish a table that sets forth the GHG
emissions rates for types or categories of
facilities. In order to promote taxpayer
certainty and fulfill the requirements of
the statute, the Annual Table should
include sufficient information about
what types or categories of facilities
meet the GHG emissions rate
requirements in sections 45Y and 48E.
The Treasury Department and the IRS
therefore do not adopt commenters’
suggestions that the Annual Table
should not include specific facility
types.
From a technical perspective, many
taxpayer situations cannot be covered in
the Annual Table in a way that would
be consistent with the statutory
requirements for determining GHG
emissions rates, as specific factual
circumstances will impact the outcomes
of this analysis. In order to avoid false
precision, the Treasury Department and
the IRS have determined that the
Annual Table should capture whether a
particular type or category of facility has
a GHG emissions rate of less than or
equal to zero or a rate that is greater
than zero. These determinations will be
made consistent with the requirements
of sections 45Y and 48E and these final
regulations.
Some commenters requested that the
publication of the Annual Table be
expedited to release the first Annual
Table at the same time as the final
regulations. Commenters also suggested
that, for types or categories of facilities
that are listed as having a GHG
emissions rate that is less than or equal

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to zero in the final regulations,
publication of the Annual Table or a
PER certification is unnecessary for
those facilities to meet the emissions
rate requirement.
Given the time and effort necessary to
conduct emissions analysis that meets
the requirements of the statute and these
final regulations, the Treasury
Department and the IRS cannot commit
to a specific timeline for publication of
the first Annual Table at this time.
However, as noted earlier in this section
of this Summary of Comments and
Explanation of Revisions, taxpayers may
treat the types or categories of facilities
that are listed in these final regulations
as having an emissions rate that is less
than equal to zero or an emissions rate
of greater than zero in accordance with
the rules provided in the final
regulations.
Commenters also raised concerns
regarding consistency between the
approach to the Annual Table and the
PER process. Some commenters stated
that the Treasury Department should
take a conservative approach to the
evaluation of any petitions for C&G
Facility types not listed in the Annual
Table. The Treasury Department and the
IRS have adopted an approach that
harmonizes the technical requirements
for the Annual Table and the PER
process. For example, for purposes of
determining the net GHG emissions rate
for a C&G Facility under sections 45Y
and 48E, any LCA must meet the
requirements of the statutes, including
taking into account lifecycle GHG
emissions as described in 42 U.S.C.
7545(o)(1)(H) and these final
regulations.
Commenters supported the proposed
regulations’ approach to updating the
Annual Table, including the
requirement to produce analysis led by
one or more of the National
Laboratories, in consultation with other
Federal agency experts, and the
requirement to publish that analysis.
The Treasury Department and the IRS
agree that such an approach is essential
to ensuring public accountability and
adherence to sound scientific principles
and adopt the approach as proposed in
the final regulations.
H. Provisional Emissions Rates
1. In General
For purposes of section 45Y, proposed
§ 1.45Y–5(g) provided the rules
applicable to provisional emissions
rates. Proposed § 1.45Y–5(g)(1) provided
that, in the case of any facility that is of
a type or category for which an
emissions rate has not been established
by the Secretary under proposed

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§ 1.45Y–5(g), a taxpayer that owns such
facility may file a petition with the
Secretary for the determination of the
emissions rate with respect to such
facility (Provisional Emissions Rate or
PER).
For purposes of section 48E, proposed
§ 1.48E–5(g) provided the rules
applicable to provisional emissions
rates. Proposed § 1.48E–5(g)(1) provided
that, in the case of any facility that is of
a type or category for which an
emissions rate has not been established
by the Secretary under proposed
§ 1.48E–5(g), a taxpayer that owns such
facility may file a petition with the
Secretary for the determination of the
emissions rate with respect to such
facility (Provisional Emissions Rate or
PER). The proposed rule is adopted
without change.
2. Rate Not Established
Proposed § 1.45Y–5(g)(2) provided
that an emissions rate has not been
established by the Secretary for a facility
for purposes of section 45Y(b)(2)(C)(ii) if
such facility is not described in the
Annual Table. If a taxpayer’s request for
an emissions value pursuant to
proposed § 1.45Y–5(g)(5) is pending at
the time such facility is or becomes
described in the Annual Table, the
taxpayer’s request for an emissions
value will be automatically denied.
Proposed § 1.48E–5(g)(2) provided
that an emissions rate has not been
established by the Secretary for a facility
for purposes of sections 45Y(b)(2)(C)(ii)
and 48E(b)(3)(B)(ii) if such facility is not
described in the Annual Table. If a
taxpayer’s request for an emissions
value pursuant to proposed § 1.48E–
5(g)(5) is pending at the time such
facility is or becomes described in the
Annual Table, the taxpayer’s request for
an emissions value will be
automatically denied.
3. Process for Filing a PER Petition
Proposed § 1.45Y–5(g)(3) provided the
process for filing a PER petition.
Proposed § 1.45Y–5(g)(3) provided that
to file a PER petition with the Secretary,
a taxpayer must submit a PER petition
by attaching it to the taxpayer’s Federal
income tax return or Federal return, as
appropriate, for the first taxable year in
which the taxpayer claims the section
45Y credit with respect to the facility to
which the PER petition applies. A PER
petition must contain an emissions
value and, if provided by DOE, the
associated DOE letter. An emissions
value may be obtained from DOE or by
using the LCA model designated in
proposed § 1.45Y–5(g)(6).
An emissions value obtained from
DOE will be based on an analytical

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assessment of the emissions rate
associated with the facility, performed
by one or more National Laboratories, in
consultation with Federal agency and
other experts as appropriate, consistent
with proposed § 1.45Y–5. A taxpayer
would be required to retain in its books
and records the request to DOE for an
emissions value, including any
information provided by the taxpayer to
DOE pursuant to the emissions value
request process provided in proposed
§ 1.45Y–5(g)(5).
Alternatively, an emissions value can
be determined by the taxpayer for a
facility using the most recent version of
an LCA model or models, as of the time
the PER petition is filed, that have been
designated by the Secretary for such use
under proposed § 1.45Y–5(g)(6). If an
emissions value is determined using the
designated model, a taxpayer is required
to provide to the IRS information to
support its determination of the
emissions value in the form and manner
prescribed in IRS forms or instructions
or in publications or guidance
published in the Internal Revenue
Bulletin. See § 601.601 of this chapter.
A taxpayer may not request an
emissions value from DOE for a facility
for which an emissions value can be
determined by using the most recent
version of an LCA model or models that
have been designated by the Secretary
for such use under proposed § 1.45Y–
5(g)(6).
Proposed § 1.48E–5(g)(3) provided the
process for filing a PER petition.
Proposed § 1.48E–5(g)(3) provided that
to file a PER petition with the Secretary,
a taxpayer must submit a PER petition
by attaching it to the taxpayer’s Federal
income tax return or Federal return, as
appropriate, for the first taxable year in
which the taxpayer claims the section
48E credit with respect to the facility to
which the PER petition applies. A PER
petition must contain an emissions
value and, if provided by DOE, the
associated DOE letter. An emissions
value may be obtained from DOE or by
using the LCA model designated in
proposed § 1.48E–5(g)(6).
An emission value obtained from DOE
will be based on an analytical
assessment of the emissions rate
associated with the facility, performed
by one or more National Laboratories, in
consultation with other Federal agency
experts as appropriate, consistent with
proposed § 1.48E–5. A taxpayer would
be required to retain in its books and
records the request to DOE for an
emissions value, including any
information provided by the taxpayer to
DOE pursuant to the emissions value
request process provided in proposed
§ 1.48E–5(g)(5).

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Alternatively, an emissions value can
be determined by the taxpayer for a
facility using the most recent version of
an LCA model or models, as of the time
the PER petition is filed, that have been
designated by the Secretary for such use
under proposed § 1.48E–5(g)(6). If an
emissions value is determined using the
designated model, a taxpayer is required
to provide to the IRS information to
support its determination of the
emissions value in the form and manner
prescribed in IRS forms or instructions
or in publications or guidance
published in the Internal Revenue
Bulletin. See § 601.601 of this chapter.
A taxpayer may not request an
emissions value from DOE for a facility
for which an emissions value can be
determined by using the most recent
version of an LCA model or models that
have been designated by the Secretary
for such use under proposed § 1.48E–
5(g)(6).
A commenter supported the process
provided in the proposed regulations for
filing a PER petition and for permitting
taxpayers to determine an emissions
value during the PER process based on
the most recent approved LCA model.
However, the commenter cautioned that
a self-certification option would be
effective only to the extent that LCA
models are approved for cleanelectricity technologies for which an
emissions rate is not available in the
Annual Table. This commenter
recommended that the Treasury
Department and the IRS approve LCA
models expeditiously and ensure that
the LCA models take avoided emissions
into account based on technologies like
fuel cells. Another commenter suggested
clarifying whether facilities with
standardized configurations and
equipment could rely upon a single
PER, rather than having to
independently apply for a PER. The
commenter emphasized that a single
PER could just as easily be applied to
separate facilities, provided that
material characteristics are sufficiently
similar.
The Treasury Department and the IRS
developed the PER process in
consultation with the DOE and other
agencies. The procedures developed for
the PER process will designate an LCA
model or models that are consistent
with the requirements of sections 45Y
and 48E and these regulations for use
under § 1.45Y–5(g)(6). The Treasury
Department and the IRS decline to
permit taxpayers to rely upon a single
PER for separate facilities, because, as a
commenter recognized, whether a single
PER could be applicable to separate
facilities would depend on the facts and
circumstances. Accordingly, to ensure

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that the taxpayer has a PER
determination applicable to each
qualified facility, the taxpayer must
submit a request for a PER
determination for each separate facility.
With respect to the Annual Table and
the PER process, a commenter requested
that the Treasury Department develop or
design an incentive for those investors
willing to invest in technological
innovations that could improve on
average results likely set forth in the
Annual Table. The Treasury Department
and the IRS decline to address this
request because the addition of extrastatutory incentives is outside the scope
of these final regulations.
4. PER Determination
Proposed § 1.45Y–5(g)(4) provided
that, upon the IRS’s acceptance of the
taxpayer’s Federal income tax return or
Federal return, as appropriate,
containing a PER petition, the emissions
value of the facility specified on such
petition will be deemed accepted. Such
PER petition must be submitted to the
IRS in the first taxable year in which the
taxpayer claims the section 45Y credit
with respect to the facility to which the
PER petition applies. A taxpayer would
be able to rely upon an emissions value
provided by DOE for purposes of
calculating and claiming a section 45Y
credit, provided that any information,
representations, or other data provided
to DOE in support of the request for an
emissions value accurately reflect the
facility’s operations in each year the
taxpayer seeks to rely on that emissions
value. If applicable, a taxpayer may rely
upon an emissions value determined for
a facility using the most recent version
of the LCA model or models that, as of
the time the PER petition is filed, have
been designated by the Secretary for
such use under proposed § 1.45Y–
5(g)(6), provided that any information,
representations, or other data used to
obtain such emissions value remain
accurate. The IRS’s deemed acceptance
of an emissions value is the Secretary’s
determination of the PER. The taxpayer
must still comply with all applicable
requirements for the section 45Y credit
and any information, representations, or
other data supporting an emissions
value are subject to later examination by
the IRS.
Proposed § 1.48E–5(g)(4) provided
that, upon the IRS’s acceptance of the
taxpayer’s Federal income tax return or
Federal return, as appropriate,
containing a PER petition, the emissions
value of the facility specified on such
petition will be deemed accepted. A
taxpayer would be able to rely upon an
emissions value provided by DOE for
purposes of calculating and claiming a

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section 48E credit, provided that any
information, representations, or other
data provided to DOE in support of the
request for an emissions value are
accurate. If applicable, a taxpayer may
rely upon an emissions value
determined for a facility using the most
recent version of the LCA model or
models that, as of the time the PER
petition is filed, have been designated
by the Secretary for such use under
proposed § 1.48E–5(g)(6), provided that
any information, representations, or
other data used to obtain such emissions
value are accurate. The IRS’s deemed
acceptance of an emissions value is the
Secretary’s determination of the PER.
The taxpayer must still comply with all
applicable requirements for the section
48E credit and any information,
representations, or other data
supporting an emissions value are
subject to later examination by the IRS.
A commenter suggested permitting
joint evaluations of similar PER
requests, as well as leveraging
information submitted under prior
evaluations, to promote a more
streamlined process. The commenter
requested that the Treasury Department
and the IRS prioritize certainty and
expediency and clarify the timing by
which taxpayers can expect to receive
an official assessment from the National
Laboratories and other involved experts.
An additional commenter stated that a
delay in PER determinations would be
hugely detrimental and disadvantage
early entrants and innovative
technologies. This commenter suggested
that the Treasury Department, the IRS,
and the DOE assess their collective
capacities and resource needs to
conduct analytical assessments for PER
applications efficiently and
expeditiously. The commenter also
recommended that the Treasury
Department direct the DOE to assess
applications and determine a facility’s
emissions rate within six months of a
taxpayer’s submission of a PER
application.
The Treasury Department and the IRS
recognize the importance of certainty
and expediency in evaluating PER
requests and have consulted with DOE
to develop the PER application process.
These agencies expect to review PER
applications within an appropriate
timeframe. Therefore, the changes
suggested by the comments are not
adopted. The Treasury Department and
the IRS will continue to consult with
the DOE as appropriate to assist in the
administration of these final regulations.
5. Emissions Value Request Process
Proposed § 1.45Y–5(g)(5) provided the
rules applicable to the emissions value

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request process. Proposed § 1.45Y–
5(g)(5) provided that an applicant that
submits a request for an emissions value
must follow the procedures specified by
DOE to request and obtain such
emissions value, and that emissions
values will be determined consistent
with the rules provided in proposed
§ 1.45Y–5. An applicant may request an
emissions value from DOE only after a
front-end engineering and design
(FEED) study or similar indication of
project maturity, as determined by DOE,
such as the completion of a project
specification and cost estimation
sufficient to inform a final investment
decision for the facility. DOE may
decline to review applications that are
non-responsive and those applications
that relate to a facility that is described
in the Annual Table (consistent with
proposed § 1.45Y–5(g)(2)) or a facility
that can determine an emissions value
using a designated LCA model under
proposed § 1.45Y–5(g)(6) (consistent
with proposed § 1.45Y–5(g)(3)), or
applications that are incomplete.
Proposed § 1.45Y–5(g)(5) also
provided that applicants must follow
DOE’s guidance and procedures for
requesting and obtaining an emissions
value from DOE. DOE will publish
guidance and procedures that applicants
must follow to request and obtain an
emissions value from DOE. DOE’s
guidance and procedure will include a
process, under limited circumstances,
for a taxpayer to request a revision to
DOE’s initial assessment of an emissions
value on the basis of revised technical
information or facility design and
operation. The Treasury Department
and the IRS anticipate that the
emissions value request process will
open after the publication of the final
regulations.
Proposed § 1.48E–5(g)(5) provided the
rules applicable to the emissions value
request process. Proposed § 1.48E–
5(g)(5) provided that an applicant that
submits a request for an emissions value
must follow the procedures specified by
DOE to request and obtain such
emissions value, and that emissions
values will be determined consistent
with the rules provided in proposed
§ 1.48E–5. An applicant may request an
emissions value from DOE only after a
FEED study or similar indication of
project maturity, as determined by DOE,
such as the completion of a project
specification and cost estimation
sufficient to inform a final investment
decision for the facility. DOE may
decline to review applications that are
non-responsive and those applications
that relate to a facility that is described
in the Annual Table (consistent with
proposed § 1.48E–5(g)(2)) or a facility

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that can determine an emissions value
using a designated LCA model under
proposed § 1.48E–5(g)(6) (consistent
with proposed § 1.48E–5(g)(3)), or
applications that are incomplete.
Proposed § 1.48E–5(g)(5) also
provided that applicants must follow
DOE’s guidance and procedures for
requesting and obtaining an emissions
value from DOE. DOE will publish
guidance and procedures that applicants
must follow to request and obtain an
emissions value from DOE. DOE’s
guidance and procedure will include a
process, under limited circumstances,
for a taxpayer to request a revision to
DOE’s initial assessment of an emissions
value on the basis of revised technical
information or facility design and
operation. The Treasury Department
and the IRS anticipate that the
emissions value request process will
open after the publication of the final
regulations.
A commenter requested that the
Treasury Department conservatively
evaluate any petitions to assign an
emissions rate for C&G facility types not
listed in the Annual Table and to strive
to be fully confident that operation of
the facility would not lead to net
lifecycle emissions.
The Treasury Department and the IRS
have adopted an approach that
harmonizes the technical requirements
for the Annual Table and the PER
process. For example, for purposes of
determining the GHG emissions rate for
a C&G Facility under sections 45Y and
48E, any LCA must meet the
requirements of the statutes, including
taking into account lifecycle GHG
emissions as described in 42 U.S.C.
7545(o)(1)(H) and these final
regulations.
Another commenter contended that
completion of a FEED study is an
inappropriate indicator of project
maturity to request a PER. The
commenter asserted that such a
requirement could substantially delay
projects and that a more logical
approach would be for the DOE to
determine a PER using a pre-FEED or
feasibility study as a demonstration of
project maturity. An additional
commenter claimed that the cost and
related timing of a FEED study may be
prohibitive for distributed or small-scale
facilities. The commenter asserted that
in order to access project financing,
project developers must know early in
the development process that a facility
will be eligible for the section 45Y or
48E credit. However, the commenter
stated that, a FEED study cannot
typically be completed until well after
a project developer will need to have
provided prospective financiers with

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certainty about credit eligibility. The
commenter noted that this disconnect
could effectively prevent the
development of clean energy production
facilities that utilize pathways not
already identified in the Annual Table.
As an alternative to requiring a FEED
study, a commenter suggested accepting
an LCA performed by a third-party,
DOE-certified provider, conducted using
the most current, approved GREET
model, provided that the following
criteria are satisfied: (i) the system is UL
or CE certified, (ii) the total landed bill
of materials (BOM) cost of the system is
less than $20 million, and (iii) the
system has less than 10 MW energy
equivalent (thermal, total gas flow, or
total electricity) in it. Similarly, a
commenter asserted that FEED studies
can cost up to $50 million and delay
project development by 6–8 months and
recommended considering projects at
FEL–2 27 of the project for PER
applications.
Proposed § 1.45Y–5(g)(5) provided
flexibility to taxpayers by permitting a
taxpayer to request an emissions value
from DOE after an indication of project
maturity, as determined by DOE, such
as a FEED study or the completion of a
project specification and cost estimation
sufficient to inform a final investment
decision for the facility. As proposed,
DOE has some discretion to determine
appropriate project maturity indicators,
if not a FEED study. However, a preFEED or feasibility study are not
adequate indicators of project maturity
as there exists too high of a likelihood
that the final design of the qualified
facility will differ from the pre-FEED or
feasibility study and therefore would
undermine the implementation of the
statutory definition of a qualified
facility. Accordingly, the proposed rule
is adopted without change.
An applicant can request an
emissions value from DOE only after a
front-end FEED study or similar
indication of project maturity, as
determined by DOE, such as the
completion of a project specification
and cost estimation sufficient to inform
a final investment decision for the
facility. The DOE will publish more
information about the process to receive
an emissions value in forthcoming
guidance.
27 FEL–2, also known as the conceptual design or
feasibility design phase of a project, may typically
result in deliverables which include project
schedule, preliminary design report, site layout,
and similar. See Stage Gate Project Management,
Mark Ludwigson, PDH Academy, https://
pdhacademy.com/wp-content/uploads/2024/01/
524-Stage_Gate_Project_Management.pdf.

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6. LCA Model for Determining an
Emissions Value for C&G Facilities
Proposed § 1.45Y–5(g)(6) provided
that the Secretary may designate one or
more LCA models for a taxpayer to
determine an emissions value for C&G
Facilities that are not described in the
Annual Table. A model may only be
designated if it complies with section
45Y(b)(2)(B) and proposed § 1.45Y–5(d)
and (e). The Secretary may revoke the
designation of an LCA model or models.
In connection with the designation or
revocation of a designation of an LCA
model or models, the Secretary is
required to publish an accompanying
expert analysis of the model prepared
by one or more of the National
Laboratories, in consultation with other
Federal agency experts as appropriate.
Such analysis must address the model’s
compliance with section 45Y(b)(2)(B)
and proposed § 1.45Y–5(d) and (e). The
Treasury Department and the IRS view
the requirement to publish an expert
analysis prepared by the National
Laboratories of the designation or
revocation of designation of an LCA
model or models as essential to ensuring
public accountability and adherence to
sound scientific principles. This
requirement also ensures that the
Secretary has a robust record to inform
any designations or revocations of an
LCA model or models.
The rules provided in proposed
§ 1.45Y–5(g)(6) regarding the
designation of an LCA model or models
for determining an emissions value for
C&G Facilities apply for purposes of
section 48E and proposed § 1.48E–
5(g)(6).
7. Effect of PER
Proposed § 1.45Y–5(g)(7) provided
that a taxpayer may use a PER
determined by the Secretary to
determine the section 45Y credit for the
facility to which the PER applies,
provided all other requirements of
section 45Y are met. The Secretary’s
determination of a PER 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 45Y credit is
claimed. A PER determination does not
signify that the IRS has determined that
the requirements of section 45Y have
been satisfied for any taxable year.
Proposed § 1.48E–5(g)(7) provided
that a taxpayer may use a PER
determined by the Secretary to

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determine the section 48E credit for the
facility to which the PER applies,
provided all other requirements of
section 48E are met. The Secretary’s
determination of a PER 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 48E credit is
claimed. A PER determination does not
signify that the IRS has determined that
the requirements of section 48E have
been satisfied for any taxable year.
8. Reliance on Annual Table or
Provisional Emissions Rate
Proposed § 1.45Y–5(h) provided that
taxpayers may rely on the Annual Table
in effect as of the date a facility began
construction or the provisional
emissions rate that has been determined
by the Secretary for the taxpayer’s
facility under proposed § 1.45Y–5(g)(4)
to determine the facility’s GHG
emissions rate for that facility for any
taxable year that is within the 10-year
period described in section 45Y(b)(1)(B),
provided that the facility continues to
operate as a type of facility that is
described in the Annual Table or the
facility’s emissions value request, as
applicable, for the entire taxable year.
A commenter requested a safe harbor
for taxpayers with ongoing transactions
in the event of any changes to categories
of facilities and corresponding GHG
emissions rates listed on the Annual
Table, with a clearly advertised cutoff
date for the applicability of the prior
iteration.
The proposed regulations provided a
rule allowing for reliance on the Annual
Table in effect as of the date a facility
began construction in order to give
sufficient taxpayer certainty for projects
in development. Specifying that reliance
on the Annual Table in effect based on
the beginning of construction date
provides a clear point in time that is
already well understood for tax
purposes. The commenter’s
recommendation requires a fact
intensive analysis of an event or series
of events that lack a definitive date
certain for when a transaction becomes
‘‘ongoing.’’ Such a rule is not
administrable for taxpayers and the IRS.
Therefore, the proposed rule is adopted
without change.
I. Determining Anticipated Greenhouse
Gas Emissions Rate
Consistent with section
48E(b)(3)(A)(iii), proposed § 1.48E–5(h)

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Federal Register / Vol. 90, No. 9 / Wednesday, January 15, 2025 / Rules and Regulations
provided rules to determine an
anticipated GHG emissions rate. As
explained in the preamble to the
proposed regulations, the Treasury
Department and the IRS interpret the
reference in section 48E(b)(3)(A)(iii) to
an ‘‘anticipated greenhouse gas
emissions rate’’ that is not greater than
zero to require a reasonable expectation
that a qualified facility will operate with
a rate or net rate of greenhouse gas
emissions that is not greater than zero
over a specified period of time. Certain
Non-C&G Facilities, such as the
facilities described in § 1.45Y–5(c)(2),
may have an anticipated greenhouse gas
emissions rate that is not greater than
zero based on the technology and
practices they rely upon to generate
electricity. For facilities that require the
use of certain fuel sources, which may
vary, or carbon capture and
sequestration, to generate electricity
with a greenhouse gas emissions rate
that is not greater than zero, objective
indicia that such facilities will use such
fuel sources or operate such carbon
capture equipment, as applicable, in a
manner that results in a greenhouse gas
emissions rate that is not greater than
zero for at least 10 years beginning from
the date the facility is placed in service
are required to establish a reasonable
expectation that the combination of fuel,
type of facility, and practice will result
in a greenhouse gas emissions rate that
is not greater than zero.
The proposed regulations provided a
non-exhaustive list of examples of
objective indicia that may establish a
reasonable expectation that a qualified
facility will operate with an anticipated
GHG emissions rate that is not greater
than zero, including include co-location
of the facility with a fuel source for
which the combination of fuel, type of
facility, and practice is reasonably
expected to result in a GHG emissions
rate that is not greater than zero; a 10year contract to purchase fuels for
which the combination of fuel, type of
facility, and practice is reasonably
expected to result in a GHG emissions
rate that is not greater than zero; or a
facility type that only accommodates
one type of fuel or a small range of fuels
for which the combination of fuel, type
of facility, and practice is reasonably
expected to result in a GHG emissions
rate that is not greater than zero; or a 10year contract for the capture, disposal,
or utilization of qualified carbon
dioxide from the facility for which the
combination of fuel, type of facility, and
practice is reasonably expected to result
in a GHG emissions rate that is not
greater than zero. These examples are
adopted in the final regulations in

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§ 1.48E–5(h)(2) with minor changes to
clarify that such contracts must be
binding written contracts and to more
closely align the language used in the
example pertaining to carbon capture
and sequestration at proposed § 1.48E–
5(h)(2)(iv) with that used for purposes of
section 45Q and referenced in section
45Y(b)(2)(D).
The Treasury Department and the IRS
requested comment on what evidence or
substantiation taxpayers should be
required to maintain to be able to
establish an anticipated GHG emissions
rate for a qualified facility. Two
commenters recommended requiring
that objective indicia take the form of
physical features that make it more
likely that the qualified facility will
operate with a GHG emissions rate that
is not greater than zero. In these
commenters’ view, if the objective
indicia do not relate to physical features
of the qualified facility, the qualified
facility could be too easily repurposed
in a way that results in a positive GHG
emissions rate. Commenters provided
examples of physical features such as
evidence of carbon capture and
sequestration equipment incorporated
into the qualified facility or a direct
pipeline connection from the qualified
facility to a waste fuel or feedstock, as
appropriate.
The Treasury Department and the IRS
have determined that objective indicia
need not always take the form of
physical features. While in some cases
physical features may provide objective
indicia that a qualified facility will
operate with a GHG emissions rate that
is not greater than zero, such features
are not relevant and therefore not
required in all cases. Some qualified
facilities may not have a physical
feature that differentiates a facility with
a GHG emissions rate that is not greater
than zero from a comparable facility
with a GHG emissions rate that is
greater than zero. In such cases, the
taxpayer must find another method of
documenting its anticipated GHG
emissions rate that is not greater than
zero that provides a comparable level of
substantiation as a physical feature.
This could take the form of a long-term
contract for fuel that would enable the
facility to attain a GHG emissions rate
that is not greater than zero, provided
the contract imposes a binding
obligation on the purchaser to
compensate the seller for a sufficient
volume of fuel to operate the entire
facility for a substantial portion of the
facility’s lifetime, such as ten years. The
Treasury Department and the IRS have
determined that in some cases nonphysical features that involve
commitment to a third party, such as the

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aforementioned contract, can provide
substantiation that a facility is
reasonably expected to operate with a
GHG emissions rate that is not greater
than zero that is equivalent to the
substantiation provided by a physical
feature and relevant for a facts and
circumstances analysis. Accordingly,
the final regulations do not adopt the
suggestion that objective indicia must
take the form of physical features.
The Treasury Department and the IRS
also recognize that in some cases, a
facility may seek to establish that it will
operate with a GHG emissions rate that
is not greater than zero on the basis that
it will continuously operate carbon
capture and sequestration equipment
during electricity production. The
physical presence of the carbon capture
equipment would not generally be
sufficient objective indicia to
substantiate that the facility will operate
using that equipment. The final
regulations therefore provide at § 1.48E–
5(h)(2)(iv) that one form of objective
indicia substantiating operation of such
equipment may include a 10-year
binding written contract for the
permanent geological storage (including
after injection into an EOR project) or
utilization of qualified carbon dioxide
from the facility for which the
combination of fuel, type of facility, and
practice is reasonably expected to result
in a GHG emissions rate that is not
greater than zero. The final regulations
further provide an additional example
of such objective indicia substantiating
the operation of this equipment at
§ 1.48E–5(h)(2)(v). Such objective
indicia may include a legally binding
Federal or State air permit which
requires, as a condition of the permit,
that the facility operates in a manner for
which the combination of fuel, type of
facility, and practice is reasonably
expected to result in a greenhouse gas
emissions rate that is not greater than
zero and that any captured carbon
dioxide is permanently geologically
stored and subjects the holder to civil or
criminal penalties in the event the
relevant permit requirements are
breached. In the case of a facility which
requires the operation of carbon capture
and sequestration equipment to achieve
a qualifying GHG emissions rate of not
greater than zero, the Treasury
Department and the IRS have currently
identified that such a permit
requirement would provide sufficient
assurance that the objective indicia
requirement is met with respect to the
operation of the carbon capture and
sequestration and expect that taxpayers
seeking to substantiate in other ways

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would need to substantiate with
substantially similar objective indicia.
The preamble to the proposed
regulations also requested comment on
the appropriate period of time for which
taxpayers should be required to be able
to demonstrate that there is a reasonable
expectation that a qualified facility will
operate with a GHG emissions rate that
is not greater than zero. Commenters
provided a range of views on this topic.
Several commenters suggested that
taxpayers be required to demonstrate
objective indicia that a qualified facility
will operate with a GHG emissions rate
that is not greater than zero for the
lifetime of the qualified facility. Several
other commenters recommended that
this period be shorter, asserting that
longer timelines, such as those beyond
ten years, could prove burdensome, in
part due to greater uncertainty over such
time periods.
Because the Treasury Department and
the IRS have determined that the
examples of objective indicia that
account for a GHG emissions rate over
ten years are sufficient to show that the
operation of a qualified facility could
reasonably be expected to result in a
GHG emissions rate that is not greater
than zero, these final regulations will
not adopt the suggestion that the
lifetime of the facility is the appropriate
period of time for which a taxpayer is
required to be able to demonstrate such
expectation. The Treasury Department
and the IRS have determined that
demonstrating a reasonable expectation
that a qualified facility will operate with
a GHG emissions rate that is not greater
than zero for the lifetime of a qualified
facility would, for some long-lived
facilities, be extremely challenging, if
not impossible. However, these final
regulations require taxpayers claiming
the section 48E credit to attest under
penalty of perjury in a manner
prescribed by the IRS in forms or
instructions that the anticipated GHG
emissions rate as determined under the
statute and these final regulations is not
greater than zero. A facility subject to
legally binding State or Federal permit
conditions requiring that the facility
operate in a manner that would be
incompatible with a greenhouse gas
emissions rate of not greater than zero
is not a facility for which the
anticipated greenhouse gas emissions
rate is not greater than zero.
J. Substantiation
Upon consideration of the comments
and consultation with other Federal
agency experts, the Treasury
Department and the IRS have also
determined that the proposed
regulations would benefit from

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additional clarity regarding
substantiation requirements. In
particular, the Treasury Department and
the IRS acknowledge commenters’
concerns about verifying and
substantiating the key characteristics
that ensure a qualified facility has a
GHG emissions rate not greater than
zero. Accordingly, the final regulations
make clear that substantiation
requirements prescribed by the
Secretary must include substantiation of
the key parameters that would
contribute to or impact the GHG
emissions rates based on analytical
assessments conducted by the National
Laboratories, in consultation with other
Federal agency experts as appropriate.
The Treasury Department and the IRS
will describe specific substantiation
requirements for such facilities,
including requirements for preparation
or verification by an unrelated third
party as appropriate, in future guidance.
The Treasury Department and the IRS
will require taxpayers to substantiate
that the full electricity production
process—including specific fuels or
feedstocks used—is consistent with the
taxpayer’s claims and meets the specific
criteria that the analytical assessment
has found are necessary for it to meet
the statutory requirement of a GHG
emissions rate not greater than zero.
Given feedback provided by
commenters on biomass discussed in
section VIII.E. of this Summary of
Comments and Explanation of
Revisions, the final regulations also
specify that for C&G Facilities utilizing
biomass feedstocks, taxpayers must
substantiate that the source of such fuels
or feedstocks used are consistent with
the taxpayer’s claims. Moreover, in
response to comments and as discussed
in section VIII.D. of this Summary of
Comments and Explanation of
Revisions, if a qualified facility uses
feedstocks that do not have
marketability, but which are
indistinguishable from marketable
feedstocks (for instance, after
processing), the taxpayer will be
required to maintain documentation
substantiating the origin and original
form of the feedstock. To ensure that
C&G Facilities that utilize biomass
feedstocks meet the statutory
requirement of a net GHG emissions rate
not greater than zero, the Treasury
Department and the IRS anticipate that
it may be appropriate to require or
encourage taxpayers to maintain thirdparty certification that verifies that these
facilities meet the criteria that the LCA
has found are necessary for a facility to
meet this statutory requirement.

