[Federal Register Volume 91, Number 62 (Wednesday, April 1, 2026)]
[Rules and Regulations]
[Pages 16388-16500]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2026-06275]
[[Page 16387]]
Vol. 91
Wednesday,
No. 62
April 1, 2026
Part IV
Environmental Protection Agency
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40 CFR Parts 63, 80, and 1090
Renewable Fuel Standard (RFS) Program: Standards for 2026 and 2027,
Partial Waiver of 2025 Cellulosic Biofuel Volume Requirement, and Other
Changes; Final Rule
Federal Register / Vol. 91 , No. 62 / Wednesday, April 1, 2026 /
Rules and Regulations
[[Page 16388]]
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ENVIRONMENTAL PROTECTION AGENCY
40 CFR Parts 63, 80, and 1090
[EPA-HQ-OAR-2024-0505; FRL-11947-02-OAR]
RIN 2060-AW23
Renewable Fuel Standard (RFS) Program: Standards for 2026 and
2027, Partial Waiver of 2025 Cellulosic Biofuel Volume Requirement, and
Other Changes
AGENCY: Environmental Protection Agency (EPA).
ACTION: Final rule.
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SUMMARY: Under the Clean Air Act (CAA), the U.S. Environmental
Protection Agency (EPA) is required to determine the applicable volume
requirements for the Renewable Fuel Standard (RFS) for years after
those specified in the statute. The EPA is establishing the applicable
volumes and percentage standards for 2026 and 2027 for cellulosic
biofuel, biomass-based diesel (BBD), advanced biofuel, and total
renewable fuel. The EPA is also partially waiving the 2025 cellulosic
biofuel volume requirement and revising the associated percentage
standard due to a shortfall in cellulosic biofuel production. Finally,
the EPA is promulgating several regulatory changes to the RFS program,
including removing renewable electricity as a qualifying renewable fuel
under the RFS program (eRINs) and making minor revisions to the biogas
provisions of the RFS program.
DATES: This rule is effective on June 15, 2026, except for amendatory
instruction 47, which is effective on April 28, 2026, and amendatory
instruction 17, which is effective on January 1, 2027. The
incorporation by reference of certain publications listed in this
regulation is approved by the Director of the Federal Register as of
June 15, 2026.
ADDRESSES: The EPA has established a docket for this action under
Docket ID No. EPA-HQ-OAR-2024-0505. All documents in the docket are
listed on the https://www.regulations.gov website. Although listed in
the index, some information is not publicly available, e.g.,
confidential business information (CBI) or other information whose
disclosure is restricted by statute. Certain other material is not
available on the internet and will be publicly available only in hard
copy form. Publicly available docket materials are available
electronically through https://www.regulations.gov.
FOR FURTHER INFORMATION CONTACT: For information about this final rule,
contact Dallas Burkholder, Assessment and Standards Division, Office of
Transportation and Air Quality, Environmental Protection Agency, 2000
Traverwood Drive, Ann Arbor, MI 48105; telephone number: 734-214-4766;
email address: [email protected].
SUPPLEMENTARY INFORMATION:
Does this action apply to me?
Entities potentially affected by this action are those involved
with the production, distribution, and sale of transportation fuels
(e.g., gasoline and diesel fuel) and renewable fuels (e.g., ethanol,
biodiesel, renewable diesel, and biogas). Potentially affected
categories include:
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NAICS \a\ Examples of potentially
Category codes affected entities
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Industry......................... 111110 Soybean farming.
Industry......................... 111150 Corn farming.
Industry......................... 112111 Cattle farming or
ranching.
Industry......................... 112210 Swine, hog, and pig
farming.
Industry......................... 211130 Natural gas liquids
extraction and
fractionation.
Industry......................... 221210 Natural gas production
and distribution.
Industry......................... 324110 Petroleum refineries
(including importers).
Industry......................... 325120 Biogases, industrial
(i.e., compressed,
liquefied, solid),
manufacturing.
Industry......................... 325193 Ethyl alcohol
manufacturing.
Industry......................... 325199 Other basic organic
chemical manufacturing.
Industry......................... 424690 Chemical and allied
products merchant
wholesalers.
Industry......................... 424710 Petroleum bulk stations
and terminals.
Industry......................... 424720 Petroleum and petroleum
products wholesalers.
Industry......................... 457210 Fuel dealers.
Industry......................... 562212 Landfills.
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\a\ North American Industry Classification System (NAICS).
This table is not intended to be exhaustive, but rather provides a
guide for readers regarding entities potentially affected by this
action. This table lists the types of entities that the EPA is now
aware could potentially be affected by this action. Other types of
entities not listed in the table could also be affected. To determine
whether your entity would be affected by this action, you should
carefully examine the applicability criteria in 40 CFR parts 80 and
1090. If you have any questions regarding the applicability of this
action to a particular entity, consult the person listed in the FOR
FURTHER INFORMATION CONTACT section.
Preamble Acronyms and Abbreviations
Throughout this document the use of ``we,'' ``us,'' or ``our'' is
intended to refer to the EPA. We use multiple acronyms and terms in
this preamble. While this list may not be exhaustive, to ease the
reading of this preamble and for reference purposes, the EPA defines
the following terms and acronyms here:
AEO Annual Energy Outlook
AFDC Alternative Fuels Data Center
ATJ alcohol-to-jet
BBD biomass-based diesel
CAA Clean Air Act
CKF corn kernel fiber
CNG compressed natural gas
CO2e carbon dioxide equivalent
CWC cellulosic waiver credit
DOE U.S. Department of Energy
EIA U.S. Energy Information Administration
EMTS EPA Moderated Transaction System
EPA U.S. Environmental Protection Agency
EU European Union
FOG fats, oils, and greases
GCAM Global Change Analysis Model
gCO2e/MJ grams of carbon dioxide equivalent per megajoule
GHG greenhouse gas
GLOBIOM Global Biosphere Management Model
GREET Greenhouse gases, Regulated Emissions, and Energy use in
Technologies
GTAP-BIO Global Trade Analysis Project-Biofuels
LCFS Low Carbon Fuel Standard
LNG liquefied natural gas
MSW municipal solid waste
[[Page 16389]]
OBBB One Big Beautiful Bill Act of 2025
OPEC Organization of Petroleum Exporting Countries
PTD product transfer document
RFS Renewable Fuel Standard
RIA Regulatory Impact Analysis
RIN Renewable Identification Number
RNG renewable natural gas
RVO Renewable Volume Obligation
STP standard temperature and pressure
UCO used cooking oil
USDA U.S. Department of Agriculture
Outline of This Preamble
I. Executive Summary
A. Summary of the Key Provisions of This Action
B. Impacts of This Rule
C. Policy Considerations
D. Endangered Species Act
II. Statutory Requirements and Conditions
A. Directive To Set Volumes Requirements
B. Statutory Factors
C. Statutory Conditions on Volume Requirements
D. Authority To Establish Volume Requirements and Percentage
Standards for Multiple Years
E. Considerations Related to the Timing of This Action
F. Impact on Other Waiver Authorities
G. Severability
H. Judicial Review
III. Volume Requirements For 2026 and 2027
A. Analyzed Volumes
B. Baselines
C. Volume Changes Analyzed
D. Summary of the Assessed Impacts of the Analyzed Volumes
E. Volume Requirements for 2026 and 2027
F. Treatment of Carryover RINs
G. Consideration of Alternative Volumes
H. Summary of Final Volumes for 2026 and 2027
IV. SRE Reallocation
A. Background and Policy Rationale
B. Legal Justification
C. SRE Reallocation Volumes
V. Total Applicable Volumes and Percentage Standards for 2026 and
2027
A. Total Applicable Volumes for 2026 and 2027
B. Calculation of Percentage Standards
C. Treatment of Small Refinery Volumes
D. Percentage Standards
VI. Partial Waiver of the 2025 Cellulosic Biofuel Volume Requirement
A. Cellulosic Waiver Authority Statutory Background
B. Assessment of Cellulosic RINs Available for Compliance in
2025
C. Implementation of the Cellulosic Waiver Authority
D. Calculation of 2025 Cellulosic Biofuel Percentage Standard
VII. Removal of Renewable Electricity From the RFS Program
A. Historical Treatment of Renewable Electricity in the RFS
Program
B. Statutory Basis for Removal of Renewable Electricity From the
RFS Program
C. Implementation of Removal of Renewable Electricity From the
RFS Program
D. Withdrawal of December 2022 Proposal Regarding Renewable
Electricity
VIII. Other Changes to RFS Regulations
A. Renewable Diesel, Naphtha, and Jet Fuel Equivalence Values
B. RIN-Related Provisions
C. Percentage Standard Equations
D. Renewable Fuel Pathways
E. Updates to Definitions
F. Compliance Reporting, Recordkeeping, and Registration
Provisions
G. New Approved Measurement Protocols
H. Biodiesel and Renewable Diesel Requirements
I. Extension of RFS Compliance Reporting Deadlines
J. Biogas Regulations
K. Technical Amendments
IX. Set 1 Remand
X. Administrative Actions
A. Assessment of the Domestic Aggregate Compliance Approach
B. Assessment of the Canadian Aggregate Compliance Approach
XI. Statutory and Executive Order Reviews
A. Executive Order 12866: Regulatory Planning and Review
B. Executive Order 14192: Unleashing Prosperity Through
Deregulation
C. Paperwork Reduction Act (PRA)
D. Regulatory Flexibility Act (RFA)
E. Unfunded Mandates Reform Act (UMRA)
F. Executive Order 13132: Federalism
G. Executive Order 13175: Consultation and Coordination With
Indian Tribal Governments
H. Executive Order 13045: Protection of Children From
Environmental Health Risks and Safety Risks
I. Executive Order 13211: Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution, or Use
J. National Technology Transfer and Advancement Act (NTTAA) and
1 CFR Part 51
K. Congressional Review Act (CRA)
XII. Amendatory Instructions
XIII. Statutory Authority
I. Executive Summary
The EPA initiated the RFS program in 2006 pursuant to the
requirements of the Energy Policy Act of 2005 (EPAct), codified in CAA
section 211(o). Congress subsequently amended the statutory
requirements in the Energy Independence and Security Act of 2007
(EISA). The RFS provisions of the CAA set forth annual, nationally
applicable volume targets for three of the four categories of renewable
fuel (cellulosic biofuel, advanced biofuel, and total renewable fuel)
through 2022 and for BBD through 2012. For subsequent calendar years,
CAA section 211(o)(2)(B)(ii) directs the EPA to determine the
applicable volume targets for each of the four categories of renewable
fuel in coordination with the Secretary of Energy and the Secretary of
Agriculture, based on a review of the implementation of the RFS program
to date and an analysis of specified statutory factors.
In this final rule, we are establishing the volume targets and
applicable percentage standards for cellulosic biofuel, BBD, advanced
biofuel, and total renewable fuel for 2026 and 2027.\1\ We are also
promulgating a number of important regulatory changes, including
removing renewable electricity as a qualifying renewable fuel under the
RFS program (commonly referred to as ``eRINs''). This preamble
describes our rationale for the final volume requirements and
regulatory changes and how public comments informed the rulemaking
process.
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\1\ The 2023-2025 volume requirements and applicable percentage
standards were established on July 12, 2023 (88 FR 44468) (the ``Set
1 Rule'').
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In June 2025, the EPA issued a proposed rule that included volume
requirements for 2026 and 2027,\2\ as well as regulatory changes,
including proposals to reduce the number of Renewable Identification
Numbers (RINs) generated for imported renewable fuel and renewable fuel
produced from foreign feedstocks and to remove renewable electricity as
a qualifying renewable fuel under the RFS program.\3\ In September
2025, the EPA issued a supplemental notice of proposed rulemaking to
address recently granted small refinery exemption (SRE) petitions for
the 2023-2025 compliance years.\4\ Subsequent to each proposal, the EPA
held a public hearing and provided an opportunity for stakeholders to
submit written comments. Stakeholders from various industries and
perspectives provided the EPA with comments, data, and updated analyses
on the Set 2 proposals, and we appreciate stakeholders' input and
interest in strengthening the implementation of the RFS program. We
also engaged directly with stakeholders throughout the rulemaking
process and have documented those discussions.
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\2\ 90 FR 25784 (June 17, 2025) (the ``Set 2 proposal'').
\3\ Throughout this section we refer to imported renewable fuel
and renewable fuel produced from foreign feedstocks collectively as
``import-based renewable fuel'' and RINs generated for these types
of renewable fuel as ``import RINs.''
\4\ 90 FR 45007 (September 18, 2025) (the ``Set 2 supplemental
proposal''). Collectively, the two proposals are referred to as the
``Set 2 proposals.''
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This final rule reflects decisions made after review of public
input, coordination with the U.S. Department of Agriculture (USDA) and
Department of Energy (DOE), and extensive technical analysis. Wherever
possible, we used the most recent data available to inform our analyses
and support the final decisions and approaches described in this
preamble and
[[Page 16390]]
supporting documentation. Where appropriate, in this final rule
preamble, we highlight key stakeholder comments and provide a summary
of our response to those comments. Detailed responses to stakeholder
comments can be found in the Response to Comments (``RTC'') document
for this action.\5\
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\5\ EPA, ``RFS Program Standards for 2026 and 2027, Partial
Waiver of 2025 Cellulosic Biofuel Volume Requirement, and Other
Changes: Response to Comments Document,'' EPA-420-R-26-012, March
2026.
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In the Set 2 proposal, we proposed a significant modification to
how import-based renewable fuel would be treated under the RFS program.
We proposed these changes to better align the RFS program with American
economic interests by strengthening support for domestic growers and
biofuel producers. The Set 2 proposal did this by proposing a new
``import RIN reduction'' (IRR) policy. Stakeholders provided a
significant number of comments and data on the proposed IRR provisions,
and we appreciate the information and analyses that were submitted or
shared directly with the Agency during stakeholder meetings. Following
careful review of this information, we have concluded that more time
would be needed to successfully establish and implement IRR provisions.
Therefore, we are not finalizing the proposed IRR provisions as part of
this final rule in connection with the renewable fuel volume
requirements for 2026 and 2027. We intend, however, to establish IRR
provisions that will take effect beginning in the 2028 compliance year
or shortly thereafter. We discuss IRR considerations and our intent for
future action further in section I.C of this preamble.
The volume requirements finalized in this action will strengthen
the RFS program, boost renewable fuel use, and provide strong support
to the domestic feedstock producers, renewable fuel producers, and
agricultural communities across the country. The final volume
requirements further these objectives, even though the IRR provisions
will follow at a later date. Ensuring a growing supply of domestically
produced renewable fuels is a key component in meeting the statutory
goals of increasing the energy independence and security of the United
States. Increasing domestic production of renewable fuel also
contributes to unleashing American energy production towards the goal
of achieving energy dominance, consistent with the Administration's
``Unleashing American Energy'' Executive Order \6\ and the energy
dominance pillar of the EPA's ``Powering the Great American Comeback''
initiative.\7\ The requirements in this action are responsive to input
from key agricultural and energy stakeholders on ways to bolster the
RFS program.
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\6\ Executive Order 14154, ``Unleashing American Energy,''
January 20, 2025 (90 FR 8353; January 29, 2025).
\7\ EPA, ``EPA Administrator Lee Zeldin Announces EPA's
`Powering the Great American Comeback' Initiative,'' February 4,
2025. https://www.epa.gov/newsreleases/epa-administrator-lee-zeldin-announces-epas-powering-great-american-comeback.
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A. Summary of the Key Provisions of This Action
1. Volume Requirements for 2026 and 2027
Based on our analysis of the factors required in the statute, and
in coordination with USDA and DOE, we are establishing the volume
requirements for 2026 and 2027, as shown in Table I.A.1-1. The final
volumes represent significant increases of over 15 percent from those
established for 2023-2025. Much of the increase in the volume
requirements in this final rule are attributable to the EPA's decision
not to finalize the proposed IRR provisions in this action. The total
quantity of renewable fuel we project will be supplied to the U.S. to
meet these volume requirements (shown in Table I.A.1-2) are very
similar to the quantities we projected would be supplied to meet the
proposed volume requirements.\8\ We note that the volume requirements
in Table I.A.1-1 do not include the SRE reallocation volumes we are
also finalizing in this action (see section I.A.2 of this preamble).
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\8\ In the Set 2 proposal, we projected that the total volume of
renewable fuel supplied to meet the proposed volume requirements
would be 22.10 billion gallons and 22.37 billion gallons in 2026 and
2027, respectively. As shown in Table I.A.1-2, we project that 21.87
billion gallons and 22.25 billion gallons of renewable fuel will be
supplied in 2026 and 2027, respectively, to meet the volume
requirements we are finalizing in this rule.
[GRAPHIC] [TIFF OMITTED] TR01AP26.026
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We project that the production and use of renewable fuels in the
U.S. will increase significantly in response to these volume
requirements. The quantities of renewable fuel we project will be
supplied to satisfy the volume requirements, after accounting for the
nested nature of the RFS volume requirements, are shown in Table I.A.1-
2. These volumes are similar to those we projected would be supplied in
the Set 2 proposal and reflect updates to EPA's analysis of the
potential supply of renewable fuel in these years and the impacts of
these fuels on the statutory factors.
[GRAPHIC] [TIFF OMITTED] TR01AP26.027
As discussed above, CAA section 211(o) requires the EPA to analyze
a specified set of factors in making our determination of the
appropriate volume requirements. Many of those factors, particularly
those related to economic and environmental impacts, are difficult to
analyze in the abstract. To facilitate a more concrete and meaningful
analysis of the statutory factors, we first identified a set of
renewable fuel volumes to analyze prior to determining the final volume
requirements. To identify those renewable fuel volumes for analysis, we
generally considered factors most likely to limit the domestic
production and/or use of qualifying renewable fuels in 2026 and 2027.
In some cases, the limiting factors we identified were based on our
assessment of the ability of the U.S. market to consume renewable fuels
in the transportation sector, while in other cases they were based on
domestic production capacity. We discuss the derivation of these
volumes for analysis in section III of this preamble. We also discuss
in section III of this preamble the analysis of the statutory factors
with respect to these volumes and our conclusions regarding the
appropriate volume requirements to establish in light of the analyses
we conducted.
The cellulosic biofuel volumes we are finalizing for 2026 and 2027
represent increases over the volumes in the Set 1 Rule. Compressed
natural gas (CNG) and liquefied natural gas (LNG) derived from biogas
comprise most of the qualifying cellulosic biofuel that we project will
be supplied through 2027. Consistent with the analysis presented in the
Set 2 proposal,\9\ and supported by data submitted by commenters and
analysis conducted subsequent to the Set 2 proposal, we project that
the use of renewable CNG/LNG used as transportation fuel will be
limited by the number of vehicles capable of using these fuels in 2026
and 2027. The cellulosic biofuel volume requirements we are finalizing
in this action reflect an updated analysis of the quantity of renewable
CNG/LNG that will be used as transportation fuel in 2026 and 2027. The
final cellulosic biofuel volumes also include projections of cellulosic
ethanol from corn kernel fiber (CKF) produced at existing corn starch
ethanol production facilities.
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\9\ 90 FR 25784 (June 17, 2025).
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Stakeholders provided the EPA with extensive comments and data
regarding the proposed BBD and advanced biofuel volume requirements
along with their views on appropriate levels for the final volume
requirements. Following issuance of the Set 2 proposal, we carefully
reviewed all new information and engaged directly and extensively with
stakeholders from relevant sectors on this topic. The BBD and advanced
biofuel volumes we are finalizing for 2026 and 2027 reflect the
significant growth observed in the production of these fuels over the
past several years and build off the volumes already achieved in the
marketplace in previous years. The final volume requirements reflect
the projected growth in the domestic production capacity and supply of
feedstocks, primarily soybean oil, with smaller projected increases in
other feedstocks including used cooking oil (UCO) and animal fats. We
have also adjusted the final BBD volume requirements, as expressed in
billion RINs, relative to the proposed volume requirements to account
for the fact that we are not finalizing the proposed IRR provisions at
this time in connection with the volume requirements for 2026 and 2027.
The final volume requirements for total renewable fuel in 2026 and
2027 reflect an implied conventional biofuel volume requirement of 15
billion gallons each year. This is consistent with the implied
conventional renewable fuel volumes in the statutory
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tables for 2015-2022,\10\ as well as the implied conventional biofuel
volumes we established for 2023-2025 in the Set 1 Rule. We recognize
that while the supply of conventional biofuel in 2026 and 2027 will
likely fall short of the 15-billion-gallon implied conventional biofuel
volume requirement, the final total renewable fuel volume requirements
are still achievable through the use of additional volumes of advanced
biofuel beyond the volume requirement for that category.
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\10\ CAA section 211(o)(2)(B)(i).
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Although the Set 1 Rule established volumes for three years (2023-
2025), we believe that it is appropriate at this time to establish
volume requirements for two years instead of a longer timeframe. There
is increased uncertainty in trying to project out further in the
future, which increases the likelihood of needing to adjust volumes in
the future. Retroactive adjustments to volume requirements create
uncertainty in the RFS program and hinder the purpose of projecting
future years, which is meant to provide certainty to the market.
2. Reallocation of Small Refinery Exemptions for 2023-2025
After the release of the Set 2 proposal, the EPA issued decisions
on 175 SRE petitions in August 2025.\11\ These decisions included
numerous grants and partial grants that relieved many small refineries
from their renewable volume obligations (RVOs) for past compliance
years. To mitigate the potential market impacts of these decisions, in
the Set 2 supplemental proposal we proposed reallocating all or a
portion of the exempted RVOs for the 2023-2025 compliance years (the
years for which the exemptions would potentially materially impact the
current RIN and renewable fuel markets) to the 2026 and 2027 compliance
years.\12\ After the release of the Set 2 supplemental proposal, the
EPA issued decisions on an additional 16 SRE petitions in November
2025.\13\ In this final rule, after considering relevant comments,
data, and analyses received from interested stakeholders on the Set 2
proposals, we are finalizing a 70 percent partial reallocation of the
2023-2025 exempted RVOs to the 2026 and 2027 compliance years. This
partial reallocation is intended to prevent the 2023-2025 exemptions
from significantly and negatively impacting biofuel demand in 2026 and
2027, while also recognizing the importance of the availability of
carryover RINs to a liquid and smoothly functioning RIN market. The
renewable fuel volume requirements, SRE reallocation volumes, and total
applicable volumes we are finalizing in this action for 2026 and 2027
are shown in Table I.A.2-1. We further discuss our reallocation of
2023-2025 exempted RVOs in section IV of this preamble.
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\11\ EPA, ``August 2025 Decisions on Petitions for RFS Small
Refinery Exemptions,'' EPA-420-R-25-010, August 2025 (``August 2025
SRE Decisions Action'').
\12\ 90 FR 45007 (September 18, 2025).
\13\ EPA, ``November 2025 Decisions on Petitions for RFS Small
Refinery Exemptions,'' EPA-420-R-25-013, November 2025 (``November
2025 SRE Decisions Action'').
[GRAPHIC] [TIFF OMITTED] TR01AP26.028
The total applicable volumes that we are establishing in this
action are the basis for the calculation of percentage standards
applicable to producers and importers of gasoline and diesel. The
calculation of the final percentage standards is discussed further in
section V of this preamble.
3. Partial Waiver of the 2025 Cellulosic Biofuel Volume Requirement
Consistent with the Set 2 proposal, we are finalizing a partial
waiver of the 2025 cellulosic biofuel volume requirement and revising
the associated percentage standard due to a 0.17 billion RIN shortfall
in the volume of cellulosic biofuel available in 2025. As such, we are
using our CAA section 211(o)(7)(D) ``cellulosic waiver authority'' to
reduce the 2025 cellulosic biofuel volume from 1.38 billion RINs to
1.21 billion RINs. The use of such waiver authority also makes
cellulosic waiver credits (CWCs) available for the 2025 compliance
year. We further discuss our partial waiver of the 2025 cellulosic
biofuel volume requirement in section VI of this preamble.
4. Removal of Renewable Electricity From the RFS Program
In the Set 2 proposal, we proposed to remove renewable electricity
as a qualifying renewable fuel under the RFS program. We discussed the
EPA's difficulties in establishing a workable regulatory framework for
such a program and sought comment on whether such a program is
consistent with the best reading of the statute in the first
instance.\14\ In this final rule, after considering relevant comments
received on this issue, we are finalizing the removal of electricity as
a qualifying renewable fuel under the RFS program. We conclude that
renewable electricity does not meet the definition of renewable fuel
under CAA section 211(o)(1)(J), read in context and considering the
structure of the statute as a whole. We are therefore removing the
regulations related to the production and use of renewable electricity
as a transportation fuel, including the regulations related to facility
registration for renewable electricity producers and the provisions for
generating RINs for use of renewable electricity as a transportation
fuel. We are also removing the definition of ``renewable electricity''
and the renewable electricity pathways in Table 1 to 40 CFR 80.1426 in
connection with this change. In addition, we are withdrawing our
December 2022 proposal associated with the Set 1 Rule pertaining to
renewable electricity,\15\
[[Page 16393]]
which was not finalized as part of the Set 1 Rule.\16\
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\14\ 90 FR 25784, 25841-42 (June 17, 2025).
\15\ 87 FR 80582 (December 30, 2022).
\16\ 88 FR 44468, 44471 (July 12, 2023).
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5. Other Regulatory Changes
In the Set 2 proposal, we proposed a series of regulatory changes
in several areas to strengthen our implementation of the RFS program
that we are now finalizing. The final changes take into account
comments and new information provided by stakeholders during the public
comment period. These regulatory changes are discussed in greater
detail in section VIII of this preamble and include:
Specifying new equivalence values for renewable diesel,
naphtha, and jet fuel.
Updating RIN generation and assignment provisions.
Clarifying that RINs cannot be generated for renewable
fuel that is used for process heat or electricity generation.
Changing the percentage standards equations, including
specifying the BBD standard in RINs rather than physical gallons.
Updating existing renewable fuel pathways and adding new
ones.
Adding definitions for terms used throughout the
regulations and updating other definitions.
Adding a joint and several liability provision applicable
to importers of renewable fuel.
Revising compliance reporting and registration provisions,
including clarifying that small refineries that receive an exemption
from their RFS obligations must still submit an annual compliance
report.
Clarifying certain requirements for biodiesel and
renewable diesel.
Other minor changes and technical corrections.
In addition, we are also finalizing several revisions to the RFS
regulations that were originally proposed in the proposed partial
waiver of the 2024 cellulosic biofuel volume requirement, including
provisions that will automatically extend the annual compliance
reporting deadline for a given compliance year if we propose to revise
an existing RFS standard for that year.\17\
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\17\ 89 FR 100442 (December 12, 2024).
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We are also making minor revisions to two main areas of the RFS
program's biogas regulations that were identified after the EPA and
market participants began implementing the regulations promulgated in
the Set 1 Rule. First, we are clarifying and providing flexibility for
how biogas, renewable natural gas (RNG), and renewable CNG/LNG are
measured, sampled, and tested to demonstrate compliance.
Second, we are making the following technical amendments to the
biogas regulations:
Clarifying what constitutes a batch of RNG.
Clarifying the requirements for the generation,
assignment, and separation of RINs for RNG.
Clarifying the registration requirements for biogas
producers, RNG producers, and RNG RIN separators.
Clarifying the attest engagement requirements for biogas
producers, RNG producers, and RNG RIN separators.
Numerous clarifications, corrections, and consistency
edits to the biogas regulations.
B. Impacts of This Rule
CAA section 211(o)(2)(B)(ii) requires the EPA to assess several
factors when determining volume requirements for calendar years after
2022. These factors are described in section II of this preamble, and
the expected impacts on each factor are discussed briefly in section
III of this preamble and in greater detail in the Regulatory Impact
Analysis (RIA) accompanying this rule.\18\ However, the statute does
not specify how the EPA must assess each factor or the weight each
factor bears on the overall analysis. For two of these statutory
factors--costs and energy security--we provide monetized estimates of
the impacts of the final volume requirements. For the other statutory
factors, we are either unable to quantify impacts at this time or we
provide quantitative estimated impacts that nevertheless cannot be
easily monetized. Thus, we are unable to quantitatively compare all the
evaluated impacts of this rulemaking.
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\18\ EPA, ``RFS Program Standards for 2026 and 2027, Partial
Waiver of 2025 Cellulosic Biofuel Volume Requirement, and Other
Changes: Regulatory Impact Analysis,'' EPA-420-R-26-011, February
2026.
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We considered all statutory factors in developing this final rule,
including factors for which we provide monetized impacts, otherwise
quantify impacts, or provide a qualitative assessment of relevant
impacts, and we find that the final volumes are appropriate under our
statutory authority after balancing all relevant factors. This approach
is consistent with CAA section 211(o)(2)(B)(ii), which requires the
Administrator to ``determin[e]'' volumes based on ``an analysis of''
the statutory factors and does not require that analysis to monetize or
quantify all relevant considerations. A summary of our assessment of
the impacts of this action can be found in section III.H of this
preamble. RIA Table ES-1 provides a list of all the impacts that we
assessed, both quantitative and qualitative. Additional detail for each
of the assessed factors is provided in RIA Chapters 4 through 10.
C. Policy Considerations
The RFS program is a critical policy tool that supports the
domestic production and use of renewable fuels. This final rule seeks
to get the RFS program back on track by aligning the incentives
provided by the RFS program with the statutory goals of, among other
things, increasing energy independence and energy security. The final
volumes for 2026 and 2027 reflect the significant growth potential, in
particular, for domestic renewable fuel production in the U.S., and
will help strengthen rural agricultural communities and industries.
As discussed above, the Set 2 proposal included provisions that
would have reduced the number of RINs generated for import-based
renewable fuel, thereby better aligning the RFS program with American
economic and security interests and strengthening support for American
farmers and domestic renewable fuel producers. The RFS program has
always allowed for import-based renewable fuel, but the surge of
imports of both feedstocks and renewable fuels in recent years has
destabilized domestic biofuel investments and U.S. agricultural
production, all while rewarding foreign feedstock and renewable fuel
producers. We proposed IRR provisions affecting import-based renewable
fuel in the Set 2 proposal. Such import-based renewable fuels do not
further energy independence and are projected to result in fewer
employment and rural economic development benefits relative to
renewable fuels produced in the U.S. from domestic feedstocks. We
proposed that, under the IRR provisions, import-based renewable fuels
would only generate half the number of RINs that they generate under
the current RFS regulations, and sought comment on this overall concept
and how it should be implemented if finalized.
We appreciate the extensive stakeholder input we received on the
proposed IRR provisions. Public comments provided perspectives on all
aspects of the proposed IRR provisions, from overarching concepts and
policy goals to timing and other implementation details. We carefully
reviewed all the comments we received and found that many stakeholders
made compelling arguments regarding when and how IRR provisions could
be most effectively phased in and integrated into
[[Page 16394]]
the RFS program. Commenters indicated that the proposed IRR provisions
could result in significant changes in the supply of renewable fuels
and feedstocks to U.S. markets and that these changes could be
disruptive without sufficient lead time for the market to prepare and
make the necessary adjustments--including leading to increase in
gasoline and diesel prices. Other comments provided constructive
feedback concerning regulatory or definitional gaps in the proposed
design of the IRR provisions and suggested that we could strengthen the
IRR provisions by clarifying various elements of the proposed approach.
We also recognize that there have been important changes in the broader
policy context in which the RFS program operates, including changes to
key Federal biofuel tax credits (we discuss those changes in section
III of this preamble and the RIA).
After reviewing this input, we have determined that it is
appropriate and prudent to take additional time to address some of
these timing and implementation questions regarding the proposed IRR
provisions. In light of that determination, we are not finalizing the
proposed IRR provisions in this final rule in the context of
establishing the volume requirements for 2026 and 2027. We continue to
believe that the IRR concept is appropriate and would better align the
RFS program with the statutory goals for the program. Given the
importance of the policy objectives underlying the proposed IRR
provisions, and the support expressed for it by many stakeholders, we
intend to establish IRR provisions that will take effect at the
beginning of the 2028 compliance year or sometime shortly thereafter.
We are currently considering our next steps and will communicate with
stakeholders as we establish our plans.
In the Set 2 proposal, we also requested comment on other
opportunities to improve the RFS program that could be considered in
future actions. Our request for comments included areas such as a
general pathway for the production of renewable jet fuel from corn
ethanol, the definition of ``produced from renewable biomass,''
additional RFS program amendments to ensure that imported renewable
fuels are produced from qualifying feedstocks and enhance our ability
to track feedstocks to their point of origin, RFS program enhancements
to increase the use of qualifying woody-biomass to produce renewable
transportation fuel, and any other modifications to the RFS program
designed to unleash the production of American energy. We also received
comments on the definitions for different types of woody biomass under
the RFS program. EPA may consider modifications to relevant definitions
such as ``areas at risk of wildfire,'' ``slash,'' ``pre-commercial
thinnings,'' and ``tree residue,'' in a future rulemaking. We
appreciate stakeholders' input on these topics and many others raised
in the comments and will consider potential ways to address these areas
in future actions.
D. Endangered Species Act
Section 7(a)(2) of the Endangered Species Act (ESA), 16 U.S.C.
1536(a)(2), requires that federal agencies such as the EPA, in
consultation with the U.S. Fish and Wildlife Service (USFWS) and/or the
National Marine Fisheries Service (NMFS) (collectively ``the
Services''), ensure that any action authorized, funded, or carried out
by the action agency is not likely to jeopardize the continued
existence of any endangered or threatened species or result in the
destruction or adverse modification of designated critical habitat for
such species. Under relevant implementing regulations, the action
agency is required to consult with the Services for actions that ``may
affect'' listed species or designated critical habitat.\19\
Consultation is not required where the action would have no effect on
such species or habitat.
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\19\ 50 CFR 402.14.
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Consistent with ESA section 7(a)(2) and relevant implementing
regulations at 50 CFR part 402, we engaged in informal consultation
with the Services and completed a Biological Evaluation (BE) for the
Set 2 Rule.\20\ Supported by the analysis in the Set 2 Rule BE, we
determined that formal consultation is not required for the Set 2 Rule
because of the absence of likely adverse effects on listed species and
their habitats. EPA has prepared an ESA section 7(d) determination
memorandum that discusses our decision to finalize this action before
the informal consultation process is complete.\21\
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\20\ EPA, ``Biological Evaluation of the Renewable Fuel Standard
Set 2 Rule,'' 2026 (``Set 2 Rule BE'').
\21\ See ``Endangered Species Act Section 7(d) Determination
with Respect to the Issuance of the Renewable Fuel Standard (RFS)
Program: Standards for 2026 and 2027, Partial Waiver of 2025
Cellulosic Biofuel Volume Requirement, and Other Changes,''
available in the docket for this action.
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II. Statutory Requirements and Conditions
A. Directive To Set Volumes Requirements
Congress enacted the RFS program for the purpose of increasing the
use of renewable fuel in transportation fuel over time. Congress
specified statutory volumes for the initial years of the program,
including for BBD through 2012, and for total renewable fuel, advanced
biofuel, and cellulosic biofuel through 2022, but allowed the EPA to
waive the statutory volumes in certain circumstances. For years after
2022, Congress provided the EPA with the directive and authority to
establish the applicable renewable fuel volume requirements.\22\ This
section of the preamble discusses our statutory authority and
additional factors we have considered due to the timing of this
rulemaking, as well as the severability of the various portions of this
rule. We generally respond to stakeholder comments received on these
topics in the RTC document.
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\22\ We refer to CAA section 211(o)(2)(B)(ii) as the ``set
authority.''
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B. Statutory Factors
CAA section 211(o)(2)(B)(ii) establishes the processes, criteria,
and standards for setting the applicable annual renewable fuel volumes.
That provision provides that the EPA shall, in coordination with USDA
and DOE,\23\ determine the applicable volumes of each renewable fuel
category, based on a review of the implementation of the program during
the calendar years specified in the tables in CAA section
211(o)(2)(B)(i) and an analysis of the following factors:
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\23\ In furtherance of this requirement, we have continued
periodic discussions with USDA and DOE on this action. We have
documented the coordination with the EPA Administrator and
Secretaries in a memorandum available in the docket for this action.
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The impact of the production and use of renewable fuels on
the environment, including on air quality, climate change, conversion
of wetlands, ecosystems, wildlife habitat, water quality, and water
supply;
The impact of renewable fuels on the energy security of
the United States;
The expected annual rate of future commercial production
of renewable fuels, including advanced biofuels in each category
(cellulosic biofuel and BBD);
The impact of renewable fuels on the infrastructure of the
United States, including deliverability of materials, goods, and
products other than renewable fuel, and the sufficiency of
infrastructure to deliver and use renewable fuel;
The impact of the use of renewable fuels on the cost to
consumers of transportation fuel and on the cost to transport goods;
and
[[Page 16395]]
The impact of the use of renewable fuels on other factors,
including job creation, the price and supply of agricultural
commodities, rural economic development, and food prices.
Congress enumerated factors that the EPA must consider without
mandating any particular types of analyses or specifying how the EPA
must weigh the various factors against one another. Thus, as the CAA
``does not state what weight should be accorded to the relevant
factors,'' the statute ``give[s] EPA considerable discretion to weigh
and balance the various factors required by statute.'' \24\ These
factors were analyzed in the context of the Set 1 Rule,\25\ as well as
the 2020-2022 RFS Rule that modified volumes under CAA section
211(o)(7)(F),\26\ which requires the EPA to comply with the processes,
criteria, and standards in CAA section 211(o)(2)(B)(ii). Our assessment
of the factors in the 2020-2022 RFS Rule was upheld by the D.C. Circuit
in Sinclair.\27\ Similarly, our assessment of the factors in the Set 1
Rule was largely upheld in CBD.\28\ Consistent with our past practice
in evaluating the factors,\29\ in this final rule we have again
determined that a holistic balancing of the factors is appropriate.\30\
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\24\ CBD, 141 F.4th at 171; Sinclair Wyo. Refin. Co. LLC v. EPA,
101 F.4th 871, 887 (D.C. Cir. 2024); see also Brown v. Watt, 668
F.2d 1290, 1317 (D.C. Cir. 1981) (``A balancing of factors is not
the same as treating all factors equally. The obligation instead is
to look at all factors and then balance the results. The Act does
not mandate any particular balance, but vests the [agency] with
discretion to weigh the elements . . . .'').
\25\ See 88 FR 44468, 44476 (July 12, 2023).
\26\ See 87 FR 39600, 39607-08 (July 1, 2022).
\27\ Sinclair, 101 F.4th at 888-89.
\28\ CBD, 141 F.4th at 169-76. To the extent the court found
fault in our analysis, we have provided a response in section IX of
this preamble.
\29\ 87 FR 39600, 39607-08 (July 1, 2022).
\30\ EPA, ``RFS Annual Rules: Response to Comments,'' EPA-420-R-
22-009, June 2022 (``2020-2022 RFS Rule RTC''), at 10.
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In addition to those factors listed in the statute, the EPA also
has authority to consider ``other'' factors, including both the implied
authority to consider factors that inform our analysis of the statutory
factors and the explicit authority under CAA section
211(o)(2)(B)(ii)(VI) to consider ``the impact of the use of renewable
fuels on other factors.'' Accordingly, for this final rule, we
considered several other relevant factors beyond those enumerated in
CAA section 211(o)(2)(B)(ii), including:
The interconnected nature of the volume requirements for
2026 and 2027, including the nested nature of those volume requirements
and the availability of carryover RINs (sections III.E and III.H of
this preamble).\31\
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\31\ This also informs our analysis of the statutory factor
``review of the implementation of the program'' in CAA section
211(o)(2)(B)(ii).
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The ability of the market to respond given the timing of
this rulemaking (RIA Chapter 7).\32\
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\32\ This also informs our analysis of the statutory factor
``the expected annual rate of future commercial production of
renewable fuels'' in CAA section 211(o)(2)(B)(ii)(III).
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The supply of qualifying renewable fuels to U.S. consumers
(section III of this preamble).\33\
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\33\ This is based on our analysis of the statutory factor the
expected annual rate of future commercial production of renewable
fuel as well as of downstream constraints on biofuel use, including
the statutory factors relating to infrastructure and costs.
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C. Statutory Conditions on Volume Requirements
As indicated above, the CAA does not specify how the EPA is to
consider the enumerated factors or any particular weight each factor
must be given in the overall analysis. However, the CAA contains three
overarching conditions that affect our determination of the applicable
volume requirements:
A constraint in setting the applicable volume of total
renewable fuel as compared to advanced biofuel, with implications for
the implied volume requirement for conventional renewable fuel.
Direction in setting the cellulosic biofuel applicable
volume regarding potential future waivers.
A floor on the applicable volume of BBD.
We discuss these conditions in further detail below.
1. Advanced Biofuel as a Percentage of Total Renewable Fuel
While the statute generally provides broad discretion in setting
the applicable volume requirements for advanced biofuel and total
renewable fuel, it also establishes a constraint on the relationship
between these two volume requirements. CAA section 211(o)(2)(B)(iii)
provides that the applicable advanced biofuel requirement must ``be at
least the same percentage of the applicable volume of renewable fuel as
in calendar year 2022,'' meaning that the EPA must, at a minimum,
maintain the ratio of advanced biofuel to total renewable fuel that was
established for 2022 for all future years in which the EPA itself sets
the applicable volume requirements. In effect, this proportional
requirement limits the proportion of the implied volume of conventional
renewable fuel within the total renewable fuel volume for years after
2022 based on the proportion that existed for calendar year 2022.
The applicable advanced biofuel volume requirement established for
2022 was 5.63 billion gallons.\34\ The total renewable fuel volume
requirement established for 2022 was 20.63 billion gallons, resulting
in an implied conventional volume requirement of 15 billion gallons.
Thus, advanced biofuel represented 27.3 percent of total renewable fuel
for 2022, and we must maintain at least that percentage of the advanced
biofuel volume requirement as compared to the total renewable fuel
volume requirement for all subsequent years. The volume requirements we
are establishing in this action for 2026 and 2027, including the SRE
reallocation volumes further described in section IV of this preamble,
and shown in Table I.A.2-1, exceed this 27.3 percent minimum, and thus
satisfy this statutory requirement for each year.
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\34\ 87 FR 39601 (July 1, 2022).
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2. Cellulosic Biofuel
CAA section 211(o)(2)(B)(iv) requires that the EPA set the
applicable cellulosic biofuel requirement ``based on the assumption
that the Administrator will not need to issue a waiver . . . under [CAA
section 211(o)](7)(D)'' for the years in which the EPA sets the
applicable volume requirement. We have historically interpreted this
requirement to mean that the cellulosic biofuel volume requirement
should be set at a level that is achievable such that we do not
anticipate a need to further lower the requirement through a waiver
under CAA section 211(o)(7)(D).\35\ CAA section 211(o)(7)(D) provides
that if ``the projected volume of cellulosic biofuel production is less
than the minimum applicable volume established under paragraph
(2)(B),'' the EPA ``shall reduce the applicable volume of cellulosic
biofuel required under paragraph (2)(B) to the projected volume
available during that calendar year.'' We maintain this interpretation
of the statute. Therefore, we are establishing the cellulosic biofuel
volume requirements such that a waiver of those requirements is not
anticipated to be necessary for those future years. Operating within
this limitation, and in light of our consideration of the statutory
factors explained in section III of this preamble, we are establishing
cellulosic volumes for 2026 and 2027 at
[[Page 16396]]
the projected volume available in each year, respectively, consistent
with our past actions in determining the cellulosic biofuel volume.\36\
These projections, discussed further in section III.A.1 of this
preamble, represent our best efforts to project the potential for
growth in the volume of cellulosic biofuel that can be achieved in 2026
and 2027.
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\35\ The cellulosic waiver authority applies when the projected
volume of cellulosic biofuel production is less than the minimum
applicable volume, per CAA section 211(o)(7)(D).
\36\ See, e.g., 87 FR 39600 (July 1, 2022) (2020-2022 RFS Rule).
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We recognize that, for 2024 and 2025, the volume of cellulosic
biofuel available was less than the volume required, and we have
partially waived the 2024 cellulosic biofuel volume requirement and are
partially waiving the 2025 cellulosic biofuel volume requirement in
this action as discussed in section VI of this preamble. In projecting
the available volume of cellulosic biofuel in 2026 and 2027, we have
considered our over-projections in previous years and have adjusted our
methodology as discussed in section III.A of this preamble and RIA
Chapter 7.1 to reflect our consideration of the prior shortfalls in the
standards. Retroactive waivers of the volume requirements under the RFS
program decrease certainty for the market and undermines confidence in
the volumes and standards we set, which could negatively impact
investment in renewable fuel production in future years. In this
action, we are changing the methodology used to project cellulosic
biofuel volumes to avoid the need for waivers of the RFS standards in
the future.
3. Biomass-Based Diesel
We have established the BBD volume requirement under CAA section
211(o)(2)(B)(ii) for the years since 2013 because the statute only
specifies BBD volume requirements through 2012. CAA section
211(o)(2)(B)(iv) also requires that the BBD volume requirement be set
at, or greater than, the 1.0-billion-gallon volume requirement
enumerated by statute for 2012, but it does not provide any other
numerical criteria that the EPA must consider. In the years since 2012,
we have steadily increased the BBD volume requirement beyond 1.0
billion gallons to 3.35 billion gallons in 2025. In this action, we are
establishing 2026 and 2027 BBD applicable volumes of 9.07 and 9.20
billion RINs, respectively.\37\ These numbers are not directly
comparable with the BBD volume requirements in previous years, as they
express the required volume of BBD in RINs rather than physical
gallons. Nevertheless, the final BBD volume requirements guarantee that
at least 5.33 and 5.75 billion gallons of BBD will be used in 2026 and
2027, respectively,\38\ far greater than 1.0-billion-gallon minimum
requirement.\39\
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\37\ As noted in section I.A.1 and explained further in section
VII.C of this preamble, we are specifying the BBD volume requirement
in RINs, rather than gallons. This is in contrast to establishing
the 2025 BBD volume requirement at 3.35 billion physical gallons.
\38\ These volumes represent the lowest possible volume of BBD
that could be used to meet the final BBD volume requirements for
2026 and 2027. These numbers are calculated by dividing the final
BBD RIN requirements by 1.7 in 2026 (the equivalence value for
renewable diesel in 2026) and 1.6 in 2027 (the highest equivalence
value we anticipate in 2027, as discussed in in section VIII.A of
this preamble). In practice, we project that significantly greater
volumes of BBD will be supplied to meet the BBD volume requirements,
as biodiesel and some renewable diesel will only generate 1.5 RINs
per gallon in these years.
\39\ Because the EPA interpreted the BBD volume requirement in
physical gallons at the time the 1.0-billion-gallon standard for
2012 was established, we provide our comparison of the 2026 and 2027
BBD volume requirements to this minimum volume requirement in
physical gallons, rather than RINs.
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D. Authority To Establish Volume Requirements and Percentage Standards
for Multiple Years
In this action, we are establishing the applicable volume
requirements and percentage standards for 2026 and 2027. We have a
statutory obligation to promulgate volume requirements under CAA
section 211(o)(2)(B)(ii) and are addressing that requirement in this
final rule. We acknowledge that the statutory deadlines for
promulgating the 2026 and 2027 applicable volume requirements passed on
October 31, 2024, and October 31, 2025, respectively. Nevertheless, we
are establishing the 2026 and 2027 applicable volume requirements ahead
of the 2027 compliance year, and early in the 2026 compliance year.
As to the percentage standards with which obligated parties must
comply, CAA section 211(o)(A)(i) and (iii) requires the EPA to
promulgate regulations that, regardless of the date of promulgation,
contain compliance provisions applicable to refineries, blenders,
distributors, and importers that ensure that the volumes in CAA section
211(o)(2)(B)--which includes volumes set by the EPA after 2022--are
met. As in the Set 1 Rule, we are also establishing corresponding
percentage standards in this action.\40\
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\40\ 88 FR 44468, 44519-21 (July 14, 2023).
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In summary, we are establishing applicable volume requirements and
associated percentage standards for 2026 and 2027, as further described
in sections III and V of this preamble.
E. Considerations Related to the Timing of This Action
In this action, we are establishing applicable volume requirements
for the 2026 and 2027 compliance years after the statutory deadlines to
establish such requirements (October 31, 2024, and October 31, 2025,
respectively).\41\ We have also missed statutory deadlines in the past
for promulgating RFS standards, including the 2023 and 2024 standards
established in the Set 1 Rule, and the BBD volume requirements for
2014-2017, which were established under CAA section 211(o)(2)(B)(ii),
the same provision under which we are establishing the 2026 and 2027
standards in this action.
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\41\ See CAA section 211(o)(2)(B)(ii), requiring the EPA to
promulgate applicable volume requirements no later than 14 months
prior to the first year in which they will apply.
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In its review of the EPA's 2015 action establishing BBD volume
requirements for 2014-2017,\42\ the D.C. Circuit found that the EPA
retains authority beyond the statutory deadlines to promulgate volumes
and annual percentage standards, even those that apply retroactively,
so long as the EPA exercises this authority reasonably.\43\ We had
missed the statutory deadline under CAA section 211(o)(2)(B)(ii) to
establish an applicable volume requirement for BBD no later than 14
months before the first year to which that volume requirement will
apply for all years. The D.C. Circuit held that when the EPA exercises
this authority after the statutory deadline, the EPA must balance the
burden on obligated parties of a delayed rulemaking with the broader
goal of the RFS program to increase renewable fuel use.\44\ In
specifically upholding the portion of that rulemaking that was late but
not retroactive, the court considered whether there was sufficient lead
time and adequate notice for obligated parties.\45\ The court found
that the EPA properly balanced the relevant considerations and provided
sufficient notice to parties in establishing the applicable volume
requirements for 2014-2017.\46\
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\42\ 80 FR 77420, 77427-28, 77430-31 (December 14, 2015).
\43\ Americans for Clean Energy (ACE) v. EPA, 864 F.3d 691 (D.C.
Cir. 2017) (the EPA may issue late applicable volumes under CAA
section 211(o)(2)(B)(ii)); Monroe Energy, LLC v. EPA, 750 F.3d 909
(D.C. Cir. 2014); NPRA v. EPA, 630 F.3d 145, 154-58 (D.C. Cir.
2010); see also CBD, 141 F.4th at 184-85; Sinclair, 101 F.4th at
887.
\44\ NPRA v. EPA, 630 F.3d at 164-65.
\45\ ACE, 864 F.3d at 721-22.
\46\ ACE, 864 F.3d at 721-23.
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Similarly, in its review of the Set 1 Rule, the D.C. Circuit
concluded that the EPA's determination of the 2023 and
[[Page 16397]]
2024 standards after the statutory deadline was permissible.\47\ The
court noted its repeated holdings that the ``EPA may promulgate late,
and even retroactive, volume requirements so long as it `reasonably
considers and mitigates any hardship caused to obligated parties by
reason of the lateness.' '' \48\ In so holding, the court noted that
the EPA's explanation of the achievability of the RFS standards, the
timing of compliance demonstrations in relation to the final rule and
existing flexibilities in the RFS program for obligated parties.\49\
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\47\ CBD, 141 F.4th at 183-84.
\48\ CBD, 141 F.4th at 184.
\49\ Id.
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In this final rule, we are exercising our authority to set the
applicable renewable fuel volume requirements for 2026 and 2027 after
the statutory deadline to promulgate such volume requirements under CAA
section 211(o)(2)(B)(ii). The 2026 standards will also have a partially
retroactive effect, as we are finalizing the standards after the
beginning of the 2026 calendar year. Nevertheless, we believe that the
2026 and 2027 standards being finalized in this action can be met in
the market by obligated parties (see section III of this preamble and
RIA Chapter 7). We are finalizing the 2027 standards prior to the
beginning of the 2027 compliance year (i.e., before January 1, 2027)
and thus these standards do not apply retroactively. Additionally, we
provided obligated parties notice as of June 17, 2025, and September
18, 2025, of the proposed 2026 and 2027 standards, several months ahead
of when the 2026 standards would apply, and over a year in advance of
when the 2027 standards would apply. As described in section I.C of
this preamble, while the volume requirements we are finalizing in this
action appear larger than the proposed volume requirements, this is in
part due to the fact that we are not finalizing the proposed IRR
provisions, which would have reduced the number of RINs generated for
import-based renewable fuel by half. The total volumes of renewable
fuel we expect will be supplied to meet the volume requirements of this
final rule are very similar to those we projected would be supplied to
meet the proposed volume requirements. Obligated parties will have at
least 12 months from the time of promulgation of this final rule before
they are required to submit associated compliance reports for 2026.
There will additionally be at least 24 months between the finalization
of this rule and the compliance deadline for the 2027 standards.
Obligated parties will also continue to have the ability to use
existing compliance flexibilities to comply with the 2026 and 2027 RFS
standards, such as the use of carryover RINs and carrying forward a
deficit from one compliance year into the next.\50\
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\50\ CAA section 211(o)(5); 40 CFR 80.1427(a)(6)(i) and (b).
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We also note that separate components of the 2026 and 2027 advanced
biofuel, BBD, and total renewable fuel applicable volumes--the SRE
reallocation volumes--were proposed with the intent that the standards
be met through the use of carryover RINs as a result of the recent SRE
decisions. In this final rule, we again intend for the SRE reallocation
volumes to be met using carryover RINs that are already available in
the market, and as such do not anticipate additional burden on
obligated parties to obtain newly generated RINs for compliance with
this portion of the applicable volumes.
F. Impact on Other Waiver Authorities
While we are establishing applicable volume requirements in this
action for future years that are achievable and appropriate based on
our consideration of the statutory factors, we retain our legal
authority to waive volumes in the future under the relevant waiver
authorities should circumstances so warrant.\51\ For example, the
general waiver authority under CAA section 211(o)(7)(A) provides that
the EPA may waive the volume requirements in ``paragraph (2),'' which
provides both the statutory applicable volume tables and the EPA's set
authority (the authority to set applicable volumes for years not
specified in the table). Therefore, similar to our exercise of the
waiver authorities to modify the statutory volumes in past annual
standard-setting rulemakings, the EPA has the authority to modify the
applicable volumes for 2023 and beyond in future actions through the
use of our waiver authorities. The Agency's general preference is to
establish requirements in a manner that reduces the need for such
waivers as much as possible. This policy, however, should not be read
as conceding the EPA's authority to implement such waivers if warranted
under the circumstances despite best efforts to project future
conditions in a reasonable and well-informed manner.
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\51\ See J.E.M. Ag Supply, Inc. v. Pioneer Hi-Bred Intern.,
Inc., 534 U.S. 124, 143-44 (2001) (holding that when two statutes
are capable of coexistence and there is not clearly expressed
legislative intent to the contrary, each should be regarded as
effective).
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We note that, as described above, CAA section 211(o)(2)(B)(iv)
requires that the EPA set the cellulosic biofuel volume requirements
for 2023 and beyond based on the assumption that we will not need to
waive those volume requirements under the cellulosic waiver authority.
Consistent with our approach in the Set 1 Rule, because we are
establishing the applicable volume requirements for 2026 and 2027 under
the set authority in this action, we do not believe we could also waive
those requirements using the cellulosic waiver authority in this same
action in a manner that would be consistent with CAA section
211(o)(2)(B)(iv), since that waiver authority is only triggered when
the projected production of cellulosic biofuel is less than the
``applicable volume established under [211(o)(2)(B)].'' In other words,
it does not appear that we could use both the set authority and the
cellulosic waiver authority to establish volumes at the same time in
this action.\52\
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\52\ We address comments that suggested we interpret this
provision differently in RTC Section 2.1.
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Establishing the volume requirements for 2026 and 2027 using our
set authority apart from the cellulosic waiver authority has important
implications for the availability of CWCs in these years. When we
reduce cellulosic volumes under the cellulosic waiver authority, we are
also required to make CWCs available under CAA section
211(o)(7)(D)(ii). In this rule we are establishing the 2026 and 2027
cellulosic biofuel volume requirements without utilizing the cellulosic
waiver authority. We interpret CAA section 211(o)(7)(D)(ii) such that
CWCs are only made available in years in which we use the cellulosic
waiver authority to reduce the cellulosic biofuel volume. Because of
this, CWCs would not be available as a compliance mechanism for
obligated parties in these years absent a future action to exercise the
cellulosic waiver authority. Despite the absence of CWCs, we expect
that obligated parties will be able to satisfy their cellulosic biofuel
obligations for these years because we are establishing the 2026 and
2027 cellulosic biofuel volume requirements based on the quantity of
cellulosic biofuel we project will be used as transportation fuel in
the U.S. each year.
G. Severability
In the event of judicial review, the EPA intends for the volume
requirements and percentage standards for each single year covered by
this rule (i.e., 2026 and 2027) to be severable from the volume
requirements and
[[Page 16398]]
percentage standards for the other year. Each year's volume
requirements and percentage standards are supported by analyses for
that year.
We also intend for the SRE reallocation volumes for total renewable
fuel, advanced biofuel, and BBD for 2026 and 2027 to be severable from
the 2026 and 2027 volume requirements. Our justification for each
volume is independent, such that invalidation of the SRE reallocation
volumes would not impact our estimates of renewable fuel that are
associated with new renewable fuel production in the market in 2026 and
2027. Our justification for the SRE reallocation volume is independent
of that establishing the 2026 and 2027 volume requirements, despite the
fact that the two terms are additive. We do not believe that it would
be appropriate to further delay implementation of the 2026 and 2027
volume requirements if a court were to find defects in the SRE
reallocation volumes.\53\
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\53\ We have also calculated what the total renewable fuel,
advanced biofuel, and BBD percentage standards for 2026 and 2027
would be without the SRE reallocation volumes. See ``Calculation of
2026 and 2027 RFS Percentage Standards Without the SRE Reallocation
Volumes,'' available in the docket for this action.
---------------------------------------------------------------------------
We intend for the revised 2025 cellulosic biofuel volume
requirement and percentage standard in section VI of this preamble to
be severable from the volume requirements and percentage standards for
the other years. The 2025 cellulosic biofuel volume requirement and
percentage standard is supported by the analysis and legal authority
for that year independent of the analysis and legal authority for the
2026 and 2027 standards.
We also intend for the removal of renewable electricity from the
RFS program discussed in section VII of this preamble and the
regulatory amendments discussed in section VIII of this preamble to be
severable from the volume requirements and percentage standards. These
regulatory amendments are intended to improve the RFS program in
general and are not part of our analysis for the volume requirements
and percentage standards for any specific year. Additionally, because
we have not registered any parties to generate RINs for renewable
electricity, no such RINs are able to be generated and we have not
relied on any such RINs in setting the standards. Further, each
regulatory amendment in sections VII and VIII of this preamble is
severable from the other regulatory amendments because they all
function independently of one another.
If any of the portions of the rule identified in the preceding
paragraph (i.e., volume requirements and percentage standards for a
single year, the individual regulatory amendments) were invalidated by
a reviewing court, we intend the remainder of this action to remain
effective as described in the prior paragraphs. To further illustrate,
if a reviewing court were to invalidate the volume requirements and
percentage standards, we intend the other regulatory amendments to
remain effective. Or, as another example, if a reviewing court
invalidates the removal of renewable electricity as a qualifying
renewable fuel under the RFS program, we intend the volume requirements
and percentage standards as well as other regulatory amendments to
remain effective.
H. Judicial Review
Under section 307(b)(1) of the CAA, petitions for judicial review
of this action must be filed in the United States Court of Appeals for
the District of Columbia Circuit by June 1, 2026. Filing a petition for
reconsideration by the Administrator of this final action under CAA
section 307(d)(7)(B) does not affect the finality of the action for
purposes of judicial review, nor does it extend the time within which a
petition for judicial review must be filed, and shall not postpone the
effectiveness of the action.
III. Volume Requirements for 2026 and 2027
This section of this preamble presents information related to how
the EPA analyzed renewable fuel volumes, assessed the impacts of the
potential volumes on the statutory factors, and other relevant
information. Section III.A of this preamble describes how we identified
volumes of component categories to facilitate our assessment of the
statutory factors. Sections III.B and C of this preamble discuss the
baselines we used for our analyses and the differences between these
baselines and the analyzed volumes. A summary of our analyses of
certain statutory factors on the analyzed volumes is in section III.D
of this preamble, with more detail on our analyses and the results in
the RIA. Sections III.E through H of this preamble discuss the volumes
we are finalizing for each component category of renewable fuel, our
consideration of carryover RINs, our consideration of alternative
volumes, and finally a summary of the volumes we are finalizing for
2026 and 2027 in this final rule.
A. Analyzed Volumes
As required under CAA section 211(o)(2)(B)(ii), we reviewed the
implementation of the RFS program to date and analyzed a specified set
of factors. Many of the statutory factors, particularly those related
to economic and environmental impacts, are difficult to analyze in the
abstract; it is challenging to assess impacts without understanding the
scale of the volume changes that are the driving force behind those
impacts. In light of this, in the Set 1 Rule we first projected
candidate volumes based on supply-side statutory factors and then
analyzed the impacts on the other statutory factors of those candidate
volumes before setting final volumes,\54\ an approach that was upheld
by the D.C. Circuit in CBD.\55\
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\54\ 88 FR 44480-508 (July 12, 2023).
\55\ CBD, 141 F.4th at 170.
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We similarly framed our analysis of the statutory factors in this
rule: we opted to first identify renewable fuel volumes for each
category of renewable fuel (hereinafter the ``Analyzed Volumes'') so
that a more concrete and meaningful analysis of the impacts of other
statutory factors may be undertaken. This section (III.A) of this
preamble describes how we developed the Analyzed Volumes as well as how
and why they changed from the Set 2 proposal. Our analysis of the
impacts of the Analyzed Volumes on a selection of the statutory factors
is summarized in section III.D of this preamble, and the volume
requirements for 2026 and 2027 that we are establishing in this action
based on our analysis of all the statutory factors and a review of the
implementation of the RFS program to date are described in section
III.E of this preamble and summarized in section III.H of this
preamble. Further details of all analyses performed for this action are
provided in the RIA.
The Analyzed Volumes were determined based primarily on two
statutory criteria: the expected annual rate of future commercial
production of renewable fuels and sufficiency of infrastructure to
deliver and use renewable fuels.\56\ This is similar to the EPA's
approach to identifying ``candidate volumes'' in the Set 1 Rule, which
were also based on supply-side factors.\57\ However, the development of
the Analyzed Volumes is more closely tied to the statutory goals of the
RFS program to, among other things, increase the domestic production
and use of renewable fuel to increase the energy independence and
security of the U.S. To best achieve these goals and consistent with
the statutory requirements, the Analyzed Volumes are designed to
account for the maximum potential production and use
[[Page 16399]]
of renewable fuels in the U.S. while at the same time recognizing
infrastructure constraints that could limit the production and use of
these fuels.
---------------------------------------------------------------------------
\56\ CAA section 211(o)(2)(B)(ii)(III) and (IV).
\57\ 88 FR 44480-81 (July 12, 2023).