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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.
Applicability Dates
These regulations apply to qualified
facilities (and for §§ 1.48E–1 through
1.48E–4, ESTs) placed in service after
December 31, 2024, and during taxable
years ending on or after January 15,
2025.
Special Analyses
I. Regulatory Planning and Review—
Economic Analysis
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
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. An agency
may not conduct or sponsor and a
person is not required to respond to a
collection of information unless it
displays a valid OMB control number.
The collections of information in
these final regulations contain
recordkeeping and reporting
requirements that are required to
substantiate eligibility to claim a section
45Y or section 48E credit. These
collections of information would
generally be used by the IRS for tax
compliance purposes and by taxpayers
to facilitate proper reporting and
compliance. The general recordkeeping
requirements mentioned within these
final regulations are considered general
tax records under § 1.6001–1(e).
The recordkeeping requirements in
these final regulations with respect to
section 45Y include the requirement in
§ 1.45Y–5(h)(1) that taxpayers claiming
the section 45Y credit must maintain in
its books and records documentation
regarding the design and operation of a
facility that establishes that such facility

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had a GHG emissions rate that is not
greater than zero for the taxable year.
Included in § 1.45Y–5(h)(2) are
examples of documentation that
sufficiently substantiates that a facility
has a GHG emissions rate that is not
greater than zero for the taxable year,
which includes documentation, or a
report prepared by an unrelated party
that verifies that a facility had such an
emissions rate. A facility described in
§ 1.45Y–5(c)(2) can maintain sufficient
documentation to demonstrate a GHG
emissions rate that is not greater than
zero for the taxable year by showing that
it is a type of facility described in
§ 1.45Y–5(c)(2). Section 1.45Y–5(h)(2)
provides that for other types of facilities
not described in § 1.45Y–5(c)(2), the
taxpayer must demonstrate that the
qualified facility meets the specific
criteria that the analytical assessment
prepared by the National Laboratories,
in consultation with other Federal
agency experts as appropriate, has
found are necessary for a facility to meet
the statutory requirement of a
greenhouse gas emissions rate not
greater than zero. Section 1.45Y–5(j)(2)
provides that for C&G Facilities that
utilize biomass feedstocks, the taxpayer
must substantiate that the source of
such fuels or feedstocks used are
consistent with the taxpayer’s claims.
Section 1.45Y–5(j)(2) further provides
that for the qualified facilities not
described in § 1.45Y–5(c)(2), the
Secretary may determine that other
types of facilities can sufficiently
substantiate a GHG emissions rate, as
determined under this section, that is
not greater than zero with certain
documentation and will describe such
facilities and documentation in IRS
forms, instructions, or publications, or
guidance published in the Internal
Revenue Bulletin. For facilities that
utilize unmarketable feedstocks that are
indistinguishable from marketable
feedstocks (for instance, after
processing), the taxpayer will be
required to maintain documentation
substantiating the origin and original
form of the feedstock. For PRA
purposes, these general tax records are
already approved by OMB under 1545–
0074 for individuals, 1545–0123 for
business entities, 1545–0092 for trust
and estate filers, and 1545–0047 for taxexempt organizations.
The recordkeeping requirements in
these final regulations with respect to
section 48E would include the
requirement in § 1.48E–5(k)(1) that a
taxpayer must maintain in its books and
records documentation regarding the
design and operation of a facility that
establishes that such facility had an

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anticipated GHG emissions rate that is
not greater than 10 grams of CO2e per
kWh during each year of the recapture
period that applies for purposes of
section 48E(g). Included in § 1.48E–
5(k)(2) are examples of documentation
that sufficiently substantiates that a
facility has a GHG emissions rate that is
not greater 10 grams of CO2e per kWh
during each year of the recapture
period, which includes documentation,
or a report prepared by an unrelated
party that verifies that a facility had
such an emissions rate. A facility
described in § 1.45Y–5(c)(2) can
maintain sufficient documentation to
demonstrate a GHG emissions rate that
is not greater than 10 grams of CO2e per
kWh by showing that it is a type of
facility described in § 1.45Y–5(c)(2). The
Secretary may determine that other
types of facilities can sufficiently
substantiate a GHG emissions rate that
is not greater than 10 grams of CO2e per
kWh with certain documentation and
will describe such facilities and
documentation in IRS forms,
instructions, or publications, or in
guidance published in the Internal
Revenue Bulletin. For such other types
of facilities that utilize biomass
feedstocks, the taxpayer must
substantiate that the source of such fuels
or feedstocks used are consistent with
the taxpayer’s claims. For all facilities
that utilize unmarketable feedstocks that
are indistinguishable from marketable
feedstocks (for instance, after
processing), the taxpayer will be
required to maintain documentation
substantiating the origin and original
form of the feedstock. For PRA
purposes, these general tax records are
already approved by OMB under 1545–
0074 for individuals, 1545–0123 for
business entities, 1545–0092 for trust
and estate filers, and 1545–0047 for taxexempt organizations.
The reporting requirements in these
final regulations are in §§ 1.45Y–5 and
1.48E–5, which provide the process for
applicants to file a petition with the
Secretary for a PER determination. To
file a PER petition with the Secretary, a
taxpayer must submit the PER petition
attached to the taxpayer’s Federal
income tax return or Federal return, as
appropriate, for the taxable year in
which the taxpayer claims the section
45Y credit or the section 48E credit with
respect to the facility to which the PER
petition relates. A PER petition must
contain an emissions value. If the
applicant obtained an emissions value
from DOE, the PER petition made to the
IRS must include and emissions value
letter from DOE. This emission value
letter process will be approved by OMB.

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A taxpayer must retain in its books and
records a copy of the taxpayer’s request
to DOE for an emissions value,
including the supporting documentation
provided to DOE with the request.
Alternatively, if applicable, a PER
petition may contain an emissions value
determined for a facility using the most
recent version of an LCA model, as of
the time the PER petition is filed, that
has been designated by the Secretary for
such use. If an emissions value is
determined using a designated model, a
taxpayer is required to provide to the
IRS information to support its
determination of the emissions value in
the form and manner prescribed in IRS
forms, instructions, or publications, or
guidance published in the Internal
Revenue Bulletin. The burden for these
requirements will be included within
the forms and instructions applicable to
sections 45Y and 48E.
For section 45Y, the burden for these
requirements will be associated the form
and instructions applicable to claiming
this credit and will be approved by
OMB, in accordance with 5 CFR
1320.10, under the following OMB
control numbers: 1545–0074 for
individuals/sole proprietors, 1545–0123
for business entities, 1545–0047 for taxexempt organizations, and 1545–0092
for trust and estate filers.
For section 48E, the burden for these
requirements will be associated with
Form 3468, Investment Credit, and will
be approved by OMB, in accordance
with 5 CFR 1320.10, under the
following OMB control numbers: 1545–
0074 for individuals/sole proprietors,
1545–0123 for business entities, 1545–
0047 for tax-exempt organizations, and
1545–0092 for trust and estate filers.
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 604 of the RFA requires the
agency to present a final regulatory
flexibility analysis (FRFA) of the final
regulations.
The Treasury Department and the IRS
have not determined whether the final
rule will likely have a significant
economic impact on a substantial
number of small entities. This

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determination requires further study.
However, because there is a possibility
of significant economic impact on a
substantial number of small entities, an
IRFA is provided in these final
regulations affected and the economic
impact on small entities.
In addition, pursuant to section
7805(f), the proposed regulations
preceding these final regulations were
submitted to the Chief Counsel for the
Office of Advocacy of the Small
Business Administration for comment
on its impact on small business, and no
comments were received from the Chief
Counsel for the Office of Advocacy of
the Small Business Administration.
However, the Small Business
Administration’s Office of Advocacy
provided comments in response to the
PWA proposed regulations, including
proposed § 1.48E–3, which is finalized
as modified by this Treasury decision.
See section III.B. of the Special Analysis
of the PWA final regulations for a
discussion of those comments.

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A. Need for and Objectives of the Rule
The final regulations provide greater
clarity to taxpayers for purposes of
claiming the section 45Y credit and
section 48E credit. The final regulations
provide necessary definitions rules
regarding the determination of credit
amounts and the procedure for
requesting a provisional emissions rate.
The final regulations provide greater
clarity to taxpayers for purposes of
claiming the section 45Y credit and the
section 48E credit and encourage
taxpayers to produce clean energy or
invest in clean energy facilities and
ESTs. Thus, the Treasury Department
and the IRS intend and expect that the
final regulations will deliver benefits
across the economy that will
beneficially impact various industries.
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 final
regulations. The Small Business
Administration’s Office of Advocacy
estimates in its 2023 Frequently Asked
Questions that 99.9 percent of American
businesses meet its definition of a small
business. The applicability of these final
regulations does not depend on the size
of the business, as defined by the Small
Business Administration.
As described more fully in the
preamble to this final regulation and in
this IRFA, the section 45Y credit and
the section 48E credit incentivize the
production of clean energy and the
investment in clean energy facilities and
energy storage facilities. Because the

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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.
The Treasury Department and the IRS
expect to receive more information on
the impact on small businesses once
taxpayers start to claim the section 45Y
credit or the section 48E credit using the
guidance and procedures provided in
these final regulations.
C. Impact of the Rules
The final regulations will allow
taxpayers to plan investments and
transactions based on the ability to
claim the section 45Y production credit
and/or the section 48E investment
credit. The increased use of these
credits will incentivize increased
production and use of clean energy as
well as the development of new
methods and technologies for generating
clean energy. The use of the credits will
also incentivize additional investment
in the facilities that produce and
develop clean energy.
Because recordkeeping and reporting
requirements relating to the section 45Y
and 48E credits will not materially
differ from the requirements relating to
existing energy production and
investment tax credits, the
recordkeeping and reporting
requirements should not materially
increase for taxpayers that already claim
existing credits. To claim the section
45Y credit or the section 48E credit,
taxpayers will need to continue to
execute the relevant form (or successor
form, or pursuant to instructions and
other guidance) and file such form with
the taxpayer’s timely filed return
(including extensions) for the taxable
year in which the property is placed in
service.
Although the Treasury Department
and the IRS do not have sufficient data
to precisely determine the likely extent
of the increased costs of compliance, the
estimated burden of complying with the
recordkeeping and reporting
requirements are described in the
Paperwork Reduction Act section of this
preamble.
D. Alternatives Considered
The Treasury Department and the IRS
considered alternatives to the final
regulations. For example, the Treasury
Department and the IRS considered
whether to impose different rules for
determining if a section 48E qualified
facility had a recapture event, and how
and when a taxpayer was required to
notify the Secretary that the emissions
rate at a qualified facility was greater
than 10 grams of CO2e per kWh. The
final regulations were designed to

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minimize burdens on taxpayers while
ensuring that the IRS has sufficient
information to determine if a section
48E qualified facility’s emissions rate
exceeded the recapture threshold. The
final regulations require that a taxpayer
that claimed the section 48E credit to
annually report to the IRS its GHG
emissions rate in the form and manner
prescribed in IRS forms or instructions
or in guidance as published in the
Internal Revenue Bulletin.
An additional example is that the
Treasury Department and the IRS
considered alternatives to how a
taxpayer should compute any increase
in capacity at a qualified facility that,
for purposes of sections 45Y and 48E,
was a qualified facility due to an
increase in capacity. The final
regulations were designed to provide a
rule that was administrable for the IRS
and taxpayers. The final regulations
offer taxpayers the following options for
measuring capacity increases: use of
capacity measures from modified or
amended facility operating licenses
from FERC or NRC, or related reports
prepared by FERC or NRC as part of the
licensing process; measurement of
nameplate capacity of the facility
consistent with the definition of
nameplate capacity provided in 40 CFR
96.202; or a measurement standard
prescribed by the Secretary in guidance
published in the Internal Revenue
Bulletin.
E. Duplicative, Overlapping, or
Conflicting Federal Rules
The final rules would not duplicate,
overlap, or conflict with any relevant
Federal rules. As discussed earlier, the
regulations provide guidance relating to
the section 45Y tax credit and the
section 48E tax credit. The Treasury
Department and the IRS invited input
from interested members of the public
about identifying and avoiding
overlapping, duplicative, or conflicting
requirements.
IV. 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).
V. Immediate Effective Date
These final regulations have an
effective date of January 15, 2025. To
the extent that a good cause statement
is necessary under any provision of law,
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.

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Federal Register / Vol. 90, No. 9 / Wednesday, January 15, 2025 / Rules and Regulations
The IRA added the section 45Y and
48E credits to the Code, and provided
that the section 45Y credit applies to
facilities placed in service after
December 31, 2024, and that the section
48E credit applies to property placed in
service after December 31, 2024.
Following the enactment of the IRA
and the addition of sections 45Y and
48E to the Code, the Treasury
Department and the IRS published
proposed regulations to provide
certainty to taxpayers. In particular, as
demonstrated by the wide variety of
public comments in response to the
proposed regulations, taxpayers and
other stakeholders continue to express
uncertainty regarding the proper
application of the statutory rules under
sections 45Y and 48E, and the need for
timely final regulations, because the
credits apply to facilities and property
placed in service after December 31,
2024. Taxpayers have requested the
certainty that these final regulations
provide prior to making investment
decisions that will affect such facilities
and property. In addition, this
uncertainty extends to the application of
a number of important provisions in
sections 45Y and 48E that require
determinations to be made by the
Secretary, in consultation with other
Federal agency experts, that are
intended to provide certainty for
taxpayers embarking on highly capital
intensive projects intended to qualify
for the section 45Y and 48E credits.
Certainty with respect to these
provisions is essential given the January
1, 2025 statutory effective date, and so
that taxpayers can accurately predict the
economic return from making particular
investments and make informed
business decisions. In addition, while
taxpayers have requested clarity
regarding the specific requirements of
these rules, the public already has been
provided notice of the general contents
of these rules and their proposed
applicability to qualified facilities and
energy storage technologies placed in
service after December 31, 2024, and
during taxable years ending on or after
the date of publication of these final
regulations. As provided in the IRA,
sections 45Y and 48E replace existing
production and investment tax credits
for facilities placed in service after
December 31, 2024. The statute and
proposed rules, therefore, provide
notice that the rules will apply to
qualified facilities and energy storage
technologies placed in service beginning
in 2025, and provide notice of the
qualification requirements being
promulgated in this final rule.
Moreover, section 45Y(f) directs the

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Secretary to issue guidance regarding
the implementation of section 45Y not
later than January 1, 2025. Section
48E(i) similarly directs the Secretary to
issue guidance regarding
implementation of section 48E not later
than January 1, 2025.
Consistent with Executive Order
14008 (January 27, 2021) and
commenters’ request for finalized rules,
the Treasury Department and the IRS
have determined that an effective date
of the final regulations as soon in time
after the 45Y and 48E credits go into
effect on January 1, 2025 as possible is
appropriate to provide certainty to
taxpayers seeking to place facilities and
property in service after December 31,
2024, in order to claim the section 45Y
and 48E credits. The final regulations
provide needed rules on what the law
requires for taxpayers to claim these
credits. Accordingly, to the extent that
a finding of good cause is necessary, the
Treasury Department and the IRS have
found good cause for the rules in this
Treasury decision to take effect on
January 15, 2025.
VI. Unfunded Mandates Reform Act
Section 202 of the Unfunded
Mandates Reform Act of 1995 (UMRA)
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 Indian Tribal
government, in the aggregate, or by the
private sector, of $100 million (updated
annually for inflation). This final rule
does not include any Federal mandate
that may result in expenditures by State,
local, or Indian Tribal governments, or
by the private sector in excess of that
threshold.
VII. 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. This final rule does not
have federalism implications and does
not impose substantial direct
compliance costs on State and local
governments or preempt State law
within the meaning of the Executive
order.

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VIII. 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.
Statement of Availability of IRS
Documents
Guidance cited in this preamble is
published in the Internal Revenue
Bulletin and is available from the
Superintendent of Documents, U.S.
Government Publishing Office,
Washington, DC 20402, or by visiting
the IRS website at https://www.irs.gov.
Drafting Information
The principal authors of these final
regulations are Maksim Berger, John M.
Deininger, Martha M. Garcia, Boris
Kukso, Nathaniel Kupferman, and
Alexander Scott (Passthroughs and
Special Industries). Other personnel
from the Treasury Department, the DOE,
the EPA, the USDA, and the IRS
participated in the development of the
final regulations.
List of Subjects in 26 CFR Part 1
Income taxes, Reporting and
recordkeeping requirements.
Adoption of 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:
■ a. Adding entries in numerical order
for §§ 1.45Y–1 and 1.45Y–2;
■ b. Revising the entry for § 1.45Y–3;
and
■ c. Adding entries in numerical order
for §§ 1.45Y–4 and 1.45Y–5 and 1.48E–
1 through 1.48E–5.
The revision and additions read in
part as follows:
■

Authority: 26 U.S.C. 7805 * * *

*

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Section 1.45Y–1 also issued under 26
U.S.C. 45Y(f).
Section 1.45Y–2 also issued under 26
U.S.C. 45Y(f).
Section 1.45Y–3 also issued under 26
U.S.C. 45Y(f).
Section 1.45Y–4 also issued under 26
U.S.C. 45Y(f).
Section 1.45Y–5 also issued under 26
U.S.C. 45Y(b) and (f).

*

*

*

*

*

Section 1.48E–1 also issued under 26
U.S.C. 48E(i).
Section 1.48E–2 also issued under 26
U.S.C. 48E(i).
Section 1.48E–3 also issued under 26
U.S.C. 48E(i).
Section 1.48E–4 also issued under 26
U.S.C. 48E(i).
Section 1.48E–5 also issued under 26
U.S.C. 48E(i).

*

*
*
*
*
Par. 2. Add an undesignated center
heading immediately following § 1.37–3
to read as follows:

■

General Business Credits
*

*
*
*
*
Par. 3. Sections 1.45Y–0 through
1.45Y–2 are added to read as follows:

■

Sec.

*

*

*

*

*

1.45Y–0 Table of contents.
1.45Y–1 Clean electricity production credit.
1.45Y–2 Qualified facility for purposes of
section 45Y.

*

*

§ 1.45Y–0

*

*

*

Table of contents.

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This section lists the captions
contained in §§ 1.45Y–1 through 1.45Y–
5.
§ 1.45Y–1 Clean electricity production
credit.
(a) Overview.
(1) In general.
(2) CHP property.
(i) In general.
(ii) Components excluded.
(3) Code.
(4) kWh.
(5) Metering device.
(i) In general.
(ii) Standards for maintaining and
operating a metering device.
(iii) Network equipment.
(iv) Examples.
(6) Qualified facility.
(7) Related person.
(i) In general.
(ii) Member of a consolidated group.
(8) Secretary.
(9) Section 45Y credit.
(10) Section 45Y regulations.
(11) Unrelated person.
(12) Waste energy recovery property
(WERP).
(b) Credit amount.
(1) In general.
(2) Applicable amount.
(i) In general.
(ii) Base amount.
(iii) Alternative amount.

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(3) Inflation adjustment.
(i) In general.
(ii) Annual computation.
(iii) Inflation adjustment factor.
(iv) GDP implicit price deflator.
(4) Energy communities increase in credit.
(5) Domestic content bonus credit amount.
(c) Credit phase-out.
(1) In general.
(2) Phase-out percentage.
(3) Applicable year.
(4) Phase-out data.
(5) Determination of phase-out.
(d) Requirements for CHP property.
(1) In general.
(2) Energy efficiency percentage.
(3) Special rule for calculating electricity
produced by CHP property.
(i) In general.
(ii) Conversion from Btu to kWh.
(e) Applicability date.
§ 1.45Y–2 Qualified facility for purposes of
section 45Y.
(a) Qualified facility.
(b) Property included in qualified facility.
(1) In general.
(2) Unit of qualified facility.
(i) In general.
(ii) Functionally interdependent.
(3) Integral part.
(i) In general.
(ii) Power conditioning and transfer
equipment.
(iii) Roads.
(iv) Fences.
(v) Buildings.
(vi) Shared integral property.
(vii) Examples.
(c) Coordination with other credits.
(1) In general.
(2) Allowed.
(3) Examples.
(d) Applicability date.
§ 1.45Y–3 Rules relating to the increased
credit amount for prevailing wage and
apprenticeship.
(a) In general.
(b) Qualified facility requirements.
(c) Nameplate capacity for purposes of the
One Megawatt Exception.
(1) In general.
(2) Nameplate capacity for qualified
facilities that generate in direct current for
purposes of the One Megawatt Exception.
(3) Integrated operations.
(4) Related taxpayers.
(i) Definition.
(ii) Related taxpayer rule.
(d) Applicability date.
§ 1.45Y–4 Rules of general application.
(a) Only production in the United States
taken into account for purposes of section
45Y.
(b) Production attributable to the taxpayer.
(1) In general.
(2) Example of gross sales.
(3) Section 761(a) election.
(c) Expansion of facility; Incremental
production (Incremental Production Rule).
(1) In general.
(2) Measurement standard.
(3) Special rule for restarted facilities.
(4) Computation of increased amount of
electricity produced.
(5) Examples.

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(d) Retrofit of an existing facility (80/20
Rule).
(1) In general.
(2) Cost of new components of property.
(3) Examples.
(e) Applicability date.
§ 1.45Y–5 Greenhouse gas emissions rates
for qualified facilities under section 45Y.
(a) In general.
(b) Definitions.
(1) CO2e per kWh.
(2) Combustion.
(3) Gasification.
(4) Facility that produces electricity
through combustion or gasification (C&G
Facility).
(5) Greenhouse gas emissions rate.
(6) Greenhouse gases emitted into the
atmosphere by a facility in the production of
electricity.
(7) Non-C&G Facility.
(8) Fuel.
(9) Feedstock.
(10) Market-mediated effects.
(c) Non-C&G Facilities.
(1) Determining a greenhouse gas
emissions rate for Non-C&G Facilities.
(i) Excluded emissions.
(ii) Emissions assessment process.
(iii) Example of greenhouse gas emissions
rate determination for a Non-C&G Facility.
(2) Non-C&G Facilities with a greenhouse
gas emissions rate that is not greater than
zero.
(d) C&G Facilities.
(1) Determining a greenhouse gas
emissions rate for C&G Facilities.
(2) LCA requirements.
(i) Starting boundary.
(ii) Ending boundary.
(iii) Baseline.
(iv) Offsets and offsetting activities.
(v) Principles for included emissions.
(vi) Principles for excluded emissions.
(vii) Alternative fates and avoided
emissions.
(viii) Temporal scales.
(ix) Spatial scales.
(x) Categorization of products.
(e) Use of methane from certain sources to
produce electricity.
(1) In general.
(2) Definitions.
(i) Biogas.
(ii) Coal mine methane.
(iii) Fugitive methane.
(iv) Renewable natural gas.
(3) Considerations regarding the lifecycle
greenhouse gas emissions associated with the
production of electricity using methane from
certain sources.
(i) In general.
(ii) Methane from landfill sources.
(iii) Methane from wastewater sources.
(iv) Coal mine methane.
(v) Methane from animal waste.
(vi) Fugitive methane other than coal mine
methane.
(4) Book and claim.
(f) Carbon capture and sequestration.
(1) In general.
(2) Substantiation.
(g) Annual publication of emissions rates.
(1) In general.
(2) Publication of analysis required for
changes to the Annual Table.

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(h) Provisional emissions rates.
(1) In general.
(2) Rate not established.
(3) Process for filing a PER petition.
(4) PER determination.
(5) Emissions value request process.
(6) LCA model for determining an
emissions value for C&G Facilities.
(7) Effect of PER.
(i) Reliance on Annual Table or Provisional
Emissions Rate.
(j) Substantiation.
(1) In general.
(2) Sufficient substantiation.
(k) Applicability date.

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§ 1.45Y–1
credit.

Clean electricity production

(a) Overview—(1) In general. For
purposes of section 38 of the Internal
Revenue Code (Code), the section 45Y
credit (defined in paragraph (a)(9) of
this section) is determined under
section 45Y of the Code and the section
45Y regulations (defined in paragraph
(a)(10) of this section). This paragraph
(a) provides definitions of terms that,
unless otherwise specified, apply for
purposes of section 45Y, the section 45Y
regulations, and any provision of the
Code or this chapter that expressly
refers to any provision of section 45Y or
the section 45Y regulations. Paragraph
(b) of this section provides rules for
determining the amount of the section
45Y credit for any taxable year.
Paragraph (c) of this section provides
rules regarding the phase-out of the
section 45Y credit. Paragraph (d) of this
section provides rules regarding
combined heat and power system (CHP)
property. See § 1.45Y–2 for rules
relating to qualified facilities for
purposes of the section 45Y credit. See
§ 1.45Y–4 for rules of general
application for the section 45Y credit.
See § 1.45Y–5 for rules to determine
greenhouse gas emissions rates for
qualified facilities.
(2) CHP property—(i) In general. For
purposes of section 45Y(g)(2)(B) and
paragraph (d) of this section, the term
CHP property means property
comprising a system that uses the same
energy source for the simultaneous or
sequential generation of electrical
power, mechanical shaft power, or both,
in combination with the generation of
steam or other forms of useful thermal
energy (including for heating and
cooling applications).
(ii) Components excluded. CHP
property does not include property used
to transport the energy source to the
generating facility or to distribute
energy produced by the facility.
(3) Code. The term Code means the
Internal Revenue Code.
(4) kWh. The term kWh means
kilowatt hours.

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(5) Metering device—(i) In general.
For purposes of section
45Y(a)(1)(A)(ii)(II), the term metering
device means equipment that is owned
and operated by an unrelated person (as
defined in paragraph (a)(11) of this
section) for energy revenue metering to
measure and register the continuous
summation of an electricity quantity
with respect to time.
(ii) Standards for maintaining and
operating a metering device. For
purposes of section 45Y(a)(1)(A)(ii)(II)
and this section, a metering device
must—
(A) Be maintained in proper working
order in accordance with the
instructions of its manufacturer;
(B) Be certified as meeting generally
accepted industry performance
standards, such as the American
National Standards Institute C12.1–2022
standard, or subsequent revisions;
(C) Be revenue grade with a +/¥0.5
percent accuracy; and
(D) Be properly calibrated.
(iii) Network equipment. For purposes
of operating the metering device, the
unrelated person may share network
equipment, such as spare fiber optic
cable owned by the taxpayer that
produces the electricity, and may colocate network equipment in the
taxpayer’s facilities.
(iv) Examples. This paragraph
(a)(5)(iv) provides examples illustrating
the application of paragraph (a)(5) of
this section.
(A) Example 1. Qualified facility
equipped with a metering device owned
and operated by an unrelated person. X
owns a qualified facility equipped with
a metering device that is owned and
operated by Y, an unrelated person. The
metering device meets the requirements
of paragraphs (a)(5)(i) through (iii) of
this section. X sells electricity produced
at the qualified facility to Z, a related
person during the taxable year. Because
the qualified facility is equipped with a
metering device that is owned and
operated by an unrelated person and
meets the requirements of paragraphs
(a)(5)(i) through (iii), X may claim a
section 45Y credit based on the
electricity produced by X and sold to Z
during the taxable year.
(B) Example 2. Electricity produced by
the taxpayer at a qualified facility sold,
consumed, or stored by the taxpayer
during the taxable year. X owns a
qualified facility equipped with a
metering device that is owned and
operated by an unrelated person, Y. The
metering device meets the requirements
of paragraphs (a)(5)(i) through (iii) of
this section. Because the qualified
facility is equipped with a metering
device that is owned and operated by an

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unrelated person and the metering
device meets the requirements of
paragraphs (a)(5)(i) through (iii), X may
sell electricity produced at the qualified
facility during the taxable year to a
related or unrelated person. X may also
consume the electricity produced at the
qualified facility during the taxable year
onsite. Additionally, X may store the
electricity produced at the qualified
facility during the taxable year in energy
storage technology owned by X. In any
of these three situations, X may claim a
section 45Y credit for the taxable year
for the kWh of electricity produced at
the qualified facility measured by the
metering device and sold, consumed, or
stored by X during the taxable year.
(6) Qualified facility. The term
qualified facility for purposes of the
section 45Y credit has the meaning
provided in § 1.45Y–2(a).
(7) Related person—(i) In general. The
term related person means a person that
is related to another person if such
persons would be treated as a single
employer under the regulations in this
chapter under section 52(b) of the Code.
(ii) Member of a consolidated group.
In the case of a corporation that is a
member of a consolidated group (as
defined in § 1.1502–1(h)), such member
will be treated as selling electricity to an
unrelated person if such electricity is
sold to an unrelated person by another
member of such group.
(8) Secretary. The term Secretary
means the Secretary of the Treasury or
their delegate.
(9) Section 45Y credit. The term
section 45Y credit means the clean
electricity production credit determined
under section 45Y of the Code and the
section 45Y regulations.
(10) Section 45Y regulations. The
term section 45Y regulations means this
section and §§ 1.45Y–2 through 1.45Y–
5.
(11) Unrelated person. For purposes
of section 45Y(a), the term unrelated
person means a person who is not a
related person as defined in section
45Y(g)(4) and paragraph (a)(7) of this
section. In the case of sales of electricity
to an individual consumer, such sales
will be treated as sales to an unrelated
party for purposes of the section 45Y
credit. For example, assume Taxpayer X
produces electricity at a qualified
facility and sells it to Consumer Y.
Consumer Y is an individual consumer
and is not subject to aggregation under
the regulations at 26 CFR 1.52–1
prescribed under section 52(b).
Therefore, Consumer Y is not treated as
a single employer with Taxpayer X
under section 52(b), and a sale to
Consumer Y is treated as a sale to an
unrelated person. The result is the same

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if Consumer Y is an individual
consumer who is a member of a
cooperative or Indian tribe that owns or
controls, directly or indirectly, Taxpayer
X. The result is also the same if
Consumer Y is an individual consumer
who is a resident of a State or
municipality that owns or controls,
directly or indirectly, Taxpayer X.
(12) Waste energy recovery property
(WERP). WERP is property that
generates electricity solely from heat
from buildings or equipment if the
primary purpose of such building or
equipment is not the generation of
electricity. Examples of buildings or
equipment the primary purpose of
which is not the generation of electricity
include, but are not limited to,
manufacturing plants, medical care
facilities, facilities on school campuses,
and associated equipment.
(b) Credit amount—(1) In general. The
section 45Y credit for any taxable year
is an amount equal to the product of the
kWh of electricity that is produced at a
qualified facility and sold by the
taxpayer to an unrelated person during
the taxable year, multiplied by the
applicable amount with respect to such
qualified facility. In the case of a
qualified facility equipped with a
metering device (as defined in
paragraph (a)(5) of this section) that is
owned and operated by an unrelated
person, the section 45Y credit for any
taxable year is an amount equal to the
product of the kWh of electricity that is
produced, as measured by the metering
device, at such qualified facility and
sold, consumed, or stored by the
taxpayer during the taxable year,
multiplied by the applicable amount
with respect to such qualified facility.
Only one section 45Y credit can be
claimed for each kWh of electricity
produced by the taxpayer at a qualified
facility. The credit amount may also be
increased as provided in section
45Y(g)(11) and paragraph (b)(5) of this
section in the case of a qualified facility
that satisfies the domestic content
requirements of section 45Y(g)(11)(B).
(2) Applicable amount—(i) In general.
The term applicable amount means the
base amount described in paragraph
(b)(2)(ii) of this section or the alternative
amount described in paragraph
(b)(2)(iii) of this section. The applicable
amount is subject to the inflation
adjustment as provided in section
45Y(c)(1) and paragraph (b)(3) of this
section. The applicable amount may
also be increased as provided in section
45Y(g)(7) and paragraph (b)(4) of this
section in the case of a qualified facility
that is located in an energy community.
(ii) Base amount. Under section
45Y(a)(2)(A), in the case of any qualified

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facility that does not satisfy the
requirements provided in section
45Y(a)(2)(B), the applicable amount is
the base amount, which is 0.3 cents.
(iii) Alternative amount. Under
section 45Y(a)(2)(B), in the case of any
qualified facility that satisfies the
prevailing wage and apprenticeship
requirements provided in section
45Y(a)(2)(B), the applicable amount is
the alternative amount, which is 1.5
cents.
(3) Inflation adjustment—(i) In
general. Pursuant to section 45Y(c)(1),
in the case of a calendar year beginning
after 2024, the base amount and the
alternative amount will each be adjusted
by multiplying such amount by the
inflation adjustment factor for the
calendar year in which the sale,
consumption, or storage of the
electricity occurs. If the base amount as
adjusted under this paragraph (b)(3)(i) is
not a multiple of 0.05 cent, such amount
will be rounded to the nearest multiple
of 0.05 cent. If the alternative amount as
adjusted under this paragraph (b)(3)(i) is
not a multiple of 0.1 cent, such amount
will be rounded to the nearest multiple
of 0.1 cent.
(ii) Annual computation. Pursuant to
section 45Y(c)(2), the inflation
adjustment factor for each calendar year
will be published in the Federal
Register not later than April 1 of that
calendar year. The base amount and the
alternative amount, as adjusted under
paragraph (b)(3)(i) of this section, will
also be published in the Federal
Register not later than April 1 of each
calendar year.
(iii) Inflation adjustment factor.
Under section 45Y(c)(3), the term
inflation adjustment factor means, with
respect to a calendar year, a fraction—
(A) The numerator of which is the
GDP implicit price deflator for the
preceding calendar year; and
(B) The denominator of which is the
GDP implicit price deflator for the
calendar year 1992.
(iv) GDP implicit price deflator. Under
section 45Y(c)(3), the term GDP implicit
price deflator means the most recent
revision of the implicit price deflator for
the gross domestic product as computed
and published by the Department of
Commerce before March 15 of the
calendar year.
(4) Energy communities increase in
credit. In the case of any qualified
facility that is located in an energy
community (as defined in section
45(b)(11)(B)), for purposes of
determining the amount of the section
45Y credit with respect to any
electricity produced by the taxpayer at
such facility during the taxable year, the
applicable amount will be increased by

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an amount equal to 10 percent of the
applicable amount that would otherwise
be in effect before application of this
paragraph (b)(4). The 10 percent
increase under this paragraph (b)(4)
applies after the inflation adjustment
under paragraph (b)(3) of this section.
(5) Domestic content bonus credit
amount. In the case of any qualified
facility that satisfies the requirements of
section 45Y(g)(11)(B)(i) (domestic
content requirement), for purposes of
determining the amount of the section
45Y credit with respect to any
electricity produced by the taxpayer at
such facility during the taxable year, the
amount of the credit otherwise
determined under this paragraph (b),
without application of paragraph (b)(4)
of this section (related to energy
communities), is increased by 10
percent.
(c) Credit phase-out—(1) In general.
The amount of the section 45Y credit for
any qualified facility, the construction
of which begins during a calendar year
provided in section 45Y(d)(2) and
described in paragraph (c)(2) of this
section, is equal to the product of—
(i) The amount of the credit
determined under section 45Y(a) and
described in paragraph (b) of this
section, without regard to section
45Y(d) and this paragraph (c);
multiplied by
(ii) The phase-out percentage
provided under section 45Y(d)(2) and
described in paragraph (c)(2) of this
section.
(2) Phase-out percentage. The phaseout percentage described in this
paragraph (c)(2) is equal to—
(i) For a facility the construction of
which begins during the first calendar
year following the applicable year, 100
percent;
(ii) For a facility the construction of
which begins during the second
calendar year following the applicable
year, 75 percent;
(iii) For a facility the construction of
which begins during the third calendar
year following the applicable year, 50
percent; and
(iv) For a facility the construction of
which begins during any calendar year
subsequent to the calendar year
described in paragraph (c)(2)(iii) of this
section, 0 percent.
(3) Applicable year. For purposes of
this paragraph (c), the term applicable
year means the later of—
(i) The calendar year in which the
Secretary makes the determination that
the annual greenhouse gas emissions
from the production of electricity in the
United States are equal to or less than
25 percent of the annual greenhouse gas
emissions from the production of

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electricity in the United States for
calendar year 2022; or
(ii) 2032.
(4) Phase-out data. For purposes of
paragraph (c)(3)(i) of this section, the
annual greenhouse gas emissions from
the production of electricity in the
United States for any calendar year must
be assessed separately using both of the
data sources described in paragraphs
(c)(4)(i) and (ii) of this section:
(i) The U.S. Energy Information
Administration’s Electric Power
Annual, summing the annual carbon
dioxide emissions data from
conventional power plants and
combined heat and power plants and
the Monthly Energy Review annual
carbon dioxide emissions from the
combustion of biomass to produce
electricity in the Electric Power Sector;
and
(ii) The U.S. Environmental
Protection Agency (EPA) Inventory of
U.S. Greenhouse Gas Emissions and
Sinks (GHGI) annual electric powerrelated carbon dioxide, methane, and
nitrous oxide emissions data including
carbon dioxide emissions from the
combustion of biomass to produce
electricity.
(5) Determination of phase-out. For
purposes of paragraph (c)(3)(i) of this
section, the Secretary will determine
that the annual greenhouse gas
emissions from the production of
electricity in the United States are equal
to or less than 25 percent of the annual
greenhouse gas emissions from the
production of electricity in the United
States for calendar year 2022 only if the
annual greenhouse gas emissions from
the production of electricity in the
United States, as determined separately
under both of the data sources described
in paragraph (c)(4) of this section, are
each equal to or less than 25 percent of
the annual greenhouse gas emissions
from the production of electricity in the
United States for calendar year 2022. If
a data source described in paragraph
(c)(4) of this section becomes
unavailable (for example, it is no longer
published or does not provide the
specified data), the Secretary must
designate a similar data source to
replace the unavailable data source.
(d) Requirements for CHP property—
(1) In general. To be eligible for the
section 45Y credit, a CHP property must
produce at least 20 percent of its total
useful energy in the form of useful
thermal energy that is not used to
produce electrical or mechanical power
(or combination thereof), and at least 20
percent of its total useful energy in the
form of electrical or mechanical power
(or combination thereof). The energy
efficiency percentage of CHP property

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must exceed 60 percent. These
percentages are determined on a British
thermal unit (Btu) basis.
(2) Energy efficiency percentage. The
energy efficiency percentage of a CHP
property is the fraction the numerator of
which is the total useful electrical,
thermal, and mechanical power
produced by the system at normal
operating rates, and expected to be
consumed in its normal application, and
the denominator of which is the lower
heating value of the fuel sources for the
system. In the case of a qualified facility
using nuclear energy, which does not
involve combustion, the denominator is
the reactor’s maximum power level in
megawatts thermal listed on the Nuclear
Regulatory Commission (NRC) operating
license, converted to Btus using
3,412,140 Btus per hour per megawatt.
For other qualified facilities not using
combustion, additional methodologies
may be prescribed by the Secretary in
guidance published in the Internal
Revenue Bulletin (see § 601.601 of this
chapter).
(3) Special rule for calculating
electricity produced by CHP property—
(i) In general. For purposes of section
45Y(a) and paragraph (b) of this section,
the kWh of electricity produced by a
taxpayer at a qualified facility includes
any production in the form of useful
thermal energy by any CHP property
within such facility, and the amount of
greenhouse gases emitted into the
atmosphere by such facility in the
production of such useful thermal
energy is included for purposes of
determining the greenhouse gas
emissions rate for such facility.
(ii) Conversion from Btu to kWh—(A)
In general. For purposes of section
45Y(g)(2)(A)(i) and this paragraph (d)(3),
the amount of kWh of electricity
produced in the form of useful thermal
energy is equal to the quotient of the
total useful thermal energy produced by
the CHP property within the qualified
facility, divided by the heat rate for such
facility.
(B) Heat rate. For purposes of this
paragraph (d)(3), the term heat rate
means the amount of energy used by the
qualified facility to generate 1 kWh of
electricity, expressed as Btus per net
kWh generated. In calculating the heat
rate of a qualified facility that includes
CHP property that uses combustion, a
taxpayer must use the annual average
heat rate, defined as the total annual
fuel consumption of the CHP property
(in Btus, using the lower heating value
of the fuel) during the taxable year for
which the section 45Y credit is claimed,
divided by the annual net electricity
generation (in kWh) of the CHP property
during such taxable year. In the case of

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a qualified facility using nuclear energy,
which does not involve combustion, the
facility’s reactor’s total annual thermal
output (in Btus, using a conversion rate
of 3,412,140 Btus per megawatt hour
thermal) shall be used in place of the
total annual fuel consumption of the
CHP property. For other qualified
facilities not using combustion,
additional methodologies may be
prescribed by the Secretary in guidance
published in the Internal Revenue
Bulletin (see § 601.601 of this chapter).
(e) Applicability date. This section
applies to qualified facilities placed in
service after December 31, 2024, and
during a taxable year ending on or after
January 15, 2025.
§ 1.45Y–2 Qualified facility for purposes of
section 45Y.

(a) Qualified facility. For purposes of
the section 45Y credit (defined in
§ 1.45Y–1(a)(9)), the term qualified
facility means a facility owned by the
taxpayer that meets the requirements of
paragraphs (a)(1) through (3) of this
section:
(1) The facility is used for the
generation of electricity, meaning that it
is a net generator of electricity taking
into account any electricity consumed
by the facility;
(2) The facility is placed in service
after December 31, 2024; and
(3) The facility has a greenhouse gas
emissions rate of not greater than zero
(as determined under rules provided in
§ 1.45Y–5).
(b) Property included in qualified
facility—(1) In general. A qualified
facility includes a unit of qualified
facility (as defined in paragraph (b)(2) of
this section) that meets the requirements
of paragraph (b)(2). A qualified facility
also includes property owned by the
taxpayer that is an integral part (as
defined in paragraph (b)(3) of this
section) of the qualified facility. Any
component of property that meets the
requirements of this paragraph (b) is
part of a qualified facility regardless of
where such component of property is
located. A qualified facility generally
does not include equipment that is an
addition or modification to an existing
qualified facility. However, see § 1.45Y–
4(c) for rules regarding the Incremental
Production Rule and § 1.45Y–4(d) for
rules regarding a retrofitted qualified
facility (80/20 Rule).
(2) Unit of qualified facility—(i) In
general. For purposes of the section 45Y
credit, the unit of qualified facility
includes all functionally interdependent
components of property (as defined in
paragraph (b)(2)(ii) of this section)
owned by the taxpayer that are operated
together and that can operate apart from

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other property to produce electricity, or,
in the case of CHP property, useful
thermal energy and electricity. No
provision of this section, § 1.45Y–1, or
§§ 1.45Y–3 through 1.45Y–5 uses the
term unit in respect of a qualified
facility with any meaning other than
that provided in this paragraph (b)(2)(i).
(ii) Functionally interdependent.
Components of property are
functionally interdependent if the
placing in service of each of the
components is dependent upon the
placing in service of each of the other
components to produce electricity.
(3) Integral part—(i) In general. For
purposes of thesection 45Ycredit, a
component of property owned by a
taxpayer is an integral part of a qualified
facility if it is used directly in the
intended function of the qualified
facility and is essential to the
completeness of such function. Property
that is an integral part of a qualified
facility is part of the qualified facility.
(ii) Power conditioning and transfer
equipment. Power conditioning
equipment and transfer equipment are
integral parts of a qualified facility.
Power conditioning equipment
includes, but is not limited to,
transformers, inverters, and converters,
which modify the characteristics of
electricity or thermal energy into a form
suitable for use, transmission, or
distribution. Parts related to the
functioning or protection of power
conditioning equipment are also treated
as power conditioning equipment and
include, but are not limited to, switches,
circuit breakers, arrestors, and hardware
used to monitor, operate, and protect
power conditioning equipment. Transfer
equipment includes components of
property that allow for the aggregation
of electricity generated by a qualified
facility and components of property that
alter voltage to permit electricity to be
transferred to a transmission or
distribution line. Transfer equipment
does not include transmission or
distribution lines. Examples of transfer
equipment include, but are not limited
to, wires, cables, and combiner boxes
that conduct electricity. Parts related to
the functioning or protection of transfer
equipment are also treated as transfer
equipment and may include items such
as current transformers used for
metering, electrical interrupters (such as
circuit breakers, fuses, and other
switches), and hardware used to
monitor, operate, and protect transfer
equipment.
(iii) Roads. Roads that are integral to
the intended function of the qualified
facility such as onsite roads that are
used to operate and maintain the
qualified facility are integral parts of a

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qualified facility. Roads used primarily
for access to the site, or roads used
primarily for employee or visitor
vehicles, are not integral to the intended
function of the qualified facility and
thus are not an integral part of a
qualified facility.
(iv)Fences. Fencing is not an integral
part of a qualified facility because it is
not integral to the intended function of
the qualified facility.
(v) Buildings. Generally, buildings are
not integral parts of a qualified facility
because they are not integral to the
intended function of the qualified
facility. However, the structures
described in paragraphs (b)(3)(v)(A) and
(B) of this section are not treated as
buildings for this purpose and are an
integral part of a qualified facility:
(A) A structure that is essentially an
item of machinery or equipment; and
(B) A structure that houses
components of property that are integral
to the intended function of a qualified
facility if the use of the structure is so
closely related to the use of the
components of property housed therein
that the structure clearly can be
expected to be replaced if the
components of property it initially
houses are replaced.
(vi) Shared integral property. Multiple
qualified facilities (whether owned by
one or more taxpayers), including
qualified facilities with respect to which
a taxpayer has claimed a credit under
section 48E or another Federal income
tax credit, may include shared property
that may be considered an integral part
of each qualified facility. In addition, a
component of property that is shared by
a qualified facility as defined in section
45Y(b) (45Y Qualified Facility) and a
qualified facility as defined by section
48E(b)(3) (48E Qualified Facility) that is
an integral part of both qualified
facilities will not affect the eligibility of
the 45Y Qualified Facility for the
section 45Y credit or the 48E Qualified
Facility for the section 48E credit
(defined in § 1.48E–1(a)(10)).
(vii) Examples. This paragraph
(b)(3)(vii) provides examples illustrating
the rules of paragraphs (b)(3)(i) through
(vi) of this section.
(A) Example 1. Co-located qualified
facilities owned by the same taxpayer
that share integral property. X
constructs and owns a solar facility
(Solar Facility) and nearby also
constructs and owns a wind facility
(Wind Facility) that are each a qualified
facility. The Solar Facility and Wind
Facility each connect to a shared
transformer that steps up the electricity
produced by each qualified facility to
electrical grid voltage before it is
transmitted to the electrical grid through

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an intertie. The fact that the Solar
Facility and Wind Facility share
property that is integral to both does not
impact the ability of X to claim a section
45Y credit for both qualified facilities.
(B) Example 2. Co-located qualified
facilities owned by different taxpayers
that share integral property. X
constructs and owns a solar facility
(Solar Facility), and nearby Y constructs
and owns a wind facility (Wind Facility)
that are each a qualified facility. X’s
Solar Facility and Y’s Wind Facility
each connect to a shared transformer
that steps up the electricity produced by
both qualified facilities to electrical grid
voltage before it is transmitted to the
electrical grid through an intertie. The
fact that the Solar Facility and Wind
Facility share property that is integral to
both does not impact the ability of X or
Y to claim a section 45Y credit for the
electricity produced by their respective
qualified facilities.
(C) Example 3. Co-located qualified
facility and Energy Storage Technology
(EST) owned by the same taxpayer that
share integral property. X constructs
and owns a wind facility that is a
qualified facility (Wind Facility) that is
co-located with an EST (as defined in
§ 1.48E–2(g)) that X also constructed
and owns. The Wind Facility and EST
share transfer equipment that is integral
to both. The fact that the Wind Facility
and EST share property that is integral
to both does not impact the ability of X
to claim a section 45Y credit for the
electricity produced by the Wind
Facility or to claim a section 48E credit
for the EST.
(D) Example 4. Co-located wind
qualified facility and Energy Storage
Technology owned by different
taxpayers that share integral property. X
constructs and owns a solar facility that
is a qualified facility (Solar Facility) that
is co-located with an EST (as defined in
§ 1.48E–2(g)) constructed and owned by
Y. The Wind Facility and EST share
transfer equipment that is integral to
both. The fact that the Wind Facility
and EST share property that is integral
to both does not impact the ability of X
to claim a section 45Y credit for the
electricity produced by the Wind
Facility or the ability of Y to claim a
section 48E credit for the EST.
(E) Example 5. Qualified facility with
integral property owned by a different
taxpayer. X constructs and owns a
hydropower production facility that is a
qualified facility (Hydropower Facility).
The Hydropower Facility connects to a
dam owned by Y, a government entity,
that is an integral part of the
Hydropower Facility. The fact that X
does not own the dam does not impact
the ability of X to claim a section 45Y

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credit for the production of electricity
by the Hydropower Facility.
(c) Coordination with other credits—
(1) In general. The term qualified facility
(as defined in section 45Y(b) and
paragraph (a) of this section) does not
include any facility for which a credit
determined under section 45, 45J, 45Q,
45U, 48, 48A, or 48E is allowed under
section 38 of the Code for the taxable
year or any prior taxable year. A
taxpayer that directly owns a qualified
facility (as defined in section 45Y(b))
that is eligible for both a section 45Y
credit and a credit determined under
one of section 45, 45J, 45Q, 45U, 48,
48A, or 48E is eligible for the section
45Y credit only if such other Federal
income tax credit was not allowed with
respect to the qualified facility. Nothing
in this paragraph (c) precludes a
taxpayer from claiming a section 45Y
credit with respect to a qualified facility
(as defined in section 45Y(b)) that is colocated with another facility for which
a credit determined under section 45,
45J, 45Q, 45U, 48, 48A, or 48E is
allowed under section 38 for the taxable
year or any prior taxable year.
(2) Allowed. For purposes of
paragraph (c)(1) of this section, the term
allowed only includes credits that a
taxpayer has claimed on a Federal
income tax return or Federal return, as
appropriate, and that the Internal
Revenue Service (IRS) has not
challenged in terms of the taxpayer’s
eligibility.
(3) Examples. This paragraph (c)(3)
provides examples illustrating the rules
of paragraph (c) of this section.
(i) Example 1. Taxpayer claims a
section 45Y credit on a solar farm and
section 48E credit on co-located EST. X
owns a solar farm that is a qualifying
facility (Solar Qualified Facility), and X
owns a co-located EST (as defined in
§ 1.48E–2(g)) (Energy Storage). The
Energy Storage is not part of the Solar
Qualified Facility, and, therefore, X may
claim the section 45Y credit based on
the kWh of electricity produced by the
Solar Qualified Facility, and X may also
claim the section 48E credit based on its
qualified investment in the Energy
Storage.
(ii) Example 2. Different taxpayers
claim a section 45Y credit for a solar
farm and a section 48E credit for colocated Energy Storage Technology. X
owns a solar farm that is a qualifying
facility (Solar Qualified Facility), and Y
owns a co-located EST (as defined in
§ 1.48E–2(g)) (Energy Storage). The
Energy Storage is not part of the Solar
Qualified Facility, and therefore, X may
claim the section 45Y credit based on
the kWh of electricity produced by the
Solar Qualified Facility, and Y may

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claim the section 48E credit based on its
qualified investment in the Energy
Storage.
(iii) Example 3. Taxpayer claiming
another credit is not allowed a section
45Y credit. X owns a wind facility that
satisfies the requirements of a qualified
facility as well as the requirements of a
qualified facility as defined in § 1.48E–
2(a). X claims a section 48E credit with
respect to the wind facility. While a
credit may be available with regard to
the wind facility under section 45Y,
because X has already claimed a section
48E credit with respect to the wind
facility, a section 45Y credit is not
allowed.
(iv) Example 4. Interaction of section
45Y and section 45Q credits for single
qualified facility. X owns a qualified
facility (Facility A) that includes carbon
capture equipment, which is needed for
the facility to meet the zero greenhouse
gas requirement, so it is functionally
interdependent to the production of
electricity by Facility A. X used the
carbon capture equipment to capture
and utilize (as described in section
45Q(f)(5)) qualified carbon dioxide and
claimed a section 45Q credit in a prior
taxable year. As a result, X cannot claim
a credit for its Facility A because a
qualified facility does not include a
facility for which a credit determined
under section 45Q is allowed.
(v) Example 5. Interaction of section
45Y and section 45Q credits for colocated qualified facilities. Assume the
same facts as in paragraph (c)(3)(iv) of
this section (Example 4), except that X
owns a co-located qualified facility
(Facility B) that also includes carbon
capture equipment, which is needed for
the facility to meet the zero greenhouse
gas requirement, so it is functionally
interdependent to the production of
electricity by Facility B. X used the
carbon capture equipment to capture
and utilize (as described in section
45Q(f)(5)) qualified carbon dioxide, but
has not claimed a section 45Q credit
with respect to Facility B. While X
claimed a section 45Q credit in a prior
taxable year for Facility A (see
paragraph (c)(3)(iv) of this section
(Example 4)), Facility B is not part of
Facility A, and, therefore, X may claim
the section 45Y credit for Facility B.
(d) Applicability date. This section
applies to qualified facilities placed in
service after December 31, 2024, and
during a taxable year ending on or after
January 15, 2025.
Par. 4. Section 1.45Y–3 is revised to
read as follows:

■

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§ 1.45Y–3 Rules relating to the increased
credit amount for prevailing wage and
apprenticeship.

(a) In general. If any qualified facility
satisfies the requirements in paragraph
(b) of this section, the applicable
amount used for calculating the amount
of the credit for producing clean
electricity determined under section
45Y(a) of the Internal Revenue Code is
the alternative applicable amount
described in section 45Y(a)(2)(B),
subject to adjustment provided by
section 45Y(c).
(b) Qualified facility requirements. A
qualified facility satisfies the
requirements of this paragraph (b), if it
is described in paragraph (b)(1), (2), or
(3) of this section:
(1) A qualified facility with a
maximum net output of less than one
megawatt (as measured in alternating
current) determined based on the
nameplate capacity as provided in
paragraph (c) of this section (One
Megawatt Exception);
(2) A qualified facility the
construction of which began prior to
January 29, 2023; or
(3) A qualified facility that 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 with respect
to the construction, alteration, or repair
of a qualified facility within the
meaning of section 45Y.
(c) Nameplate capacity for purposes
of the One Megawatt Exception—(1) In
general. For purposes of paragraph
(b)(1) of this section, the determination
of whether a qualified facility has a
maximum net output of less than 1
megawatt (MW) of electrical energy (as
measured in alternating current) is
determined based on the nameplate
capacity of the qualified facility. If a
qualified facility has integrated
operations with one or more other
qualified facilities, then the aggregate
nameplate capacity of the qualified
facilities is used for the purposes of
determining if the qualified facility
meets the requirements of paragraph
(b)(1) of this section. The nameplate
capacity for purposes of the One
Megawatt Exception is the maximum
electrical generating output in
megawatts that a qualified facility is
capable of producing on a steady state
basis and during continuous operation
under standard conditions, as measured
by the manufacturer and consistent with
the definition of nameplate capacity
provided in 40 CFR 96.202. If
applicable, the International Standard
Organization conditions should be used

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to measure the maximum electrical
generating output.
(2) Nameplate capacity for qualified
facilities that generate in direct current
for purposes of the One Megawatt
Exception. For qualified facilities that
generate electricity in direct current, the
taxpayer determines the maximum net
output (in alternating current) of each
qualified facility by using the lesser of:
(i) The sum of the nameplate
generating capacities within the unit of
qualified facility in direct current,
which is deemed the nameplate
generating capacity of the unit of
qualified facility in alternating current;
or
(ii) The nameplate capacity of the first
component of property that inverts the
direct current electricity into alternating
current.
(3) Integrated operations. Solely for
the purposes of the One Megawatt
Exception, a qualified facility is treated
as having integrated operations with
any other qualified facility of the same
technology type if the facilities are
owned by the same or related taxpayers,
placed in service in the same taxable
year; and transmit electricity generated
by the facilities through the same point
of interconnection or, if the facilities 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.
(4) Related taxpayers—(i) Definition.
For purposes 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)).
(ii) Related taxpayer rule. For
purposes of this section, related
taxpayers are treated as one taxpayer in
determining whether a qualified facility
has integrated operations.
(d) Applicability date—(1) In general.
Except as provided in paragraph (d)(2)
of this section, this section applies to
qualified facilities placed in service in
taxable years ending after January 15,
2025, and the construction of which
begins after January 15, 2025. Taxpayers
may apply this section to qualified
facilities placed in service in taxable
years ending on or before January 15,
2025, and qualified facilities placed in
service in taxable years ending after
January 15, 2025, the construction of
which begins before January 15, 2025,
provided that taxpayers follow this
section in its entirety and in a consistent
manner.
(2) Paragraph (b)(1) of this section.
Paragraph (b)(1) of this section applies
to qualified facilities placed in service
in taxable years ending after January 15,
2025, and the construction of which

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begins after March 17, 2025. Taxpayers
may apply this section to qualified
facilities placed in service in taxable
years ending on or before January 15,
2025, the construction of which begins
before January 15, 2025, provided that
taxpayers follow this section in its
entirety and in a consistent manner.
■ Par. 5. Sections 1.45Y–4 and 1.45Y–
5 are added to read as follows:
*
*
*
*
*
Sec.
1.45Y–4 Rules of general application.
1.45Y–5 Greenhouse gas emissions rates for
qualified facilities under section 45Y.

*

*

§ 1.45Y–4

*

*

*

Rules of general application.

(a) Only production in the United
States is taken into account for purposes
of section 45Y. Consumption, sales, or
storage are taken into account for
purposes of the section 45Y credit
(defined in § 1.45Y–2(a)) only with
respect to electricity the production of
which is within the United States
(within the meaning of section 638(1) of
the Internal Revenue Code (Code)), or a
United States territory, which for
purposes of section 45Y and the section
45Y regulations (defined in § 1.45Y–
2(a)) has the meaning of the term a
possession of the United States (within
the meaning of section 638(2)).
(b) Production attributable to the
taxpayer—(1) In general. In the case of
a qualified facility in which more than
one person has an ownership share (and
the arrangement is not treated as a
partnership for Federal tax purposes)
production from the qualified facility is
allocated among such persons in
proportion to their respective ownership
shares in the gross sales from such
qualified facility. The respective owners
each determine their respective section
45Y credit under section 45Y(a) and
based on their respective ownership
shares in the gross sales from such
qualified facility during the taxable
year.
(2) Example of gross sales. A, B and
C, all calendar year taxpayers, each own
an interest in a solar facility which is a
qualified facility (as defined in § 1.45Y–
2(a)) (Solar Facility). A owns 45 percent,
B owns 35 percent, and C owns 20
percent, and each are allocated gross
sales from the Solar Facility in
proportion to their ownership interest.
The Solar Facility produced 1000 kWh
of electricity during the taxable year. A,
B, and C will each determine their
respective section 45Y credit under
section 45Y(a) and § 1.45Y–1(b) based
on their allocable share of the gross
sales from the 1000 kWh of electricity
produced at the Solar Facility during
the taxable year.