---------------------------------------------------------------------------
The Analyzed Volumes in this final rule differ from the volume
scenarios and the proposed volumes in several ways, reflecting
consideration of public comments received and certain adjustments that
were contemplated at proposal. The Analyzed Volumes reflect additional
analyses based on data received since proposal. The Analyzed Volumes
also reflect modifications to our methodologies for projecting the
potential volumes of renewable fuel production and use made in response
to the public comments, including comments asserting that certain
intervening developments discussed below warranted adjustments.\58\
Finally, the Analyzed Volumes have been adjusted to reflect the EPA's
decision not to finalize the proposed IRR provisions in this action.
---------------------------------------------------------------------------
\58\ For example, the analyses that support this final rule have
been revised to reflect tax credit changes in OBBB.
---------------------------------------------------------------------------
For cellulosic biofuel and conventional renewable fuel, the
Analyzed Volumes are equal to the projected volumes of these fuels we
project will be used as RFS-qualifying transportation fuel in 2026 and
2027. Our projections of the use of these fuels assume continued
incentives for the production and use of these fuels provided by the
RFS program and by other State and Federal programs remain in place for
the periods of time currently described in their respective statutes
and regulations.
For non-cellulosic advanced biofuel (including BBD and other
advanced biofuel), the projected supply of these fuels in future years
is highly dependent on the incentives for these fuels provided by the
RFS program, other State and Federal incentives in the U.S., and
actions by foreign countries. Unlike cellulosic biofuel and
conventional renewable fuel, we do not expect that the supply of non-
cellulosic advanced biofuel will be limited by the ability for the
market to use these fuels as RFS-qualifying transportation fuel.
Instead, we project that the available supply of non-cellulosic
advanced biofuel will depend on a number of interrelated factors,
including the supply of feedstocks to produce these fuels, demand for
these feedstocks in non-biofuel markets, and the available incentives
for the production and use of these fuels in the U.S. and other
countries.
The non-cellulosic advanced biofuel volumes we chose to analyze are
based on the projected domestic production capacity of biodiesel and
renewable diesel in 2026 and 2027, as well as the projected supplies of
other advanced biofuels. In determining the Analyzed Volumes for non-
cellulosic advanced biofuel, we also considered the availability of
qualifying feedstocks to produce these fuels but ultimately determined
that feedstock availability was unlikely to limit the production of
these fuels to a level below the domestic production capacity.
Developing volumes of non-cellulosic advanced biofuel for analysis
based on the domestic production capacity for these fuels is consistent
with the statute's goals of increasing energy independence and security
and the Administration's goals of achieving energy dominance.
We recognize that imported renewable fuels are eligible to generate
RINs under the RFS program, provided these fuels meet all relevant
statutory and regulatory requirements. Imported renewable fuels are
expected to continue to contribute to the supply of renewable fuel to
the U.S. in 2026 and 2027. However, the volume of non-cellulosic
advanced biofuels imported into the U.S. decreased significantly in
2025 and we believe based on the balance of available evidence that
this trend will continue into 2026 and 2027 due to new trends in trade
dynamics. Data from the EPA Moderated Transaction System (EMTS)
indicates that biodiesel and renewable diesel imports decreased from
approximately 830 million gallons in 2024 to approximately 140 million
gallons in 2025. This drop in imported renewable fuel was a response to
changing economic conditions, including the transition to the Federal
Internal Revenue Code Section 45Z Clean Fuel Production tax credit
(hereinafter the ``45Z credit''), which does not provide credit for
imported biofuels. The 45Z credit was amended by the One Big Beautiful
Bill Act of 2025 (OBBB).\59\ Among other changes, OBBB required
biofuels to be produced from North American feedstocks to qualify for
the tax credit. Because the 45Z credit is effective for fuel produced
after December 31, 2024, EPA had insufficient data on the impacts of
the new structure of the credit and the market's response to consider
these impacts in the Set 2 proposal. However, the significant drop in
the total volume of imported non-cellulosic advanced biofuels observed
in 2025 further supports our decision to base the non-cellulosic
advanced biofuel Analyzed Volumes on our projection of domestic
production capacity for these fuels.
---------------------------------------------------------------------------
\59\ Public Law 119-21 (2025).
---------------------------------------------------------------------------
Given the nested nature of the statutory renewable fuel categories,
we largely framed our assessment of volumes in terms of the component
categories rather than in terms of the statutory categories (cellulosic
biofuel, BBD, advanced biofuel, and total renewable fuel). The
statutory categories are those addressed in CAA section
211(o)(2)(B)(i)-(ii). The component categories are the categories of
renewable fuels that make up the statutory categories, but which are
not nested within one another. They possess distinct economic,
environmental, technological, and other characteristics relevant to the
factors we must analyze under the statute, making our focus on them
rather than the nested categories in the statute technically sound.
Finally, an analysis of the component categories is equivalent to
analyzing the statutory categories, since doing so would effectively
require us to evaluate the difference between various statutory
categories (e.g., assessing ``the difference between volumes of
advanced biofuel and total renewable fuel'' instead of assessing ``the
volume of conventional renewable fuel''), adding unnecessary complexity
to our analysis. In any event, were we to frame our analysis in terms
of the statutory categories, we believe that our substantive approach
and conclusions would remain materially the same.
In sections III.A.1 through 4 of this preamble, we provide greater
detail on the methodology and data used for identifying the Analyzed
Volumes of cellulosic biofuel, non-cellulosic advanced biofuel, and
conventional renewable fuel.
1. Cellulosic Biofuel
CAA section 211(o)(1)(E) defines cellulosic biofuel as renewable
fuel derived from any cellulose, hemi-cellulose, or lignin that has
lifecycle greenhouse gas (GHG) emissions that are at least 60 percent
less than the baseline lifecycle GHG emissions. Since the inception of
the RFS program, cellulosic biofuel production has steadily increased,
reaching record levels in 2025. This growth has primarily been driven
by renewable CNG/LNG, although small volumes of liquid cellulosic
biofuels, particularly ethanol produced from CKF, have also played a
contributing role.
Figure III.A.1-1: Cellulosic RINs Generated
[[Page 16400]]
[GRAPHIC] [TIFF OMITTED] TR01AP26.029
Sections III.A.1.a-d of this preamble describe our methodology for
determining the appropriate volumes of renewable CNG/LNG and CKF
ethanol and, in turn, the total cellulosic biofuel volume used in our
statutory factor analysis. Additional details on our volume projections
for cellulosic biofuel are provided in RIA Chapter 7.1.
a. Renewable CNG/LNG
To qualify as a RIN-generating fuel under the RFS program biogas
from qualifying sources must first be collected and upgraded for
vehicle use. The upgrading process varies depending on the final
application but typically involves removing undesirable components and
contaminants from the raw biogas. Biogas that has been upgraded and
distributed through a closed distribution system, either as a
biointermediate or for the production of renewable fuel, is defined as
``treated biogas,'' whereas biogas that has been upgraded to be
suitable for injection into the commercial natural gas pipeline system
and could be used to produce renewable fuel is defined as ``renewable
natural gas'' (RNG).\60\ Although they are defined differently in the
regulations, we use the term ``RNG'' to collectively refer to both
treated biogas and RNG in this document. Likewise, we use ``renewable
CNG/LNG'' to refer to both treated biogas and RNG when used as a
transportation fuel in CNG/LNG vehicles, and we apply this term in
contexts where such use is eligible for and results in RIN generation
and separation under the RFS program.
---------------------------------------------------------------------------
\60\ 40 CFR 80.2.
---------------------------------------------------------------------------
To determine appropriate volumes of renewable CNG/LNG, we analyzed
two factors: the amount of RNG that could be produced and the amount of
renewable CNG/LNG that could be consumed as RFS-qualifying
transportation fuel. As discussed further below and in RIA Chapter 7.1,
we updated the analysis from the Set 2 proposal, taking into
consideration data and information provided by commenters, and we
continue to find that consumption, not production, is the primary
constraint on future volumes of renewable CNG/LNG.
For our assessment of consumption of renewable CNG/LNG, we first
estimate total CNG/LNG use in transportation, regardless of whether the
fuel is fossil-based or renewable. Our methodology is the same as in
the Set 2 proposal: we combine estimates of the number of vehicles
capable of using CNG/LNG with data on vehicle miles traveled, fuel
economy, and fuel consumption. Since the Set 2 proposal, we updated
these inputs using more recent data. Commenters generally agreed with
our methodologies for estimating consumption, though some urged more
aggressive assumptions for fuel use and anticipated market growth. We
address these points in detail in RTC Section 3; based on the available
data, however, we believe our estimates strike an appropriate balance
that reflects potential growth in total CNG/LNG consumption while
remaining grounded in observed market trends. Having established this
total-use baseline, we then assess the practical limits on the share of
CNG/LNG that can be supplied by RNG. Fully replacing total CNG/LNG
usage with RNG is unlikely due to facility-specific infrastructure
limitations, costs, and other challenges. Therefore, to account for
this, we adjusted our total CNG/LNG estimate to reflect these
constraints and calculated the share that can realistically be met with
RNG.
To calculate this usage and verify that it reflects real-world
conditions, we examined data from California's Low Carbon Fuel Standard
(LCFS) program. This data shows that approximately 97 percent of
transportation CNG/LNG demand in California has been supplied by RNG
over the past several years, which is the same figure cited in the Set
2 proposal and remains valid based on updated data.\61\ Accordingly, we
applied a 97 percent factor to total CNG/LNG consumption to estimate
potential renewable-based volume. The results of our projected total
CNG/LNG transportation use and the applied 97 percent efficiency factor
are shown in Table III.A.1.a-1 and further discussed in RIA Chapter
7.1.4.1.
---------------------------------------------------------------------------
\61\ CARB, ``LCFS Quarterly Data Summary Spreadsheet,'' August
11, 2025. https://ww2.arb.ca.gov/resources/documents/low-carbon-fuel-standard-reporting-tool-quarterly-summaries.
---------------------------------------------------------------------------
To validate this expected consumption-limitation on renewable CNG/
LNG volumes, we also examined potential production capacity under
unconstrained market conditions (i.e., assuming no consumption limits)
to determine whether production, rather
[[Page 16401]]
than consumption, may be the limiting constraint in 2026 and 2027. To
do this, we used the same industry-wide production projection method
employed in RFS standard-setting since 2018: applying an industry-wide
year-over-year growth rate to the current RNG production rate (see RIA
Chapter 7.1.2).
Specifically, we determined an appropriate year-over-year
production growth rate by analyzing cellulosic RIN generation for RNG
over the two most recent full calendar years. While we have
historically used a rolling 24-month window, including in the Set 2
proposal, for this analysis we aligned to calendar years to reduce
seasonal distortion as RIN generation typically slows early in the year
and surges at year-end. Early 2025 departed from this pattern, likely
due to new biogas regulatory reform regulations, so using full calendar
year data captures both the complete seasonal cycle and any changes to
the seasonal pattern of RIN generation for RNG attributable to the
biogas regulatory reform changes. From this data, we derived a 24
percent year-over-year growth rate. We applied this rate to the 2025
cellulosic RIN generation baseline for RNG to project 2026 RIN
generation and then used the 2026 projection to estimate 2027 RIN
generation. Results from our growth rate-based production estimate are
shown in Table III.A.1.a-1 and discussed further in RIA Chapter
7.1.4.2.
[GRAPHIC] [TIFF OMITTED] TR01AP26.031
Performing this analysis and comparing RNG production with
consumption of renewable CNG/LNG confirms that for 2026 and 2027,
production is expected to exceed consumption as transportation fuel.
This shows that the volume of these fuels will most likely be
constrained by the market's capacity to use RNG as an RFS-qualifying
transportation fuel. Importantly, under the RFS regulations for biogas-
derived renewable fuel as amended in the Set 1 Rule,\62\ while RINs for
renewable CNG/LNG are generally generated when the RNG is injected into
a commercial pipeline,\63\ they are separated and available for
compliance only once the gas is used as transportation fuel.\64\
Consequently, even if production is higher than consumption, the number
of separated RINs from renewable CNG/LNG remains constrained by total
CNG/LNG use in transportation.
---------------------------------------------------------------------------
\62\ Prior to these regulatory changes, which went into effect
on January 1, 2025, RINs for CNG/LNG derived from biogas could not
be generated until parties demonstrated that the CNG/LNG had been
produced from qualifying renewable biomass and used as
transportation fuel.
\63\ 40 CFR 80.125(b).
\64\ 40 CFR 80.125(d).
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In previous RFS rulemakings, we recognized that renewable CNG/LNG
consumption could eventually become the limiting factor in determining
volumes but did not know when it would do so. In the Set 1 Rule, we set
the 2023-2025 cellulosic biofuel volume requirements based on projected
production and the historical growth of cellulosic RIN generation,
assuming production capacity, not end-use consumption, would be the
primary constraint.\65\ Evidence now shows a potential shift toward a
consumption-limited baseline for those years. Cellulosic biofuel
deficits from 2023 and 2024 carried into the following year were
significantly larger than the deficits in previous years.\66\ EPA
partially waived the 2024 cellulosic biofuel volume requirement due to
a shortfall in the projected volume of cellulosic biofuel available
relative to the 2024 cellulosic biofuel standard.\67\ Similarly, as
described in section VI of this preamble, we are partially waiving the
2025 cellulosic biofuel volume requirement due to a shortfall in 2025
cellulosic RINs necessary to meet the original 2025 requirement
established in the Set 1 Rule.
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\65\ Set 1 RIA Chapter 6.1.3.
\66\ Cellulosic biofuel deficits for 2023 and 2024 were
approximately 55-60 million RINs each year. Prior the 2023, the
largest cellulosic biofuel deficit in a single year was
approximately 20 million RINs in 2017. See ``RFS Compliance Data as
of February 20, 2026,'' available in the docket for this action.
\67\ 90 FR 29751 (July 7, 2025).
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In addition, we are also now seeing a rapid increase in cellulosic
RINs retired for non-transportation purposes, which provides further
evidence that consumption, rather than production capacity, is
increasingly the binding constraint. Specifically, retirements of
cellulosic RINs for non-transportation use increased from 0.4 million
RINs in 2024 to 74.5 million RINs in 2025,\68\ further reducing the
number of cellulosic RINs available for compliance.\69\ Thus, while we
still project continued growth in cellulosic biofuel production in 2026
and 2027, growth in cellulosic RIN availability is likely to remain
significantly constrained for the foreseeable future by the ability of
fuel consumers to use renewable CNG/LNG.
---------------------------------------------------------------------------
\68\ See ``RIN retirement data from January 2026'' RIN data file
available at: https://www.epa.gov/fuels-registration-reporting-and-compliance-help/spreadsheet-rin-retirement-data-renewable-fuel.
\69\ For a detailed discussion, see RIA Chapter 7.1.3.
---------------------------------------------------------------------------
Based on our analysis of renewable CNG/LNG consumption and RNG
production, we reach the same conclusion as in the Set 2 proposal: in
2026 and 2027, cellulosic volumes from renewable CNG/LNG are
constrained by total CNG/LNG transportation usage. Commenters were
divided on this point; some agreed that consumption could limit volumes
in the near term, while others argued that we should base our Analyzed
Volumes solely on projected production without consideration of the end
use of the CNG/LNG. Because cellulosic RINs can only be separated and
made available to demonstrate compliance if the CNG/LNG is used as
transportation fuel, EPA decided it was appropriate to consider
constraints related to the use of CNG/LNG as transportation fuel in
determining the Analyzed Volumes. Accordingly, we treat the volumes in
Table III.A.1.a-2 as the renewable CNG/LNG contribution to the total
cellulosic biofuel volume used in our statutory factor analysis.
[[Page 16402]]
[GRAPHIC] [TIFF OMITTED] TR01AP26.032
b. Ethanol From Corn Kernel Fiber
Several technologies are currently being developed to produce
liquid fuels from cellulosic biomass. However, most of these
technologies are unlikely to yield significant volumes of cellulosic
biofuel by 2027. One notable exception is the production of ethanol
from CKF, for which several companies have developed production
processes. Many of these processes involve co-processing of both the
starch and cellulosic components of the corn kernel. However, to be
eligible for cellulosic RIN generation, facilities must accurately
determine the amount of ethanol produced specifically from the
cellulosic portion of the corn kernel using approved methodologies.
This requires the ability to reliably and precisely calculate the
ethanol derived from the cellulosic component, distinct from the starch
portion of the corn kernel. In September 2022, we issued updated
guidance on analytical methods that could be used to quantify the
amount of ethanol produced when co-processing CKF and corn starch.\70\
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\70\ EPA, ``Guidance on Qualifying an Analytical Method for
Determining the Cellulosic Converted Fraction of Corn Kernel Fiber
Co-Processed with Starch,'' EPA-420-B-22-041, September 2022.
---------------------------------------------------------------------------
We also had substantive discussions with technology providers
intending to use analytical methods consistent with this guidance, as
well as with owners of facilities registered as cellulosic biofuel
producers using these methods. Based on information from these
technology providers, we believe that cellulosic ethanol production
from CKF could be feasible at all existing corn ethanol facilities,
with minimal additional processing units or modifications. To generate
cellulosic RINs for ethanol produced from CKF, a facility would need to
demonstrate the converted fraction consistent with appropriate test
methods. For the purposes of this analysis, we assume that 90 percent
of facilities will produce cellulosic ethanol over this period due to
potential facility-specific challenges that may prevent 100 percent
adoption.
Based on data submitted to the EPA by renewable fuel producers
generating cellulosic RINs for CKF ethanol, the current industry-wide
average conversion among registered facilities is approximately 1
percent. Accordingly, for this analysis we use a 1 percent conversion
rate. We recognize that some parties have claimed they can demonstrate
up to 1.5 percent conversion using analytical methods consistent with
EPA guidance, but we do not yet have sufficient data to support
adopting that higher rate.
Commenters generally supported our inclusion of robust volumes of
CKF ethanol. Some, however, as discussed earlier, urged more aggressive
assumptions for facility participation and conversion efficiency. We
address these comments in detail in RTC Section 3. Based on the
available data, we do not find sufficient support to increase these
rates at this time.
The projected production of cellulosic ethanol from CKF, as shown
in Table III.A.1.b-1, is based on projections of total corn ethanol
production, with a 90 percent facility participation rate and a 1
percent conversion efficiency applied.\71\
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\71\ A detailed discussion of the methodology used to project
cellulosic ethanol production from CKF can be found in RIA Chapter
7.1.5.
[GRAPHIC] [TIFF OMITTED] TR01AP26.033
c. Other Cellulosic Biofuels
We expect U.S. commercial-scale production of cellulosic biofuels,
other than renewable CNG/LNG and CKF ethanol, to be very limited in
2026 and 2027. Several technologies in development may be capable of
producing small volumes by 2027. These technologies primarily target
cellulosic hydrocarbons from feedstocks such as separated municipal
solid waste (MSW), precommercial thinnings, and tree residues, which
can be blended into gasoline, diesel, and jet fuel. However, because no
producer has achieved sustained U.S. production to date, projected
volumes for 2026 and 2027 remain highly uncertain and are likely to be
small. Accordingly, we do not project production of cellulosic biofuels
beyond renewable CNG/LNG and CKF ethanol during 2026 and 2027.
d. Summary of Cellulosic Biofuel Volumes
In determining the Analyzed Volumes of cellulosic biofuel for 2026
and 2027, we started by considering the statutory volume targets for
2010-2022. The statutory volumes for cellulosic biofuel increased
rapidly, from 100 million gallons in 2010 to 16 billion gallons in 2022
with the largest increases in the later years. These increases are even
more notable in comparison to the implied statutory volumes for the
other renewable fuel volumes. Statutory BBD volumes did not increase
after 2012, implied conventional renewable fuel volumes did not
increase after 2015, and non-cellulosic advanced biofuel volumes
reached a maximum of 5 billion in 2022. Thus, by 2022, the statute was
clearly oriented toward expanding cellulosic biofuel volumes.
Given the statute's emphasis on growing cellulosic biofuel volumes,
our statutory analysis evaluates the highest feasible volume of
cellulosic biofuel. However, as discussed in section II.C of this
preamble, CAA section 211(o)(2)(B)(iv) requires the EPA to set the
cellulosic biofuel volume requirement such that we do not anticipate a
need to waive the volumes under CAA section 211(o)(7)(D). Accordingly,
the Analyzed Volumes of cellulosic biofuel used in our statutory
analysis for 2026 and 2027 are equal to the projected amount of
cellulosic biofuel used as RFS-qualifying transportation fuel in those
years,
[[Page 16403]]
balancing the statute's goal of increasing cellulosic biofuel while
avoiding the need to waive future volumes.
Table III.A.1.d-1 presents the Analyzed Volumes of cellulosic
biofuels for 2026 and 2027. Because production characteristics and
market conditions differ across cellulosic fuels, we present CKF
ethanol and renewable CNG/LNG separately.
[GRAPHIC] [TIFF OMITTED] TR01AP26.034
2. Non-Cellulosic Advanced Biofuel
CAA section 211(o)(1)(D) defines BBD as renewable fuel that is
biodiesel as defined by 42 U.S.C. 12330(f) and that has GHG emissions
reductions of at least 50 percent from the baseline. It also excludes
biodiesel that is co-processed with petroleum feedstocks. The BBD
standard is nested within the advanced biofuel standard. Historically,
the BBD supply under the RFS program has exceeded the BBD standard,
with the additional supply used by obligated parties to meet their
advanced biofuel volume requirements. Thus, the advanced biofuel
standard has incentivized the use of BBD beyond just the BBD standard.
a. Biodiesel and Renewable Diesel
Since 2010, when the BBD volume requirement was added to the RFS
program, production of BBD has generally increased annually. The volume
of BBD supplied in any given year is influenced by a number of factors,
including: production capacity; feedstock availability and cost;
available incentives including the RFS program; the availability of
imported BBD; the demand for BBD (and feedstocks used to produce BBD)
in foreign markets; and several other economic factors.
Most renewable fuel that qualifies as BBD is either biodiesel or
renewable diesel. Both these fuels are replacements for petroleum
diesel and are produced from the same lipid-based feedstocks, a diverse
category that includes animal fats, UCO, and vegetable oil feedstocks.
Biodiesel and renewable diesel differ in their production processes and
chemical composition. Biodiesel is an oxygenated fuel that is generally
produced using a transesterification process. Renewable diesel, on the
other hand, is a hydrocarbon fuel that closely resembles petroleum
diesel and that is generally produced by hydrotreating renewable
feedstocks.
i. Historic Production of Biodiesel and Renewable Diesel
From 2012 through 2022 the largest volume of advanced biofuel
supplied in the RFS program was biodiesel. Domestic biodiesel
production increased from approximately 1.3 billion gallons in 2014 to
approximately 1.8 billion gallons in 2018. From 2018 to 2024, domestic
biodiesel production decreased slightly to approximately 1.7 billion
gallons. In 2025, domestic biodiesel production decreased to an
estimated 1.1 billion gallons.\72\
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\72\ Further details on these volume projections can be found in
RIA Chapter 7.2.
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In the early years of the RFS program renewable diesel was produced
and imported in smaller quantities than biodiesel, as shown in Figure
III.A.2.a.i-1. In recent years, however, domestic production of
renewable diesel has increased significantly. Renewable diesel
production facilities generally have higher capital costs relative to
biodiesel, which likely accounts for the historically higher volumes of
biodiesel production relative to renewable diesel production prior to
2023. The higher capital cost of renewable diesel production can
largely be offset through the benefits of economies of scale, since
renewable diesel production facilities tend to be much larger than
biodiesel production facilities.\73\ For example, according to data
from the U.S. Energy Information Administration (EIA), in 2025, there
were 19 active renewable diesel facilities that produced an average of
248 million gallons of renewable diesel per facility,\74\ compared to
48 active biodiesel facilities that produced an average of 41 million
gallons of biodiesel per facility.\75\
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\73\ See RIA Chapter 10 for more detail on our assessment of the
cost to produce biodiesel and renewable diesel.
\74\ EIA, ``U.S. Renewable Diesel Fuel and Other Biofuels Plant
Production Capacity,'' September 26, 2025. https://www.eia.gov/biofuels/renewable/capacity.
\75\ EIA, ``U.S. Biodiesel Plant Production Capacity,''
September 26, 2025. https://www.eia.gov/biofuels/biodiesel/capacity.
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Because renewable diesel more closely resembles petroleum diesel
than biodiesel, renewable diesel can be blended at much higher
concentrations with diesel than biodiesel. This allows renewable diesel
to more easily be blended into diesel at higher rates and enables
renewable diesel producers to sell greater volumes of renewable diesel
in California, benefiting from the LCFS credits in California in
addition to RFS incentives and the 45Z credit.\76\ The greater ability
for renewable diesel to generate credits under California's LCFS
program provides a significant advantage over biodiesel. Biodiesel
blends in California containing 6-20 percent biodiesel require the use
of an additive to comply with California's Alternative Diesel Fuels
Regulations, making the use of higher-level biodiesel blends more
challenging in California.\77\ The Washington, Oregon, and New Mexico
programs modeled from the California LCFS have generally mirrored this
incentive structure. If additional States were to adopt clean fuels
programs using a similar structure, these programs could provide an
additional advantage to renewable diesel production relative to
biodiesel production in the U.S.
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\76\ For example, when LCFS credits are worth $100/metric ton,
blending renewable diesel into California generates LCFS credits
worth approximately $0.25 to $0.90 per gallon (assuming carbon
intensities of 70 and 20 gCO2e/MJ respectively).
Renewable fuel producers that sell qualifying renewable fuel in
California can generate both RINs under the RFS program and LCFS
credits.
\77\ CARB, ``Frequently Asked Questions on the Alternative
Diesel Fuels Regulation,'' November 2017. In 2021, nearly all
renewable diesel consumed in the U.S. was consumed in California.
Together renewable diesel and biodiesel represented approximately
65-70 percent of all diesel fuel consumed in California in the
second half of 2024.
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Figure III.A.2.a.i-1: Domestic Production of Biodiesel and Renewable
Diesel
[[Page 16404]]
[GRAPHIC] [TIFF OMITTED] TR01AP26.035
Imports and exports of biodiesel and renewable diesel also impact
the domestic supply of these fuels. The U.S. has been a net importer of
biodiesel since 2013. Biodiesel imports reached a peak in 2016, with
the majority of the imported biodiesel coming from Argentina.\78\ In
August 2017, the U.S. announced tariffs on biodiesel imported from
Argentina and Indonesia.\79\ These tariffs were subsequently confirmed
in April 2018 and remain in place after being reaffirmed in 2023.\80\
Biodiesel imports started dropping in 2017 but increased precipitously
in 2023, reaching approximately 500 million gallons.\81\ Biodiesel
imports saw large declines in 2024 and 2025 to 398 million gallons and
34 million gallons, respectively.\82\
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\78\ In 2016 and 2017, 67 percent of all biodiesel imports were
from Argentina. EIA, ``U.S. Imports by Country of Origin--
Biodiesel,'' Petroleum & Other Liquids, April 30, 2025. https://www.eia.gov/dnav/pet/pet_move_impcus_a2_nus_EPOORDB_im0_mbbl_a.htm.
\79\ 82 FR 40748 (August 28, 2017).
\80\ 83 FR 18278 (April 26, 2018).
\81\ EIA, ``U.S. Imports of Biodiesel,'' Petroleum & Other
Liquids, April 30, 2025. https://www.eia.gov/dnav/pet/hist/LeafHandler.ashx?n=pet&s=m_epoordb_im0_nus-z00_mbbl&f=a.
\82\ See RIA Chapter 7.2 for further discussion of EPA estimates
of imports and exports of BBD.
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Imports and exports of renewable diesel have also varied over time.
Nearly all the renewable diesel imported into the U.S. through 2025 was
imported from Singapore.\83\ In more recent years, the U.S. has also
exported increasing volumes of renewable diesel. In 2022-2025,
renewable diesel exports exceeded renewable diesel imports based on
data collected through EMTS (see Table III.A.2.b-1).
---------------------------------------------------------------------------
\83\ EIA, ``U.S. Imports by Country of Origin--Renewable Diesel
Fuel,'' Petroleum & Other Liquids, April 30, 2025. https://www.eia.gov/dnav/pet/pet_move_impcus_a2_nus_EPOORDO_im0_mbbl_a.htm.
---------------------------------------------------------------------------
The simultaneous import and export of significant volumes of
biodiesel and renewable diesel is likely the result of a number of
factors, including the design of the previous biodiesel tax credits
(which were available with respect to biodiesel and renewable diesel
that was either produced or used in the U.S. and thus eligible for
exported volumes as well), the varying structures of the available
incentives (with the level of incentives varying by country and often
depending on the feedstocks used), and logistical considerations
(biodiesel and renewable diesel may be imported and exported from
different parts of the country). Starting in 2026, the 45Z credit,
which consolidated and replaced the previous $1 per gallon credits for
biodiesel and renewable diesel, is only available for fuel produced in
the U.S. from feedstocks sourced from North America. As the 45Z credit,
unlike the tax credits it replaced, does not provide tax incentives to
imported biofuels, imports of biodiesel and renewable diesel dropped
significantly in 2025 relative to previous years. The magnitude of the
effect of the structure of the 45Z credit was not apparent in the
available data at the time of the Set 2 proposal. We expect that
biodiesel and renewable diesel imports will continue to be available in
future years, but that the structure of the 45Z credit will continue to
provide strong support for biodiesel and renewable diesel produced in
the U.S. relative to imported fuels.
[[Page 16405]]
[GRAPHIC] [TIFF OMITTED] TR01AP26.036
ii. Biodiesel and Renewable Diesel Feedstock Assessment
---------------------------------------------------------------------------
\84\ USDA, ``Fats and Oils: Oilseed Crushings, Production,
Consumption, and Stocks,'' February 2, 2026. https://esmis.nal.usda.gov/sites/default/release-files/795753/cafo0226.pdf.
---------------------------------------------------------------------------
When considering the potential production and import of biodiesel
and renewable diesel in future years and the likely impacts of
biodiesel and renewable diesel production, feedstock availability is a
key consideration. Currently, biodiesel and renewable diesel in the
U.S. are produced from a number of different feedstocks, including
fats, oils, and greases (FOG), distillers corn oil, and virgin
vegetable oils such as soybean oil and canola oil. The available supply
of distillers corn oil is primarily a function of corn ethanol
production, as most corn ethanol facilities currently extract and sell
distillers corn oil. The available supply of soybean oil and canola oil
is primarily a function of the quantity of these oils produced by
oilseed crushing facilities, both of which have increased in recent
years.\84\
Figure III.A.2.a.ii-1: Feedstocks Used To Produce Biodiesel and
Renewable Diesel in the U.S.
[GRAPHIC] [TIFF OMITTED] TR01AP26.037
[[Page 16406]]
Use of soybean oil to produce biodiesel grew from approximately 10
percent of all domestic soybean oil production in the 2009/2010
agricultural marketing year to 48 percent in the 2023/2024 agricultural
marketing year, the latest data available at the time of writing.\85\
In the intervening years, the total increase in domestic soybean oil
production and the increase in the quantity of soybean oil used to
produce biodiesel and renewable diesel were similar while the use of
soybean oil in non-biofuel markets has been fairly stable. This
indicates that the increase in oil production was likely driven by the
increasing demand for biofuel. Notably, the percentage of the soybean
value that came from the soybean oil (rather than the meal and hulls)
had been relatively stable and averaged approximately 33 percent from
2016-2020. The percentage of the soybean value that came from the
soybean oil increased significantly starting in 2021, reaching a high
of 53 percent in October 2021, before declining slightly to 39 percent
in August 2024 (the most recent date for which data are available).\86\
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\85\ USDA, ``Oil Crops Yearbook,'' March 2025. https://www.ers.usda.gov/data-products/oil-crops-yearbook.
\86\ Id.
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Available volumes of FOG (including UCO and animal fats) and
distillers corn oil from domestic sources are expected to continue to
increase in future years, but these increases are expected to be
limited, especially as new trade dynamics take hold. FOG feedstocks,
like UCO, are the byproducts of other activities (e.g., food production
and rendering operations), and production of FOG is not responsive to
increasing demand for biofuel production. Similarly, distillers corn
oil is a byproduct of ethanol production. Since we do not anticipate
significant growth in ethanol production in future years (see section
III.A.3.a of this preamble), we do not project significant increases in
the production of distillers corn oil for biofuel production, as most
ethanol production facilities currently produce distillers corn oil.
Therefore, if biodiesel and renewable diesel production increase in
future years, it will likely require increased use of vegetable oils
such as soybean oil and canola oil, either from new production or
diverted from other markets, or increased use of imported feedstocks,
as occurred in 2022 and 2023 to some extent.
Greater volumes of soybean oil are projected to be produced from
new or expanded soybean crushing facilities through 2027. In recent
years, several parties announced plans to expand existing soybean
crushing capacity or build new soybean crushing facilities, including a
swing plant in Louisiana and a dedicated soy crush plant in
Illinois.\87\ Public announcements of near-certain expansions and new
builds suggest that domestic soybean crush capacity could reach 615,000
bushels per day in 2026, with growth largely coming from announced or
planned crush plants.\88\ This projection, which only accounts for
plants recently completed or under construction as of Q1 2026 would
result in 360 million additional gallons of BBD in 2026 alone.\89\ At
the time of writing, USDA projects 2026 increases in soy crush that
could result in domestic soybean oil production sufficient to produce
approximately 200 million gallons over current levels annually.\90\
Including announced future capacity, some projections of the domestic
crush capacity could result in an increase in domestic soybean oil
production sufficient to produce approximately 750 million additional
gallons of BBD per year and suggests a 250 million gallon per year
annual increase in soybean oil production through 2026.\91\ Similarly,
a 2024 assessment of potential BBD feedstocks in future years estimated
that increases in domestic soybean oil production could support the
production of an additional 1 billion gallons of BBD from 2023 to
2027.\92\ Recent data suggests that the domestic soybean crushing
industry is capable of continuing to add significant capacity in future
years, but any investment in domestic soybean crushing is highly
dependent on demand for soybean oil (and soybean meal) from biofuel
producers and other markets.\93\
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\87\ American Soybean Association, ``Soybean Crush Expansion,
2025 Update,'' April 10, 2025. https://soygrowers.com/news-releases/soybean-crush-expansion-2025-update.
\88\ American Soybean Association, ``Soybean Crush Expansion,
2025 Update,'' April 10, 2025. https://soygrowers.com/news-releases/soybean-crush-expansion-2025-update.
\89\ To note, announced facilities that have not begun
construction as of Q1 2026 are considered too uncertain.
\90\ USDA, ``World Agricultural Supply and Demand Estimates
Report,'' January 12, 2026. https://www.usda.gov/oce/commodity/wasde/wasde0126.pdf.
\91\ See RIA Section 7.2. This estimate assumes a soybean oil
yield of 12 lbs per bushel of soybeans and 1 gallon of BBD per 7.75
lbs of soybean oil.
\92\ S&P Global, ``Availability of Feedstocks for Biofuel Use--
Key Highlights,'' July 2024.
\93\ See RIA Chapter 7.2 for further discussion of this topic.
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If domestic crushing of soybeans increases at the expense of
soybean exports, domestic vegetable oil production could increase
without the need for increasing domestic soybean acreage. Increased
demand for BBD feedstock could also be met through diversion of
increasing volumes of qualifying feedstocks (e.g., soybean oil and
canola oil) from existing markets to produce biodiesel and renewable
diesel. Were this diversion to occur, non-qualifying feedstocks (e.g.,
palm oil, imported soybean oil from Latin American, or other virgin
vegetable oils) could be used in larger quantities in place of soybean
and canola oil in food and oleochemical markets. Diverting feedstocks
from existing uses would be projected to result in higher prices for
these feedstocks, as biofuel producers would have to outbid the current
users of these feedstocks.
In addition to processing domestic feedstocks such as distillers
corn oil and soybean oil, a number of domestic biodiesel and renewable
diesel producers produce fuel from imported feedstocks. In recent
years, the market has seen a significant increase in the quantity of
imported feedstocks. Imports of feedstocks that are often considered
wastes or by-products of other industries, such as UCO and tallow, have
seen the greatest increase in recent years. Figure III.A.2.b.ii-1 shows
total imports of common biodiesel and renewable diesel feedstocks
through 2024. Figure III.A.2.b.ii-2 shows the total volumes of domestic
biodiesel and renewable diesel produced from domestic feedstocks,
domestic biodiesel and renewable diesel produced from imported
feedstocks, and imported biodiesel and renewable diesel. Greater
discussion of both domestic and imported feedstocks can be found in RIA
Chapter 7.2.
Figure III.A.2.b.ii-1: Imports of BBD Feedstocks
[[Page 16407]]
[GRAPHIC] [TIFF OMITTED] TR01AP26.038
Figure III.A.2.b.ii-2: Domestic BBD From Domestic and Imported
Feedstocks and Imported BBD
[GRAPHIC] [TIFF OMITTED] TR01AP26.039
There are several factors that have likely contributed to the
recent increases in imports of certain BBD feedstocks to the U.S. Three
key factors contributing to the increase in imported feedstocks are
increasing domestic demand for these feedstocks, increasing available
supply of these feedstocks in other countries, and the structure of
[[Page 16408]]
incentive programs for biofuels in the U.S. relative to other
countries' policies. As noted in section III.A.2.b.iii of this
preamble, the production capacity for renewable diesel and renewable
jet fuel has increased rapidly and is expected to continue to be
maintained or grow in future years. As the total production capacity
for these fuels has grown, the demand for feedstocks for renewable fuel
production has grown along with the production capacity. This has led
to increases in not only domestic feedstock demand, but imported
feedstock demand as well. For example, we project that production of
canola oil will increase in future years due to expanding canola
crushing capacity in Canada and that much of this expanded production
will be exported to the U.S. for biofuel production.\94\ Similar to the
investments in soybean crushing in the U.S., a number of companies have
announced investment in additional canola crushing capacity in Canada,
and some of these projects are already under construction. Increasing
canola oil production in Canada could provide an opportunity for
domestic renewable diesel producers to import canola oil for biofuel
production. We note that these parties will face competition for this
feedstock from Canadian biofuel producers as well as food and other
non-biofuel markets. For example, in 2023, Canada began implementing
their Clean Fuels Requirements, requiring that the carbon intensity of
transportation fuel decrease by 1.5 gCO2e/MJ per year each
year from 2023 to 2030.\95\
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\94\ Some of the projected expansion in soybean crushing
capacity discussed in section III.B.2.c of this preamble is from
facilities also capable of crushing canola and other oilseeds.
Domestic production of canola is limited, however, and the majority
of canola oil supplied to biofuel producers through 2027 is expected
to be imported from Canada.
\95\ Government of Canada, ``What are the Clean Fuel
Regulations?'' July 7, 2022. https://www.canada.ca/en/environment-climate-change/services/managing-pollution/energy-production/fuel-regulations/clean-fuel-regulations/about.html.
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Canadian canola oil is the most prominent non-domestic beneficiary
after the 45Z credit changes in OBBB, but other non-domestic North
American feedstocks will also likely begin to expand their role in the
U.S. biofuels markets. This includes virgin seed oils, animal fats, and
larger UCO markets. In particular, Mexican UCO collection is poised to
expand, due to a precipitous dip in the observed trend of imported
Asian UCO in 2025 and lower collection costs than Canada.\96\ Domestic
incentives, coupled with rapidly shifting international financial
backing for biofuels, are poised to shift the biofuels feedstocks
market.
---------------------------------------------------------------------------
\96\ See RIA chapter 7.2 for further discussion of North
American feedstock growth potential.
---------------------------------------------------------------------------
The incentives available in foreign countries to encourage
production and use of BBD are changing rapidly, on an almost annual
basis. For example, in response to the Russian invasion of Ukraine in
February 2022, many European countries reduced biofuel mandates and
penalties for not fulfilling the mandates.\97\ The reduction in demand
from these countries resulted in an increase in the available feedstock
supply to the U.S. Around the same time, the European Union (EU) took
actions to discourage the importation of UCO and biodiesel produced
from China. On December 20, 2023, the EU announced an anti-dumping
investigation on biodiesel imported from China,\98\ finalized in July
2024.\99\ These actions, in part, led to increased UCO importation into
the U.S. from China. By that same token, however, export of Chinese UCO
was greatly affected by the removal of an export rebate by the Chinese
government in order to incentivize use in their burgeoning sustainable
aviation industry, contributing to declining growth of UCO importation
in the U.S. in 2024 and 2025.\100\
---------------------------------------------------------------------------
\97\ USDA, ``Biofuel Mandates in the EU by Member State--2024,''
June 27, 2024.
\98\ European Commission, ``European Commission to Examine
Allegations of Unfairly Traded Biodiesel from China,'' December 20,
2023. https://policy.trade.ec.europa.eu/news/european-commission-examine-allegations-unfairly-traded-biodiesel-china-2023-12-20_en.
\99\ Reuters, ``EU to Set Tariffs on Chinese Biodiesel in Anti-
Dumping Probe,'' July 19, 2024. https://www.reuters.com/business/energy/eu-set-tariffs-chinese-biodiesel-imports-anti-dumping-probe-2024-07-19.
\100\ USDA FAS, ``UCO Export Tax Rebate Terminated'', https://www.fas.usda.gov/data/china-uco-trade-update.
---------------------------------------------------------------------------
Recent changes in the trade flows of UCO from China illustrate the
changing nature of incentive programs and the impact these changes can
have on the supply of biofuel feedstocks. From 2018-2023, exports of
UCO from China increased significantly, from approximately 0.6 million
metric tons in 2018 to about 2.1 million metric tons in 2023. From
2018-2022, the primary destination of these exports was Europe,
accounting for approximately 60 percent of all exports of UCO from
China, while less than 1 percent of all exports of UCO from China were
exported to the U.S.\101\ In 2023, however, the market dynamics changed
significantly. Exports of UCO from China to Europe fell to just 23
percent of total exports, while exports to the U.S. increased to 41
percent.\102\ The decline in European UCO imports was due to a
combination of factors, including reduced demand for biodiesel and
renewable diesel in some EU member states and concerns that imported
UCO from China may include palm oil. These concerns resulted in
decreased demand for UCO sourced from China in the EU and simultaneous
increased demand for this feedstock in the U.S. In 2025, this dynamic
again shifted, with a precipitous drop in U.S. imports of Chinese UCO.
This coincided with a high tariff environment, the removal of a UCO
export rebate by the Chinese government in December 2024,\103\ and a
upsurge of Chinese sustainable aviation fuel refining.\104\ The
unpredictable nature of changes to biofuel incentives in both the U.S.
and other countries in future years, combined with the potentially
significant impact of these changes, makes it very difficult to predict
the supply of these feedstocks to U.S. biofuel producers with a high
degree of certainty.
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\101\ UN Comtrade Database, Trade Data, HS Code 1518.
\102\ Id.
\103\ USDA Foreign Agricultural Service, ``UCO Export Tax Rebate
Terminated,'' CH2024-0149, November 25, 2024. https://apps.fas.usda.gov/newgainapi/api/Report/DownloadReportByFileName?fileName=UCO%20Export%20Tax%20Rebate%20Terminated_Beijing_China%20-%20People%27s%20Republic%20of_CH2024-0149.pdf.
\104\ International Civil Aviation Organization, ``Progress of
Sustainable Aviation Fuels Pilot In China,'' September 13, 2025.
https://www.icao.int/sites/default/files/Meetings/a42/Documents/WP/wp_573_en.pdf.
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Incentive programs for biofuels in the U.S. have also contributed
to the recent observed increases in biofuel feedstock imports. State
low carbon fuel standards or clean fuels programs, such as California's
LCFS, provide greater incentives for fuels with lower carbon
intensities. In general, fuels produced from byproducts such as UCO or
tallow have lower carbon intensity values under these programs and thus
generate greater credits relative to virgin vegetable oils such as
soybean oil and canola oil. In recent years, additional States such as
Oregon, Washington, and New Mexico have adopted programs that similarly
provide higher incentives for fuels with lower carbon intensity.
While these State programs do not explicitly favor imported fuels
and/or feedstocks over domestic fuels and feedstocks, most of the
available waste and by-product feedstocks such as UCO and tallow
available in the U.S. are already being used for biofuel production.
The nature of these programs has played a role in biofuel producers
seeking to import UCO and
[[Page 16409]]
tallow from foreign countries rather than increasing their use of
domestic soybean oil to maximize their generation of credits under
these programs.
For the reasons discussed above, in recent years, animal fats and
UCO have become a popular source of feedstock. Most of the economically
recoverable UCO and animal fats in the U.S. are currently collected and
productively used, primarily for biofuel production.\105\ It is a well-
established market and while the supply of these feedstocks are
projected to grow, the rate of growth will be modest and driven by
domestic meat production and the use of vegetable oil for food
production.
---------------------------------------------------------------------------
\105\ Global Data, ``UCO Supply Outlook,'' August 2023.
---------------------------------------------------------------------------
In contrast, there is both significant growth potential and a high
degree of uncertainty surrounding the supply of animal fats and UCO
that could be imported into the U.S. and used for biofuel production.
There is large supply capable of being bid away from other markets, but
rapidly shifting trading dynamics and strong domestic feedstock
availability may dampen growth in future years. The global supply of
animal fats is expected to increase with global meat consumption.
Global meat production increased 53 percent from 2000 to 2021 and is
expected to continue to increase in future years.\106\ Like other
biodiesel and renewable diesel feedstocks, animal fats have
historically been used in other markets such as for oleochemical
production and livestock feed. We project that strong incentives for
biofuels produced from animal fats in the U.S. (from both State and
Federal incentive programs) will result in increasing quantities of
these feedstocks being used for biofuel production. Thus, we project
that the available supply of animal fats to biofuel producers will
increase in future years due to both increasing animal fat production
as a byproduct of increasing meat production. It may also supplant some
UCO imports as an alternative biofuel feedstock. In 2025, for example,
tallow imports surged as UCO imports declined.\107\ The environmental
benefits associated with biofuels produced from diverting animal fats
(or any feedstock) diverted from existing markets are likely less than
the environmental benefits associated with biofuels produced from
feedstocks that would not otherwise be productively used.\108\
---------------------------------------------------------------------------
\106\ Food and Agriculture Organization of the United Nations,
``World Food and Agriculture--Statistical Yearbook 2023,'' 2023.
https://doi.org/10.4060/cc8166en.
\107\ Argus Media, ``Viewpoint: US Policy Shift Elevates
Domestic Feedstocks,'' February 1, 2026. https://www.argusmedia.com/en/news-and-insights/latest-market-news/2771306-viewpoint-us-policy-shift-elevates-domestic-feedstocks.
\108\ When feedstocks are diverted from existing uses, the
markets that previously used these feedstocks generally seek
alternative feedstocks. Potential alternatives could include
petroleum-based feedstocks or palm oil. Increased use of these
feedstocks in non-biofuel markets could reduce or negate the
intended environmental benefits from increased biofuel production.
---------------------------------------------------------------------------
The global supply of UCO is primarily a function of UCO collection
rates, which are themselves a function of the total quantity of
vegetable oils used in food production and the infrastructure in place
to collect and productively use UCO. UCO collection rates vary
significantly by country, from virtually nothing in many countries to
approximately 2.5 pounds per capita per year in the U.S.\109\ Demand
for UCO as a feedstock for biofuel production in recent years has
resulted in a rapid increase in the global collection of UCO, from
approximately 2.3 billion gallons in 2018 to approximately 3.7 billion
gallons in 2022.\110\ A recent study projected that the increase in
global UCO collection from 2022 to 2027 could range from 1.4 billion
gallons (based on projected increases in population and GDP) to 6.1
billion gallons (based on increasing collection rates in countries that
currently have some UCO collection infrastructure in place).\111\
---------------------------------------------------------------------------
\109\ Global Data, ``UCO Supply Outlook,'' August 2023.
\110\ Id.
\111\ Id.
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Despite competing incentives and a growing worldwide biofuels
market, feedstocks abound, with the U.S. remaining the preeminent
destination for renewable fuel production. As renewable diesel and
biodiesel capacity has expanded, so too has the flexibility of the
market to utilize different feedstocks. More facilities than ever
before accept mixed streams of feedstocks, and those feedstocks are all
growing rapidly. With an unyielding supply of distillers corn oil,
ever-expanding UCO collection coverage, and robust growth in canola and
soy crush, domestic renewable fuel producers are likely to be able to
source the quantities of feedstocks they need in order to maximize
production. We do not believe feedstocks will be a limiting factor in
2026 and 2027, and we believe that the industry is capable of utilizing
more capacity than it has over the previous several years.
iii. Biodiesel and Renewable Diesel Production Capacity
Available data suggests that there is significant unused biodiesel
production capacity in the U.S., and thus domestic biodiesel production
could grow without the need to invest in additional production
capacity. Data reported by EIA shows that domestic biodiesel production
capacity in November 2025 was approximately 1.96 billion gallons per
year, roughly 800 million gallons more than was utilized through
2025.\112\ According to this data, annual average biodiesel production
capacity grew relatively slowly from about 2.1 billion gallons in 2012
to a peak of approximately 2.6 billion gallons in 2019. Reduction in
EIA's reported operable capacity from 2015 to present likely reflects
facility inactivity or closure. While EIA reports operable capacity,
EPA data suggests that there are potential mothballed, inactive, or
temporarily halted facilities beyond EIA's reported operable
capacity.\113\ This is a result of unfavorable economics in many cases.
Renewable diesel has supplanted much of the available biodiesel
capacity over the past decade.
---------------------------------------------------------------------------
\112\ EIA, ``U.S. Biodiesel Production Capacity,'' Petroleum &
Other Liquids, February 6, 2026. https://www.eia.gov/dnav/pet/hist/LeafHandler.ashx?n=PET&s=M_EPOORDB_8BDPC_NUS_MMGL&f=M.
\113\ See ``BBD Facility Capacity,'' available in the docket for
this action.
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Total domestic renewable diesel production capacity has increased
significantly in recent years from approximately 280 million gallons in
2017 \114\ to approximately 5 billion gallons at the end of 2025.\115\
Additionally, a number of parties have announced plans to build new
renewable diesel production capacity with the potential to begin
production in future years. While production slowed down in 2025,
capacity expansions are buoyed by continued demand for renewable jet
fuel and the strength of State market incentives. This new capacity
includes new renewable diesel production facilities, expansions of
existing renewable diesel production facilities, and the conversion of
units at petroleum refineries to produce renewable diesel.
---------------------------------------------------------------------------
\114\ Renewable diesel capacity based on facilities registered
in EMTS.
\115\ EIA, ``U.S. Total Biofuels Operable Production Capacity,''
Petroleum & Other Liquids, October 30, 2025. https://www.eia.gov/dnav/pet/pet_pnp_capbio_dcu_nus_m.htm.
---------------------------------------------------------------------------
EIA previously projected that renewable diesel production capacity
would continue to expand and could reach nearly 6 billion gallons by
the end of 2025, but acknowledged that they expected some of these
projects would
[[Page 16410]]
be delayed or cancelled.\116\ This projection was not met, but EIA
continues to project robust annual production growth of 25 percent over
the next two years.\117\ A 2024 report found that by 2028 the domestic
production capacity for renewable diesel and renewable jet fuel through
the hydrotreating process alone could increase to 9.6 billion gallons
per year.\118\ In previous years, domestic renewable diesel production
has increased in concert with increases in domestic production
capacity, with renewable diesel facilities generally operating at high
utilization rates.\119\
---------------------------------------------------------------------------
\116\ EIA, ``Domestic renewable diesel capacity could more than
double through 2025,'' Today in Energy, February 2, 2023. https://www.eia.gov/todayinenergy/detail.php?id=55399.
\117\ EIA, ``Short-Term Energy Outlook,'' January 2026, Table
4d--U.S. Biofuel Supply, Consumption, and Inventories. https://www.eia.gov/outlooks/steo/tables/pdf/4dtab.pdf.
\118\ Calderon, Oscar Rosales, Ling Tao, Zia Abdullah, Michael
Talmadge, Anelia Milbrandt, Sharon Smolinski, Kristi Moriarty, et
al. ``Sustainable Aviation Fuel State-of-Industry Report:
Hydroprocessed Esters and Fatty Acids Pathway,'' National Renewable
Energy Laboratory NREL/TP-5100-87803, July 30, 2024. https://doi.org/10.2172/2426563.
\119\ For further discussion and visualization of capacity and
utilization rates, see RIA Chapter 7.2.
---------------------------------------------------------------------------
iv. Biodiesel and Renewable Diesel Analyzed Volumes
In developing the Analyzed Volumes of biodiesel and renewable
diesel, we have identified the maximum quantity of BBD that could
reasonably be produced utilizing all the currently operating domestic
production capacity, mirroring utilization seen in similar industries
(90 percent utilization rate).\120\ Our assessment of available
feedstocks indicates that domestic production capacity, rather than the
availability of feedstock, is the factor most likely to constrain
domestic biodiesel and renewable diesel production in 2026 and 2027,
based on new data and analysis subsequent to the Set 2 proposal.
---------------------------------------------------------------------------
\120\ EIA, U.S. Percent Utilization of Refinery Operable
Capacity, https://www.eia.gov/dnav/pet/hist/LeafHandler.ashx?n=pet&s=mopueus2&f=a.
\121\ More detail on the development of this projection can be
found in RIA Chapters 3 and 6.
\122\ Renewable jet fuel volumes are based on data from EMTS.
\123\ The equivalence values for renewable diesel and jet fuel
are similar. As discussed in section VIII.A of this preamble, we are
revising the renewable diesel equivalence value to be 1.5 RINs per
gallon, while also establishing the renewable jet fuel equivalence
value to be 1.5 RINs per gallon. However, we expect most renewable
diesel will generate 1.6 RINs/gallon in 2027 through the equivalence
value application process.
---------------------------------------------------------------------------
In addition to projecting the overall Analyzed Volumes of biodiesel
and renewable diesel we have also projected the mix of feedstocks used
to produce these fuels in 2026 and 2027. The mix of the feedstocks used
to produce BBD will indirectly impact other statutory factors, as the
environmental and economic impacts of biodiesel and renewable diesel
may differ depending on the feedstocks used to produce these fuels. For
example, the impacts of increasing biodiesel and renewable diesel
production vary depending on whether the fuel was produced from UCO
that would not otherwise have been collected, soybean oil from
additional production and processing of soybeans, or the diversion of
feedstocks or biofuels that would otherwise have been used in other
markets. Our projections of the feedstocks used to produce biodiesel
and renewable diesel in 2026 and 2027 reflect input received from
commenters, the most recent data available at the time the projections
were completed, and our assessment of the impact of the 45Z credit. As
biodiesel and renewable diesel producer feedstock procurement is driven
largely by input feedstock cost, the composition of feedstocks
contributing to the actual volumes of biodiesel and renewable diesel in
2026 and 2027 may differ.\121\
[GRAPHIC] [TIFF OMITTED] TR01AP26.040
b. Renewable Jet Fuel
There is also a small volume of renewable jet fuel that qualifies
as BBD. Renewable jet fuel has qualified as a RIN-generating BBD and
advanced biofuel under the RFS program since 2010 and must achieve at
least a 50 percent GHG reduction in comparison to petroleum-based
fuels. While relatively little renewable jet fuel was produced or
imported through 2023 (20 million gallons or less per year) production
volumes have been increasing in recent years, reaching approximately
110 million gallons in 2024 and approximately 290 million gallons in
2025.\122\
Tax credits for renewable jet fuel available during 2023 and 2024,
often referred to as the ``sustainable aviation fuel credit'' or ``40B
credit'' (also available as the 6426(k) excise tax credit), may have
resulted in increasing volumes of renewable jet fuel produced from
existing renewable diesel production facilities. The 45Z credit is
available from 2025 through 2029 and, starting in 2026, provides up to
$1.00 per gallon of renewable jet fuel, provided the relevant wage and
apprenticeship requirements are met by the producer. The 45Z credit may
provide continued support for renewable jet fuel production. Renewable
jet fuel production from existing renewable diesel facilities, however,
would likely result in a decrease in renewable diesel production, with
little or no net change in their overall production of RIN-generating
fuels.\123\
The vast majority of renewable jet fuel produced through 2025 was
produced using the same feedstocks and very similar production
technologies as renewable diesel, and in most cases are produced at the
same production facilities. For example, Montana Renewables produced
both renewable diesel and renewable jet fuel at their Great Falls,
Montana facility in 2024,\124\ as did Phillips 66 in their Rodeo,
California facility.\125\ Historically,
[[Page 16411]]
greater incentives have been available for renewable diesel production
than for renewable jet fuel production. This has resulted in most
production facilities choosing to maximize renewable diesel production,
although based on the production data at the time of this writing this
dynamic may be starting to change.
In the near term, we expect that because the vast majority of
renewable jet fuel will be produced using the same feedstocks and at
the same facilities as renewable diesel any increase in renewable jet
fuel production will result in a corresponding decrease in renewable
diesel production. We recognize that new technologies are being
developed to produce renewable jet fuel from a wider variety of
feedstocks, some of which are not suitable for use in the hydrotreating
process that dominates renewable diesel production. For example,
several companies are developing new technologies intended to produce
renewable jet fuel from ethanol or other alcohols, through a technology
often referred to as the ``alcohol-to-jet'' (``ATJ'') process. To date,
we have not approved a generally applicable pathway for these fuels,
but we have approved a facility-specific pathway for the production of
renewable jet fuel from ethanol to generate D4 RINs.\126\ While ATJ has
the potential to produce significant volumes of renewable jet fuel in
future years, there is a high degree of uncertainty related to the
production of these fuels through 2027 as commercial scale production
of these fuels has been limited and no RINs have yet been generated for
these fuels at the time of this writing. Production of renewable jet
fuel using these emerging technologies may not negatively impact
renewable diesel production to the extent that they do not compete for
feedstocks.
---------------------------------------------------------------------------
\124\ Montana Renewables, ``Products,'' https://montanarenewables.com/products.
\125\ Phillips 66, ``Rodeo Renewable Energy Complex,'' https://www.phillips66.com/rodeo-renewable-energy-complex.
\126\ See, e.g., EPA, ``Letter from EPA to LanzaJet, Inc.,''
January 12, 2023.
---------------------------------------------------------------------------
In this action, we have not separately projected growth in
renewable jet fuel production. Instead, we are considering any
production of renewable jet fuel from hydrotreating lipid feedstocks in
our projection of renewable diesel production. We recognize that other
renewable jet fuel production technologies and production facilities
are being developed and, in some cases, may produce small fuel volumes
in the near term. These could enable the future production of renewable
jet fuel from new facilities and feedstocks that are not expected to
impact renewable diesel production.
c. Other Advanced Biofuels
In addition to biodiesel, renewable diesel, and renewable jet fuel,
other renewable fuels that qualify as advanced biofuel have been
produced and used in the U.S. in the past and are expected to
contribute to compliance with applicable RFS volume requirements in the
future. These other advanced biofuels include imported sugarcane
ethanol, domestically produced advanced ethanol, RNG used in CNG/LNG
vehicles not produced from cellulosic biomass, and heating oil,
naphtha, and co-processed renewable diesel that does not qualify as
BBD.\127\
---------------------------------------------------------------------------
\127\ Renewable diesel produced through coprocessing vegetable
oils or animal fats with petroleum cannot be categorized as BBD but
remains advanced biofuel.
---------------------------------------------------------------------------
These biofuels have been used in much smaller quantities than
biodiesel and renewable diesel in the past, and the production volumes
of many of these fuels have been highly variable. Some of these ``other
advanced biofuels'' such as naphtha and heating oil are byproducts of
the production of other types of renewable fuel. Others, such as co-
processed renewable diesel and sugarcane ethanol, are consistently
produced or imported at volumes far below their theoretical production
capacity. This variability in the technologies used to produce these
fuels and their production volumes over time makes projecting the
potential production or import volumes in future years challenging.
To determine the Analyzed Volumes of these other advanced biofuels
in 2026 and 2027, we used the same general methodology as in the Set 2
proposal and the Set 1 Rule. We projected the supply of these other
advanced biofuels using historic data on the supply of these fuels from
2015-2025. Our methodology addresses the historical variability in
these categories of advanced biofuel while recognizing that consumption
in more recent years is likely to provide a better basis for making
future projections than consumption in earlier years. Specifically, we
applied a weighting scheme to historical volumes wherein the weighting
was higher for more recent years and lower for earlier years. The
result of this approach is shown in Table III.A.2.c-1. Details of the
derivation of these estimates can be found in RIA Chapter 5.4. As the
available data varies significantly from year to year, it does not
allow us to identify an upward or downward trend in the historical
consumption of these other advanced biofuels. Therefore, we have used
the volumes in Table III.A.2.c-1 both 2026 and 2027.
[[Page 16412]]
[GRAPHIC] [TIFF OMITTED] TR01AP26.041
d. Analyzed Volumes of Non-Cellulosic Advanced Biofuels
Non-cellulosic advanced biofuel has been the fastest growing
category of renewable fuel in the RFS program since 2021, with the
majority of the growth coming from renewable diesel. While the supply
of non-cellulosic advanced biofuels decreased from 2024 to 2025, our
analyses indicate that sufficient domestic production capacity and
feedstocks are available to enable the production of these fuels to
increase significantly in 2026 and 2027. Sections III.A.2.a through c
of this preamble describe our derivation of the Analyzed Volumes of
different types of non-cellulosic advanced biofuels for 2026 and 2027.
These Analyzed Volumes are summarized in Table III.A.2.d-1.
[GRAPHIC] [TIFF OMITTED] TR01AP26.042
3. Conventional Renewable Fuel
Conventional renewable fuel includes any renewable fuel that is
made from renewable biomass as defined in 40 CFR 80.1401, does not
qualify as advanced biofuel (including cellulosic biofuel and BBD), and
meets one of the following criteria:
Is demonstrated to achieve a minimum 20 percent reduction
in lifecycle GHG emissions in comparison to the gasoline or diesel
which it displaces; or
Is exempt (``grandfathered'') from the 20 percent minimum
GHG reduction requirement due to having been produced in a facility or
facility expansion that commenced construction on or before December
19, 2007, as described in 40 CFR 80.1403 and pursuant to CAA section
211(o)(2)(A)(i).
Under the statute, there is no volume requirement for conventional
renewable fuel. Instead, conventional renewable fuel may fill that
portion of the total renewable fuel volume requirement that is not
required to be advanced biofuel. In some cases, this portion of the
total renewable fuel requirement that can be met with conventional
renewable fuel is referred to as an ``implied'' volume requirement.
However, obligated parties are not required to comply with it per se,
since any portion of it can be met with advanced biofuel volumes
exceeding what is needed to meet the advanced biofuel volume
requirement.
To develop the Analyzed Volumes of conventional renewable fuel for
2026 and 2027, we focused primarily on projecting volumes of ethanol
consumed via motor gasoline use across all gasoline blends with varying
concentrations of ethanol (i.e., E10, E15, and E85). We also
investigated potential volumes of non-advanced biodiesel and renewable
diesel.
a. Corn Ethanol
Ethanol made from corn starch has historically been the renewable
fuel supplied in the greatest quantities basis in the past and is
expected to continue to do so in 2026 and 2027.\128\ Corn starch
ethanol is prohibited by CAA section 211(i)(1)(B)(i) from being an
advanced biofuel regardless of its lifecycle GHG emissions performance
in comparison to gasoline.
---------------------------------------------------------------------------
\128\ Conventional ethanol from feedstocks other than corn
starch have been produced in the past, but at significantly lower
volumes. Production of ethanol from grain sorghum reached 125
million gallons in 2019, representing just less than 1 percent of
all conventional ethanol in that year; grain sorghum ethanol in 2024
was only 46 million gallons. Waste industrial ethanol and ethanol
made from non-cellulosic portions of separated food waste have been
produced more sporadically and at even lower volumes. These other
sources do not materially affect our assessment of volumes of
conventional ethanol that can be produced.
---------------------------------------------------------------------------
Total domestic corn ethanol production capacity increased
dramatically between 2005 and 2010 and increased at a slower rate
thereafter. As of late 2025, domestic corn ethanol production capacity
exceeded 18 billion gallons.\129\ Actual production of corn ethanol in
the U.S. was approximately
[[Page 16413]]
16.2 billion gallons in 2024 and is estimated to have reached 16.4
billion gallons in 2025.\130\
---------------------------------------------------------------------------
\129\ EIA, ``Monthly Biofuels Capacity and Feedstocks Update,''
November 28, 2025. https://www.eia.gov/biofuels/update.
\130\ EIA, ``Monthly Energy Review,'' Total Energy, March 2025.
https://www.eia.gov/totalenergy/data/monthly/pdf/mer.pdf.
---------------------------------------------------------------------------
The expected annual rate of future commercial production of corn
ethanol will continue to be driven primarily by gasoline demand in 2026
and 2027, as most gasoline is expected to continue to contain 10
percent ethanol during this period. Commercial production of corn
ethanol is also a function of exports of ethanol and the demand for E0,
E15, and E85. There is evidence that some fuel retailers sell higher
volumes of E15 than E10, leveraging lower prices at the pump and
marketing higher-level ethanol blends to their customers as a cheaper
fuel option with only negligible effects on fuel economy (a 1-2 percent
reduction compared to E10). In addition to government incentives,
industry-led efforts such as Prime-the-Pump have enjoyed great success
in growing markets for higher ethanol gasoline blends by providing
technical and financial assistance to fuel retailers.\131\
Acknowledging the potential for growth in these fuel markets, we have
incorporated projected growth in opportunities for sales of E15 and E85
blends into our assessment.
---------------------------------------------------------------------------
\131\ Transportation Energy Institute, ``The Case of E15,''
February 2018.
---------------------------------------------------------------------------
Despite this steady growth, there remains excess production
capacity of ethanol and corn feedstock in comparison to the ethanol
volumes that we estimate will be consumed domestically during 2026 and
2027, given constraints on U.S. ethanol consumption. Thus, as was the
case with the Set 1 Rule, we do not expect production capacity to be a
limiting factor in determining the Analyzed Volumes.
The total volume of ethanol that can be used--including ethanol
produced from corn, grain sorghum, cellulosic biomass, the non-
cellulosic portions of separated food waste, and sugarcane--is a
function of demand for E10, E15, and E85 ethanol blends most commonly
used in the U.S. and for E0. Ethanol concentration across the entire
gasoline pool can exceed 10 percent only insofar as the incremental
ethanol in E15 and E85 volumes more than offsets the lack of ethanol in
E0 volume. As shown in Figure III.A.3.a-1, poolwide ethanol
concentration increased dramatically from 2003 through 2010 and has
continued to grow more slowly since 2010. As the average ethanol
concentration approached and then exceeded 10 percent, the gasoline
pool became saturated with E10, with a small, likely stable volume of
E0 and small but gradually increasing volumes of E15 and E85. We expect
this trend to continue during 2026 and 2027.
Figure III.A.3.a-1: Historical Poolwide Volumetric Ethanol
Concentration
[GRAPHIC] [TIFF OMITTED] TR01AP26.043
[[Page 16414]]
For this action, volume data from USDA's Higher Blends
Infrastructure Incentive Program (HBIIP) \132\ and additional volume
data acquired directly from six States with high volumes of higher-
level ethanol blends (California, Kansas, Iowa, Minnesota, New York,
and North Dakota) has enabled a data-driven, bottom-up approach to
projecting ethanol volumes into the future that differs from the way
these projections were calculated in previous years. More information
on this method of projection ethanol concentration can be found in RIA
Chapter 7.5.1. We introduced this new methodology in the Set 2 proposal
and continue to refine it here. In the Set 1 Rule, we projected ethanol
concentration in the national gasoline pool using a least-squares
regression model using then-current E15 and E85 fueling station
population data.\133\ This was due to lack of data and a subsequent
inability to aggregate sales volumes by ethanol volume at the retail
fuel station level. Now, greater availability of sales volume data from
the aforementioned six States, HBIIP, and industry partners has enabled
an updated and simplified methodology for producing the ethanol volume
projections in this action.
---------------------------------------------------------------------------
\132\ USDA, ``Higher Blends Infrastructure Incentive Program,''
May 2023. https://www.rd.usda.gov/hbiip.
\133\ See ``Renewable Fuel Standard (RFS)Program: Standards for
2023-2025 and Other Changes Regulatory Impact Analysis,'' EPA-420-R-
23-015, June 2023 (``RFS Set 1 RIA''), Chapter 7.5.1.
---------------------------------------------------------------------------
Using the average sales of each gasoline-ethanol blend per retail
fueling station, as well as updated station populations from DOE's
Alternative Fuels Data Center (AFDC) \134\ and the California Air
Resources Board (CARB) \135\ for 2021-2024, we produced projections of
expected growth in station counts and throughputs out to 2027 for each
gasoline-ethanol blend other than E10. In addition to a projection for
each blend, E85 projections were expanded in this action relative to
the Set 1 Rule. After reviewing the State-specific data, the difference
between the E85 market in California compared to five other States
(i.e., Kansas, Iowa, Minnesota, New York, and North Dakota) became
apparent. Thus, we chose to analyze the California E85 market
separately from the other States in order to more accurately project
E85 in California versus the rest of the U.S. We then used these
projections to estimate the total fuel volume for these gasoline-
ethanol blends (E0, E15, and E85) for 2026 and 2027 using the following
relation: for gasoline-ethanol blends at each concentration, the total
fuel volume consumed in any given year is equal to the product of the
number of retail fueling stations offering that blend for sale and the
volume of that fuel blend sold at a fueling station (i.e., throughput)
on average during that year. Finally, we projected E10 as the remainder
of the gasoline pool, after accounting for the Analyzed Volumes of E0,
E15, and E85, using the most recent version of EIA's Annual Energy
Outlook to project total gasoline demand for 2026 and 2027.\136\
---------------------------------------------------------------------------
\134\ AFDC, ``Historical Alternative Fueling Station Counts.''
https://afdc.energy.gov/stations/states.
\135\ CARB, ``Annual E85 Volumes,'' April 11, 2025.
\136\ EIA, ``Annual Energy Outlook 2025,'' April 15, 2025
(``AEO2025''). https://www.eia.gov/outlooks/aeo.
---------------------------------------------------------------------------
Total ethanol consumption is the sum of gasoline (E0) blended with
ethanol to create E10, E15, and E85.\137\ The ethanol portion of the
projected total consumption for each fuel blend (i.e., total ethanol
consumption) is shown in Table III.A.3.a-1. While we project that the
ethanol concentration in the gasoline pool will increase in future
years, total ethanol consumption is projected to decrease due to
decreases in total gasoline consumption in future years.
---------------------------------------------------------------------------
\137\ See RIA Chapter 7.5.1 for a more comprehensive discussion
of the methodology employed to produce the total ethanol consumption
projection.
\138\ Less than 15 million gallons total of conventional
biodiesel and renewable diesel has been produced domestically from
2014-2025.
[GRAPHIC] [TIFF OMITTED] TR01AP26.044
b. Conventional Biodiesel and Renewable Diesel
Other than conventional ethanol, the only other conventional
renewable fuels that have been used at significant levels in the U.S.
in recent years have been conventional biodiesel and renewable diesel.
Conventional biodiesel and renewable diesel are produced at facilities
grandfathered under 40 CFR 80.1403 because there are no currently valid
RIN-generating pathways for their production. Almost all conventional
biodiesel and renewable diesel historically used in the U.S. has been
imported.\138\ According to EMTS data, the use of conventional
biodiesel and renewable diesel did grow marginally in 2024 after a
period of very low volume (less than 1 million gallons per year from
2018-2022), though the overall supply remained negligible (less than
0.1 percent of total biofuel supply to the U.S.) and the total supply
of conventional biodiesel and renewable diesel in 2025 was once again
less than one million gallons. While some sparse generation of D6 RINs
for these fuels have been observed in recent years, nearly all these
RINs were retired for being designated for use in any application other
than transportation fuel and therefore do not represent qualifying fuel
under the RFS program. As discussed in RIA Chapter 7.7, there exists
much greater potential for domestic production and use of conventional
biodiesel and renewable diesel than has actually been supplied in prior
years, suggesting the use of these fuels in the U.S. is largely a
function of domestic demand for these fuels and the incentives
available for conventional biodiesel and renewable diesel in the U.S.
relative to other countries. While there exists some potential for
growth in 2026 and 2027, we are not including volumes of conventional
biodiesel and renewable diesel in our analyses for this final rule.
c. Conventional Renewable Fuel Summary
The Analyzed Volumes of conventional renewable fuel represent the
volume of these fuels we project would be supplied to the market when
considering the incentives that could be available through the RFS
program and other State and Federal incentives. Since the supply of
ethanol is projected to be limited by the ability for the market to
consume ethanol in gasoline blends, the supply of conventional ethanol
in 2026 and 2027 can be estimated from the total ethanol
[[Page 16415]]
consumption projections from Table III.A.3.a-1 and our projections for
other forms of ethanol as discussed earlier in this section. Our
projected volumes of ethanol consumption are presented in Table
III.A.3.c-1. We do not currently project that non-ethanol conventional
renewable fuels will be supplied to the U.S. under the RFS program in
2026 and 2027.
[GRAPHIC] [TIFF OMITTED] TR01AP26.045
4. Summary of Analyzed Volumes
For the reasons explained in the introduction of section III.A of
this preamble, we have developed Analyzed Volumes for 2026 and 2027 to
aid our analyses under CAA section 211(o)(2)(B)(ii). The methodology
used to develop the Analyzed Volumes of each component category of fuel
are summarized in sections III.A.1 through 3 of this preamble. The
Analyzed Volumes used to support this final rule are presented in
Tables III.A.4-1 and 2.
[GRAPHIC] [TIFF OMITTED] TR01AP26.046
[GRAPHIC] [TIFF OMITTED] TR01AP26.047
To determine the final volume requirements for 2026 and 2027, we
developed and evaluated these Analyzed Volumes to facilitate our
analysis of the statutory factors listed in CAA section
211(o)(2)(B)(ii)(I)-(VI). A summary of several of these analyses is
described in section III.D of this preamble and discussed in greater
detail in the RIA. Details of the individual biofuel types and
feedstocks that make up the Analyzed Volumes are provided in RIA
Chapter 3. In section III.E of this preamble we discuss the volume
requirements based on a consideration of all the factors that we
analyzed.
B. Baselines
To estimate the impacts of the Analyzed Volumes, we must identify
the appropriate baseline(s). The primary baseline developed for this
final rule reflects the use of renewable fuels absent this final rule
or the RFS program (i.e., the alternative collection of biofuel volumes
by feedstock, production process (where appropriate), and biofuel type
that would be anticipated to occur in 2026 and 2027 in the absence of
RFS program), and acts as the point of reference for assessing the
impacts of this final rule. To this end, we have developed a ``No RFS''
scenario that we used as the baseline for analytical purposes
(hereinafter the ``No RFS Baseline''). Many of the same supply-related
factors that we used to develop the Analyzed Volumes were also relevant
in developing the No RFS Baseline.
We also developed a 2025 baseline that in some cases is more
informative in understanding the impacts of the Analyzed Volumes
relative to the status quo.
1. No RFS Baseline
Broadly speaking, the RFS program is designed to increase the use
of renewable fuels in the transportation sector beyond what would occur
in the absence of the program. It is appropriate, therefore, to use a
scenario representing what would occur if the RFS program did not
continue to exist as the baseline for estimating the costs and impacts
of the Analyzed Volumes. Our No RFS Baseline is consistent with the
Office of Management and Budget's Circular A-4, which says that the
appropriate baseline would normally ``be a `no action' baseline: what
the world will be like if the proposed rule is not adopted.'' \139\
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\139\ Office Management and Budget, ``Circular A-4,'' 68 FR
58366 (October 9, 2003).
---------------------------------------------------------------------------
Importantly, this No RFS Baseline is not equivalent to a market
scenario
[[Page 16416]]
wherein no renewable fuels are used at all. Prior to the RFS program,
both biodiesel and ethanol were used in the transportation sector,
whether due to State or local incentives, tax credits, or a price
advantage over conventional petroleum-based gasoline and diesel. This
same situation would exist in 2026 and 2027 in the absence of the RFS
program. Federal, State, and local tax credits, incentives, and support
payments would continue to be in place for these fuels, as well as
State programs such as blending mandates and LCFS programs.
Furthermore, now that capital investments in renewable fuels have been
made and markets have been oriented towards their use, there are strong
incentives in place for continuing their use even if the RFS program
were to disappear. As a result, it would be improper and inaccurate to
attribute all use of renewable fuel in 2026 and 2027 to the applicable
standards under the RFS program.
To inform our assessment of the volume of renewable fuels that
would be used in the absence of the RFS program for the years 2026 and
2027, we began by analyzing the trends in the economics for renewable
fuels blending in prior years. Assessing these trends is important
because the economics for blending renewable fuels changes from year to
year based on renewable fuel feedstock and petroleum product prices and
other factors that affect the relative economics for blending renewable
fuels into petroleum-based transportation fuels. A renewable fuel
facility investor and the financiers who fund their projects will
review the historical (e.g., did they lose money in a previous year),
current, and perceived future economics of the renewable fuel market
when deciding whether to continue to operate their renewable fuel
facilities, and our analysis attempted to account for these factors.
The No RFS Baseline economic analysis for 2026 and 2027 compares
the projected renewable fuel cost with the projected cost for the
fossil fuel it displaces. The comparison is performed at the point that
the renewable fuel is blended with the fossil fuel (generally a fuel
terminal) to assess whether the renewable fuel provides an economic
advantage to blenders. If the renewable fuel is lower cost than the
fossil fuel it displaces, it is assumed that the renewable fuel would
be used absent the RFS program (within the constraints described
below). The No RFS Baseline economic analysis that we conducted mirrors
the fuel cost analysis described in section III.D.4 of this preamble,
but there are several differences. The primary difference is that the
No RFS Baseline economic analysis was conducted from the fuels
industry's perspective, asking whether they would find it economically
advantageous to blend renewable fuel into petroleum fuel in the absence
of the RFS program. Conversely, the social cost analysis in section
III.D.4 of this preamble reflects the overall fuel cost impacts on
society at large.\140\ A primary example of a social cost not
considered for the No RFS Baseline economic analysis is the fuel
economy effect due to the lower energy density of the renewable fuel,
as this cost is generally borne by consumers, not the fuels industry.
Other ways that the No RFS Baseline economic analysis is different from
the social cost analysis include:
---------------------------------------------------------------------------
\140\ See section III.D.4 of this preamble and RIA Chapter 10
for descriptions of the social cost analysis.
---------------------------------------------------------------------------
In the context of assessing production costs, we amortized
the capital costs at a higher rate of return more typical for industry
investment instead of the rate of return used for social costs.
We assessed renewable fuel distribution costs to the point
where it is blended into petroleum fuel, not all the way to the point
of use, which is necessary for estimating the fuel economy cost.\141\
---------------------------------------------------------------------------
\141\ For several renewable fuels (e.g., ethanol blended as E10,
biodiesel, and renewable diesel), the fuel economy cost is paid by
the consumer. Because it is the fuels industry (i.e., refiners,
terminals, and retailers) that decides whether to blend renewable
fuels into petroleum fuels, they are only concerned about the
relative cost at the point in which the renewable fuel is blended
into the petroleum fuel, not the costs downstream of that blending
point.
---------------------------------------------------------------------------
While we generally do not account for the fuel economy
disadvantage of most renewable fuels for the No RFS Baseline economic
analysis, the exception is E85 where the lower fuel economy of using
E85 is noticeable to vehicle owners such that they demand a lower price
to make up for this loss of fuel economy. As a result, retailers must
price E85 lower than the primary alternative E10 to account for the
lower energy content of E85 and they must consider this in their
decisions to blend and sell E85.\142\
---------------------------------------------------------------------------
\142\ See RIA Chapter 2 for further discussion of this topic.
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To estimate the relative cost of a renewable fuel compared to the
fossil fuel being displaced, we considered several different cost
components (i.e., production cost, distribution cost, any blending
cost, retail modification costs) together to reflect the relative cost
of each renewable fuel to its respective fossil fuel. We also
considered any applicable Federal or State programs, incentives, or
subsidies that could reduce the apparent blending cost of the renewable
fuel at the terminal, including the 45Z credit. The exact amount of
credit under 45Z is more variable and depends on a range of factors.
However, generally speaking, the amount of credit that fuel producers
are able to claim under 45Z is less than the previous $1 per gallon tax
credits that biodiesel and renewable diesel producers were able to
claim under 40A and 6426.\143\ In the case of higher-level ethanol
blends, the retail cost associated with the equipment or use of
compatible materials needed to enable the sale of these newer fuels is
assumed to be reduced by 75 percent due to the HBIIP program.
---------------------------------------------------------------------------
\143\ See RIA Chapter 1 for a further discussion of the 45Z
credit.
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In addition, there are a number of State programs that create
subsidies for biodiesel and renewable diesel, the largest being offered
by California and Oregon through their LCFS programs.\144\ We accounted
for State and local biodiesel mandates by including their mandated
volume regardless of the economics. Several States offer tax credits
for blending ethanol at 10 percent. Other States offer tax credits for
E85, of which the largest is New York. We are not aware of any State
tax credits or subsidies for E15.\145\ To account for the various State
assumptions, it was necessary to model the cost of using these biofuels
on a State-by-State basis.
---------------------------------------------------------------------------
\144\ At the time the analysis for the No RFS Baseline was
completed, there was insufficient data to project the impacts of
LCFS programs in New Mexico on biofuel consumption in these States
in the absence of the RFS program.
\145\ In light of the fluid situation with respect to a 1-psi
RVP waiver for E15 or actions to remove the 1-psi waiver for E10 in
seven Midwestern States, our analysis did not specifically assume
either of these potential changes. These assumptions can affect the
relative cost of E15; however, adopting these assumptions would not
have impacted the overall conclusions with respect to blending E15
in the absence of the RFS program.
---------------------------------------------------------------------------
For most renewable fuels, the economic analysis provided consistent
results, indicating that they are either economical in all years or are
not economical in any year. However, this was not true for biodiesel
and renewable diesel, where the results varied from year to year. Such
swings in the economic attractiveness of biodiesel and renewable diesel
confound efforts on the part of investors to project future returns on
their investments to determine whether to continue to operate their
facilities or shut down. Thus, to smooth out the swings in the
economics for using biodiesel and renewable diesel and look at it the
way facility operators and their investors would do in the absence of
the RFS
[[Page 16417]]
program, we made two key assumptions. First, the economics for
biodiesel and renewable diesel were modeled starting in 2009 and the
trend in their use was made dependent on the relative economics in
comparison to petroleum diesel over distinct four-year periods. As a
result, the first four-year period modeled the costs over 2009-2012 to
estimate the volume of biodiesel and renewable diesel that would be
used in 2012 in the absence of the RFS program. Second, the estimated
biodiesel and renewable diesel volumes were limited in the analysis to
no greater volume than what occurred under the RFS program in any year,
since the existence of the RFS program would be expected to create a
much greater incentive for using these fuels than if the RFS program
was not in place.
We also conducted an analysis for cellulosic biofuels, focusing
primarily on renewable CNG/LNG and CKF ethanol. We found that renewable
CNG/LNG is more expensive than fossil natural gas and, without targeted
incentives and given competing demand in other sectors, would see
little transportation use. However, because California, Oregon, and
Washington do have State-level biofuels programs that incentivize CNG/
LNG in transportation, we assumed these programs would support some use
even without the RFS program. To estimate that future level of use, we
analyzed each State's program data and extrapolated trends through
2027. Additionally, CKF ethanol is eligible for additional incentives
through programs such as California's LCFS program, so we expect CKF
ethanol will continue to be produced at the volumes determined in this
rule even in the absence of the RFS program. The No RFS Baseline for
2026 and 2027 is summarized in Table III.B.1-1.\146\ More details on
the No RFS Baseline can be found in RIA Chapter 2.
---------------------------------------------------------------------------
\146\ See RIA Chapter 2 for a more complete description of the
No RFS Baseline and its derivation.>
\147\ Since E85 is borderline economical in California in the No
RFS Baseline when we do not assume any increase in California's LCFS
credit, a likely increase in the LCFS credit under the No RFS
Baseline increases the certainty that E85 would be economic.
Additionally, we did not consider the possibility that cellulosic
ethanol, which receives a larger LCFS credit, could be used to
produce E85 and may be more economical than corn ethanol.
[GRAPHIC] [TIFF OMITTED] TR01AP26.048
Our analysis shows that conventional ethanol is economical to use
in 10 percent blends (E10) without the presence of the RFS program.
Conversely, higher-level ethanol blends are only partially economical
without the RFS program. E85 is economical in 2026 and 2027 in
California; thus, we assumed that E85 would be consumed in California
without the RFS program.\147\ Conversely, E15 is not economical without
the RFS program due to the relatively low sales volumes per station and
high cost associated with the equipment needed to be installed at
retail stations, even if these costs are partially subsidized by
government funding, and the lack of octane blending value. Some volume
of biodiesel is estimated to be blended based on State mandates in the
absence of the RFS program, and some additional volume of both
biodiesel and renewable diesel is estimated to be economical to use
without the RFS program, particularly in California and Oregon due to
the LCFS incentives. The volumes of renewable CNG/LNG and imported
sugarcane ethanol are projected to be consumed in States with an LCFS
program due to the economic support provided by their programs.
2. 2025 Baseline
The applicable volume requirements established for one year under
the RFS program do not roll over automatically to the next, nor do the
volume requirements that apply in one year become the default volume
requirements for the following year in the event that no volume
requirements are set for that following year. Nevertheless, the volume
requirements established for the previous year represent the most
recent set of volume requirements that the market was required to meet
and are indicative of current market conditions.
Since the previous year's volume requirements represent the
starting point for any adjustments that the market may need to make to
meet the next year's volume requirements, they represent another
informational baseline for comparison. For this reason, in previous RFS
annual standard-setting rulemakings we used previous year's standards
as a baseline against which to compare the projected impacts of the
volume requirements and are also doing so here in addition to the No
RFS Baseline for some of the factors (e.g., the cost of this action).
In the Set 2 proposal, we estimated a 2025 baseline using the
analysis performed in the Set 1 Rule. We considered using 2025 partial-
year data for the 2025 Baseline in the Set 2 proposal, but we instead
continued to rely on the Set 1 Rule analysis. In this final rule, we
now have data from EMTS on the actual production and use of renewable
fuel in the U.S. in 2025. In this final rule we have revised and
updated the 2025 Baseline using this data, such that the 2025 Baseline
reflects the actual production and use of biofuels in 2025 rather than
the projected volumes from the Set 1 Rule. In some cases (such as the
feedstocks used to produce biodiesel and renewable diesel) we have
supplemented the data collected by EMTS with other data sources.
Our estimates of the actual use of qualifying biofuels in 2025 are
shown in Table III.B.2-1. More details on the 2025 Baseline can be
found in RIA Chapter 2.
[[Page 16418]]
[GRAPHIC] [TIFF OMITTED] TR01AP26.049
C. Volume Changes Analyzed
In general, our analyses of the impacts of this rule were based on
the differences between the No RFS Baseline and the Analyzed Volumes
(i.e., our assessment of how the market would respond to the Analyzed
Volumes were they to become the final volume requirements). Those
differences are shown in Table III.C-1.\148\ Because this approach is
squarely focused on the differences in volumes between the No RFS
Baseline and the Analyzed Volumes, our analyses do not assess impacts
from total renewable fuel use in the U.S. As noted above, we also
consider the impacts of the Analyzed Volumes relative to the 2025
Baseline for some of our analyses. The changes in renewable fuel
consumption relative to the 2025 Baseline are shown in Table III.C-2.
---------------------------------------------------------------------------
\148\ See RIA Chapter 2 for more details of this assessment,
including a more precise breakout of those differences.
\149\ A full description of the analysis for all factors is
provided in the RIA.
[GRAPHIC] [TIFF OMITTED] TR01AP26.050
[GRAPHIC] [TIFF OMITTED] TR01AP26.051
D. Summary of the Assessed Impacts of the Analyzed Volumes
As described in section II.B of this preamble, the statute
specifies a number of factors that the EPA must analyze in making a
determination of the appropriate volume requirements to establish for
years after 2022 (and for BBD, years after 2012).\149\ In this section,
we provide a summary of the analysis of a selection of factors,
including employment, rural economic development, energy security,
climate change, costs, environmental impacts, and various other
economic impacts, for the Analyzed Volumes, along with some
implications of those analyses. We provide a summary of our
consideration of all factors in determining the final volume
requirements in section III.E of this preamble.
We received numerous comments on the analyses of statutory factors
presented in the proposal. In some cases, we have updated our analyses
to incorporate feedback provided by commenters (e.g., climate change,
prices of agricultural commodities). Changes in methodology relative to
the Set 2 proposal are described in the sections below and in the
corresponding RIA Chapters. Other comments not addressed in those
sections are addressed in the Response to Comment document in the
docket for this rule.
It was not always possible to precisely identify the implications
of the analysis of a specific factor for a specific component category
of renewable fuel. For instance, while we analyzed the impact of
biodiesel and renewable diesel on the cost to consumers of
transportation fuel (section III.D.4 of this preamble), biodiesel and
renewable diesel can be used to satisfy multiple biofuel requirements
(e.g., BBD, advanced biofuel, and total renewable fuel) and this
analysis therefore does not apply to a single standard in that regard.
Additionally, air quality impacts are driven primarily by biofuel type
(e.g., ethanol, biodiesel) rather than by biofuel category (e.g.,
advanced biofuel,
[[Page 16419]]
cellulosic biofuel), and energy security impacts are driven by the
amount of fossil fuel energy displaced. In these cases, we have
analyzed one or more of the standards collectively rather than
individually.
Moreover, except for CAA section 211(o)(2)(ii)(III), the statute
does not require that the requisite analyses be specific to each
category of renewable fuel. Rather, the statute directs the EPA to
analyze certain factors, without specifying how that analysis must be
conducted. In addition, the statute directs the EPA to analyze the
``program'' and the impacts of ``renewable fuels'' generally, further
indicating that Congress intended to provide flexibility regarding how
and at what level of specificity to analyze the statutory factors.\150\
---------------------------------------------------------------------------
\150\ See CBD, 141 F.4th at 171 (``The text of the CAA does not
require EPA to monetize or otherwise quantify all of the factors it
must consider[.]'').
---------------------------------------------------------------------------
1. Job Creation and Rural Economic Development
In this section, we summarize our estimates of the impacts
(relative to the No RFS Baseline) of the Analyzed Volumes on economy-
wide employment and rural economic development. These estimates include
direct, indirect, and induced impacts for both job creation and rural
economic development and are presented in Table III.D.1-1. More details
on these analyses can be found in RIA Chapter 9.
We apply two analytical approaches common in the literature--the
``rule-of-thumb'' approach and, where feasible, input-output (IO)
modeling. The rule-of-thumb approach uses employment and economic
development impact estimates from previous studies, expressed in jobs
and GDP per unit of biofuel production, and multiplies these estimated
impacts by the Analyzed Volumes to arrive at employment and GDP
estimates. This approach is taken to produce estimates for the impacts
of the quantities of ethanol, BBD, and RNG in the Analyzed Volumes
relative to the No RFS Baseline.
The IO modeling approach relies on the use of a methodology
developed specifically for analysis of dry mill corn ethanol. Using the
results from this IO analysis we have developed ranges of potential
impacts from the projected corn ethanol volumes based on uncertainty
regarding how the volumes will be provided. For example, volumes of
corn ethanol associated with new production capacity would also be
associated with some number of temporary construction jobs, while
expanded capacity utilization at existing dry mill corn ethanol
facilities would not. These ranges of potential impacts are summarized
in tables in RIA Chapter 9 along with detailed explanations of the
associated methodology. Similar IO modeling methods were not readily
available to estimate impacts from other types of ethanol, BBD or RNG,
so we have not attempted to do so.
We estimate that all three categories of renewable fuel we
analyzed--ethanol, BBD, and RNG--are associated with increases in jobs
to varying degrees. BBD is projected to have the highest job creation
impact overall, primarily due to substantially higher projected fuel
volume increases relative to the No RFS Baseline. In terms of rural
employment specifically, ethanol has the highest direct and total
effects per million gallons of ethanol equivalent. Relative to the No
RFS Baseline and accounting for direct, indirect, and induced effects,
BBD is projected to have the highest impact on agricultural employment,
again primarily due to substantially higher projected fuel volume
increases due to the 2026 and 2027 standards relative to the No RFS
Baseline.
We also estimate that ethanol, BBD, and RNG are all associated with
increased rural economic development, again to varying degrees. Since
renewable fuels rely on agricultural feedstocks, we use the GDP impacts
associated with agricultural feedstocks to infer the effects on rural
economic development. We estimate that BBD and ethanol have higher
impacts per million gallons of ethanol equivalent on rural economic
development than does RNG. Relative to the No RFS Baseline and
accounting for direct, indirect, and induced effects, BBD is projected
to have the highest impact on rural economic development, again
primarily due to substantially higher projected fuel volume increases
due to the 2026 and 2027 standards relative to the No RFS Baseline.
Table III.D.1-1 summarizes the estimated economy-wide employment
impacts, expressed in terms of full-time equivalent jobs, and rural
economic development impacts, expressed in terms of rural GDP in 2024$
associated with the Analyzed Volumes of ethanol, BBD, and RNG.\151\
---------------------------------------------------------------------------
\151\ More detail on our estimates of job creation and rural
economic development, including a discussion of the limitations of
these estimates, can be found in RIA Chapter 9.1.
[GRAPHIC] [TIFF OMITTED] TR01AP26.052
2. Energy Security
Our analysis shows that the Analyzed Volumes will have a positive
impact on energy security by reducing U.S. reliance on foreign sources
of energy. Monetized energy security impacts of the Analyzed Volumes
are summarized in Table III.D.2-1. Energy security and methods of
quantifying energy security impacts are discussed further below and in
RIA Chapter 6.
[[Page 16420]]
[GRAPHIC] [TIFF OMITTED] TR01AP26.053
Changes in the required volumes of renewable fuels under the RFS
program can significantly impact: (1) the U.S.'s trade in crude oil and
petroleum products, affecting both imports and exports--collectively
referred to as ``net petroleum imports'' and (2) the financial and
energy security risks associated with this oil trade. These changes
directly influence U.S. national energy security. Similarly, the
Analyzed Volumes may alter imports and exports of renewable fuels and
renewable fuel feedstocks, which may also affect U.S. energy security.
Energy security is defined as the continued availability of energy
sources at an acceptable price.\152\ Achieving the separate but related
goal of energy independence involves reducing reliance on foreign
energy imports to minimize their impact on economic, military, or
foreign policies.\153\ A longstanding goal of U.S. energy policy has
been to decrease oil imports, thereby reducing dependency on foreign
oil suppliers.
---------------------------------------------------------------------------
\152\ IEA, ``Energy Security.'' https://www.iea.org/topics/energy-security.
\153\ Greene, David L. ``Measuring Energy Security: Can the
United States Achieve Oil Independence?'' Energy Policy 38, no. 4
(March 7, 2009): 1614-21. https://doi.org/10.1016/j.enpol.2009.01.041.
---------------------------------------------------------------------------
Since the beginning of the RFS2 regulatory program in 2010, the
U.S. has experienced significant changes in its exposure to the global
oil market, with implications for energy security. In 2010, U.S. net
petroleum imports were approximately 9.4 million barrels a day
(MMBD).\154\ Since then, increased domestic production of shale oil and
renewable fuels have shifted the U.S. from a large net petroleum
importer to a net exporter,\155\ with net exports reaching 2.4 MMBD in
2024.\156\ EIA projects continued growth in U.S. net exports of
petroleum, reaching 3.3-3.8 MMBD by 2026 and 2027. Despite this shift,
substantial imports of renewable fuels and feedstocks have been used to
meet RFS obligations in recent years. This trend has implications for
the U.S.'s energy security and independence.
---------------------------------------------------------------------------
\154\ EIA, ``Oil imports and exports,'' Oil and petroleum
products explained, January 19, 2024. https://www.eia.gov/energyexplained/oil-and-petroleum-products/imports-and-exports.php.
\155\ Id.
\156\ EIA, AEO2025, Table 11--Petroleum and Other Liquids Supply
and Disposition.
---------------------------------------------------------------------------
Even with the long-term shift in U.S.'s net petroleum trade
position, energy security risks persist due to three main factors.
First, even as a net exporter, the U.S. economy can be adversely
affected by energy price shocks. Both crude oil and renewable fuels are
globally traded commodities, making global price and supply shocks an
ongoing concern even from a relatively comfortable national net trade
position. Second, many U.S. refineries depend heavily on imported heavy
crude oil, making them susceptible to international supply disruptions.
In 2024, gross petroleum imports were about 8.4 MMBD.\157\ Likewise,
the U.S. has experienced period of elevated imports of BBD feedstocks
in recent years (see Figure III.A.2.b.ii-2). Third, oil exporters with
a large share of global production can alter global oil prices through
the Organization of Petroleum Exporting Countries (OPEC) by affecting
oil supply relative to demand. These factors contribute to the
vulnerability of the U.S. economy to fuel supply shocks and price
spikes, despite EIA's projections of continued net petroleum exports
through 2026 and 2027.
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\157\ EIA, ``U.S. Supply and Disposition,'' Petroleum & Other
Liquids, May 30, 2025. https://www.eia.gov/dnav/pet/pet_sum_snd_d_nus_mbblpd_a_cur.htm.
---------------------------------------------------------------------------
The EPA collaborates with Oak Ridge National Laboratory (ORNL) to
assess the energy security implications of reduced net petroleum
imports and exposure to global oil markets. ORNL has developed
methodologies to evaluate social costs and energy security impacts of
oil imports. This approach estimates two distinct impacts of importing
petroleum in addition to the purchase price of petroleum itself: (1)
the risk of reductions in U.S. economic output and disruption to the
U.S. economy caused by sudden disruptions in the supply of imported oil
to the U.S. (i.e., macroeconomic disruption/adjustment costs); and (2)
the impacts that a change in U.S. net oil imports have on overall U.S.
oil demand and subsequent changes in the world oil price (i.e., the
``demand'' or ``monopsony'' impacts).\158\ Consistent with previous RFS
rulemakings, we consider demand impacts to be transfer payments and
exclude them from estimated monetized social benefits of the Analyzed
Volumes.\159\ However, the economy-wide benefits of avoiding
macroeconomic disruption costs (estimated using ORNL's methodology) are
societal benefits, which we label ``macroeconomic oil security
premiums.'' For this final rule, the EPA and ORNL have developed
estimates of these premiums based upon recent energy security
literature and oil price projections and energy market and economic
trends from AEO2025.\160\
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\158\ Monopsony impacts stem from changes in the demand for
imported oil, which changes the price of all imported oil.
\159\ See RIA Chapter 6.4.2 for more discussion of our
assessment of monopsony impacts of this action. Also, for a
discussion of monopsony oil security premiums, see, e.g., EPA,
``Revised 2023 and Later Model Year Light Duty Vehicle GHG Emissions
Standards: Regulatory Impact Analysis,'' EPA-420-R-21-028, December
2021, Section 3.2.5.
\160\ See RIA Chapter 6.4.2 for how the macroeconomic oil
security premiums have been updated based upon a review of recent
energy security literature on this topic.
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To calculate the energy security benefits of the Analyzed Volumes,
ORNL's macroeconomic oil security premiums are combined with estimates
of annual reductions in net U.S. petroleum imports due to renewable
fuel volume changes.\161\ Table III.D.2-1 presents the macroeconomic
oil security premiums and the total energy security benefits for the
Analyzed Volumes. The average macroeconomic oil security premiums are
estimated to be $3.69 per barrel in 2026 to $3.67 per barrel in 2027.
Because there is uncertainty associated with these estimates, we also
present confidence intervals in the table. In terms of cents per
gallon, the macroeconomic oil security premiums are estimated to be
0.088[cent] per gallon in 2026 and 0.087[cent] per gallon in 2027.
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\161\ See RIA Chapter 6.4.1 for a discussion of the methodology
used to estimate changes in U.S. annual net petroleum imports from
the Analyzed Volumes.
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[[Page 16421]]
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3. Climate Change
CAA section 211(o)(2)(B)(ii) provides that when determining the
applicable volumes of each renewable fuel category after the year 2022,
the EPA shall include as part of its review ``an analysis of . . . the
impact of the production and use of renewable fuels on the environment,
including on . . . climate change.'' The statute does not define the
term ``climate change'' and expressly provides that regulations issued
pursuant to the RFS provisions shall not impact the regulatory status
of any GHG under any other provision of the CAA.\162\
---------------------------------------------------------------------------
\162\ CAA section 211(o)(12).
---------------------------------------------------------------------------
Although the uncertainty inherent in our analysis does not allow us
to determine whether these regulations would have a material impact on
climate change, the EPA is providing the GHG emission amounts for the
Analyzed Volumes for 2026 and 2027. As such, we have undertaken an
assessment of the GHG emission changes of the Analyzed Volumes for 2026
and 2027 relative to the No RFS Baseline. Several commenters stated
that we should consider estimates based on the Greenhouse gases,
Regulated Emissions, and Energy use in Technologies (GREET) and Global
Trade Analysis Project-Biofuels (GTAP-BIO) models in the climate change
analysis. We agree; our climate change analysis of the Analyzed Volumes
includes additional estimates based on these models, alongside
estimates based on the Global Change Analysis Model (GCAM) and Global
Biosphere Management Model (GLOBIOM) models presented in the proposal.
More details on this analysis can be found in RIA Chapter 5.
Our analysis of the effects of the Analyzed Volumes on climate
change includes three estimates of potential changes in GHG emissions.
In terms of average annual CO2e emissions through 2055,
these three estimates are: (1) a 1 million metric ton increase; (2) a
17 million metric ton decrease; and (3) a 31 million metric ton
decrease. Two of these estimates show the potential for reductions in
GHG emissions relative to the assessed No RFS Baseline, while one
estimate shows a comparatively much smaller increase in GHG emissions.
As illustrated by the wide range of estimates, modeling of GHG
emissions impacts of biofuel use is inherently uncertain, especially
over the multiple decade-long analytical timeframe used for these
estimates. Additionally, while we consider the impacts on climate
change as required by statute, the range of potential GHG emission
reductions, when coupled with additional uncertainties involved in
commonly used climate change end points, makes it difficult to quantify
potential climate change impacts such as changes in global temperature.
However, our assessment of the Analyzed Volumes shows the potential for
net GHG emissions reductions in the majority of our estimates over that
time period but does not conclude such reductions are likely to result
in a material difference in commonly evaluated ``climate endpoints.''
In past rulemakings for the RFS program, the EPA has considered this
factor by using ``lifecycle GHG emissions estimates as a proxy for
climate change impacts.'' \163\ The analytical approach we are taking
in this final rule is similar in that we are providing GHG emissions as
a proxy; this factor is one of many Congress instructed the EPA to
consider when setting volumes, and we have considered it in a
transparent and reasonable manner.
---------------------------------------------------------------------------
\163\ See, e.g., 88 FR 44468, 44500 (July 12, 2023).
---------------------------------------------------------------------------
Scenarios included in the climate change analysis estimate
cumulative GHG emissions impacts for a 30-year analytical scenario
duration.\164\ Cumulative emissions impact estimates for this 30-year
analytical time period are presented in Table III.D.3-1. We present
three separate estimates of these emissions, two of which estimate
emissions reductions associated with the Analyzed Volumes. See RIA
Chapter 5 for further information.
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\164\ See RIA Chapter 5.2 for the EPA's explanation regarding
why the Agency has not monetized the GHG emissions impacts of this
rule.
[GRAPHIC] [TIFF OMITTED] TR01AP26.055
[[Page 16422]]
4. Fuel Costs
This section provides a brief discussion of the methodology used to
estimate the cost impacts for the renewable fuels expected to be
produced and consumed for the Analyzed Volumes and summarizes the
estimated costs.
The cost analysis compared the cost of biofuels attributable to the
RFS program to the cost of the fossil fuels they displace. The net
estimated fuel cost impacts are social costs, excluding any subsidies
and transfer payments. The fuel cost of each biofuel estimated to be
consumed and of each fossil fuel being displaced as a result can be
divided into various subcomponents:
Production cost: feedstock cost is usually the most
prominent factor, though production processing costs are also
significant for some fuels.
Distribution cost: because a given biofuel often has a
different energy density than the petroleum fuel it is replacing, the
distribution costs are estimated all the way to the point of use to
capture the full fuel economy effect of using these fuels.
Blending value: in the case of ethanol blended as E10,
there is a blending value that mostly accounts for ethanol's octane
value realized by lower gasoline production costs, but also a
volatility cost that accounts for ethanol's blending volatility in RVP-
controlled gasoline.
Retail infrastructure cost: in the case of higher-level
ethanol blends, there is a retail cost since retail stations usually
need to add equipment or use compatible materials to enable the sale of
these newer fuels.
Fuel economy cost: different fuels have different energy
content, leading to different cost levels of fuel economy, which
impacts the relative fossil fuel volume being displaced and the cost to
the consumer.
We added these various cost components together as appropriate for
each renewable fuel to reflect the cost of that fuel. We conducted a
similar cost estimate for the fossil fuels being displaced since their
relative cost to biofuels is used to estimate the net cost of the
increased use of biofuels. Unlike for biofuels, however, we did not
calculate production costs for the fossil fuels since their production
costs are inherent in the wholesale price projections provided in
AEO2025.\165\
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\165\ Estimating production costs for renewable fuels facilities
is possible because the plants are generally single purpose
production processes producing a predictable, limited array of
feedstocks into products, while petroleum refineries are each
configured differently and each is refining a different mix of
feedstocks of varying quality and each refinery is producing a
unique number and volume of products.
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As described in section III.A.2 of this preamble, the Analyzed
Volumes of biodiesel and renewable diesel reflect large year-over-year
increases relative to current volumes; thus, we anticipate higher
biodiesel and renewable diesel prices as the industry increases
production to meet the volume requirements. Higher demand for biodiesel
and renewable diesel feedstocks is projected to result in higher
vegetable oil prices, which have a first order impact on costs. We have
considered the impact of increased demand for vegetable oils used to
produce biofuels in our assessment of fuel costs and the fuel price
impacts for this final rule. This represents a change from our analysis
for the Set 2 proposal, which used a static vegetable oil price for our
projection of fuel costs and fuel price impacts.
Our vegetable oil price projection is based on a vegetable oil
modeling study for how increased vegetable oil demand for biofuel use
would impact its price. Based on this study, we project that soybean
oil will rise into the $0.60 per pound range, with FOG and corn oil
priced somewhat lower. This is different from the analysis conducted
for the Set 2 proposal, which assumed that vegetable oil prices would
continue at the projected USDA price for 2026 and 2027. The higher
projected BBD feedstock prices, along with lower projected crude oil
prices, are the principal reasons for the higher estimated costs of
this final rule compared to the cost analysis in the Set 2 proposal.
There is uncertainty in projecting soybean oil prices, the market
of which is also associated with, and affected by, the markets for
whole soybeans, soybean meal, and soybean oil consumed in foods, as
well as the markets for other vegetable oils. To provide an upper- and
lower-bound on estimated costs at higher and lower vegetable oil
prices, we estimate costs based on higher (approximately $0.80 per
pound) and lower (USDA projected) soybean oil prices. Modeling USDA
projected soybean oil prices (approximately $0.40 per pound) for the
Analyzed Volumes aims to capture the costs presuming that the
agricultural market will at some point stabilize at a lower price point
consistent with current USDA projections. Because of the large increase
in biodiesel and renewable diesel volumes over the baseline volumes, we
can attribute a cost for the price increase not just to the new
incremental volume increase, but to all biodiesel and renewable diesel,
including that in the baseline. Thus, the prices projected in the
Analyzed Volumes case are higher than the prices projected in the No
RFS Baseline case and this substantially increases the estimated cost
of the RFS program. Over time, though, the market is expected to
restabilize at lower prices. Consistent with previous analyses, we also
estimate costs at the primary, high, and low vegetable oil price
estimates relative to the 2025 Baseline.
The estimated fuel costs for the Analyzed Volumes based on the
middle estimate of vegetable oil prices and relative to both the No RFS
and 2025 Baselines are presented in Tables III.D.4-1 and 2.\166\ Table
III.D.4-3 discounts the costs in 2027 to 2026 and adds them to the
costs incurred in 2026 to provide a single cost estimate for the 2026
and 2027 standards.
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\166\ More detailed information on the costs for the Analyzed
Volumes is available in RIA Chapter 10.4.2.
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[[Page 16423]]
[GRAPHIC] [TIFF OMITTED] TR01AP26.056
[GRAPHIC] [TIFF OMITTED] TR01AP26.057
[GRAPHIC] [TIFF OMITTED] TR01AP26.058
The biofuel costs are generally higher than the costs of the
gasoline, diesel, and natural gas that they displace as evidenced by
the increases in fuel costs shown in Table III.D.4-1 through 3.\167\ As
described more fully in RIA Chapter 10, our assessment of costs did not
yield a specific threshold value below which the incremental costs of
biofuels are reasonable and above which they are not. Given the
significant inherent uncertainty in both the crude oil and agricultural
feedstock price forecasts, any attempt to identify such a threshold
value is extremely difficult. Nevertheless, throughout section III of
this preamble we consider the directional cost inferences along with
the other factors that we analyzed in the context of our discussion of
the Analyzed Volumes for 2026 and 2027.
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\167\ Natural gas shows a cost savings despite the fact that RNG
is more expensive than fossil natural gas. This is because the
Analyzed Volume for cellulosic biofuel is estimated to cause a
smaller RNG volume in 2026 and 2027 compared to either the No RFS
Baseline or the 2025 Baseline.
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The fuel cost estimates for the high and low vegetable oil prices
relative to the No RFS Baseline, and fuel costs relative to the 2025
Baseline, along with a more detailed discussion of the cost analysis,
are summarized in RIA Chapter 10.
5. Cost to Transport Goods
We also estimated the impact of the Analyzed Volumes on the cost to
transport goods. However, we do not include these estimates in our
social cost analysis because the fuel prices used to form these
estimates include a number of other factors, such as RIN value and
Federal incentives. Because these factors are economic transfers and
are not separable from the non-transfer components of the cost to
transport goods, it would not be appropriate to include the overall
estimates of these impacts in our social cost estimates.
To estimate price impacts, the per-unit costs from Table III.D.4-2
are adjusted to reflect RIN price impacts and account for the 45Z
credit and other market factors, and the resulting values can be
thought of as retail price impacts. Consistent with our assessment of
the fuels markets, we have assumed that obligated parties pass through
their RIN costs to consumers and that fuel blenders reflect the RIN
value of the renewable fuels in the price of the blended fuels they
sell.\168\ Table III.D.5-1 summarizes the estimated impacts of the
Analyzed Volumes on gasoline and diesel fuel prices at retail when the
costs of each biofuel are amortized over the fossil fuel it displaces.
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\168\ See RIA Chapter 10.5 for more detailed information on our
estimates of the fuel price impacts of this action.
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[[Page 16424]]
[GRAPHIC] [TIFF OMITTED] TR01AP26.059
For estimating the cost to transport goods, we focus on the impact
on diesel fuel prices since trucks that transport goods are normally
fueled by diesel fuel. Reviewing the data in Table III.D.5-1, the
largest projected price increase is $0.223 per gallon for diesel fuel
in 2027 relative to the No RFS Baseline.
The impact of fuel price increases on the price of goods overall
can be estimated based on a USDA study that analyzed the impact of fuel
prices on the wholesale price of produce.\169\ Applying the price
correlation from the USDA study indicates that the $0.223 per gallon
diesel fuel cost increase raises retail diesel fuel prices by about 6
percent, which would then increase the wholesale price of produce by
about 1.5 percent. If produce being transported by a diesel truck costs
$3 per pound, the increase in that product's price would be $0.045 per
pound.\170\ If the estimated price impacts are averaged over the
combined gasoline and diesel fuel pool, the impact on produce prices
would be proportionally lower based on the lower per-gallon cost.
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\169\ USDA, ``How Transportation Costs Affect Fresh Fruit and
Vegetable Prices,'' Economic Research Report 160, November 2013.
\170\ Coupons.com, ``Comparing Prices on Groceries,'' May 4,
2021.
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6. Conversion of Natural Lands, Water, Soil, and Ecosystem Impacts
Increases in volumes attributable to the Analyzed Volumes could
lead to potential increases in agricultural land conversion to produce
biofuel feedstocks. Such land use changes could subsequently contribute
to negative impacts to water and soil quality, water quantity, and
ecosystems and wildlife habitat. This is discussed further in RIA
Chapters 4.2 through 4.5.
7. Infrastructure
We evaluated the Analyzed Volumes and how they may impact the
existing renewable fuels infrastructure required for product
distribution. This includes whether the current infrastructure system
is sufficient to accommodate the increases in the Analyzed Volumes and
potential changes that could occur with increases in renewable fuel
production and use. Based on our analysis, we project that the Analyzed
Volumes would be compatible with existing infrastructure and that the
supply of these fuels will not adversely impact the infrastructure
required for product distribution. A more detailed summary of this
analysis can be found in RIA Chapter 8.
8. Commodity Supply
We project that the supply of commodities used for biofuel
production for the Analyzed Volumes, such as corn and soybeans, will
continue to increase in future years primarily due to yield increases,
consistent with historic trends. It is possible that increasing demand
for biofuel feedstocks such as soybean oil will divert these feedstocks
from other markets; however, we project that substitute feedstocks will
be available to markets that previously used soybean oil diverted to
biofuel production. See RIA Chapter 9.2 for more detail on our analysis
of the impact of biofuel production on the supply of commodities.
9. Air Quality
We expect some localized increases in some emissions due to the
Analyzed Volumes, particularly at locations near biofuel production and
transport routes. Overall, considering end use, transport, and
production, emission changes are expected to have variable impacts on
ambient concentrations of emitted gases in specific locations across
the U.S. Air quality impacts are discussed further in RIA Chapter 4.1.
10. Food and Commodity Prices
Our analysis indicates that the Analyzed Volumes have the potential
to affect the prices of agricultural commodities and food prices. Corn
price impacts are estimated using a literature-based elasticity of 3
percent per additional billion gallons of corn ethanol, applied to the
difference between the Analyzed Volumes and the No RFS Baseline. Our
analysis for soybean oil and meal uses a linear equilibrium
displacement model from the literature, which maps biofuel demand
shocks to commodity prices. Specifically, a 20 percent increase in
soybean oil demand for biofuel corresponds to an 8.17 percent increase
in the soybean oil price. We then quantify 2026 and 2027 price impacts
for the Analyzed Volumes relative to the No RFS Baseline. We also
assess grain sorghum, barley, oats, and distillers grains using
historical price relationships with corn and find only small impacts.
Combining these commodity price changes with forecasts of commodity use
for food production suggests modest effects on total food expenditures,
given that commodity costs represent a small share of retail food
prices. A summary of the estimated impacts is provided in Table
III.D.10-1, and further discussion can be found in RIA Chapters 9.3 and
9.4.
[[Page 16425]]
[GRAPHIC] [TIFF OMITTED] TR01AP26.060
E. Volume Requirements for 2026 and 2027
Our review of the history of the RFS program to date and assessment
of the impact of the Analyzed Volumes on the statutory factors, some of
which are described briefly in section III.D of this preamble, provide
the basis for the volumes we are finalizing in this action for 2026 and
2027. While we do not separately discuss each of the statutory factors
for each component category in section III.D of this preamble, we have
analyzed all the statutory factors in the RIA. Determining the
appropriate volumes for 2026 and 2027 requires that we balance these
factors, a task complicated by the fact that higher volumes of
renewable fuel production and use are projected to impact some of the
statutory factors positively and others negatively. Further, some of
the impacts we are directed to consider have varying impacts on
different stakeholders. As discussed in section II.B of this preamble,
Congress provided the EPA flexibility by enumerating factors that we
must consider without mandating any particular forms of analysis or
specifying how we must weigh the various factors against one
another.\171\ The following sections describe our consideration of our
review of the implementation of the RFS program to date and the
statutory factors to determine the appropriate volumes for 2026 and
2027.
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\171\ See CBD at 171-172.
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1. Cellulosic Biofuel
In EISA, Congress set increasing targets for cellulosic biofuel,
aiming to reach 16 billion gallons by 2022.\172\ After 2015, all growth
in the mandated total renewable fuel volume was designated for advanced
biofuels, with the majority of that growth focused on cellulosic
biofuels.\173\ This indicates that Congress intended the RFS program to
strongly incentivize cellulosic biofuels, placing a particular emphasis
on their development after 2015. While cellulosic biofuel production
has not reached the levels envisioned by Congress in 2007, we remain
committed to supporting the advancement and commercialization of these
fuels. As described in section III.A.1 of this preamble, the Analyzed
Volume for cellulosic biofuel project growth in cellulosic biofuel
production and transportation use through 2027, while accounting for
potential constraints on both. We evaluated these volumes using
additional statutory factors. The results of these evaluations are
summarized here and detailed further in the RIA.
---------------------------------------------------------------------------
\172\ CAA section 211(o)(2)(B)(i)(III).
\173\ CAA section 211(o)(2)(B)(i).
---------------------------------------------------------------------------
Our analysis of the statutory factors, summarized here and
discussed in greater detail in the RIA, shows that cellulosic biofuels
have the potential to provide significant reductions in GHG emissions.
We expect that in 2026 and 2027 the cellulosic biofuel supply will come
mainly from three sources: renewable CNG/LNG produced from landfill
biogas, renewable CNG/LNG produced from agricultural digester biogas,
and CKF ethanol. Renewable CNG/LNG produced from landfill biogas and
agricultural digester biogas is expected to account for the largest
share of total volume. Because both fuel sources recover energy from
waste materials and byproducts of existing processes, they are not
expected to drive significant land-use change. As a result, we project
that producing these fuels will help limit adverse impacts identified
in the statutory factors, including the conversion of wetlands and
other ecosystems, the loss of wildlife habitat, degradation of soil and
water quality, and volatility in food prices and supply. Although we
recognize potential soil and water concerns that could result from
increased production of biogas from manure and agricultural digestors,
the relatively small volumes of these fuels relative to landfill-
sourced biogas suggests these impacts will remain minimal.
Beyond these environmental benefits, cellulosic biofuels deliver
substantial economic and energy security gains. Converting otherwise
unused products into transportation fuel supports jobs and generates
positive economic impacts. However, the combination of growing CNG/LNG
use as transportation fuel and high cellulosic RIN prices, which
refiners typically recover through fuel sales, is expected to increase
gasoline and diesel prices. Despite this increase, strengthening the
cellulosic biofuel market advances statutory goals for energy
independence and security, reduces reliance on foreign fuel sources,
and supports long-term economic resilience.
In summary, our analysis of the statutory factors indicates that
the benefits of increasing cellulosic biofuel volumes outweigh the
potential downsides. We are finalizing cellulosic biofuel volumes for
2026 and 2027 at levels that align with projected growth in the
consumption of CNG/LNG as transportation fuel in these years. These
volumes, based on the most current data at the time of this action,
represent a
[[Page 16426]]
well-informed estimate of the achievable growth in cellulosic biofuel
production during this period. We believe that these volumes will
continue to encourage investment in and development of cellulosic
biofuels while adhering to statutory requirements, including those
under CAA section 211(o)(2)(B)(iv) that the EPA set the cellulosic fuel
volumes such that we do not anticipate a need to lower the requirement
through a waiver under CAA section 211(o)(7)(D). To that end, because
the ``projected volume available'' \174\ equals the analyzed volume, we
are finalizing the cellulosic biofuel volumes at the analyzed level--
i.e., the level to which the EPA would reduce the cellulosic biofuel
requirement if it exercised the cellulosic waiver authority--as shown
in Table III.E.1-1.
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\174\ CAA section 211(o)(7)(D)(i).
[GRAPHIC] [TIFF OMITTED] TR01AP26.061
2. Non-Cellulosic Advanced Biofuel
The volume targets established by Congress through 2022 anticipated
volumes of advanced biofuel beyond what would be needed to satisfy the
cellulosic standard. The statutory target for advanced biofuel in 2022
(21 billion gallons) allowed for up to five billion gallons of non-
cellulosic advanced biofuel to be used towards the advanced biofuel
volume target, with additional quantities of non-cellulosic advanced
biofuel able to contribute towards meeting the total renewable fuel
requirement.\175\ The applicable volumes for 2022 similarly include
five billion RINs of non-cellulosic advanced biofuel.\176\ In the Set 1
Rule, we continued to grow the implied non-cellulosic advanced biofuel
category, which reached 5.95 billion RINs in 2025.\177\
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\175\ CAA section 211(o)(2)(B)(i).
\176\ 87 FR 39600, 39624 (July 1, 2022).
\177\ 88 FR 44468, 44518 (July 12, 2023).
---------------------------------------------------------------------------
The non-cellulosic advanced biofuel volumes in this action reflect
growth rates based on analysis of feedstock availability and production
capacity potential. In this action, we are finalizing volume
requirements that reflect 4.2 and 4.4 billion RIN increases in the
projected supply of non-cellulosic advanced biofuel for 2026 and 2027,
respectively. These increases are relative to the volume of non-
cellulosic advanced biofuel supplied to the U.S. in 2025 based on
available data. Our decision to finalize these volumes is based on our
assessment of the impacts of non-cellulosic advanced biofuels
(primarily biodiesel and renewable diesel) on the statutory factors.
Our assessment of the statutory factors, and how these assessments
support the final non-cellulosic advanced biofuel volumes, are
summarized in the remainder of this section and are discussed in
greater detail in the RIA. Section V.E.3 of this preamble discusses our
consideration of what portion of the non-cellulosic advanced biofuel
volume should be restricted to BBD.
To date, the vast majority of non-cellulosic advanced biofuel in
the RFS program has been biodiesel and renewable diesel, with
relatively small volumes of sugarcane ethanol and other advanced
biofuels. Advanced biodiesel and renewable diesel together accounted
for 95 percent, or more, of the total supply of non-cellulosic advanced
biofuel over the last several years, and this trend is expected to
continue through 2027 due to the limited production and import of other
types of non-cellulosic advanced biofuels.\178\ We therefore focused
our attention on the impacts of these fuels in relation to the
statutory factors in determining appropriate levels of non-cellulosic
advanced biofuel for 2026 and 2027.\179\
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\178\ See RIA Chapters 7.2 through 7.4.
\179\ We have also considered the potential for increasing
volumes of renewable jet fuel. Given its similarity to renewable
diesel, for purposes of projecting appropriate volume requirements
for 2026 and 2027, in most cases we consider renewable jet fuel to
be a component of renewable diesel.
---------------------------------------------------------------------------
As in past RFS rulemakings, our analyses indicate that for some of
the statutory factors the projected impacts of increasing production
and use of biodiesel and renewable diesel are expected to be generally
positive or neutral, while for other factors the impacts are expected
to be generally negative. For some factors, the projected impacts vary
significantly depending on where the fuel is produced (i.e., foreign or
domestic), whether the feedstock used to produce the fuel is a waste or
byproduct (e.g., UCO) or an agricultural commodity (e.g., soybean oil),
and whether it is sourced domestically or imported.
With respect to GHG emission reductions, while there remains
considerable uncertainty as to the GHG emission impacts of non-
cellulosic advanced biofuels (particularly biofuel produced from crop-
based feedstocks) our assessment suggests these fuels have the
potential to provide net GHG emission reductions. Regardless of the
potential resulting impacts to climate change from the reduction in GHG
emissions due to this program, as Congress intended to emphasize lower
GHG-emitting fuels within the RFS program, the potential GHG reductions
suggest that higher non-cellulosic advanced biofuel volumes than those
established by Congress for 2022 (5.0 billion RINs) or established by
the EPA for 2025 (5.95 billion RINs) may be appropriate.
All qualifying biodiesel and renewable diesel is expected to
diversify the transportation fuel supply and thus have a positive
impact on the energy security of the U.S. Similarly, because we project
that a greater percentage of the increase in the supply of biodiesel
and renewable diesel through 2027 will be supplied from domestic
biofuel producers using domestic feedstocks, we expect these fuels to
positively impact employment and rural economic development. We do not
anticipate the availability of infrastructure to distribute or use
biodiesel and renewable diesel will limit the consumption of these
fuels in future years, nor do we anticipate that increasing supplies of
these fuels will negatively impact the deliverability of materials,
goods, and products other than renewable fuel. Together, these
statutory factors further support higher volumes of biodiesel and
renewable diesel in future years.
[[Page 16427]]
Other statutory factors suggest that lower volumes of biodiesel and
renewable diesel may be appropriate. Biodiesel and renewable diesel
have historically had higher costs than the diesel fuel they displace
and are expected to continue to cost more into the future, primarily
due to relatively high feedstock costs. These higher costs are expected
to ultimately be passed through to consumers, resulting in higher costs
for transportation fuel and higher costs to transport goods.\180\
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\180\ This discussion refers to societal costs. We recognize
that with the incentives provided by the RFS program and other State
and local programs, the price for biodiesel and renewable diesel
(net available incentives) may be lower than the price of petroleum
fuels. See RIA Chapter 10 for a further discussion of our cost
estimates.
---------------------------------------------------------------------------
Biodiesel and renewable diesel produced from vegetable oils are
also expected to result in higher prices for these oils and the crops
from which they are derived (e.g., soybeans and canola). These higher
vegetable oil prices are projected to have both positive and negative
impacts. Higher vegetable oil prices are expected to drive increased
investment in the domestic oilseed crushing industry, resulting in
increased employment and economic impact, as well as higher revenue for
feedstock producers. This projected increased investment in domestic
oilseed crushing capacity would reduce domestic oilseed producers
reliance on export markets, as it would increase the capacity for
processing oilseed domestically. Higher vegetable oil prices are,
however, expected to result in higher prices for products that use them
as inputs (e.g., food and feed).