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(3) Section 761(a) election. If a
qualified facility is owned through an
unincorporated organization that has
made a valid election under section
761(a) of the Code, each member’s
undivided ownership share in the
qualified facility will be treated as a
separate qualified facility owned by
such member.
(c) Expansion of facility; Incremental
production (Incremental Production
Rule)—(1) In general. Solely for
purposes of this paragraph (c), the term
qualified facility includes either a new
unit or an addition of capacity placed in
service after December 31, 2024, in
connection with a facility described in
section 45Y(b)(1)(A) (without regard to
section 45Y(b)(1)(A)(ii)) that was placed
in service before January 1, 2025, but
only to the extent of the increased
amount of electricity produced at the
facility by reason of such new unit or
addition of capacity. This rule is only
applicable to an addition of capacity or
new unit that would not otherwise
qualify as a separate qualified facility as
defined in section 45Y(b)(1)(A). A new
unit or an addition of capacity that
meets the requirements of this
paragraph (c) will be treated as a
separate qualified facility. For purposes
of this paragraph (c), a new unit or an
addition of capacity requires the
addition or replacement of components
of property, including any new or
replacement integral property, added to
a facility necessary to increase capacity.
For purposes of assessing the One
Megawatt Exception provided in section
45Y(a)(2)(B)(i), the maximum net output
for a new unit or an addition of capacity
is the sum of the capacity of the added
qualified facility and the capacity of the
facility to which the qualified facility
was added, as determined under
§ 1.45Y–3(c) and paragraph (c)(2) of this
section.
(2) Measurement standard. For
purposes of this paragraph (c), taxpayers
must use one of the measurement
standards described in paragraph
(c)(2)(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 (c)(2)(ii) of this
section if they are able to use the
measurement standard described in
paragraph (c)(2)(i) of this section:
(i) Modified or amended facility
operating licenses from the Federal
Energy Regulatory Commission (FERC)
or the Nuclear Regulatory Commission
(NRC), or related reports prepared by
FERC or NRC as part of the licensing
process;
(ii) Nameplate capacity certified
consistent with generally accepted

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industry standards, such as the
International Standard Organization
(ISO) conditions to measure the
nameplate capacity of the facility
consistent with the definition of
nameplate capacity provided in 40 CFR
96.202; or
(iii) A measurement standard
prescribed by the Secretary in guidance
published in the Internal Revenue
Bulletin (see § 601.601 of this chapter).
(3) Special rule for restarted facilities.
Solely for purposes of this paragraph (c),
a facility that is decommissioned or in
the process of decommissioning and
restarts can be considered to have
increased capacity from a base of zero
if the conditions described in each of
paragraphs (c)(3)(i) through (iv) of this
section 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,
FERC or NRC);
(iii) The restarted facility must be
eligible to restart based on an operating
license issued by either FERC or NRC;
and
(iv) The existing facility may not have
ceased operations for the purpose of
qualifying for the special rule for
restarted facilities in this paragraph
(c)(3).
(4) Computation of increased amount
of electricity produced. To determine
the increased amount of electricity
produced by a facility in a taxable year
by reason of a new unit or an addition
of capacity, a taxpayer must multiply
the amount of electricity that the facility
produces during that taxable year after
the new unit or addition of capacity is
placed in service by a fraction, the
numerator of which is the added
capacity that results from the new unit
or addition of capacity, and the
denominator of which is the total
capacity of the facility with the new
unit or addition of capacity added,
provided the added capacity and
resulting total capacity are measured
using a measurement standard
identified in paragraph (c)(2) of this
section.
(5) Examples. This paragraph (c)(5)
provides examples illustrating the rules
of paragraph (c) of this section.
(i) Example 1. New Unit. X owns a
hydropower facility (Facility H) that
was originally placed in service in 2020,
with a FERC license authorizing an
installed capacity of 60 megawatts.
During taxable years 2020 through 2024,
X claimed a section 45 credit for the
electricity produced by Facility H. On

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July 1, 2025, as allowed by a FERC
license amendment, X places in service
components of property comprising a
new unit that results in Facility H
having an increased authorized installed
capacity of 90 megawatts in 2025. For
purposes of paragraph (c) of this section,
this new unit will be treated as a
separate facility (Facility J). X may claim
a section 45Y credit during the 10-year
credit period starting on July 1, 2025,
based on the increased amount of
electricity generated as a result of the
new unit, which is determined by
multiplying the electricity that Facility
H produces with Facility J by one-third
(equal to the 30-megawatt increase in
capacity that results from the addition
of Facility J divided by the 90 megawatt
capacity of Facility H with Facility J).
Even though X claimed a section 45
credit for the existing capacity of
Facility H in taxable years 2020 through
2024, X can claim a section 45Y credit
for the production of electricity
associated with Facility J. X may also
continue to claim the section 45 credit
through taxable year 2030 for electricity
generated by Facility H (excluding the
incremental electricity generation
related to Facility J).
(ii) Example 2. Addition of Capacity.
Y owns a nuclear facility (Facility N)
that was originally placed in service on
January 1, 2000. Y claimed a section
45U credit in taxable years 2024 and
2025 for the electricity generated by
Facility N. On January 15, 2026, Y
completed and placed in service an
investment associated with a power
uprate approved by an NRC license
amendment that involved the removal
and replacement of components of
property and placing in service
additional components of property. NRC
reports associated with the license
amendment describe the uprate as
increasing the nuclear facility’s
electrical capacity by 100 MW to 900
MW. For purposes of this paragraph (c),
Facility N’s addition of capacity is
treated as a new separate qualified
facility placed in service on January 15,
2026 (Facility P). Y may claim a section
45Y credit during the 10-year credit
period starting on January 15, 2026,
based on the increased amount of
electricity produced at Facility N that is
attributable to the addition of capacity
(Facility P), which is determined by
multiplying the electricity that Facility
N produces with Facility P by 1⁄9 (equal
to the 100-megawatt increase in capacity
divided by Facility N’s new total
capacity of 900 megawatts with Facility
P, as described in NRC reports
associated with the license amendment).
Even though Y claimed a section 45U

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4103

credit in taxable years 2024 and 2025 for
the existing capacity of Facility N, Y can
claim a section 45Y credit for the
production of electricity associated with
Facility P. Y may also continue to claim
the section 45U credit for electricity
generated by Facility N (excluding the
incremental electricity generation
related to Facility P).
(iii) Example 3. Geothermal Turbine
and Generator Additions of Capacity. X
owns a geothermal power plant (Facility
G) with a 24 MW nameplate capacity,
which is placed in service in 2007. Over
the subsequent years, the plant’s
generating capability declines because
of physical degradation of the turbine
and generator. On March 1, 2027, X
places in service components of
property at Facility G that increase its
capacity. The turbine rotor is removed,
and the eroded blades are replaced with
new blades. The generator is refurbished
by removing old subcomponents of the
generator and replacing those with new
subcomponents, as well as replacing the
old copper windings with new windings
in concert with new insulation. After
the upgrade, the plant increases its
nameplate capacity to 26 MW, an
increase of 2 MW over the previous
nameplate capacity. For purposes of this
paragraph (c), the addition of capacity to
Facility G is treated as a new separate
qualified facility placed in service on
March 1, 2027 (Facility N). X may claim
a section 45Y credit during the 10-year
credit period starting on March 1, 2027,
based on the amount of electricity
produced by Facility N, which is
determined by multiplying the aggregate
amount of electricity that Facility G
produces with Facility N by 1/13 (that
is, the fraction equal to the 2-megawatt
increase in nameplate capacity
attributable to Facility N divided by the
new total aggregate 26 megawatt
nameplate capacity of Facility G with
Facility N).
(iv) Example 4. Hydropower Addition
of Capacity. X owns a hydropower plant
(Facility H) that was placed in service
in 1960. Facility H has become less
efficient since it was placed in service
with attendant reductions in its
generating capacity. As approved by a
FERC license amendment, X increases
Facility H’s capacity by installing new
headcovers, new turbines with
integrated dissolved oxygen injection,
and a new high pressure digital
governor system. The new turbines are
more efficient and are capable of more
power output than the original design.
Improvements to the generators involve
removing the old asphalt coated copper
windings and purchasing and then
installing new epoxy coated double
wound windings. X adds digital

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controls to effectively utilize new digital
governors while simultaneously
investing in cybersecurity protection. As
set forth in the FERC order amending its
license, these investments, which are
placed in service on April 15, 2026,
increase Facility H’s authorized
installed capacity from 180 MW to 190
MW, an increase of 10 MW. For
purposes of this paragraph (c), Facility
H’s addition of capacity is treated as a
new separate qualified facility placed in
service on April 16, 2026 (Facility A). X
may claim a section 45Y credit during
the 10-year credit period starting on
April 16, 2026, based on the amount of
electricity produced by Facility A,
which is determined by multiplying the
aggregate amount of electricity that
Facility H produces with Facility A by
1/19 (equal to the 10-megawatt increase
in capacity attributable to Facility A
divided by the new total aggregate 190
MW capacity of Facility H with Facility
A).
(v) Example 5. Nonoperational
Nuclear Facility that Satisfies Restart
Rule. T owns a nuclear facility (Facility
N) that was originally placed in service
in 1982. In 2020, Facility N ceased
operations, began decommissioning,
and the NRC no longer authorized the
operation of Facility N. T did not cease
operations at Facility N for the purpose
of qualifying for the special rule for
restarted facilities under section 45Y. In
2028, the NRC authorized Facility N to
restart and, on October 1, 2028, Facility
N placed in service components of
property and restarted and resumed
operations, with an electrical capacity of
800 MW, as indicated in NRC
documents related to the authorization
to restart. For purposes of this paragraph
(c), the restart of Facility N is
considered to have increased capacity
from a base of zero, and Facility N is
treated as having an addition of capacity
equal to 800 MW. For purposes of this
paragraph (c), Facility N’s 800 MW
addition of capacity is treated as a new
qualified facility placed in service on
October 1, 2028 (Facility P). T may
claim a section 45Y credit during the
10-year period starting on October 1,
2028, based on the increased amount of
electricity produced at Facility N that is
attributable to that addition of capacity
(Facility P).
(d) Retrofit of an existing facility (80/
20 Rule)—(1) In general. For purposes of
section 45Y(b)(1)(B), a facility may
qualify as originally placed in service
even if it contains some used
components of property within the unit
of qualified facility, provided the fair
market value of the used components of
the unit of qualified facility is not more
than 20 percent of the total value of the

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unit of qualified facility (that is, the cost
of the new components of property plus
the fair market value of the used
components of property within the unit
of qualified facility) (80/20 Rule). If a
facility satisfies the requirements of the
80/20 Rule, then the date on which such
qualified facility is considered
originally placed in service for purposes
of section 45Y(b)(1)(B) is the date on
which the new components of property
of the unit of qualified facility are
placed in service. A qualified facility
that meets the 80/20 Rule may claim the
section 45Y credit without regard to any
addition of capacity to the qualified
facility.
(2) Cost of new components of
property. For purposes of the 80/20
Rule, the cost of new components of the
unit of qualified facility includes all
costs properly included in the
depreciable basis of the new
components of property of the unit of
qualified facility.
(3) Examples. The following examples
illustrate the rules of this paragraph (d).
(i) Example 1. Retrofitted facility that
meets the 80/20 Rule. A owns an
existing wind facility. On February 1,
2026, A replaces used components of
the unit of qualified facility of a wind
facility with new components at a cost
of $2 million. The fair market value of
the remaining original components of
the unit of qualified facility is $400,000,
which is not more than 20 percent of the
retrofitted unit of qualified facility’s
total fair market value of $2.4 million
(the cost of the new components ($2
million) + the fair market value of the
remaining original components of the
unit of qualified facility ($400,000)).
Thus, the retrofitted wind facility will
be considered newly placed in service
for purposes of section 45Y, and the
section 45Y credit is allowable for
electricity produced by A at the wind
qualified facility and sold, consumed, or
stored, during the 10-year period
beginning on February 1, 2026,
assuming all the other requirements of
section 45Y are met.
(ii) Example 2. Retrofit of an existing
facility that meets the 80/20 Rule.
Facility Z, a facility that was originally
placed in service on January 1, 2026,
was not a qualified facility (as described
in § 1.45Y–2(a)) when it was placed in
service because it did not meet the
greenhouse gas emissions rate
requirements (as determined under
rules provided in § 1.45Y–5). On
January 1, 2027, Facility Z was
retrofitted and now meets the
requirements to be a qualified facility
under § 1.45Y–2(a). After the retrofit,
the cost of the new property included in
the unit of qualified facility of Facility

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Z is greater than 80 percent of the unit
of qualified facility of Facility Z’s total
fair market value. Because Facility Z
meets the 80/20 Rule, Facility Z is
deemed to be originally placed in
service on January 1, 2027. Therefore, a
section 45Y credit is allowable for
electricity produced by Facility Z and
sold, consumed, or stored during the 10year period beginning on January 1,
2027, assuming all the other
requirements of section 45Y are met.
(iii) Example 3. Retrofitted nuclear
facility that satisfied the 80/20 Rule. T
owns a nuclear facility (Facility N) that
was originally placed in service on
March 1, 1982. T replaces used
components of property of unit of
qualified facility of Facility N with new
components at a cost of $200 million,
placing in service the components of
property on July 15, 2026. The fair
market value of the remaining original
components of the unit of qualified
facility of Facility N, prior to the retrofit,
is $30 million, which is less than 20
percent of the unit of qualified facility
of Facility N’s total fair market value of
$230 million (the cost of the new
components ($200 million) + the fair
market value of the remaining original
components of the unit of qualified
facility ($30 million)) ($30 million/$230
million = 13%). Thus, Facility N will be
considered newly placed in service on
July 15, 2026, for purposes of section
45Y, and T will be able to claim a
section 45Y credit based on the
electricity generated at Facility N,
assuming all the other requirements of
section 45Y are met.
(iv) Example 4. Capital improvements
to an existing qualified facility that do
not satisfy the 80/20 Rule. X owns an
existing facility, Facility C, that was
originally placed in service on January
1, 2023. X makes capital improvements
to Facility C that are placed in service
on June 1, 2026. The cost of the capital
improvements to the unit of qualified
facility of Facility C is $500,000 and the
fair market value of the unit of qualified
facility of Facility C after the
improvements is $2 million. The value
of the old components of property of the
unit of qualified facility is $1,500,000
out of $2.0 million, or 75 percent
($500,000/$2,000,000) of the total fair
market value of the unit of qualified
facility after the improvements. Because
the fair market value of the new
property included in the unit of
qualified facility is less than 80 percent
of the total fair market value of the unit
of qualified facility, Facility C does not
meet the 80/20 Rule. Facility C will not
be considered a qualified facility (as
defined in § 1.45Y–2(a)) eligible for the
section 45Y credit. If the capital

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improvements to Facility C increase its
nameplate capacity, the determination
that it does not meet the 80/20 Rule
does not prevent X from claiming a
section 45Y credit if the requirements
under paragraph (c)(1) of this section are
met.
(v) Example 5. Upgrades to a
hydropower qualified facility that
satisfies the 80/20 Rule: Y owns a
hydropower qualified facility
(hydropower facility) and no taxpayer,
including Y, has ever claimed a section
45 credit for the hydropower facility.
The hydropower facility consists of a
unit of qualified facility including water
intake, water isolation mechanisms,
turbine, pump, motor, and generator.
The associated impoundment (dam) and
power conditioning equipment are
integral parts of the unit of qualified
facility. Y makes upgrades to the unit of
qualified facility by replacing the
turbine, pump, motor, and generator
with new components at a cost of $1.5
million. Y does not make any upgrades
to the property that is an integral part
of the unit of qualified facility. The
remaining original components of the
unit of qualified facility have a fair
market value of $100,000, which is not
more than 20 percent of the retrofitted
hydropower facility’s total value of $1.6
million (that is, the cost of the new
components ($1.5 million) + the value
of the remaining original components
($100,000)). Thus, the retrofitted
hydropower facility will be considered
newly placed in service for purposes of
section 45Y, and Y will be able to claim
a section 45Y credit based on the cost
of the new components ($1.5 million).
(e) Applicability date. This section
applies to qualified facilities placed in
service after December 31, 2024, and
during a taxable year ending on or after
January 15, 2025.

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§ 1.45Y–5 Greenhouse gas emissions
rates for qualified facilities under section
45Y.

(a) In general. This section provides
rules and definitions for determining
emissions rates for purposes of section
45Y of the Internal Revenue Code
(Code). Paragraph (b)(4) of this section
provides a definition for a facility that
produces electricity through combustion
or gasification and paragraph (b)(7) of
this section defines a facility that does
not produce electricity through
combustion or gasification. Paragraphs
(c) through (e) provide rules for
determining the greenhouse gas
emissions rates for facilities for
purposes of section 45Y. Paragraph (f) of
this section provides rules for the
annual publication of emissions rates.
Paragraph (g) of this section provides

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rules related to provisional emissions
rates. Paragraph (h) of this section
provides rules regarding reliance on the
annual publication of emissions rates
and provisional emissions rates. Finally,
paragraph (i) of this section provides
rules regarding substantiation
requirements.
(b) Definitions. The definitions in this
paragraph (b) apply for purposes of this
section.
(1) CO2e per kWh. The term CO2e per
kWh means with respect to any
greenhouse gas, the equivalent carbon
dioxide (as determined based on global
warming potential) per kWh of
electricity produced. The 100-year time
horizon global warming potentials
(GWP–100) from the Intergovernmental
Panel on Climate Change’s Fifth
Assessment Report (AR5) must be used
to convert emissions to equivalent
carbon dioxide emissions. For purposes
of this paragraph (b)(1), the GWP–100
from AR5 (as shown in table 1 to this
paragraph (b)(1)) excludes climatecarbon feedbacks. Table 1 to this
paragraph (b)(1) provides GWP–100
amounts for certain greenhouse gases
applicable to this section.

TABLE 1 TO PARAGRAPH (b)(1)—100
YEAR GLOBAL WARMING POTENTIALS FOR GREENHOUSE GASES
Greenhouse gas

GWP

CO2 ....................................
CH4 ....................................
N2O ....................................
SF6 .....................................
Hydrofluorocarbons ...........
Perfluorocarbons ...............

1.
28.
265.
23,500.
Varies by gas.
Varies by gas.

(2) Combustion. The term combustion
means a rapid exothermic chemical
reaction, specifically the oxidation of a
fuel, which liberates energy including
heat and light.
(3) Gasification. The term gasification
means a thermochemical process that
converts carbon-containing materials
into syngas, a gaseous mixture that is
composed primarily of carbon
monoxide, carbon dioxide, and
hydrogen.
(4) Facility that produces electricity
through combustion or gasification
(C&G Facility). Consistent with section
45Y(b)(2)(B), the term facility that
produces electricity through combustion
or gasification (C&G Facility) means a
facility that produces electricity through
combustion or uses an input energy
source to produce electricity, if the
input energy source was produced
through a fundamental transformation
of one energy source into another using
combustion or gasification.

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(5) Greenhouse gas emissions rate.
Consistent with section 45Y(b)(2)(A),
the term greenhouse gas emissions rate
means the amount of greenhouse gases
emitted into the atmosphere by a facility
in the production of electricity,
expressed as grams of CO2e per kWh.
(6) Greenhouse gases emitted into the
atmosphere by a facility in the
production of electricity. For purposes
of section 45Y(b)(2)(A), for both C&G
and Non-C&G Facilities, the term
greenhouse gases emitted into the
atmosphere by a facility in the
production of electricity means
emissions from a facility that directly
occur from the processes that transform
the input energy source into electricity
but excludes emissions described in
paragraphs (b)(6)(i) through (vi) of this
section.
(i) Emissions from electricity
production by back-up or auxiliary
generators that are primarily used in
maintaining critical systems in case of a
power system outage or for supporting
restart of a generator after an outage.
(ii) Emissions from routine
operational and maintenance activities
that are integral to the production of
electricity, including, but not limited to,
emissions from internal combustion
vehicles used to access and perform
maintenance on remote electricity
generating facilities or emissions
occurring from heating and cooling
control rooms or dispatch centers.
(iii) Emissions from a step-up
transformer that conditions the
electricity into a form suitable for
productive use or sale.
(iv) Emissions that occur before
commercial operations commence or
after commercial operations terminate,
including, but not limited to, on-site
emissions occurring from construction
or manufacturing of the facility itself,
emissions from the off-site
manufacturing of facility components,
or emissions occurring due to siting or
decommissioning.
(v) Emissions from infrastructure
associated with the facility, including,
but not limited to, emissions from road
construction for feedstock production.
(vi) Emissions from the distribution of
electricity to consumers.
(7) Non-C&G Facility. The term NonC&G Facility means a facility that
produces electricity and is not described
in paragraph (b)(4) of this section.
(8) Fuel. The term fuel means material
directly used to produce electricity or
energy inputs that are used to produce
electricity.
(9) Feedstock. The term feedstock
means any raw material used in a
process for electricity generation or to
produce an intermediate product or

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finished fuel used for electricity
generation.
(10) Market-mediated effects. The
term market-mediated effects means
effects resulting from policy
interventions and other factors (for
example, technological advances) that
alter the availability of and demand for
marketed goods and activities and their
related greenhouse gas (GHG) emissions
profiles. These effects are driven by and
result in changes in absolute and
relative prices which can occur at local,
national, and global boundaries.
Examples of market-mediated effects
include direct and significant indirect
emissions, such as land use changes or
land use management changes that
result from the production of fuels
derived from biomass and shifts in total
market demand and supply for input
fuels, feedstocks and related
commodities, and other materials, as a
result of changes associated with the
policy intervention.
(c) Non-C&G Facilities—(1)
Determining a greenhouse gas emissions
rate for Non-C&G Facilities. Greenhouse
gas emissions rates for Non-C&G
Facilities must be determined under
paragraphs (c) and (e) of this section.
(i) Excluded emissions. With respect
to Non-C&G Facilities only, greenhouse
gases emitted into the atmosphere by a
facility in the production of electricity
excludes emissions of greenhouse gases
that are not directly produced by the
fundamental transformation of the input
energy source into electricity, including,
but not limited to:
(A) Emissions from hydropower
reservoirs due to anoxic conditions;
(B) Ebullitive, diffuse, and degassing
emissions from hydropower operations;
(C) Emissions of non-condensable
gases from underground reservoirs
during geothermal operations; and
(D) Emissions occurring due to
activities and operations occurring offsite, including but not limited to, the
production and transportation of fuels
used by the facility, or land use change
from siting or changes in demand.
(ii) Emissions assessment process.
Subject to paragraphs (b)(6) and (c)(1) of
this section, a greenhouse gas emissions
rate for a Non-C&G Facility must be
determined through a technical and
engineering assessment of the
fundamental energy transformation into
electricity. This assessment must
consider all input and output energy
carriers and chemical reactions or
mechanical processes taking place at the
facility in the production of electricity.
(iii) Example of greenhouse gas
emissions rate determination for a NonC&G Facility—(A) Facts. A facility uses
solar photovoltaic technologies to

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convert light directly into electricity
through use of the photovoltaic effect.
This is a physical phenomenon in
which certain semiconducting materials
upon exposure to light, absorb the light
and transform the energy contained in
the light directly into an electric
current. There are many materials that
may be used to generate electricity
through this method, including
crystalline silicon, amorphous silicon,
cadmium telluride, copper indium
gallium diselenide, perovskites,
quantum dots, and carbon-based
materials known as organic
photovoltaics. The smallest unit of
photovoltaic materials is a cell. Multiple
cells are typically assembled into a
panel or module and electrically
connected. Multiple modules or panels
are generally connected to comprise a
solar system or installation. Solar
photovoltaic technologies produce
direct current electricity that can be
used as is or, more typically, can be fed
into inverters to transform it into
alternating current. Solar panels can be
ground mounted at a fixed angle or can
be mounted with tracking systems that
move the panels to track the location of
the sun over the course of the day and
season in order to maximize electricity
production. Solar panels may also be
mounted on buildings (for example, on
roofs), or solar photovoltaic materials
can be integrated into other building
components such as roofing tiles.
(B) Analysis. For solar photovoltaic
technologies, the fundamental
transformation of input energy (solar
electromagnetic radiation) into
electricity using the photovoltaic effect
involves no mechanical energy or
chemical reactions. Academic studies
on the lifecycle greenhouse gas
emissions from solar photovoltaic
power indicate that there is a small but
non-zero amount of emissions
associated with the operational phase of
these technologies. However, these
emissions exclusively occur due to
ongoing maintenance (for example, the
washing of solar panels), preventative
maintenance (for example, the periodic
replacement of electrical equipment
such as inverters), and a minimal
amount of project management (for
example, inverter standby mode at
night). These emissions do not occur
directly due to the production of
electricity. Therefore, consistent with
paragraph (c)(1)(ii) of this section, the
greenhouse gas emissions rate for
facilities that produce electricity by
solar photovoltaic properties is not
greater than zero.
(2) Non-C&G Facilities with a
greenhouse gas emissions rate that is
not greater than zero. The types or

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categories of facilities described in
paragraphs (c)(2)(i) through (viii) of this
section are Non-C&G Facilities with a
greenhouse gas emissions rate that is not
greater than zero and may be treated as
listed in the Annual Table (see
paragraph (g) of this section) with an
emissions rate that is not greater than
zero:
(i) Wind (including small wind
properties);
(ii) Hydropower (including retrofits
that add electricity production to nonpowered dams, conduit hydropower,
hydropower using new impoundments,
and hydropower using diversions such
as a penstock or channel);
(iii) Marine and hydrokinetic;
(iv) Solar (including photovoltaic and
concentrated solar power);
(v) Geothermal (including flash and
binary plants);
(vi) Nuclear fission;
(vii) Fusion energy; and
(viii) Waste energy recovery property
that derives energy from a source
described in paragraphs (c)(2)(i) through
(vii) of this section.
(d) C&G Facilities—(1) Determining a
greenhouse gas emissions rate for C&G
Facilities. The greenhouse gas emissions
rate for a C&G Facility—
(i) Must be determined by a lifecycle
analysis (LCA) that complies with the
requirements of paragraphs (d) and (e)
of this section; and
(ii) Equals the net rate of greenhouse
gases emitted into the atmosphere by
such facility (taking into account
lifecycle greenhouse gas emissions, as
described in 42 U.S.C. 7545(o)(1)(H)) in
the production of electricity, expressed
as grams of CO2e per kWh.
(2) LCA requirements. For purposes of
this paragraph (d), an LCA must comply
with the requirements of paragraphs
(d)(2)(i) through (x) of this section:
(i) Starting boundary. The starting
boundary of the LCA for an LCA
involving generation-derived feedstocks
(such as biogenic feedstocks) is
feedstock generation. The starting
boundary of the LCA for an LCA
involving extraction-derived feedstocks
(such as fossil fuel feedstocks) is
feedstock extraction. The starting
boundaries include the processes and
inputs necessary to produce and collect
or extract the raw materials used to
produce electricity from combustion or
gasification technologies, including
those used as energy inputs to
electricity production. This includes,
but is not limited to, the emissions
effects, including associated direct and
indirect greenhouse gas emissions, of
relevant land management activities or
changes related to or associated with the

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extraction or production of raw
feedstock materials or fuel.
(ii) Ending boundary. The ending
boundary of the LCA for electricity that
is transmitted to the grid or electricity
that is used on-site is the meter at the
point of production of the C&G Facility.
The use of such electricity generated by
the C&G Facility (and what other types
of energy sources it displaces),
including emissions from transmission
and distribution, are outside of the LCA
boundary.
(iii) Baseline. The LCA must be based
on a future anticipated baseline, which
projects future status quo in the absence
of the availability of the section 45Y and
48E credits (taking into account
anticipated changes in technology,
policies, practices, and environmental
and other socioeconomic conditions).
The future anticipated baseline must be
updated as necessary to capture material
regulatory, economic, supply chain, or
environmental changes. The baseline
must be updated at least every ten years,
but not more often than every five years.
(iv) Offsets and offsetting activities.
Offsets and offsetting activities may not
be taken into account in the LCA.
(v) Principles for included emissions.
The LCA must take into account direct
emissions and significant indirect
emissions. Sources of direct emissions
include those associated with feedstock
production or extraction, including
emissions at all stages of fuel and
feedstock production, and distribution,
and emissions associated with
distribution, delivery, and use of
feedstocks to and by a C&G Facility.
Sources of significant indirect emissions
include emissions in the United States
and other countries associated with
market-mediated changes in related
commodity markets, such as emission
from indirect land use change and
emissions consequences of commodity
production. These included emissions
are within the system boundary of the
LCA.
(A) Direct emissions. For purposes of
this paragraph (d)(2)(v), direct emissions
include, but are not limited to:
(1) Emissions from feedstock
generation, production, and extraction
(including emissions from feedstock and
fuel harvesting and extraction and direct
land use change and management,
including emissions from fertilizers, and
changes in carbon stocks);
(2) Emissions from feedstock and fuel
transport (including emissions from
transporting the raw or processed
feedstock to the fuel processing facility);
(3) Emissions from transporting and
distributing fuels to electricity
production facility;

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(4) Emissions from handling,
processing, upgrading, and/or storing
feedstocks, fuels and intermediate
products (including emissions from on/
offsite storage and preparation/pretreatment for use (for example,
torrefaction or pelletization) and
emissions from process additives); and
(5) Emissions from combustion and
gasification at the electricity generating
facility (including emissions from the
combustion and/or gasification process
and emission from gasification or
combustion additives).
(B) Significant indirect emissions. For
purposes of this paragraph (d)(2)(v),
examples of significant indirect
emissions include, but are not limited
to, emissions from indirect land use and
land use change, and induced emissions
associated with the increased use of the
feedstock for energy production.
(vi) Principles for excluded emissions.
The LCA must not take into account the
types of emissions described in
paragraphs (d)(2)(vi)(A) through (D) of
this section:
(A) Emissions from facility
construction, siting or decommissioning
(including on-site emissions occurring
from construction or manufacturing of
the facility itself);
(B) Emissions from facility
maintenance (including emissions from
the on and offsite construction or
maintenance of the facility; emissions
from vehicles used to access and
perform maintenance on electricity
generating facilities; emissions from
back-up generators that do not provide
additional firm power and are used in
maintaining critical systems in case of a
power system outage or for supporting
restart of a generator after an outage; and
emissions occurring from heating and
cooling control rooms or dispatch
centers);
(C) Emissions from infrastructure
associated with the facility (including
emissions from road construction for
feedstock production and emissions
from onsite backup or emergency
generators used in an emergency or
unplanned outage); and
(D) Emissions from the distribution of
electricity to consumers.
(vii) Alternative fates and avoided
emissions. The LCA may consider
alternative fates and account for avoided
emissions, including for the fuels and
feedstocks consumed in the fuel and
feedstock supply chain and at the
electricity generating facility. 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

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4107

for the feedstock’s new use due to the
implementation of policy (that is, to
produce electricity). The term avoided
emissions means the estimated
emissions associated with the feedstock,
including the feedstock’s production
and use or disposal, that would have
occurred in the alternative fate (if such
feedstock had not been diverted for
electricity production) but are instead
avoided with the feedstock’s use for
electricity production.
(viii) Temporal scales. The LCA
should evaluate the emissions over a
time horizon of 30 years from the year
in which a qualified facility first
qualifies for the credit (or, for purposes
of the section 48E credit, the year in
which a qualified facility was placed in
service).
(ix) Spatial scales. To determine the
initial spatial scope of the LCA, the
initial qualitative assessment should
analyze whether the feedstock has been
or is anticipated: to be used or sold on
the market in the absence of the section
45Y and 48E credits; to be used directly
in or as an input to an activity or good
in local markets; to be transported for
use in domestic markets elsewhere; to
be traded for use in international
markets; and to be used in a manner that
has significant ramifications on other
markets. If this assessment concludes
that the feedstock does not meet one or
more of the criteria in this paragraph
(d)(2)(ix), then the market-mediated
effects analysis would not be necessary
beyond the relevant spatial scale(s) (for
example, if the feedstock is not traded
or not anticipated to be traded for use
in international markets and increased
use in the United States is not
anticipated to have significant market
ramifications abroad, international
market-mediated effects analysis would
not be necessary). Based on the results
of the assessment, the LCA should
evaluate the emissions on a subregional, regional, national, or
international scale as appropriate. The
evaluation of emissions should include
the market and emissions implications
of sourcing new or additional material
for electricity generation across the
applicable market and spatial scales.
(x) Categorization of products. As
appropriate, the LCA should distinguish
between primary products, co-products,
byproducts, and waste products.
(A) Products should be categorized
based on the definitions in paragraphs
(d)(2)(x)(A)(1) through (4) of this
section.
(1) A primary product is an input or
an output with marketability and is the
main driver of the process from which
it is produced.