Notably, the projected impacts on some of the statutory factors are
expected to vary depending on the feedstock used to produce biodiesel
or renewable diesel. We have generally assumed that biofuels produced
from FOG feedstocks such as UCO and tallow do not drive the conversion
of land to cropland, increase the intensity of farming practices, or
raise agricultural commodity or food prices.\181\ Because of this
assumption, biofuels produced from FOG are also generally expected to
result in greater GHG emission reductions. However, commodities such as
UCO and tallow now command prices comparable to those of crop-derived
vegetable oils in some cases which makes forecasting which feedstocks
will be economically preferable more difficult than in previous years.
---------------------------------------------------------------------------
\181\ This is particularly true if the feedstocks used to
produce these biofuels would otherwise be landfilled or not
productively used. It is not the case, however, that all feedstocks
assumed to be wastes or byproducts would otherwise be landfilled or
not productively used. For example, UCO and animal fats such as
tallow have historically had a variety of productive uses, include
use as animal feed and use as a feedstock to produce soaps,
detergents, and other oleochemicals. Historically, such demands have
been outstripped significantly by product supply, leading to
unproductive disposal of excess supply in the absence of a
productive use opportunity. However, increasing levels of demand for
these feedstocks for biofuel production could not only fully consume
this previously excess supply, but also result in the diversion of
these feedstocks from existing markets. In turn, markets that
previously used these waste and byproduct feedstocks may seek
alternatives, and any impacts on cropland, GHG emissions, or other
factors that result from the sourcing of these alternative
feedstocks should then be attributable to biofuel production.
---------------------------------------------------------------------------
Increases in domestic sources of FOG feedstocks in future years are
projected to be limited as much of the available feedstocks are already
being used for biofuel production with smaller quantities collected for
other productive uses. Significant volumes of these feedstocks may be
available from foreign countries, though there is significant
uncertainty in the quantities and origin of these feedstocks that will
be available to the U.S. in future years.
Biodiesel and renewable diesel produced from domestic agricultural
commodities such as soybean oil and canola oil are more likely to have
negative impacts on wetlands, wildlife habitat and ecosystems, and
water quality, as demand for these feedstocks can result in increased
conversion of native lands to cropland. This land conversion (whether
land is converted directly to produce biofuel crops or induced through
higher commodity prices) generally results in GHG emissions, and
therefore biofuels produced from these feedstocks may have lifecycle
GHG emission greater than biofuels produced from wastes or
byproducts.\182\ Significant opportunities exist for increasing
domestic production of soybean oil (which would be expected to
positively impact job creation and rural economic development), as well
as imported canola oil from Canada. Generally, agricultural feedstocks
grown in North America are eligible for lower incentives in foreign
biofuel programs compared to waste feedstocks. Consequently, we have
greater confidence in projecting the potential supply of these
feedstocks available for domestic renewable fuel production in future
years.
---------------------------------------------------------------------------
\182\ However, the land use impacts with respect to GHG
emissions may be outweighed by additional transportation GHG
emissions especially if obtained from international sources.
---------------------------------------------------------------------------
Our analysis of the Analyzed Volumes indicated likely differences
in impacts on the statutory factors between growth in the supply of
biodiesel and renewable diesel produced from FOG feedstocks such as UCO
and tallow (the marginal supplies of which are primarily sourced from
foreign countries) and those produced from virgin vegetable oils (the
marginal supplies of which are primarily sourced from the U.S. and
Canada). Thus, the availability and likely use of these feedstocks for
biofuel production and use in the U.S. is a key factor in our
consideration of the Analyzed Volumes of non-cellulosic advanced
biofuel. As discussed in section III.A.2 of this preamble and RIA
Chapter 7, there is relatively less uncertainty in the projected
availability of marginal quantities of vegetable oils than there is in
the projected availability of marginal quantities of FOG. The higher
uncertainty in the projected availability of the waste and byproduct
feedstocks is not only a function of the quantity of these feedstocks
that can be collected globally, but also of demand for these feedstocks
for biofuel production, other productive uses in other countries, and
highly dynamic trading environments. Due to the relatively high
uncertainty in the available supply of FOG and the structure of the 45Z
credit (which is not available to imported biofuels nor, starting in
2026, biofuels produced from feedstocks originating outside of North
America), we project that biofuels produced from domestic feedstocks
are more likely to be used in significant quantities in future years
than imported biofuels and feedstocks, particularly imported feedstocks
originating outside North America.
We have also considered how the increased production of domestic
biodiesel and renewable diesel relates to the statutory factors. As is
typically the case, not all factors are affected positively or
negatively in a uniform fashion by increasing or decreasing domestic
biodiesel and renewable diesel production. However, there are several
statutory factors that have the potential to be positively impacted in
a material way by increasing domestic production of these fuels,
including employment and rural economic development and energy security
impacts. Energy security is bolstered through a further displacement of
fossil fuels by increasing volumes of renewable fuel, a large and
increasing fraction of which will be produced from domestic feedstocks
as we move forward and changes in trade dynamics and tax incentives
(45Z) work through renewable fuel markets.
Employment and rural economic development can be affected very
positively by increasing the domestic production of biodiesel and
renewable
[[Page 16428]]
diesel by more fully utilizing the production assets which have been
underutilized or ceased production in recent years. Our analysis
indicates that significantly higher domestic production of biodiesel
and renewable diesel from existing facilities is possible given the low
utilization rates in 2025 compared to previous years and historical
precedent and that the industry has been able to achieve utilization
rates greater than 90% in past years.\183\
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\183\ See further discussion in RIA Chapter 7.2.
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Increasing the domestic production of non-cellulosic advanced
biofuels would have several positive effects for employment and rural
economic development. Direct effects of increased production would be
increased employment as additional workers would be required to restart
or expand production and increased economic activity for the rural
communities wherein these renewable production facilities are often
located. Increasing domestic production of biodiesel and renewable
diesel is also expected to result in increased investment in domestic
oilseed crushing to supply feedstocks for biofuel production. These
investments would decrease the reliance of domestic soybean producers
on export markets and further benefit rural economic development and
employment. A few second order positive impacts may include: increased
demand for feedstock produced in rural communities, expansion of
associated input and service sector employment related to biofuel and
feedstock production, and potential for either new or expanded biofuel
production capacity in rural communities. In totality, our analysis of
the statutory factors suggests that higher non-cellulosic advanced
biofuel volumes intended to realize higher and historically-precedented
capacity utilization rates are appropriate.
Based on our analyses of all the statutory factors, we are
finalizing volumes for 2026 and 2027 that reflect the Analyzed Volumes
of non-cellulosic advanced biofuel. These volumes were calculated
projecting a 90 percent utilization rate of existing biodiesel and
renewable diesel production capacity (with some growth from 2026 to
2027) and the projected production and import of other advanced
biofuels. These volumes reflect our consideration of the impacts of
these fuels on the statutory factors, including the potential increases
in employment and economic impacts for renewable fuel producers,
feedstocks producers and processors, and the rural communities in which
these facilities are located. These volumes also reflect our
consideration of the impact of these fuels on fuel prices and climate
change, although the potential impacts on climate change are more
uncertain, as discussed previously. The final non-cellulosic advanced
biofuel volume requirements also reflect our assessment of the
available supply of feedstocks used to produce these fuels (including
the uncertainties associated with these projections), the projected
high costs for these fuels relative to the petroleum fuel they
displace, and the potential negative impacts associated with increasing
demand for vegetable oils or diverting feedstocks from existing uses to
biofuel production.
We project that the feedstocks needed to produce the final non-
cellulosic advanced biofuel volume requirements could be supplied
primarily, if not exclusively from domestic sources and imports from
Canada and Mexico. Trade dynamics and changes to the 45Z credit
increase the likelihood that the increase in the supply of non-
cellulosic advanced biofuels through 2027 will be supplied by domestic
biofuel producers using North American feedstocks. Through 2027, we
project that imported renewable fuels and imported feedstocks from
countries other than Canada and Mexico may continue to contribute
towards the total supply of non-cellulosic advanced biofuels, but that
the relative share of these fuels will decrease in future years as
domestic supplies (and the supply of feedstocks from Canada and Mexico)
increase in response to the incentives provided by tax and trade
policy.
We recognize that there are potential negative impacts likely to
result from non-cellulosic advanced biofuel volume requirements that
are too high or too low. If we establish volume requirements for these
fuels that are too low, the market will likely supply lower volumes of
these fuels to the U.S. than could be achieved with higher volume
requirements. This could negatively impact biofuel producers and result
in lower employment, economic impacts, and GHG emission reductions than
could be achieved with higher volume requirements. Conversely, if we
establish volume requirements for these fuels that are too high, the
costs of these fuels would be expected to rise, increasing the prices
of food, fuel, and other goods for consumers. It is also possible that
the market would be unable to supply higher volumes, requiring the EPA
to reduce the volume requirements in the future, undermining the market
stability the RFS program is designed to provide.
Non-cellulosic advanced biofuel is again expected to fill some of
the total renewable fuel volume requirement in excess of the advanced
biofuel requirement. Consistent with the approach taken in the Set 1
Rule, and as discussed in greater detail in section III.E.4 of this
preamble, we are finalizing volume requirements in this action that
reflect an implied conventional renewable fuel requirement of 15
billion gallons in each year. Since we project that the quantity of
conventional renewable fuel available in these years will be limited,
significant volumes of non-ethanol biofuels will be needed to meet the
conventional renewable fuel volume requirement of 15 billion gallons.
We project that the most likely source of non-ethanol biofuel will
be biodiesel and renewable diesel that qualifies as advanced biofuel.
Biodiesel and renewable diesel cannot be used to satisfy the projected
shortfall in conventional renewable fuel if we already require the use
of these fuels to meet the non-cellulosic advanced biofuel volume
requirement. Therefore, the final renewable fuel volumes we are
establishing for 2026 and 2027 reflect non-cellulosic advanced biofuel
volumes equal to the analyzed volumes of these fuels less the volume
projected to be needed to meet the shortfall in the conventional
renewable fuel volume requirement. The final non-cellulosic advanced
biofuel volumes for 2026 and 2027 are summarized in Table III.E.2-1.
[[Page 16429]]
[GRAPHIC] [TIFF OMITTED] TR01AP26.062
3. Biomass-Based Diesel
Because BBD makes up for the vast majority of non-cellulosic
advanced biofuel, we did not separately assess the impacts of BBD on
the statutory factors from those of non-cellulosic advanced biofuels.
Our analysis of the impacts of the Analysis Volumes for BBD can be
found in section III.E.2 of this preamble. In determining the
appropriate BBD volumes for 2026 and 2027, our primary consideration is
how much of the non-cellulosic advanced biofuel volume to reserve
exclusively for BBD based on our review of the implementation of the
RFS program to date and our analysis of the statutory factors. This
approach is consistent with the approach we have taken to establishing
the BBD volume requirements in previous years.
In previous RFS rulemakings, we have adopted an approach of
increasing the BBD volume requirement in concert with the change, if
any, in the implied non-cellulosic advanced biofuel volume
requirement.\184\ This approach provides ongoing support for BBD
producers, while maintaining an opportunity for other advanced biofuels
to compete for market share. In reviewing the implementation of the RFS
program to date, we determined that this approach successfully balanced
a desire to provide support for BBD producers with an increasing
guaranteed market, while at the same time maintaining an opportunity
for other advanced biofuels to compete within the advanced biofuel
category. Our assessment of the impacts of BBD on the statutory factors
is discussed further in the RIA.
---------------------------------------------------------------------------
\184\ See, e.g., 88 FR 44516-17 (July 12, 2023).
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As in recent years, we believe that excess volumes of BBD beyond
the BBD volume requirements will be used to satisfy the advanced
biofuel volume requirement within which the BBD volume requirement is
nested. Historically, the BBD standard has not independently driven the
use of BBD in the market. This is due to the nested nature of the
standards and the competitiveness of BBD relative to other advanced
biofuels. Moreover, BBD use can also be driven by the implied
conventional renewable fuel volume requirement as an alternative to
using increasing volumes of corn ethanol in higher-level ethanol blends
such as E15 and E85. We believe these trends will continue through
2027.
We also believe it is important to maintain space for other
advanced biofuels to participate within the advanced biofuel standard
of the RFS program. Although the BBD industry has matured over the past
decade, the production of advanced biofuels other than biodiesel and
renewable diesel continues to be relatively low and uncertain.
Maintaining this space for other advanced biofuels can in the long-term
facilitate increased commercialization and use of other advanced
biofuels, which may have superior environmental benefits, avoid
concerns with food prices and supply, and have lower costs relative to
BBD. Furthermore, rather than only supporting BBD, the 45Z credit may
support the production and use of North American non-BBD advanced
biofuels as well. Despite the potential impacts of the 45Z credit, we
do not think increasing the size of this space is necessary through
2027 given that only small quantities of these other advanced biofuels
have been used in recent years relative to the space we have provided
for them in those years.
The final BBD volumes represent significant growth from the volumes
established in the Set 1 Rule. At the same time, these volumes preserve
an opportunity for non-cellulosic advanced biofuels other than BBD to
compete for market share within the advanced biofuel category. We are
finalizing BBD volumes that maintain a 600 million RIN opportunity for
non-cellulosic advanced biofuels other than BBD, which is approximately
equal to the opportunity for these fuels from 2023-2025. The final BBD
volumes are shown in Table III.E.3-1.\185\
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\185\ Note that, unlike in previous years, the BBD volume
requirement is expressed in RINs rather than physical gallons. As
discussed in section VIII.C of this preamble, we are making this
change to better align the BBD requirement with the requirements for
the other three categories of renewable fuel, which are expressed in
RINs rather than gallons.
[GRAPHIC] [TIFF OMITTED] TR01AP26.063
[[Page 16430]]
4. Conventional Renewable Fuel
Although Congress had intended cellulosic biofuel to become the
most widely used renewable fuel by 2022,\186\ conventional renewable
fuel has continued to account for the majority of renewable fuel supply
since the RFS program began in 2005. The favorable economics of
blending corn ethanol at 10 percent into gasoline, even without the
incentives created by the RFS program, caused it to quickly saturate
the gasoline supply shortly after the RFS program began.
---------------------------------------------------------------------------
\186\ CAA section 211(o)(2)(B)(i).
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The implied statutory volume target for conventional renewable fuel
rose annually between 2009 and 2015 until it reached 15 billion
gallons, where it remained through 2022.\187\ We have maintained the
implied statutory volume target for conventional renewable fuel at 15
billion gallons since 2022, including in the Set 1 Rule.\188\
---------------------------------------------------------------------------
\187\ Id.
\188\ 88 FR 44517-18 (July 12, 2023).
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As discussed in section III.A.3.a of this preamble, constraints on
ethanol consumption have prevented the volume of ethanol used in
transportation fuel from reaching 15 billion gallons, even with the
incentives provided by the RFS program and after accounting for the
projected increase in the availability of higher-level ethanol blends
such as E15 and E85. Such higher-level ethanol blends are an avenue
through which higher volumes of renewable fuel can be used in the
transportation sector to reduce GHG emissions and improve energy
security over time. Incentives created by the implied conventional
renewable fuel volume requirement contribute to the economic
attractiveness of these fuels. However, we expect the constraints that
currently limit adoption of these blends, and ethanol consumption as a
whole, to continue to exist through 2027. The difficulty in reaching 15
billion gallons with ethanol is compounded by the fact that gasoline
demand for 2026 and 2027 is expected to continue to decline slightly
relative to gasoline demand in 2025.
We do not believe that constraints on ethanol consumption should be
the single determining factor in the appropriate level of conventional
renewable fuel to establish for 2026 and 2027. The implied volume
requirement for conventional renewable fuel is not a requirement for
ethanol, nor even for conventional renewable fuel. Instead,
conventional renewable fuel is the portion of total renewable fuel that
is not required to be advanced biofuel. The implied volume requirement
for conventional renewable fuel can be satisfied by any approved
renewable fuel. Examples of non-ethanol renewable fuels that regularly
contribute to this volume include conventional biodiesel and renewable
diesel, as well as advanced biodiesel and renewable diesel beyond what
is required by the advanced biofuel volume requirement. For these
reasons, we are establishing the appropriate level of conventional
renewable fuel on a broader basis than just the amount of conventional
ethanol likely to be consumed each year.
While this segment of the RFS program creates opportunities for all
approved renewable fuels to contribute, our analyses of several of the
statutory factors, described in more detail in the RIA, also highlights
the importance of ongoing support for corn ethanol generally and for an
implied conventional renewable fuel volume requirement that helps to
incentivize the domestic consumption of corn ethanol. Moreover,
sustained and predictable support of higher-level ethanol blends
through consistent implied conventional renewable fuel volume
requirements helps provide some longer-term incentives for the market
to invest in the infrastructure necessary to expand the availability of
higher-level ethanol blends. The benefits of this approach include
potential increases in employment and economic impact, most notably for
corn farmers, but also positive impacts on ethanol producers and
related ethanol blending and distribution activities. The rural
economies surrounding these industries also benefit from strong demand
for ethanol. Increased demand for higher-level ethanol blends could
also increase employment and economic impact more broadly if retail
station owners respond to the incentives created by the RFS program and
other Federal actions by investing in infrastructure necessary to
increase the availability of higher-level ethanol blends at their
stations. In addition, the consumption of renewable fuels, including
domestically produced ethanol, reduces our reliance on foreign sources
of petroleum imports and increases the energy security status of the
U.S. as noted in section III.D.2 of this preamble.
We are projecting that total ethanol consumption will remain steady
in 2026 and 2027 despite the increase in consumption of E15 and E85, as
discussed in section III.A.3.a of this preamble. At the same time, we
are projecting that sufficient BBD and other non-ethanol advanced
biofuels will be available in 2026 and 2027 to compensate for this
reduction in ethanol consumption and to enable an implied volume
requirement for conventional renewable fuel of 15 billion gallons to be
met. We are thus establishing the implied conventional renewable fuel
volume requirement for 2026 and 2027 at the Analyzed Volumes of 15
billion gallons of conventional biofuel.
[GRAPHIC] [TIFF OMITTED] TR01AP26.064
5. Summary of the Volume Requirements for 2026 and 2027
Sections III.E.1 through 4 of this preamble summarize our holistic
balancing of the statutory factors to determine the appropriate volumes
for each of the component categories of renewable fuel. After
determining the appropriate volumes for each component category, we
calculated the volumes for each of the four statutory renewable fuel
categories. These volumes for 2026 and 2027 are shown in Table III.E.5-
1.
[[Page 16431]]
[GRAPHIC] [TIFF OMITTED] TR01AP26.065
In balancing the factors to arrive at these volumes, we have
recognized that the cost of achieving them is significant, and that
these costs are not offset by benefits that we are able to monetize.
Nevertheless, we believe that these volumes represent a reasonable
balancing of the statutory factors, including those for which we were
unable to provide monetized estimates. In establishing the RFS program,
Congress established ambitious renewable fuel volume requirements
recognizing that the production and use of renewable fuel was often
more costly than using petroleum-based fuels.\189\ The waiver
authorities provided by Congress authorized reductions of the statutory
volumes only when achieving these volumes would cause severe economic
harm.\190\ Further, while Congress required that the EPA evaluate the
impact of the use of renewable fuels on the cost to consumers of
transportation fuel and the cost to transport goods, Congress did not
require that the consideration of these costs outweigh the
consideration of the other statutory factors.\191\ Indeed, the D.C.
Circuit found that ``[n]othing in the Act or precedent supports a
freestanding requirement that EPA balance the quantifiable costs and
benefits of the volumes it sets, let alone that EPA may implement the
RFS Program only insofar as its benefits--quantified or not--outweigh
its costs.'' \192\
---------------------------------------------------------------------------
\189\ The D.C. Circuit has observed that ``Congress in the RFS
Program `made a policy choice to accept higher fuel prices' in
exchange for the benefits of energy security and reduced GHG
emissions.'' CBD, 141 F.4th at 171 (quoting Sinclair, 101 F.4th at
889).
\190\ See generally CAA section 211(o)(7)(A).
\191\ See CAA section 211(o)(2)(B)(ii).
\192\ CBD at 172.
---------------------------------------------------------------------------
While the general approach we are taking to organize our analysis
of the statutory factors is consistent with our approach in the Set 1
Rule, which was upheld by the D.C. Circuit in CBD, we acknowledge that
our balancing of the statutory factors in this rule differs in certain
respects from previous rules.\193\ In the Set 1 Rule, we emphasized the
potential for significant GHG emission reductions, alongside the
projected energy security benefits and support for increasing the
annual rate of future commercial production of renewable fuels, job
creation, and rural economic development, in justifying renewable fuel
volume requirements with high costs.\194\ In this action we continue to
consider all the statutory factors, but, in contrast to previous rules,
we are placing less emphasis on the potential impact of this rule on
climate change while retaining the general practice of using lifecycle
GHG emission reduction estimates as a proxy for this analysis. As
explained previously, the ranges of potential GHG emission reductions
vary widely from substantial net reductions to very slight net
increases. This variability, when coupled with the additional
uncertainties involved in commonly used climate change end points,
makes it difficult to quantify potential climate change impacts such as
changes in global temperature. The potential for net GHG emission
reductions is sufficient to consider the climate change factor Congress
specified as a relevant environmental consideration, particularly in
light of Congress' use of GHG emission reduction thresholds in defining
renewable fuels. On the other hand, we have placed greater emphasis on
the impact of this rule on other statutory criteria: energy security,
job creation, and rural economic development, and have maintained our
intent to increase the annual rate of future commercial production of
renewable fuels. As a result, we have generally sought to establish
volumes that support the domestic production of renewable fuels from
domestic feedstocks. This is most apparent in our approach to
determining the appropriate volumes for non-cellulosic advanced
biofuel. In previous RFS rules our determination of the final volume
requirements for non-cellulosic advanced biofuel was based on estimates
of the quantity of feedstocks available without diverting feedstock
from non-biofuel markets or use in other countries. In this action, the
final volume requirements reflect the domestic production capacity for
non-cellulosic advanced biofuel, consistent with the policy goal of
supporting increased domestic production of these fuels as explained in
section III.A of this preamble.
---------------------------------------------------------------------------
\193\ See FDA v. Wages & White Lion Invs., L.L.C., 604 U.S. 542,
569-570 (2025).
\194\ Additionally, the EPA promulgated the 2020-2022 Rule under
its authority in CAA section 211(o)(7)(F), which directs the EPA to
conduct the statutory factor analysis under CAA section
211(o)(2)(B)(ii). 87 FR 39600 (July 1, 2022). The D.C. Circuit
similarly upheld the EPA's analysis there. See Sinclair v. EPA, 101
F.4th 871, 887 (2024).
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F. Treatment of Carryover RINs
In our assessment of supply-related factors in section III.A of
this preamble, we focused on those factors that could directly or
indirectly impact the use of renewable fuel in the U.S. and thereby
determine the potential number of RINs generated in each year that
could be available for compliance with the applicable standards in
those same years. However, carryover RINs represent another source of
RINs that can be used for compliance. We therefore investigated whether
and to what degree carryover RINs should be considered in the context
of determining appropriate levels for the final volume requirements.
CAA section 211(o)(5) requires that the EPA establish a credit
program as part of its RFS regulations, and that the credits be valid
for obligated parties to show compliance for 12 months as of the date
of generation. We implemented this requirement through the use of RINs,
which are generated for the production of qualifying renewable fuels.
Obligated parties can comply by blending renewable fuels into the
transportation fuel supply themselves, or by purchasing RINs that
represent the renewable fuels that other parties have blended into the
supply. RINs can be used to demonstrate compliance for the year in
which they are generated or the subsequent compliance year. Obligated
parties can obtain more RINs than they need in a given compliance year,
allowing them to ``carry over'' these excess RINs for use in the
subsequent compliance year, although the RFS regulations limit the use
of these carryover RINs to 20 percent of the obligated party's
RVO.\195\ For the collective supply of carryover RINs to be preserved
from one year to the next,
[[Page 16432]]
individual carryover RINs are used for compliance before they expire
and are essentially replaced with newer vintage RINs that are then held
for use in the next year. For example, vintage 2025 carryover RINs must
be used for compliance with 2026 compliance year obligations, or they
will expire. However, using 2025 vintage RINs to meet 2026 compliance
obligations reduces the need to use vintage 2026 RINs, which can then
be saved for use toward 2027 compliance.
---------------------------------------------------------------------------
\195\ 40 CFR 80.1427(a)(5).
---------------------------------------------------------------------------
As noted in past RFS annual rules, carryover RINs are a
foundational element of the design and implementation of the RFS
program.\196\ Carryover RINs play an important role in providing a
liquid and well-functioning RIN market upon which success of the entire
program depends, and in providing obligated parties compliance
flexibility in the face of substantial uncertainties in the
transportation fuel marketplace.\197\ Carryover RINs enable parties
``long'' on RINs to trade them to those ``short'' on RINs, instead of
forcing all obligated parties to comply through physical blending.
Carryover RINs also provide flexibility and reduce spikes in compliance
costs in the face of a variety of unforeseeable circumstances--
including weather-related damage to renewable fuel feedstocks and other
circumstances potentially affecting the production and distribution of
renewable fuel--that could limit the availability of RINs.
---------------------------------------------------------------------------
\196\ See, e.g., 72 FR 23904 (May 1, 2007).
\197\ See 80 FR 77482-87 (December 14, 2015), 81 FR 89754-55
(December 12, 2016), 82 FR 58493-95 (December 12, 2017), 83 FR
63708-10 (December 11, 2018), 85 FR 7016 (February 6, 2020), 87 FR
39600 (July 1, 2022), 88 FR 44468 (July 12, 2023).
---------------------------------------------------------------------------
Just as the economy as a whole is able to function efficiently when
individuals and businesses prudently plan for unforeseen events by
maintaining inventories and reserve money accounts, we believe that the
RFS program is best able to function when sufficient carryover RINs are
held in reserve for potential use by the RIN holders themselves, or for
possible sale to others that may not have established their own
carryover RIN reserves. Without sufficient RINs in reserve, even minor
disruptions causing shortfalls in renewable fuel production or
distribution, or higher-than-expected transportation fuel demand
(requiring greater volumes of renewable fuel to comply with the
percentage standards that apply to all volumes of transportation fuel,
including the unexpected volumes) could result in deficits and/or
noncompliance by parties without RIN reserves. Moreover, because
carryover RINs are individually and unequally held by market
participants, a non-zero but nevertheless small number of available
carryover RINs may negatively impact the RIN market, even when the
market overall could satisfy the standards. In such a case, market
disruptions could force the need for a retroactive waiver of the
standards, undermining the market certainty so critical to the RFS
program. For all these reasons, carryover RINs provide a necessary
programmatic buffer that helps facilitate compliance by individual
obligated parties, provides for smooth overall functioning of the
program to the benefit of all market participants, and is consistent
with the statutory provision requiring the generation and use of
credits.
Carryover RINs have also provided flexibility when we have
considered the need to use our waiver authorities to lower volumes. For
example, in the context of the 2013 RFS rulemaking we noted that an
abundance of carryover RINs available in that year, together with
possible increases in renewable fuel production and import, justified
maintaining the advanced and total renewable fuel volume requirements
for that year at the levels specified in the statute.\198\
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\198\ 79 FR 49793-95 (August 15, 2013).
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1. Projected Number of Available Carryover RINs
The projected number of available carryover RINs after compliance
with the 2024 standards (i.e., the number of carryover RINs available
for compliance with the 2025 standards) is summarized in Table III.F.1-
1.\199\ This is the most recent year for which complete RFS compliance
data was available at the time of this action.
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\199\ The calculations performed to project the number of
available carryover RINs can be found in RIA Chapter 1.8.
[GRAPHIC] [TIFF OMITTED] TR01AP26.066
Assuming that the market exactly meets the 2025 standards with new
RIN generation, these are also the number of carryover RINs that would
be available for 2026 and 2027. However, there remains considerable
uncertainty surrounding the ultimate number of the carryover RINs that
will be available for compliance with the 2026 and 2027 standards for
several reasons, including the granting of small refinery exemptions
(projected to total 990 million RINs in 2025, as discussed in section
IV of this preamble), higher or lower than expected transportation fuel
[[Page 16433]]
demand (requiring greater or lower volumes of renewable fuel to comply
with the percentage standards that apply to all volumes of
transportation fuel), and the impact of 2025 RFS compliance on the
availability of carryover RINs. While we project that the volume
requirements in 2025-2027 could be achieved without the use of
carryover RINs, there is nevertheless some uncertainty about how the
market will choose to meet the applicable standards. The result is that
there remains some uncertainty surrounding the ultimate number of
carryover RINs that will be available for compliance with the 2026 and
2027 standards.
In addition, we note that there have been enforcement actions in
past years that have resulted in the retirement of carryover RINs to
make up for the generation and use of invalid RINs and/or the failure
to retire RINs for exported renewable fuel. To the extent that there
are enforcement actions in the future, they could have similar results
and require that obligated parties or renewable fuel exporters settle
past enforcement-related obligations in addition to complying with the
annual standards. In light of these uncertainties, the number of
carryover RINs that will be available for compliance with the 2026 and
2027 standards could be larger or smaller than the number projected in
Table III.F.1-1.
2. Treatment of Carryover RINs for 2026 and 2027
We evaluated the number of carryover RINs projected to be available
and considered whether we should include any portion of them in the
determination of the volume requirements that we are establishing for
2026 and 2027. Doing so would be equivalent to intentionally drawing
down the number of available carryover RINs in setting those volume
requirements. As part of this consideration, we note that, as further
discussed in section IV of this preamble, we are reallocating a portion
of the exempted RVOs for the 2023-2025 compliance years to the 2026 and
2027 compliance years, which we intend to be met with carryover RINs
attributable to the 2023-2025 exemptions. These reallocated
obligations, which total over 2 billion RINs, represent over 50 percent
of the number of currently available carryover RINs. Thus, absent the
impact of other factors (e.g., higher or lower than expected
transportation fuel demand), we would expect that compliance with the
SRE reallocated volumes will result in a significant decrease in the
number of available carryover RINs over the course of the 2026 and 2027
compliance years.
After due consideration, we do not believe that it would be
appropriate to establish final volume requirements that would
intentionally draw down the projected number of available carryover
RINs any further than will already be required by the SRE reallocation
volumes. In reaching this determination, we considered the functions of
carryover RINs, the projected number available, the uncertainties
associated with this projection, the potential impact of carryover RINs
on the production and use of renewable fuel, the ability and need for
obligated parties to draw on carryover RINs to comply with their
obligations (both on an individual basis and on a market-wide basis),
and the impacts of drawing down the number of available carryover RINs
on obligated parties and the fuels market more broadly. As previously
described, carryover RINs provide important and necessary programmatic
functions--including as a cost spike buffer--that will both facilitate
individual compliance and provide for smooth overall functioning of the
program. We believe that a balanced consideration of the possible role
of carryover RINs in achieving the volume requirements, versus
maintaining an adequate number of carryover RINs for important
programmatic functions, is appropriate when we exercise our discretion
under our statutory authorities.
Furthermore, in this action we are prospectively establishing
volume requirements for multiple years. This inherently adds
uncertainty and makes it more challenging to project with accuracy the
number of carryover RINs that will be available for each of these
years. Given these factors, and the uneven holding of carryover RINs
among obligated parties, we believe that further increasing the volume
requirements for 2026 and 2027 with the intent to draw down the number
of available carryover RINs could lead to significant deficit
carryforwards and noncompliance by some obligated parties. We do not
believe this would be a desirable outcome. Therefore, consistent with
the approach we have taken in recent annual rules, we are not
establishing the 2026 and 2027 volume requirements at levels that will
intentionally draw down the projected number of available carryover
RINs beyond what will already be required by the SRE reallocation
volumes for 2026 and 2027.
We are not determining that the number of carryover RINs projected
in Table III.F.1-1 is a bright-line threshold for the number of
carryover RINs that provides sufficient market liquidity and allows
carryover RINs to play their important programmatic functions. As in
past years, we are instead evaluating, on a rule-by-rule basis, the
number of available carryover RINs in the context of the RFS standards
and the broader transportation fuel market. Based upon this holistic,
case-by-case evaluation, we are concluding that it would be
inappropriate to intentionally reduce the number of carryover RINs by
establishing higher volumes than what we anticipate the market can
achieve in 2026 and 2027. Conversely, while a larger number of
available carryover RINs may provide greater assurance of market
liquidity, we do not believe it would be appropriate to set the
standards at levels specifically designed (i.e., low) to increase the
number of carryover RINs available to obligated parties.
G. Consideration of Alternative Volumes
When determining the appropriate volumes for 2026 and 2027, we also
considered alternative volumes. This section briefly discusses
alternative volumes we considered based on the comments we received. As
with the final volume requirements, we have structured our discussion
of the alternative volumes around the component categories of renewable
fuel as these component categories have distinct economic,
environmental, technological, and other characteristics relevant to the
factors we must analyze under the statute. More detail on each of the
analyses discussed in this section can be found in the RIA.
The cellulosic biofuel volume requirements we are finalizing for
2026 and 2027 are equal to the volumes of cellulosic biofuel we project
will be used as qualifying transportation fuel in these years. These
projections take into account the limited production capacity (in the
case of CKF ethanol) and the limited ability for the market to consume
cellulosic biofuel as transportation fuel (in the case of renewable
CNG/LNG). Establishing higher cellulosic biofuel volume requirements
than the market can supply is inconsistent with our statutory
authority.\200\ Establishing lower cellulosic biofuel volume
requirements would be expected to decrease demand for these fuels.\201\
Lower demand in turn
[[Page 16434]]
is expected to decrease investment in the technologies needed to expand
cellulosic biofuel production and use in future years. Such an action
would ultimately forgo the many benefits associated with higher
production and use of cellulosic biofuel (see section III.E.1 of this
preamble), both in 2026 and 2027 as well as future years.
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\200\ For a further discussion of our authority to establish
cellulosic biofuel volume requirements in years after 2022, see
section II.B of this preamble.
\201\ For a discussion of our projection of cellulosic biofuel
production and use absent the incentives provided by the RFS
program, see RIA Chapter 2.1.
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The non-cellulosic advanced biofuel volume requirements we are
finalizing for 2026 and 2027 are approximately equal to the volumes of
biodiesel and renewable diesel we project can be supplied by domestic
producers, as well as the projected supplies of other advanced biofuels
(e.g., advanced CNG/LNG, sugarcane ethanol, renewable naphtha). We
acknowledge that higher volumes of these fuels could be supplied to
U.S. markets in 2026 and 2027. However, because the non-cellulosic
advanced biofuel volumes we are finalizing are based on domestic
production capacity, higher required volumes would most likely be met
primarily, if not entirely, with imported biofuels.\202\ Imported
biofuels do not further energy independence, nor do they further the
Administration's goal of achieving energy dominance.\203\ Imported
biofuels are also projected to have few, if any, positive impacts on
domestic jobs and rural economic development and are unlikely to be
produced from domestic feedstocks.\204\ Therefore, increased non-
cellulosic advanced biofuel volumes are not projected to materially
benefit domestic feedstock suppliers such as soybean farmers or oilseed
processors. In addition to lacking these key benefits, higher volumes
of non-cellulosic advanced biofuels would be projected to increase fuel
costs and the cost to transport goods.
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\202\ RIA Chapter 7.2.
\203\ RIA Chapter 6.
\204\ RIA Chapter 9.
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We also considered establishing lower volumes of non-cellulosic
advanced biofuels for 2026 and 2027. Our consideration of lower volumes
of these fuels was primarily due to the high cost of these fuels, which
could suggest that lower volumes are appropriate to minimize the impact
of the volume requirements on fuel prices. We project that a majority
of the non-cellulosic advanced biofuels supplied in 2026 and 2027 will
be produced in the U.S. from domestic feedstocks.\205\ Lower volume
requirements for these fuels would therefore be expected to result in
lower domestic production and decreased demand for domestic
feedstocks.\206\ These decreases in domestic production would
negatively impact all parties involved in the biofuel production supply
chain (e.g., farmers, oilseed processors, parties that transport
feedstocks and finished fuels). Depending on the degree of the
reduction in the required volumes for these fuels, it is likely that
the decrease in demand due to the RFS would result in the closure of
biodiesel and renewable diesel production facilities. To the degree
that lower volume requirements in 2026 and 2027 resulted in the closure
of biodiesel and renewable diesel production facilities, lower volume
requirements could also have negative impacts in future years.
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\205\ RIA Chapter 7.2.
\206\ RIA Chapter 2.1.
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Finally, we also considered whether higher or lower volumes of
conventional renewable fuel would be appropriate for 2026 and 2027. In
this action, we have maintained the 15-billion-gallon implied
conventional renewable fuel volume established for 2023-2025 in the Set
1 Rule and implied in the statutory RFS volumes for years 2015-2022.
Based on the most recent data available, we project that ethanol
consumption in the U.S. will fall below the 15-billion-gallon implied
conventional renewable fuel volume primarily due to the limited
availability of higher-level ethanol blends (e.g., E15 and E85) at
retail stations.\207\ Establishing a higher volume for conventional
renewable fuel would therefore be unlikely to result in the increased
production and use of ethanol, but would rather increase the production
and use of other non-ethanol biofuels such as biodiesel and renewable
diesel.\208\
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\207\ RIA Chapter 7.5.
\208\ The impacts of higher volumes of these fuels are discussed
earlier in this section.
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A number of commenters requested that we finalize conventional
renewable fuel volumes that are at or below the E10 blendwall in 2026
and 2027. These commenters generally argued that doing so would not
have a significant impact on ethanol production and consumption but
would result in significantly lower prices for conventional (D6) RINs.
Lower D6 RIN prices would in turn, these commenters argued, decrease
compliance costs for obligated parties and fuel prices to consumers.
As discussed in previous actions and the Set 2 proposal,
maintaining a 15-billion-gallon implied conventional renewable fuel
volume provides continued incentives for investment in the distribution
and use of ethanol in higher-level ethanol blends. The higher D6 RIN
prices that we project would result from maintaining a 15-billion-
gallon implied conventional volume (relative to an implied conventional
volume below the E10 blendwall) provide greater incentives to increase
the use of conventional ethanol. In the long term, we project that
investments in higher-level ethanol blends are crucial to increase
consumption (and by extension the production) of ethanol in the
U.S.\209\ Increasing ethanol production and use is projected to have
similar positive impacts on several of the statutory factors, such as
jobs and rural economic development, and energy security. Unlike the
majority of non-cellulosic advanced biofuels, ethanol is generally
cheaper than the gasoline it displaces on a per gallon basis and
increasing ethanol use has the potential to decrease fuel prices.\210\
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\209\ RIA Chapter 7.5.
\210\ RIA Chapter 10.
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We do not dispute commenters' claims that finalizing conventional
biofuel volumes below the E10 blendwall would result in significantly
lower D6 RIN prices. We note, however, that higher D6 RIN prices
provide much of the incentives to invest in infrastructure to increase
the availability of higher-level ethanol blends at retail stations.
Contrary to commenters' claims about the impact of D6 RIN prices on
obligated parties, our analysis of the fuels market has demonstrated
that, on average at the nationwide scale, obligated parties that
acquire RINs recover the cost of these RINs in the sales prices of the
gasoline and diesel they produce and are therefore not negatively
impacted by higher D6 RIN prices.\211\ Finally, our analysis has shown
that RINs operate as a cross-subsidy, effectively increasing the price
of petroleum-based fuels to retailers and consumers while decreasing
the price of renewable fuels to these parties.\212\ Higher D6 RIN
prices increase the price of fuels with little or no renewable content
(such as gasoline that is not blended with ethanol) and decrease the
price of fuels with high renewable content (such as E85). Higher D6 RIN
prices have little to no impact on E10, which represents approximately
97 percent of the gasoline we project will be sold in 2026 and
2027.\213\ Our analysis indicates that reducing the implied
conventional renewable fuel volumes would decrease the incentives for
higher-level ethanol blends but would not positively impact obligated
parties or materially reduce fuel prices for consumers.\214\
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\211\ RTC Section 9.1.8.
\212\ RTC Section 9.1.4.
\213\ RTC Section 9.1.4.
\214\ For a further discussion of the impacts of lower
conventional renewable fuel volumes on RIN prices, see RTC Section
6.1.6. The RTC also contains further discussion of the impact of the
RFS standards on RIN prices, retail fuel prices, and refiners (RTC
Sections 9.1.3, 9.1.4, and 9.1.8, respectively).
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[[Page 16435]]
H. Summary of Final Volumes for 2026 and 2027
For the reasons described above, we are finalizing volume
requirements for 2026 and 2027 based on the three component categories
discussed. The volumes for each of the component categories (sometimes
referred to as implied volume requirements) are summarized in Table
III.H-1. Table III.H-1 also includes the volume requirements for BBD,
which is not a component category of renewable fuel but is based on our
evaluation of non-cellulosic advanced biofuel and other considerations
described in section III.E.3 of this preamble.
[GRAPHIC] [TIFF OMITTED] TR01AP26.067
The volumes for each of the four component categories shown in the
table above can be combined to produce volume requirements for the four
statutory renewable fuel categories on which the applicable percentage
standards are based. The results are shown in Table III.H-2.
[GRAPHIC] [TIFF OMITTED] TR01AP26.068
We believe that these volume requirements will preserve and
substantially build upon the gains made in biofuel production and use
in previous years. In particular, these volume requirements would
continue to support the domestic renewable fuel industry and help move
the U.S. towards greater energy independence and energy security. These
volume standards are expected to drive increased employment and
economic impact in the U.S. and have the potential to reduce GHG
emissions from the transportation sector. The volume requirements will
also promote ongoing development within the biofuels and agriculture
industries as well as the economies of the rural areas in which
biofuels production facilities and feedstock production reside.
IV. SRE Reallocation
In this action, we are adding a new ``SRE reallocation volume''
term in the percentage standard equations for 2026 and 2027 that, taken
together, account for the 2023-2025 exempted RVOs. This section
describes the EPA's authority to consider the impact of SREs granted
for the 2023-2025 compliance years when establishing the RFS standards
for 2026 and 2027 and the SRE reallocation volumes we are adding to the
volume requirements for 2026 and 2027.
A. Background and Policy Rationale
On August 22, 2025, the EPA issued decisions on 175 SRE petitions
in the August 2025 SRE Decisions Action, in which 64 petitions were
granted full (100 percent) exemptions, 76 petitions were granted
partial (50 percent) exemptions, 28 petitions were denied, and 7
petitions were determined to be ineligible. On September 18, 2025, the
EPA proposed in the Set 2 supplemental proposal to reallocate all or a
portion of the 2023-2025 exempted RVOs that resulted from the August
2025 SRE Decisions Action--which at the time totaled 1.4 billion RINs--
and solicited comment on what amount, if any, to reallocate.\215\ On
November 7, 2025, the EPA issued decisions on 16 additional SRE
petitions in the November 2025 SRE Decisions Action, in which 2
petitions were granted full (100 percent) exemptions, 12 petitions were
granted partial (50 percent) exemptions, and 2 petitions were denied,
resulting in an additional 2023-2025 exempted RVO of 0.5 billion RINs.
The EPA made the SRE decisions in August and November 2025,
collectively referred to as the ``2025 SRE Decisions Actions,'' using a
consistent policy approach across all SRE petitions under
consideration, and we intend to use this same approach going forward.
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\215\ 90 FR 45007, 45009 (September 18, 2025). At the time of
the Set 2 supplemental proposal, no decisions had been issued for
the 2025 compliance year, and additional decisions for 2023 and 2024
petitions were pending. However, we also noted that we intended to
update our projection of exempted volumes for the final rule using
the most recent available data.
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In this final rule, we are revising the percentage standards
equations for 2026 and 2027 to add new volumes we refer to as the ``SRE
reallocation volumes,'' which account for a portion of the 2023-2025
exempted RVOs. Specifically, we are adding SRE reallocation volumes
that account for 70 percent of: (1) the actual exempted RVOs for the
2023 and 2024 compliance years; and (2) the projected exempted RVOs for
the 2025 compliance year.\216\ The SRE reallocation volumes correspond
to three statutory categories
[[Page 16436]]
of renewable fuel (advanced biofuel, BBD, and renewable fuel), such
that there are three SRE reallocation volumes for each year.\217\ Each
SRE reallocation volume is then added to the corresponding volume
requirement in section III of this preamble and the sum of the volumes
for each year is used to calculate the percentage standards for 2026
and 2027, as discussed further in section V of this preamble. We are
dividing the SRE reallocation volumes across two years to lessen the
disruption to the market and the burden on obligated parties. The
inclusion of this new term in the percentage standards equations will
only be for the 2026 and 2027 compliance years and is linked to the
impact of SREs granted for the 2023-2025 compliance years. In the
future, we intend to continue our policy of prospectively accounting
for exempted volumes of gasoline and diesel such that there will be no
need to include SRE reallocation volumes in this manner again.
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\216\ The exact SRE reallocation volumes for 2026 and 2027 are
described in section IV.C of this preamble.
\217\ We are not establishing SRE reallocation volumes for
cellulosic biofuel for the reasons discussed in section IV.B of this
preamble.
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We received many comments on our authority to implement SRE
reallocation volumes, as well as the need for SRE reallocation volumes
and the percentage of 2023-2025 exempted RVOs that should be
reallocated. Biofuel producers generally argued that we have the legal
authority and obligation to reallocate all the 2023-2025 exempted RVOs,
while refiners generally argued that we had no legal authority to
reallocate any exempted RVOs. We respond fully to these comments in RTC
Section 7.3.
The 2025 SRE Decisions Actions resolved a backlog of SRE petitions
and exempted significant volumes of gasoline and diesel for the 2023
and 2024 compliance years, resulting in an increased number of RINs
available for obligated parties to use for compliance with their RFS
obligations. We expect additional SREs will be granted for the 2025
compliance year as well. These RINs represent renewable fuel produced
and used in 2023-2025 that obligated parties will no longer need to
retire for compliance because of the relieved obligations from SREs.
The availability of these RINs--and the ability for obligated parties
to use them to comply with their RFS obligations in lieu of RINs
generated for renewable fuel produced and used in 2026 and 2027--could
reduce RIN demand and RIN prices in future years and may ultimately
result in the market failing to produce the volume of renewable fuel
anticipated by the volume requirements in section III of this preamble.
The impacts of the SREs granted in the 2025 SRE Decisions Actions
on the RIN market are as follows.\218\ For the 2023 and 2024 compliance
years, we project that 1.9 billion RINs no longer need to be retired
for compliance. While the SREs granted for these years have no impact
on the volume of renewable fuel actually produced and used in 2023 and
2024--since those years are in the past--the SREs directly increase the
supply of RINs available for other obligated parties to use for
compliance in future years. As a result, obligated parties will be able
to use the RFS program's carryover RIN provisions to roll these RINs
forward to the 2025 compliance year and beyond.\219\
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\218\ The RIN volumes and exemptions discussed in this section
are limited to the SRE decisions the EPA issued as of the time of
this final rule (i.e., those in the 2025 SRE Decisions Actions),
which did not include the 2025 compliance year. However, as
discussed in section IV.C of this preamble, we are also projecting
exempted volumes for 2025 as part of determining the SRE
reallocation volumes for 2026 and 2027.
\219\ Contrary to suggestions by some commenters that this
``impermissibly increases the lifespan of RINs,'' we find that this
is a wholly permissible compliance mechanism and is how the RIN
market has operated since its inception.
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CAA section 211(o)(5) requires that the EPA establish a credit
program as part of its RFS regulations and that the credits be valid
for obligated parties to show compliance for 12 months after the date
of generation. We implemented this requirement through the use of RINs,
which can be used to demonstrate compliance for the year in which they
are generated and the subsequent compliance year. Obligated parties can
obtain more RINs than needed in a given compliance year, allowing them
to carry over these RINs for use in the subsequent compliance year,
although the RFS regulations limit the use of these carryover RINs to
20 percent of the obligated party's RVO. For the total number of
available carryover RINs to be preserved from one year to the next,
individual carryover RINs are used for compliance before they expire
and are replaced with newer vintage RINs that are then held for use in
the next year. For example, 2023 carryover RINs must be used for
compliance in 2024, or they will expire. However, the use of 2023 RINs
to meet up to 20 percent of an obligated party's 2024 RVO increases the
number of 2024 RINs that can then be carried over for compliance with
the 2025 standards.
While there may have been some impact from the increased number of
carryover RINs as a result of the 2023 and 2024 SREs on renewable fuel
production and use in 2025 after the 2025 SRE Decisions Actions were
issued, the effect of these RINs is likely to be most acute in 2026 and
2027 when obligated parties will be able to choose whether to use
carryover RINs to comply with their 2026 and 2027 RVOs in lieu of
acquiring renewable fuel produced in those years, which would reduce
demand for renewable fuel production and use in those years. Failure to
mitigate the market impacts of the increased number of carryover RINs
due to these SREs could result in a decrease in demand for renewable
fuel produced in 2026 and 2027.
We recognize that while significant quantities of carryover RINs
can negatively impact the production and use of renewable fuels,
carryover RINs also play an important role in providing a liquid and
well-functioning RIN market, as we have stated on multiple
occasions.\220\ The continued success of the RFS program depends on a
functioning RIN market. Carryover RINs provide obligated parties
compliance flexibility for substantial uncertainties in the
transportation fuel marketplace. In the 2025 SRE Decisions Actions, the
EPA granted SREs for multiple years at a single time, representing
significant exempted RVOs after the volume requirements for those years
had been established and actual production for those years had
concluded. The resulting influx of additional RINs in the market could
have a deleterious effect on current and future volume requirements
without corrective action to address the increased number of carryover
RINs due to the 2023-2025 exempted RVOs.
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\220\ See, e.g., 90 FR 25784, 25827 (June 17, 2025); see also,
e.g., 88 FR 44468, 44494 (July 12, 2023), 87 FR 39600, 39613 (July
1, 2022), 85 FR 7016, 7021 (February 6, 2020), 83 FR 63704, 63708-10
(December 11, 2018), 82 FR 58486, 58493-95 (December 12, 2017), 81
FR 89746, 89754-55 (December 12, 2016), 80 FR 77420, 77482-87
(December 14, 2015).
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As described above, we are finalizing SRE reallocation volumes for
2026 and 2027 that represent 70 percent of the 2023-2025 exempted RVOs.
In determining this value, we weighed the impacts of intentionally
drawing down the number of available carryover RINs through SRE
reallocation volumes against the need to ensure that the 2026 and 2027
volume requirements are met with renewable fuel use in those years.
We first assessed the ability of the RIN market to manage an
intentional drawdown in the number of available carryover RINs through
the SRE reallocation volumes over the 2026 and 2027 compliance years.
As described in section III.F.1 of this preamble, we project that there
are effectively 3.60 billion carryover RINs after compliance
[[Page 16437]]
with the 2024 RFS standards. In the Set 2 Supplemental proposal, we
discussed the fact that some obligated parties may choose to retain
some of the RINs associated with the 2023-2025 exempted RVOs as a
compliance flexibility. We do not find that it would be appropriate to
require the retirement of all RINs associated with the 2023-2025
exempted RVOs because doing so would hinder an existing and statutory
compliance flexibility for obligated parties (i.e., the use of
carryover RINs). As described in section III.F of this preamble,
carryover RINs are a foundational element of the design and
implementation of the RFS program. Establishing applicable volumes that
would likely result in obligated parties using more carryover RINs than
the market can manage in a single year (i.e., drawing down the number
of carryover RINs such that the functions of carryover RINs are
impaired) could lead to issues such as RIN scarcity or illiquidity in
the RIN trading market, resulting in significant instances of
noncompliance by obligated parties. In reviewing the historical number
of available carryover RINs in RIA Chapter 1.8.3, we observe that the
largest drawdown in the number of available carryover RINs was 0.94
billion RINs from 2021 to 2022. We did not observe issues with RIN
scarcity or illiquidity during this time period, and thus we believe
that the market could handle carryover RIN drawdowns of similar
magnitude in 2026 and 2027. Based on this observation and the current
number of available carryover RINs currently available, we believe that
the market is capable of absorbing a drawdown of approximately 1
billion RINs in each of 2026 and 2027, or a total of approximately 2
billion RINs.
We then evaluated how this volume of carryover RIN drawdown
compares to the 2023-2025 exempted RVOs. We find that it is necessary
to reallocate the majority of the 2023-2025 exempted RVOs to protect
the market-forcing nature of the 2026 and 2027 volume requirements.
Without this reallocation, it is likely that a portion of the 2026 and
2027 volume requirements would not be met with new renewable fuel use
in the market. As described in section IV.C of this preamble, we
project that the total 2023-2025 exempted RVOs will be 2.89 billion
RINs. A carryover RIN drawdown of approximately 2 billion RINs
represents 70 percent of the 2023-2025 exempted RVOs, which we find is
sufficiently significant to ensure that the 2026 and 2027 volume
requirements are met with renewable fuel use these years.
We note as well that we are promulgating the 2026 and 2027 SRE
reallocation volumes late, and that the 2026 SRE reallocation volumes
are partially retroactive in effect. Our consideration of the timing of
these actions is discussed in section II.E of this preamble. When the
EPA promulgates late rulemakings, including those with retroactive
effects, it must consider the benefits and burdens of doing so.\221\ In
light of the burden on obligated parties, the 70 percent reallocation
serves as a means to mitigate the burdens on obligated parties by
preserving some amount of carryover RINs associated with the 2023-2025
exempted RVOs and not requiring 100 percent reallocation. We are
therefore finalizing SRE reallocation volumes for 2026 and 2027 equal
to 70 percent of the 2023-2025 exempted RVOs.
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\221\ See e.g., CBD, 141 F.4th at 165.
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We are not accounting for any SREs granted for compliance years
prior to 2023. Pre-2023 vintage RINs that were returned to small
refineries that received an SRE for these years in the 2025 SRE
Decisions Actions are expired and can only be used to satisfy
outstanding, non-exempted pre-2023 obligations by the small refinery.
At the time the SREs were granted in the 2025 SRE Decisions Actions,
RFS compliance had not yet occurred for 2024. Thus, 2023 and newer
vintage RINs were valid for RFS compliance at that time and had value
within the RIN market. In contrast, 2022 and older RINs were expired
and thus could not be used for compliance with 2024 or later RFS
obligations.\222\ Therefore, we are finalizing SRE reallocation volumes
for 2026 and 2027 that only account for the 2023-2025 exempted RVOs
(i.e., the vintage RINs that could still be used for RFS compliance at
the time the SREs were granted in ways that may impact the production
and use of renewable fuels in 2026 and 2027). Obligated parties could
use 2023 RINs to satisfy up to 20 percent of their 2024 obligations,
2024 RINs to satisfy their 2024 or up to 20 percent of their 2025
obligations, and 2025 RINs to satisfy their 2025 or up to 20 percent of
their 2026 obligations.
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\222\ 40 CFR 80.1428(c).
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B. Legal Justification
As described in section II.B of this preamble, CAA section
211(o)(2)(B)(ii) provides the statutory factors the EPA is to consider
in establishing the volume requirements. We are using this authority to
consider the 2023-2025 exempted RVOs and establish RFS volumes for 2026
and 2027 that incorporate the SRE reallocation volumes discussed in
this section. In discussing the statutory conditions in CAA section
211(o)(2)(B)(iii) and (v) in section II.B of this preamble, we have
assessed the total applicable volumes, including the SRE reallocation
volumes.
As also discussed in section II.B of this preamble, CAA section
211(o)(2)(B)(iv) requires that the EPA set the cellulosic biofuel
standard based on the assumption that the Administrator will not need
to waive the volume using the cellulosic waiver authority. The
cellulosic waiver authority at CAA section 211(o)(7)(D) requires that
the EPA reduce the cellulosic biofuel volume in circumstances where the
projected volume of cellulosic biofuel production is less than the
cellulosic biofuel volume requirement. In these circumstances, under
the cellulosic waiver authority, the EPA must reduce the volume to the
``projected volume available.'' As described in section III of this
preamble, we are establishing cellulosic biofuel volumes at the
``projected volume available'' to satisfy the CAA section
211(o)(2)(B)(iv) condition. We recognize the D.C. Circuit's holding
that the ``projected volume available'' excludes carryover RINs, and
its indication that any ``projection of cellulosic biofuel production''
would likely also exclude any carryover RINs.\223\ Therefore, we are
not establishing SRE reallocation volumes associated with cellulosic
biofuel exempted RVOs. This is primarily due to the statutory
conditions on cellulosic biofuel volume requirements, which we do not
read as allowing the EPA to set the total applicable volume of
cellulosic biofuel at a volume that is greater than the projected
volume available, and which necessarily excludes cellulosic carryover
RINs.
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\223\ Sinclair, 101 F.4th at 883-84.
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In establishing these SRE reallocation volumes under CAA section
211(o)(2)(B)(ii), we also analyzed the statutory factors and a review
of implementation of the program. As noted in the Set 2 supplemental
proposal, we have considered the impact of the volume of RINs
associated with the 2023-2025 exempted RVOs on the future rate of
production of renewable fuels and concluded that without an SRE
reallocation volume, the future rate of production of renewable fuels
would be reduced by an amount as large as 1.9 billion RINs (the RINs
associated with the 2023-2025 exempted RVOs). Because we project that
the SRE reallocation volumes will be met with carryover RINs
attributable to the 2023-2025 exempted RVOs, we
[[Page 16438]]
do not expect the SRE reallocation volumes to increase the production
and use of renewable fuel beyond the volumes described in section III
of this preamble. Our analysis of all other factors is therefore not
impacted by the SRE reallocation volumes. This includes air quality,
climate change, conversion of wetlands, ecosystems, wildlife habitat,
water quality and supply, energy security, infrastructure, job
creation, the prices and supply of agricultural commodities, rural
economic development, or food prices.
Our assessment of the other statutory factors drove the selection
of the 2026 and 2027 volume requirements, and that is not affected by
the use of carryover RINs in 2026 and 2027. For example, we analyze the
infrastructure required for production distribution with the 2026 and
2027 renewable fuel volumes by looking at the volumes for 2026 and 2027
and the existing and future infrastructure for product distribution in
light of those renewable fuel volumes. Because we are establishing SRE
reallocation volumes at the level necessary to avoid erosion of the
2026 and 2027 renewable fuel volumes, it is appropriate to only look at
the renewable fuel volumes, without considering the additional volume
of carryover RINs required to be retired to meet the SRE reallocation
volumes. Two statutory factors that may be impacted by our decision to
include the SRE reallocation volumes in the applicable volume (rather
than the volume of renewable fuel produced and used in 2026 and 2027)
are the cost to consumers of transportation fuel and the cost to
transport goods. In assessing those factors, we have utilized higher
percentage standards to calculate the impacts of the SRE reallocation
volumes, along with the renewable fuel volume requirements to quantify
the effects. Our consideration of the impact of the SRE reallocation
volumes on these factors is discussed in the RIA Chapter 10.5.4.
Some commenters suggested that the EPA's review of implementation
of the program, and consideration of the exempted RVOs from SREs as
part of that review, extended beyond the terms of the statute that
requires the EPA to review implementation of the program for the
calendar years in the statute (i.e., through 2012 for the BBD standard,
and through 2022 for all other renewable fuel types). The statutory
text does refer to the years identified in the statutory tables.
However, our consideration of the years identified in the statutory
tables, including our own experience implementing the program during
that timeframe and the impacts of carryover RINs on the renewable fuels
market in those past years, informs our evaluation in this action. As
described in the Set 2 supplemental proposal, recent SRE decisions
resulted in increased carryover RINs available for obligated parties as
a compliance mechanism with future (i.e., 2026 and 2027) volume
requirements. These carryover RINs have the potential to be used in
lieu of new renewable fuel, thus decreasing demand for renewable fuel.
Even absent consideration of years beyond 2022, we would conclude that
the SRE reallocation volumes are appropriate given the impacts on the
future rate of commercial production and other statutory factors.
C. SRE Reallocation Volumes
In this final rule, we are establishing new SRE reallocation
volumes for 2026 and 2027 equivalent to 70 percent of the 2023-2025
exempted RVOs. These final SRE reallocation volumes reflect
consideration of public comments, including data and argumentation,
received in response to the Set 2 supplemental proposal, in which we
sought comment on what an appropriate SRE reallocation volume would be
if the Agency were to finalize SRE reallocation volumes for 2026 and
2027.\224\ Commenters provided a variety of perspectives on the
appropriate level for SRE reallocation. The 70 percent reallocation
finalized in this action reflects our analysis of the comments
submitted and endeavors to achieve an appropriate balance among
relevant statutory considerations.
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\224\ 90 FR 45007, 45011 (September 18, 2025).
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Since we issued decisions for all the 2023 and 2024 SRE petitions
that were before the Agency and obligated parties have submitted
compliance reports for these years, we are able to determine the actual
exempted RVOs for the 2023 and 2024 compliance years. Specifically, we
used information from EMTS compliance data to calculate the actual
total exempted gasoline and diesel volumes for 2023 and 2024. In turn,
we used these exempted volumes, together with the previously
established percentage standards for 2023 and 2024, to calculate the
actual exempted RVOs for these years.
However, we have not yet issued any SRE decisions for 2025. In
order to develop a projection of the 2025 exempted RVOs, we used data
on the volumes of exempted gasoline and diesel for previous years.
Consistent with the approach that the EPA first advanced in the 2020
RFS Rule (in which the EPA projected future exempted fuel
volumes),\225\ we believe it is appropriate to use average volumes of
exempted gasoline and diesel over a three-year period as our projection
of future exempted volumes of gasoline and diesel in 2025, rather than
the volumes of gasoline and diesel that were exempted in any single
year. This helps to average the effects of unique events or market
circumstances that occurred in individual years that may or may not
occur in 2025, and thus serves as a better predictor of the volume of
gasoline and diesel that will ultimately be exempted in 2025.\226\
Thus, we used information from 2022-2024 SRE petitions to calculate the
annual average volumes of exempted gasoline and diesel and used those
volumes to represent our projection of the exempted volumes of gasoline
and diesel in 2025, as shown in Table IV.C-1.
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\225\ 85 FR 7016, 7051-53 (February 6, 2020). We note that while
we projected exempted volumes of gasoline and diesel in the 2020
final rule, we later revised the 2020 percentage standards via
rulemaking, including adjusting our projection of exempted volume
from SREs. 87 FR 39600 (July 1, 2022) (``Reset Rule'').
\226\ 84 FR 57677 (October 28, 2019); 85 FR 7016 (February 6,
2020).
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[[Page 16439]]
[GRAPHIC] [TIFF OMITTED] TR01AP26.069
Using these exempted fuel volumes and multiplying them by the RFS
percentage standards in 40 CFR 80.1405(a), we calculated the 2023-2025
exempted RVOs, as shown in Table IV.C-2.
[GRAPHIC] [TIFF OMITTED] TR01AP26.070
As discussed in section IV.B of this preamble, we are not
establishing SRE reallocation volumes for cellulosic biofuel. In making
this decision, we have considered that there are very few 2024
cellulosic carryover RINs available to meet the 2025 compliance
obligations.\227\ In the Set 2 supplemental proposal, we requested
comment on our treatment of the advanced biofuel and total renewable
fuel SRE reallocation volumes if we chose not to establish an SRE
reallocation volume for cellulosic biofuel. We noted that, given the
nested nature of the standards, the total renewable fuel and advanced
biofuel SRE reallocation volumes would include some amount of RINs
associated with the 2023-2025 exempted cellulosic biofuel RVOs, unless
we made corresponding reductions in the total renewable fuel and
advanced biofuel SRE reallocation volumes.
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\227\ As described in RIA Chapter 1.8.1, we project that there
effectively fewer than 20 million cellulosic carryover RINs
available for compliance with the 2025 standards. This represents
approximately 1 percent of the revised 2025 cellulosic biofuel
volume requirement of 1.21 billion RINs.
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In this final rule, we find that it is appropriate to require the
full total renewable fuel and advanced biofuel SRE reallocation volumes
for 2026 and 2027. As discussed in section III.F of this preamble,
there are currently over 2.5 billion non-cellulosic advanced carryover
RINs and nearly 1.1 billion conventional carryover RINs, whereas the
2023-2025 cellulosic biofuel exempted RVOs total 140 million RINs
(which would be reduced to 100 million RINs after multiplying by 70
percent). Thus, we find that there are sufficient conventional and
advanced carryover such that the full SRE reallocation volumes for 2026
and 2027 can be met without reducing the total renewable fuel and
advanced biofuel SRE reallocation volumes by the amount of the 2023-
2025 cellulosic biofuel exempted RVOs. Declining to reduce the total
renewable fuel and advanced biofuel SRE reallocation volumes by the
amount of 2023-2025 cellulosic biofuel exempted RVOs would better serve
the purpose of the SRE reallocation volumes, which is to require the
use of carryover RINs that resulted from the 2023-2025 exempted RVOs
and realize the renewable fuel volumes through renewable fuel
production in 2026 and 2027. This will mean that, given the nested
nature of the standards, the advanced biofuel SRE reallocation volumes
will be used to satisfy a portion of the 2023-2025 cellulosic biofuel
exempted RVOs.
We then multiplied the 2023-2025 exempted RVOs for BBD, advanced
biofuel, and total renewable fuel in Table IV.C-2 by 70 percent and
used those reduced values to determine the SRE reallocation volumes for
2026 and 2027. Specifically, we are establishing SRE reallocation
volumes for 2026 equivalent to all the reduced 2023 exempted RVOs and
half of the reduced 2024 exempted RVOs, and for 2027 equivalent to the
remaining half of the reduced 2024 exempted RVOs and all the projected
reduced 2025 exempted RVOs. The resulting SRE reallocation volumes are
shown in Table IV.C-3.
[[Page 16440]]
[GRAPHIC] [TIFF OMITTED] TR01AP26.071
V. Total Applicable Volumes and Percentage Standards for 2026 and 2027
The EPA implements the nationally applicable volume requirements by
establishing percentage standards that apply to obligated parties.\228\
The obligated parties to which the percentage standards apply are
producers and importers of gasoline and diesel, as defined by 40 CFR
80.2. Each obligated party multiplies the percentage standards by the
sum of all non-renewable gasoline and diesel they produce or import to
determine their RVOs. The RVOs are the number of RINs that the
obligated party is responsible for procuring to demonstrate compliance
with the applicable standards for that year. Since there are four
categories of renewable fuel under the RFS program, there are likewise
four RVOs applicable to each obligated party for each year. As
described in section II.D of this preamble, the EPA establishes
applicable percentage standards for multiple future years after 2022 in
a single action for as many years as it establishes volume
requirements.
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\228\ See 40 CFR 80.1407 and 75 FR 14670 (March 26, 2010). As
discussed in the Set 1 Rule, we determined that continuing to use
percentage standards as the implementing mechanism for years after
2022 was effective and reasonable. 88 FR 44519 (July 12, 2023).
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A. Total Applicable Volumes for 2026 and 2027
For 2026 and 2027, the total applicable volumes are the sum of the
renewable fuel volumes requirements (discussed in section III of this
preamble) and the SRE reallocation volumes (discussed in section IV of
this preamble). These volumes are shown in Table V.A-1.
[GRAPHIC] [TIFF OMITTED] TR01AP26.072
We find that the total applicable volumes--including both the
renewable fuel volume requirements and the SRE reallocation volumes--
are achievable in the market through a combination of both new
production of renewable fuel and the use of carryover RINs. As
described in section III of this preamble (renewable fuel volume
requirements) and section IV of this preamble (SRE reallocation
volumes), each component of the total applicable volumes is justified
for the reasons described therein. While we have assumed that each
component will be met with new renewable fuel production or carryover
RINs, in practice carryover RINs or RINs representing renewable fuel
production in 2026 and 2027 can be used to meet both volume components,
and compliance demonstrations will be identical to past years. We find
that the overall applicable volumes are also appropriate and justified,
as they balance the need to address the 2023-2025 exempted RVOs and the
continued growth of renewable fuel use in the U.S. in 2026 and 2027. We
have used these volumes together to calculate the percentage standards
for 2026 and 2027.
B. Calculation of Percentage Standards
The formulas used to calculate the percentage standards applicable
to obligated parties are provided in 40 CFR 80.1405. In this action, we
are revising the percentage standard equations in 40 CFR 80.1405 such
that the numerator in the percentage standard equations for 2026 and
2027 is the sum of the annual volume requirement (RFV) and SRE
reallocation volume (SRERV). Consistent with previous RFS rulemakings,
we also account for a projection of the gasoline and diesel volumes
exempted through SREs in 2026 and 2027 in the denominator of the
percentage standard equations for 2026 and 2027. These equations
incorporating the SRE reallocation volume will only be used for the
2026 and 2027 percentage standards. In the future, we intend to
continue our policy of prospectively accounting for exempted volumes of
gasoline and diesel such that there will be no need to include SRE
reallocation volumes in this manner again.
In addition to the required volumes of renewable fuel, the formulas
also require estimates of the volumes of non-renewable gasoline and
diesel, for both highway and nonroad uses, that are projected to be
used in the year in which the standards will apply. Consistent with
previous RFS rulemakings, we are using fuel projections provided by
EIA--specifically AEO2025. However, these projections include volumes
of renewable fuel (e.g., ethanol, biodiesel, renewable diesel) used in
gasoline and
[[Page 16441]]
diesel. Since the percentage standards apply only to the non-renewable
portions of gasoline and diesel, the volumes of renewable fuel are
subtracted out of the EIA fuel projections as part of the percentage
standard equations.\229\
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\229\ Further adjustments of these projections, including the
AEO2025 adjustment factors, are discussed in ``AEO2025 Adjustment
Factors for Set 2 Final Rule,'' and ``Calculation of Final 2026 and
2027 RFS Percentage Standards,'' available in the docket for this
action.
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C. Treatment of Small Refinery Volumes
The percentage standard equations also require projections of the
exempted volumes of gasoline and diesel.\230\ As discussed in section
IV of this preamble, we have already developed a projection of exempted
gasoline and diesel volumes for 2025 using a three-year average of the
actual exempted gasoline and diesel volumes from 2022-2024 (4.35
billion gallons of gasoline and 3.20 billion gallons of diesel). We
believe this projection is an appropriate estimate of exempted gasoline
and diesel for 2026 and 2027 as well and are using this projection of
exempted gasoline and diesel volume for 2025 to inform our projection
of exempted gasoline and diesel within the percentage standard
equations. We note, however, that we do not plan to revise the
percentage standards for 2026 and 2027 to account for any subsequent
changes to our approach to evaluating SRE petitions or other
inaccuracies in the projection of exempt volumes of gasoline and
diesel.\231\
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\230\ The D.C. Circuit upheld the EPA's change to the regulatory
formula for percentage standards to account for future exempted
volumes in Sinclair, 101 F.4th at 892-93 (challenge to the Reset
Rule). See also 40 CFR 80.1405(c).
\231\ For further discussion on our approach if the actual
volume of exempt gasoline and diesel differs from our projection,
see 2020-2022 RFS Rule RTC Section 7.1.
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D. Percentage Standards
The formulas used to calculate the percentage standards applicable
to obligated parties as a function of their gasoline and diesel fuel
production or importation are provided in 40 CFR 80.1405.\232\ Using
the total applicable volumes shown in Table V.A-1, we have calculated
the percentage standards for 2026 and 2027, as shown in Table V.D-
1.\233\ These percentage standards are included in the regulations at
40 CFR 80.1405(a) and apply to producers and importers of gasoline and
diesel.
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\232\ As described in section VIII.C of this preamble, we are
revising and clarifying the percentage standard equations.
\233\ ``Calculation of Final 2026 and 2027 RFS Percentage
Standards,'' available in the docket for this action. As discussed
in section II.G of this preamble, the 2026 and 2027 percentage
standards without the SRE reallocation volumes are presented in
``Calculation of 2026 and 2027 RFS Percentage Standards Without SRE
Reallocation Volumes,'' also available in the docket for this
action.
[GRAPHIC] [TIFF OMITTED] TR01AP26.073
VI. Partial Waiver of the 2025 Cellulosic Biofuel Volume Requirement
In the Set 1 Rule, the EPA promulgated RFS volume requirements and
percentage standards for 2023-2025 and projected that 1.38 billion
cellulosic RINs would be available for compliance in 2025.
Consequently, we used that volume to establish the 2025 cellulosic
biofuel percentage standard of 0.81 percent.\234\ In the Set 2
proposal, we proposed to partially waive the 2025 cellulosic biofuel
volume requirement and revise the associated 2025 cellulosic biofuel
percentage standard due to a projected shortfall in 2025 cellulosic
biofuel production. In this action, we are finalizing a partial waiver
of the 2025 cellulosic biofuel requirement. Based on cellulosic RIN
generation and retirement data for 2025, we now project that only 1.21
billion cellulosic RINs will be available for compliance in 2025, which
is 0.17 billion fewer than the 1.38 billion RINs projected in the Set 1
Rule. Due to this shortfall and reasons further explained below, we are
finalizing a partial waiver of the 2025 cellulosic biofuel volume
requirement to 1.21 billion RINs (the projected cellulosic RINs
available for compliance in 2025) using the CAA section 211(o)(7)(D)
``cellulosic waiver authority.'' Use of the cellulosic waiver authority
also triggers the availability of CWCs for 2025 as an additional
compliance flexibility for obligated parties.
---------------------------------------------------------------------------
\234\ 40 CFR 80.1405(a).
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We currently project that the supply of advanced biofuel and total
renewable fuel in 2025 will exceed the required volumes, despite the
projected shortfall in cellulosic biofuel. Given the projected surplus
of 2025 advanced RINs, we are not waiving the volume requirements for
any of the other categories of renewable fuel (i.e., BBD, advanced
biofuel, and total renewable fuel).
A. Cellulosic Waiver Authority Statutory Background
The cellulosic waiver authority at CAA section 211(o)(7)(D)(i)
provides that ``[f]or any calendar year for which the projected volume
of cellulosic biofuel production is less than the minimum applicable
volume established under [CAA section 211(o)](2)(B)], as determined by
the Administrator based on the estimate provided under [CAA section
211(o)](3)(A),'' the EPA ``shall reduce the applicable volume of
cellulosic biofuel required under [CAA section 211(o)](2)(B) to the
projected volume available during that calendar year'' and that this
reduction is to be made ``not later than November 30 of the preceding
calendar year.'' For those years in which the EPA ``makes such a
reduction,'' the statute further provides that the EPA ``may also
reduce the applicable volume of renewable fuel and advanced biofuels
requirement . . . by the same or a lesser volume.'' As such, even when
the EPA exercises its cellulosic waiver authority, the determination of
whether to correspondingly reduce the total renewable fuel or advanced
biofuel requirements is discretionary.
When we determine that the projected volume of cellulosic biofuel
production for a given year will be less than the annual applicable
volume established under CAA section 211(o)(2)(B), we are then required
to reduce the applicable volume of cellulosic biofuel for that calendar
year. Pursuant to this
[[Page 16442]]
provision, we established the cellulosic biofuel volume requirement
lower than the CAA section 211(o)(2)(B)(i)(III) statutory volumes
enumerated by Congress for each year from 2010-2022, and again for the
2024 compliance year. Legal challenges to our interpretation of this
statutory provision ensued, leading the D.C. Circuit to evaluate
various aspects of our implementation of the cellulosic waiver
authority.\235\ In 2013 in API, the court held that the EPA must take a
``neutral aim at accuracy'' in determining the projected volume of
cellulosic biofuel available.\236\ In API and Alon Refining Krotz
Springs, Inc. v. EPA, the D.C. Circuit upheld the EPA's decision to use
EIA's projected volume of cellulosic biofuel production to inform the
EPA's projection, without requiring ``slavish adherence by EPA to the
EIA estimate.'' \237\ In Sinclair Wyoming Refining Co. LLC, et al. v.
EPA, the D.C. Circuit upheld the EPA's reading of the statutory phrase
``projected volume available'' to exclude carryover RINs.\238\
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\235\ See, e.g., American Petroleum Institute (API) v. EPA, 706
F.3d 474, 479 (D.C. Cir. 2013) (interpreting the ``projected volume
available'' and indicating that ``the most natural reading of the
provision is to call for a projection that aims at accuracy, not at
deliberately indulging a greater risk of overshooting than
undershooting'' in projecting the available cellulosic biofuel
volume); ACE, 864 F.3d at 730 (determining the EPA's use of the
cellulosic waiver authority to reduce advanced and total renewable
fuel was reasonable); Sinclair, 101 F.4th at 883 (rejecting biofuels
producers' challenge that the EPA must include carryover cellulosic
RINs in its determination of ``projected volume available during
that calendar year'').
\236\ API, 706 F.3d at 476.
\237\ Alon Refining Krotz Springs, Inc. v. EPA, 396 F.3d 628,
660 (D.C. Cir. 2019); API, 607 F.3d at 478.
\238\ Sinclair, 101 F.4th at 883-86.
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In this action, we recognize that we are implementing the
cellulosic waiver authority to reduce the 2025 cellulosic biofuel
volume after the deadline articulated in the statute; CAA section
211(o)(7)(D)(i) directs the EPA to act ``by November 30 of the
preceding calendar year'' to determine whether cellulosic biofuel
production is likely to fall short of the volume requirements in a
given year, and then reduce the standard to the projected volume
available. The statute is silent about the consequences of the EPA
missing this procedural deadline, which the Supreme Court and the D.C.
Circuit have both declined to interpret as Congress intending an agency
to lose authority to act in other contexts, including related
provisions in CAA section 211(o).\239\ Although we have implemented the
cellulosic waiver authority to reduce the cellulosic biofuel volume
after the November 30 deadline on several occasions,\240\ no party has
specifically challenged the EPA's use of the cellulosic waiver
authority after the November 30 deadline and so no court has weighed in
on the EPA's authority to issue a delayed cellulosic waiver. However,
Congress has directed the EPA to waive the cellulosic biofuel volume in
specific circumstances that have been met for 2025. Furthermore, the
compliance deadline for 2025 has not yet passed, suggesting it is still
appropriate to partially waive the 2025 cellulosic biofuel volume
requirement. We read the statute as allowing the EPA to retain
authority to waive the volume requirements for a given year even when
the November 30 deadline in the preceding year has passed, as it has in
this instance.
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\239\ See ACE, 864 F.3d at 721; Monroe Energy, 750 F.3d at 919-
21; National Petrochemical Manufacturers v. EPA, 630 F.3d 145, 152-
158 (D.C. Cir. 2010) (citing Barnhart v. Peabody Coal Co., 537 U.S.
149 (2003)).
\240\ See, e.g., 79 FR 25025 (May 2, 2014) (direct final rule
reducing the 2013 cellulosic biofuel volume in May 2014), 80 FR
77420 (December 14, 2015) (final rule reducing the 2014 and 2015
cellulosic biofuel volumes in December 2015), 87 FR 39600 (July 1,
2022) (final rule reducing the 2020 and 2021 volumes in July 2022).
The EPA has also waived the statutory volume requirements under CAA
section 211(o)(7)(F)--the ``reset'' authority--after the deadline
prescribed in the statute for such a waiver. 87 FR 39600 (July 1,
2022). See also CAA section 211(o)(7)(F), providing that the EPA
shall waive the volume under the provision ``within 1 year'' after
the triggering event. The EPA waived the volumes several years after
the first statutory trigger, and approximately two years after the
second statutory trigger.
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CAA section 211(o)(7)(D)(i) also refers to the ``projected volume
of cellulosic biofuel production'' and the ``projected volume
available,'' which some parties have suggested is another indication
that the provision should or could only be used prospectively. We
believe the best reading of the statute is instead that there are
projections necessary to determine the ``volume of . . . production''
and the ``volume available,'' both when the EPA acts in a timely manner
by November 30 of the preceding year and when the EPA waives the volume
requirement after the November 30 date. The use of the term
``projected'' in the statute does contemplate the need for forward-
looking estimates; however, it does not follow that the statutory
language prohibits the EPA from acting after November 30.\241\ Instead,
the language is consistent with the relevant circumstances when the
statutory deadline of November 30 is met.
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\241\ See Loper Bright Enterprises v. Raimondo, 603 U.S. 369,
400 (2024) (in overruling Chevron deference, the Court observed that
it ``makes no sense to speak of a `permissible' interpretation [of a
statute] that is not the one the court, after applying all relevant
interpretive tools, concludes is best. In the business of statutory
interpretation, if it is not the best, it is not permissible.'').
---------------------------------------------------------------------------
We note that the statutory language indicates that the use of the
cellulosic waiver authority is mandatory. That is, whenever the
projected volume of cellulosic biofuel production is less than the
minimum applicable volume established under CAA section (o)(2)(B), CAA
section 211(o)(7)(D)(i) provides that the EPA ``shall reduce the
applicable volume of cellulosic biofuel required under paragraph (2)(B)
to the projected volume available during that calendar year.'' We
implemented this provision for every year from 2010-2022 and again in
2024 to reduce the cellulosic biofuel volume consistent with the
statutory directive that the EPA shall reduce the volume when the
requisite conditions are met.\242\ As discussed further in RTC Section
8.1, we are acting consistent with this mandatory provision, which
prescribes both when the EPA must issue a waiver and to what volume the
EPA must reduce the cellulosic biofuel standard and does not provide
the EPA discretion in either circumstance.
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\242\ The EPA acknowledges that it did not waive the 2023
cellulosic biofuel volume requirement. https://www.epa.gov/renewable-fuel-standard-program/epa-denial-petition-partial-waiver-2023-cellulosic-biofuel.
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In addition, CAA section 211(o)(7)(D)(ii) directs the EPA to make
CWCs available whenever it reduces the cellulosic biofuel volume under
CAA section 211(o)(7)(D). CWCs--which are offered for sale to obligated
parties at a price established by regulation \243\ per CAA section
211(o)(7)(D)(iii)--provide compliance flexibility for obligated
parties. However, it should be noted that CWCs only satisfy an
obligated party's cellulosic biofuel obligation; unlike a cellulosic
RIN, a CWC cannot be used to satisfy an obligated party's advanced
biofuel or total renewable fuel obligation.\244\ To obtain the same
compliance value as a cellulosic RIN, an obligated party using a CWC
for compliance with the cellulosic biofuel standard needs to also
acquire an advanced or BBD RIN to use towards meeting its advanced
biofuel and total renewable fuel obligations. When CWCs are made
available, they generally limit or cap the price of cellulosic
RINs.\245\
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\243\ 40 CFR 80.1456.
\244\ 72 FR 14726-27 (March 26, 2010).
\245\ See, e.g., 85 FR 7025 (February 6, 2020); 87 FR 39616
(July 1, 2022).
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CAA section 211(o)(7)(D) provides that the EPA may reduce the
applicable volume of total renewable fuel and advanced biofuel in years
when the EPA reduces the applicable volume of cellulosic biofuel under
that provision.
[[Page 16443]]
That reduction must be less than or equal to the reduction in
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cellulosic biofuel. The D.C. Circuit explained:
There is no requirement to reduce these latter quotas, nor does
the statute prescribe any factors that EPA must consider in making
its decision. . . . In the absence of any express or implied
statutory directive to consider particular factors, EPA reasonably
concluded that it enjoys broad discretion regarding whether and in
what circumstances to reduce the advanced biofuel and total
renewable fuel volumes under the cellulosic waiver provision.\246\
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\246\ Monroe, 750 F.3d at 915; see also ACE, 864 F.3d at 721.
Using this discretion, we have, in the past, declined to reduce the
advanced biofuel and total renewable fuel volumes in certain
circumstances.\247\ In other circumstances, we have reduced the
advanced biofuel and total renewable fuel volumes using this
authority.\248\ It is worth noting that the EPA's practice of reducing
the advanced biofuel and total renewable fuel volumes utilizing the
cellulosic waiver authority in past years served to carry through the
partial waiver necessitated by the shortfall in cellulosic biofuel to
the other nested renewable fuel categories when reducing the statutory
cellulosic biofuel volumes established by Congress in 2007. In many
cases, reductions to the advanced biofuel and total renewable fuel
volumes were necessary to enable compliance by obligated parties. For
example, we reduced the cellulosic biofuel volume by over 15 billion
gallons for 2022. Had we not also reduced the 2022 advanced biofuel and
total renewable fuel volumes, these requirements would have been 15
billion gallons higher, far exceeding the market's ability to supply
qualifying renewable fuels, even after considering available carryover
RINs. In contrast, for 2025, a year for which we set the volume
requirements using our set authority, the partial waiver of the
cellulosic biofuel volume requirement is significantly smaller than in
prior years (0.17 billion RINs). The starting point of a waiver in
years prior to 2023 was the statutory table volumes set by Congress in
2007, which were perhaps overly optimistic for production in years
further out in the future. The EPA itself established the 2025 volume
requirements in 2023 based on projection of cellulosic biofuel
production and use in 2025 using the best data and information
available at the time the projections were made. As discussed further
in section VI.B of this preamble, we are not adjusting the 2025 total
renewable fuel and advanced biofuel volumes because those volumes are
likely to be achieved in the market.
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\247\ See, e.g., 78 FR 49794, 49811 (August 15, 2013).
\248\ See, e.g., 80 FR 77420 (December 14, 2015). 81 FR 89746
(December 12, 2016).
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We received comments on various aspects of CAA section 211(o)(7)(D)
and our proposed use of the cellulosic waiver authority. Some
commenters suggested that the provision cannot be used in these
circumstances given that there is not a shortfall in production. Some
commenters suggested that using the cellulosic waiver authority to
waive the 2025 volume is not permitted after November 30, 2024. Other
commenters supported our proposed waiver of the 2025 cellulosic biofuel
requirement and our reading of the statutory requirements. We respond
fully to these comments in RTC Section 8.1.
B. Assessment of Cellulosic RINs Available for Compliance in 2025
Based on the actual cellulosic RIN data available at the time of
this writing, we estimate that 1.21 billion cellulosic RINs will be
available for compliance in 2025. We determined this quantity by taking
the total number of cellulosic RINs generated in 2025 through the date
of this analysis (1.29 billion cellulosic RINs),\249\ and subtracting
the number of cellulosic RINs retired for reasons other than
demonstrating annual compliance (0.08 billion RINs).\250\ As described
in section VI.C of this preamble, we believe this volume represents the
projected volume of cellulosic biofuel production in 2025.
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\249\ See ``Available RINs to date from January 2026'' RIN data
file available at: https://www.epa.gov/fuels-registration-reporting-and-compliance-help/spreadsheet-available-rins-date-renewable-fuel.
\250\ See ``RIN retirement data from January 2026'' RIN data
file available at: https://www.epa.gov/fuels-registration-reporting-and-compliance-help/spreadsheet-rin-retirement-data-renewable-fuel.
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We recognize that this analysis differs from our assessment of
cellulosic biofuel availability in 2024 because both the RFS
regulations and the timing have changed. For 2024, we determined the
total number of cellulosic RINs available for compliance with the 2024
cellulosic biofuel standard, based on the ``Total Net Generation RIN''
dataset--that is, all cellulosic RINs generated in 2024, excluding
those retired due to generation errors (invalid RINs).\251\ This
approach reflects how cellulosic RIN generation operated in 2024,
particularly for biogas-derived renewable fuel. Under the RFS
regulations in place for 2024, cellulosic RINs for biogas-derived
renewable fuel could only be generated once the cellulosic RIN
generator obtained documentation that showed that a specified volume of
biogas-derived renewable fuel had been produced and used as
transportation fuel. Because cellulosic RIN generation was tied to
actual use of biogas-derived renewable fuel as transportation fuel, it
was reasonable to project that all cellulosic RINs that were generated
in 2024 (and not retired due to generation errors) would be available
for obligated parties to demonstrate compliance with their 2024
cellulosic biofuel obligations. Additionally, the partial wavier of the
2024 cellulosic biofuel volume requirement occurred six months after
the end of the 2024 compliance year. Thus, by mid-2025, when we
finalized the partial waiver of the 2024 cellulosic biofuel volume
requirement, the ``Total Net Generation'' RIN dataset was an
appropriate determination of the 2024 cellulosic RINs available for
compliance.
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\251\ 90 FR 29755 (July 7, 2025).
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In contrast, the biogas regulatory reform revisions from the Set 1
Rule that took effect in 2025 decoupled cellulosic RIN generation from
the demonstration that the biogas-derived renewable fuel is used as
transportation fuel. In short, cellulosic RINs for biogas-derived
renewable fuel (i.e., RNG RINs) are now generated prior to use as a
transportation fuel, and such RINs are not separated--and thus made
available for compliance--until the RNG RIN separator obtains
documentation demonstrating that the volume of renewable CNG/LNG was
used as transportation fuel.\252\ Such RIN separation must occur by
December 31 of the subsequent calendar year after the RNG RIN was
separated; otherwise the RIN is expired and must be retired.\253\ For
example, an RNG RIN generated on January 1, 2025, can be separated
until December 31, 2026.\254\ Thus, while we are able to know the
number of cellulosic RINs generated for 2025 shortly after the end of
the 2025 compliance year, there remains some uncertainty regarding the
actual number of these RINs that will be separated and made available
for compliance in 2025 since there are still many months left until
these RINs must be separated (or else will expire).
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\252\ 40 CFR 80.125(d) and (e).
\253\ Id.
\254\ Pursuant to 40 CFR 80.125(d)(5), RNG RINs generated in
2025 will expire if they are not separated by December 31, 2026.
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Given this regulatory shift and the timing of this action, we must
instead make a projection of 2025 cellulosic RIN availability.
Accordingly, we projected that the cellulosic RINs available for
compliance in 2025 is the total number
[[Page 16444]]
of cellulosic RINs generated in 2025 at the time of this analysis,
minus those RINs retired for reasons other than demonstrating annual
compliance. This calculation intentionally excludes RINs retired for
non-transportation purposes from our projection of available cellulosic
RINs, and that exclusion is significant: retirements in this category
grew from 0.4 million RINs in 2024 to 74.5 million in 2025--an increase
we anticipated given the consumption constraints expected to affect the
cellulosic biofuel market.\255\ Excluding these retirements, we project
that the remaining cellulosic RINs that were generated in 2025 will
ultimately be separated and available for use toward 2025 compliance.
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\255\ We discuss future consumption constraints in further
detail in section III of this preamble and RIA Chapter 7.
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Finally, we note that if, for the partial waiver of the 2024
cellulosic biofuel volume requirement, we had used the same methods in
this action (i.e., excluding all cellulosic RINs retired for reasons
other than demonstrating annual compliance) rather than excluding only
those cellulosic RINs retired due to generation errors (invalid RINs),
then the partial waiver of the 2024 cellulosic biofuel requirement
would not have been materially different.\256\ Together with the 2024
regulations governing cellulosic RIN generation for biogas-derived
renewable fuel, this confirms that our previous approach to estimating
the RINs available for compliance was appropriate for the time.
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\256\ In our assessment of cellulosic biofuel availability in
the rule for the partial waiver of the 2024 cellulosic biofuel
volume requirement, we projected that only 1.01 billion cellulosic
RINs were generated and available in 2024. 90 FR 29755 (July 7,
2025). If we were to have calculated that figure using the same
methodology described in this action, there would still have been
1.01 billion cellulosic RINs.
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We intend to utilize the approach described in this action going
forward, both in projecting the volume of cellulosic biofuel that will
be used (as described in section III of this preamble) and in
evaluating any future waivers under CAA section 211(o)(7)(D).
C. Implementation of the Cellulosic Waiver Authority
The cellulosic waiver authority is specific regarding when it is
available and how the volume reduction should be determined when acting
under the authority, as discussed in section VI.A of this preamble. We
have determined that ``the projected volume of cellulosic biofuel
production is less than the minimum applicable volume'' for 2025. In
the Set 1 Rule, we established the ``minimum applicable volume'' of
cellulosic biofuel for 2025 to be 1.38 billion RINs and used that
volume to calculate the 2025 cellulosic biofuel percentage standard of
0.81 percent.\257\ The actual number of cellulosic RINs that obligated
parties will ultimately need to retire for compliance with the current
standard will not be known until after the 2025 compliance deadline,
which will be determined after the promulgation of the 2026 percentage
standards in this action,\258\ when obligated parties report to the EPA
their 2025 gasoline and diesel production and import volumes.\259\
However, for the purpose of making a decision to partially waive the
2025 cellulosic biofuel volume requirement, we have assumed that the
actual total 2025 cellulosic biofuel obligation, if not reduced, will
be 1.38 billion RINs.\260\
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\257\ 88 FR 44470-71 (July 12, 2023).
\258\ The compliance deadline for the 2025 standards will be the
first quarterly reporting deadline after the 2026 standards are
effective. 40 CFR 80.1451(f)(1)(i)(A).
\259\ 40 CFR 80.1451 and 80.1427(a).
\260\ Because the compliance obligation is calculated on a
percentage basis, if the actual gasoline and diesel volumes reported
by obligated parties differ from the projected gasoline and diesel
volumes that were used to derive the percentage standard, then the
actual number of RINs required for compliance will differ from the
projected volume that was used to calculate the percentage standard.
Although we rely on the 1.38-billion-RIN projection for 2025 in the
Set 1 Rule that was the basis for the 2025 cellulosic biofuel
percentage standard, we would reach the same conclusion to waive the
2025 cellulosic biofuel volume requirement, for the reasons stated
below, using a higher RIN obligation (i.e., a higher gasoline and
diesel projection).
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We currently estimate that only 1.21 billion 2025 cellulosic RINs
are projected to be generated and separated.\261\ To qualify as
cellulosic biofuel, a fuel must be produced from qualifying renewable
biomass, derived from cellulose, hemi-cellulose, or lignin, and have
lifecycle GHG emissions that are at least 60 percent less than the
baseline GHG emissions. Fuels that meet these criteria (along with
other relevant statutory and regulatory provisions) qualify to generate
cellulosic RINs. RIN-generating fuels must also be used in the covered
location to replace or reduce the quantity of fossil fuel present in
transportation fuel, heating oil, or jet fuel and such fuels that meet
this criterion are generally eligible to be separated. Thus, only fuels
for which cellulosic RINs have been generated and separated fully meet
the requirements to qualify as cellulosic biofuel and thus are
``available.'' We therefore believe our estimate of the number of 2025
cellulosic RINs that have been generated and separated represents the
projected volume of cellulosic biofuel production in 2025. This
projected volume (1.21 billion gallons) is 0.17 billion fewer RINs than
the 1.38 billion RINs needed to comply with the original 2025
cellulosic biofuel standard, a shortfall of approximately 13 percent.
We therefore find that the shortfall in the projected volume of
cellulosic biofuel production in 2025 relative to the required volume
triggers the need for implementation of the cellulosic waiver authority
for 2025.
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\261\ RIA Chapter 7.1.3.
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When the EPA determines that a waiver of the cellulosic biofuel
volume requirement is appropriate under CAA section 211(o)(7)(D)(i),
the EPA must then reduce the required cellulosic biofuel volume to
``the projected volume available.'' We have previously interpreted the
phrase ``projected volume available'' to exclude carryover RINs when
determining the volume adjustment to be made; this interpretation was
affirmed by the D.C. Circuit in Sinclair.\262\ We have consistently
interpreted the ``projected volume available'' as ``the volume of
qualifying cellulosic biofuel projected to be produced or imported and
available for use as transportation fuel in the U.S. in that year.''
\263\ In determining the ``projected volume available,'' the EPA must
take a ``neutral aim at accuracy.'' \264\
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\262\ Sinclair, 101 F.4th at 883-86.
\263\ See, e.g., 87 FR 39600 (July 1, 2022); see also Sinclair,
101 F.4th at 883-86.
\264\ API, 706 F.3d at 479.
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As discussed in section VI.B of this preamble, the projected volume
of cellulosic biofuel available in 2025 is 1.21 billion RINs. Thus,
when the cellulosic waiver authority is applied, we are only able to
reduce the 2025 cellulosic biofuel volume to the projected volume
available of 1.21 billion RINs. However, in accordance with the
statute, we are also required to make CWCs available to obligated
parties, which can be used--along with additional BBD or advanced
RINs--to cover any remaining shortfall.\265\ With the waiver of the
cellulosic biofuel requirement for 2025, we are making CWCs available
to obligated parties at a price of $1.91.\266\ The availability of CWCs
helps ensure RFS program stability by reducing the likelihood that
obligated parties may be forced into non-compliance with their RFS
obligations; any obligated party that is
[[Page 16445]]
unable to acquire sufficient cellulosic RINs to comply with their 2025
cellulosic biofuel obligations--plus any cellulosic RIN deficit carried
from 2024--will be able to purchase CWCs to cover the shortfall.\267\
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\265\ Pursuant to 40 CFR 80.1405(d), the CWC price is calculated
using the methodology specified in 40 CFR 80.1456(d) and posted on
the EPA's website at: https://www.epa.gov/renewable-fuel-standard-program/cellulosic-waiver-credits-under-renewable-fuel-standard-program.
\266\ See ``Cellulosic Waiver Credit Price Calculation for
2025,'' available in the docket for this action.
\267\ Unlike cellulosic RINs--which apply towards an obligated
party's cellulosic biofuel, advanced biofuel, and total renewable
fuel obligations--CWCs only apply towards an obligated party's
cellulosic biofuel obligation and not toward their nested advanced
biofuel and total renewable fuel obligation. Obligated parties that
satisfy their cellulosic biofuel obligations with CWCs would
therefore also have to purchase additional BBD or advanced RINs to
meet their associated advanced biofuel and total renewable fuel
obligations.
---------------------------------------------------------------------------
Given that ``the projected volume of cellulosic biofuel production
is less than the minimum applicable volume'' for 2025, we are
implementing the cellulosic waiver authority to waive the 2025
cellulosic biofuel volume requirement to 1.21 billion RINs, a reduction
of 0.17 billion RINs from the original volume requirement of 1.38
billion RINs. This volume requirement matches the projected 1.21
billion cellulosic RINs available for 2025.
Finally, CAA section 211(o)(7)(D) provides that the EPA may reduce
the applicable volume of total renewable fuel and advanced biofuel in
years when the EPA reduces the applicable volume of cellulosic biofuel
under that provision. That reduction must be less than or equal to the
reduction in cellulosic biofuel. The D.C. Circuit concluded that the
cellulosic waiver authority provides the EPA ``broad discretion'' to
consider a variety of factors in determining whether to reduce the
total renewable fuel and advanced biofuel volumes under this
provision.\268\ RIN generation data from EMTS indicates that there will
likely be a sufficient supply of RINs to meet the advanced biofuel and
total renewable fuel volume requirements in 2025. Advanced and total
RIN generation in 2025 (8.57 billion RINs and 23.23 billion RINs,
respectively) exceeded the 2025 volume requirements (7.33 billion RINs
and 22.33 billion RINs, respectively).\269\ These RIN generation
numbers indicate that the market is capable of meeting the 2025
advanced biofuel and total renewable volume requirements even with the
projected shortfall in cellulosic biofuel. Further, the significant
oversupply of RINs in previous years indicates that there will be
sufficient carryover RINs to facilitate compliance.
---------------------------------------------------------------------------
\268\ ACE, 864 F.3d at 730-34; see also Monroe, 750 F.3d 909.
\269\ See ``Total Net Generation'' RIN data table at: https://www.epa.gov/fuels-registration-reporting-and-compliance-help/rins-generated-transactions.
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We believe reductions to the 2025 advanced biofuel and total
renewable fuel volumes are not necessary or warranted based on the
available supply data, given that the market has provided volumes of
these fuels in excess of the requirements established in the Set 1
Rule. Reductions in these volume requirements at this time would only
serve to increase the number of advanced and total carryover RINs.
Historically, we have declined to take actions that would inflate the
number of available carryover RINs.\270\
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\270\ 87 FR 39600, 39621 (July 1, 2022) (``While EPA has
previously set the RFS standards at what the market actually used
(like for 2014 and 2015 in the 2014-2016 rule), we have never
intentionally reduced the standards with the express intent to
inflate the size of the carryover RIN bank.''); 2020-2022 RFS Rule
RTC Section 2.6.1.
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D. Calculation of 2025 Cellulosic Biofuel Percentage Standard
As described in section VI.C of this preamble, we are implementing
the cellulosic waiver authority to partially waive the 2025 cellulosic
biofuel volume requirement from 1.38 billion RINs to 1.21 billion RINs.
As described in section V of this preamble, the formula used to
calculate the cellulosic biofuel percentage standard applicable to
obligated parties as a function of their gasoline and diesel fuel
production or importation is provided in 40 CFR 80.1405. Using the same
values from the Set 1 Rule for the variables in this formula other than
RFVCB (the cellulosic biofuel volume),\271\ we have
calculated the revised cellulosic biofuel percentage standard for 2025
to be 0.71 percent, down from 0.81 percent.\272\ This percentage
standard is included in the regulations at 40 CFR 80.1405(a) and
applies to producers and importers of gasoline and diesel.
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\271\ 88 FR 44519-21 (July 12, 2023).
\272\ ``Calculation of Final 2025 Cellulosic Biofuel Percentage
Standard,'' available in the docket for this action.
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VII. Removal of Renewable Electricity From the RFS Program
The EPA previously promulgated regulations permitting RIN
generation for renewable electricity (commonly referred to as eRINs).
In the Set 2 proposal, the EPA proposed to remove renewable electricity
as a qualifying renewable fuel under the RFS program, and in this
action we are finalizing the removal. We do so under a new, better
interpretation of the statute, consistent with our proposal, that finds
that renewable electricity is not a qualifying renewable fuel.
A. Historical Treatment of Renewable Electricity in the RFS Program
The statutory definition of ``renewable fuel'' in CAA section
211(o)(1)(J) requires that renewable fuel be produced from renewable
biomass and used to replace or reduce the quantity of fossil fuel
present in a transportation fuel. CAA section 211(o)(1)(B)(ii)(B)
further indicates that the definition of renewable fuel may include
certain non-liquid biofuels, such as biogas produced through the
conversion of organic matter from renewable biomass. We have permitted
RIN generation for non-liquid biofuels from biogas that are produced
through the conversion of organic matter from renewable biomass, such
as renewable CNG/LNG. Thus, renewable fuels under the RFS program can
be broadly categorized as either liquid biofuels (e.g., ethanol and
biodiesel) or non-liquid biofuels (e.g., renewable CNG/LNG that is
produced from qualifying biogas), so long as these fuels are used as
transportation fuel. Non-liquid biofuels have played a part in the RFS
program since the RFS2 Rule was promulgated in 2010. In that rule, we
specified that electricity, as well as natural gas and propane,
produced from renewable biomass could be a RIN-generating renewable
fuel under the RFS program. However, we stipulated that electricity
could only be a RIN-generating renewable fuel if it could be
demonstrated that specific quantities of electricity ``are actually
used as a transportation fuel[ ].'' \273\ The record for the RFS2 Rule
did not further elaborate on how renewable electricity (i.e.,
electricity that is derived from renewable biomass) satisfies the
statutory definition of renewable fuel or is consistent with other
applicable statutory requirements.
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\273\ 74 FR 14670, 14686 (March 26, 2010).
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Pursuant to the mistaken determination that renewable electricity
is, in certain circumstances, a qualifying renewable fuel, in the RFS2
Rule we also established regulatory provisions governing the generation
of RINs representing renewable electricity in anticipation of a future
action that would provide a RIN-generating pathway for electricity
produced from renewable biomass and used as transportation fuel. In
doing so, we discussed the relevant differences between liquid and non-
liquid biofuels and established regulatory provisions for renewable
electricity that recognized those distinctions.\274\ In a separate
action also in 2010, we promulgated a definition of ``renewable
electricity'' to ``clarify that electricity must meet the definition of
renewable fuel in order to qualify for RINs.'' \275\
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\274\ 75 FR 14670, 14729 (March 26, 2010).
\275\ 75 FR 26026, 26031 (May 10, 2010).
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[[Page 16446]]
In 2014, we established novel RIN-generating pathways for
electricity produced from biogas from landfills and waste
digesters.\276\ In the same 2014 rulemaking, we updated the regulations
governing RIN generation for renewable electricity.\277\ In general,
the regulatory requirements were intended to ensure that any RINs
generated correspond to electricity that meets the statutory criteria
to qualify as renewable fuel. For example, the electricity must be
produced from renewable biomass under an approved pathway
(demonstrating it meets the required GHG reduction threshold), the
electricity must be sold for use as transportation fuel and for no
other purpose (and the RIN generator must provide documentation to
support its use as transportation fuel), and it must be the case that
no other party relied on the renewable electricity for the generation
of RINs.
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\276\ Rows Q and T of Table 1 to 40 CFR 80.1426. 79 FR 42128
(July 18, 2014).
\277\ 40 CFR 80.1426(f)(10)(i) and (f)(11)(i).
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Although renewable electricity has been part of the RFS program
since 2010, and a pathway has existed since 2014 for renewable
electricity produced from biogas, the EPA has never registered a party
to generate RINs for renewable electricity. We intended our proposed
updates to the ``eRIN'' regulatory program for renewable electricity as
part of the Set 1 proposal in December 2022 to revise the existing
regulations governing renewable electricity to allow RIN generation
under the existing pathways.\278\ However, the Set 1 Rule was
ultimately finalized without the proposed eRIN regulatory program,
leaving the previously existing, inadequate regulations governing
renewable electricity in place.
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\278\ 87 FR 80582 (December 30, 2022).
---------------------------------------------------------------------------
B. Statutory Basis for Removal of Renewable Electricity From the RFS
Program
In this final rule, and consistent with the Set 2 proposal, we are
reversing the determination in the RFS2 Rule that renewable electricity
is eligible to generate RINs because the statute does not permit
renewable electricity to generate RINs under the RFS program. As such,
we are finalizing the removal of renewable electricity as a qualifying
renewable fuel under the RFS program. This decision marks a change in
position from the Agency's prior interpretations discussed above but is
well within our authority to review and revise prior policies by
acknowledging the change, offering a reasoned explanation for the
change, and considering reliance interests, if any, that counsel
against the change.\279\ Given the regulatory history of the eRIN
regulatory program, we do not believe that significant and cognizable
reliance interests have arisen in the renewable electricity
interpretation set out in these prior actions. As discussed in section
VII.A of this preamble, although we previously determined that
electricity could qualify as a renewable fuel under the RFS program and
promulgated regulations for the generation of RINs for renewable
electricity, the EPA has not registered any parties to generate RINs
for renewable electricity and no RINs representing renewable
electricity have ever been generated. As explained further below, this
change is supported by the best reading of the statute that engages
fully with relevant interpretive tools. We have repeatedly acknowledged
the difficulties in formulating a workable eRIN regulatory program,
including when we decided not to finalize additional regulations as
part of the Set 1 Rule. In this final rule, we conclude that CAA
section 211(o)(1)(J), read in context and considering the structure of
the statute as a cohesive whole, does not authorize such a program.
This explains, in part, the difficulty in implementing such a program
given the applicable requirements and structure of the statute.
---------------------------------------------------------------------------
\279\ See FDA v. Wages & White Lion Invs., L.L.C., 604 U.S. 542,
567-69 (2025); FCC v. Fox Television Stations, Inc., 556 U.S. 502,
514 (2009); Motor Vehicle Mfrs. Ass'n of U.S., Inc. v. State Farm
Mut. Auto. Ins. Co., 463 U.S. 29, 43 (1983).
---------------------------------------------------------------------------
We are removing renewable electricity from the RFS program on the
grounds that, under the best reading of the statute, renewable
electricity is not a renewable fuel. Congress defined renewable fuel in
CAA section 211(o)(1)(J) as ``fuel that is produced from renewable
biomass and that is used to replace or reduce the quantity of fossil
fuel present in a transportation fuel.'' Congress further defined
transportation fuel in CAA section 211(o)(1)(L) as ``fuel for use in
motor vehicles, motor vehicle engines, nonroad vehicles, or nonroad
engines.'' We have consistently interpreted ``renewable fuel'' to
encompass three key components: (1) there must be a fuel; (2) the fuel
must be produced from renewable biomass; and (3) the fuel must be used
to replace or reduce fossil fuel present in a transportation fuel.\280\
While we previously, in 2010, assumed that renewable electricity could
meet this definition, we have revisited the statutory analysis based on
the text of the statute and consistent with intervening Supreme Court
decisions on standards for statutory interpretation.\281\
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\280\ 87 FR 80582, 80634 (December 30, 2022); 87 FR 73956-57
(December 2, 2022) (discussing what fuels can generate RINs).
\281\ Loper Bright, 603 U.S. 369; see also West Virginia v. EPA,
597 U.S. 697 (2022).
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Our analysis focuses on the last component of the renewable fuel
definition--that the fuel must be used to replace or reduce the
quantity of fossil fuel present in a transportation fuel. The best
reading of this language is that a renewable fuel must physically
displace a volume of fossil fuel that is present in a motor vehicle or
motor vehicle engine. The statutory definition uses the phrases
``quantity of fossil fuel'' and ``present in a transportation fuel.''
The plain meanings of ``present'' include ``now existing or in
progress,'' ``being in view or at hand,'' ``existing in something
mentioned or under consideration,'' and ``constituting the one actually
involved, at hand, or being considered.'' \282\ Each of these
definitions indicates that for something to be ``present,'' it must
physically and actively be involved or at hand. The word ``quantity''
in the definition of renewable fuel reinforces that there must be a
measurable physical unit of fossil fuel involved that is replaced or
reduced.
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\282\ Merriam Webster online, definition of ``present,'' https://www.merriam-webster.com/dictionary/present, last accessed January
26, 2026.
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The definition of transportation fuel provides that the relevant
scale at which renewable fuel must replace or reduce fossil fuel is in
a motor vehicle, motor vehicle engine, nonroad vehicle, or nonroad
engine (hereinafter ``motor vehicle''), as opposed to in the U.S.
transportation fuel supply overall. It is not sufficient for a biofuel
to be capable of reducing or replacing fossil fuel in the abstract--it
must replace or reduce a measurable, physical volume of fossil fuel
that is actually at hand in a fuel in a motor vehicle.
Electricity cannot replace or reduce a volume of fossil fuel that
is present in a motor vehicle or motor vehicle engine. Rather, to the
extent it does replace or reduce fossil fuel, it does so at the level
of the national, aggregate transportation fuel supply. But it is not
fungible with fossil fuel that is present in a motor vehicle and,
therefore, does not meet the statutory definition of renewable fuel.
In contrast, biogas that is cleaned up into RNG (and then
compressed into renewable CNG/LNG) can replace and reduce fossil
natural gas that is used in a motor vehicle. That is, natural gas that
is used in a motor vehicle powered by CNG/LNG is a fossil fuel, and
renewable
[[Page 16447]]
CNG/LNG can replace or reduce the physical volume of fossil fuel in
that motor vehicle. CNG/LNG produced from qualifying biogas is
therefore a renewable fuel. But because electricity cannot physically
displace fossil fuel present in a motor vehicle, it is not a renewable
fuel. While it is true that electricity produced from biogas does, or
may, replace or reduce electricity that would have been produced from
fossil fuels, such displacement occurs in an electric generating unit,
not in a motor vehicle. Renewable electricity does not replace or
reduce fossil fuel that is present in a transportation fuel in a motor
vehicle. Said a different way, electricity is not a fossil fuel but is
rather produced from fossil fuels. Renewable biomass may be swapped for
fossil fuels in an electric generating unit, but not in a motor
vehicle.
Additionally, we note that ``electricity'' is not mentioned in CAA
section 211(o), in contrast to over fifty references to liquid fuels.
The RFS program statutory language in CAA section 211(o) speaks to
``volumes'' and ``gallons'' of renewable fuel. The fact that the CAA
explicitly references physical units implies that the RFS program was
intended to measure, and thus include, only quantities of liquid or
gaseous fuels. To this end, when Congress amended the RFS program in
2007, it revised the definition of ``renewable fuel'' and elaborated
the types of fuels that are included under this definition.\283\ When
it did so, Congress was aware that electricity was being used to power
motor vehicles.\284\ And although it explicitly referenced biogas in
the list of fuels eligible for consideration as advanced biofuel, it
declined to include electricity in this list, or to reference
electricity in any other way in CAA section 211(o). This is further
evidence that Congress did not intend for electricity to qualify as a
renewable fuel under the RFS program.
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\283\ Compare Public Law 109-58 Sec. 1501(a)(2) (2005), with 42
U.S.C. 7545(o)(1).
\284\ See, e.g., Public Law 110-140, sec. 206 (2007) (directing
the EPA to conduct a study of credits for use of renewable
electricity in electric vehicles).
---------------------------------------------------------------------------
We received comments both in support of and in opposition to our
proposed interpretation and determination. Many commenters in support
of the proposed removal of renewable electricity agreed that
electricity cannot be a renewable fuel because it does not physically
replace fossil fuel in a motor vehicle, and that if Congress had
intended for the EPA to include electricity in the RFS program, it
would have explicitly stated so. Some commenters also cited policy
reasons for excluding electricity from the RFS program, including
impacts on the economy and competition for feedstocks. Commenters
opposed to the proposed removal of renewable electricity argued, among
other things, that Congress deliberately drafted the statutory
definitions of renewable fuel and transportation fuel to be broad
enough to encompass electricity. Reasons for opposing the proposed
removal of renewable electricity on policy grounds included support for
biogas markets and for domestic manufacturing. We respond to these and
all other significant comments in RTC Section 10.
In addition, some commenters noted that, despite having included
renewable electricity regulations under the RFS program since
2010,\285\ the EPA has been unable to implement those regulations.
Indeed, as early as 2016 the EPA stated that those regulations
``created an untenable environment for the approval of any single
registration request by the EPA.'' \286\ The Agency further explained
that the RIN generation regulations for renewable electricity were
inadequate to prevent double counting of electricity claimed for
transportation use, which is fundamental to ensuring RIN integrity and
the volume requirements under the RFS program.\287\ Specifically,
because the regulations allowed any party that could demonstrate
compliance with the applicable requirements to be the RIN generator, it
was possible under those regulations for multiple parties to claim RIN
generation for the same quantity of renewable electricity. But if RINs
do not correspond to the actual volume of renewable fuel, the credit
mechanism breaks down.\288\ Thus, even if the EPA was not finalizing
the complete removal of renewable electricity from all RFS regulations
because it does not meet the definition of ``renewable fuel'' under CAA
section 211(o), it would remove the implementing regulations for
renewable electricity because they are unworkable. That is, in addition
to and as an alternative to the final action the Agency is taking here
to interpret the statute to exclude renewable electricity from the RFS
program, the EPA is removing the implementing regulations for renewable
electricity in 40 CFR part 80, subpart M, on the basis that those
regulations fail to adequately implement the RFS program with
integrity.\289\
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\285\ The EPA significantly updated the renewable electricity
regulations in 2014, including by adding the pathways for renewable
electricity that would have, in theory, allowed for RIN generation.
79 FR 42128 (July 18, 2014).
\286\ 81 FR 80828, 80891 (November 16, 2016); see also EPA Final
Brief defending decision to not include renewable electricity
volumes in 2019 Annual Volumes Rule, Growth Energy v. EPA, D.C. Cir.
No. 19-1023, Doc. # 1831996 at 74-77 (filed March 5, 2020).
\287\ 81 FR 80891 (November 16, 2016).
\288\ See CAA section 211(o)(5)(A) (providing that the EPA's
regulations under CAA section 211(o)(2)(A) shall provide for the
generation of an appropriate amount of credits).
\289\ These implementing regulations include the pathway,
equivalence value, RIN generation, RIN separation, registration,
reporting, and recordkeeping requirements for renewable electricity.
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C. Implementation of Removal of Renewable Electricity From the RFS
Program
Our determination that electricity is not a renewable fuel is
effectuated by removing all regulatory provisions associated with
renewable electricity from 40 CFR part 80, subparts A and M. First, we
are removing the definition of ``renewable electricity'' from the
definitions in 40 CFR 80.2. Second, we are removing the regulations
associated with generating RINs for renewable electricity. These
actions include removing the renewable electricity pathways in table 1
to 40 CFR 80.1426, the renewable electricity equivalence value in 40
CFR 80.1415(b), the renewable electricity RIN generation requirements
in 40 CFR 80.1426(f)(10) and (11), the renewable electricity RIN
separation requirements in 40 CFR 80.1429(b)(5), and all associated
registration, reporting, and recordkeeping requirements in 40 CFR
80.1450(b)(1), 80.1451(b)(1), and 80.1454(k) and (l).
D. Withdrawal of December 2022 Proposal Regarding Renewable Electricity
We previously proposed to restructure the regulatory provisions for
renewable electricity in the December 2022 Set 1 proposal.\290\ We
received a wide variety of comments on all aspects of our proposal,
with stakeholder positions ranging from strong support to strong
opposition. In light of the significant number and complexity of
comments received, we did not finalize the proposed revisions to the
electricity provisions with the rest of the Set 1 Rule in July
2023.\291\
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\290\ 87 FR 80582 (December 30, 2022).
\291\ 88 FR 44468, 44471 (July 12, 2023).
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We are now withdrawing the December 2022 proposal pertaining to
renewable electricity. The primary reason for doing so is that we are
removing renewable electricity from the RFS program on the basis that
CAA section 211(o) does not allow for it. This action renders our
December 2022 proposal moot. We are formally
[[Page 16448]]
withdrawing this proposal to avoid any potential confusion about its
status.
VIII. Other Changes to RFS Regulations
This section describes the other regulatory changes beyond those
already discussed that we are finalizing for the fuel quality and RFS
programs. We address comments related to these regulatory changes in
RTC Section 12.
A. Renewable Diesel, Naphtha, and Jet Fuel Equivalence Values
In this action, we are finalizing revisions to the equivalence
values for renewable diesel, naphtha, and jet fuel to account for the
non-renewable portion of these fuels, as they are all typically
produced using a hydrotreating process. Due to an oversight when
initially establishing the equivalence values for these fuels, the
existing equivalence values for these fuels do not take into
consideration the fact that a portion of the hydrogen in these fuels
originates from the hydrogen used in the hydrotreating process, nearly
all of which is produced from fossil natural gas. Equivalence values
dictate the number of RINs a renewable fuel producer or importer can
generate per gallon of fuel they produce (e.g., a party who produces a
renewable fuel with an equivalence value of 1.5 can generate 1.5 RINs
for every gallon of qualifying fuel they produce). By not accounting
for the hydrogen produced from fossil natural gas in these fuels, the
current equivalence values are artificially high and effectively allow
these hydrotreated fuels to generate RINs for non-renewable content.
This conflicts not only with the statutory direction that fuels must be
produced from renewable biomass to be eligible under the RFS program,
but also with the approach EPA has taken for other biofuels that
contain non-renewable content (e.g., biodiesel, which by standard
practice is generally comprised partially of fossil fuel-based
methanol).\292\
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\292\ See ``Calculation of Equivalence Values for renewable
fuels under the RFS program,'' Docket Item No. EPA-HQ-OAR-2005-0161-
0046.
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In the Set 2 proposal, we proposed to reduce the equivalence value
for renewable diesel to 1.6 and establish equivalence values of 1.6 for
renewable jet fuel and 1.4 for renewable naphtha. Stakeholders
submitted comments on multiple aspects of the proposed revisions,
including comments on the EPA's technical analysis supporting the
proposed equivalence values and policy arguments for why higher or
lower equivalence values for these fuels may be appropriate. Some of
these comments are discussed briefly in this section, and we respond
fully to comments in RTC Section 11.1.
In this action, we are finalizing equivalence values for renewable
diesel and renewable jet fuel that are lower than was proposed and
finalizing the equivalence value for renewable naphtha as proposed.
Specifically, we are reducing the equivalence value for renewable
diesel specified in 40 CFR 80.1415(b) from 1.7 to 1.5 and specifying
equivalence values of 1.4 for renewable naphtha and 1.5 for renewable
jet fuel. Equivalence values for renewable naphtha and renewable jet
fuel were not previously specified in 40 CFR 80.1415(b), but were
instead determined on a facility-by-facility basis using an equation
specified in 40 CFR 80.1415(c). Previously approved equivalence values
for naphtha ranged from 1.4 to 1.5 with the majority approved at 1.5,
and for renewable jet fuel ranged from 1.6 to 1.7, with the majority
approved at 1.6.\293\ These equivalence values properly account for the
fossil-derived hydrogen found in most renewable diesel, renewable
naphtha, and renewable jet fuel. The final equivalence values for
renewable diesel and renewable jet fuel differ from the proposed
equivalence values for the reasons discussed below.
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\293\ See ``Feedstock Summary'' RIN data table at: https://www.epa.gov/fuels-registration-reporting-and-compliance-help/rins-generated-transactions.
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The equivalence values for renewable diesel, renewable naphtha, and
renewable jet fuel are based on our technical assessment of the
proportion of these fuels that are derived from renewable biomass and
the average energy content of these fuels. The equivalence values we
are establishing in this action better align the equivalence values of
these fuels with the approach used for other biofuels that contain non-
renewable content described above.\294\
---------------------------------------------------------------------------
\294\ See ``Calculation of Equivalence Values and Energy Content
for Renewable Diesel, Naphtha, and Jet Fuel for the Set 2 FRM,''
available in the docket for this action.
---------------------------------------------------------------------------
When we proposed to modify the equivalence values for renewable
diesel, renewable naphtha, and renewable jet fuel, we provided
documentation of our technical evaluation of the proportion of these
fuels derived from renewable biomass and their average energy content.
Our proposal was consistent with the EPA's longstanding practice of
calculating equivalence values based on these factors.\295\ We received
several comments on this technical evaluation and have revised our
analysis based on these comments, along with additional data.
Consistent with our initial analysis, our updated analysis demonstrates
that the proportion of each of these fuels derived from renewable
biomass varies slightly depending on the feedstocks used to produce
these fuels. Further, the energy content of the fuels produced can vary
depending on a variety of factors, including the feedstocks used to
produce the fuels, the operating conditions of the renewable fuel
production facility, the age of the catalyst used in the production
process, and other factors.
---------------------------------------------------------------------------
\295\ See 40 CFR 80.1415. Equivalence values in the RFS program
have been based on the energy content and portion of the fuel
derived from renewable biomass since RFS2 Rule.
---------------------------------------------------------------------------
Based on our updated technical analysis, we have estimated the
average renewable content of renewable diesel (93.9 percent), renewable
jet fuel produced using distillation and hydrocracking technologies
(96.2 percent and 92.1 percent, respectively), and renewable naphtha
(91.7 percent).\296\ These estimates are based on a representative mix
of feedstocks that are used to produce these fuels. We then used these
estimates of the average proportion of these fuels that is derived from
renewable biomass together with our estimates of the average energy
content of these fuels as the basis for calculating the appropriate
equivalence values for these fuels.\297\ Based on our updated analysis,
we are finalizing equivalence values of 1.5 for renewable diesel, 1.5
for renewable jet fuel, and 1.4 for renewable naphtha.
---------------------------------------------------------------------------
\296\ See ``Calculation of Equivalence Values and Energy Content
for Renewable Diesel, Naphtha, and Jet Fuel for the Set 2 FRM,''
available in the docket for this action.
\297\ Id.
---------------------------------------------------------------------------
We believe that the equivalence values we are finalizing in this
action reflect the appropriate equivalence value for the vast majority
of renewable jet fuel and naphtha. However, our analysis indicates that
the appropriate equivalence value for renewable diesel could be either
1.5 or 1.6, depending on the renewable content and energy content of
the renewable diesel. The equivalence value we are finalizing in this
action for renewable diesel (1.5) is therefore slightly conservative,
as we expect that renewable diesel with relatively high renewable
content or energy content could qualify for an equivalence value of
1.6. We believe establishing a slightly conservative equivalence value
for renewable diesel is appropriate since renewable diesel producers
that believe their fuel should qualify for a higher equivalence value
are able to apply for a higher equivalence value under 40 CFR 80.1415.
This application process
[[Page 16449]]
allows renewable diesel with a sufficiently high energy content or
renewable content to qualify for an equivalence value of 1.6 without
over-crediting other renewable diesel that does not meet the necessary
thresholds. Were we to establish a higher default equivalence value,
some quantity of renewable diesel would continue to be over-credited.
We are not changing the regulations governing the application
process for equivalence values in this action, and we note that this
application process is available to any producer or importer of any
renewable fuel--including renewable jet fuel and naphtha--who has
reason to believe that an equivalence value that differs from the
default equivalence value is warranted. In these applications,
renewable diesel producers may use the average renewable content for
renewable diesel we have estimated for this action (93.9 percent) or
may provide justification for an alternative renewable content.
Renewable diesel producers that choose to base their application on the
average renewable content will only need to submit testing results of
the energy content of their renewable diesel in their application. At
this time, consistent with the regulations in 40 CFR 80.1415, we are
not requiring renewable diesel producers to submit testing information
supporting their equivalence value petitions on an ongoing (e.g.,
quarterly) basis. However, if we become aware of information that
suggests the testing results we receive through this application
process are not representative of the renewable fuel actually produced
for commercial scale, we may add regular testing requirements to the
regulations in a future action.
We recognize that changing the equivalence values for these fuels
in the middle of a compliance year has the potential to cause confusion
for renewable fuel producers that generate RINs and obligated parties
that are required to acquire RINs for compliance. We also recognize
that it may take some time for renewable diesel producers that could
qualify for an equivalence value of 1.6 to submit an application and
for the EPA to process those applications. We are therefore delaying
the effective date for the new equivalence values in this action for
renewable diesel (1.5), renewable jet fuel (1.5), and renewable naphtha
(1.4) to January 1, 2027. Furthermore, we anticipate that we will be
able to process any applications for a higher equivalence value that
are submitted in a timely manner before January 1, 2027.
Stakeholders submitted comments on several aspects of the proposed
equivalence value changes. Several of these comments are discussed
briefly below, and we respond fully to these comments in RIA Chapter
11.1. Several commenters provided input on our technical analysis of
the average energy content and renewable content of renewable diesel,
jet fuel, and naphtha. As discussed previously, we have considered
these comments in our updated analysis for this final rule.