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(2) A co-product is an input or an
output with marketability that is
produced together with another
product, both of which are economic
drivers of the process from which they
are produced.
(3) A byproduct is an input or an
output that is produced together with
another product, and which has a
market recognized economic value of
zero or greater, but the output is not an
economic driver of the process from
which it is produced.
(4) A waste product is an input or an
output with negative economic value,
demonstrated by—
(i) The absence of a market in which
the product is purchased and sold; and
(ii) The existence of a market in which
producers pay for the collection and
removal or disposal of the input or
output material or the existence of a
predominant operational practice in
which producers themselves collect and
remove, give away, or dispose of the
input or output material as part of
operational processes.
(B) The LCA should adopt the
principles in paragraphs (d)(2)(x)(B)(1)
through (6) of this section for
categorizing and assessing the emissions
outcomes for different types of products
if such categorization is relevant to the
LCA model or models used.
(1) All classification of materials and
LCAs should take into account relevant
geospatial variations in supply and
demand (that is, differences across local,
sub-regional, and larger regions), as well
as variations across specific product
types and characteristics, and producer
types as relevant.
(2) The LCA should assess whether
there are market-mediated effects and, if
so, take these into account as part of the
GHG analysis.
(3) Regardless of how a material is
categorized, the LCA should consider
whether the availability of the section
45Y and 48E credits is expected to
result in additional production of that
material or in material changes in the
supply chain, and, if so, should take
into account the direct and indirect
emissions impact of the additional
production or changes in the supply
chain.
(4) Policy and other interventions (for
example, technological advances) can
alter the availability and demand for
marketed goods and services, which can
alter the treatment of materials once
disposed of. Therefore, reevaluation of
material categorization should occur at
least every ten years, but not more often
than every five years.
(5) All determinations of
marketability, market-mediated effects,
and behavioral changes must be

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supported by an analytical assessment
performed by one or more National
Laboratories, in consultation with other
Federal agency experts as appropriate.
(6) A material should be considered to
have a market recognized economic
value and an established market if one
existed within the last five years as of
the date of the analysis.
(e) Use of methane from certain
sources to produce electricity—(1) In
general. The requirements provided by
this paragraph (e) apply to C&G
Facilities (as defined in paragraph (b)(4)
of this section) that produce electricity
through combustion or gasification
using methane derived from biogas,
renewable natural gas (RNG) derived
from biogas, or fugitive sources of
methane (or any hydrogen derived from
methane from these sources) as a fuel or
feedstock.
(2) Definitions. The following
definitions apply for purposes of
paragraph (e) of this section:
(i) Biogas. The term biogas means gas
containing methane that results from the
decomposition of organic matter under
anaerobic conditions.
(ii) 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).
(iii) 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.
(iv) Renewable natural gas. The term
renewable natural gas (RNG) means
biogas that has been upgraded to remove
water, CO2, and other impurities such
that it is interchangeable with fossil
natural gas.
(3) Considerations regarding the
lifecycle greenhouse gas emissions
associated with the production of
electricity using methane from certain
sources—(i) In general. For purposes of
determining the GHG emissions rate of
a C&G Facility (as provided in
paragraph (d)(1) of this section) that
produces electricity through combustion
or gasification using methane derived
from biogas, RNG derived from biogas,
or fugitive sources of methane (or any

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hydrogen derived from methane from
these sources) as a fuel or feedstock,
measurements of lifecycle GHG
emissions must consider all the direct
and significant indirect emissions
associated with a C&G Facility’s
production of electricity. For purposes
of determining the alternative fates and
avoided emissions under paragraph
(d)(2)(vii) of this section, such
determinations must consider the
alternative fates of that methane,
including avoided emissions and
alternative productive uses of that
methane; the risk that the availability of
tax credits creates incentives resulting
in the production of additional methane
or otherwise induces additional
emissions; and observable trends and
anticipated changes in waste
management and disposal practices over
time as they are applicable to methane
generation and uses.
(ii) Methane from landfill sources. For
purposes of determining the GHG
emissions rate of a C&G Facility (as
provided in paragraph (d)(1) of this
section) that produces electricity
through combustion or gasification
using methane derived from landfill
sources as a fuel or feedstock, the
alternative fate of such gas must be
flaring.
(iii) Methane from wastewater
sources. For purposes of determining
the GHG emissions rate of a C&G
Facility (as provided in paragraph (d)(1)
of this section) that produces electricity
through combustion or gasification
using methane derived from wastewater
sources as a fuel or feedstock, the
alternative fate of such gas must be
flaring of gas not used to heat the
anaerobic digester.
(iv) Coal mine methane. For purposes
of determining the GHG emissions rate
of a C&G Facility (as provided in
paragraph (d)(1) of this section) that
produces electricity through combustion
or gasification using coal mine methane
that is drainage gas as a fuel or
feedstock, the alternative fate of such
gas must be flaring.
(v) Methane from animal waste. For
purposes of determining the GHG
emissions rate of a C&G Facility (as
provided in paragraph (d)(1) of this
section) that produces electricity
through combustion or gasification
using methane derived from animal
waste as a fuel or feedstock, the
emissions associated with producing
and transporting such biogas 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 gCO2e/
megajoule (MJ), where the MJ basis
refers to the lower heating value of the

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methane contained in the biogas prior to
upgrading.
(vi) Fugitive methane other than coal
mine methane. For purposes of
determining the GHG emissions rate of
a C&G Facility (as provided in
paragraph (d)(1) of this section) that
produces electricity through combustion
or gasification using fugitive methane
other than coal mine methane as a fuel
or feedstock, such as fugitive methane
from oil and gas operations, the
alternative fate of such gas must be
productive use, resulting in emissions
equivalent to the carbon intensity of
using fossil natural gas.
(4) Book-and-claim. For purposes of
determining a GHG emissions rate of a
facility under section 45Y or 48E, a
book-and-claim accounting system may
not be used to establish or claim the
energy attributes of biogas, RNG, coal
mine methane, or any other methane
described in this paragraph (e), or any
other input or feedstock.
(f) Carbon capture and
sequestration—(1) In general. For
purposes of determining a greenhouse
gas emissions rate for a Non-C&G
Facility or C&G Facility, the greenhouse
gas emissions rate must not include any
qualified carbon dioxide (as defined in
section 45Y(c)(3)) that is produced in
such facility’s production of electricity,
that is captured by the taxpayer, and
pursuant section 45Q(f)(2) and 26 CFR
1.45Q–3, disposed of by the taxpayer in
secure geological storage, or utilized by
the taxpayer in a manner described in
section 45Q(f)(5) and 26 CFR 1. 45Q–4.
(2) Substantiation. The requirements
for substantiation and verification of
carbon capture and sequestration
provided by regulations and guidance
published in the Internal Revenue
Bulletin (see § 601.601 of this chapter)
under section 45Q (section 45Q
requirements) must be satisfied for
qualified carbon dioxide to be taken into
account under paragraph (e)(1) of this
section. A taxpayer that uses carbon
capture and sequestration at a qualified
facility for which a section 45Y credit is
claimed must comply with applicable
requirements of the U.S. Environmental
Protection Agency’s Greenhouse Gas
Reporting Program (GHGRP) under 40
CFR part 98, subpart PP (for carbon
capture), subpart RR (for geological
storage), and subpart RR or VV (for
storage through enhanced oil recovery).
In addition to the section 45Q
requirements, taxpayers using the ISO
27916 standard for enhanced oil
recovery must report information to
GHGRP under 40 CFR part 98, subpart
VV. Furthermore, the taxpayer must also
include their applicable GHGRP ID
number(s) on the IRS Form used to

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claim the section 45Y or section 48E
credit, with the exception of taxpayers
claiming the credits by performing
carbon capture and utilization. The
GHGRP does not provide a reporting
mechanism for utilization.
(g) Annual publication of emissions
rates—(1) In general. As required by
section 45Y(b)(2)(C)(i), the Secretary
will annually publish a table that sets
forth the greenhouse gas emissions rates
for types or categories of facilities
(Annual Table), which a taxpayer must
use for purposes of section 45Y. Except
as provided in paragraph (h) of this
section, a taxpayer that owns a facility
that is described in the Annual Table on
the first day of the taxpayer’s taxable
year in which the section 45Y credit or
section 48E credit is determined with
respect to such facility must use the
Annual Table as of such date to
determine an emissions rate for such
facility for such taxable year.
(2) Publication of analysis required for
changes to the Annual Table. In
connection with the publication of the
Annual Table, the Secretary must
publish an accompanying expert
analysis that addresses any types or
categories of facilities added or removed
from the Annual Table, as well as any
changes to emissions determinations for
any types or categories of facilities in
the Annual Table, since its last
publication. Types or categories of
facilities will be added or removed from
the Annual Table consistent with, for
Non-C&G Facilities, a technical
assessment of the fundamental energy
transformation into electricity as
provided in paragraph (c)(1)(ii) of this
section, and, for C&G Facilities, an LCA
that complies with paragraphs (d) and
(f) of this section. Such expert analysis
must be prepared by one or more of the
National Laboratories, in consultation
with other Federal agency experts as
appropriate, and must address whether
the addition or removal of types or
categories of facilities from the Annual
Table complies with section
45Y(b)(2)(A) and (B) of the Internal
Revenue Code and this section.
(h) Provisional emissions rates—(1) In
general. In the case of any facility that
is of a type or category for which an
emissions rate has not been established
by the Secretary under paragraph (g) of
this section, a taxpayer that owns such
facility may file a petition with the
Secretary for the determination of the
emissions rate with respect to such
facility (Provisional Emissions Rate or
PER). A PER must be determined and
obtained under the rules of this section.
(2) Rate not established. An emissions
rate has not been established by the
Secretary for a facility for purposes of

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section 45Y(b)(2)(C)(ii) if such facility is
not described in the Annual Table. If a
taxpayer’s request for an emissions
value pursuant to paragraph (h)(5) of
this section is pending at the time such
facility is or becomes described in the
Annual Table, the taxpayer’s request for
an emissions value will be
automatically denied.
(3) Process for filing a PER petition.
To file a PER petition with the
Secretary, a taxpayer must submit a PER
petition by attaching it to the taxpayer’s
Federal income tax return or Federal
return, as appropriate, for the first
taxable year in which the taxpayer
claims the section 45Y credit with
respect to the facility to which the PER
petition applies. The PER petition must
contain an emissions value, and, if
applicable, the associated letter from the
Department of Energy (DOE). An
emissions value may be obtained from
DOE or by using the designated LCA
model in accordance with paragraph
(h)(6) of this section. An emission value
obtained from DOE will be based on an
analytical assessment of the emissions
rate associated with the facility,
performed by one or more National
Laboratories, in consultation with other
Federal agency experts as appropriate,
consistent with this section. A taxpayer
must retain in its books and records a
copy of the application and
correspondence to and from DOE
including a copy of the taxpayer’s
request to DOE for an emissions value
and any information provided by the
taxpayer to DOE pursuant to the
emissions value request process
provided in paragraph (h)(5) of this
section. Alternatively, an emissions
value can be determined by the taxpayer
for a facility using the most recent
version of an LCA model, as of the time
the PER petition is filed, that has been
designated by the Secretary for such use
under paragraph (h)(6) of this section. If
an emissions value is determined using
the most recent version of the model or
models, the taxpayer is required to
provide to the IRS information to
support its determination in the form
and manner prescribed in IRS forms or
instructions or in publications or
guidance published in the Internal
Revenue Bulletin. See § 601.601 of this
chapter. A taxpayer may not request an
emissions value from DOE for a facility
for which an emissions value can be
determined by using the most recent
version of an LCA model or models that
have been designated by the Secretary
for such use under paragraph (h)(6) of
this section.
(4) PER determination. Upon the IRS’s
acceptance of the taxpayer’s Federal
income tax return or Federal return, as

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appropriate, containing a PER petition,
the emissions value of the facility
specified on such petition will be
deemed accepted. A taxpayer may rely
upon an emissions value provided by
DOE for purposes of claiming a section
45Y credit, provided that any
information, representations, or other
data provided to DOE in support of the
request for an emissions value are
accurate. If applicable, a taxpayer may
rely upon an emissions value
determined for a facility using the most
recent version of the specific LCA
model or models that, as of the time the
PER petition is filed, have been
designated by the Secretary for such use
under paragraph (h)(6) of this section,
provided that any information,
representations, or other data used to
obtain such emissions value are
accurate. The IRS’s deemed acceptance
of an emissions value is the Secretary’s
determination of the PER. However, the
taxpayer must still comply with all
applicable requirements for the section
45Y credit and any information,
representations, or other data
supporting an emissions value are
subject to later examination by the IRS.
(5) Emissions value request process.
An applicant that submits a request for
an emissions value must follow the
procedures specified by DOE to request
and obtain such emissions value.
Emissions values will be determined
consistent with the rules provided in
this section. An applicant may request
an emissions value from DOE only after
a front-end engineering and design
(FEED) study or similar indication of
project maturity, as determined by DOE,
such as completion of a project
specification and cost estimation
sufficient to inform a final investment
decision for the facility. DOE may
decline to review applications that are
not responsive, including those
applications that relate to a facility
described in the Annual Table
(consistent with paragraph (h)(2) of this
section) or a facility for which an
emissions value can be determined by
an LCA model designated under
paragraph (h)(6) of this section
(consistent with paragraph (h)(3) of this
section), or applications that are
incomplete. DOE will publish guidance
and procedures that applicants must
follow to request and obtain an
emissions value from DOE. DOE’s
guidance and procedures will include a
process for, under limited
circumstances, requesting a revision to
DOE’s initial assessment of an emissions
value based on revised technical
information or facility design and
operation.

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(6) LCA model for determining an
emissions value for C&G Facilities. The
Secretary may designate one or more
LCA models for determining an
emissions value for C&G Facilities that
are not described in the Annual Table.
The Secretary may only designate a
model under this paragraph (h)(6) if the
model complies with section
45Y(b)(2)(B) and paragraphs (d) and (f)
of this section. The Secretary may
revoke the designation of an LCA model
or models. In connection with the
designation or revocation of a
designation of an LCA model or models,
the Secretary is required to publish an
accompanying expert analysis of the
model that is prepared by one or more
of the National Laboratories, in
consultation with other Federal agency
experts as appropriate, and such
analysis must address the model’s
compliance with section 45Y(b)(2)(B) of
the Internal Revenue Code and
paragraphs (d) and (f) of this section.
(7) Effect of PER. A taxpayer may use
a PER determined by the Secretary to
determine eligibility for the section 45Y
credit for the facility to which the PER
applies, provided all other requirements
of section 45Y are met. 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 45Y credit is
claimed. Further, a PER determination
does not signify that the IRS has
determined that the requirements of
section 45Y have been satisfied for any
taxable year.
(i) Reliance on Annual Table or
provisional emissions rate. Taxpayers
may rely on the Annual Table in effect
as of the date a facility began
construction or the provisional
emissions rate determined by the
Secretary for the taxpayer’s facility
under paragraph (h)(4) of this section to
determine the facility’s greenhouse gas
emissions rate for any taxable year that
is within the 10-year period described
in section 45Y(b)(1)(B), provided that
the facility continues to operate as a
type of facility that is described in the
Annual Table or the facility’s emissions
value request, as applicable, for the
entire taxable year.
(j) Substantiation—(1) In general. A
taxpayer must maintain in its books and
records documentation regarding the
design, operation, and, if applicable,
feedstock or fuel source used by the
facility that establishes that such facility

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had a greenhouse gas emissions rate, as
determined under this section, that is
not greater than zero for the taxable
year.
(2) Sufficient substantiation.
Documentation sufficient to substantiate
that a facility had a greenhouse gas
emissions rate, as determined under this
section, that is not greater than zero for
the taxable year includes documentation
or a report prepared by an unrelated
party that verifies that a facility had
such an emissions rate. For a facility
described in paragraph (c)(2) of this
section, the taxpayer can maintain
sufficient documentation to demonstrate
a greenhouse gas emissions rate that is
not greater than zero for the taxable year
by showing that it is the type of facility
described in paragraph (c)(2). For
qualified facilities not described in
paragraph (c)(2), the taxpayer must
demonstrate that the qualified facility
meets the specific criteria that the
analytical assessment prepared by the
National Laboratories, in consultation
with other Federal agency experts as
appropriate, has found are necessary for
a facility to meet the statutory
requirement of a greenhouse gas
emissions rate not greater than zero. For
C&G Facilities that utilize biomass
feedstocks, the taxpayer must
substantiate that the source of such fuels
or feedstocks used are consistent with
the taxpayer’s claims. The Secretary
may determine that qualified facilities
not described in paragraph (c)(2) can
sufficiently substantiate a greenhouse
gas emissions rate, as determined under
this section, that is not greater than zero
with certain documentation and will
describe such facilities and
documentation in IRS forms or
instructions or in publications or
guidance published in the Internal
Revenue Bulletin. See § 601.601 of this
chapter. For facilities that utilize
unmarketable feedstocks that are
indistinguishable from marketable
feedstocks (for instance, after
processing), the taxpayer will be
required to maintain documentation
substantiating the origin and original
form of the feedstock.
(k) Applicability date. This section
applies to qualified facilities placed in
service after December 31, 2024, and
during a taxable year ending on or after
January 15, 2025.
■ Par. 6. Sections 1.48E–0 through
1.48E–5 are added to read as follows:
Sec.

*

*

*

*

*

1.48E–0 Table of contents.
1.48E–1 Clean electricity investment credit.
1.48E–2 Qualified investments in qualified
facilities and EST for purposes of section
48E.

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1.48E–3 Rules relating to the increased
credit for prevailing wage and
apprenticeship.
1.48E–4 Rules of general application.
1.48E–5 Greenhouse gas emissions rates for
qualified facilities under section 48E.

*

*

§ 1.48E–0

*

*

*

Table of contents.

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This section lists the captions
contained in §§ 1.48E–1 through 1.48E–
5.
§ 1.48E–1 Clean electricity investment
credit.
(a) Overview.
(1) In general.
(2) Claim.
(3) Code.
(4) EST.
(5) kWh.
(6) Qualified facility.
(7) Qualified investment with respect to a
qualified facility.
(8) Qualified investment with respect to
EST.
(9) Secretary.
(10) Section 48E credit.
(11) Section 48E regulations.
(12) Waste energy recovery property
(WERP).
(b) Credit amount.
(1) In general.
(2) Applicable percentage.
(3) Base rate.
(4) Alternative rate.
(5) Energy communities increase in credit
rate.
(i) In general.
(ii) Applicable credit rate increase.
(6) Domestic content increase in credit rate.
(i) In general.
(ii) Applicable credit rate increase.
(c) Credit phase-out.
(1) In general.
(2) Phase-out percentage.
(3) Applicable year.
(d) Related taxpayers.
(1) Definition.
(2) Related taxpayer rule.
(e) Applicability date.
§ 1.48E–2 Qualified investments in
qualified facilities and EST for purposes
of section 48E.
(a) Qualified investment with respect to a
qualified facility.
(1) In general.
(2) Total basis amount.
(b) Qualified facility.
(1) In general.
(2) Placed in service.
(i) In general.
(ii) Qualified facility subject to § 1.48–4
election to treat lessee as purchaser.
(c) Qualified property.
(1) In general.
(2) Location of property.
(d) Property included in qualified facility.
(1) In general.
(2) Unit of a qualified facility.
(i) In general.
(ii) Functionally interdependent.
(3) Integral part.
(i) In general.
(ii) Power conditioning and transfer
equipment.

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(iii) Roads.
(iv) Fences.
(v) Buildings.
(vi) Shared integral property.
(vii) Examples.
(e) Definitions related to requirements for
qualified property.
(1) Tangible personal property.
(2) Other tangible property.
(3) Depreciation allowable.
(i) In general.
(ii) Exclusions from allowable.
(4) Construction, reconstruction, or
erection of the property.
(5) Acquisition of qualified property.
(6) Original use of the property.
(7) Retrofitted qualified facility.
(f) Coordination with other credits.
(1) In general.
(2) Allowed.
(3) Examples.
(g) EST.
(1) Property included in EST.
(2) Unit of EST.
(i) In general.
(ii) Functionally interdependent.
(3) Integral part.
(4) Qualified investment with respect to
EST.
(5) Placed in service.
(i) In general.
(ii) EST subject to § 1.48–4 election to treat
lessee as purchaser.
(6) Types of EST.
(i) Electrical energy storage property.
(ii) Thermal energy storage property.
(iii) Hydrogen energy storage property.
(7) Modification of EST.
(h) Applicability date.
§ 1.48E–3 Rules relating to the increased
credit for prevailing wage and
apprenticeship.
(a) In general.
(b) Qualified facility or EST requirements.
(c) Nameplate capacity for purposes of the
One Megawatt Exception.
(1) Qualified facilities.
(2) Nameplate capacity for qualified
facilities that generate in direct current for
purposes of the One Megawatt Exception.
(3) EST.
(i) In general.
(ii) Electrical energy storage property.
(iii) Thermal energy storage property.
(iv) Hydrogen energy storage property.
(4) Integrated operations.
(i) One Megawatt Exception.
(ii) EST One Megawatt Exception.
(d) Transition waiver of penalty for
prevailing wage requirements.
(e) No alteration or repair during recapture
period described in § 1.48–13(c)(3).
(f) Applicability date.
§ 1.48E–4 Rules of general application.
(a) Qualified interconnection costs
included in certain lower-output qualified
facilities.
(1) In general.
(2) Qualified interconnection property.
(3) Five-Megawatt Limitation.
(i) In general.
(ii) Nameplate capacity for purposes of the
Five-Megawatt Limitation.
(iii) Nameplate capacity for qualified
facilities that generate in direct current for
purposes of the Five-Megawatt Limitation.

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(4) Interconnection agreement.
(5) Utility.
(6) Reduction to amounts chargeable to
capital account.
(7) Examples.
(b) Expansion of facility; Incremental
production (Incremental Production Rule).
(1) In general.
(2) Measurement standard.
(3) Special rule for restarted facilities.
(4) Computation of qualified investment for
a new unit or an addition of capacity.
(i) New unit.
(ii) Addition of capacity.
(5) Examples.
(c) Retrofit of an existing facility (80/20
Rule).
(1) In general.
(2) Expenditures taken into account.
(3) Cost of new components.
(4) New costs.
(5) Excluded costs.
(6) Examples.
(d) Special rules regarding ownership.
(1) Qualified investment with respect to a
qualified facility or EST.
(2) Multiple owners.
(3) Section 761(a) election.
(4) Examples.
(e) Coordination rule for section 42 credits
and section 48E credits.
(f) Recapture.
(1) In general.
(2) Recapture event.
(i) In general.
(ii) Changes to the Annual Table.
(iii) Yearly determination.
(iv) Carryback and carryforward
adjustments.
(3) Recapture amount.
(i) In general.
(ii) Applicable recapture percentage.
(4) Recapture period.
(5) Increase in tax for recapture.
(g) Qualified progress expenditure election.
(h) Incremental cost.
(i) Cross references.
(j) Applicability date.
§ 1.48E–5 Greenhouse gas emissions rates
for qualified facilities under section 48E.
(a) In general.
(b) Definitions.
(c) Non-C&G Facilities.
(d) C&G Facilities.
(e) Use of methane from certain sources to
produce electricity.
(f) Carbon capture and sequestration.
(g) Annual publication of emissions rates.
(h) Provisional emissions rates.
(1) In general.
(2) Rate not established.
(3) Process for filing a PER petition.
(4) PER determination.
(5) Emissions value request process.
(6) LCA model for determining an
emissions value for C&G Facilities.
(7) Effect of PER.
(i) Determining anticipated greenhouse gas
emissions rate.
(1) In general.
(2) Examples of objective indicia.
(j) Reliance on Annual Table or Provisional
Emissions Rate.
(k) Substantiation.
(1) In general.
(2) Sufficient substantiation.

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(l) Applicability date.

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§ 1.48E–1
credit.

Clean electricity investment

(a) Overview—(1) In general. For
purposes of section 46 of the Internal
Revenue Code (Code), the section 48E
credit (defined in paragraph (a)(10) of
this section) is determined under
section 48E of the Code and the section
48E regulations (defined in paragraph
(a)(11) of this section). This paragraph
(a) provides definitions of terms that,
unless otherwise specified, apply for
purposes of section 48E, the section 48E
regulations, and any provision of the
Code or this chapter that expressly
refers to any provision of section 48E or
the section 48E regulations. Paragraph
(b) of this section provides rules for
determining the amount of the section
48E credit for any taxable year.
Paragraph (c) of this section provides
rules regarding the phase-out of the
section 48E credit. See § 1.48E–2 for
rules relating to qualified investments in
qualified facilities and energy storage
technology (EST) for purposes of the
section 48E credit. See § 1.48E–4 for
rules of general application for the
section 48E credit. See § 1.48E–5 for
rules to determine greenhouse gas
emissions rates for qualified facilities
under section 48E.
(2) Claim. For purposes of
determining a taxpayer’s section 48E
credit with respect to a qualified facility
or EST or a credit described in section
48E(b)(3)(C), the term claim means filing
a completed Form 3468, Investment
Credit, or any successor form(s), or other
relevant form as it relates to the credits
described in section 48E(b)(3)(C), with
the taxpayer’s timely filed (including
extensions) Federal income tax return or
Federal return, as appropriate, for the
taxable year in which the qualified
facility or EST is placed in service, and
for the taxable year in which the facility
for which the credit described in section
48E(b)(3)(C) is placed in service. It
includes making an election under
section 6417 or 6418 of the Code and 26
CFR 1.6417–1 and 1.6418–1,
respectfully, with respect to such
section 48E credit on the taxpayer’s
filed return.
(3) Code. The term Code means the
Internal Revenue Code.
(4) EST. The term EST for purposes of
the section 48E credit means energy
storage technology as defined in
§ 1.48E–2(g).
(5) kWh. The term kWh means
kilowatt hours.
(6) Qualified facility. The term
qualified facility for purposes of the
section 48E credit has the meaning
provided in § 1.48E–2(b).