Some commenters suggested that, in order to achieve desired policy
outcomes, we should establish equivalence values that are not strictly
based on the energy content and renewable content of renewable diesel,
jet fuel, and naphtha. For example, several commenters stated that we
should establish higher equivalence values for renewable jet fuel to
support this relatively new industry, while other commenters stated
that we should establish an equivalence value of 1.5 for renewable
diesel (or alternatively increase the equivalence value for biodiesel
to 1.6) to provide parity in the number of RINs generated per gallon of
biodiesel and renewable diesel. At this time, we do not believe it
would be appropriate to deviate from our longstanding practice of
calculating equivalence values in the RFS program based on the energy
content and renewable content of the renewable fuel. Such a change
would invite requests for higher (or lower) equivalence values to
support a wide range of policy goals. We believe any such changes
should only be considered holistically, and with adequate notice and
opportunity for public comment.
Finally, some commenters suggested that renewable diesel, renewable
jet fuel, and renewable naphtha producers should be required to
regularly test the energy content of their fuel and that its
equivalence value should be based on these testing results. At this
time, it is unclear whether the requested regular testing is necessary
to ensure that such renewable fuel production is credited
appropriately. We will continue to review the available data and may
consider adopting regular testing requirements in the future if data
indicates that this type of testing is necessary.
B. RIN-Related Provisions
1. RIN Generation and Assignment
Since we finalized the biogas regulatory reform provisions in the
Set 1 Rule, we have received a significant number of questions from
stakeholders regarding when RINs for RNG must be generated and
assigned. In response to these inquiries, we proposed to specify when
RINs must be generated and assigned both for renewable fuel and for
RNG. We are finalizing these provisions largely as proposed, with
additional clarifications added in response to comments from
stakeholders. For most renewable fuels (not including RNG or renewable
CNG/LNG), we are specifying in 40 CFR 80.1426(f)(18) that RINs must be
generated at:
For domestic renewable fuel producers, the point of
production or point of sale.
For RIN-generating foreign producers, the point of
production or when the renewable fuel is loaded onto a vessel or other
transportation mode for transport to the covered location.
For RIN-generating importers of renewable fuel, upon
importation into the covered location.
We are also specifying in 40 CFR 80.1426(f)(18) that RINs for RNG
and renewable fuels that are gaseous at standard temperature and
pressure (STP) (e.g., renewable CNG/LNG) must be generated no later
than five business days after all applicable requirements for RIN
generation under 40 CFR 80.125(b), 80.130(b), and 80.1426(f), as
applicable, have been met. An exception would be for foreign produced
RIN-less RNG, in which RINs must be generated no later than when title
is transferred from the foreign producer to the RIN-generating
importer.
Furthermore, we are specifying in 40 CFR 80.1426(e) that, except
for renewable fuels that are gaseous at STP, RINs generated at the
point of production or the point of importation into the covered
location must be assigned to a volume of renewable fuel when the
renewable fuel leaves the renewable fuel production or import facility,
while RINs generated at the point of sale or when the renewable fuel
was loaded onto a vessel or other transportation mode for transport to
the covered location must be assigned prior to the transfer of
ownership of the renewable fuel. We are also requiring that RINs for
renewable fuels that are gaseous at STP must be assigned to a volume of
renewable fuel at the same time the RIN is generated.
Several commenters expressed confusion regarding the proposed
changes to 40 CFR 80.1426(e) and (f). Our intent was to improve
consistency of data submissions related to RIN generation for all types
of fuel, including RNG. To help clarify this intent, we are adding
additional language to 40 CFR 1426(f)(18). As proposed, 40 CFR
80.1426(f)(18)(i) and (ii) clarify the RIN generation event (also
[[Page 16450]]
known as ``fuel production date'' in EMTS), while newly added 40 CFR
80.1426(f)(18)(iii) describes when the RIN generator must submit this
information via EMTS. To improve consistency, we also added additional
references in 40 CFR 80.1426(f)(18)(ii) to 40 CFR 80.125 and 80.130.
The regulation at 40 CFR 80.1426(f)(18)(ii) only provides
clarification on existing procedures. When the RNG producer is able to
meet the applicable requirements in 40 CFR 80.125(b), 80.130(b), and
80.1426(f), the RIN generation event has occurred and the RNG producer
then has 5 business days to submit this information to EMTS.
Using a hypothetical example to illustrate 40 CFR
80.1426(f)(18)(ii), an RNG producer continuously measures and injects
RNG into the commercial pipeline from April 1 to April 30. The RNG
producer receives the first pipeline statement on May 15 showing values
from April 1 to April 15, and a second pipeline statement on June 15
covering values from April 16 to April 30. The RNG producer then
combines the two statements to reflect the full calendar month of
production for April. The associated biogas producer submits the
monthly biogas batch in EMTS (``biogas token'') on May 31 and then
transfers the biogas batch tokens in EMTS to the RNG producer, which
provides necessary information on the pathway and the total volume of
biogas. The RNG producer has all the required inputs for calculating
the RNG batch volume described in 40 CFR 80.110(j)(4) on June 15,
including the biogas batch and the pipeline injection statements. The
RNG producer is now able to calculate the RNG volume from April 1 to
April 30 and uses April 30 as the ``Fuel Production Date'' for purposes
of RIN generation. The RNG producer then has up to five business days
from June 15 to submit the RIN generation event in EMTS.
2. Renewable Fuel Used for Process Heat or Electricity Generation
This rule aims to ensure that renewable fuel producers do not
generate RINs for renewable fuel used for process heat or electricity
generation--and that they retire any RINs generated for renewable fuel
that the producer has reason to know is used for process heat or
electricity generation--as these RINs are invalid because Congress did
not include such uses as qualifying under the RFS program. In the Set 2
proposal, we proposed changing the definition of heating oil to state
that pure biodiesel (i.e., B100) or neat biodiesel (i.e., B99) used for
process heat or power generation is not heating oil. After considering
the comments received, we are instead finalizing a prohibition on RIN
generation for fuel that is used for process heat or electricity
generation, for the reasons described below and in RTC Section 11.2.2.
Additionally, in the Set 2 proposal, we referred to ``power
generation'' instead of ``electricity generation'' in the context of
this proposed amendment. In this final rule, we instead now refer to
``electricity generation'' to reduce ambiguity. The EPA has never
allowed RINs to be generated for renewable fuel used for electricity
generation under the RFS program. Indeed, the only RIN-generating use
of electricity previously permitted under the RFS program was renewable
electricity generated from biogas and used as transportation fuel.\298\
However, under this section we use the term ``electricity generation''
to refer to the production of electrical power by a utility for
generalized use by the public; it does not refer to the renewable
electricity pathway described in section VII of this preamble.
---------------------------------------------------------------------------
\298\ As discussed in section VII of this preamble, we are
removing renewable electricity as a qualifying renewable fuel under
the RFS program in this action.
---------------------------------------------------------------------------
a. Statutory and Regulatory History
The CAA only permits credit (i.e., RIN) generation for renewable
fuel, which is limited to fuel that replaces or reduces the quantity of
fossil fuel present in transportation fuel, home heating oil, or jet
fuel. EPAct initially limited the definition of ``renewable fuel'' to
motor vehicle fuel only, and we subsequently promulgated RFS program
regulations to implement Congress's mandates.\299\ Separately, we
initially defined heating oil as ``any #1, #2, or non-petroleum diesel
blend that is sold for use in furnaces, boilers, stationary diesel
engines, and similar applications and which is commonly or commercially
known or sold as heating oil, fuel oil, and similar trade names, and
that is not jet fuel, kerosene, or MVNRLM diesel fuel.'' \300\
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\299\ Public Law 109-58, 119 Stat. 594, 1068.
\300\ 71 FR 25706, 25716 (May 1, 2006). The reference to
``stationary diesel engines'' was removed from the definition in 40
CFR 80.2(ccc) as part of the EPA's final rule concerning oceangoing
vessels. 75 FR 22896 (April 30, 2010).
---------------------------------------------------------------------------
In 2007, Congress added the definition of ``additional renewable
fuel'' in EISA, which expanded the scope of renewable fuel qualifying
for the RFS program to include home heating oil and jet fuel.\301\
Process heat and electricity generation were not included in EISA's
expanded qualifying uses. In 2010, we subsequently modified ``the
regulatory requirements to allow RINs assigned to renewable fuel
blended into heating oil or jet fuel in addition to highway and nonroad
transportation fuels to continue to be valid for compliance purposes.''
\302\
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\301\ EISA, H.R. 6, 110th Cong., sec. 201 (2007); 42 U.S.C.
7545(o)(1)(A).
\302\ 75 FR 14670, 14687 (March 26, 2010).
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Additionally, we added a second definition of heating oil in the
RFS regulations in 2013 (the ``Heating Oil Rule''), which expanded the
definition of heating oil to include ``[a]ny fuel oil that is used to
heat or cool interior spaces of homes or buildings to control ambient
climate for human comfort.'' \303\ The Heating Oil Rule explicitly
prohibited RIN generation on fuel oils used to generate process heat,
electricity, or other functions under the newly added definition,
because those fuels did not fall within the scope of ``home heating
oil'' as the term is used in EISA.\304\ We also stated that the first
definition of heating oil would remain unaffected: ``All fuels
previously included in the definition of heating oil continue to be
included as heating oil under 40 CFR 80.1401 for purposes of the RFS
program.'' \305\ To the extent that renewable fuel producers believed
that renewable fuel used for process heat or electricity generation
qualified as heating oil under the first definition, this final rule
clarifies that it does not.
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\303\ 78 FR 62462, 62470 (October 22, 2013); 40 CFR 80.2.
\304\ 78 FR 62462, 62463-64, 68 (October 22, 2013). Although the
Heating Oil Rule preamble uses the word ``power,'' we are using
``electricity'' throughout this final rule to reduce ambiguity, as
previously explained.
\305\ Id. at 62463-64.
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b. Changes From the Set 2 Proposal
In the Set 2 proposal, we proposed revising the definition of
heating oil under 40 CFR 80.2 to state that ``pure biodiesel (i.e.,
B100) or neat biodiesel (i.e., B99) that is used for process heat or
power generation is not heating oil.'' After considering the comments
we received on our proposal and the goals of this clarification, we are
instead adding a new prohibited act in 40 CFR 80.1460(b) to prohibit
the generation of a RIN for fuel that is used for process heat or
electricity generation, except as specified in 40 CFR 80.1426(f)(12).
Consistent with this change, we are also clarifying in 40 CFR
80.1431(a) that RINs generated for a prohibited act are invalid RINs.
Rather than revising the definition of heating oil to exclude only
certain concentrations of biodiesel, we are instead prohibiting RIN
generation on any renewable fuel that is used for
[[Page 16451]]
process heat or electricity generation. First, as several commenters
pointed out, because the EPA has expressly stated that blends of
biodiesel above B80 fall under the definition of ``heating oil,'' it
makes little sense to distinguish blends above B80 from B99 or B100.
Additionally, we have decided to expand the prohibition beyond
biodiesel to all renewable fuels because, although most other renewable
fuels are unlikely to meet the first definition of heating oil at 40
CFR 80.2, process heat and electricity generation are not qualifying
uses for the RFS program as contemplated by Congress in the CAA.
Further, we have determined that this clarification is better
conveyed by adding a prohibited act, rather than changing the
definition of heating oil. Adding a new prohibited act is the clearest
way for the EPA to ensure that RINs are only generated for qualifying
renewable fuel under the RFS program. While amending the definition of
heating oil may have been one way to accomplish that goal, clarifying
that the practice is ``prohibited'' is the most direct way of
communicating this to stakeholders. Additionally, clarifying that RINs
generated for a prohibited act are invalid provides a more complete
picture of the consequences to stakeholders, as the existing RIN
retirement regulations already state that any invalid RIN must be
retired.\306\
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\306\ 40 CFR 80.1434(a)(8).
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c. Additional Clarifications
First, several commenters pointed to one of our responses in the
RTC document for the Heating Oil Rule, in which we stated that the
``inclusion of the new heating oil provision for fuel oils does not
impact the current definition and use of biodiesel as heating oil, even
where that biodiesel is used for process heat, power generation, or in
stationary sources. EPA confirms that biodiesel producers can (and
must) separate the RINs from wet gallons when used by the producer as
heating oil or for process heat or power.'' \307\ Commenters on the Set
2 proposal appear to have interpreted our prior response to mean that,
under the first definition of heating oil, renewable fuel producers
were allowed to generate RINs on biodiesel that was used for process
heat or electricity generation, and that the EPA was reminding
producers to separate RINs from wet gallons of biodiesel when doing so.
While this errant response to comment is part of the rulemaking record,
its language was not incorporated into the text of the regulation.
Indeed, the interpretation of this response by commenters on the Set 2
proposal is contrary to the CAA. If Congress had intended any reduction
or replacement of fossil-based fuels by renewable fuels to qualify for
RIN generation, it would have either said so explicitly or refrained
from specifying particular uses.
---------------------------------------------------------------------------
\307\ EPA, ``Regulation of Fuel and Fuel Additives:
Modifications to Renewable Fuel Standard Program, Response to
Comments,'' EPA-420-R-13-010, September 2013, at 13-14.
---------------------------------------------------------------------------
Second, we recognize that for renewable fuels meeting the first
definition of heating oil, no tracking or documentation of end use is
required, and some heating oils that meet the original definition could
end up being used for other purposes. In the Heating Oil Rule, we
explained that renewable fuel qualifying as heating oil under the first
definition must have the physical or other characteristics that make it
the type of fuel oil normally used to heat homes, and that products
qualifying as heating oil under the second definition will be
identified not by their chemical specifications but instead by their
actual use to control indoor climates for human comfort.\308\ As a
result, we adopted registration, recordkeeping, product transfer
document (PTD), and reporting requirements for fuel oils qualifying as
heating oil under the second definition.
---------------------------------------------------------------------------
\308\ 78 FR 62462, 62466 (October 22, 2013).
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While this final rule requires renewable fuel producers to
determine in good faith whether their product is eventually used for
process heat or electricity generation, this does not add significant
documentation burdens. Given the fungible nature of the heating oil
delivery market, we understand that tracking the end use for products
that fall under the first definition of heating oil would likely be
sufficiently difficult and potentially expensive so as to discourage
the generation of RINs. However, the PTDs accompanying fuel shipments
already require the producer to designate RIN-generating renewable fuel
for a qualifying use.\309\ As we previously stated in the QAP Rule,
``parties designating fuel for a qualifying use who know or have reason
to know that the fuel would likely not be'' used as such would be in
violation of the regulation.\310\ As an example, a renewable fuel
producer that uses its own product for process heat or electricity
generation will be the end user and tracking its end use will not be a
significant burden. Likewise, if a renewable fuel producer sells its
product to a utility company for electricity generation, that producer
will be able to track the portion of the product being sold to that
customer.
---------------------------------------------------------------------------
\309\ 40 CFR 80.1453(a)(12).
\310\ 79 FR 42078, 42104 (July 18, 2014).
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This final rule does not require renewable fuel producers that
generate RINs immediately upon production to change their RIN
generation practices. Producers of renewable fuel that falls under the
first definition of heating oil are not required to track end use, so
they may be more likely to generate RINs at the time of renewable fuel
production. For producers that fall into this category, we are
clarifying in 40 CFR 80.1431(a) that RINs generated for a prohibited
act are invalid. When combined with the existing RIN retirement
regulation at 40 CFR 80.1434(a)(8), this additional clarification
informs producers that such RINs must be retired. As stated above, we
do not anticipate that this will impose significant documentation
burdens on renewable fuel producers, because as the end user
themselves, they will be in a position to know the renewable fuel's
final use.
Finally, this prohibition on RIN generation does not apply to de
minimis or incidental volumes of renewable fuel used as heating oil in
emergency backup generators for mission critical functions during power
outages. We are not imposing additional documentation burdens on
producers of heating oil meeting the first definition and those
producers are not expected to determine whether their renewable fuel is
ultimately used in backup diesel-powered generators. We also recognize
the importance of such backup forms of power to mission critical
functions such as hospitals and 911 call centers during power outages.
Therefore, we are not requiring additional documentation for instances
when a small or incidental volume of renewable fuel is ultimately used
in such emergency situations.
C. Percentage Standard Equations
In the Set 2 proposal, we proposed several changes to the
percentage standard equations in 40 CFR 80.1405(c), including to: (1)
clarify that the volume requirements used to calculate the percentage
standards for cellulosic biofuel, advanced biofuel, and total renewable
fuel are based on the number of ``gallon-RINs''; (2) change the BBD
volume requirement to be expressed in gallon-RINs; and (3) clarify,
revise, or remove certain terms of the percentage standard equations.
Commenters were generally supportive of these changes, although several
commenters raised concerns about our proposed change to express the BBD
volume requirement in gallon-RINs instead of physical gallons. After
consideration of those comments, we
[[Page 16452]]
are finalizing the changes to the percentage standard equations as
proposed with minor clerical revisions to the proposed language.\311\
We address the specific concerns raised by commenters in RTC Section
11.3.
---------------------------------------------------------------------------
\311\ Our changes to the percentage standard formulas are
limited to the changes here and in sections IV and V of this
preamble that establish SRE reallocation volumes for 2026 and 2027.
We have not reopened any other aspects of the percentage standard
formulas, including the factors that project exempt volumes of
gasoline and diesel due to small refinery exemptions.
---------------------------------------------------------------------------
First, consistent with our long-standing practice, we are
clarifying that the volume requirements used to calculate the
percentage standards for cellulosic biofuel, advanced biofuel, and
total renewable fuel (RFVCB,i, RFVAB,i, and
RFVRF,i, respectively) are based on the number of ``gallon-
RINs'' of each fuel, rather than simply ``gallons'' as previously
specified. As described in the RFS2 Rule, we have interpreted these
volume requirements as being on an energy-equivalent basis (rather than
wet or physical gallons of liquid fuel) and that when the volume
requirements are used to calculate the applicable percentage standards,
it would be through the use of the equivalence value for RIN generation
(the ``Equivalence Value'' approach).\312\ This energy-equivalent basis
for using the volume requirements to calculate the percentage standards
is expressed through the use of gallon-RINs, and thus we believe these
terms should be defined as such in the regulations.
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\312\ 75 FR 14709-10, 16-18 (March 26, 2010).
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Second, we are changing the BBD volume requirement
(RFVBBD,i) from being expressed in physical gallons to
gallon-RINs, consistent with the methodology used to specify the other
three renewable fuel volume requirements. Since the BBD volume
requirement was first established in the RFS2 Rule, we have interpreted
the statutory BBD volume requirements as being in physical
gallons.\313\ Thus, while the percentage standard equations for
cellulosic biofuel, advanced biofuel, and total renewable fuel were
established on a gallon-RINs basis, the BBD percentage standard was
established on a physical gallon basis. Because the BBD standard was
assumed in the RFS2 Rule to be met exclusively with biodiesel, and
biodiesel generated 1.5 RINs per gallon, we applied a 1.5 multiplier
(the ``BBD conversion factor'') to the BBD percentage standard equation
to convert from the number of BBD physical gallons in the statutory
volume requirements to the equivalent number of gallon-RINs. Since the
RFS2 Rule, we have continued to use the energy-equivalent (or gallon-
RIN) approach in establishing the cellulosic biofuel, advanced biofuel,
and total renewable fuel volume requirement and associated percentage
standards. However, the BBD volume requirement has continued to be
expressed in physical gallons and then converted to a gallon-RIN
equivalent in the BBD percentage standard equation by multiplying the
BBD volume requirement by the BBD conversion factor (either 1.5 (from
2010-2022) or 1.6 (from 2023-2025)).
---------------------------------------------------------------------------
\313\ In the RFS2 rule, we stated that ``we are finalizing the
energy content approach to Equivalence Values for the cellulosic
biofuel, advanced biofuel, and total renewable fuel standards.
However, the biomass-based diesel standard is based on the volume of
biodiesel. In order to align both of these approaches
simultaneously, biodiesel will continue to generate 1.5 RINs per
gallon as in RFS1, and the biomass-based diesel volume mandate from
EISA is then adjusted upward by the same 1.5 factor.'' 75 FR 14716
(March 26, 2010).
---------------------------------------------------------------------------
As discussed in section III of this preamble, since the
promulgation of the RFS2 Rule, fuels other than biodiesel, most
prominently renewable diesel, have become significant contributors to
the BBD volume requirement. This increased contribution from renewable
diesel to the BBD pool, along with an equivalence value of 1.7 for
renewable diesel \314\--compared to an equivalence value of 1.5 for
biodiesel--resulted in the average equivalence value for BBD increasing
from 1.51 in 2012 to nearly 1.59 in 2022.\315\ The shifting equivalence
value has led to confusion among stakeholders regarding the correct way
to interpret the BBD volume requirement and a perceived lack of clarity
regarding how the BBD percentage standard is calculated.
---------------------------------------------------------------------------
\314\ While we acknowledge that we are revising the specified
equivalence value for renewable diesel from 1.7 to 1.5 in this
action, our decision here to specify the BBD volume requirement in
gallon-RINs rather than physical gallons is independent from our
decision to revise the equivalence value for renewable diesel. In
addition, we expect that many renewable diesel producers will
petition for a greater equivalence value, as discussed in section
VIII.A of this preamble.
\315\ For additional discussion of the BBD conversion factor,
see our discussion on this topic in the Set 1 Rule in which we
revised the BBD conversion factor from 1.5 to 1.6. 88 FR 44545-47
(July 12, 2023).
---------------------------------------------------------------------------
Acknowledging that the BBD volume requirement is now being met with
a more complex mixture of fuels than we anticipated in the RFS2 Rule,
we are now revising the definition of RFVBBD,i to specify
that the BBD volume requirement is expressed in gallon-RINs rather than
physical gallons. We believe that specifying the BBD volume requirement
in gallon-RINs reduces confusion among stakeholders regarding how to
interpret the BBD volume requirement and how the BBD percentage
standard is calculated. We acknowledge that this is a change in our
approach to the BBD volume requirement. In 2010, we believed that
Congress intended the BBD volume mandate to be treated as volumes
rather than in terms of gallon-RINs.\316\ However, Congress did not
specify BBD volume requirements for any years after 2012. Subsequent
experience implementing the RFS program has compelled us to revisit
this interpretation, as well as the facts that the EPA has broad
discretion to establish the BBD volume requirements after 2012 (based
on a review of the implementation of the RFS program to date and the
statutory factors) and the increasingly complex mix of renewable fuels
that are used to meet the BBD volume requirement.
---------------------------------------------------------------------------
\316\ 75 FR 14710 (March 26, 2010).
---------------------------------------------------------------------------
We now believe that the BBD volume requirement is best read as
requiring BBD volumes to be specified in gallon-RINs, consistent with
the other three renewable fuel categories under the RFS program. Under
CAA section 211(o)(B)(i), the tables listing the statutory volume
requirements for all four categories of renewable fuel (cellulosic
biofuel, BBD, advanced biofuel, and total renewable fuel) specify the
units as being ``in billions of gallons.'' There is no indication in
the statutory text that the units of the BBD volume requirement should
be treated differently than the other renewable fuel categories. The
reason we gave in 2010 for differentiating BBD--that we believed the
BBD volume requirements set by Congress through 2012 were best
interpreted as physical gallons rather than RIN-gallons--is no longer
relevant since Congress did not provide BBD volume requirements for
years after 2012.
In addition, we note that there is no practical effect on regulated
parties by specifying the BBD volume requirement in gallon-RINs rather
than physical gallons. Whether the EPA specifies the BBD volume
requirement in gallon-RINs or physical gallons, ultimately the
numerator in the BBD percentage standard equation--and thus the BBD
percentage standard itself--would be the same. Since 2010, obligated
parties have used the BBD percentage standards to determine their BBD
RVOs in gallon-RINs, rather than in physical gallons. This was clear in
the multiplier (initially 1.5, revised to 1.6 for 2023-2025) used in
the BBD percentage standard equation, which was unique to BBD. The
purpose of this multiplier was to ensure that the percentage standards
[[Page 16453]]
represented obligations in gallon-RINs rather than physical gallons.
Were we to still specify the BBD volume requirement in physical
gallons, we would first determine the intended increase in the BBD
volume requirement in RINs and then divide by 1.6 to calculate the
necessary BBD volume requirement in physical gallons. This conversion
would then be reversed in the numerator of the BBD percentage standard
equation, where the BBD physical gallon volume requirement would be
multiplied by 1.6 to convert from physical gallons back to RINs.
Ultimately, the BBD volume requirement is simply an input into the BBD
percentage standard equation, not a standalone or otherwise enforceable
requirement itself. By specifying the BBD volume requirement in gallon-
RINs in the first place, we avoid a confusing and unnecessary step in
the calculation of the BBD percentage standard (i.e., the requirement
with which obligated parties actually have to comply) and ensure
consistency with the other three renewable fuel categories.
Consistent with this clarification, we are also revising the BBD
percentage standard to remove the 1.6 conversion factor. By specifying
the BBD volume requirement in gallon-RINs, the BBD conversion factor is
no longer necessary to convert from physical gallons of BBD to gallon-
RINs. This also eliminates the need to track the average equivalence
value of BBD to adjust the BBD conversion factor in the future. For
example, we recently revised from 1.5 to 1.6 in the Set 1 Rule due to
increased production volumes of renewable diesel relative to biodiesel;
\317\ such adjustments will no longer be necessary.
---------------------------------------------------------------------------
\317\ 88 FR 44545-47 (July 12, 2023).
---------------------------------------------------------------------------
We are also removing the terms GSi, DSi,
RGSi, and RDSi from the percentage standard
equations. These terms relate to the use of gasoline, diesel, and
renewable fuels contained in gasoline and diesel in Alaska or a U.S.
territory if the State or territory opts into the RFS program. However,
if Alaska or a U.S. territory were to opt into the RFS program in the
future, we would instead account for gasoline, diesel, and renewable
fuel use in the State or territory under the existing Gi,
Di, RGi, and RDi terms. These terms
refer to the amounts of gasoline, diesel, or renewable fuel used in
gasoline or diesel in the covered location, which is defined as ``the
contiguous 48 states, Hawaii, and any state or territory that has
received an approval from the EPA to opt-in to the RFS program under
Sec. 80.1443.'' \318\ Thus, there is no need to have separate terms in
the percentage standards just for Alaska or a U.S. territory that opts
into the RFS program in the future.
---------------------------------------------------------------------------
\318\ 40 CFR 80.2.
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Finally, we are revising the definitions of RGi and
RDi (the projected amounts of renewable fuel in gasoline and
diesel, respectively) to clarify that these projections are for the
amounts of renewable fuel contained within the projections of
Gi and Di themselves (the amounts of gasoline and
diesel, respectively, projected to be used in the U.S.), rather than a
projection of the absolute amount of renewable fuel contained in
gasoline and diesel. While the EIA projections that the EPA uses to
calculate the percentage standards have historically contained some
volume of renewable fuel (e.g., ethanol in gasoline, biodiesel and
renewable diesel in diesel), EIA has recently changed their STEO
projection methodology to provide separate projections of petroleum-
based distillate and renewable fuels blended into distillate (e.g.,
biodiesel and renewable diesel). Thus, were we to use these projections
to calculate the percentage standards, we would use the petroleum-based
distillate projection for Di and a value of zero for
RDi, as the Di projection does not contain any
renewable fuel.\319\ We believe this clarification makes clear how we
would calculate the percentage standards under this potential future
scenario.
---------------------------------------------------------------------------
\319\ Note that the percentage standards in this action are
calculated using projections from AEO2025, which does include
renewable fuels in its projections of gasoline and distillate.
---------------------------------------------------------------------------
D. Renewable Fuel Pathways
In the Set 2 proposal, we proposed changes to the table of approved
renewable fuel pathways in order to clarify the parameters for certain
pathways. In particular, we proposed to revise references to ``any'' in
the production process requirements of table 1 to 40 CFR 80.1426
(hereinafter ``Table 1'') with more precise descriptions. These
revisions are intended to more accurately describe the production
processes that we evaluated when we approved these pathways as
satisfying the statutory requirements for lifecycle emissions
reductions. In the Set 2 proposal, we also proposed to add biogenic
waste fats, oils, and greases as a feedstock for producing renewable
naphtha and liquefied petroleum gas (LPG). In this action, we are
finalizing many of the proposed changes with modifications based on our
consideration of the public comments.
Table 1 lists generally applicable fuel pathways that have been
approved for the RFS program. Fuel producers that produce fuel through
a pathway (i.e., a unique combination of a fuel, feedstock, and
production process) described in Table 1 may submit a registration
application to the EPA.\320\ Table 1 lists an applicable RIN D code for
each approved pathway based on the statutory criteria, including the
type of fuel produced, the feedstock used to produce the fuel, and
whether it satisfies the statutory 20 percent, 50 percent, or 60
percent lifecycle emissions reduction threshold. In section VIII.D.1 of
this preamble, we are finalizing clarifications to the parameters of
certain pathways in Table 1. In section VIII.D.2 of this preamble, we
are finalizing the addition of pathways to Table 1 for naphtha and LPG
produced from biogenic waste fats, oils, and greases. These amendments
to Table 1 are summarized in Table VIII.D-1.\321\ We are finalizing
these changes largely as proposed, but with certain modifications based
on our consideration of the comments.
---------------------------------------------------------------------------
\320\ Note that an individual row in Table 1 can include
multiple fuel pathways.
\321\ The reasons for these regulatory amendments are described
in section X.D of the Set 2 proposal (90 FR 25845-49; June 17,
2025).
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[[Page 16454]]
[GRAPHIC] [TIFF OMITTED] TR01AP26.074
1. Table 1 Pathways That Include ``Any'' Production Process
In addition to requiring that renewable fuel be produced from
renewable biomass and used to reduce or replace the quantity of fossil
fuel in transportation fuel,\322\ the CAA also requires that qualifying
biofuels meet the lifecycle emissions reduction threshold specified for
the applicable category of renewable fuel.\323\ The CAA further
requires the EPA to determine the lifecycle emissions for renewable
fuels.\324\ We have evaluated the lifecycle emissions associated with a
wide range of fuel pathways and listed those pathways that satisfy the
statutory emissions reduction criteria and other statutory criteria in
Table 1. To do so, we evaluate particular feedstocks that are put
through particular production processes to produce particular fuels.
Thus, an approved pathway in Table 1 signifies that we have determined
that the specific combination of elements we evaluated--feedstock,
process, and fuel--meets the applicable lifecycle emissions reduction
threshold.
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\322\ CAA section 211(o)(1)(J).
\323\ CAA sections 211(o)(1)(B), (D), (E); 211(o)(2)(A)(i).
\324\ CAA section 211(o)(1)(H).
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For certain pathways that were promulgated in the RFS2 Rule, we
believed, based on the fuel production process data available at the
time, that the use of any process would result in emissions for the
resulting fuel that meet the applicable lifecycle emissions reduction
threshold.\325\ However, since that time, we have observed the
emergence and development of fuel production processes that vary from
those assumed in the original lifecycle assessments underlying the
approved pathways in Table 1. These developments have resulted in
processes that differ much more than we anticipated was possible in the
RFS2 Rule. Indeed, some of the fuel production processes that parties
are now interested in registering under ``any'' pathways bear little
resemblance to the processes we evaluated as the basis for including a
given pathway in Table 1. In some cases, the lifecycle emissions
performance of such new processes may be significantly worse than the
processes we analyzed in the RFS2 Rule or the notional processes we
anticipated might be developed in the future. These new processes may
therefore not meet the applicable statutory lifecycle emissions
reduction threshold. For example, we have received petitions for
thermochemical cellulosic biofuel production technologies that would
use a large amount of conventional natural gas and grid electricity per
unit of fuel produced, whereas our 2010 analysis assumed that this type
of process would use practically zero fossil fuel or grid electricity,
relying instead on combustion of char, coke, and syngas derived from
the cellulosic renewable biomass feedstock for process energy.\326\
---------------------------------------------------------------------------
\325\ See, e.g., our discussion of ``assessments of similar
feedstocks sources'' at 75 FR 14792-14797 (March 26, 2010).
\326\ See Table 2.4-59 of the RFS2 Rule RIA (EPA-HQ-OAR-2021-
0427-0115) (March 26, 2010).
---------------------------------------------------------------------------
Given the possibility that some pathways nominally fitting the
description in Table 1 might not actually meet the corresponding
statutory lifecycle emissions reduction requirement, we believe it is
inappropriate to continue listing ``any'' production process under
certain approved pathways in Table 1. Therefore, we are finalizing
changes to clarify certain approved pathways in Table 1 by replacing
the ``any'' terminology with more precise language that reflects the
fuel production processes that we have determined satisfy the
applicable lifecycle emissions reduction thresholds.
Specifically, to further clarify the scope of approved pathways in
Table 1, we are replacing the term ``any'' with more precise language
in the production technology requirements column of Rows K, L, M, P, Q,
and T. Previously, Rows K and L listed the production process
requirements as ``Any process that converts cellulosic biomass to
fuel,'' Row M included ``any process utilizing biogas and/or biomass as
the only process energy sources which
[[Page 16455]]
converts cellulosic biomass to fuel,'' and Rows P, Q, and T listed the
production process requirements as ``Any.'' As discussed below, we are
replacing some or all of the current language in each of these rows
with a description of the production process and associated parameters
that we evaluated for the corresponding lifecycle assessment and that
we determined meet the applicable lifecycle emissions reduction
threshold. Furthermore, we are making related changes to Row N and
adding a new Row U so that the full set of previously evaluated and
approved pathways are listed in Table 1. Renewable fuel production
facilities that do not satisfy the production process requirements in
Table 1 may petition the EPA pursuant to 40 CFR 80.1416 to request our
evaluation of the lifecycle emissions associated with their fuel.
As discussed further in section VIII.D.1.h of this preamble, we are
adding two provisions in the regulations at 40 CFR 80.1426(f)(1) to
clarify the implementation of pathways in Table 1. First, we are adding
a paragraph to clarify that the amendments to Table 1 in this action do
not affect renewable fuel producers with an existing pathway
registration. Second, we are adding a paragraph that specifies the
criteria the EPA applies to determine whether a feedstock, fuel, or
production process qualifies for an approved pathway in Table 1.
Stakeholders provided comments on these proposed changes. Some
commenters were neutral and provided specific recommendations for
modifying the proposed changes to Rows Q and T. One commenter was
generally opposed to the changes, saying they were unnecessary, but did
not provide specific reasons. Other commenters questioned the need for
changes to specific rows, and in some cases these comments recommended
specific alternatives. We discuss some of these specific comments and
our response in the subsections below, and more detail is contained in
RTC Section 11.4.1.
a. Row K
Row K includes pathways for ethanol produced from certain
cellulosic feedstocks to qualify for D3 RINs. We are finalizing
revisions to Row K as proposed but with modifications based on
consideration of comments and further review of the processes that we
evaluated in prior RFS rulemakings. As proposed, we are revising Row K
to specify that the approved production processes include biochemical
conversion, thermochemical conversion, and dry mill processes that
satisfy certain conditions. In response to comments that requested
additional clarity, we are modifying the proposed text in Row K that
specifies the production process requirements, and we are describing
these processes in more detail in this section. Below, we describe the
production processes evaluated and the associated criteria specified
for each of these production processes in Row K.
Biochemical conversion refers to processes that involve the
fermentation, or other biological conversion, of sugars liberated from
the breakdown of cellulosic biomass. A biochemical conversion process
to produce ethanol from cellulosic biomass includes the following main
steps: feedstock pretreatment, hydrolysis, saccharification,
fermentation, dehydration, and lignin recovery.\327\ Feedstock physical
pretreatment involves reducing the feedstock's particle size by
grinding, shredding, or chopping. Following physical pretreatment, the
feedstock undergoes chemical pretreatment, enzymatic hydrolysis, and
saccharification to break down the cellulose and hemicellulose into
simple sugars such as glucose and xylose. Chemical pretreatment and
hydrolysis include treating the feedstock with hot water, dilute acid,
alkaline, organic solvent, ammonia, sulfur dioxide, carbon dioxide, or
other chemicals to make the biomass more digestible by enzymes.
Saccharification breaks down the polysaccharides into simple sugars via
enzymatic or acidic methods. The resulting sugars are then fermented to
ethanol with yeast, nutrients, and enzymes. Following fermentation, the
mixture undergoes dehydration to remove water, carbon dioxide, and
other materials. Biochemical conversion processes are unable to produce
fuel from the lignin portion of cellulosic biomass feedstocks. During
the processing steps described above, the lignin portion of the
renewable biomass is isolated for combustion. The biochemical
conversion processes we evaluated for this pathway combust the lignin
onsite to provide all the thermal and electrical process energy needs
for fuel production processes at the facility.
---------------------------------------------------------------------------
\327\ For additional information on the processes the EPA
evaluated, see: 75 FR 14782 (March 26, 2010); RFS2 Rule RIA at 101-
107 and 433-435; and Tao and Aden (2009) (Docket Item No. EPA-HQ-
OAR-2005-0161-0844).
---------------------------------------------------------------------------
We are specifying in Row K that the biochemical conversion process
must use lignin from the renewable biomass feedstock (i.e., the
feedstock(s) listed in Row K) to provide all thermal and electrical
process energy. For example, this means that a biochemical conversion
process using corn stover feedstock must combust the lignin that
remains after the cellulose and hemicellulose portions of the corn
stover are converted to ethanol to provide heat and power for all the
fuel production processes at the facility, such that no grid
electricity or other fuels are purchased to supply heat and power for
these processes. We have determined that these process requirements are
necessary to ensure that the pathways in Row K conform with the
biochemical conversion processes that we evaluated and determined
satisfy the statutory criteria for cellulosic biofuel.
Thermochemical conversion refers to processes that break down
cellulosic biomass into intermediates using heat and then upgrade the
intermediates to transportation fuel. A thermochemical conversion
process to produce ethanol from cellulosic biomass includes the
following main steps: feedstock pretreatment, gasification, syngas
cleanup and conditioning, fuel synthesis, and separation.\328\
Feedstock pretreatment includes drying and particle size reduction for
proper feeding into the gasifier. The biomass is gasified to syngas
with an exothermic partial oxidation (directly heated) gasifier or an
indirect gasifier using steam and heat transfer. The syngas cleanup and
conditioning step involves removing impurities such as tar, sulfur,
nitrogen oxides, alkali metals, and particulates. The syngas
conditioning step includes sulfur polishing to remove trace levels of
hydrogen sulfide and water-gas shift to adjust the final ratio of
hydrogen to carbon monoxide. The clean syngas, comprised of carbon
monoxide and hydrogen, is converted to ethanol through either a
catalytic process or a fermentation process. During the alcohol
separation step, ethanol, methanol, and other alcohols are separated
with molecular sieves or distillation. The gasification step produces
char and coke solid byproducts that are combusted to provide heat and
power for the process. Unreacted gases and slipstreams of syngas from
the gas conditioning through separation stages can also be combusted to
provide process energy. The thermochemical conversion processes that we
evaluated for this pathway combust the char, coke, and syngas onsite to
provide all the thermal
[[Page 16456]]
and electrical process energy needs for fuel production processes at
the facility.
---------------------------------------------------------------------------
\328\ For additional information on the processes the EPA
evaluated, see: 75 FR 14782 (March 26, 2010); RFS2 Rule RIA at 107-
111 and 433-435; and Aden (2009) (Docket Item No. EPA-HQ-OAR-2005-
0161-3034).
---------------------------------------------------------------------------
We are specifying in Row K that the thermochemical conversion
process must use char, coke, or syngas derived from the renewable
biomass feedstock (i.e., the feedstock(s) listed in Row K) to provide
all thermal and electrical process energy. For example, this means that
a thermochemical conversion process using corn stover feedstock must
combust the char, coke, or syngas byproducts from gasification of the
corn stover to provide heat and power for all the fuel production
processes at the facility, such that no grid electricity or other fuels
are purchased to supply heat and power for these processes. We have
determined that these process requirements are necessary to ensure that
the pathways in Row K conform with the thermochemical conversion
processes that we evaluated and determined satisfy the statutory
criteria for cellulosic biofuel.
Dry mill crop residue conversion refers to the conversion of the
cellulosic crop residue portion of grain ethanol feedstocks at a dry
mill ethanol plant via in-situ or offline technologies. A dry mill
ethanol production process to produce ethanol from cellulosic biomass
includes the following main steps: grinding, pretreatment,
fermentation, distillation, and dehydration.\329\ Grain feedstocks are
milled into a coarse flour known as meal. The meal is pretreated (e.g.,
cooking, liquefaction, hydrolysis) with the addition of water and
enzymes to produce a mixture called mash. The mash is fermented with
the addition of yeast, nutrients, and enzymes to produce ethanol,
carbon dioxide, and solids from the grain and yeast, known as fermented
mash. The fermented mash is distilled to produce a mixture of ethanol
and water, and a residue of non-fermentable solids known as stillage.
The mixture of ethanol and water is dehydrated to produce 200-proof
ethanol. Co-products from the dry mill process include distillers
grains, and may also include carbon dioxide, solubles syrup, and
distillers oil. Grain feedstocks often have a fiber layer on the
outside of the kernel that is predominantly composed of cellulosic
biomass. We have determined that this fibrous layer on the outside of
grain feedstocks (i.e., barley, corn, oats, rice, rye, grain sorghum,
and wheat) qualify as crop residue.\330\ While this fiber traditionally
ends up in the stillage and is sold with the distillers grains as
animal feed, additional ethanol can be produced by converting the
kernel fiber to ethanol via in-situ or offline technologies. In-situ
technologies perform the fiber and starch conversion simultaneously
with minimal changes to the traditional ethanol process; these
processes involve pretreatment of the stillage and the addition of
specialized enzymes. Offline processes perform the fiber conversion
separately from the starch conversion; these processes involve separate
process trains to pretreat the stillage and then ferment the fiber
portions. The dry mill crop residue conversion processes that we
evaluated for this pathway use natural gas, biogas, or crop residue for
all thermal process energy.
---------------------------------------------------------------------------
\329\ For additional information on the processes the EPA
evaluated, see: 79 FR 42145-51 (July 18, 2014).
\330\ 79 FR 42150-42151 (July 18, 2014).
---------------------------------------------------------------------------
We are specifying in Row K that the dry mill crop residue
conversion process must use natural gas, biogas, or crop residue for
all thermal process energy. Thermal process energy refers to heat
energy needed for all the processes at dry mill ethanol plants that are
associated with ethanol and distillers grains production. The dry mill
processes that we evaluated also use grid electricity to satisfy
electrical process energy needs. We have determined that these process
requirements are necessary to ensure that the pathways in Row K conform
with the dry mill crop residue conversion processes that we evaluated
and determined satisfy the statutory criteria for cellulosic biofuel.
b. Row L
Row L includes pathways for cellulosic diesel, cellulosic jet fuel,
and cellulosic heating oil produced from certain cellulosic feedstocks
to qualify for D7 RINs. We proposed to leave the feedstocks in Row L
unchanged and revise the production process requirements from ``Any
process that converts cellulosic biomass to fuel,'' to ``Fischer-
Tropsch process that converts cellulosic biomass to transportation fuel
or heating oil; only includes processes that use a portion of the
feedstock for over 99% of thermal and electrical process energy.'' We
are finalizing more substantial revisions to Row L than proposed based
on consideration of comments and further review of the processes that
we evaluated in prior RFS rulemakings.
One commenter stated that Row L should not be limited to Fischer-
Tropsch conversion processes. Upon further review, we agree with this
commenter as we have previously evaluated several other production
processes (i.e., the set of production processes included in Row M) to
produce cellulosic diesel from corn stover and determined that these
pathways satisfy the 60 percent lifecycle emissions reduction
threshold. Thus, we are finalizing a broader set of process
technologies in Row L that matches the set of technologies included in
Row M. To include this broader set of process technologies in Row L
while ensuring the fuels produced satisfy the statutory criteria for
lifecycle emissions, we are also revising the set of feedstocks
included in Row L. Specifically, we are removing purpose-grown crop
feedstocks from Row L and moving them to a new Row U and pairing them
with a more limited set of production processes.\331\ We are moving the
purpose-grown crop feedstocks because they are associated with
emissions related to crop production (e.g., fertilizer application,
feedstock harvesting) that are not present for the other feedstocks in
Row L, which are residue and waste feedstocks. In this section, we
describe the finalized pathways in Row L and the associated criteria
for each of the specified production processes.
---------------------------------------------------------------------------
\331\ Row U is discussed in section VIII.D.1.e of this preamble.
---------------------------------------------------------------------------
In the RFS2 Rule and the Pathways I Rule, we evaluated biochemical
and thermochemical processes that convert lignocellulosic feedstocks to
hydrocarbon fuels such as renewable diesel, gasoline, and jet fuel. We
found that hydrocarbon fuels produced from cellulosic feedstocks
qualify for the 60 percent lifecycle emissions reduction criteria when
certain criteria are satisfied. Below, we describe the production
processes evaluated and the associated criteria specified for each of
these production processes in Row L.
Thermochemical conversion refers to processes that break down
cellulosic biomass into intermediates using heat and then upgrade the
intermediates to transportation fuel. Gasification is a thermochemical
process that partially combusts biomass and makes syngas intermediate.
Pyrolysis is a thermochemical process that heats biomass under high
temperature and pressure in the absence of oxygen and makes bio-oil
intermediates. Gasification processes can convert cellulosic biomass to
ethanol or hydrocarbons, whereas pyrolysis is used to produce
hydrocarbons.
A gasification and upgrading process to produce hydrocarbon fuels
from cellulosic biomass includes the following main steps: feedstock
pretreatment, gasification, syngas cleanup and conditioning, fuel
[[Page 16457]]
synthesis, upgrading, and separation.\332\ Feedstock pretreatment
includes drying and particle size reduction for proper feeding into the
gasifier. The biomass is gasified to syngas with an exothermic partial
oxidation (directly heated) gasifier or an indirect gasifier using
steam and heat transfer. The syngas cleanup and conditioning step
involves removing impurities such as tar, sulfur, nitrogen oxides,
metals, and particulates. The syngas conditioning step includes
polishing to remove hydrogen sulfide and water-gas shift to adjust the
final ratio of hydrogen to carbon monoxide. A slipstream of clean
syngas is sent to a pressure swing adsorption unit to provide hydrogen
for downstream hydroprocessing. The cleaned and water-shifted syngas is
sent to a reactor (e.g., Fischer-Tropsch) where the carbon monoxide and
hydrogen are reacted over catalyst creating a synthetic crude oil
(``syncrude''). The syncrude from the reactor is sent to a distillation
column where it is separated into various hydrocarbon fuels such as
naphtha, distillates, and wax, and the heavier compounds can be
hydrocracked to maximize the production of diesel. The wax undergoes
hydroprocessing to upgrade it to fuel-range-material, and diesel fuel
is often finished with a hydrotreating step. The gasification step
produces char and coke byproducts that are combusted to provide heat
and power for the process. Unreacted gases and slipstreams of syngas
from the gas conditioning through separation stages can be combusted to
provide process energy. The thermochemical conversion processes that we
evaluated for this pathway combust the char, coke, and syngas onsite to
provide all the thermal and electrical process energy needs for fuel
production processes at the facility.
---------------------------------------------------------------------------
\332\ For additional information on the processes the EPA
evaluated, see: 75 FR 14782 (March 26, 2010); 78 FR 14208 (March 5,
2013); RFS2 Rule RIA at 101-113 and 433-435; and Davis (2009)
(Docket Item No. EPA-HQ-OAR-2005-0161-3035).
---------------------------------------------------------------------------
A pyrolysis and upgrading process to produce hydrocarbon fuels from
cellulosic biomass includes the following main steps: feedstock
pretreatment, pyrolysis, upgrading, separation, and distillation.\333\
The feedstock pretreatment step includes biomass drying and size
reduction and normalization. The biomass is fed to the pyrolysis
reactor where it is rapidly heated in the absence of oxygen and
thermally decomposed to pyrolysis vapor, water vapor, non-condensable
product gases, char, coke, and ash. The pyrolysis vapor is cooled and
condensed to liquid bio-oil. The bio-oil is upgraded via
hydroprocessing with the addition of hydrogen to remove oxygen, sulfur,
nitrogen, olefins, and metals. The upgraded bio-oil is separated into
off-gas, wastewater, and stabilized oil streams. The stabilized oil is
distilled into gasoline, diesel, and other hydrocarbon products. This
pyrolysis step generates char, coke, and product gas that can be
combusted to provide process energy. The pyrolysis and upgrading
processes that we evaluated for this pathway combust the char, coke,
and product gas onsite to provide all the thermal and electrical
process energy needs for fuel production processes at the facility,
other than the use of natural gas to produce hydrogen via steam methane
reforming for the upgrading step. The pyrolysis and upgrading processes
that we evaluated consume no more than 0.5 Btu of natural gas per Btu
of finished fuel.
---------------------------------------------------------------------------
\333\ For additional information on the processes the EPA
evaluated, see: 78 FR 14208-09 (March 5, 2013); RFS2 Rule RIA at
112; and Kinchin (2011) (Docket Item No. EPA-HQ-OAR-2011-0542-0007).
---------------------------------------------------------------------------
A biochemical conversion and upgrading process to produce
hydrocarbon fuels from cellulosic biomass includes the following main
steps: feedstock pretreatment, hydrolysis, and aqueous phase catalytic
reforming to selectively upgrade intermediates to liquid hydrocarbon
fuels.\334\ Feedstock pretreatment involves drying and size reduction
by grinding, shredding, or chopping. Following pretreatment, the
feedstock undergoes hydrolysis to break down the cellulose and
hemicellulose into aqueous intermediates including simple sugars and
platform chemicals derived from these sugars. The aqueous phase
catalytic reforming step is a form of upgrading to convert sugars into
hydrocarbon fuels. This form of upgrading requires hydrogen as an input
and involves substantial chemical transformations and multiple
reactions involving oxygen removal (e.g., dehydration, hydrogenation,
hydrogenolysis) combined with carbon-to-carbon coupling (e.g., aldol
condensation, ketonization, oligomerization). Biochemical conversion
processes are unable to produce fuel from the lignin portion of
cellulosic biomass feedstocks. During the processing steps described
above, the lignin portion of the renewable biomass is isolated for
combustion. The biochemical conversion and upgrading processes that we
evaluated for this pathway combust the lignin onsite to provide all the
thermal and electrical process energy needs for fuel production
processes at the facility, other than natural gas needed to produce
hydrogen for upgrading. The biochemical conversion and upgrading
processes that we evaluated consume no more than 0.5 Btu of natural gas
per Btu of finished fuel.
---------------------------------------------------------------------------
\334\ For additional information on the processes the EPA
evaluated, see: 78 FR 14209-10 (March 5, 2013).
---------------------------------------------------------------------------
A direct biochemical conversion process to produce hydrocarbon
fuels from cellulosic biomass includes the following main steps:
feedstock pretreatment, hydrolysis, saccharification, fermentation with
enhanced microorganisms, and lignin recovery. The process is similar to
the biochemical conversion to ethanol process, with the major
difference being that the fermentation step utilizes organisms enhanced
through synthetic biology to produce hydrocarbons instead of ethanol.
Direct biochemical conversion processes are unable to produce fuel from
the lignin portion of cellulosic biomass feedstocks. During the
processing steps described above, the lignin portion of the renewable
biomass is isolated for combustion. The direct biochemical conversion
processes we evaluated for this pathway combust the lignin onsite to
provide all the thermal and electrical process energy needs for fuel
production processes at the facility.
We are specifying in Row L the following feedstocks: crop residue;
slash, pre-commercial thinnings, and tree residue; separated yard
waste; biogenic components of separated MSW; and cellulosic components
of separated food waste. We are specifying in Row L the following
production processes that use lignin, char, or syngas derived from the
renewable biomass feedstock to provide all the thermal and electrical
process energy: gasification and upgrading; and direct biochemical
conversion. We are also specifying in Row L the following production
processes that use lignin, char, or syngas derived from the renewable
biomass feedstock to provide all the thermal and electrical process
energy other than natural gas to produce hydrogen for upgrading
(maximum 0.5 Btu of natural gas per Btu of finished fuel): pyrolysis
and upgrading; and biochemical conversion and upgrading. We have
determined that these process requirements are necessary to ensure that
the pathways in Row L conform with the processes that we evaluated and
determined satisfy the statutory criteria for cellulosic biofuel.
Relative to the revisions proposed for Row L, we are finalizing a
broader set of production processes and a narrower set of feedstocks.
We analyzed the
[[Page 16458]]
lifecycle emissions associated with renewable fuel produced from corn
stover and switchgrass via each of the production processes described
above.\335\ We determined that when corn stover is used as feedstock,
these pathways satisfy the 60 percent lifecycle emissions reduction
criteria to qualify as cellulosic biofuel. However, when switchgrass is
used as feedstock, not all the production processes listed in Row L
would satisfy the 60 percent lifecycle emissions reduction criteria. We
extended the corn stover estimates to other waste and residue
feedstocks, and we extended the switchgrass estimates to other purpose-
grown crop feedstocks including other energy grasses and annual cover
crops. These revisions clarify the eligible pathways in Row L. As
mentioned above, we are moving the purpose-grown crop feedstocks to a
new Row U, which includes a narrower set of production processes.
---------------------------------------------------------------------------
\335\ For additional information on the EPA's analysis of the
emissions associated with producing and transporting these
feedstocks, see: 75 FR 14791-95 (March 26, 2010); and RFS2 Rule RIA
Section 2.4.
---------------------------------------------------------------------------
c. Row M
Row M includes pathways for renewable gasoline, renewable gasoline
blendstock, and co-processed cellulosic diesel, jet fuel, and heating
oil produced from certain cellulosic feedstocks to qualify for D3 RINs.
These pathways were originally evaluated and approved as part of the
Pathways I Rule.\336\ The production process requirements listed in Row
M were not described as ``any'' production process, but they were
listed without a great deal of specificity. We are finalizing the
revisions to Row M as proposed but with modifications based on
consideration of comments and further review of the processes that we
evaluated in prior RFS rulemakings.
---------------------------------------------------------------------------
\336\ 78 FR 14205-13 (March 5, 2013).
---------------------------------------------------------------------------
In response to comments that requested additional clarity, we are
modifying the production process requirements in Row M to provide
additional specificity. For example, the revisions clarify that the
approved gasification and upgrading and direct biochemical conversion
processes do not use any fossil fuels for process energy, whereas the
pyrolysis and upgrading and biochemical conversion and upgrading
processes can use up to a specific amount of natural gas to produce
hydrogen for upgrading per unit of fuel produced. These revisions align
the production process requirements in Row M with the production
processes that we evaluated and approved in the Pathways I Rule.\337\
---------------------------------------------------------------------------
\337\ Id.
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We are also moving ``cellulosic components of annual cover crops''
from Row M to Row N. As discussed in section VIII.D.1.b of this
preamble, when we evaluated hydrocarbon fuels produced from switchgrass
through the pyrolysis and upgrading and biochemical conversion and
upgrading processes, we found that these pathways did not satisfy the
60 percent lifecycle emissions reduction criteria. We extended the
switchgrass estimates to other purpose-grown crop feedstocks because
they are associated with emissions related to crop production (e.g.,
fertilizer application, feedstock harvesting) that are not present for
the other feedstocks in Row L. Thus, as discussed in section VIII.D.1.d
of this preamble, to further align the pathways approved under Row M
with our prior evaluations, we are moving ``cellulosic components of
annual cover crops'' to Row N.
After these modifications, the production process requirements and
feedstocks for Rows L and M are now the same. See section VIII.D.1.b of
this preamble for further discussion of the production processes and
feedstocks approved under Rows L and M and the reasons for the
revisions in this action.
d. Row N
Row N currently includes pathways for naphtha produced from
switchgrass and other energy grasses through a gasification and
upgrading process to qualify for D3 RINs.\338\ As discussed in section
VIII.D.1.c of this preamble, we also previously determined that a wider
range of hydrocarbon fuels (e.g., renewable gasoline, co-processed
cellulosic diesel) produced from specific energy grasses or the
cellulosic components of annual cover crops produced through a
gasification and upgrading process or a direct biochemical conversion
satisfies the 60 percent lifecycle emissions reduction criteria
provided that specific production process requirements are met.\339\ In
this action, we are moving specific feedstocks from Row M to Row N to
ensure that the correct pairings of fuels, feedstocks, and production
processes qualify for D3 RINs based on our prior lifecycle analyses. We
are also adding fuels to Row N to ensure that the complete set of
pathways that we previously determined satisfy the statutory criteria
are listed in Table 1. We did not receive any comments opposing these
amendments.
---------------------------------------------------------------------------
\338\ The current pathways in Row N were approved based on the
evaluation described at 78 FR 14208 (March 5, 2013).
\339\ 78 FR 14205-13 (March 5, 2013).
---------------------------------------------------------------------------
e. Row U
As discussed in section VIII.D.1.b of this preamble, we are moving
specific pathways from Row L to a new Row U to ensure that the correct
pairings of fuels, feedstocks, and production processes qualify for D7
RINs based on our prior lifecycle analyses. Specifically, Row U
includes pathways for the production of cellulosic diesel, renewable
jet fuel, and heating oil from specific energy grasses and cellulosic
components of annual cover crops through gasification and upgrading or
direct biochemical conversion that uses lignin, char, coke, or syngas
derived from the renewable biomass feedstock to provide all thermal and
electrical process energy. We previously evaluated these pathways in
the RFS2 Rule and the Pathways I Rule and determined that they satisfy
the statutory criteria for D7 RINs.\340\ We are creating Row U to
ensure that the complete set of pathways that we previously determined
satisfy the statutory criteria are listed in Table 1. We did not
receive any comments opposing these amendments.
---------------------------------------------------------------------------
\340\ For additional information on the gasification and
upgrading pathways, see: 75 FR 14782 (March 26, 2010) and 78 FR
14208 (March 5, 2013). For additional information on the direct
biochemical conversion pathways, see: 78 FR 14210 (March 5, 2013).
---------------------------------------------------------------------------
f. Row P
We are finalizing the revisions to Row P as proposed for the
reasons described in the Set 2 proposal.\341\ Specifically, we are
revising the production processes in Row P to include: fermentation
using natural gas, biogas, or crop residue for thermal energy;
hydrotreating; and transesterification.\342\ We did not receive any
comments opposing these amendments.
---------------------------------------------------------------------------
\341\ 90 FR 25848 (June 17, 2025).
\342\ For background on the EPA's evaluation of these pathways,
see: 75 FR 14792-95 (March 26, 2010); and RFS2 Rule RIA Section 2.4.
---------------------------------------------------------------------------
g. Rows Q and T
Rows Q and T include pathways for renewable CNG/LNG produced from
biogas. Row Q includes pathways for D3 RINs for renewable CNG/LNG
produced from: biogas from landfills, municipal wastewater treatment
facility digesters, agricultural digesters, and separated MSW
digesters; and biogas from the cellulosic components of biomass
processed in other waste digesters. The pathways in Row Q qualify for
D3 RINs. Row T includes pathways for D5 RINs
[[Page 16459]]
for renewable CNG/LNG produced from biogas from waste digesters.\343\
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\343\ For background on the EPA's evaluation of these pathways,
see: 79 FR 42140-44 (July 18, 2014).
---------------------------------------------------------------------------
We are finalizing changes to Rows Q and T with revisions relative
to what we proposed based on our consideration of the comments. In the
production process requirements for Rows Q and T, we proposed to
replace ``Any'' with ``The following processes that occur in North
America: CNG production from treated biogas via compression; LNG
production from treated biogas via liquefaction.'' Commenters stated
that it could be problematic to reference the fuels (CNG/LNG) in the
production process requirements, and that CNG/LNG can also be produced
from biogas and RNG. Based on our consideration of these comments, we
are describing the production processes as ``Treatment and
compression'' and ``Treatment and liquefaction.'' Based on our
consideration of comments, we are also replacing the condition that the
production processes ``occur in North America'' with a condition that
the production process ``do[es] not transport RNG or renewable CNG/LNG
by ocean-going vessel.'' These modifications are discussed below.
Treatment and compression refers to the process of upgrading biogas
to RNG and subsequent compression to produce renewable CNG for use in
CNG vehicles. Treatment and liquefaction refers to the process of
upgrading biogas to renewable LNG for use in LNG vehicles. Treatment
begins with moisture and particulate removal from raw biogas, followed
by advanced cleaning technologies that remove carbon dioxide, non-
methane organic compounds and a variety of other contaminants including
sulfur compounds. Treatment technologies include the use of pressure
swing adsorption, water scrubbing, chemical absorption, membrane
separation, or other technologies to remove additional components so
the gas is suitable for injection into the natural gas commercial
pipeline system. The RNG is then transported and distributed to
refueling stations via the natural gas pipeline system, or potentially
in a tube as compressed gas or liquefied in a tank. Final compression
or liquefaction of the RNG at a refueling station depends on how the
gas will be used as a vehicle fuel. Compression is the physical
compression of RNG to produce renewable CNG, while liquefaction is the
physical conversion of RNG into a liquid state by cooling it to low
temperatures to produce renewable LNG.
As noted above, a commenter disagreed with the proposed condition
limiting the processes in Rows Q and T to ``processes that occur in
North America.'' In the Set 2 proposal, we explained that this
condition was appropriate because there could be CNG/LNG transportation
and distribution scenarios associated with high GHG emissions that we
did not consider in the lifecycle analyses that formed the basis for
Rows Q and T. We specifically discussed long-duration LNG
transportation with associated boil-off emissions as a scenario that
the underlying evaluation for Rows Q and T did not consider; we
estimated that transporting LNG is associated with boil-off emissions
of approximately 0.10 to 0.15 percent per day.\344\ Pursuant to the
definition of ``lifecycle greenhouse gas emissions,'' \345\ we always
evaluate emissions associated with transport of feedstocks and fuels in
our lifecycle emissions calculations. In the case of LNG transportation
in particular, the transport emissions have the potential to be
dispositive in terms of meeting the statutory emissions reduction
criteria to qualify for D3 or D5 RINs, so it is appropriate to
condition the pathway on this basis. Thus, the proposed condition that
CNG/LNG production processes ``occur in North America'' was intended to
exclude long international transportation of LNG that could result in
large boil-off or other sources of emissions that could be results in
the production process (including transportation and distribution) not
meeting the 50 percent or 60 percent emissions reduction threshold.
---------------------------------------------------------------------------
\344\ 90 FR 25848 (June 17, 2025).
\345\ ``The term `lifecycle greenhouse gas emissions' . . .
include[es] all stages of fuel and feedstock production and
distribution, from feedstock generation or extraction through the
distribution and delivery and use of the finished fuel to the
ultimate consumer. . . .'' CAA section 211(o)(1)(H).
---------------------------------------------------------------------------
However, based on our consideration of the public comments, the
restriction to North America raised other questions, such as whether
renewable CNG/LNG produced and used in Hawaii or other covered
locations would qualify for the Row Q and T pathways.\346\ Given that
our primary concern is long-duration international transportation and
distribution scenarios that would likely involve marine transport of
renewable CNG/LNG, we are instead finalizing a condition that the
production processes under Rows Q and T, ``do not transport RNG, or
renewable CNG/LNG by ocean-going vessel.'' \347\ We believe this change
more directly addresses our primary concern of long-duration
transportation scenarios. We note that renewable fuel producers seeking
to transport renewable CNG/LNG on ocean-going vessels can still
petition the EPA to evaluate a new pathway using the petition process
specified at 40 CFR 80.1416.
---------------------------------------------------------------------------
\346\ Covered location is defined as ``the contiguous 48 states,
Hawaii, and any state or territory that has received an approval
from EPA to opt-in to the RFS program.'' 40 CFR 80.2.
\347\ Ocean-going vessel is defined as ``vessels that are
equipped with engines meeting the definition of `Category 3' in 40
CFR 1042.901.'' 40 CFR 80.2.
---------------------------------------------------------------------------
h. Other Associated Regulatory Changes
The revisions described in this section VIII.D.1 of this preamble
do not affect existing pathway registrations and we are adding language
to 40 CFR 80.1426(f)(1) to clarify that a renewable fuel producer may
continue to use an existing registration that was under a pathway in
Table 1 that previously specified ``Any'' or ``Any process that
converts cellulosic biomass to fuel'' as its production process
requirement if the pathway was in the renewable fuel facility's
registration that was accepted by EPA prior to the effective date of
this rule. Producers with an existing pathway registration that
satisfies the above criteria do not need to update or modify their
registrations due to the Table 1 amendments in this action, nor will
any existing pathway registrations be deactivated. Any modifications to
the renewable fuel production facility's registration after the
effective date of this action must meet an approved pathway.\348\ These
provisions are appropriate as prior registrations were reviewed and
accepted by the EPA based on our engineering judgement and
interpretation of the fuel pathways in Table 1, including our
consideration of the parameters of the lifecycle analyses that formed
the basis for the approved pathways.
---------------------------------------------------------------------------
\348\ An approved pathway is defined as ``a pathway listed in
table 1 to Sec. 80.1426 or in a petition approved under Sec.
80.1416 that is eligible to generate RINs of a particular D code.''
40 CFR 80.2.
---------------------------------------------------------------------------
To provide additional clarity going forward regarding the criteria
the EPA will apply to determine whether a feedstock, fuel, or
production process qualifies for an approved pathway in Table 1, we are
adding the following language to 40 CFR 80.1426(f)(1): ``For purposes
of identifying the appropriate approved pathway, the fuel must be
produced, distributed, and used in a manner consistent with the pathway
EPA evaluated when it determined that the pathway satisfies the
applicable lifecycle emissions reduction requirement.'' One commenter
stated that this language was unnecessary and unhelpful, but based on
our experience
[[Page 16460]]
implementing the RFS program we believe adding this provision to the
regulations will improve program implementation and clarify how to
handle situations that have arisen in the past where a production
process appeared to meet the production process requirements in Table 1
but did not actually satisfy the statutory criteria.
i. Conclusion
We believe the revisions to Table 1 discussed in this section will
improve implementation of the RFS program in accordance with the
statutory criteria. Although we have strived to describe the pathways
in Table 1 in a manner that aligns with the lifecycle analysis that
supports each pathway, we recognize there will likely still be some
cases where it is not clear whether a particular production process
qualifies for a particular pathway. Renewable fuel producers seeking to
determine if their fuel fits within the bounds of a pathway listed in
Table 1 can contact the EPA through the pathway screening tool for
clarification.\349\ The pathway screening tool process was designed for
the express purpose of providing a means for renewable fuel producers
to seek input on whether a fuel fits an existing pathway in Table 1 or
whether a new renewable fuel pathway petition, pursuant to 40 CFR
80.1416, is needed prior to registering to generate RINs.
---------------------------------------------------------------------------
\349\ EPA, ``Renewable Fuel Pathway Screening Tool.'' https://www.epa.gov/renewable-fuel-standard-program/forms/renewable-fuel-pathway-screening-tool.
---------------------------------------------------------------------------
2. Adding Waste Fats, Oils, and Greases as Feedstock for Producing
Renewable Naphtha and LPG
As discussed in the Set 2 proposal, we are adding new pathways to
Row I for renewable naphtha and LPG produced from biogenic waste oils,
fats, and greases through a hydrotreating process to qualify for D5
RINs.\350\ Specifically, we are adding ``Biogenic waste oils/fats/
greases'' as a feedstock in Row I. As discussed in the Set 2 proposal,
we are adding these pathways based on our finding that these pathways
satisfy the statutory 50 percent lifecycle emission reduction criteria
to qualify for D5 RINs. We did not receive any comments opposing these
amendments.
---------------------------------------------------------------------------
\350\ 90 FR 25848-49 (June 17, 2025).
---------------------------------------------------------------------------
E. Updates to Definitions
1. New Definitions
The RFS regulations previously did not define the terms ``renewable
fuel producer,'' ``renewable fuel oil,'' ``renewable naphtha,'' and
``renewable jet fuel''; however, all these terms are used within the
RFS regulations. To provide regulatory clarity, we proposed to define
each of these terms in the Set 2 proposal. Commenters were generally
supportive of defining these terms but suggested minor revisions to
improve clarity and accuracy of the definitions. We have incorporated
these suggestions into our final definitions described below.
We are defining a renewable fuel producer as ``any person that
owns, leases, operates, controls, or supervises a facility where
renewable fuels are produced.'' This definition is consistent with
other definitions of regulated parties under the RFS program. We are
defining renewable fuel oil as ``heating oil that is renewable fuel and
that meets paragraph (2) of the definition of heating oil,'' renewable
naphtha as ``naphtha that is renewable fuel,'' and renewable jet fuel
as ``jet fuel that is renewable fuel and that meets ASTM D1655 or ASTM
D7566.'' These definitions are consistent with other definitions of
renewable fuels under the RFS program.
We believe these definitions will provide more clarity to both the
regulated community and the public.
2. Revised Definitions
Given the complex nature of global supply chains, we are updating
the definitions of foreign renewable fuel producers and importers as
proposed in the Set 2 proposal. These revisions will also provide
clarity to regulated parties regarding which entities qualify as
foreign renewable fuel producers or importers.
Under 40 CFR 80.2, a foreign renewable fuel producer was previously
defined as ``a person from a foreign country or from an area outside
the covered location who produces renewable fuel for use in
transportation fuel, heating oil, or jet fuel for export to the covered
location. Foreign ethanol producers are considered foreign renewable
fuel producers.'' This definition was unclear because renewable fuel
produced at a facility in the United States could arguably be
considered produced by a ``foreign renewable fuel producer'' if the
corporation that produced the renewable fuel is incorporated in a
foreign country. We are instead defining a foreign renewable fuel
producer as ``any person that owns, leases, operates, controls, or
supervises a facility outside the covered location where renewable fuel
is produced.'' This revised definition is consistent with how foreign
biogas producers and foreign RNG producers have been defined under the
RFS regulations.
Further, under 40 CFR 80.2 an importer was previously defined as
``any person who imports transportation fuel or renewable fuel into the
covered location from an area outside of the covered location.'' To
provide greater clarity to the regulated community as to which entities
can be considered an importer, we are revising the definition of
importer to include ``the importer of record or an authorized agent
acting on their behalf, as well as the actual owner, the consignee, or
the transferee, if the right to withdraw merchandise from a bonded
warehouse has been transferred.''
Finally, we are adding a provision in the liability provisions at
40 CFR 80.1461 that specifies that each person meeting the definition
of an importer of renewable fuel under the RFS regulations is jointly
and severally liable for any violations of the RFS requirements,
including the new import RIN reduction provisions. The change is
consistent with the liability framework for other parties participating
in the RFS program and the liability framework that applies in our fuel
quality program under 40 CFR part 1090. These provisions are also
necessary to ensure that importers who import non-qualifying renewable
fuel or renewable fuel feedstocks can be held liable.
3. New Biointermediates
In the 2020-2022 RFS Rule, we established provisions for
biointermediates to be used to produce qualifying renewable fuels. At
the same time, we listed in the regulations the specific
biointermediates that are allowed under the RFS program.\351\ We also
stated that new biointermediates would be brought into the RFS program
via notice-and-comment rulemaking. In the Set 1 Rule, we added biogas
as a biointermediate and in the Set 2 proposal we proposed to add two
more biointermediates: activated sludge and converted oils. These new
biointermediates were requested in two separate petitions for
rulemaking submitted to the EPA in 2023 and 2024.\352\ We are
finalizing the addition of these two new biointermediates in this
action.
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\351\ 87 FR 39600 (July 1, 2022).
\352\ ``Agresti Energy Petition to Add Potential
Biointermediates to the Regulatory Definition,'' October 12, 2023;
``DS Dansuk Petition for Addition of New Biointermediate Produced
via a New Production Process,'' November 26, 2024. Both petitions
are available in the docket for this action.
---------------------------------------------------------------------------
First, we are adding activated sludge, which is waste sludge from a
secondary wastewater treatment process involving oxygen and
microorganisms. One petitioner suggested that activated
[[Page 16461]]
sludge could initially be used to produce renewable CNG, potentially
followed by other fuels such as LNG, ethanol, biobutanol, and methanol
in the future. Second, we are adding converted oils, which are
glycerides such as monoglycerides and diglycerides that are produced
through the glycerolysis of waste oils, fats, or greases with glycerol.
Converted oils must exclusively consist of glycerides with fatty acid
alkyl groups that originate from qualifying biogenic waste oils, fats,
or greases during the conversion process. One petitioner suggested that
converted oils could be used to produce biodiesel, renewable diesel, or
jet fuel.
We are finalizing these changes as proposed. Several commenters
supported the proposed changes, while one commenter expressed concern
about considering activated sludge a biointermediate rather than simply
as an approved feedstock. In response to this comment, we want to
clarify that biogas from municipal wastewater treatment facility
digesters is already an approved feedstock in Rows Q and T, and such
pathways may involve the production of biogas from activated sludge at
the same facility where the activated sludge is produced. Furthermore,
biogas used to make a renewable fuel other than renewable CNG/LNG is
also a biointermediate.\353\ In cases where the activated sludge is
produced at one facility and used to produce renewable fuel at a second
facility, the activated sludge would need to be a biointermediate. This
is because activated sludge is produced from primary sludge, which has
been substantially altered through anaerobic and aerobic treatment.
Thus, by adding activated sludge as a new biointermediate, we are
facilitating the production of qualifying fuel from this material.
---------------------------------------------------------------------------
\353\ 40 CFR 80.2.
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F. Compliance Reporting, Recordkeeping, and Registration Provisions
1. Exempt Small Refinery Compliance Reporting
Under the RFS program, small refineries are eligible to petition
for and receive an exemption from their RFS obligations for a given
compliance year. The RFS regulations do not, however, exempt these
small refineries from having to submit an annual compliance report. In
the Set 2 proposal, we proposed to clarify that such exempt small
refineries must file an annual compliance report. Commenters were
generally supportive of this change and we are finalizing this
clarification as proposed.
While an exempt small refinery does not have to retire RINs to
comply with an RVO, it still produces gasoline or diesel that is used
as transportation fuel in the United States and thus this fuel is
included in EIA's projections of nationwide fuel consumption. We use
these projections as the basis for calculating the annual RFS
percentage standards and, as described in the Set 1 Rule, we have
recently discovered a discrepancy between the volumes of gasoline and
diesel reported by obligated parties in their annual compliance reports
and EIA's reported actual volumes of gasoline and diesel consumed.\354\
In order for the EPA to have a complete picture of the actual volume of
gasoline and diesel that was produced by refiners--including fuel
produced by exempt small refineries--that would otherwise be reported
as obligated fuel in a given compliance year, it is necessary that all
refiners submit an annual compliance report regardless of whether they
received an exemption from their RFS obligations for the given
compliance year. Having this data will improve the accuracy of our
gasoline and diesel projections in future standard-setting actions and
better ensure that there is not overcompliance by obligated parties.
Without gasoline and diesel production volumes from exempt small
refineries, we are more likely to underestimate the actual amount of
gasoline and diesel expected to be used in a given compliance year.
This would result in overly stringent percentage standards, and thus
more RINs would need to be retired than necessary to comply with the
annual volume requirements. Therefore, we are clarifying under 40 CFR
80.1441(e)(2) and 80.1442(h) that exempt small refineries and small
refiners are still subject to RFS reporting requirements under 40 CFR
80.1451(a) and must submit an annual compliance report by the annual
compliance reporting deadline. Such exempt small refineries will need
to report their actual annual production of gasoline and diesel that
would otherwise be obligated fuel.
---------------------------------------------------------------------------
\354\ Set 1 RIA, Chapter 1.11.
---------------------------------------------------------------------------
In addition, we also proposed to clarify under 40 CFR 80.1441(e)(2)
and 80.1442(h) that a small refinery or small refiner that receives an
exemption for a given compliance year is not exempt from having to
comply with any deficit RVOs that were carried forward from the
previous compliance year. Several small refinery commenters objected to
this clarification and claimed that this proposed change would negate
the intent behind both the deficit carryforward provision and small
refinery hardship relief. We disagree with these commenters and are
finalizing this clarification as proposed, consistent with our long-
standing interpretation and implementation of an exemption under the
SRE program. We address the specific concerns raised by commenters in
RTC Section 11.6.1.
2. Compliance Report Updates
We are finalizing several changes to requirements related to
compliance reports. Generally, these changes are intended to reduce
burden, support implementation, and improve the quality of information
submitted to the EPA under 40 CFR 80.1449, 80.1451, and 80.1452.
Commenters were generally supportive of these changes.
First, we are sunsetting the reporting requirement specific to how
each entity owning RINs must calculate the volume of renewable fuel (in
gallons) owned at the end of each quarter and report this on a
quarterly basis. The general requirements for RIN distribution specify
that the number of assigned RINs owned must be less than or equal to
the amount of renewable fuel owned multiplied by 2.5. However, since
2010 there have been no documented compliance issues with entities
meeting the distribution requirement for assigned RINs. To reduce
reporting burden, we are removing as proposed this quarterly reporting
requirement under 40 CFR 80.1451 and also updating the associated
requirement under 40 CFR 80.1428(a)(4).
Next, we are simplifying the ``production outlook report'' and its
associated requirements as proposed. Renewable fuel producers were
required to submit an annual ``production outlook report'' that
previously included a monthly or annual projection in future years; we
are now only requiring annual projections. Reducing this reporting
requirement to annual projections will reduce burden while maintaining
a minimum level of reporting needed to assess future production. We are
also updating or removing other outdated language under 40 CFR 80.1449.
Additionally, producers or importers of biogas used for
transportation fuel were required to report on a quarterly basis the
total energy produced and supplied for use as transportation fuel, as
well as where the fuel is sold for use as a transportation fuel. These
quarterly reporting requirements under 40 CFR 80.1451(b)(1)(ii)(P) were
similar to other existing reporting requirements under
[[Page 16462]]
40 CFR 80.140. We are therefore removing this separate quarterly
reporting requirement as proposed to further reduce reporting burden.
Finally, we are taking steps to improve the quality of information
when entities generate RINs in EMTS. Currently, each reporting party
must enter a ``reason code'' whenever they are reporting a buy, sell,
separate or retire transaction in EMTS, as described in 40 CFR 80.1452.
This information is then used for implementation, compliance, and
public data postings on our website. As proposed, we are now adding a
``reason code'' for RIN generation to directly improve implementation.
For example, commenters noted long delays by the EPA in processing
report corrections in EMTS and we will first use this new field to
automate processing report corrections submitted by renewable fuel
producers (e.g., under-generation of RINs). We will initially utilize a
transition period that only requires entities submitting report
corrections to complete this new element followed by full
implementation starting on January 1, 2027. We will also post
additional information specific to compliance assistance and technical
support material on our website while gradually phasing in this new
field and closely monitoring feedback towards improving implementation
and automation.
3. Third-Party Auditor Registration Renewal
We are changing the frequency with which independent third-party
auditors are required to renew their registrations. Previously, a
third-party auditor's registration expired each year on December 31.
However, we have found that there is significant burden on both the EPA
and auditors to review and approve these registrations every year. We
believe that it is not necessary to require auditors to renew their
registrations annually and that a two-year registration period is more
appropriate. This length of time still ensures that we are regularly
reviewing auditor registrations, while also reducing burden on the EPA
and auditors. Commenters were generally supportive of this change.
Thus, we are specifying that a third-party auditor's registration will
expire on December 31 every other year.
4. Engineering Review Site Visits
Under 40 CFR 80.1450(b)(2), renewable fuel production facilities
are required to undergo an independent third-party engineering review
prior to registration. As part of that engineering review, the
independent third-party engineer is required to conduct a site visit.
However, the previous regulations did not specify when such site visits
need to occur. Recently, we have received some engineering reviews
where the site visit was over a year old. In the Set 2 proposal, we
proposed to specify that engineering review site visits must be
conducted within six months prior to submitting a registration request
in order to ensure that the site visit is reflective of the current
operation of the facility. Several commenters expressed concern about
the limited number of qualified engineers to conduct such reviews.
However, we believe that it is critical that the engineering review
site visit accurately reflects the current operations of the facility.
We are therefore finalizing the requirement for engineering review site
visits to be conducted within six months prior to submitting a
registration request, as proposed.
5. Biogas Batch Period of Production
As part of the biogas regulatory reform provisions in the Set 1
Rule, a batch of biogas was specified as the volume of biogas measured
for a calendar month, with the last day of the month as the production
date.\355\ Stakeholders have subsequently provided feedback to the EPA
that allowing biogas producers to produce batches for time periods of
less than a month would improve implementation of the biogas
regulations. To provide additional flexibility for biogas producers, in
the Set 2 proposal we proposed to change the period of production such
that a biogas batch may be ``up to'' a calendar month, allowing for
more frequent biogas batches as indicated by the business practices of
the biogas producer. This change also provides additional flexibility
to RNG producers that use the biogas batches as part of their RNG RIN
generation. Commenters were generally supportive of this change, and we
are therefore finalizing this flexibility as proposed.
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\355\ 40 CFR 80.105(j)(1) and 80.140(b)(2).
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G. New Approved Measurement Protocols
In the Set 2 proposal, we proposed to add measurement protocols to
the list of approved methods for measuring the volume of RNG or treated
biogas. Commenters were generally supportive of adding these methods to
the regulations and suggested additional methods that could be added.
We agree with commenters and have included these additional methods in
the list of approved methods, as we have already accepted all these
methods through alternative measurement protocols.\356\ The methods we
are adding under 40 CFR 80.155(a) are the following: AGA Report No. 3;
AGA Report No. 7; AGA Report No. 9; AGA Report No. 11; ASME MFC-3M;
ASME MFC-5.1; ASME MFC-11; ASME MFC-12M; ASME MFC-21.2; ANSI B109.3;
API MPMS 14.9; ISO 5167-1 and ISO 5167-2, ISO 5167-4, or ISO 5167-5;
ISO 10790; ISO 14511; ISO 17089-1; and ISO 17089-2.
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\356\ EPA, ``Alternative Measurement Protocols for Biogas and
Renewable Natural Gas,'' https://www.epa.gov/fuels-registration-reporting-and-compliance-help/alternative-measurement-protocols-biogas-and-0.
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We also proposed to add methods for the measurement of biogas and
RNG samples under 40 CFR 80.155(b)(2). Commenters were generally
supportive of adding these methods to the regulations and suggested
additional methods that could be added. We agree with commenters and
have included these additional methods in the list of approved methods.
For methane, carbon dioxide, nitrogen, and oxygen, we are adding ASTM
D1945, ASTM D1946, and ASTM D7833; previously, the only specified
method was EPA Method 3C. For hydrogen sulfide and total sulfur, we are
adding ASTM D6228 and ASTM D6968; previously the only specified method
was ASTM D5504. For moisture, we are adding ASTM D1142, ASTM D5454, and
ASTM D7904; previously, the only specified method was ASTM D4888. For
hydrocarbon analysis, we are adding ASTM D1945, ASTM D1946, ASTM D7833,
and EPA Method TO-15; previously, the only specified method was EPA
Method 18.
H. Biodiesel and Renewable Diesel Requirements
We did not propose and are not finalizing any changes to the sulfur
standards for biodiesel or renewable diesel in this action. However, we
are taking this opportunity to reiterate that biodiesel and renewable
diesel producers must comply with all of our regulatory requirements
for diesel producers in 40 CFR part 1090 for the biodiesel and
renewable diesel they produce (referred to as ``nonpetroleum diesel
fuel'' in 40 CFR part 1090), including demonstrating homogeneity for
each batch of biodiesel and renewable diesel and testing each batch for
sulfur content to ensure the fuel meets the 15 ppm standard.\357\ This
also
[[Page 16463]]
includes the requirement that all sulfur test results must be obtained
by the producer before shipping biodiesel or renewable diesel from the
facility. Requiring measurement before shipping provides assurance of
compliance prior to the fuel being mixed and comingled in the fungible
distribution system.
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\357\ We have previously made clear that biodiesel producers
must comply with all our regulatory requirements for diesel
producers. See EPA, ``Guidance for Biodiesel Producers and Biodiesel
Blenders/Users,'' EPA-420-B-07-019, November 2007; see also EPA ``Am
I required to register biodiesel? How would I do that?'' April 1,
2025. https://www.epa.gov/fuels-registration-reporting-and-compliance-help/am-i-required-register-biodiesel-how-would-i-do.
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To further make clear that all the above requirements apply to
biodiesel and renewable diesel, we proposed to clarify the language at
40 CFR 1090.300(a), 1090.305(a), 1090.1310(b)(1), and 1090.1337(e).
Commenters were generally supportive of these clarifications, and we
are finalizing these changes as proposed with minor clerical revisions
to the proposed language.
I. Extension of RFS Compliance Reporting Deadlines
In 2022, we finalized changes to the way the RFS compliance and
attest engagement reporting deadlines are determined.\358\ Prior to
that action, the compliance and attest engagement reporting deadlines
for a given compliance year were March 31 and June 1 of the subsequent
year, respectively, even if the applicable RFS standards for that year
had not yet been established. Any change to these deadlines required
the EPA to undertake a notice-and-comment rulemaking process to revise
the RFS regulations on a case-by-case basis. However, under the new
provisions finalized in 2022, the annual compliance reporting deadline
is the latest date of the following: \359\
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\358\ 87 FR 5696 (February 2, 2022).
\359\ 40 CFR 80.1451(f)(1)(i)(A).
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March 31st of the subsequent calendar year;
The next quarterly reporting deadline after the effective
date of the subsequent compliance year's standards (typically 60 days
after publication of the final rule in the Federal Register); or
The next quarterly reporting deadline under 40 CFR
80.1451(f)(2) after the annual compliance reporting deadline for the
prior compliance year.
In December 2024, we proposed to add a new provision that would
automatically extend the annual compliance reporting deadline for a
given compliance year if we propose to revise an existing RFS standard
for that year.\360\ Some commenters supported the certainty that this
change would provide to stakeholders when EPA proposes to revise an
existing RFS standard, while other commenters expressed concern that
these provisions were unnecessary and could undermine RFS program
integrity. On balance, we find that the benefits of the proposed new
compliance date extension provisions outweigh the concerns raised by
some commenters and we are finalizing the provisions as proposed. We
address the specific concerns raised by commenters in RTC Section 11.9.
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\360\ 89 FR 100442 (December 12, 2024).
---------------------------------------------------------------------------
Under this approach, the publication of a document in the Federal
Register proposing to revise a renewable fuel standard in 40 CFR
80.1405(a) will automatically extend the annual compliance reporting
deadline for that year to the next quarterly reporting deadline after
either: (1) The effective date of the final rule that revises the
existing standard (typically 60 days after publication of the final
rule in the Federal Register); or (2) 60 days after the publication of
a document in the Federal Register withdrawing the proposed revision.
However, if we do not either finalize or withdraw the proposed revision
within 12 months after the proposed rule is published, we are limiting
the extension in this specific circumstance to no more than the next
quarterly reporting deadline that is 12 months after the date of
publication of the proposed rule.\361\ We believe that this provides
sufficient time for the EPA to either finalize or withdraw the proposed
revision to an existing RFS standard and do not want to indefinitely
extend the compliance reporting deadline for a compliance year with
already established RFS standards.
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\361\ We note that under any of these scenarios, the applicable
compliance reporting deadline in 40 CFR 80.1451(f)(1)(i)(A) or (B)
of this section would apply if it were later than the proposed
extension (e.g., the deadline would be no earlier than March 31 of
the subsequent calendar year or the next quarterly reporting
deadline after the annual compliance reporting deadline for the
prior compliance year).
---------------------------------------------------------------------------
Essentially, this new provision means that the mere proposal--as
opposed to a final action--by the EPA to change an existing RFS
standard would change the associated compliance reporting deadline for
that compliance year. This change is being made because by the time the
need is evident to extend the compliance deadline, there is often
inadequate time to both propose and finalize a rulemaking to do so. And
even when we have undertaken rulemakings to extend compliance
deadlines, these actions have required significant time and resources
by EPA staff that could have been dedicated to other Agency priorities.
By further automating the extension of compliance deadlines when we
propose to revise an existing RFS standard, EPA staff will have more
time to work on the final rulemaking to revise the existing RFS
standard. This will likely result in the final rule being completed
sooner than it would otherwise if the same EPA staff had to work on a
separate final rule to first extend the associated compliance deadline
before then revising the existing RFS standard.
As an example, under this approach, if the 2026 compliance deadline
was originally established as March 31, 2027, but then we proposed to
revise the 2026 cellulosic biofuel standard on November 30, 2026, the
2026 compliance reporting deadline would be automatically extended
until the first quarterly reporting deadline after the effective date
of the final rule establishing the revised 2026 cellulosic biofuel
standard. We would not have to separately propose to extend the 2026
compliance reporting deadline in that same action, because the deadline
would be automatically extended by operation of law. If we then
finalized the proposed revision to the 2026 cellulosic biofuel standard
on February 15, 2027, with an effective date of April 16, 2027, the
2026 compliance reporting deadline would be June 1, 2027 (i.e., the
next quarterly reporting deadline after the effective date of the final
rule). Alternatively, if we chose not to finalize the proposed revision
to the 2026 cellulosic biofuel standard and instead published a
document in the Federal Register to withdraw the proposed revision on
April 30, 2027, the 2026 compliance reporting deadline would be
September 1, 2027 (i.e., the next quarterly reporting deadline that is
at least 60 days after publication of that document in the Federal
Register). Finally, if we took no action after proposing to revise the
2026 cellulosic biofuel standard, the 2026 compliance deadline would be
December 1, 2027 (i.e., the next quarterly reporting deadline that is
12 months after the date of publication of the proposed rule).
This approach will provide regulatory certainty for obligated
parties by clearly establishing future compliance deadlines when we
propose to change a previously established RFS standard, thereby
preventing unnecessary burden on obligated parties to prepare, submit,
and then possibly retract and revise compliance reports for deadlines
that were later extended. This approach is consistent with our prior
rules extending RFS compliance reporting deadlines in different factual
[[Page 16464]]
circumstances \362\ and with D.C. Circuit's decisions on this
issue.\363\
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\362\ 86 FR 17073 (April 1, 2021); 87 FR 5696 (February 2,
2022).
\363\ Wynnewood Refining Co., LLC, et al. v. EPA, 77 F.4th 767,
779 (D.C. Cir. 2023) (``Thus, rather than task EPA with overseeing a
fixed compliance schedule, the Act gives EPA flexibility to craft
and adjust a compliance regime in service of the Act's core mandate:
to ensure the Act's annual renewable fuel volumes are met.''). See
also ACE, 864 F.3d at 718-21; Monroe Energy, LLC v. EPA, 750 F.3d
909, 919-20 (D.C. Cir. 2014); Nat'l Petrochemical & Refiners Ass'n
v. EPA, 630 F.3d 145, 154-58) (D.C. Cir. 2010).
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J. Biogas Regulations
In December 2024, we proposed minor revisions to two main areas of
the RFS program's biogas regulations that were identified after the EPA
and market participants began implementing the regulations promulgated
in the Set 1 Rule.\364\ First, we proposed to clarify and provide
flexibility for how biogas, RNG, and renewable CNG/LNG are measured,
sampled, and tested to demonstrate compliance. Second, we proposed
several clarifying technical amendments to the biogas regulations.
Commenters were generally supportive of all these changes, with several
suggesting minor revisions or additions to our proposed language. As
described in more detail below, we are finalizing these clarifications
largely as proposed with mostly minor clerical revisions to the
proposed language. We address stakeholders' specific comments on these
changes in RTC Section 11.10.
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\364\ 89 FR 100442 (December 12, 2024).
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1. Measurement, Sampling, and Testing
We are finalizing revisions to align the testing frequency of
pipeline-specified components for RNG with the reporting frequency for
those pipeline specification components. Previously, RNG producers
needed to annually sample and test their RNG to demonstrate that the
RNG production facility was producing RNG that met applicable pipeline
specifications,\365\ and they needed to submit these results as part of
their three-year registration updates.\366\ Stakeholders have
highlighted the disconnect between the annual testing requirement and
the three-year reporting requirement. Since we only collect this
information as part of the three-year engineering review update, we
believe it appropriate to only require sampling and testing of RNG once
every three years, rather than each year, and are revising 40 CFR
80.110(f)(2)(iii) to this end. We are further clarifying that such
sampling and testing is required beginning with three-year engineering
review updates submitted on or after January 1, 2027.
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\365\ 40 CFR 80.110(f)(2)(iii).
\366\ 40 CFR 80.135(d)(6).
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We are also finalizing clarifications to the regulations to
reinforce that we may approve alternative test methods for testing
components of RNG and that we may exempt the testing of a component
that is not required under the RNG producer's applicable pipeline
specifications. Specifically, we are revising 40 CFR 80.135(d)(6),
which contains the information related to RNG quality that RNG
producers must provide (including certificates of analysis for RNG
components), to allow alternatives to the test methods for individual
RNG components that are specified at 40 CFR 80.155(b). We will assess
alternative test methods based on whether the requested alternative
test method provides results that are reasonably accurate to the
results provided by the method specified at 40 CFR 80.155(b). While
under 40 CFR 80.135(d)(6)(v) RNG producers can already request
alternative methods and exemption from non-specified parameters, we
believe that adding further clarification will help alleviate
stakeholder confusion concerning the sampling and testing requirements
for RNG.
In order to streamline the alternative measurement protocol
approval and registration acceptance process, we are finalizing the
removal of the requirement that biogas and RNG production facilities
must demonstrate that their facility is incapable of using certain
specified meters in order to receive an alternative measurement
protocol. After promulgation of the biogas regulatory reform provisions
in the Set 1 Rule, we have received dozens of alternative measurement
protocol submissions and issued guidance for the application of the
criterion that a facility demonstrate that it is incapable of using the
specified meters.\367\ We have determined that many of these meters are
as accurate and precise as those specified in the regulations, and have
also received a number of registration submissions for facilities that
have demonstrated the appropriateness of using such meters.\368\ Based
on our review of the alternative measurement protocol and registration
submissions and the new information we have obtained in the course of
this review, we believe that the first criterion whereby a facility
must demonstrate that they cannot use the specified meters is not
necessary to ensure the accurate and precise measurement of biogas and
RNG under the RFS program.\369\ We are also removing the associated
requirement that biogas producers and RNG producers demonstrate at
registration that they are unable to use the meters specified.\370\
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\367\ EPA, ``Biogas Regulatory Reform Rule Criteria for
Qualifying for an Alternative Measurement Protocol Guidance,'' EPA-
420-B-24-014, March 2024.
\368\ A list of approved alternative measurement protocols can
be found at: https://www.epa.gov/fuels-registration-reporting-and-compliance-help/alternative-measurement-protocols-biogas-and-0.
\369\ 40 CFR 80.155(a)(3)(i).
\370\ 40 CFR 80.135(c)(3)(iii)(A) and (d)(3)(iii)(A).
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Finally, we note that due to the numerous changes to the provisions
of 40 CFR 80.155(a) in this action, we are restructuring 40 CFR
80.155(a) to ensure that the measurement requirements for biogas,
treated biogas, RNG, and renewable CNG/LNG are clearly enumerated.
2. Other Amendments
We are finalizing clarifications to the provisions surrounding the
annual attest engagement procedures for biogas producers, RNG
producers, and RNG RIN separators at 40 CFR 80.165. These changes
clarify that annual attest engagements are only required for parties
that engage in activities regulated under biogas regulatory reform in a
given compliance year (e.g., an RNG RIN separator only needs to obtain
an annual attest engagement if they separate RNG RINs in a compliance
year).
We are also clarifying that any party transferring RINs assigned to
a volume of RNG is deemed to also be transferring a corresponding
volume of RNG for the purposes of 40 CFR part 80 (i.e., the RFS
program). The original language in 40 CFR 80.125(c)(3) led to confusion
among stakeholders as to whether physical volumes of RNG were required
to be exchanged when transferring assigned RNG RINs. We are replacing
this language with text that makes clear that when a party transfers
title of an assigned RNG RIN to another party, they are deemed to have
also transferred a corresponding volume of RNG to the transferee. We
are also clarifying under 40 CFR 80.1460(a)(4) that, while it need not
be the same volume of RNG used for RIN generation, the transferee
taking title to the assigned RNG RINs must also acquire a corresponding
volume of RNG.
We are clarifying that all biogas production facilities registered
under the previous biogas provisions (i.e., registered under 40 CFR
80.1450(b) to generate RINs under 40 CFR 80.1426(f)(10) or (11)) do not
need updated engineering reviews as part of registering for the new
biogas provisions. In the Set 1 Rule, we intended to allow all
previously
[[Page 16465]]
registered biogas production facilities that did not undergo changes as
a result of the new biogas provisions to rely on their existing
engineering reviews until their next three-year engineering review is
due. However, after promulgation of the new biogas provisions,
stakeholders noted that the language in the regulations appears to
limit this allowance to only those biogas production facilities in a
biogas closed distribution system. Therefore, we are revising 40 CFR
80.135(b)(2)(ii) to make it clear that all previously registered biogas
production facilities can use their existing engineering review until
the next one is due. We note, however, that if changes to the facility
are needed that would otherwise require a new engineering review, the
new engineering review must be submitted regardless of this
flexibility.
We are also making two changes to the registration requirements for
RNG RIN separators under 40 CFR 80.135(f). First, we are requiring
that, as part of the information submitted at registration, RNG RIN
separators must provide the location on the natural gas commercial
pipeline system where the RNG is withdrawn, which is information we
already require to be reported in periodic reports under 40 CFR
80.140(e)(1). In addition, as part of the forms and procedures
established for those reports, we require that the RNG RIN separator
include an EPA-issued facility registration system identification (FRS
ID) number. While most withdrawal points have previously assigned FRS
ID numbers, some do not. Due to how the EPA's registration system is
designed, the only way to obtain those new FRS ID numbers is at the
point of registration. Therefore, to aid in the timely submittal of
reports, we are clarifying that RNG RIN separators must supply the
withdrawal locations at registration.
Second, we are removing the limitation at 40 CFR 80.115(b) that a
CNG/LNG dispensing location may only be part of one RNG RIN separator's
registration at a time. Based on our experience implementing the
program, it is difficult for parties to know which RNG RIN separator
has registered for a particular CNG/LNG dispensing location. Under the
previous framework, there was a perverse incentive for an RNG RIN
separator to register for a CNG/LNG dispensing location in order to
block another party from registering that location and prevent that
party from separating RNG RINs for transportation fuel dispensed at
that location--even though the registering party does not maintain an
actual relationship to that location. Removing this restriction will
allow a dispensing location to be in multiple parties' registrations,
thereby avoiding the situation where one party that does not intend to
actually dispense renewable CNG/LNG can block another party that does
intend to dispense renewable CNG/LNG from separating RINs at that
location. However, we are maintaining the limitation at 40 CFR
80.125(d)(2)(v) that only one party may actually separate RINs for a
given CNG/LNG dispensing location during a calendar month. We continue
to believe that this restriction is necessary to preclude double
counting of RINs because it is the limitation that only one party can
separate RINs for a volume dispensed at a station during a given month
that avoids double-counting, not whether multiple parties reflect that
station in their registration information on file with the EPA.
K. Technical Amendments
We are finalizing numerous technical amendments to the RFS
regulations. These amendments are being made to correct minor
inaccuracies and clarify the current regulations. These changes are
described in Table VIII.K-1.
BILLING CODE 6560-50-P
[[Page 16466]]
[GRAPHIC] [TIFF OMITTED] TR01AP26.075
[[Page 16467]]
[GRAPHIC] [TIFF OMITTED] TR01AP26.076
BILLING CODE 6560-50-C
IX. Set 1 Remand
On June 20, 2025, the D.C. Circuit issued an opinion in CBD, a
challenge by multiple petitioners to the Set 1 Rule. The majority
opinion held that the EPA had reasonably considered and balanced the
statutory factors to determine the required volumes of renewable fuel,
with one exception concerning the consideration of climate change
impacts.
CAA section 211(o)(2)(B)(ii) states that the basis for setting
applicable renewable fuel volumes after 2022 under the RFS program must
include, among other things, ``an analysis of . . . the impact of the
production and use of renewable fuels on the environment, including on
. . . climate change.'' Accordingly, we conducted an analysis of the
potential climate change impacts of the 2023-2025 standards finalized
under the Set 1 Rule. Our climate change analysis for the Set 1 Rule
relied on two distinct and sequential analytical steps:
1. We conducted a broad review of lifecycle GHG emissions analyses
published in peer reviewed literature and government reports for
biofuels affected by the RVO standards and for the fossil fuels that
those biofuels are intended to displace.\371\ This review produced
ranges of published lifecycle GHG emissions estimates for each fuel
type.
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\371\ Studies identified and associated ranges of lifecycle GHG
emissions estimates for each fuel pathway are discussed in Set 1 RIA
Chapters 4.2.2.2 through 4.2.2.12 and summarized in Set 1 RIA
Chapter 4.2.2.13.
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2. We used a subset of the studies identified in the literature
review described above to construct two scenarios illustrating a range
of potential monetized GHG emissions impacts associated with the RVO
standards.\372\
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\372\ Ranges of lifecycle GHG emissions estimates used for
monetization of potential impacts of the Set 1 volume standards and
monetized impacts estimates are presented, respectively, in Set 1
RIA Chapters 4.2.3 and 4.2.4.
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In CBD, the D.C. Circuit noted that, in general, the EPA used the
high- and low-end estimates of GHG emissions to construct the best- and
worst-case scenarios of monetized GHG emissions
[[Page 16468]]
impacts. However, the Court also stated that the EPA took a different
approach for the category of biofuels produced from crops;
specifically, that the Agency relied on just a subset of studies that
did not represent the full range of GHG emissions when monetizing the
impacts of crop-based biofuels. The Court then held that the EPA had
failed to articulate a rational explanation for limiting the
calculation of monetized impacts for crop-based biofuels to only a
subset of the LCA studies identified in the EPA's literature review.
The Court stated that ``EPA's unexplained decision to generally rely on
[ranges of GHG emissions estimates from credible publications] for
every other fuel category and to disregard them for crop-based
renewable fuels in favor of ranges derived from its dated 2010 study
was arbitrary and capricious.'' \373\ The Court raised concerns with
the EPA's justification for relying on the EPA's 2010 analyses of crop-
based fuels in the monetization of GHG emissions impacts and remanded
these issues back to the EPA for further explanation.\374\ We intend
the discussion below to fulfill our obligation to provide further
explanation in response to this remand.
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\373\ CBD at 173.
\374\ Analyses of crop-based fuels conducted for the RFS2 Rule
are discussed in Section 2.6.1 of the RFS2 Rule RIA (EPA, ``RFS2
Regulatory Impact Analysis,'' EPA-420-R-10-006, February 2010).
Annual estimates used in the monetization calculation were included
in the docket for the RFS2 Rule (EPA-HQ-OAR-2005-0161).
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First, the Court noted that the EPA had made conflicting statements
in the Agency's justification for why it relied on only the 2010
analyses for crop-based fuels, as opposed to the full range of GHG
emissions estimates from the literature. The Court stated that the EPA
had explained that the 2010 analyses provided the only estimates of GHG
emissions reported on an annual basis.\375\ However, the Court pointed
out that the EPA had also stated that ``[t]he majority of the land use
change GHG estimates in the literature--i.e., not all of them--do not
report an annual stream [of GHG emissions impacts].'' \376\ Thus, the
Court understood the EPA to have belied its assertion that ``only'' the
2010 analyses were a sufficient basis for monetizing the GHG emissions
impacts of crop-based biofuels. That is, it appears the Court believed
there were additional studies the Agency could have relied on for this
purpose.
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\375\ Annualized GHG emissions estimates were necessary to
monetize the impacts of those emissions under the guidance that was
in place at the time of the Set 1 rulemaking. The methodology used
to monetize estimated GHG emissions impacts in the Set 1 Rule was
based on the guidance provided by the February 2021 Technical
Support Document: Social Cost of Carbon, Methane, and Nitrous Oxide
Interim Estimates under Executive Order 13990, available to the
docket in the Set 1 Rule (EPA-HQ-OAR-2021-0427-0339). That guidance
provided factors expressed as dollars-per-ton of emissions in each
individual year. Thus, to appropriately use the guidance on
monetizing emissions impacts, it was necessary for emissions
estimates to be projected for each individual year being assessed.
\376\ CBD, 141 F.4th at 174.
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The EPA is clarifying here that its statement in the Set 1 RIA that
``[t]he majority of the land use change GHG estimates in the literature
do not report an annual stream'' meant that all the land use change GHG
estimates in the literature except EPA's 2010 analyses did not report
annual streams of emissions. That is, for the crop-based fuels assessed
in the Set 1 RIA--corn ethanol and soy biodiesel--the EPA's 2010
analyses were the only studies within the literature review which
provided emissions estimates that were suitable for estimating
monetized emissions impacts. No other analyses were identified in the
literature review that the EPA could have used to estimate annual
streams of emissions impacts.
Second, the Court stated that the EPA justified using only the
Agency's 2010 analyses of crop-based fuels in the monetized impacts
calculation by arguing that the full range of estimates in the
literature systematically overestimates GHG emissions from land use
changes. The Court then noted that ``that assertion of systemic skew is
contradicted by EPA's own figures showing that GHG emissions estimates
drawn from the literature review were effectively identical to those
included in the 2010 study for all crop-based renewable fuel--except
corn-based ethanol.'' \377\
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\377\ CBD, 141 F.4th at 174.
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We are clarifying and reinforcing here that our sole reliance on
the 2010 analyses to monetize the GHG emissions impacts of crop-based
fuels was because these were the only studies available that were
suitable for such a calculation for the reason discussed above; the
only studies within the literature review with annual emissions
estimates were our 2010 analyses. We did not argue in the Set 1 Rule
that estimates identified in the literature review systematically
overestimated emissions from land use change, nor would we agree with
such a statement in general. To the contrary, the Set 1 RIA explicitly
states that the EPA did not adjudicate relative strengths or
appropriateness of the various studies and that the literature review
was designed to be inclusive of all published comparable
estimates.\378\
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\378\ See Set 1 RIA at 125 (June 2023, EPA-420-R-23-015):
``Given that all LCA studies and models have particular strengths
and weaknesses, as well as uncertainties and limitations, our goal
for this compilation of literatures estimates is to consider the
ranges of published estimates, not to adjudicate which particular
studies, estimates or assumptions are most appropriate . . . Our
review is intentionally broad and inclusive, and is informed by our
experience conducting LCA evaluations of transportation fuels for
the RFS program.''
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As noted by the Court, the range of corn ethanol emissions
estimates identified in the Set 1 Rule literature review (38 to 116
gCO2e/MJ) was wider than the range of emissions estimates of
the studies used in the monetized impacts calculation (49 to 91
gCO2e/MJ). Relatedly, the Court raised concerns that this
``unexplained discrepancy is particularly problematic for EPA because
[corn ethanol] plays an outsized role in the program overall. Corn-
based ethanol is by volume the largest category of renewable fuel
produced in the United States--and it drives the largest aggregate
portion of GHG emissions attributable to renewable fuels. If EPA
improperly relied on a lower high-end emission estimate for corn-based
ethanol, it lacks support for its climate conclusion that `on average
[corn-based ethanol] provides some GHG reduction in comparison to
gasoline.' '' \379\
---------------------------------------------------------------------------
\379\ CBD, 141 F.4th at 174.
---------------------------------------------------------------------------
As explained above, we considered all available GHG emissions
estimates identified in the literature that were suitable for the
monetized impacts calculation. The only studies of crop-based fuels
that met these criteria were the EPA's 2010 analyses of those fuels. We
also note that it is not necessarily the case that using a larger range
of emissions estimates (higher and lower) would have resulted in higher
and lower monetized GHG emissions impacts. Due to complexities in the
timing and relative magnitude of GHG emissions associated with crop-
based biofuels (e.g., there may be large pulses of emissions early in
the time period analyzed followed by smaller amounts of emissions, or
even negative emissions, later on in the time period analyzed),
monetized impacts do not necessarily scale linearly with emissions.
This is why annualized estimates are needed to monetize emissions--an
annual average or net emissions estimate alone does not provide the
necessary timing and magnitude information required for monetization.
Additionally, while corn ethanol does represent the largest category of
biofuel generating credits under the RFS program, it represented only
15 percent of the difference in total biofuel use associated with the
fuel volumes that we modeled to be
[[Page 16469]]
attributable to the Set 1 rule, relative to a scenario in which there
were no RFS standards for 2023, 2024, and 2025.\380\ Thus, while it is
not possible to accurately monetize the impacts of the full range of
GHG emissions estimates from the full literature review, any
discrepancy is limited to a small minority (15 percent by energy
content) of the total volumes of fuels assessed.
---------------------------------------------------------------------------
\380\ The impact on corn ethanol consumption volumes
attributable to the RFS program is discussed in Set 1 RIA Chapters
2.1.1 and 3.2.
---------------------------------------------------------------------------
X. Administrative Actions
A. Assessment of the Domestic Aggregate Compliance Approach
The RFS regulations specify an ``aggregate compliance'' approach
for demonstrating that planted crops and crop residue from the U.S.
comply with the ``renewable biomass'' requirements that address lands
from which qualifying feedstocks may be harvested.\381\ In the RFS2
Rule, we established a baseline number of acres for U.S. agricultural
land in 2007 (the year of EISA's enactment) and determined that as long
as this baseline number of acres is not exceeded, it is unlikely, based
on our assessment of historical trends and economic considerations,
that new land outside of the 2007 baseline is being devoted to crop
production for renewable fuel production. The regulations specify,
therefore, that renewable fuel producers using planted crops or crop
residue from the U.S. as feedstock in renewable fuel production need
not undertake individual recordkeeping and reporting related to
documenting that their feedstocks come from qualifying lands, unless
the EPA determines through one of its annual evaluations that the 2007
baseline acreage of 402 million acres of agricultural land has been
exceeded. The RFS regulations require the EPA to make an annual finding
concerning whether the 2007 baseline amount of U.S. agricultural land
has been exceeded in a given year. If the baseline is found to have
been exceeded, then producers using U.S. planted crops and crop residue
as feedstocks for renewable fuel production would be required to comply
with individual recordkeeping and reporting requirements to verify that
their feedstocks are renewable biomass.
---------------------------------------------------------------------------
\381\ 40 CFR 80.1454(g). We established the ``aggregate
compliance'' approach in the 2010 RFS2 rule and has applied it for
the U.S. in annual RFS rulemakings since then. 75 FR 14701-04 (March
26, 2010). In this final rule, we have not reexamined or reopened
this policy, including the regulations at 40 CFR 80.1454(g) and
80.1457. Similarly, as further explained below, we have applied this
approach for Canada since our approval of Canada's petition to use
aggregate compliance in 2011. In this final rule, we have also not
reexamined or reopened our decision on that petition. Any comments
we received on these issues are beyond the scope of this rulemaking.
---------------------------------------------------------------------------
USDA provided the EPA with data from the discontinued Grassland
Reserve Program (GRP) and Wetlands Reserve Program (WRP) as well as the
Agricultural Land Easements (ACEP-ALE) and the Wetlands Reserve
Easements (ACEP-WRE) programs. Based on data from reduced cropland
based on historic programs, WRE and GRP, estimated cropland reached
approximately 372.4 million acres in 2024 and thus did not exceed the
2007 baseline acreage of 402 million acres.\382\ We will continue to
monitor total agricultural land annually to determine if national
agricultural land acreage increases above this 2007 national aggregate
baseline, as specified in the RFS2 Rule.\383\
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\382\ For additional analysis and the underlying USDA data, see
``Assessment of Domestic Aggregate Compliance Approach 2024,''
available in the docket for this action.
\383\ 75 FR 14701 (March 26, 2010).
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B. Assessment of the Canadian Aggregate Compliance Approach
The RFS regulations specify a petition process through which we may
approve the use of an aggregate compliance approach for planted crops
and crop residue from foreign countries.\384\ On September 29, 2011, we
approved such a petition from the Government of Canada.\385\ The 2007
baseline acreage for Canadian agricultural land is 122.1 million acres.
The total agricultural land in Canada in 2025 is estimated at 115.4
million acres. This total agricultural land area includes 94.6 million
acres of cropland and summer fallow, 11.0 million acres of pastureland,
and 9.8 million acres of agricultural land under conservation
practices. This acreage estimate is based on the same methodology used
to set the 2007 baseline acreage for Canadian agricultural land in our
response to Canada's petition. This 2025 acreage does not exceed the
2007 baseline acreage of 122.1 million acres.\386\ We will continue to
monitor total agricultural land annually to determine if Canadian
agricultural land acreage increases above its 2007 aggregate baseline,
as specified in the RFS2 Rule.\387\
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\384\ 40 CFR 80.1457.
\385\ ``EPA Decision on Canadian Aggregate Compliance Approach
Petition'' (Docket Item No. EPA-HQ-OAR-2011-0199-0015).
\386\ The data used to make this calculation can be found in
``Changes to the Renewable Fuel Standard Program Aggregate
Compliance for Canadian Crops and Crop Residues- Data Analysis and
Justification for 2025,'' available in the docket for this action.
\387\ 75 FR 14701 (March 26, 2010).
---------------------------------------------------------------------------
XI. Statutory and Executive Order Reviews
Additional information about these statutes and Executive orders
can be found at https://www.epa.gov/laws-regulations/laws-and-executive-orders.
A. Executive Order 12866: Regulatory Planning and Review
This action is a significant regulatory action as defined under
section 3(f)(1) of Executive Order 12866. Accordingly, it was submitted
to the Office of Management and Budget (OMB) for review. Any changes
made in response to OMB recommendations have been documented in the
docket. We prepared an analysis of the potential costs and benefits
associated with this action. This analysis is presented in RIA Chapter
10.6, available in the docket for this action.
B. Executive Order 14192: Unleashing Prosperity Through Deregulation
This action is considered an Executive Order 14192 regulatory
action. For regulatory accounting purposes, the estimated present value
and annualized value of the costs of this rule are $31.1 billion and
$2.18 billion, respectively (7% discount rate, 2024$, 2026 present
value year, perpetuity time horizon). Details on the estimated costs of
this final rule can be found in EPA's analysis of the potential costs
and benefits associated with this action.
C. Paperwork Reduction Act (PRA)
The information collection activities in this rule have been
submitted for approval to the Office of Management and Budget (OMB)
under the PRA. The Information Collection Request (ICR) document that
the EPA prepared has been assigned EPA ICR number 7804.02, OMB Control
Number 2060-0767. You can find a copy of the ICR in the docket for this
rule, and it is briefly summarized here. The information collection
requirements are not enforceable until OMB approves them.
The volume standards and associated percentage standards for 2026
and 2027 do not add to the burdens already estimated under existing,
approved ICRs for the RFS program. This final rule creates reporting
for RIN generators to identify a generation protocol code. We
anticipate the increase in burden related to this code to be very small
because the parties already provide reports for the RFS program,
generally. General recordkeeping and reporting for the RFS
[[Page 16470]]
program is contained in the Renewable Fuel Standard program ICR, OMB
Control Number 2060-0725 (extended pending OMB decision).
Respondents/affected entities: Renewable fuel producers, obligated
parties, RIN owners, third party auditors (attest engagements), QAP
auditors.
Respondent's obligation to respond: Mandatory, under 40 CFR part
80.
Estimated number of respondents: 3,689.
Frequency of response: Quarterly, annual, on occasion/as needed.
Total estimated burden: 11,483 hours (per year). Burden is defined
at 5 CFR 1320.3(b).
Total estimated cost: $24,512 (per year), includes $0 annualized
capital or operation & maintenance costs.
An agency may not conduct or sponsor, and a person is not required
to respond to, a collection of information unless it displays a
currently valid OMB control number. The OMB control numbers for the
EPA's regulations in 40 CFR are listed in 40 CFR part 9. When OMB
approves this ICR, the Agency will announce that approval in the
Federal Register and publish a technical amendment to 40 CFR part 9 to
display the OMB control number for the approved information collection
activities contained in this final rule.
D. Regulatory Flexibility Act (RFA)
I certify that this action will not have a significant economic
impact on a substantial number of small entities under the RFA.
With respect to the amendments to the RFS regulations, this action
makes minor corrections and modifications to those regulations. As
such, we do not anticipate that there will be any significant adverse
economic impact on directly regulated small entities as a result of
these revisions.
The small entities directly regulated by the annual percentage
standards associated with the RFS volumes are small refiners that
produce gasoline or diesel fuel, which are defined at 13 CFR 121.201.
We believe that there are currently 6 refiners (owning 7 refineries)
producing gasoline and/or diesel that meet the definition of small
entity by having 1,500 employees or fewer. To evaluate the impacts of
the 2026 and 2027 volume requirements on small entities, we have
conducted a screening analysis to assess whether we should make a
finding that this action will not have a significant economic impact on
a substantial number of small entities.\388\
---------------------------------------------------------------------------
\388\ RIA Chapter 11.
---------------------------------------------------------------------------
This action does not change the compliance flexibilities currently
offered to small entities under the RFS program and currently available
information shows that the impact on small entities from implementation
of this rule will not be significant. We have reviewed and assessed the
available information, which shows that obligated parties, in general
on a nationwide scale, are able to recover the cost of acquiring the
RINs necessary for compliance with the RFS standards through higher
sales prices of the petroleum products they sell than would be expected
in the absence of the RFS program.\389\ This is true whether they
acquire RINs by purchasing renewable fuels with attached RINs or
purchasing separated RINs. The costs of the RFS program are thus being
passed on to consumers in a highly competitive marketplace. Even if we
were to assume that the cost of acquiring RINs was not recovered by
obligated parties, a cost-to-sales ratio test shows that the costs to
small entities of the RFS standards established in this action are less
than 1 percent of the value of their sales.\390\
---------------------------------------------------------------------------
\389\ For a further discussion of the ability of obligated
parties to recover the cost of RINs, see, e.g., EPA, ``Denial of
Petitions for Rulemaking to Change the RFS Point of Obligation,''
EPA-420-R-17-008, November 2017. See also Gerveni, Maria, Todd
Hubbs, Scott H. Irwin, and James H. Stock. ``The Biofuels Blueprint:
Understanding the U.S. Renewable Fuel Standard,'' January 12, 2026.
See also CBD at 188, finding that the EPA properly considered RIN
cost passthrough in setting the volume requirements in the Set 1
Rule, and acknowledging the ``central premise'' that ``refineries
are able to pass RIN costs along to consumers'' as generally true.
\390\ A cost-to-sales ratio of 1 percent represents a typical
agency threshold for determining the significance of the economic
impact on small entities. ``Final Guidance for EPA Rulewriters:
Regulatory Flexibility Act as amended by the Small Business
Regulatory Enforcement Fairness Act,'' November 2006.
---------------------------------------------------------------------------
While the screening analysis described above supports a
certification that this rule will not have a significant economic
impact on small refiners, we continue to believe that it is more
appropriate to consider the 2026 and 2027 standards as a part of our
ongoing implementation of the overall RFS program. When considered this
way, the impacts of the RFS program as a whole on small entities were
addressed in the RFS2 Rule, which was the rule that implemented the
entire program as required by EISA 2007.\391\ As such, the Small
Business Regulatory Enforcement Fairness Act (SBREFA) panel process
that took place prior to the 2010 rule was also for the entire RFS
program and looked at impacts on small refiners through the full
implementation of the statutory volume targets.
---------------------------------------------------------------------------
\391\ 75 FR 14670 (March 26, 2010).
---------------------------------------------------------------------------
For the SBREFA process for the RFS2 Rule, we analyzed the potential
impacts of the RFS regulations on small entities. As a part of this
analysis, we convened a Small Business Advocacy Review Panel (SBAR
Panel, or ``the Panel''). During the Panel process, we gathered
information and recommendations from Small Entity Representatives
(SERs) on how to reduce the impact of the rule on small entities, and
those comments are detailed in the Final Panel Report.\392\ We also
conducted an analysis of the potential impacts of the RFS program on
all refiners, including small refiners, and found that the program
would not have a significant economic impact on a substantial number of
small entities.\393\ For small refiners subject to the RFS program, the
analysis included a cost-to-sales ratio test, a ratio of the estimated
annualized compliance costs to the value of sales per company. From
this test, we estimated that all directly regulated small entities
would have compliance costs that are less than one percent of their
sales over the full implementation of the statutory volume
targets.\394\ Furthermore, the EPA conducted a section 610 review of
the RFS program in May 2020, in which the Agency was required to
determine whether the RFS program should continue without change or
should be rescinded or amended, consistent with the stated objectives
of the CAA, to minimize any significant economic impact of the rule
upon a substantial number of small entities.\395\ Following a review of
relevant evidence, the EPA did not identify any such potential changes
that would reduce burden on a substantial number of small entities in a
manner consistent with the stated objectives of the CAA or EISA and
concluded that no changes to the RFS program were warranted.\396\
---------------------------------------------------------------------------
\392\ EPA, ``Final Report of the Small Business Advocacy Review
Panel on EPA's Planned Proposed Rule Regulation of Fuels and Fuel
Additives: Renewable Fuel Standard Program,'' September 8, 2008,
Docket Item No. EPA-HQ-OAR-2005-0161-0457.
\393\ 75 FR 14858-62 (March 26, 2010).
\394\ 75 FR 14862 (March 26, 2010).
\395\ EPA, ``Results of EPA's Section 610 Review of the Final
Rule for Regulation of Fuels and Fuel Additives: Changes to
Renewable Fuel Standard Program,'' May 2020, Docket Item No. EPA-HQ-
OAR-2019-0168-0022.
\396\ Id.
---------------------------------------------------------------------------
We have determined that this final rule will not impose any
additional requirements on small entities beyond those already
analyzed, since the impacts of this rule are not greater or
fundamentally different than those already considered in the analysis
for
[[Page 16471]]
the RFS2 final rule assuming full implementation of the statutory
volume targets. While in this action we are establishing volumes
through our Set authority rather than reducing the statutory volumes
through our waiver authorities (as was the case through 2022), the
magnitude of the cellulosic biofuel, advanced biofuel, and total
renewable fuel volume requirements established in this action
nonetheless remain significantly below the statutory volume targets
analyzed in the RFS2 Rule.\397\ Compared to the burden that would be
imposed under the volumes that we assessed in the analysis for the RFS2
Rule (i.e., the volumes specified in the CAA), the volume requirements
in this rule reduce burden on small entities. Regarding the BBD
standard, it is a nested standard within the advanced biofuel category,
and as discussed in section III of this preamble, the BBD volume
requirements for 2026 and 2027 are below the volume of BBD that is
anticipated to be produced and used to satisfy the advanced biofuel and
total renewable fuel requirements. In other words, the volume of BBD
actually used in 2026 and 2027 will be driven not by the 2026 and 2027
BBD standards, but rather by the 2026 and 2027 advanced biofuel and
total renewable fuel standards. The net result of the standards being
promulgated in this action is a reduction in burden as compared to
implementation of the statutory volume targets assumed in the RFS2 Rule
analysis.
---------------------------------------------------------------------------
\397\ The statutory volume targets analyzed in the RFS2 Rule
were 16 billion gallons of cellulosic biofuel, 21 billion gallons of
advanced biofuel, and 36 billion gallons of total renewable fuel.
---------------------------------------------------------------------------
Furthermore, to the degree that small entities may be impacted by
this action, these impacts are mitigated by the existing compliance
flexibilities in the RFS program that are available to small entities,
which we are not changing in this rule. These flexibilities include
being able to comply through RIN trading rather than renewable fuel
blending, 20 percent RIN rollover allowance (up to 20 percent of an
obligated party's RVO can be met using previous-year RINs), and deficit
carry-forward (the ability to carry over a deficit from a given year
into the following year, provided that the deficit is satisfied
together with the next year's RVO). Additionally, as required by CAA
section 211(o)(9)(B), the RFS regulations include a hardship relief
provision that allows for a small refinery to petition for an extension
of its small refinery exemption at any time based on a showing that the
refinery is experiencing a ``disproportionate economic hardship.''
\398\ The RFS regulations provide the same relief to small refiners
that are not eligible for small refinery relief.\399\ In the RFS2 Rule,
we discussed other potential small entity flexibilities that had been
suggested by the SBAR Panel or through comments, but we did not adopt
them, in part because we had serious concerns regarding our legal
authority to do so.\400\
---------------------------------------------------------------------------
\398\ 40 CFR 80.1441(e)(2).
\399\ 40 CFR 80.1442(h).
\400\ 75 FR 14858-62 (March 26, 2010).
---------------------------------------------------------------------------
In sum, this rule will not change the compliance flexibilities
currently offered to small entities under the RFS program and available
information shows that the impact on small entities from implementation
of this rule will not be significant. We have therefore concluded that
this action will not have any significant adverse economic impact on
directly regulated small entities.
E. Unfunded Mandates Reform Act (UMRA)
This action does not contain an unfunded mandate of $100 million
(adjusted annually for inflation) or more (in 1995 dollars) as
described in UMRA, 2 U.S.C. 1531-1538, for State, local, or Tribal
governments, and does not significantly or uniquely affect small
governments. This action imposes no enforceable duty on any State,
local, or Tribal governments. This action contains a Federal mandate
under UMRA that may result in expenditures of $100 million (adjusted
annually for inflation) or more (in 1995 dollars) for the private
sector in any one year. Accordingly, the costs associated with this
rule are discussed in section III of this preamble and RIA Chapter 10.
This action is not subject to the requirements of section 203 of
UMRA because it contains no regulatory requirements that might
significantly or uniquely affect small governments.
F. Executive Order 13132: Federalism
This action does not have federalism implications. It will not have
substantial direct effects on the States, on the relationship between
the National Government and the States, or on the distribution of power
and responsibilities among the various levels of government.
G. Executive Order 13175: Consultation and Coordination With Indian
Tribal Governments
This action does not have Tribal implications as specified in
Executive Order 13175. This action will be implemented at the Federal
level and affects transportation fuel refiners, blenders, marketers,
distributors, importers, exporters, and renewable fuel producers and
importers. Tribal governments will be affected only to the extent they
produce, purchase, or use regulated fuels. Thus, Executive Order 13175
does not apply to this action.