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(7) Qualified investment with respect
to a qualified facility. The term qualified
investment with respect to a qualified
facility for purposes of the section 48E
credit has the meaning provided in
§ 1.48E–2(a).
(8) Qualified investment with respect
to EST. The term qualified investment
with respect to EST for purposes of the
section 48E credit has the meaning
provided in § 1.48E–2(g)(4).
(9) Secretary. The term Secretary
means the Secretary of the Treasury or
their delegate.
(10) Section 48E credit. The term
section 48E credit means the clean
electricity investment credit determined
under section 48E of the Code and the
section 48E regulations.
(11) Section 48E regulations. The term
section 48E regulations means this
section and §§ 1.48E–2 through 1.48E–5.
(12) Waste energy recovery property
(WERP). WERP is property that
generates electricity solely from heat
from buildings or equipment if the
primary purpose of such building or
equipment is not the generation of
electricity. Examples of buildings or
equipment the primary purpose of
which is not the generation of electricity
include, but are not limited to,
manufacturing plants, medical care
facilities, facilities on school campuses,
and associated equipment.
(b) Credit amount—(1) In general. For
purposes of section 46 of the Code, the
section 48E credit for any taxable year
is an amount equal to the applicable
percentage of the qualified investment
for such taxable year with respect to any
qualified facility and any EST.
(2) Applicable percentage. The term
applicable percentage means the base
rate described in paragraph (b)(3) of this
section or the alternative rate described
in paragraph (b)(4) of this section. The
applicable percentage may be increased
as provided in section 48E(a)(3)(A) and
paragraph (b)(5) of this section in the
case of a qualified facility that is located
in an energy community. Similarly, the
applicable percentage may be increased
as provided in section 48E(a)(3)(B) and
paragraph (b)(6) of this section in the
case of a qualified facility that satisfies
the domestic content requirements.
(3) Base rate. Under section
48E(a)(2)(A)(i) and (B)(i), in the case of
any qualified facility or EST that does
not satisfy the requirements provided in
section 48E(a)(2)(A)(ii) or (B)(ii), the
applicable percentage is the base rate,
which is 6 percent.
(4) Alternative rate. In the case of any
qualified facility or EST that satisfies
the prevailing wage and apprenticeship
requirements provided in section
48E(a)(2)(A)(ii) or (B)(ii), the applicable

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percentage is the alternative rate, which
is 30 percent.
(5) Energy communities increase in
credit rate—(i) In general. In the case of
any qualified facility or EST that is
placed in service within an energy
community (as defined in section
45(b)(11)(B)), the applicable percentage
under section 48E(a)(2) and paragraph
(b)(2) of this section will be increased by
the applicable credit rate increase
described in section 48E(a)(3)(A)(ii) and
paragraph (b)(5)(ii) of this section.
(ii) Applicable credit rate increase. In
the case of any qualified investment
with respect to a qualified facility or
EST to which the base rate is applicable,
the applicable credit rate increase is 2
percentage points, and with respect to
any qualified investment with respect to
a qualified facility or EST to which the
alternative rate is applicable, the
applicable credit rate increase is 10
percentage points.
(6) Domestic content increase in
credit rate—(i) In general. In the case of
any qualified facility or EST that
satisfies the requirements of section
45(b)(9)(B) (domestic content
requirement), the applicable percentage
under section 48E(a)(2) and paragraph
(b)(2) of this section will be increased by
the applicable credit rate increase
described in paragraph (b)(6)(ii) of this
section.
(ii) Applicable credit rate increase. In
the case of any qualified investment
with respect to a qualified facility or
EST to which the base rate is applicable,
2 percentage points, and with respect to
any qualified investment with respect to
a qualified facility or EST to which the
alternative rate is applicable, 10
percentage points.
(c) Credit phase-out—(1) In general.
The amount of the credit as determined
under section 48E(a) and paragraph (b)
of this section for any qualified facility
or EST, the construction of which
begins during a calendar year described
in section 48E(e)(2) and paragraph (c)(2)
of this section is equal to the product
of—
(i) The amount of the credit
determined under section 48E(a) and
paragraph (b) of this section without
regard to section 48E(e) and paragraph
(c) of this section; multiplied by
(ii) The phase-out percentage under
section 48E(e)(2) and paragraph (c)(2) of
this section.
(2) Phase-out percentage. The phaseout percentage under this paragraph
(c)(2) is equal to—
(i) For any qualified investment with
respect to any qualified facility or EST
the construction of which begins during
the first calendar year following the
applicable year, 100 percent;

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(ii) For any qualified investment with
respect to any qualified facility or EST
the construction of which begins during
the second calendar year following the
applicable year, 75 percent;
(iii) For any qualified investment with
respect to any qualified facility or EST
the construction of which begins during
the third calendar year following the
applicable year, 50 percent; and
(iv) For any qualified investment with
respect to any qualified facility or EST
the construction of which begins during
any calendar year subsequent to the
calendar year described in paragraph
(c)(2)(iii) of this section, 0 percent.
(3) Applicable year. For purposes of
this paragraph (c), the term applicable
year has the same meaning provided
under § 1.45Y–1(c)(3).
(d) Related taxpayers—(1) Definition.
For purposes of the section 48E credit,
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)).
(2) Related taxpayer rule. For
purposes of the section 48E credit,
related taxpayers are treated as one
taxpayer in determining whether a
taxpayer has made an investment in a
qualified facility or EST with respect to
which a section 48E credit may be
determined.
(e) Applicability date. This section
applies to qualified facilities and ESTs
placed in service after December 31,
2024, and during a taxable year ending
on or after January 15, 2025.

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§ 1.48E–2 Qualified investments in
qualified facilities and EST for purposes of
section 48E.

(a) Qualified investment with respect
to a qualified facility—(1) In general. A
qualified investment of a taxpayer for a
taxable year with respect to a qualified
facility is the total basis amount for the
taxable year with respect to the
qualified facility.
(2) Total basis amount. The total basis
amount is the sum of:
(i) The basis of any qualified property
that is a part of the qualified facility and
that is placed in service by the taxpayer
during the taxable year; plus
(ii) The amount of any expenditures
paid or incurred by the taxpayer for
qualified interconnection property (as
defined in section § 1.48E–4(a)(2)) in
connection with a qualified facility
which has a maximum net output of not
greater than five megawatts (as
measured in alternating current), that
was placed in service during the taxable
year of the taxpayer, and that are
properly chargeable to the capital
account.
(b) Qualified facility—(1) In general.
A qualified facility is a facility that:

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(i) Is used for the generation of
electricity, meaning that it is a net
generator of electricity taking into
account any electricity consumed by the
facility;
(ii) Is placed in service by the
taxpayer after December 31, 2024; and
(iii) Has an anticipated greenhouse
gas emissions rate of not greater than
zero (as determined under the rules
provided in § 1.48E–5).
(2) Placed in service—(i) In general. A
qualified facility is considered placed in
service in the earlier of:
(A) The taxable year in which, under
the taxpayer’s depreciation practice, the
period for depreciation with respect to
such qualified facility begins; or
(B) The taxable year in which the
qualified facility is placed in a
condition or state of readiness and
availability to produce electricity,
whether in a trade or business or in the
production of income. A qualified
facility in a condition or state of
readiness and availability to produce
electricity includes, but is not limited
to, components of property that are
acquired and set aside during the
taxable year for use as replacements for
a particular qualified facility (or
facilities) in order to avoid operational
time loss and equipment that is
acquired for a specifically assigned
function and is operational but is
undergoing testing to eliminate any
defects. However, components of
property acquired to be used in the
construction of a qualified facility are
not considered in a condition or state of
readiness and availability for a
specifically assigned function.
(ii) Qualified facility subject to § 1.48–
4 election to treat lessee as purchaser.
Notwithstanding paragraph (b)(2)(i) of
this section, a qualified facility with
respect to which an election is made
under section 50(d)(5) of the Code and
§ 1.48–4 to treat the lessee as having
purchased such qualified facility is
considered placed in service by the
lessor in the taxable year in which
possession is transferred to such lessee.
(c) Qualified property—(1) In general.
For purposes of this paragraph (c), the
term qualified property means all
property owned by the taxpayer that
meets all of the requirements of
paragraphs (c)(1)(i) through (iii) of this
section:
(i) The property is tangible personal
property (as defined in paragraph (e)(1)
of this section) or other tangible
property (as defined in paragraph (e)(2)
of this section) but only if such other
tangible property is used as an integral
part of the qualified facility;
(ii) Depreciation (or amortization in
lieu of depreciation) is allowable (as

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defined in paragraph (e)(3) of this
section) with respect to the property;
and
(iii) Either—
(A) The construction, reconstruction,
or erection of the property is completed
by the taxpayer (as defined in paragraph
(e)(4) of this section) with respect to the
property; or
(B) The taxpayer acquires the property
(as defined in paragraph (e)(5) of this
section) and the original use of the
property (as defined in paragraph (e)(6)
of this section) commences with the
taxpayer.
(2) Location of property. Any
component of qualified property that
otherwise satisfies the requirements of
this paragraph (c) is part of a qualified
facility regardless of where such
component is located.
(d) Property included in qualified
facility—(1) In general. A qualified
facility includes a unit of a qualified
facility (as defined in paragraph (d)(2) of
this section) owned by the taxpayer. A
qualified facility also includes
components of qualified property
owned by the taxpayer that are an
integral part (as defined in paragraph
(d)(3) of this section) of the qualified
facility. Any component of qualified
property that meets the requirements of
this paragraph (d) is part of a qualified
facility regardless of where such
component of qualified property is
located. A qualified facility does not
include any electrical transmission
equipment, such as electrical
transmission lines and towers, or any
equipment beyond the electrical
transmission stage. See § 1.48E–4(b)
regarding the Incremental Production
Rule and § 1.48E–4(c) for rules regarding
a retrofitted qualified facility (80/20
rule).
(2) Unit of a qualified facility—(i) In
general. For purposes of the section 48E
credit, a unit of a qualified facility
includes all functionally interdependent
components of property (as defined in
paragraph (d)(2)(ii) of this section)
owned by the taxpayer that are operated
together and that can operate apart from
other property to produce electricity. No
provision of this section, § 1.48E–1, or
§§ 1.48E–3 through 1.48E–5 uses the
term unit in respect of a qualified
facility with any meaning other than
that provided in this paragraph (d)(2)(i).
(ii) Functionally interdependent.
Components of property are
functionally interdependent if the
placing in service of each of the
components is dependent upon the
placing in service of the other
components to generate electricity.
(3) Integral part—(i) In general. For
purposes of the section 48E credit, a

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component of property owned by a
taxpayer is an integral part of a qualified
facility if it is used directly in the
intended function of the qualified
facility and is essential to the
completeness of such function. Property
that is an integral part of a qualified
facility is part of the qualified facility.
A taxpayer may not claim the section
48E credit for any property not owned
by the taxpayer that is an integral part
of the qualified facility owned by the
taxpayer.
(ii) Power conditioning and transfer
equipment. Power conditioning
equipment and transfer equipment are
integral parts of a qualified facility.
Power conditioning equipment
includes, but is not limited to,
transformers, inverters and converters,
which modify the characteristics of
electricity into a form suitable for use,
transmission, or distribution. Parts
related to the functioning or protection
of power conditioning equipment are
also treated as power conditioning
equipment and include, but are not
limited to, switches, circuit breakers,
arrestors, and hardware used to monitor,
operate, and protect power conditioning
equipment. Transfer equipment
includes components of property that
allow for the aggregation of electricity
generated by a qualified facility and
components of property that alter
voltage to permit electricity to be
transferred to a transmission or
distribution line. Transfer equipment
does not include transmission or
distribution lines. Examples of transfer
equipment include, but are not limited
to, wires, cables, and combiner boxes
that conduct electricity. Parts related to
the functioning or protection of transfer
equipment are also treated as transfer
equipment and may include items such
as current transformers used for
metering, electrical interrupters (such as
circuit breakers fuses, and other
switches) and hardware used to
monitor, operate, and protect transfer
equipment.
(iii) Roads. Roads that are integral to
the intended function of the qualified
facility such as onsite roads that are
used to operate and maintain the
qualified facility are an integral part of
a qualified facility. Roads used
primarily to access the site, or roads
used primarily for employee or visitor
vehicles, are not integral to the intended
function of the qualified facility, and
thus are not an integral part of a
qualified facility.
(iv) Fences. Fencing is not an integral
part of a qualified facility because it is
not integral to the intended function of
the qualified facility.

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(v) Buildings. Generally, buildings are
not integral parts of a qualified facility
because they are not integral to the
intended function of the qualified
facility. For purposes of section 48E, a
structure that is essentially an item of
machinery or equipment is not
considered a building. In addition, a
structure is not a building if it houses
components of property that are integral
to the intended function of the qualified
facility and if the use of the structure is
so closely related to the use of the
housed components of property therein
that the structure clearly can be
expected to be replaced if the
components of property it initially
houses are replaced.
(vi) Shared integral property. Multiple
qualified facilities (whether owned by
one or more taxpayers), including
qualified facilities with respect to which
a taxpayer has claimed a credit under
section 48E or another Federal income
tax credit, may include shared property
that may be considered an integral part
of each qualified facility so long as the
cost basis for the shared property is
properly allocated to each qualified
facility and the taxpayer only claims a
section 48E credit with respect to the
portion of the cost basis properly
allocable to a qualified facility for which
the taxpayer is claiming a section 48E
credit. The total cost basis of such
shared property divided among the
qualified facilities may not exceed 100
percent of the cost of such shared
property. In addition, a component of
property that is shared by a qualified
facility as defined by section 48E(b)(3)
(48E Qualified Facility) and a qualified
facility as defined in section 45Y(b)
(45Y Qualified Facility) that is an
integral part of both qualified facilities
will not affect the eligibility of the 48E
Qualified Facility for the section 48E
credit or the 45Y Qualified Facility for
the section 45Y credit.
(vii) Examples. This paragraph
(d)(3)(vii) provides examples illustrating
the rules of this paragraph (d).
(A) Example 1. Co-located qualified
facilities owned by the same taxpayer
that share integral property. X
constructs and owns a solar facility
(Solar Facility) and nearby also
constructs and owns a wind facility
(Wind Facility) that are each a qualified
facility. The Solar Facility and Wind
Facility each connect to a shared
transformer that steps up the electricity
produced by each qualified facilities to
electrical grid voltage before it is
transmitted to the electrical grid through
an intertie. X assigns 50% of the cost of
the shared transformer to the Solar
Facility and the Wind Facility,
respectively. The fact that the Solar

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Facility and Wind Facility share
property that is integral to both does not
impact the ability of X to claim a section
48E credit for both qualified facilities.
When X places the qualified facilities in
service, 50% of the cost of the
transformer is included in X’s basis in
each of the qualified facilities for
purposes of computing the section 48E
credit.
(B) Example 2. Co-located qualified
facilities owned by different taxpayers
that share integral property. X
constructs and owns a solar facility
(Solar Facility), and nearby Y constructs
and owns a wind facility (Wind Facility)
that are each a qualified facility. The
Solar Facility and the Wind Facility
both connect to a shared transformer
that steps up the electricity produced by
both qualified facilities to electrical grid
voltage before it is transmitted to the
electrical grid through an intertie. X and
Y each pay 50% of the cost of the shared
transformer. The fact that the Solar
Facility and Wind Facility share
property that is integral to both does not
impact the ability of X or Y to claim a
section 48E credit for their respective
qualified facilities. When X and Y place
their respective qualified facilities in
service, 50% of the cost of the
transformer is included in X’s and Y’s
basis in their respective qualified
facilities for purposes of computing the
section 48E credit.
(C) Example 3. Co-located qualified
facility and Energy Storage Technology
(EST) owned by the same taxpayer. X
constructs and owns a wind facility
(Wind Facility) that is co-located with
an EST that X also constructs and owns.
The Wind Facility and EST share
transfer equipment that is integral to
both. X assigns 50% of the cost of the
shared transfer equipment to the Wind
Facility and 50% of the cost to the EST.
The fact that the Wind Facility and EST
share property that is integral to both
does not impact the ability of X to claim
a section 48E credit for the Wind
Facility and the EST. X may include
50% of the cost of the transfer
equipment in its basis to determine a
section 48E credit for the Wind Facility
and the EST.
(D) Example 4. Co-located qualified
facility and Energy Storage Technology
owned by different taxpayers. X
constructs and owns a solar facility that
is a qualified facility (Solar Facility) and
is co-located with an EST constructed
and owned by Y. The Solar Facility and
EST share transfer equipment that is
integral to both. X and Y each incur
50% of the cost of the transfer
equipment. The fact that the Solar
Facility and EST share property that is
integral to both does not impact the

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ability of X to claim a section 48E credit
for the Solar Facility or Y to claim a
section 48E credit for the EST. When X
and Y place in service the Solar Facility
and EST, for purposes of computing the
section 48E credit, 50% of the cost of
the transfer equipment is included in
X’s basis in the Solar Facility and 50%
of the cost is included in Y’s basis in the
EST.
(E) Example 5. Qualified facility with
integral property owned by a different
taxpayer. X constructs and owns a
hydropower production facility that is a
qualified facility (Hydropower Facility).
The Hydropower Facility connects to a
dam owned by Y, a government entity,
that is an integral part of the
Hydropower Facility. X pays for upkeep
of the dam. The fact that X does not own
the dam does not impact the ability of
X to claim a section 48E credit for the
Hydropower Facility. When X places in
service the Hydropower Facility, for
purposes of computing the section 48E
credit, the cost incurred by X related to
the dam would not be included in X’s
basis in the Qualified Facility because X
does not own the dam.
(e) Definitions related to requirements
for qualified property—(1) Tangible
personal property. The term tangible
personal property means any tangible
property except land or improvements
thereto, such as buildings or other
inherently permanent structures
(including items that are structural
components of such buildings or
structures. Tangible personal property
includes all property (other than
structural components) that is contained
in or attached to a building. Further, all
property that is in the nature of
machinery (other than structural
components of a building or other
inherently permanent structure) is
considered tangible personal property
even though located outside a building.
Machinery located outside of a building
is qualified property if it is used for the
generation of electricity and the
components of machinery are
functionally interdependent. Local law
does not control whether property is
tangible property or is tangible personal
property for purposes of the section 48E
credit. Thus, tangible property may be
tangible personal property for purposes
of the section 48E credit even though
under local law the property is
considered a fixture and therefore is real
property under local law.
(2) Other tangible property. The term
other tangible property means tangible
property other than tangible personal
property (not including a building and
its structural components) that is used
as an integral part of furnishing
electricity by a person engaged in a

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trade or business of furnishing any such
service. Other tangible property may be
tangible property for purposes of the
section 48E credit even though under
local law the property is considered a
fixture and is therefore real property
under local law.
(3) Depreciation allowable—(i) In
general. For purposes of applying
paragraph (c) of this section,
depreciation (or amortization in lieu of
depreciation) (collectively,
depreciation) is allowable with respect
to the property if such property is of a
character subject to the allowance for
depreciation under section 167 of the
Code and the basis or cost of such
property is recovered using a method of
depreciation (for example, the straight
line method), which includes any
additional first year depreciation
deduction method of depreciation (for
example, under section 168(k) of the
Code). Further, if an adjustment with
respect to the Federal income tax or
Federal return, as appropriate, for such
taxable year requires the basis or cost of
such qualified property to be recovered
using a method of depreciation,
depreciation is allowable to the taxpayer
with respect to the qualified property.
(ii) Exclusions from allowable. For
purposes of paragraph (c) of this section,
depreciation is not allowable with
respect to a qualified facility if the basis
or cost of such qualified facility is not
recovered through a method of
depreciation but, instead, such basis or
cost is recovered through a deduction of
the full basis or cost of the qualified
facility in one taxable year (for example,
under section 179 of the Code).
(4) Construction, reconstruction, or
erection of the property. The term
construction, reconstruction, or erection
of the property means work performed
to construct, reconstruct, or erect
property either by the taxpayer or for
the taxpayer in accordance with the
taxpayer’s specifications.
(5) Acquisition of qualified property.
The term acquisition of qualified
property means a transaction by which
a taxpayer acquires the rights and
obligations to establish tax ownership of
the property for Federal tax purposes.
(6) Original use of the property. The
term original use of the property means
the first use to which the unit of
property is put, whether or not such use
is by the taxpayer.
(7) Retrofitted qualified facility. A
retrofitted qualified facility acquired by
the taxpayer will not be treated as being
put to original use by the taxpayer
unless the rules in § 1.48E–4(c)
regarding retrofitted qualified facilities
(80/20 Rule) apply. The question of
whether a qualified facility meets the

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80/20 Rule is a facts and circumstances
determination.
(f) Coordination with other credits—
(1) In general. The term qualified facility
(as defined in section 48E(b)(3)) and
paragraph (b) of this section does not
include any facility for which a credit
determined under section 45, 45J, 45Q,
45U, 45Y, 48, or 48A is allowed under
section 38 of the Code for the taxable
year or any prior taxable year. A
taxpayer that directly owns a qualified
facility (as defined in section 48E(b)(3))
for which the taxpayer is eligible for
both a section 48E credit and another
Federal income tax credit is eligible for
the section 48E credit only if the other
Federal income tax credit was not
allowed to the taxpayer with respect to
the qualified facility. Nothing in this
paragraph (f) precludes a taxpayer from
claiming a section 48E credit with
respect to a qualified facility (as defined
in section 48E(b)(3)) that is co-located
with another facility for which a credit
determined under section 45, 45J, 45Q,
45U, 45Y, 48, or 48A is allowed under
section 38 of the Code for the taxable
year or any prior taxable year.
(2) Allowed. For purposes of this
paragraph (f), the term allowed only
includes credits that taxpayers have
claimed on a Federal income tax return
or Federal return, as appropriate, and
that the Internal Revenue Service (IRS)
has not challenged in terms of the
taxpayer’s eligibility.
(3) Examples. This paragraph (f)(3)
provides examples illustrating the rules
provided in this paragraph (f).
(i) Example 1. Taxpayer claims a
section 45Y credit on a solar farm and
section 48E credit on co-located Energy
Storage Technology. X owns a solar
farm that is a qualifying facility (as
defined in § 1.45Y–2(a)) (Solar Qualified
Facility), and a co-located EST (Energy
Storage). The Energy Storage is not part
of the Solar Qualified Facility, and
therefore X may claim the section 45Y
credit based on the kWh of electricity
produced by the Solar Qualified
Facility, and X may also claim the
section 48E credit based on its qualified
investment in the Energy Storage.
(ii) Example 2. Different taxpayers
claim a section 45Y credit for a solar
farm and a co-located Energy Storage
Technology. X owns a solar farm that is
a qualifying facility (as defined in
§ 1.45Y–2(a)) (Solar Qualified Facility),
and Y owns a co-located EST (Energy
Storage). The Energy Storage is not part
of the Solar Qualified Facility, and
therefore, X may claim the section 45Y
credit based on the kWh of electricity
produced by the Solar Qualified
Facility, and Y may claim the section

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48E credit based on its qualified
investment in the Energy Storage.
(iii) Example 3. Taxpayer claiming a
section 48E credit; another credit is not
allowed. X owns a wind facility that
satisfies the requirements of a qualified
facility under section 48E as well as the
requirements of a qualified facility as
defined in § 1.45Y–2(a) under section
45Y. X claims a section 45Y credit with
respect to the wind facility. While a
credit may be available with regard to
the wind facility under section 48E,
because X has already claimed a section
45Y credit with respect to the wind
facility, a section 48E credit is not
allowed. Local law is not controlling for
purposes of determining whether
property is or is not tangible property or
tangible personal property. Thus,
tangible property may be personal
property for purposes of the energy
credit even though under local law the
property is considered a fixture and
therefore real property.
(iv) Example 4. Interaction of section
48E and section 45Q credits for single
qualified facility. X owns a qualified
facility (Facility A) that includes carbon
capture equipment, which is needed for
the facility to meet the zero greenhouse
gas requirement, so it is functionally
interdependent to the production of
electricity by the Facility A. X uses the
carbon capture equipment to capture
and utilize (as described in section
45Q(f)(5)) qualified carbon dioxide and
claimed a section 45Q credit in the
current taxable year. As a result, X
cannot claim a section 48E credit for its
48E Facility A because a qualified
facility does not include a facility for
which a credit determined under
section 45Q is allowed.
(v) Example 5. Interaction of section
48E and section 45Q credits for colocated qualified facilities. Assume the
same facts as in paragraph (f)(3)(iv) of
this section (Example 4), except that X
owns a co-located qualified facility
(Facility B) that also includes carbon
capture equipment, which is needed for
the facility to meet the zero greenhouse
gas requirement, so it is functionally
interdependent to the production of
electricity by the Facility B. X uses the
carbon capture equipment to capture
and utilize (as described in section
45Q(f)(5)) qualified carbon dioxide, but
does not claim a section 45Q credit with
respect to the Facility B. While X
claimed a section 45Q credit in the
current taxable year for the Facility A
(see Example 4), the Facility B is not
part of the Facility A, and, therefore, X
may claim the section 48E credit for its
Facility B.
(g) EST—(1) Property included in
EST. An EST includes a unit of energy

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storage technology (unit of EST) (as
defined in paragraph (g)(2) of this
section) that meets the requirements of
paragraph (g)(2)(ii) of this section. An
EST also includes property owned by
the taxpayer that is an integral part (as
defined in paragraph (g)(3) of this
section) of the EST. An EST does not
include equipment that is an addition or
modification to an existing EST. For
purposes of the section 48E credit, EST
includes electrical energy storage
property (as described in paragraph
(g)(6)(i) of this section), thermal energy
storage property (as described in
paragraph (g)(6)(ii) of this section), and
hydrogen energy storage property (as
described in paragraph (g)(6)(iii) of this
section).
(2) Unit of EST—(i) In general. For
purposes of the section 48E credit, a
unit of EST includes all functionally
interdependent components of property
(as defined in paragraph (g)(2)(ii) of this
section) owned by the taxpayer that are
operated together and that can operate
apart from other property to perform the
intended function of the EST. No
provision of this section, § 1.48E–1, or
§§ 1.48E–3 through 1.48E–5 uses the
term unit in respect of an EST with any
meaning other than that provided in this
paragraph (g)(2)(i).
(ii) Functionally interdependent.
Components of property are
functionally interdependent if the
placing in service of each of the
components is dependent upon the
placing in service of each of the other
components to perform the intended
function of the EST.
(3) Integral part. For purposes of the
section 48E credit, property owned by a
taxpayer is an integral part of an EST
owned by the same taxpayer if it is used
directly in the intended function of the
EST and is essential to the completeness
of such function. Property that is an
integral part of an EST is part of that
EST. A taxpayer may not claim the
section 48E credit for any property not
owned by the taxpayer that is an
integral part of EST owned by the
taxpayer.
(4) Qualified investment with respect
to EST. The qualified investment with
respect to any EST for any taxable year
is the basis of any EST placed in service
by the taxpayer during such taxable
year.
(5) Placed in service—(i) In general.
An EST is considered placed in service
in the earlier of:
(A) The taxable year in which, under
the taxpayer’s depreciation practice, the
period for depreciation with respect to
such EST begins; or
(B) The taxable year in which the EST
is placed in a condition or state of

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readiness and availability for the
intended function of the EST, whether
in a trade or business or in the
production of income. An EST in a
condition or state of readiness and
availability for its intended function
includes, but is not limited to,
components of property that are
acquired and set aside during the
taxable year for use as replacements for
a particular EST (or ESTs) in order to
avoid operational time loss and
equipment that is acquired for a
specifically assigned function and is
operational but is undergoing testing to
eliminate any defects. However,
components of property acquired to be
used in the construction of an EST are
not considered in a condition or state of
readiness and availability for a
specifically assigned function.
(ii) EST subject to § 1.48–4 election to
treat lessee as purchaser.
Notwithstanding paragraph (g)(5)(i) of
this section, EST with respect to which
an election is made under section
50(d)(5) of the Code and § 1.48–4 to treat
the lessee as having purchased such
EST is considered placed in service by
the lessor in the taxable year in which
possession is transferred to such lessee.
(6) Types of EST—(i) Electrical energy
storage property. Electrical energy
storage property is property (other than
property primarily used in the
transportation of goods or individuals
and not for the production of electricity)
that receives, stores, and delivers energy
for conversion to electricity, and has a
nameplate capacity of not less than 5
kWh. For example, subject to the
exclusion for property primarily used in
the transportation of goods or
individuals, electrical energy storage
property includes but is not limited to
rechargeable electrochemical batteries of
all types (such as lithium-ion, vanadium
redox flow, sodium sulfur, and leadacid); ultracapacitors; physical storage
such as pumped storage hydropower,
compressed air storage, flywheels; and
reversible fuel cells.
(ii) Thermal energy storage property—
(A) In general. Thermal energy storage
property is property comprising a
system that is directly connected to a
heating, ventilation, or air conditioning
(HVAC) system; removes heat from, or
adds heat to, a storage medium for
subsequent use; and provides energy for
the heating or cooling of the interior of
a residential or commercial building.
Thermal energy storage property
includes equipment and materials, and
parts related to the functioning of such
equipment, to store thermal energy for
later use to heat or cool, or to provide
hot water for use in heating a residential
or commercial building. It does not

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Federal Register / Vol. 90, No. 9 / Wednesday, January 15, 2025 / Rules and Regulations
include property that transforms other
forms of energy into heat in the first
instance. Property that ‘‘removes heat
from, or adds heat to, a storage medium
for subsequent use’’ is property that is
designed with the particular purpose of
substantially altering the time profile of
when heat added to or removed from
the thermal storage medium can be used
for heating or cooling of the interior of
a residential or commercial building.
Paragraph (g)(6)(ii)(B) of this section
provides a safe harbor for determining
whether a thermal energy storage
property has such a purpose. Thermal
energy storage property does not
include a swimming pool, combined
heat and power system property (as
defined in section 45Y(g)(2)), or a
building or its structural components.
For example, thermal energy storage
property includes, but is not limited to,
a system that adds heat to bricks heated
to high temperatures that later use this
stored energy to heat a building through
the HVAC system; thermal ice storage
systems that use electricity to run a
refrigeration cycle to produce ice that is
later connected to the HVAC system as
an exchange medium for air
conditioning a building, heat pump
systems that store thermal energy in an
underground tank, an artificial pit, an
aqueous solution, a borehole field, or a
solid-liquid phase change material to be
extracted for later use for heating and/
or cooling; and air-to-water heat pump
systems with a water storage tank.
However, consistent with § 1.48–14(d),
if thermal energy storage property, such
as a heat pump system, includes
equipment, such as a heat pump, that
also serves a purpose in an HVAC
system that is installed in connection
with the thermal energy storage
property, the taxpayer’s qualified
investment with respect to the thermal
energy storage property includes the
total cost of the thermal energy storage
property and HVAC system less the cost
of an HVAC system without thermal
storage capacity that would meet the
same functional heating or cooling
needs as the heat pump system with a
storage medium, other than time
shifting of heating or cooling. See
§ 1.48–14(h) for application of the
Incremental Cost Rule.
(B) Safe harbor. A thermal energy
storage property will be deemed to have
the purpose of substantially altering the
time profile of when heat added to or
removed from the thermal storage
medium can be used to heat or cool the
interior of a residential or commercial
building if that thermal energy storage
property is capable of storing energy
that is sufficient to provide heating or

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cooling of the interior of a residential or
commercial building for a minimum of
one hour.
(iii) Hydrogen energy storage
property. Hydrogen energy storage
property is property (other than
property primarily used in the
transportation of goods or individuals
and not for the production of electricity)
that stores hydrogen and has a
nameplate capacity of not less than 5
kWh, equivalent to 0.127 kg of hydrogen
or 52.7 standard cubic feet (scf) of
hydrogen. Hydrogen energy storage
property includes, but is not limited to,
above ground storage tanks,
underground storage facilities, and
associated compressors. Property that is
an integral part of hydrogen energy
storage property includes, but is not
limited to, hydrogen liquefaction
equipment and gathering and
distribution lines within a hydrogen
energy storage property.
(7) Modification of EST. With respect
to an electrical energy storage property
or a hydrogen energy storage property,
modified as set forth in this paragraph
(g)(7), such property will be treated as
an electrical energy storage property (as
described in paragraph (g)(6)(i) of this
section) or a hydrogen energy storage
property (as described in paragraph
(g)(6)(iii) of this section), except that the
basis of any existing electrical energy
storage property or hydrogen energy
storage property prior to such
modification is not taken into account
for purposes of this paragraph (g)(7) and
section 48E. This paragraph (g)(7)
applies to any electrical energy storage
property and hydrogen energy storage
property that either:
(i) Was placed in service before
August 16, 2022, and would be
described in section 48(c)(6)(A)(i),
except that such property had a
nameplate capacity of less than 5 kWh
and is modified in a manner that such
property (after such modification) has a
nameplate capacity of not less than 5
kWh; or
(ii) Is described in section
48(c)(6)(A)(i) and is modified in a
manner that such property (after such
modification) has an increase in
nameplate capacity of not less than 5
kWh. The increase in nameplate
capacity is equal to the difference
between nameplate capacity
immediately after the modification and
nameplate capacity immediately prior to
the modification.
(h) Applicability date. This section
applies to qualified facilities and EST
placed in service after December 31,
2024, and during a taxable year ending
on or after January 15, 2025.

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§ 1.48E–3 Rules relating to the increased
credit for prevailing wage and
apprenticeship.

(a) In general. If any qualified facility
or EST satisfies the requirements in
paragraph (b) of this section, the
applicable percentage used for
calculating the amount of the credit for
a qualified investment determined
under section 48E(a) for the taxable year
equals 30 percent.
(b) Qualified facility or EST
requirements. A qualified facility or EST
satisfies the requirements of this
paragraph (b) if it is a facility described
in one of paragraphs (b)(1) through (6)
of this section:
(1) A qualified facility with a
maximum net output of less than one
megawatt of electrical energy (as
measured in alternating current) based
on the nameplate capacity as provided
in paragraph (c) of this section (One
Megawatt Exception);
(2) A qualified facility the
construction of which began prior to
January 29, 2023;
(3) A qualified facility that meets the
prevailing wage requirements of section
48E(d)(3) and §§ 1.45–7(a)(2) and (3)
and (b) through (d) and 1.48–13(c), the
apprenticeship requirements of section
45(b)(8) and § 1.45–8, and the
recordkeeping and reporting
requirements of § 1.45–12;
(4) An EST with a capacity of less
than one megawatt based on the
nameplate capacity as provided in
paragraph (c) of this section (EST One
Megawatt Exception);
(5) An EST the construction of which
began prior to January 29, 2023; or
(6) An EST that satisfies the
prevailing wage requirements of section
48E(d)(3) and §§ 1.45–7(a)(2) and (3)
and (b) through (d) and 1.48–13(c), the
apprenticeship requirements of section
45(b)(8) and § 1.45–8, and the
recordkeeping and reporting
requirements of § 1.45–12.
(c) Nameplate capacity for purposes
of the One Megawatt Exception—(1)
Qualified facilities. For purposes of
paragraph (b)(1) of this section, whether
a qualified facility has a maximum net
output of less than 1 megawatt (MW) of
electrical energy (as measured in
alternating current) is determined based
on the nameplate capacity of the
facility. If a qualified facility has
integrated operations (as defined in
paragraph (c)(4)(i) of this section) with
one or more other qualified facilities,
then the aggregate nameplate capacity of
the qualified facilities is used for the
purposes of determining if the qualified
facilities satisfy the One Megawatt
Exception. If applicable, taxpayers
should use the International Standard

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Organization (ISO) conditions to
measure the maximum electrical
generating output of a facility.
(2) Nameplate capacity for qualified
facilities that generate in direct current
for purposes of the One Megawatt
Exception. For qualified facilities that
generate electricity in direct current, the
taxpayer determines the maximum net
output (in alternating current) of each
unit of qualified facility by using the
lesser of:
(i) The sum of the nameplate
generating capacities within the unit of
qualified facility in direct current,
which is deemed the nameplate
generating capacity of the unit of
qualified facility in alternating current;
or
(ii) The nameplate capacity of the first
component of property that inverts the
direct current electricity into alternating
current.
(3) EST—(i) In general. Paragraphs
(c)(3)(ii) through (iv) of this section
provide rules for applying the EST One
Megawatt Exception described in
paragraph (b)(4) of this section to
different types of energy storage
properties. If the EST has integrated
operations (as defined in paragraph
(c)(4)(ii) of this section) with one or
more other ESTs, then the aggregate
nameplate capacity of the ESTs is used
for the purposes of the EST One
Megawatt Exception. If applicable,
taxpayers should use the ISO conditions
to measure the maximum net output of
an EST.
(ii) Electrical energy storage property.
In the case of electrical energy storage
property (as defined in § 1.48E–
2(g)(6)(i)), the EST One Megawatt
Exception is determined by using the
storage device’s maximum net output. If
the output of electrical energy storage
property is in direct current, taxpayer
should apply the rules of paragraph
(c)(2) of this section.
(iii) Thermal energy storage property.
In the case of thermal energy storage
property (as defined in § 1.48E–
2(g)(6)(ii)), the EST One Megawatt
Exception is determined by using the
property’s maximum net output. The
maximum net output in MW is
calculated by using a conversion
whereby one MW is equal to 3.4 million
British Thermal Units per hour (mmBtu/
hour) for heating and 284 tons for
cooling (Btu per hour/3,412,140 = MW).
The maximum net output is the
maximum instantaneous rate of
discharge and is determined based on
the nameplate capacity of the
equipment that generates or distributes
thermal energy for productive use
(including distributing the thermal
energy from the storage medium). For

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purposes of determining the maximum
net output of thermal energy storage
property, if the nameplate capacity of
the thermal energy storage is not
available, the nameplate capacity of the
equipment delivering thermal energy to
the thermal energy storage may be used.
For thermal energy storage property
distributing thermal energy to a building
or buildings, the nameplate capacity can
be assessed as either the aggregate
maximum thermal capacity of all
individual heating or cooling elements
within the building or buildings, or as
the maximum thermal output that the
thermal energy storage property is
capable of delivering to a building or
buildings at any given moment. The
maximum thermal capacity of an entire
thermal energy storage property is
capable of delivering at any given
moment does not take into account the
capacity of redundant equipment if such
equipment is not operated when the
system is at maximum output during
normal operation. For thermal energy
storage property and other energy
property that generates or distributes
thermal energy for a productive use, the
maximum thermal capacity that the
entire system is capable of delivering is
considered to be the greater of the rate
of cooling or the rate of heating of the
aggregate of the nameplate capacity of
the equipment distributing energy for
productive use, including distributing
the thermal energy from the thermal
energy storage medium to the building
or buildings. If such nameplate capacity
is unavailable, in the case of thermal
energy storage property only, the
maximum thermal capacity may instead
be considered to be the greater of the
rate of cooling or the rate of heating of
the aggregate of the nameplate capacity
of all the equipment delivering energy
to the thermal energy storage property
in the project.
(iv) Hydrogen energy storage property.
In the case of a hydrogen energy storage
property (as defined in § 1.48E–
2(g)(6)(iii)), the EST One Megawatt
Exception is determined by using the
property’s maximum net output. The
maximum net output in MW is
calculated by using a conversion
whereby one MW is equal to 3.4
mmBtu/hour of hydrogen or
equivalently 10,500 standard cubic feet
(scf) per hour of hydrogen.
(4) Integrated operations—(i) One
Megawatt Exception. Solely for the
purposes of the One Megawatt
Exception described in paragraph (b)(1)
of this section, a qualified facility is
treated as having integrated operations
with any other qualified facility of the
same technology type if the facilities
are:

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(A) Owned by the same or related
taxpayers;
(B) Placed in service in the same
taxable year; and
(C) Transmit electricity generated by
the facilities through the same point of
interconnection or, if the facilities 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.
(ii) EST One Megawatt Exception.
Solely for the purposes of the EST One
Megawatt Exception described in
paragraph (b)(4) of this section, an EST
is treated as having integrated
operations with any other EST of the
same technology type if the ESTs are:
(A) Owned by the same or related
taxpayers;
(B) Placed in service in the same
taxable year; and
(C) Transmit energy through the same
point of interconnection or, if the ESTs
are not grid-connected or are providing
storage directly to an end user behind a
utility meter, are able to support the
same end user. In the case of EST
described in paragraphs (c)(3)(iii) and
(iv) of this section, which use the same
piping and distribution systems for the
respective type of EST.
(d) Transition waiver of penalty for
prevailing wage requirements. For
purposes of the transition waiver
described in § 1.48–13(c)(2) (by
reference to § 1.45–7(c)(6)(iii)), the
penalty payment required by § 1.45–
7(c)(1)(ii) to cure a failure to satisfy the
prevailing wage requirements in
paragraph (b)(3) or (6) of this section is
waived with respect to a laborer or
mechanic who performed work in the
construction, alteration, or repair of an
energy project on or after January 29,
2023, and prior to January 15, 2025, if
the taxpayer relied upon Notice 2022–
61, 2022–52 I.R.B. 560, or the PWA
proposed regulations (REG–100908–23)
(88 FR 60018), corrected in 88 FR 73807
(Oct. 27, 2023), corrected in 89 FR
25550 (April 11, 2024), to determine
when the activities of any laborer or
mechanic became subject to the
prevailing wage requirements, and the
taxpayer makes the correction payments
required by § 1.45–7(c)(1)(i) with respect
to such laborer and mechanics within
180 days of January 15, 2025.
(e) No alteration or repair during
recapture period described in § 1.48–
13(c)(3). If no alteration or repair work
occurs during the five-year recapture
period, the taxpayer is deemed to satisfy
the prevailing wage requirements
described in paragraph (b)(3) or (6) of
this section with respect to such taxable
year.

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(f) Applicability date. This section
applies to qualified facilities and
qualified ESTs placed in service in
taxable years ending after January 15,
2025, and the construction of which
begins after March 17, 2025. Taxpayers
may apply this section to qualified
facilities and qualified ESTs placed in
service in taxable years ending on or
after January 15, 2025, the construction
of which begins before January 15, 2025,
provided that taxpayers follow this
section in its entirety and in a consistent
manner.

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§ 1.48E–4

Rules of general application.

(a) Qualified interconnection costs
included in certain lower-output
qualified facilities—(1) In general. For
purposes of determining the section 48E
credit (as defined in § 1.48E–1(a)), the
qualified investment with respect to a
qualified facility (as defined in § 1.48E–
2(a)) includes amounts paid or incurred
by the taxpayer for qualified
interconnection property (as defined in
paragraph (a)(2) of this section), in
connection with a qualified facility (as
defined in § 1.48E–2(a)) that has a
maximum net output of not greater than
5 MW (as measured in alternating
current) as described in paragraph (a)(3)
of this section (Five-Megawatt
Limitation). The qualified
interconnection property must provide
for the transmission or distribution of
the electricity produced by a qualified
facility and must be properly chargeable
to the capital account of the taxpayer as
reduced by paragraph (a)(6) of this
section. If the costs borne by the
taxpayer are reduced by utility or nonutility payments, Federal income tax
principles may require the taxpayer to
reduce the amounts of costs treated as
paid or incurred for qualified
interconnection property to determine a
section 48E credit.
(2) Qualified interconnection
property. For purposes of this paragraph
(a), the term qualified interconnection
property means, with respect to a
qualified facility, any tangible property
that is part of an addition, modification,
or upgrade to a transmission or
distribution system that is required at or
beyond the point at which the qualified
facility interconnects to such
transmission or distribution system in
order to accommodate such
interconnection; is either constructed,
reconstructed, or erected by the
taxpayer (as defined in § 1.48E–2(e)(4)),
or for which the cost with respect to the
construction, reconstruction, or erection
of such property is paid or incurred by
such taxpayer; and the original use (as
defined in § 1.48E–2(e)(6)) of which,
pursuant to an interconnection

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agreement (as defined in paragraph
(a)(4) of this section), commences with
a utility (as defined in paragraph (a)(5)
of this section). For purposes of
determining the original use of
interconnection property in the context
of a sale-leaseback or lease transaction,
the principles of section 50(d)(4) of the
Internal Revenue Code (Code) must be
taken into account, as applicable, with
such original use determined on the
date of the sale-leaseback or lease.
Qualified interconnection property is
not part of a qualified facility. As a
result, qualified interconnection
property is not taken into account in
determining whether a qualified facility
satisfies the requirements for the
increase in credit rate for energy
communities provided in section
48E(a)(3)(A) of the Code, the increase in
credit rate for domestic content
referenced in section 48E(a)(3)(B) (by
reference to the rules of section
48(a)(12)) or the increase in credit rate
for prevailing wage requirements
referenced in section 48E(d)(3) and
apprenticeship requirements referenced
in section 48E(d)(4).
(3) Five-Megawatt Limitation—(i) In
general. For purposes of this paragraph
(a), the Five-Megawatt Limitation is
measured at the level of the qualified
facility in accordance with section
48E(b)(1)(B). The maximum net output
of a qualified facility is measured only
by nameplate generating capacity (in
alternating current) of the unit of
qualified facility, which does not
include the nameplate capacity of any
integral property, at the time the
qualified facility is placed in service.
The nameplate generating capacity of
the unit of qualified facility is measured
independently from any other qualified
facilities that share the same integral
property.
(ii) Nameplate capacity for purposes
of the Five-Megawatt Limitation. For
purposes of paragraph (a)(1) of this
section, the determination of whether a
qualified facility has a maximum net
output of not greater than 5 MW (as
measured in alternating current) is
based on the nameplate capacity. The
nameplate capacity for purposes of the
Five-Megawatt Limitation is the
maximum electrical generating output
in megawatts that the unit of qualified
facility is capable of producing on a
steady state basis and during continuous
operation under standard conditions, as
measured by the manufacturer and
consistent with the definition of
nameplate capacity provided in 40 CFR
96.202. If applicable, taxpayers should
use the International Standard
Organization (ISO) conditions to
measure the maximum electrical

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4119

generating output of a unit of qualified
facility.
(iii) Nameplate capacity for qualified
facilities that generate in direct current
for purposes of the Five-Megawatt
Limitation. For qualified facilities that
generate electricity in direct current, a
taxpayer determines whether a qualified
facility has a maximum net output of
not greater than five MW (in alternating
current) by using the lesser of:
(A) The sum of the nameplate
generating capacities within the unit of
qualified facility property in direct
current, which is deemed the nameplate
generating capacity of the unit of
qualified facility property in alternating
current; or
(B) The nameplate capacity of the first
component of the qualified facility that
inverts the direct current electricity into
alternating current.
(4) Interconnection agreement. For
purposes of this paragraph (a), the term
interconnection agreement means an
agreement with a utility for the
purposes of interconnecting the
qualified facility owned by such
taxpayer to the transmission or
distribution system of the utility. In the
case of the election provided under
section 50(d)(5) (relating to certain
leased property), the term includes an
agreement regarding a qualified facility
leased by such taxpayer.
(5) Utility. For purposes of this
paragraph (a), the term utility means the
owner or operator of an electrical
transmission or distribution system that
is subject to the regulatory authority of
a State or political subdivision thereof,
any agency or instrumentality of the
United States, a public service or public
utility commission or other similar body
of any State or political subdivision
thereof, or the governing or ratemaking
body of an electric cooperative.
(6) Reduction to amounts chargeable
to capital account. In the case of costs
paid or incurred for qualified
interconnection property as defined in
paragraph (a)(2) of this section, amounts
otherwise chargeable to capital account
with respect to such costs must be
reduced under rules of section 50(c)
(including section 50(c)(3)).
(7) Examples. This paragraph (a)(7)
provides examples illustrating the
application of the general rules
provided in paragraph (a)(1) of this
section and Five-Megawatt Limitation
provided in this paragraph (a).
(i) Example 1. Application of FiveMegawatt Limitation to an
interconnection agreement for qualified
facilities owned by taxpayer. X places in
service two solar qualified facilities (48E
Facilities) each with a maximum net
output of 5 MW (as measured in

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alternating current by using the
nameplate capacity of an inverter,
which is the first component of property
attached to each of the 48E Facilities
that inverts the direct current electricity
into alternating current). The two 48E
Facilities each have their own inverter,
which is integral property to each
facility, and share a step-up transformer,
which is integral property to both
facilities. As part of the development of
the 48E Facilities, interconnection costs
are required by the utility to modify and
upgrade the transmission system at or
beyond the common intertie to the
utility’s transmission system to
accommodate the interconnection. X
has an interconnection agreement with
the utility that allows for a maximum
output of 10 MW (as measured in
alternating current). The
interconnection agreement provides the
total cost to X of the qualified
interconnection property. X may
include the costs paid or incurred by X,
respectively, for qualified
interconnection property subject to the
terms of the interconnection agreement,
to calculate X’s section 48E credit for
each of the 48E Facilities because each
qualified facility has a maximum net
output of not greater than 5 MW
(alternating current).
(ii) Example 2. Application of FiveMegawatt Limitation to an
interconnection agreement for qualified
facilities owned by separate taxpayers.
X places in service a solar farm that is
a qualified facility (as defined in
§ 1.48E–2(a)) (Solar Qualified Facility)
with a maximum net output of 5 MW (as
measured in alternating current by using
the nameplate capacity of the first
component of property attached to the
Solar Qualified Facility that inverts the
direct current electricity into alternating
current). The Solar Qualified Facility
includes an inverter, which is integral
property. Y places in service a wind
facility (as defined in § 1.48E–2(a))
(Wind Qualified Facility), with a
maximum net output of 5 MW (as
measured in alternating current by using
the nameplate capacity of the first
component of property attached to the
Wind Qualified Facility that inverts the
direct current electricity into alternating
current). The Solar Qualified Facility
and the Wind Qualified Facility share a
step-up transformer, which is integral to
both facilities. As part of the
development of the Solar Qualified
Facility and Wind Qualified Facility,
interconnection costs are required by
the utility to modify and upgrade the
transmission system at or beyond the
common intertie to the utility’s
transmission system to accommodate

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the interconnection. X and Y are party
to the same interconnection agreement
with the utility that allows for a
maximum output of 10 MW (as
measured in alternating current). The
interconnection agreement provides the
total cost of the qualified
interconnection property to X and Y. X
and Y may include the costs paid or
incurred by X and Y, respectively, for
qualified interconnection property
subject to the terms of the
interconnection agreement, to calculate
their respective section 48E credits for
the Solar Qualified Facility and the
Wind Qualified Facility because each
has a maximum net output of not greater
than 5 MW (alternating current).
(iii) Example 3. Application of FiveMegawatt Limitation to an
interconnection agreement for a single
qualified facility. X develops three solar
farms (Solar Qualified Facilities) located
in close proximity. Each of the Solar
Qualified Facilities is a unit of qualified
facility that has a maximum net output
of 4 MW. The nameplate capacity of
each Solar Qualified Facility is
determined by using the sum of the
nameplate generating capacities within
the unit of each Solar Qualified Facility
in direct current, which is deemed the
nameplate generating capacity of each
Solar Qualified Facility in alternating
current. Electricity from the three Solar
Qualified Facilities feeds into a single
gen-tie line and a common point of
interconnection with the transmission
system. X is party to a separate
interconnection agreement with the
utility for each of the Solar Qualified
Facilities and each interconnection
agreement allows for a maximum output
of 10 MW (as measured in alternating
current). X may include the costs it paid
or incurred for qualified interconnection
property for each of the Solar Qualified
Facilities to calculate its section 48E
credit for each of the Solar Qualified
Facilities, subject to the terms of each
interconnection agreement, because
each of the Solar Qualified Facilities has
a maximum net output of not greater
than 5 MW (in alternating current). X
cannot include more than the total costs
X paid or incurred for the qualified
interconnection property in calculating
the aggregate section 48E credit amount
for the Solar Qualified Facilities.
(iv) Example 4. Utility payment
reducing costs borne by taxpayer. In
year 1, X places in service a solar
facility (Solar Qualified Facility) with a
maximum net output of 3 MW (as
measured in alternating current) by
using the nameplate capacity of the
inverter attached to the solar facility,
which is the first component of the
qualified facility that inverts the direct

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current electricity into alternating
current. X is party to an interconnection
agreement with a utility for the purpose
of connecting the Solar Qualified
Facility to the transmission or
distribution system of the utility.
Pursuant to the interconnection
agreement, X pays $1 million to the
utility, and the utility places in service
qualified interconnection property. In
year 1, X had no reasonable expectation
of any payment from the utility or other
parties with respect to the qualified
interconnection property. The $1
million is properly chargeable to the
capital account of X, subject to
paragraph (a)(6) of this section. X
properly includes the $1 million paid to
the utility in determining its credit
under section 48E for Year 1. In Year 4,
taxpayer Y enters into an agreement
with the utility under which Y pays the
utility $100,000 for the use of qualified
interconnection property placed in
service by the utility pursuant to the
interconnection agreement between X
and the utility. The utility pays
$100,000 to X. Under these
circumstances, the payment from the
utility in year 4 would not require X to
reduce the amount treated as paid or
incurred for the qualified
interconnection property for the
purpose of determining the section 48E
credit in year 1; instead X would treat
the payment as income.
(v) Example 5. Non-utility payment
reducing costs borne by taxpayer. The
facts in year 1 are the same as in
paragraph (a)(7)(iii) of this section
(Example 3). In Year 4, taxpayer Y
enters into an agreement with the utility
under which Y pays X $100,000 for the
use of qualified interconnection
property placed in service by the utility
pursuant to the interconnection
agreement between X and the utility. Y
pays $100,000 to X. In year 1, X had no
reasonable expectation of any payment
from Y for subsequent agreements with
Y or other parties with respect to the
qualified interconnection property.
Under these circumstances, the payment
from Y in year 4 would not require X
to reduce the amount treated as paid or
incurred for the qualified
interconnection property for the
purpose of determining the section 48E
credit in year 1; instead X would treat
the payment as income.
(b) Expansion of facility; Incremental
production (Incremental Production
Rule)—(1) In general. Solely for
purposes of this paragraph (b), the term
qualified facility includes either a new
unit or an addition of capacity placed in
service after December 31, 2024, in
connection with a facility described in
section 48E(b)(3)(A) (without regard to

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section 48E(b)(3)(A)(ii)), which was
placed in service before January 1, 2025,
but only to the extent of the increased
amount of electricity produced at the
facility by reason of such new unit or
addition of capacity. This paragraph (b)
is only applicable to an addition of
capacity or new unit that would not
otherwise qualify as a separate qualified
facility as defined in section 48E(b)(3).
A new unit or an addition of capacity
that meets the requirements of this
paragraph (b) will be treated as a
separate qualified facility. For purposes
of this paragraph (b), a new unit or an
addition of capacity requires the
addition or replacement of qualified
property (as defined in § 1.48E–2(e)),
including any new or replacement
integral property, added to a facility
necessary to increase capacity. For
purposes of assessing the One Megawatt
Exception provided in section
48E(a)(2)(A)(ii)(I), the maximum net
output for a new unit or an addition of
capacity is the sum of the capacity of
the added qualified facility and the
capacity of the facility to which the
qualified facility was added, as
determined under § 1.48E–3(c) and
paragraph (b)(2) of this section.
(2) Measurement standard. For
purposes of this paragraph (b), taxpayers
must use one of the measurement
standards described in paragraph
(b)(2)(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 (b)(2)(ii) of this
section if the taxpayer is able to use the
measurement standard described in
paragraph (b)(2)(i) of this section:
(i) Modified or amended facility
operating licenses from the Federal
Energy Regulatory Commission (FERC)
or the Nuclear Regulatory Commission
(NRC), or related reports prepared by
FERC or NRC as part of the licensing
process;
(ii) Nameplate capacity certified
consistent with generally accepted
industry standards, such as the
International Standard Organization
(ISO) conditions to measure the
nameplate capacity of the facility
consistent with the definition of
nameplate capacity provided in 40 CFR
96.202; or
(iii) A measurement standard
prescribed by the Secretary in guidance
published in the Internal Revenue
Bulletin (see § 601.601 of this chapter).
(3) Special rule for restarted facilities.
Solely for purposes of this paragraph
(b), a facility that is decommissioned or
in the process of decommissioning and
restarts can be considered to have
increased capacity from a base of zero

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if the conditions described in each of
paragraphs (b)(3)(i) through (iv) of this
section 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,
FERC or NRC);
(iii) The restarted facility must be
eligible to restart based on an operating
license issued by either FERC or NRC;
and
(iv) The existing facility may not have
ceased operations for the purpose of
qualifying for the special rule for
restarted facilities.
(4) Computation of qualified
investment for a new unit or an addition
of capacity. For purposes of this
paragraph (b), a new unit or an addition
of capacity requires the addition or
replacement of components of qualified
property, including any new or
replacement integral property, added to
a facility necessary to increase capacity.
The taxpayer’s qualified investment
during the taxable year that resulted in
an increased capacity of a facility by
reason of a new unit or addition of
capacity is its total qualified investment
associated with the components of
property that result in the new unit or
addition of capacity.
(5) Examples. This paragraph (b)(5)
provides examples illustrating the rules
of this paragraph (b).
(i) Example 1. New Unit. X owns a
hydropower facility (Facility H) that
was originally placed in service in 2020,
with a FERC license authorizing an
installed capacity of 60 megawatts.
During taxable years 2020 through 2024,
X claimed a section 45 credit for the
electricity produced by Facility H. On
July 1, 2025, as allowed by a FERC
license amendment, X places in service
components of property comprising a
new unit that results in Facility H
having an increased authorized installed
capacity of 90 megawatts in 2025. These
components of property meet the
requirements of qualified property (as
defined in § 1.48E–2(e)). For purposes of
this paragraph (b), this new unit will be
treated as a separate facility (Facility J).
X determines the amount of its section
48E credit based on the amount of its
qualified investment in Facility J. Even
though X claimed a section 45 credit for
electricity produced by Facility H in
taxable years 2020 through 2024, X can
claim a section 48E credit for its
qualified investment in Facility J. X may
also continue to claim the section 45
credit through taxable year 2030 for
electricity generated by Facility H

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(excluding the incremental electricity
generation related to Facility J).
(ii) Example 2. Addition of Capacity.
Y owns a nuclear facility (Facility N)
that was originally placed in service on
January 1, 2000. Y claimed a section
45U credit in taxable years 2024 and
2025 for the electricity generated by
Facility N. On January 15, 2026, Y
completed and placed in service an
investment associated with a power
uprate approved by an NRC license
amendment that involved the removal
and replacement of components of
property and placing in service
additional components of property.
Both of these replacement and
additional components of property meet
the requirements of qualified property
(as defined in § 1.48E–2(c)). NRC reports
associated with the license amendment
describe the uprate as increasing the
nuclear facility’s electrical capacity by
100 MW to 900 MW. For purposes of
this paragraph (b), Facility N’s addition
of capacity equal to 100 MW is treated
as a new separate qualified facility
placed in service on January 15, 2026
(Facility P). Y determines the amount of
its section 48E credit based on the entire
amount of its qualified investment on
January 15, 2026. Even though Y
claimed a section 45U credit in taxable
years 2024 and 2025 for the existing
capacity of Facility N, Y can claim a
section 48E credit for its investment in
components of property needed to
support the increase in capacity. Y may
also continue to claim the section 45U
credit for electricity generated by
Facility N (excluding the incremental
electricity generation related to Facility
P).
(iii) Example 3. Geothermal Turbine
and Generator Additions of Capacity. X
owns a geothermal power plant (Facility
G) with a 24 MW nameplate capacity,
which is placed in service in 2007. Over
the subsequent years, the plant’s
generating capability declines because
of physical degradation of the turbine
and generator. On March 1, 2027, X
places in service components of
property at Facility G that increase its
capacity. The turbine rotor is removed,
and the eroded blades are replaced with
new blades, with associated capital
expenditures. The generator is
refurbished by removing old
subcomponents of the generator and
replacing those with new
subcomponents, as well as replacing the
old copper windings with new windings
in concert with new insulation. These
components of property meet the
requirements of qualified property (as
defined in § 1.48E–2(c)). After the
upgrade, the plant increases its
nameplate capacity to 26 MW, an

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increase of 2 MW over the previous
nameplate capacity. For purposes of this
paragraph (b), the addition of capacity
to Facility G is treated as a new separate
qualified facility placed in service on
March 1, 2027 (Facility N). X
determines the amount of its section
48E credit based on the amount of its
qualified investment in qualified
property needed to increase the capacity
of the facility.
(iv) Example 4. Hydropower Addition
of Capacity. X owns a hydropower plant
(Facility H) placed in service in 1960.
Facility H has become less efficient
since it was placed in service with
attendant reductions in its generating
capacity. As approved by a FERC
license amendment, X increases Facility
H’s capacity by installing new
headcovers, new turbines with
integrated dissolved oxygen injection,
and a new high pressure digital
governor system. All of the existing
turbine systems are replaced with new
turbine and governor systems. The new
turbines are more efficient, and are
capable of more power output, than the
original design installed in 1960.
Improvements to the generators involve
removing the old asphalt coated copper
windings and purchasing and then
installing new epoxy coated double
wound windings. X adds digital
controls to effectively utilize new digital
governors. These components of
property meet the requirements of
qualified property (as defined in
§ 1.48E–2(c)). X simultaneously invests
in cybersecurity protection. As set forth
in the FERC order amending its license,
these investments, which are placed in
service on April 15, 2026, increase
Facility H’s authorized installed
nameplate capacity from 180 MW to 190
MW, an increase of 10 MW over the
previous nameplate capacity. For
purposes of this paragraph (b), Facility
H’s addition of capacity is treated as a
new separate qualified facility placed in
service on April 16, 2026 (Facility A). X
determines the amount of its section
48E credit based on the amount of its
qualified investment in qualified
property needed in Facility A to result
in the final 190 MW capacity, which
would not include any investments in
intangible property, such as those that
might be associated with cybersecurity
protection.
(v) Example 5. Nonoperational
Nuclear Facility that Satisfies Restart
Rule. T owns a nuclear facility (Facility
N) that was originally placed in service
in 1982. In 2020, Facility N ceased
operations, began decommissioning,
and the NRC no longer authorized the
operation of Facility N. T did not cease
operations at Facility N for the purpose

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of qualifying for the special rule for
restarted facilities under section 48E. In
2028, the NRC authorized Facility N to
restart, and, on October 1, 2028, Facility
N placed in service qualified property
that enabled Facility N to restart and
resume operations, with an electrical
capacity of 800 MW, as indicated in
NRC documents related to the
authorization to restart. For purposes of
this paragraph (b), the restart of Facility
N is considered to have increased
capacity from a base of zero, and
Facility N is treated as having an
addition of capacity equal to 800 MW.
For purposes of this paragraph (b),
Facility N’s 800 MW addition of
capacity is treated as a new qualified
facility placed in service on October 1,
2028 (Facility P). T determines the
amount of its section 48E credit based
on the amount of its qualified
investment in qualified property needed
to restart the facility.
(c) Retrofit of an existing facility (80/
20 Rule)—(1) In general. For purposes of
section 48E(b)(3)(A)(ii), a retrofitted
qualified facility or an energy storage
technology (EST) may qualify as
originally placed in service even if it
contains some used components of
property within the unit of qualified
facility or unit of EST, provided that the
fair market value of the used
components of the unit of qualified
facility or unit of EST is not more than
20 percent of the total value of the unit
of qualified facility or unit of EST (that
is, the cost of the new components of
property plus the value of the used
components of property within the unit
of qualified facility or unit of EST) (80/
20 Rule). A qualified facility or EST that
meets the 80/20 Rule may claim the
section 48E credit without regard to any
addition of capacity to the qualified
facility or EST.
(2) Expenditures taken into account.
Notwithstanding the rule provided in
paragraph (c)(1) of this section, only the
cost of new components of the unit of
qualified facility or unit of EST are
taken into account for purposes of
computing the credit determined under
section 48E with respect to the qualified
facility or EST.
(3) Cost of new components. For
purposes of this 80/20 Rule, the cost of
new components of the unit of qualified
facility or unit of EST includes all costs
properly included in the depreciable
basis of the new components of the unit
of qualified facility.
(4) New costs. If the taxpayer satisfies
the 80/20 Rule with regard to the unit
of qualified facility or unit of EST and
the taxpayer pays or incurs new costs
for property that is an integral part of
the qualified facility (as defined in

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§ 1.48E–2(a)) or the EST (as defined in
§ 1.48E–2(g)), the taxpayer may include
these new costs paid or incurred for
property that is an integral part of the
qualified facility or EST in the basis of
the qualified facility or EST for
purposes of the section 48E credit.
(5) Excluded costs. Costs incurred for
new components of property added to
used components of a unit of qualified
facility or unit of EST may not be taken
into account for purposes of the section
48E credit unless the taxpayer satisfies
the 80/20 Rule by placing in service a
unit of qualified facility or unit of EST
for which the fair market value of the
used components of property is not
more than 20 percent of the total value
of the unit of qualified facility or unit
of EST taking into account the cost of
the new components of property plus
the value of the used components of
property.
(6) Examples. This paragraph (c)(6)
provides examples illustrating the rules
of this paragraph (c).
(i) Example 1. Retrofitted facility that
satisfies the 80/20 Rule. A owns an
existing wind facility. On February 1,
2026, A replaces used components of
unit of qualified facility of the wind
facility with new components at a cost
of $2 million. The fair market value of
the remaining original components of
the unit of qualified facility is $400,000,
which is not more than 20 percent of the
retrofitted unit of qualified facility’s
total fair market value of $2.4 million
(the cost of the new components ($2
million) + the fair market value of the
remaining original components of the
unit of qualified facility ($400,000)).
Thus, the retrofitted wind facility will
be considered newly placed in service
for purposes of section 48E, assuming
all the other requirements of section 48E
are met, and A will be able to claim a
section 48E credit based on its
investment in 2026 ($2 million).
(ii) Example 2. Retrofit of an existing
facility that meets the 80/20 Rule.
Facility Z, a facility that was originally
placed in service on January 1, 2026,
was not a qualified facility (as defined
in § 1.48E–2(a)) when it was placed in
service because it did not meet the
greenhouse gas emissions rate
requirements (as determined under
rules provided in § 1.48E–5). On January
1, 2027, Facility Z was retrofitted and
now meets the requirements to be a
qualified facility (as defined in § 1.48E–
2(a)). After the retrofit, the cost of the
new property included in the unit of
qualified facility of Facility Z is greater
than 80 percent of unit of qualified
facility’s total fair market value. Because
Facility Z meets the 80/20 Rule, Facility
Z is deemed to be originally placed in

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service on January 1, 2027. Assuming all
the other requirements of section 48E
are met, Z may claim a section 48E
credit based on its investment in the
new components used to retrofit the
existing facility in 2027.
(iii) Example 3. Retrofitted nuclear
facility that satisfied the 80/20 Rule. T
owns a nuclear facility (Facility N) that
was originally placed in service on
March 1, 1982. T replaces used
components of property of the unit of
qualified facility of Facility N with new
components at a cost of $200 million,
and then places in Facility N in service
on July 15, 2026. The fair market value
of the remaining original components of
the unit of qualified facility, prior to the
retrofit, is $30 million, which is not
more than 20 percent of the unit of
qualified facility’s total fair market
value of $230 million (the cost of the
new components ($200 million) + the
fair market value of the remaining
original components of the unit of
qualified facility ($30 million)) ($30
million/$230 million = 13%). Thus,
assuming all the other requirements of
section 48E are met, Facility N will be
considered newly placed in service on
July 15, 2026, for purposes of section
48E, and T will be able to claim a
section 48E credit based on its
investment in the new components
($200 million).
(iv) Example 4. Capital improvements
to an existing qualified facility that do
not satisfy the 80/20 Rule. X owns an
existing facility, Facility C, that was
originally placed in service on January
1, 2023. X makes capital improvements
to Facility C that are placed in service
on June 6, 2026. The cost of the capital
improvements to the unit of qualified
facility of Facility C total $500,000 and
the fair market value of the unit of
qualified facility after the improvements
is $2 million. The fair market value of
the old components of the unit of
qualified facility is $1,500,000 or 75
percent of the total fair market value of
the Facility C after the improvements.
Because the fair market value of the new
property included in the unit of
qualified facility is less than 80 percent
of the unit of qualified facility’s total
fair market value, Facility C does not
meet the 80/20 Rule.
(v) Example 5. Upgrades to a
hydropower qualified facility that
satisfies the 80/20 Rule: Y owns a
hydropower qualified facility
(hydropower facility) and no taxpayer,
including Y, has ever claimed a section
45 credit for the hydropower facility.
The hydropower facility consists of a
unit of qualified facility including water
intake, water isolation mechanisms,
turbine, pump, motor, and generator.

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The associated impoundment (dam) and
power conditioning equipment are
integral parts of the unit of qualified
facility. Y makes upgrades to the unit of
qualified facility by replacing the
turbine, pump, motor, and generator
with new components at a cost of $1.5
million. Y does not make any upgrades
to the property that is an integral part
of the unit of qualified facility. The
remaining original components of the
unit of qualified facility have a fair
market value of $100,000, which is not
more than 20 percent of the retrofitted
hydropower facility’s total value of $1.6
million (that is, the cost of the new
components ($1.5 million) + the value
of the remaining original components
($100,000)). Thus, the retrofitted
hydropower facility will be considered
newly placed in service for purposes of
section 48E, and Y will be able to claim
a section 48E credit based on the cost of
the new components ($1.5 million).
(d) Special rules regarding
ownership—(1) Qualified investment
with respect to a qualified facility or
EST. For purposes of this paragraph (d),
a taxpayer that owns a qualified
investment with respect to a qualified
facility or EST is eligible for the section
48E credit only to the extent of the
taxpayer’s basis in the qualified facility
or EST. In the case of multiple taxpayers
holding direct ownership through their
qualified investments in a single
qualified facility or EST (and such
arrangement is not treated as a
partnership for Federal income tax
purposes), each taxpayer determines its
basis based on its fractional ownership
interest in the qualified facility or EST.
(2) Multiple owners. A taxpayer must
directly own at least a fractional interest
in the entire unit of qualified facility (as
defined in § 1.48E–2(b)(2)) or unit of
EST (as defined in § 1.48E–2(g)(2)) for a
section 48E credit to be determined with
respect to such taxpayer’s interest. No
section 48E credit may be determined
with respect to a taxpayer’s ownership
of one or more separate components of
a qualified facility or an EST if the
components do not constitute a unit of
qualified facility (as defined in § 1.48E–
2(b)(2)) or unit of EST (as defined in
§ 1.48E–2(g)(2)). However, the use of
property owned by one taxpayer that is
an integral part of a qualified facility or
EST owned by another taxpayer will not
prevent a section 48E credit from being
determined with respect to the second
taxpayer’s qualified investment in a
qualified facility or EST (though neither
taxpayer would be eligible for a section
48E credit with respect to the first
taxpayer’s property). See § 1.48E–
2(b)(3)(vi) for rules regarding shared
integral property.

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(3) Section 761(a) election. If a
qualified facility or EST is owned
through an unincorporated organization
that has made a valid election under
section 761(a) of the Code, each
member’s undivided ownership share in
the qualified facility or EST will be
treated as a separate qualified facility or
EST owned by such member.
(4) Examples. The following examples
illustrate the rules in this paragraph (d).
In each example, X and Y are unrelated
taxpayers.
(i) Example 1. Fractional ownership
required to satisfy section 48E. X and Y
each own a direct fractional ownership
interest in an entire qualified facility (as
defined in § 1.48E–2(b)) and as a result,
a section 48E credit may be determined
with respect to X’s and Y’s qualified
investment in their fractional ownership
interests in the qualified facility.
(ii) Example 2. Ownership of separate
components of property that are part of
a qualified facility. X and Y each own
separate components of a qualified
facility, which taken together would
constitute a unit of qualified facility but
taken separately would not constitute a
unit of qualified facility. X owns
component A and Y owns component B.
No section 48E credit may be
determined with respect to either
component A or component B because
X and Y each owns a separate
component of a qualified facility that
does not constitute a unit of qualified
facility (as defined in § 1.48E–2(b)(2)).
(iii) Example 3. Separate ownership of
property that is an integral part of
separate qualified facilities. X owns a
solar farm that is a qualified facility (as
defined in § 1.48E–2(b)) (Solar Qualified
Facility), which includes property that
is an integral part of the Solar Qualified
Facility, specifically a transformer in
which the electricity is stepped up to
electrical grid voltage before being
transmitted to the electrical grid through
an intertie. Y owns a wind facility that
is a qualified facility (as defined in
§ 1.48E–2(b)) (Wind Qualified Facility)
that connects to X’s transformer. X and
Y are not related persons within the
meaning of paragraph (d)(4)(i) of this
section. Because Y does not hold an
ownership interest in the transformer, Y
may compute its section 48E credit for
the Wind Qualified Facility, but it may
not include any costs relating to the
transformer in its section 48E credit
base.
(iv) Example 4. Related taxpayers and
property that is an integral part. X owns
a wind facility that is a unit of qualified
facility and a solar facility that is a unit
of qualified facility. Both the wind
facility and the solar facility are
connected to a transformer where the

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electricity is stepped up to electrical
grid voltage before being transmitted to
the electrical grid through an intertie.
The transformer is an integral part of
both the wind facility and the solar
facility (within the meaning of § 1.48E–
2(d)(3)(i)) and is owned by Y. X and Y
are related persons within the meaning
of paragraph (d)(4)(i) of this section. X
and Y are treated as one taxpayer under
paragraph (d)(4)(ii) of this section. X
may include the basis of the transformer
in computing its section 48E credit with
respect to the wind facility and the solar
facility (but may not include more than
100% of that basis in the aggregate).
(e) Coordination rule for section 42
credits and section 48E credits. As
provided under section 50(c)(3)(C) of
the Code, in determining eligible basis
for purposes of calculating a credit
under section 42 of the Code (section 42
credit), a taxpayer is not required to
reduce its basis in a qualified facility or
EST by the amount of the section 48E
credit determined with respect to the
taxpayer’s qualified investment with
respect to such qualified facility or EST.
The qualified investment with respect to
a qualified facility or EST property may
be used to determine a section 48E
credit and may also be included in
eligible basis to determine a section 42
credit. See paragraph (d) of this section
for special rules regarding ownership.
(f) Recapture—(1) In general. The
credit calculated under section 48E(a)
and § 1.48E–1(b) is subject to general
recapture rules under section 50(a).
Additionally, section 48E(g) provides
for recapture for any qualified facility
for which a taxpayer claimed a section
48E credit that has a greenhouse gas
emissions rate (as determined under
rules provided in § 1.45Y–5) of greater
than 10 grams of CO2e per kWh during
the five-year period beginning on the
date such qualified facility is originally
placed in service (five-year recapture
period).
(2) Recapture event—(i) In general.
Any event that results in a qualified
facility having a greenhouse gas
emissions rate (as determined under
rules provided in § 1.45Y–5) of greater
than 10 grams of CO2e per kWh during
the five-year period is a recapture event.
If a qualified facility’s greenhouse gas
emissions rate exceeds 10 grams of CO2e
per kWh, the section 48E credit is
subject to recapture.
(ii) Changes to the Annual Table. A
change to the greenhouse gas emissions
rate for a type or category of facility that
is published in the Annual Table (as
defined in § 1.48E–5(f)) after a facility is
placed in service does not result in a
recapture event.

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(iii) Yearly determination—(A) In
general. A determination of whether a
recapture event occurred under this
paragraph (f)(2) must be made for each
taxable year (or portion thereof)
occurring within the five-year recapture
period, beginning with the taxable year
ending after the date the qualified
facility is placed in service. Thus, for
each taxable year that begins or ends
within the five-year recapture period,
the taxpayer must determine, for any
qualified facility for which it has
claimed the section 48E credit, whether
such facility has maintained a
greenhouse gas emissions rate of not
greater than 10 grams of CO2e per kWh.
(B) Annual reporting requirement. A
taxpayer that has claimed the section
48E credit amount under § 1.48E–1(b),
including a taxpayer that has transferred
a specified credit portion under section
6418 of the Code, is required to provide
to the IRS information on the
greenhouse gas emissions rate of the
qualified facility during the recapture
period at the time and in the form and
manner prescribed in IRS forms or
instructions or in publications or
guidance published in the Internal
Revenue Bulletin. See § 601.601 of this
chapter.
(iv) Carryback and carryforward
adjustments. In the case of any
recapture event described in this
paragraph (f)(2), the carrybacks and
carryforwards under section 39 of the
Code must be adjusted by reason of such
recapture event.
(3) Recapture amount—(i) In general.
If a recapture event occurred as
described in paragraph (f)(2) of this
section, the tax under chapter 1 of the
Code for the taxable year in which the
recapture event occurs is increased by
an amount equal to the applicable
recapture percentage multiplied by the
credit amount that was claimed by the
taxpayer under § 1.48E–1(b).
(ii) Applicable recapture percentage.
If the recapture event occurs:
(A) Within one full year after the
property is placed in service, the
recapture percentage is 100;
(B) Within one full year after the close
of the period described in paragraph
(f)(3)(ii)(A) of this section, the recapture
percentage is 80;
(C) Within one full year after the close
of the period described in paragraph
(f)(3)(ii)(B) of this section, the recapture
percentage is 60;
(D) Within one full year after the close
of the period described in paragraph
(f)(3)(ii)(C) of this section, the recapture
percentage is 40; and
(E) Within one full year after the close
of the period described in paragraph

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(f)(3)(ii)(D) of this section, the recapture
percentage is 20.
(4) Recapture period. The five-year
recapture period begins on the date the
qualified facility is placed in service
and ends on the date that is five full
years after the placed in service date.
Each 365-day period (366-day period in
case of a leap year) within the five-year
recapture period is a separate recapture
year for recapture purposes.
(5) Increase in tax for recapture. The
increase in tax under chapter 1 of the
Code for the recapture of the credit
amount claimed under section 48E(a)
and § 1.48E–1(b) occurs in the year of
the recapture event.
(g) Qualified progress expenditure
election. A taxpayer may elect, as
provided in § 1.46–5, to increase the
qualified investment with respect to any
qualified facility or EST of an eligible
taxpayer for the taxable year, by any
qualified progress expenditures made
after August 16, 2022.
(h) Incremental cost—(1) In general.
For purposes of section 48E, if a
component of qualified property of a
qualified facility or component of
property of an EST is also used for a
purpose other than the intended
function of the qualified facility or EST,
only the incremental cost of such
component is included in the basis of
the qualified facility or EST. The term
incremental cost means the excess of the
total cost of a component over the
amount that would have been expended
for the component if that component
were used for a non-qualifying purpose.
(2) Example. A installs a solar
qualified facility above the surface of an
existing roof of a building that A owns.
The solar qualified facility uses bifacial
panels that convert to energy the light
that strikes both the front and back of
the panels. Therefore, along with
installing the bifacial panels, A is
reroofing their building with a reflective
roof that has a highly reflective surface.
Because the reflective roof enables the
panels’ generation of significant
amounts of electricity from reflected
sunlight, when installed in connection
with the solar qualified facility, it
constitutes part of that solar qualified
facility to the extent that the cost of the
reflective roof exceeds the cost of
reroofing A’s building with a nonreflective roof. The cost of reroofing
with the reflective roof is $15,000
whereas the cost of a reroofing with a
standard roof for the building would be
$10,000. The incremental cost of the
reflective roof is $5,000, and that
amount is included in A’s basis in the
solar qualified facility for purposes of
the section 48E credit.

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(i) Cross references. (1) To determine
applicable recapture rules, see section
50(a) of the Code.
(2) For rules regarding the credit
eligibility of property used outside the
United States, see section 50(b)(1) of the
Code.
(3) For rules regarding the credit
eligibility of property used by certain
tax-exempt organizations, see section
50(b)(3) of the Code. See section
6417(d)(2) of the Code for an exception
to the rule in section 50(b)(3) in the case
of an applicable entity making an
elective payment election.
(4) For application of the
normalization rules to the section 48E
credit in the case of certain regulated
companies, including rules regarding
the election not to apply the
normalization rules to EST (as defined
in section 48(c)(6) of the Code without
regard to section 48(c)(6)(D) of the
Code), see section 50(d)(2) of the Code.
(5) For rules relating to certain leased
property, see section 50(d)(5) of the
Code.
(j) Applicability date. This section
applies to qualified facilities and ESTs
placed in service after December 31,
2024, and during a taxable year ending
on or after January 15, 2025.

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§ 1.48E–5 Greenhouse gas emissions
rates for qualified facilities under section
48E.

(a) In general. Section 48E(b)(3)(B)(ii)
provides that rules similar to the rules
of section 45Y(b)(2) regarding
greenhouse emissions rates apply for
purposes of section 48E. Paragraphs (b)
through (f) of this section thus provide
that the definitions and rules regarding
greenhouse gas emissions rate
requirements (as determined under
rules provided in § 1.45Y–5) apply for
purposes of section 48E and this
section. Paragraph (g) of this section
provides rules related to provisional
emissions rates for purposes of section
48E and this section. Paragraph (h) of
this section provides rules for
determining an anticipated greenhouse
gas emissions rate. Paragraph (i) of this
section provides rules regarding reliance
on the annual publication of emissions
rates and provisional emissions rates.
Finally, paragraph (j) of this section
provides rules regarding substantiation
requirements.
(b) Definitions. The definitions
provided in § 1.45Y–5(b) apply for
purposes of section 48E and this
section.
(c) Non-C&G Facilities. The rules
provided in § 1.45Y–5(c) apply for
purposes of determining greenhouse gas
emissions rates for Non-C&G Facilities

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for purposes of section 48E and this
section.
(d) C&G Facilities. The rules provided
in § 1.45Y–5(d) apply for purposes of
determining greenhouse gas emissions
rates for C&G Facilities for purposes of
section 48E and this section.
(e) Use of methane from certain
sources to produce electricity. The rules
provided in § 1.45Y–5(e) regarding the
use of methane from certain sources to
produce electricity apply for purposes
of section 48E and this section.
(f) Carbon capture and sequestration.
The rules provided in § 1.45Y–5(f)
regarding carbon capture and
sequestration apply for purposes of
section 48E and this section.
(g) Annual publication of emissions
rates. The rules provided in § 1.45Y–
5(g) regarding the annual publication of
a table (Annual Table) that sets forth the
greenhouse gas emissions rates for types
or categories of facilities apply for
purposes of section 48E and this
section.
(h) Provisional emissions rates—(1) In
general. In the case of any facility for
which an emissions rate has not been
established by the Secretary, a taxpayer
that owns such facility may file a
petition with the Secretary for
determination of the emissions rate with
respect to such facility (Provisional
Emissions Rate or PER). A PER must be
determined and obtained under the
rules of this section.
(2) Rate not established. An emissions
rate has not been established by the
Secretary for a facility for purposes of
sections 45Y(b)(2)(C)(ii) and
48E(b)(3)(B)(ii) if such facility is not
described in the Annual Table. If a
taxpayer’s request for an emissions
value pursuant to paragraph (h)(5) of
this section is pending at the time such
facility is or becomes described in the
Annual Table, the taxpayer’s request for
an emissions value will be
automatically denied.
(3) Process for filing a PER petition.
To file a PER petition with the
Secretary, a taxpayer must submit a PER
petition by attaching it to the taxpayer’s
Federal income tax return or Federal
return, as appropriate, for the taxable
year in which the taxpayer claims the
section 48E credit with respect to the
facility to which the PER petition
relates. The PER petition must contain
an emissions value and, if applicable,
the associated letter from DOE. An
emissions value may be obtained from
DOE or by using the designated LCA
model in accordance with paragraph
(h)(6) of this section. An emission value
obtained from DOE will be based on an
analytical assessment of the emissions
rate associated with the facility

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4125

performed by one or more of the
National Laboratories, in consultation
with other Federal agency experts as
appropriate, consistent with this
section. A taxpayer must retain in its
books and records the application and
correspondence to and from DOE
including a copy of the taxpayer’s
request to DOE for an emissions value
and any information provided by the
taxpayer to DOE pursuant to the
emissions value request process
provided in paragraph (h)(5) of this
section. Alternatively, an emissions
value can be determined by the taxpayer
for a facility using the most the recent
version of an LCA model, as of the time
the PER petition is filed, that has been
designated by the Secretary for such use
under paragraph (h)(6) of this section. If
an emissions value is determined using
the designated LCA model under
paragraph (h)(6) of this section, a
taxpayer is required to provide to the
IRS information to support its
determination in the form and manner
prescribed in IRS forms or instructions
or in publications or guidance
published in the Internal Revenue
Bulletin. See § 601.601 of this chapter.
A taxpayer may not request an
emissions value from DOE for a facility
for which an emissions value can be
determined using the most recent
version of an LCA model or models
designated for such use under paragraph
(h)(6) of this section.
(4) PER determination. Upon the IRS’s
acceptance of the taxpayer’s return to
which a PER petition is attached, the
emissions value of the facility specified
on such petition is deemed accepted. A
taxpayer can rely upon an emissions
value provided by DOE for purposes of
claiming a section 48E credit, provided
that any information, representations, or
other data provided to DOE in support
of the request for an emissions value are
accurate. If applicable, a taxpayer may
rely upon an emissions value
determined for a facility using the LCA
model designated under paragraph
(h)(6) of this section, provided that any
information, representations, or other
data used to obtain such emissions
value are accurate. The IRS’s deemed
acceptance of an emissions value is the
Secretary’s determination of the PER.
However, the taxpayer must also
comply with all applicable requirements
for the section 48E credit and any
information, representations, or other
data supporting an emissions value are
subject to later examination by the IRS.
(5) Emissions value request process.
An applicant that submits a request for
an emissions value must follow the
procedures specified by DOE to request
and obtain such emissions value.

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Federal Register / Vol. 90, No. 9 / Wednesday, January 15, 2025 / Rules and Regulations

Emissions values will be determined
consistent with the rules provided in
this section. An applicant can request
an emissions value from DOE only after
a front-end engineering and design
(FEED) study or similar indication of
project maturity, as determined by DOE,
such as the completion of a project
specification and cost estimation
sufficient to inform a final investment
decision for the facility. DOE may
decline to review applications that are
not responsive, including those
applications that relate to a facility
described in the Annual Table
(consistent with paragraph (h)(2) of this
section) or a facility for which an
emissions value can be determined by
an LCA model under paragraph (h)(6) of
this section (consistent with paragraph
(h)(3) of this section), or applications
that are incomplete. Applicants must
follow DOE’s guidance and procedures
for requesting and obtaining an
emissions value from DOE. DOE will
publish this guidance and procedures,
including a process for, under limited
circumstances, a revision to DOE’s
initial assessment of an emissions value
on the basis of revised technical
information or facility design and
operation.
(6) LCA model for determining an
emissions value for C&G Facilities. The
rules provided in § 1.45Y–5(h)(6)
regarding the designation of an LCA
model or models for determining an
emissions value for C&G Facilities apply
for purposes of section 48E and this
section.
(7) Effect of PER. A taxpayer who files
for a PER must use a PER determined by
the Secretary to determine eligibility for
the section 48E credit, provided all
other requirements of section 48E are
met. 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 48E
credit is claimed. Further, a PER
determination does not signify that the
IRS has determined that the
requirements of section 48E have been
satisfied for any taxable year.
(i) Determining anticipated
greenhouse gas emissions rate—(1) In
general. A facility’s anticipated
greenhouse gas emissions rate must be
objectively determined based on an
examination of all the facts and
circumstances. Certain Non-C&G
Facilities, such as the facilities
described in § 1.45Y–5(c)(2), may have

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an anticipated greenhouse gas emissions
rate that is not greater than zero based
on the technology and practices they
rely upon to generate electricity. For
facilities that require the use of certain
fuel sources, which may vary, or carbon
capture and sequestration, to generate
electricity with a greenhouse gas
emissions rate that is not greater than
zero, objective indicia that such
facilities will use such fuel sources or
operate such carbon capture equipment,
as applicable, in a manner that results
in a greenhouse gas emissions rate that
is not greater than zero for at least 10
years beginning from the date the
facility is placed in service are required
to establish a reasonable expectation
that the combination of fuel, type of
facility, and practice will result in a
greenhouse gas emissions rate that is not
greater than zero. Taxpayers must attest
under penalty of perjury that the
anticipated greenhouse gas emissions
rate as determined under the statute and
these final regulations is not greater
than zero. A facility subject to legally
binding Federal or State permit
conditions requiring that the facility
operate in a manner that would be
incompatible with a greenhouse gas
emissions rate of not greater than zero
is not a facility for which the
anticipated greenhouse gas emissions
rate is not greater than zero.
(2) Examples of objective indicia.
Examples of objective indicia that may
establish an anticipated greenhouse gas
emissions rate that is not greater than
zero for specific elements of the type of
facility, fuel source, or practice include,
but are not limited to:
(i) Co-location of the facility with a
fuel source (for example, an anaerobic
digester) for which the combination of
fuel, type of facility, and practice is
reasonably expected to result in a
greenhouse gas emissions rate that is not
greater than zero;
(ii) A 10-year binding written contract
to purchase fuels for which the
combination of fuel, type of facility, and
practice is reasonably expected to result
in a greenhouse gas emissions rate that
is not greater than zero;
(iii) A facility type that only
accommodates one type of fuel or a
small range of fuels for which the
combination of fuel, type of facility, and
practice is reasonably expected to result
in a greenhouse gas emissions rate that
is not greater than zero;
(iv) A 10-year binding written
contract for the permanent geological
storage (including after injection into an
enhanced oil and gas recovery (EOR)
project) or utilization of qualified
carbon dioxide from the facility for
which the combination of fuel, type of

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facility, and capture and practice is
reasonably expected to result in a
greenhouse gas emissions rate that is not
greater than zero; or
(v) A legally binding Federal or State
air permit which requires, as a
condition of the permit, that the facility
operates in a manner for which the
combination of fuel, type of facility, and
practice is reasonably expected to result
in a greenhouse gas emissions rate that
is not greater than zero and that any
captured carbon dioxide is permanently
geologically stored and subjects the
holder to civil or criminal penalties in
the event the relevant permit
requirements are breached.
(j) Reliance on Annual Table or
provisional emissions rate. Taxpayers
may rely on the Annual Table in effect
as of the date a facility began
construction or the provisional
emissions rate determined by the
Secretary for the taxpayer’s facility
under paragraph (h)(4) of this section to
determine the facility’s greenhouse gas
emissions rate, provided that the facility
continues to operate as a type of facility
that is described in the Annual Table or
the facility’s emissions value request, as
applicable, for the entire taxable year.
(k) Substantiation—(1) In general. A
taxpayer must maintain in its books and
records documentation regarding the
design and operation of a facility that
establishes that such facility had an
anticipated greenhouse gas emissions
rate that is not greater than zero in the
year in which the section 48E credit is
determined and operated with a
greenhouse gas emissions rate that is not
greater than 10 grams of CO2e per kWh
during each year of the recapture period
that applies for purposes of section
48E(g).
(2) Sufficient substantiation.
Documentation sufficient to substantiate
that a facility had a greenhouse gas
emissions rate, as determined under this
section, not greater than 10 grams of
CO2e per kWh during each year of the
recapture period that applies for
purposes of section 48E(g) includes
documentation or a report prepared by
an unrelated party that verifies the
facility’s actual emissions rate. A facility
described in § 1.45Y–5(c)(2) can
maintain sufficient documentation to
demonstrate a greenhouse gas emissions
rate that is not greater than 10 grams of
CO2e per kWh during each year of the
recapture period that applies for
purposes of section 48E(g) by showing
that it is the type of facility described in
§ 1.45Y–5(c)(2). The Secretary may
determine that other types of facilities
can sufficiently substantiate a
greenhouse gas emissions rate, as
determined under this section, that is

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not greater than 10 grams of CO2e per
kWh during each year of the recapture
period that applies for purposes of
section 48E(g) with certain
documentation and will describe such
facilities and documentation in IRS
forms or instructions or in publications
or guidance published in the Internal
Revenue Bulletin. See § 601.601 of this
chapter. For such other types of
facilities that utilize biomass feedstocks,
the taxpayer must substantiate that the

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source of such fuels or feedstocks used
are consistent with the taxpayer’s
claims. For all facilities that utilize
unmarketable feedstocks that are
indistinguishable from marketable
feedstocks (for instance, after
processing), the taxpayer will be
required to maintain documentation
substantiating the origin and original
form of the feedstock.
(l) Applicability date. This section
applies to qualified facilities placed in

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service after December 31, 2024, and
during a taxable year ending on or after
January 15, 2025.
Douglas W. O’Donnell,
Deputy Commissioner.
Approved: December 31, 2024.
Aviva R. Aron-Dine,
Deputy Assistant Secretary of the Treasury
(Tax Policy).
[FR Doc. 2025–00196 Filed 1–7–25; 4:15 pm]
BILLING CODE 4830–01–P

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