H. Executive Order 13045: Protection of Children From Environmental
Health Risks and Safety Risks
Executive Order 13045 directs Federal agencies to include an
evaluation of the health and safety effects of the planned regulation
on children in Federal health and safety standards and explain why the
regulation is preferable to potentially effective and reasonably
feasible alternatives. This action is subject to Executive Order 13045
because it is an economically significant regulatory action under
Executive Order 12866, and we believe that the environmental health or
safety risks of the pollutants impacted by this action may have a
disproportionate effect on children. The 2021 Policy on Children's
Health also applies to this action.\401\ An assessment of the
environmental impacts from this rule is included in RIA Chapter 4.
---------------------------------------------------------------------------
\401\ EPA, ``2021 Policy on Children's Health,'' October 5,
2021. https://www.epa.gov/system/files/documents/2021-10/2021-policy-on-childrens-health.pdf.
---------------------------------------------------------------------------
I. Executive Order 13211: Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution, or Use
This action is not a ``significant energy action'' because it is
not likely to have a significant adverse effect on the supply,
distribution, or use of energy. This action establishes the required
renewable fuel content of the transportation fuel supply for 2026 and
2027 pursuant to the CAA. The RFS program and this rule are designed to
achieve positive effects on the nation's transportation fuel supply by
increasing energy independence and security. These positive impacts are
described in section III of this preamble and RIA Chapter 6.
J. National Technology Transfer and Advancement Act (NTTAA) and 1 CFR
Part 51
This action involves technical standards. Except for the standards
discussed in this section, the standards included in the regulatory
text as incorporated by reference were all previously approved for
incorporation by reference (IBR) and no change is included in this
action.
[[Page 16472]]
In accordance with the requirements of 1 CFR 51.5, we are
incorporating by reference the use of certain standards and test
methods from the American Gas Association (AGA), American Petroleum
Institute (API), American Society of Mechanical Engineers (ASME), ASTM
International (ASTM), International Organization for Standardization
(ISO), and the EPA. The standards and test methods may be obtained
through the AGA website (www.aga.org) or by calling AGA at (202) 824-
7000; the ANSI website (www.ansi.org) or by calling ANSI at (202) 293-
8020; the API website (www.api.org) or by calling API at (202) 682-
8000; the ASME website (www.asme.org) or by calling ASME at (800) 843-
2763; the ASTM website (www.astm.org) or by calling ASTM at (877) 909-
2786; the ISO website (www.iso.org) or by calling ISO at +41-22-749-01-
11; and the EPA website (www.epa.gov) or by calling the EPA at (202)
272-0167. We are incorporating by reference the following standards:
BILLING CODE 6560-50-P
[[Page 16473]]
[GRAPHIC] [TIFF OMITTED] TR01AP26.077
[[Page 16474]]
[GRAPHIC] [TIFF OMITTED] TR01AP26.078
[[Page 16475]]
[GRAPHIC] [TIFF OMITTED] TR01AP26.079
[[Page 16476]]
[GRAPHIC] [TIFF OMITTED] TR01AP26.080
[[Page 16477]]
[GRAPHIC] [TIFF OMITTED] TR01AP26.081
[[Page 16478]]
[GRAPHIC] [TIFF OMITTED] TR01AP26.082
[[Page 16479]]
[GRAPHIC] [TIFF OMITTED] TR01AP26.083
[[Page 16480]]
[GRAPHIC] [TIFF OMITTED] TR01AP26.084
[[Page 16481]]
[GRAPHIC] [TIFF OMITTED] TR01AP26.085
BILLING CODE 6560-50-C
K. Congressional Review Act (CRA)
This action is subject to the CRA, and the EPA will submit a rule
report to each House of the Congress and to the Comptroller General of
the United States. This action meets the criteria set forth in 5 U.S.C.
804(2).
XII. Amendatory Instructions
Amendatory instructions are the standard terms that the Office of
the Federal Register (OFR) uses to give specific instructions to
agencies on how to change the CFR. OFR's historical guidance was to
include amendatory instructions accompanying each individual change
that was being made (e.g., each sentence or individual paragraph). The
piecemeal amendments served as an indication of changes we were making.
Due to the extensive number of technical and conforming amendments
included in this action, however, we are utilizing OFR's new amendatory
instruction ``revise and republish'' for revisions finalized in this
action.\402\ Therefore, instead of the past practice of piecemeal
amendments for revisions to the CFR, we are using the ``revise and
republish'' instruction to both revise regulatory text and republish in
their entirety certain sections of 40 CFR part 80 that contain the
regulatory text being revised. To indicate those portions of provisions
where changes are being revised, we have created a red-line version of
40 CFR part 80 that incorporates the changes. This red-line version is
available in the docket for this action. This red-line version provides
further context to assist the public in reviewing the regulatory text
changes. As previously noted, we did not reopen those unchanged
provisions for comment. Republishing provisions that are unchanged in
this action is consistent with guidance from OFR.
---------------------------------------------------------------------------
\402\ OFR's Document Drafting Handbook (Chapter 2, 2-38)
explains that agencies ``[u]se [r]epublish to set out unchanged text
for the convenience of the reader, often to provide context for your
regulatory changes.'' https://www.archives.gov/federal-register/write/handbook. Additional information on OFR's mandatory use of
``revise and republish'' is available at https://www.archives.gov/federal-register/write/ddh/revise-republish.
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XIII. Statutory Authority
Statutory authority for this action comes from sections 114, 203-
05, 208, 211, 301, and 307 of the Clean Air Act, 42 U.S.C. 7414, 7522-
24, 7542, 7545, 7601, and 7607.
List of Subjects
40 CFR Part 63
Administrative practice and procedure, Air pollution control.
40 CFR Part 80
Environmental protection, Administrative practice and procedure,
Air pollution control, Diesel fuel, Fuel additives, Gasoline, Imports,
Incorporation by reference, Oil imports, Petroleum, Renewable fuel.
40 CFR Part 1090
Environmental protection, Administrative practice and procedure,
Air pollution control, Diesel fuel, Fuel
[[Page 16482]]
additives, Gasoline, Imports, Incorporation by reference, Oil imports,
Petroleum, Renewable fuel.
Lee Zeldin,
Administrator.
For the reasons set forth in the preamble, EPA amends 40 CFR parts
63, 80, and 1090 as follows:
PART 63--NATIONAL EMISSION STANDARDS FOR HAZARDOUS AIR POLLUTANTS
FOR SOURCE CATEGORIES
0
1. The authority citation for part 63 continues to read as follows:
Authority: 42 U.S.C. 7401 et seq.
Subpart UUUUU--National Emission Standards for Hazardous Air
Pollutants: Coal- and Oil-Fired Electric Utility Steam Generating
Units
0
2. Amend Sec. 63.10042 by revising the definition for ``Clean fuel''
to read as follows:
Sec. 63.10042 What definitions apply to this subpart?
* * * * *
Clean fuel means natural gas, synthetic natural gas that meets the
specification necessary for that gas to be transported on a Federal
Energy Regulatory Commission (FERC) regulated pipeline, propane,
distillate oil, synthesis gas that has been processed through a gas
clean-up train such that it could be used in a system's combustion
turbine, or ultra-low-sulfur diesel (ULSD) fuel, including those fuels
meeting the requirements of part 1090, subpart D of this chapter.
* * * * *
PART 80--REGULATION OF FUELS AND FUEL ADDITIVES
0
3. The authority citation for part 80 continues to read as follows:
Authority: 42 U.S.C. 7414, 7521, 7542, 7545, and 7601(a).
Subpart A--General Provisions
0
4. Amend Sec. 80.2 by:
0
a. Adding, in alphabetical order, a definition for ``Activated
sludge'';
0
b. Removing the definition for ``A-RIN'';
0
c. Revising definitions for ``Assigned RIN'' and ``Biodiesel'';
0
d. In the definition for ``Biointermediate'', adding paragraphs (5)(x)
and (xi);
0
e. In the definition for ``Biomass-based diesel'', revising paragraph
(1)(ii);
0
f. Removing the definition for ``B-RIN'';
0
h. In the definition for ``Continuous measurement'', in paragraph (2),
removing the text ``flow meters'' and adding, in its place, the text
``flowmeters'';
0
i. Adding, in alphabetical order, a definition for ``Converted oils'';
0
j. In the definition for ``Co-processed cellulosic diesel'', revising
paragraph (1)(ii);
0
k. In the definition for ``Diesel fuel'', revising paragraph (1)(ii);
0
l. Revising definitions for ``Foreign renewable fuel producer'' and
``Importer'';
0
m. Removing the definition for ``Interim period'';
0
n. Revising the definition for ``MVNRLM diesel fuel'';
0
o. Removing the definition for ``Non-ester renewable diesel or
renewable diesel'';
0
p. In the definition for ``Permitted capacity'', removing the text
``renewable fuel facility'' and adding, in its place, the text
``renewable fuel production facility'';
0
q. Adding, in alphabetical order, a definition for ``Renewable
diesel'';
0
r. Removing the definition for ``Renewable electricity'';
0
s. Adding, in alphabetical order, definitions for ``Renewable fuel
oil'', ``Renewable fuel producer'', and ``Renewable jet fuel'';
0
t. Revising the definition for ``Renewable liquefied natural gas or
renewable LNG''; and
0
u. Adding, in alphabetical order, a definition for ``Renewable
naphtha''.
The revisions and additions read as follows:
Sec. 80.2 Definitions.
* * * * *
Activated sludge means the waste sludge from a secondary wastewater
treatment process involving oxygen and microorganisms.
* * * * *
Assigned RIN means a RIN assigned to a volume of renewable fuel or
RNG pursuant to Sec. 80.1426(e) or Sec. 80.125(c), respectively, with
a K code of 1 for renewable fuel or 3 for RNG.
* * * * *
Biodiesel means diesel fuel that is renewable fuel and that meets
ASTM D6751 (incorporated by reference, see Sec. 80.12).
* * * * *
Biointermediate * * *
(5) * * *
(x) Activated sludge.
(xi) Converted oils.
* * * * *
Biomass-based diesel * * *
(1) * * *
(ii) Meets the definition of either biodiesel or renewable diesel.
* * * * *
Converted oils means glycerides such as monoglycerides and
diglycerides that are produced through the glycerolysis of biogenic
waste oils/fats/greases with glycerol. Converted oils must exclusively
consist of glycerides with fatty acid alkyl groups that originate from
biogenic waste oils/fats/greases during the conversion process.
* * * * *
Co-processed cellulosic diesel * * *
(1) * * *
(ii) Meets the definition of either biodiesel or renewable diesel.
* * * * *
Diesel fuel * * *
(1) * * *
(ii) A non-distillate fuel other than residual fuel with comparable
physical and chemical properties (e.g., biodiesel, renewable diesel).
* * * * *
Foreign renewable fuel producer means any person that owns, leases,
operates, controls, or supervises a facility outside the covered
location where renewable fuel is produced.
* * * * *
Importer means any person who imports transportation fuel or
renewable fuel into the covered location from an area outside of the
covered location. This includes the importer of record or an authorized
agent acting on their behalf, as well as the actual owner, the
consignee, or the transferee, if the right to withdraw merchandise from
a bonded warehouse has been transferred.
* * * * *
MVNRLM diesel fuel means any diesel fuel or other distillate fuel
that is used, intended for use, or made available for use in motor
vehicles or motor vehicle engines, or as a fuel in any nonroad diesel
engines, including locomotive and marine diesel engines, except the
following: Distillate fuel with a T90, as determined using ASTM D86
(incorporated by reference, see Sec. 80.12), at or above 700 [deg]F
that is used only in Category 2 and 3 marine engines is not MVNRLM
diesel fuel, and ECA marine fuel is not MVNRLM diesel fuel (note that
fuel that conforms to the requirements of MVNRLM diesel fuel is
excluded from the definition of ``ECA marine fuel'' in this section
without regard to its actual use).
(1) Any diesel fuel that is sold for use in stationary engines that
are required to meet the requirements of 40 CFR 1090.300, when such
provisions are applicable to nonroad engines, is considered MVNRLM
diesel fuel.
[[Page 16483]]
(2) [Reserved]
* * * * *
Renewable diesel means diesel fuel that is renewable fuel and that
is one or more of the following:
(1) A fuel or fuel additive that meets the Grade No. 1-D or No. 2-D
specification in ASTM D975 (incorporated by reference, see Sec.
80.12).
(2) A fuel or fuel additive that is registered under 40 CFR part
79.
* * * * *
Renewable fuel oil means heating oil that is renewable fuel and
that meets paragraph (2) of the definition for heating oil.
Renewable fuel producer means any person that owns, leases,
operates, controls, or supervises a facility where renewable fuels are
produced.
* * * * *
Renewable jet fuel means jet fuel that is renewable fuel and that
meets ASTM D1655 or ASTM D7566 (both incorporated by reference, see
Sec. 80.12).
Renewable liquefied natural gas or renewable LNG means biogas,
treated biogas, or RNG that is liquefied (i.e., it is cooled below its
boiling point) for use as transportation fuel and meets the definition
of renewable fuel.
Renewable naphtha means naphtha that is renewable fuel.
* * * * *
0
5. Amend Sec. 80.3 by revising entry LNG to read as follows:
Sec. 80.3 Acronyms and abbreviations.
------------------------------------------------------------------------
------------------------------------------------------------------------
* * * * *
LNG....................................... Liquefied natural gas.
* * * * *
------------------------------------------------------------------------
0
6. Revise and republish Sec. 80.12 to read as follows:
Sec. 80.12 Incorporation by reference.
Certain material is incorporated by reference into this part with
the approval of the Director of the Federal Register under 5 U.S.C.
552(a) and 1 CFR part 51. All approved incorporation by reference (IBR)
material is available for inspection at the U.S. EPA and at the
National Archives and Records Administration (NARA). Contact the U.S.
EPA at: U.S. EPA, Air and Radiation Docket and Information Center, WJC
West Building, Room 3334, 1301 Constitution Ave. NW, Washington, DC
20460; (202) 566-1742; [email protected]. For information on the
availability of this material at NARA, visit www.archives.gov/federal-register/cfr/ibr-locations or email [email protected]. The
material may be obtained from the following sources:
(a) American Gas Association (AGA), 400 North Capitol Street NW,
Suite 450, Washington, DC 20001; (202) 824-7000; www.aga.org.
(1) AGA Report No. 3 Part 1, Orifice Metering of Natural Gas and
Other Related Hydrocarbon Fluids--Concentric, Square-edged Orifice
Meters Part 1: General Equations and Uncertainty Guidelines, 4th
Edition, including Errata July 2013, Reaffirmed, July 2022; IBR
approved for Sec. 80.155(a).
(2) AGA Report No. 3 Part 2, Orifice Metering of Natural Gas and
Other Related Hydrocarbon Fluids--Concentric, Square-edged Orifice
Meters Part 2: Specification and Installation Requirements, 5th
Edition, March 2016; IBR approved for Sec. 80.155(a).
(3) AGA Report No. 3 Part 3, Orifice Metering of Natural Gas and
Other Related Hydrocarbon Fluids--Concentric, Square-edged Orifice
Meters Part 3: Natural Gas Applications, 4th Edition, Reaffirmed,
June 2021; IBR approved for Sec. 80.155(a).
(4) AGA Report No. 3 Part 4, Orifice Metering of Natural Gas and
Other Related Hydrocarbon Fluids--Concentric, Square-edged Orifice
Meters Part 4--Background, Development, Implementation Procedure,
and Example Calculations, 4th Edition, October 2019; IBR approved
for Sec. 80.155(a).
(5) AGA Report No. 7, Measurement of Natural Gas by Turbine Meters,
Revised February 2006; IBR approved for Sec. 80.155(a).
(6) AGA Report No. 9, Measurement of Gas by Multipath Ultrasonic
Meters, 2nd Edition, April 2007; IBR approved for Sec. 80.155(a).
(7) AGA Report No. 11, Measurement of Natural Gas by Coriolis Meter,
2nd Edition, February 2013; IBR approved for Sec. 80.155(a).
(8) ANSI B109.3-2019 (R2024), Rotary-Type Gas Displacement Meters,
Fifth Edition, ANSI-approved, February 5, 2019 (Reaffirmed April 16,
2024) (ANSI B109.3); IBR approved for Sec. 80.155(a).
Note 1 to paragraph (a)(8): ANSI B109.3 is also available from the
American National Standards Institute (www.ansi.org).
(b) American Petroleum Institute (API), 200 Massachusetts Avenue NW,
Suite 1100, Washington, DC 20001-5571; (202) 682-8000; www.api.org.
(1) API MPMS 14.1-2016, Manual of Petroleum Measurement Standards
Chapter 14--Natural Gas Fluids Measurement Section 1--Collecting and
Handling of Natural Gas Samples for Custody Transfer, 7th Edition,
May 2016 (API MPMS 14.1); IBR approved for Sec. 80.155(b).
(2) API MPMS 14.3.1-2012, Manual of Petroleum Measurement Standards
Chapter 14.3.1--Orifice Metering of Natural Gas and Other Related
Hydrocarbon Fluids--Concentric, Square-edged Orifice Meters Part 1:
General Equations and Uncertainty Guidelines, 4th Edition, including
Errata July 2013, Reaffirmed, July 2022 (API MPMS 14.3.1); IBR
approved for Sec. 80.155(a).
(3) API MPMS 14.3.2-2016, Manual of Petroleum Measurement Standards
Chapter 14.3.2--Orifice Metering of Natural Gas and Other Related
Hydrocarbon Fluids--Concentric, Square-edged Orifice Meters Part 2:
Specification and Installation Requirements, 5th Edition, March 2016
(API MPMS 14.3.2); IBR approved for Sec. 80.155(a).
(4) API MPMS 14.3.3-2013, Manual of Petroleum Measurement Standards
Chapter 14.3.3--Orifice Metering of Natural Gas and Other Related
Hydrocarbon Fluids--Concentric, Square-edged Orifice Meters Part 3:
Natural Gas Applications, 4th Edition, Reaffirmed, June 2021 (API
MPMS 14.3.3); IBR approved for Sec. 80.155(a).
(5) API MPMS 14.3.4-2019, Manual of Petroleum Measurement Standards
Chapter 14.3.4--Orifice Metering of Natural Gas and Other Related
Hydrocarbon Fluids--Concentric, Square-edged Orifice Meters Part 4--
Background, Development, Implementation Procedure, and Example
Calculations, 4th Edition, October 2019 (API MPMS 14.3.4); IBR
approved for Sec. 80.155(a).
(6) API MPMS 14.9-2013, Measurement of Natural Gas by Coriolis
Meter, 2nd Edition, February 2013 (API MPMS 14.9); IBR approved for
Sec. 80.155(a).
(7) API MPMS 14.12-2017, Manual of Petroleum Measurement Standards
Chapter 14--Natural Gas Fluid Measurement Section 12--Measurement of
Gas by Vortex Meters, 1st Edition, March 2017 (API MPMS 14.12); IBR
approved for Sec. 80.155(a).
Note 2 to paragraph (b): API MPMS 14.3.1, 14.3.2, 14.3.3, and
14.3.4, are co-published as AGA Report 3, Parts 1, 2, 3, and 4,
respectively. API MPMS 14.9 is co-published as AGA Report No. 11.
(c) American Public Health Association (APHA), 1015 15th Street NW,
Washington, DC 20005; (202) 777-2742; www.standardmethods.org.
(1) SM 2540, Solids, revised June 10, 2020; IBR approved for Sec.
80.155(c).
(2) [Reserved]
(d) American Society of Mechanical Engineers (ASME), Two Park
Avenue, New York, NY 10016-5990; (800) 843-2763; www.asme.org.
(1) ASME MFC-3M-2004 (R2017), Measurement of Fluid Flow in Pipes
Using Orifice, Nozzle, and Venturi, including ASME MFC-3M--2004
Addenda, Reaffirmed 2017 (ASME MFC-3M); IBR approved for Sec.
80.155(a).
(2) ASME MFC-5.1-2011 (R2024), Measurement of Liquid Flow in Closed
Conduits Using Transit-Time Ultrasonic Flowmeters, Reaffirmed 2024
(ASME MFC-5.1); IBR approved for Sec. 80.155(a).
(3) ASME MFC-11-2006 (R2014), Measurement of Fluid Flow by Means of
Coriolis Mass Flowmeters, Reaffirmed 2014 (ASME MFC-11); IBR
approved for Sec. 80.155(a).
[[Page 16484]]
(4) ASME MFC-12M-2006 (R2014), Measurement of Fluid Flow in Closed
Conduits Using Multiport Averaging Pitot Primary Elements,
Reaffirmed 2014 (ASME MFC-12M); IBR approved for Sec. 80.155(a).
(5) ASME MFC-21.2-2010 (R2018), Measurement of Fluid Flow by Means
of Thermal Dispersion Mass Flowmeters, Reaffirmed 2018 (ASME MFC-
21.2); IBR approved for Sec. 80.155(a).
(e) ASTM International (ASTM), 100 Barr Harbor Dr., P.O. Box C700,
West Conshohocken, PA 19428-2959; (877) 909-2786; www.astm.org.
(1) ASTM D86-23ae2, Standard Test Method for Distillation of
Petroleum Products and Liquid Fuels at Atmospheric Pressure,
approved December 1, 2023 (ASTM D86); IBR approved for Sec. 80.2.
(2) ASTM D975-24a, Standard Specification for Diesel Fuel, approved
August 1, 2024 (ASTM D975); IBR approved for Sec. 80.2.
(3) ASTM D1142-95 (Reapproved 2021), Standard Test Method for Water
Vapor Content of Gaseous Fuels by Measurement of Dew-Point
Temperature, approved July 1, 2021 (ASTM D1142); IBR approved for
Sec. 80.155(b).
(4) ASTM D1250-19e1, Standard Guide for the Use of the Joint API and
ASTM Adjunct for Temperature and Pressure Volume Correction Factors
for Generalized Crude Oils, Refined Products, and Lubricating Oils:
API MPMS Chapter 11.1, approved May 1, 2019 (ASTM D1250); IBR
approved for Sec. 80.1426(f).
(5) ASTM D1655-25, Standard Specification for Aviation Turbine
Fuels, approved October 1, 2025 (ASTM D1655); IBR approved for Sec.
80.2.
(6) ASTM D1945-25, Standard Test Method for Analysis of Natural Gas
by Gas Chromatography, approved August 1, 2025 (ASTM D1945); IBR
approved for Sec. 80.155(b).
(7) ASTM D1946-24, Standard Practice for Analysis of Gaseous Fuels
by Gas Chromatography, approved December 1, 2024 (ASTM D1946); IBR
approved for Sec. 80.155(b).
(8) ASTM D3588-98 (Reapproved 2024)e1, Standard Practice for
Calculating Heat Value, Compressibility Factor, and Relative Density
of Gaseous Fuels, approved May 1, 2024 (ASTM D3588); IBR approved
for Sec. 80.155(b) and (f).
(9) ASTM D4057-22, Standard Practice for Manual Sampling of
Petroleum and Petroleum Products, approved May 1, 2022 (ASTM D4057);
IBR approved for Sec. 80.8(a).
(10) ASTM D4177-22e1, Standard Practice for Automatic Sampling of
Petroleum and Petroleum Products, approved July 1, 2022 (ASTM
D4177); IBR approved for Sec. 80.8(b).
(11) ASTM D4442-20 (Reapproved 2025), Standard Test Methods for
Direct Moisture Content Measurement of Wood and Wood-Based
Materials, approved August 1, 2025 (ASTM D4442); IBR approved for
Sec. 80.1426(f).
(12) ASTM D4444-25, Standard Test Method for Laboratory
Standardization and Calibration of Hand-Held Moisture Meters,
approved August 1, 2025 (ASTM D4444); IBR approved for Sec.
80.1426(f).
(13) ASTM D4888-20, Standard Test Method for Water Vapor in Natural
Gas Using Length-of-Stain Detector Tubes, approved December 15, 2020
(ASTM D4888); IBR approved for Sec. 80.155(b).
(14) ASTM D5454-11 (Reapproved 2020), Standard Test Method for Water
Vapor Content of Gaseous Fuels Using Electronic Moisture Analyzers,
approved January 1, 2020 (ASTM D5454); IBR approved for Sec.
80.155(b).
(15) ASTM D5504-20, Standard Test Method for Determination of Sulfur
Compounds in Natural Gas and Gaseous Fuels by Gas Chromatography and
Chemiluminescence, approved November 1, 2020 (ASTM D5504); IBR
approved for Sec. 80.155(b).
(16) ASTM D5842-23, Standard Practice for Sampling and Handling of
Fuels for Volatility Measurement, approved October 1, 2023 (ASTM
D5842); IBR approved for Sec. 80.8(c).
(17) ASTM D5854-25, Standard Practice for Mixing and Handling of
Liquid Samples of Petroleum and Petroleum Products, approved July 1,
2025 (ASTM D5854); IBR approved for Sec. 80.8(d).
(18) ASTM D6228-19, Standard Test Method for Determination of Sulfur
Compounds in Natural Gas and Gaseous Fuels by Gas Chromatography and
Flame Photometric Detection, approved April 1, 2019 (ASTM D6228);
IBR approved for Sec. 80.155(b).
(19) ASTM D6751-24, Standard Specification for Biodiesel Fuel
Blendstock (B100) for Middle Distillate Fuels, approved March 1,
2024 (ASTM D6751); IBR approved for Sec. 80.2.
(20) ASTM D6866-24a, Standard Test Methods for Determining the
Biobased Content of Solid, Liquid, and Gaseous Samples Using
Radiocarbon Analysis, approved December 1, 2024 (ASTM D6866); IBR
approved for Sec. Sec. 80.155(b); 80.1426(f); 80.1430(e).
(21) ASTM D6968-03 (Reapproved 2015), Standard Test Method for
Simultaneous Measurement of Sulfur Compounds and Minor Hydrocarbons
in Natural Gas and Gaseous Fuels by Gas Chromatography and Atomic
Emission Detection, approved June 1, 2015 (ASTM D6968); IBR approved
for Sec. 80.155(b).
(22) ASTM D7164-21, Standard Practice for On-line/At-line Heating
Value Determination of Gaseous Fuels by Gas Chromatography, approved
April 1, 2021 (ASTM D7164); IBR approved for Sec. 80.155(a).
(23) ASTM D7566-25a, Standard Specification for Aviation Turbine
Fuel Containing Synthesized Hydrocarbons, approved November 15, 2025
(ASTM D7566); IBR approved for Sec. 80.2.
(24) ASTM D7833-20, Standard Test Method for Determination of
Hydrocarbons and Non-Hydrocarbon Gases in Gaseous Mixtures by Gas
Chromatography, approved June 1, 2020 (ASTM D7833); IBR approved for
Sec. 80.155(b).
(25) ASTM D7904-21, Standard Test Method for Determination of Water
Vapor (Moisture Concentration) in Natural Gas by Tunable Diode Laser
Spectroscopy (TDLAS), approved November 1, 2021 (ASTM D7904); IBR
approved for Sec. 80.155(b).
(26) ASTM D8230-19, Standard Test Method for Measurement of Volatile
Silicon-Containing Compounds in a Gaseous Fuel Sample Using Gas
Chromatography with Spectroscopic Detection, approved June 1, 2019
(ASTM D8230); IBR approved for Sec. 80.155(b).
(27) ASTM E711-23e1, Standard Test Method for Gross Calorific Value
of Refuse-Derived Fuel by the Bomb Calorimeter, approved April 1,
2023 (ASTM E711); IBR approved for Sec. 80.1426(f).
(28) ASTM E870-24, Standard Test Methods for Analysis of Wood Fuels,
approved October 1, 2024 (ASTM E870); IBR approved for Sec.
80.1426(f).
(f) European Committee for Standardization (CEN), Rue de la Science
23, B-1040 Brussels, Belgium; + 32 2 550 08 11; www.cencenelec.eu.
(1) EN 17526:2021(E), Gas meter--Thermal-mass flow-meter based gas
meter, approved July 11, 2021 (EN 17526); IBR approved for Sec.
80.155(a).
(2) [Reserved]
(g) International Organization for Standardization (ISO), Chemin de
Blandonnet 8, CP 401, 1214 Vernier, Geneva, Switzerland; +41 22 749
01 11; www.iso.org.
(1) ISO 5167-1:2022(E), Measurement of fluid flow by means of
pressure differential devices inserted in circular cross-section
conduits running full--Part 1: General principles and requirements,
Third edition, June 2022 (ISO 5167-1); IBR approved for Sec.
80.155(a).
(2) ISO 5167-2:2022(E), Measurement of fluid flow by means of
pressure differential devices inserted in circular cross-section
conduits running full--Part 2: Orifice plates, Second edition, June
2022 (ISO 5167-2); IBR approved for Sec. 80.155(a).
(3) ISO 5167-4:2022(E), Measurement of fluid flow by means of
pressure differential devices inserted in circular cross-section
conduits running full--Part 4: Venturi tubes, Second edition, June
2022 (ISO 5167-4); IBR approved for Sec. 80.155(a).
(4) ISO 5167-5:2022(E), Measurement of fluid flow by means of
pressure differential devices inserted in circular cross-section
conduits running full--Part 5: Cone meters, Second edition, October
2022 (ISO 5167-5); IBR approved for Sec. 80.155(a).
(5) ISO 10790:2015(E), Measurement of fluid flow in closed
conduits--Guidance to the selection, installation and use of
Coriolis flowmeters (mass flow, density and volume flow
measurements), Third edition, April 1, 2015 (ISO 10790); IBR
approved for Sec. 80.155(a).
(6) ISO 14511:2019(E), Measurement of fluid flow in closed
conduits--Thermal mass flowmeters, Second edition, January 2019 (ISO
14511); IBR approved for Sec. 80.155(a).
[[Page 16485]]
(7) ISO 17089-1:2019(E), Measurement of fluid flow in closed
conduits--Ultrasonic meters for gas--Part 1: Meters for custody
transfer and allocation measurement, Second edition, August 2019
(ISO 17089-1); IBR approved for Sec. 80.155(a).
(8) ISO 17089-2:2012(E), Measurement of fluid flow in closed
conduits--Ultrasonic meters for gas--Part 2: Meters for industrial
applications, First edition, October 1, 2012 (ISO 17089-2); IBR
approved for Sec. 80.155(a).
(h) U.S. Environmental Protection Agency (EPA), 1200 Pennsylvania
Avenue NW, Washington, DC 20460; (202) 272-0167; www.epa.gov.
(1) EPA Compendium Method TO-15, Determination Of Volatile Organic
Compounds (VOCs) In Air Collected In Specially-Prepared Canisters
And Analyzed By Gas Chromatography/Mass Spectrometry (GC/MS), (as
published in/625/R-96/010b, Compendium of Methods for the
Determination of Toxic Organic Compounds in Ambient Air, Second
Edition), January 1999 (EPA Method TO-15); IBR approved for Sec.
80.155(b).
(2) [Reserved]
Subpart E--Biogas-Derived Renewable Fuel
0
7. Amend Sec. 80.105 by revising paragraphs (j)(1) and (3) and adding
paragraph (j)(4) to read as follows:
Sec. 80.105 Biogas producers.
* * * * *
(j) * * *
(1) Except for biogas produced from a mixed digester, the batch
volume of biogas is the volume of biogas measured under paragraph (f)
of this section for a single batch pathway at a single facility for up
to a calendar month, in Btu HHV.
* * * * *
(3) The biogas producer must assign a number (the ``batch number'')
to each batch of biogas consisting of their EPA-issued company
registration number, the EPA-issued facility registration number, the
last two digits of the compliance year in which the batch was produced,
and a unique number for the batch during the compliance year (e.g.,
4321-54321-25-000001).
(4) The production date for a batch of biogas is the last day of
the time period that the batch represents. For example, the production
date for a batch of biogas for the month of January would be January
31, while the production date for a batch of biogas for February 1-14
would be February 14.
* * * * *
0
8. Amend Sec. 80.110 by revising paragraphs (f)(2)(iii) introductory
text and (j)(1) and (3) to read as follows:
Sec. 80.110 RNG producers, RNG importers, and biogas closed
distribution system RIN generators.
* * * * *
(f) * * *
(2) * * *
(iii) As part of three-year engineering review updates required
under Sec. 80.135(b)(3) submitted on or after January 1, 2027, an RNG
producer that injects RNG from an RNG production facility into a
natural gas commercial pipeline system must sample and test a
representative sample of all the following at least once every three
years, as applicable:
* * * * *
(j) * * *
(1) A batch of RNG is the total volume of RNG injected into a
natural gas commercial pipeline system from an RNG production facility
under a single batch pathway for the calendar month, in Btu LHV, as
determined under paragraph (j)(4) of this section.
* * * * *
(3) The RNG producer, RNG importer, or biogas closed distribution
system RIN generator must assign a number (the ``batch number'') to
each batch of RNG or biogas-derived renewable fuel consisting of their
EPA-issued company registration number, the EPA-issued facility
registration number, the last two digits of the compliance year in
which the batch was produced, and a unique number for the batch during
the compliance year (e.g., 4321-54321-25-000001).
* * * * *
0
9. Amend Sec. 80.115 by revising paragraph (b) to read as follows:
Sec. 80.115 RNG RIN separators.
* * * * *
(b) Registration. The RNG RIN separator must register with EPA
under Sec. Sec. 80.135 and 80.1450 and 40 CFR part 1090, subpart I, as
applicable.
* * * * *
0
10. Amend Sec. 80.125 by:
0
a. In paragraphs (b)(6) and (7), removing the text ``Sec.
80.1415(b)(5)'' and adding, in its place, the text ``Sec.
80.1415(b)'';
0
b. Revising paragraphs (c)(3) and (d)(4);
0
c. Adding paragraph (d)(5); and
0
d. Revising paragraphs (e)(1) and (2).
The revisions and addition read as follows:
Sec. 80.125 RINs for RNG.
* * * * *
(c) * * *
(3) For purposes of this part, each party that transfers title of
an assigned RIN for RNG is deemed to have transferred a corresponding
volume of RNG to the transferee.
(d) * * *
(4) A party must only separate a number of RINs equal to the total
volume of RNG (where the Btu LHV are converted to gallon-RINs using the
conversion specified in Sec. 80.1415(b)) that the party demonstrates
is used as renewable CNG/LNG under paragraph (d)(2) of this section.
(5) An assigned RIN for RNG must be separated by December 31 of the
subsequent calendar year after the RIN for RNG was generated. Any RINs
for RNG not separated by this date are expired.
(e) * * *
(1) A party must retire RINs for RNG if any of the conditions
specified in Sec. 80.1434(a) apply and must comply with Sec.
80.1434(b).
(2) A party must retire any expired RINs for RNG under paragraph
(d)(5) of this section by March 31 of the subsequent calendar year
after the RINs expired. For example, if an RNG producer assigns RINs
for RNG in 2025, the RINs expire if they are not separated under
paragraph (d) of this section by December 31, 2026, and must be retired
by March 31, 2027.
* * * * *
0
11. Amend Sec. 80.135 by:
0
a. Revising paragraph (b)(2)(ii);
0
b. Revising and republishing paragraph (c)(3);
0
d. Revising paragraph (c)(10)(vi)(A)(5);
0
e. Revising and republishing paragraph (d)(3);
0
f. Revising paragraphs (d)(5) and (d)(6)(i) and (ii);
0
g. Adding paragraph (d)(6)(vi); and
0
h. Revising paragraphs (d)(7)(ii) and (f).
The revisions, republications, and addition read as follows:
Sec. 80.135 Registration.
* * * * *
(b) * * *
(2) * * *
(ii) A biogas closed distribution system RIN generator or biogas
producer does not need to submit an updated engineering review for any
facility before the next three-year engineering review update is due as
specified in Sec. 80.1450(d)(3).
* * * * *
(c) * * *
(3) The following information related to biogas measurement:
(i) A description of how biogas will be measured, including the
specific standards under which the meters are operated.
(ii) A description of the biogas production process, including a
process
[[Page 16486]]
flow diagram that includes metering type(s) and location(s).
(iii) For an alternative measurement protocol under Sec.
80.155(a)(2), all the following:
(A) A description of how measurement is conducted.
(B) Any standards or specifications that apply.
(C) A description of all routine maintenance and the frequency that
such maintenance will be conducted.
(D) A description of the frequency of all measurements and how
often such measurements will be recorded under the alternative
measurement protocol.
(E) A comparison between the accuracy, precision, and reliability
of the alternative measurement protocol and the requirements specified
in Sec. 80.155(a)(1), including any supporting data.
* * * * *
(10) * * *
(vi) * * *
(A) * * *
(5) A demonstration that no biogas produced from non-cellulosic
biogas feedstocks could be used to generate RINs for a batch of
renewable fuel with a D code of 3 or 7. EPA may reject this
demonstration if it is not sufficiently protective.
* * * * *
(d) * * *
(3) The following information related to RNG measurement:
(i) A description of how RNG will be measured, including the
specific standards under which the meters are operated.
(ii) A description of the RNG production process, including a
process flow diagram that includes metering type(s) and location(s).
(iii) For an alternative measurement protocol under Sec.
80.155(a)(2), all the following:
(A) A description of how measurement is conducted.
(B) Any standards or specifications that apply.
(C) A description of all routine maintenance and the frequency that
such maintenance will be conducted.
(D) A description of the frequency of all measurements and how
often such measurements will be recorded under the alternative
measurement protocol.
(E) A comparison between the accuracy, precision, and reliability
of the alternative measurement protocol and the requirements specified
in Sec. 80.155(a)(1), as applicable, including any supporting data.
* * * * *
(5) A description of the natural gas specifications for the natural
gas commercial pipeline system into which the RNG will be injected,
including information on all parameters regulated by the pipeline
(e.g., hydrogen sulfide, total sulfur, carbon dioxide, oxygen,
nitrogen, heating content, moisture, siloxanes, etc.).
(6) * * *
(i) A certificate of analysis from an independent laboratory for a
representative sample of the biogas produced at the biogas production
facility as specified in Sec. 80.155(b).
(ii) A certificate of analysis from an independent laboratory for a
representative sample of the RNG prior to addition of non-renewable
components as specified in Sec. 80.155(b).
* * * * *
(vi) Except as specified in Sec. 80.155(b)(2)(vii), an RNG
producer does not need to test for a parameter specified in Sec.
80.155(b)(2) if the parameter is not included in the pipeline
specifications submitted at registration under paragraph (d)(5) of this
section.
(7) * * *
(ii) A diagram showing the locations of flowmeters, gas analyzers,
and in-line GC meters used in the allocation procedure.
* * * * *
(f) RNG RIN separator. In addition to the information required
under paragraph (b) of this section, an RNG RIN separator must submit
all the following information:
(1) A list of locations of any dispensing stations where the RNG
RIN separator supplies or intends to supply renewable CNG/LNG for use
as transportation fuel.
(2) A list of the names and locations of each point where RNG will
be withdrawn from the natural gas commercial pipeline system.
* * * * *
0
12. Amend Sec. 80.140 by revising paragraph (b)(2) and paragraph
(e)(2) introductory text to read as follows:
Sec. 80.140 Reporting.
* * * * *
(b) * * *
(2) Production date.
* * * * *
(e) * * *
(2) An RNG RIN separator must submit monthly reports to EPA
containing all the following information for each month's renewable
CNG/LNG dispensing activity:
* * * * *
0
13. Amend Sec. 80.155 by:
0
a. Revising and republishing paragraphs (a) and (b)(2);
0
b. Adding paragraph (b)(3); and
0
c. Revising paragraph (f)(2) introductory text.
The revisions, republications, and addition read as follows:
Sec. 80.155 Sampling, testing, and measurement.
(a) Continuous measurement--(1) Biogas, treated biogas, and RNG
measurement. Except as specified in paragraph (a)(3) of this section,
any party required to measure the volume of biogas, treated biogas, or
RNG under this subpart must continuously measure using meters as
specified in paragraphs (a)(1)(i) and (ii) of this section or have an
accepted alternative measurement protocol as specified in paragraph
(a)(2) of this section.
(i) In-line GC meters compliant with ASTM D7164 (incorporated by
reference, see Sec. 80.12), including sections 9.2, 9.3, 9.4, 9.5,
9.7, 9.8, and 9.11 of ASTM D7164.
(ii) Flowmeters compliant with one of the following:
Table 1 to Paragraph (a)(1)(ii)--Flowmeter Methods
------------------------------------------------------------------------
Flowmeter type Method \1\
------------------------------------------------------------------------
Cone.............................. ISO 5167-1 and ISO 5167-5.
Coriolis.......................... AGA Report No. 11; API MPMS 14.9;
ASME MFC-11; ISO 10790.
Orifice plate..................... AGA Report No. 3 Parts 1, 2, 3, and
4; API MPMS 14.3.1, API MPMS
14.3.2, API MPMS 14.3.3, and API
MPMS 14.3.4; ASME MFC-3M; ISO 5167-
1 and ISO 5167-2.
Pitot tube........................ ASME MFC-12M.
Rotary............................ ANSI B109.3.
Thermal dispersion................ ASME MFC[hyphen]21.2.
Thermal mass...................... EN 17526 compatible with gas type H;
ISO 14511.
Turbine........................... AGA Report No. 7.
Ultrasonic........................ AGA Report No. 9; ASME MFC-5.1; ISO
17089-1; ISO 17089-2.
[[Page 16487]]
Venturi........................... ISO 5167-1 and ISO 5167-4.
Vortex............................ API MPMS 14.12.
------------------------------------------------------------------------
\1\ Methods are incorporated by reference, see Sec. 80.12).
(2) Alternative measurement protocols. EPA may accept an
alternative measurement protocol if the party demonstrates that the
alternative measurement protocol is at least as accurate and precise as
the methods specified in paragraph (a)(1) of this section. An
alternative measurement protocol may include less frequent measurement
or recording than specified in the definition of continuous
measurement.
(3) RNG RIN separator measurement. An RNG RIN separator must
measure natural gas or renewable CNG/LNG using one of the following:
(i) A method specified in paragraph (a)(1) or (2) of this section.
(ii) Documentation (e.g., pipeline or utility statements, scale
tickets, or bills of lading) that establishes the volume of natural gas
or renewable CNG/LNG. Documentation must be specified in Btu LHV or
converted as specified in paragraph (f) of this section.
(b) * * *
(2) Perform all the following measurements on each representative
sample:
(i) Methane, carbon dioxide, nitrogen, and oxygen using EPA Method
3C (see appendix A-2 to 40 CFR part 60), ASTM D1945, ASTM D1946, or
ASTM D7833 (all incorporated by reference, see Sec. 80.12).
(ii) Hydrogen sulfide and total sulfur using ASTM D5504, ASTM
D6228, or ASTM D6968 (all incorporated by reference, see Sec. 80.12).
(iii) Siloxanes using ASTM D8230 (incorporated by reference, see
Sec. 80.12).
(iv) Moisture using ASTM D1142, ASTM D4888, ASTM D5454, or ASTM
D7904 (all incorporated by reference, see Sec. 80.12).
(v) Hydrocarbon analysis using EPA Method 18 (see appendix A-6 to
40 CFR part 60), ASTM D1945, ASTM D1946, ASTM D7833, or EPA Method TO-
15 (all incorporated by reference, see Sec. 80.12).
(vi) Heating value and relative density using ASTM D3588
(incorporated by reference, see Sec. 80.12).
(vii) If the RNG producer blends non-renewable components into RNG,
carbon-14 analysis using ASTM D6866 (incorporated by reference, see
Sec. 80.12).
(3) EPA may approve a party's request to use a method other than
those specified in paragraph (b)(2) of this section if the party
demonstrates one of the following:
(i) The alternative analysis provides information that is
reasonably accurate to that determined by the applicable method
specified in paragraph (b)(2) of this section.
(ii) The alternative analysis is required by pipeline
specifications or has been approved to be used by a State or Federal
government agency.
* * * * *
(f) * * *
(2) A party with documentation under paragraph (a)(3) of this
section that is not specified in Btu must convert to Btu LHV as
follows:
* * * * *
0
14. Amend Sec. 80.165 by revising paragraph (a)(1) to read as follows:
Sec. 80.165 Attest engagements.
(a) * * *
(1) The following parties must arrange for annual attestation
engagement using agreed-upon procedures:
(i) Biogas producers that supplied biogas to produce RNG or a
biogas-derived renewable fuel within the compliance year.
(ii) RNG producers that generated RINs within the compliance year.
(iii) RNG importers that generated RINs within the compliance year.
(iv) Biogas closed distribution system RIN generators that
generated RINs within the compliance year.
(v) RNG RIN separators that separated RINs from RNG within the
compliance year.
(vi) Renewable fuel producers that use RNG as a feedstock within
the compliance year.
* * * * *
Subpart M--Renewable Fuel Standard
0
15. Amend Sec. 80.1405 by:
0
a. In table 1 to paragraph (a), revising entry 2025 and adding entries
2026 and 2027 in numerical order; and
0
b. Revising paragraphs (b) through (d).
The revisions and additions read as follows:
Sec. 80.1405 What are the Renewable Fuel Standards?
(a) * * *
Table 1 to Paragraph (a)--Annual Renewable Fuel Standards
----------------------------------------------------------------------------------------------------------------
Supplemental
Cellulosic Biomass-based Advanced Renewable fuel total renewable
Year biofuel diesel biofuel standard (%) fuel standard
standard (%) standard (%) standard (%) (%)
----------------------------------------------------------------------------------------------------------------
* * * * * * *
2025.......................... 0.71 3.15 4.31 13.13 n/a
2026.......................... 0.79 5.24 6.42 15.50 n/a
2027.......................... 0.84 5.37 6.61 15.78 n/a
----------------------------------------------------------------------------------------------------------------
(b) Except as specified in paragraph (c) of this section, EPA will
calculate the annual renewable fuel percentage standards using the
following equations:
[[Page 16488]]
[GRAPHIC] [TIFF OMITTED] TR01AP26.086
Where:
StdCB,i = Cellulosic biofuel standard for year i, in
percent.
StdBBD,i = Biomass-based diesel standard for year i, in
percent.
StdAB,i = Advanced biofuel standard for year i, in
percent
StdRF,i = Renewable fuel standard for year i, in percent.
RFVCB,i = Annual volume of cellulosic biofuel required by
42 U.S.C. 7545(o)(2)(B) for year i, or volume as adjusted pursuant
to 42 U.S.C. 7545(o)(7)(D), in gallon-RINs.
RFVBBD,i = Annual volume of biomass-based diesel required
by 42 U.S.C. 7545(o)(2)(B) for year i, in gallon-RINs.
RFVAB,i = Annual volume of advanced biofuel required by
42 U.S.C. 7545(o)(2)(B) for year i, in gallon-RINs.
RFVRF,i = Annual volume of renewable fuel required by 42
U.S.C. 7545(o)(2)(B) for year i, in gallon-RINs.
Gi = Amount of gasoline projected to be used in the
covered location for year i, in gallons.
Di = Amount of diesel projected to be used in the covered
location for year i, in gallons.
RGi = Amount of renewable fuel projected to be contained
in the projection of Gi for year i, in gallons.
RDi = Amount of renewable fuel projected to be contained
in the projection of Di for year i, in gallons.
GEi = Amount of gasoline projected to be exempt for year
i, in gallons, per Sec. Sec. 80.1441 and 80.1442.
DEi = Amount of diesel fuel projected to be exempt for
year i, in gallons, per Sec. Sec. 80.1441 and 80.1442.
(c) For the 2026 and 2027 compliance years, EPA will calculate the
annual renewable fuel percentage standards using the following
equations:
[GRAPHIC] [TIFF OMITTED] TR01AP26.087
Where:
StdCB,i = Cellulosic biofuel standard for year i, in
percent.
StdBBD,i = Biomass-based diesel standard for year i, in
percent.
StdAB,i = Advanced biofuel standard for year i, in
percent
StdRF,i = Renewable fuel standard for year i, in percent.
RFVCB,i = Annual volume of cellulosic biofuel required by
42 U.S.C. 7545(o)(2)(B) for year i, or volume as adjusted pursuant
to 42 U.S.C. 7545(o)(7)(D), in gallon-RINs.
RFVBBD,i = Annual volume of biomass-based diesel required
by 42 U.S.C. 7545(o)(2)(B) for year i, in gallon-RINs.
RFVAB,i = Annual volume of advanced biofuel required by
42 U.S.C. 7545(o)(2)(B) for year i, in gallon-RINs.
RFVRF,i = Annual volume of renewable fuel required by 42
U.S.C. 7545(o)(2)(B) for year i, in gallon-RINs.
SRERVBBD,i = Small refinery exemption reallocation volume
for biomass-based diesel for year i, in gallon-RINs.
SRERVAB,i = Small refinery exemption reallocation volume
for advanced biofuel for year i, in gallon-RINs.
SRERVRF,i = Small refinery exemption reallocation volume
for renewable fuel for year i, in gallon-RINs.
Gi = Amount of gasoline projected to be used in the
covered location for year i, in gallons.
Di = Amount of diesel projected to be used in the covered
location for year i, in gallons.
RGi = Amount of renewable fuel projected to be contained
in the projection of Gi for year i, in gallons.
RDi = Amount of renewable fuel projected to be contained
in the projection of Di for year i, in gallons.
GEi = Amount of gasoline projected to be exempt for year
i, in gallons, per Sec. Sec. 80.1441 and 80.1442.
[[Page 16489]]
DEi = Amount of diesel fuel projected to be exempt for
year i, in gallons, per Sec. Sec. 80.1441 and 80.1442.
(d) The price for cellulosic biofuel waiver credits will be
calculated in accordance with Sec. 80.1456(d) and published on EPA's
website.
0
16. Amend Sec. 80.1407 by revising paragraph (f)(5) to read as
follows:
Sec. 80.1407 How are the Renewable Volume Obligations calculated?
* * * * *
(f) * * *
(5) Gasoline or diesel fuel exported for use outside the covered
location.
* * * * *
0
17. Effective January 1, 2027, amend Sec. 80.1415 by revising
paragraphs (a), (b), and (c)(1) to read as follows:
Sec. 80.1415 How are equivalence values assigned to renewable fuel?
(a) General. (1) Each gallon (or gallon-equivalent) of a renewable
fuel must be assigned an equivalence value by the producer or importer
pursuant to paragraph (b) or (c) of this section, as applicable.
(2) The equivalence value is a number that is used to determine how
many gallon-RINs can be generated for a gallon of renewable fuel
according to Sec. 80.1426.
(b) Assigned equivalence values. (1) Equivalence values for certain
renewable fuels are assigned as follows:
Table 1 to Paragraph (b)(1)--Equivalence Values for Certain Renewable
Fuels
------------------------------------------------------------------------
Equivalence
Fuel Amount value
------------------------------------------------------------------------
Biodiesel......................... 1 gallon............ 1.5
Butanol........................... 1 gallon............ 1.3
Denatured ethanol................. 1 gallon............ 1.0
Fuels that are gaseous at STP 77,000 Btu LHV...... 1.0
(e.g., RNG, renewable CNG/LNG).
Renewable diesel.................. 1 gallon............ 1.5
Renewable jet fuel................ 1 gallon............ 1.5
Renewable naphtha................. 1 gallon............ 1.4
------------------------------------------------------------------------
(2) For all other renewable fuels, a producer or importer must
submit an application to EPA for an equivalence value following the
provisions of paragraph (c) of this section. A producer or importer may
also submit an application for an alternative equivalence value
pursuant to paragraph (c) of this section if the renewable fuel is
listed in this paragraph (b), but the producer or importer has reason
to believe that a different equivalence value than that listed in this
paragraph (b) is warranted.
(c) * * *
(1) The equivalence value for renewable fuels described in
paragraph (b)(2) of this section must be calculated using the following
formula:
EqV = (R/0.972) * (EC/77,000)
Where:
EqV = Equivalence Value for the renewable fuel, rounded to the
nearest tenth.
R = Renewable content of the renewable fuel. This is a measure of
the portion of a renewable fuel that came from renewable biomass,
expressed as a fraction, on an energy basis.
EC = Energy content of the renewable fuel, in Btu LHV per gallon.
* * * * *
0
18. Amend Sec. 80.1425 by adding paragraph (a)(3) to read as follows:
Sec. 80.1425 Renewable Identification Numbers (RINs).
* * * * *
(a) * * *
(3) K has the value of 3 when the RIN is assigned to a volume of
RNG pursuant to Sec. Sec. 80.125(c) and 80.1426(e).
* * * * *
0
19. Amend Sec. 80.1426 by:
0
a. Revising paragraphs (b)(2), (c)(7), and (e);
0
b. In paragraphs (f)(1)(v)(A) and (B), removing the text ``D-code'' and
adding, in its place, the text ``D code'';
0
c. Adding paragraphs (f)(1)(vii) and (viii);
0
d. Revising paragraphs (f)(8) introductory text, (f)(8)(iii), and
(f)(10), (11), and (17);
0
e. Adding paragraph (f)(18); and
0
f. Revising table 1 to the section.
The revisions and additions read as follows:
Sec. 80.1426 How are RINs generated and assigned to batches of
renewable fuel?
* * * * *
(b) * * *
(2) If EPA approves a petition of Alaska or a United States
territory to opt-in to the renewable fuel program under the provisions
in Sec. 80.1443, then the requirements of paragraph (b)(1) of this
section shall also apply to renewable fuel produced or imported for use
as transportation fuel, heating oil, or jet fuel in that state or
territory beginning in the next calendar year.
(c) * * *
(7) For renewable fuel oil, renewable fuel producers and importers
must not generate RINs unless they have received affidavits from the
final end user or users of the fuel oil as specified in Sec.
80.1451(b)(1)(ii)(T)(2).
* * * * *
(e) Assignment of RINs to batches. (1)(i) Except as specified in
paragraphs (e)(1)(ii) and (g) of this section, the producer or importer
of renewable fuel must assign all RINs generated to volumes of
renewable fuel as follows:
(A) If RINs were generated for the renewable fuel at the point of
production or upon importation into the covered location, RINs must be
assigned when such volumes leave the renewable fuel production or
import facility.
(B) If RINs were generated for the renewable fuel at the point of
sale or when the renewable fuel was loaded onto a vessel or other
transportation mode for transport to the covered location, RINs must be
assigned prior to the transfer of ownership of the renewable fuel.
(ii) For renewable fuels that are gaseous at STP, RINs must be
assigned to a volume of renewable fuel at the same time the RIN is
generated.
(iii) For RNG, RINs must be assigned as specified in Sec.
80.125(c).
(2) A RIN is assigned to a volume of renewable fuel when ownership
of the RIN is transferred along with the transfer of ownership of the
volume of renewable fuel, pursuant to Sec. 80.1428(a).
(3) All assigned RINs must have a K code value of 1 for RINs
assigned to renewable fuel or 3 for RINs assigned to RNG.
(f) * * *
(1) * * *
(vii) For purposes of identifying the appropriate approved pathway,
the fuel must be produced, distributed, and used in a manner consistent
with the pathway EPA evaluated when it determined that the pathway
satisfies the applicable lifecycle emissions reduction requirement.
[[Page 16490]]
(viii) A renewable fuel producer may continue to use an existing
registration that was under a pathway in table 1 to this section that
previously specified ``Any'' or ``Any process that converts cellulosic
biomass to fuel'' as its production process requirement if the pathway
was in the renewable fuel production facility's registration that was
accepted by EPA prior to June 1, 2026. Any modifications to the
renewable fuel production facility's registration after this date must
meet an approved pathway.
* * * * *
(8) Standardization of volumes. In determining the standardized
volume of a batch of liquid renewable fuel or liquid biointermediate
under this subpart, the batch volume must be adjusted to a standard
temperature of 60 [deg]F as follows:
* * * * *
(iii) For other renewable fuels and biointermediates, an
appropriate formula commonly accepted by the industry must be used to
standardize the actual volume to 60 [deg]F. Formulas used must be
reported to EPA and may be determined to be inappropriate.
* * * * *
(10) Renewable CNG/LNG produced from biogas distributed via a
closed distribution system. RIN generators may only generate RINs for
renewable CNG/LNG produced from biogas that is distributed via a
closed, private, non-commercial system if all the following
requirements are met:
(i) The renewable CNG/LNG was produced from renewable biomass under
an approved pathway.
(ii) The RIN generator has entered into a written contract for the
sale or use of a specific quantity of renewable CNG/LNG for use as
transportation fuel, or has obtained affidavits from all parties
selling or using the renewable CNG/LNG as transportation fuel.
(iii) The renewable CNG/LNG was used as transportation fuel and for
no other purpose.
(iv) The biogas was introduced into the closed, private, non-
commercial system no later and the renewable CNG/LNG produced from the
biogas was used as transportation fuel no later than December 31, 2024.
(v) RINs may only be generated on biomethane content of the
renewable CNG/LNG used as transportation fuel.
(11) Renewable CNG/LNG produced from RNG distributed via a
commercial distribution system. RINs for renewable CNG/LNG produced
from RNG that is introduced into a commercial distribution system may
only be generated if all the following requirements are met:
(i) The renewable CNG/LNG was produced from renewable biomass and
qualifies for a D code in an approved pathway.
(ii) The RIN generator has entered into a written contract for the
sale or use of a specific quantity of RNG, taken from a commercial
distribution system (e.g., physically connected pipeline, barge, truck,
rail), for use as transportation fuel, or has obtained affidavits from
all parties selling or using the RNG taken from a commercial
distribution system as transportation fuel.
(iii) The renewable CNG/LNG produced from the RNG was sold for use
as transportation fuel and for no other purpose.
(iv) The RNG was injected into and withdrawn from the same
commercial distribution system.
(v) The RNG was withdrawn from the commercial distribution system
in a manner and at a time consistent with the transport of the RNG
between the injection and withdrawal points.
(vi) The volume of RNG injected into the commercial distribution
system and the volume of RNG withdrawn are measured by continuous
metering.
(vii) The volume of renewable CNG/LNG sold for use as
transportation fuel corresponds to the volume of RNG that was injected
into and withdrawn from the commercial distribution system.
(viii) No other party relied upon the volume of biogas, RNG, or
renewable CNG/LNG for the generation of RINs.
(ix) The RNG was introduced into the commercial distribution system
no later than December 31, 2024, and the renewable CNG/LNG was used as
transportation fuel no later than December 31, 2024.
(x) RINs may only be generated on biomethane content of the biogas,
treated biogas, RNG, or renewable CNG/LNG.
(xi)(A) On or after January 1, 2025, RINs may only be generated for
RNG injected into a natural gas commercial pipeline system for use as
transportation fuel as specified in subpart E of this part.
(B) RINs may be generated for RNG as specified in subpart E of this
part prior to January 1, 2025, if all applicable requirements under
this part are met.
* * * * *
(17) Qualifying use demonstration for certain renewable fuels. For
purposes of this section, any renewable fuel other than ethanol,
biodiesel, renewable gasoline, renewable jet fuel, or renewable diesel
that meets paragraph (1) of the definition for renewable diesel is
considered renewable fuel and the producer or importer may generate
RINs for such fuel only if all the following apply:
(i) The fuel is produced from renewable biomass and qualifies to
generate RINs under an approved pathway.
(ii) The fuel producer or importer maintains records demonstrating
that the fuel was produced for use as a transportation fuel, heating
oil, or jet fuel by any of the following:
(A) Blending the renewable fuel into gasoline or distillate fuel to
produce a transportation fuel, heating oil, or jet fuel that meets all
applicable standards under this part and 40 CFR part 1090.
(B) Entering into a written contract for the sale of the renewable
fuel, which specifies the purchasing party must blend the fuel into
gasoline or distillate fuel to produce a transportation fuel, heating
oil, or jet fuel that meets all applicable standards under this part
and 40 CFR part 1090.
(C) Entering into a written contract for the sale of the renewable
fuel, which specifies that the fuel must be used in its neat form as a
transportation fuel, heating oil, or jet fuel that meets all applicable
standards.
(iii) The fuel was sold for use in or as a transportation fuel,
heating oil, or jet fuel, and for no other purpose.
(18) RIN generation timing. A RIN generator must generate RINs as
follows:
(i) Except as specified in paragraph (f)(18)(ii) of this section,
RINs must be generated at:
(A) For domestic renewable fuel producers, the point of production
or point of sale.
(B) For RIN-generating foreign producers, the point of production
or when the renewable fuel is loaded onto a vessel or other
transportation mode for transport to the covered location.
(C) For RIN-generating importers of renewable fuel, the point of
importation into the covered location.
(ii)(A) Except as specified in paragraph (f)(18)(ii)(B) of this
section, for RNG and renewable fuels that are gaseous at STP, RINs must
be generated no later than 5 business days after the RIN generator has
met all applicable requirements for the generation of RINs under
Sec. Sec. 80.125(b) and 80.130(b) and this paragraph (f), as
applicable.
(B) For foreign produced RIN-less RNG, RINs must be generated no
later than when title is transferred from the foreign producer to the
RIN-generating importer.
(iii) After the RIN generation event has occurred, the RIN
generator must submit the required information to EPA
[[Page 16491]]
following the procedures and reporting deadline specified in Sec.
80.1452(b).
* * * * *
Table 1 to Sec. 80.1426--Applicable D Codes for Each Fuel Pathway for Use in Generating RINs
----------------------------------------------------------------------------------------------------------------
Production process
Row Fuel type Feedstock requirements D code
----------------------------------------------------------------------------------------------------------------
A................................ Ethanol............. Corn starch......... All the following: Dry 6
mill process, using
natural gas, biomass,
or biogas for process
energy and at least two
advanced technologies
from table 2 to this
section.
B................................ Ethanol............. Corn starch......... All the following: Dry 6
mill process, using
natural gas, biomass,
or biogas for process
energy and at least one
of the advanced
technologies from table
2 to this section plus
drying no more than 65%
of the distillers
grains with solubles it
markets annually.
C................................ Ethanol............. Corn starch......... All the following: Dry 6
mill process, using
natural gas, biomass,
or biogas for process
energy and drying no
more than 50% of the
distillers grains with
solubles it markets
annually.
D................................ Ethanol............. Corn starch......... Wet mill process using 6
biomass or biogas for
process energy.
E................................ Ethanol............. Starches from crop Fermentation using 6
residue and annual natural gas, biomass,
cover crops. or biogas for process
energy.
F................................ Biodiesel; Renewable Soybean oil; Oil The following processes 4
diesel; Renewable from annual cover that do not co-process
jet fuel; Heating crops; Oil from renewable biomass and
oil. algae grown petroleum:
photosynthetically; Transesterification
Biogenic waste oils/ with or without
fats/greases; esterification pre-
Camelina sativa treatment;
oil; Distillers Esterification;
corn oil; Hydrotreating.
Distillers sorghum
oil; Commingled
distillers corn oil
and sorghum oil.
G................................ Biodiesel; Renewable Canola/Rapeseed oil. The following processes 4
diesel; Renewable that do not co-process
jet fuel; Heating renewable biomass and
oil. petroleum:
Transesterification
using natural gas or
biomass for process
energy; Hydrotreating.
H................................ Biodiesel; Renewable Soybean oil; Oil The following processes 5
diesel; Renewable from annual cover that co-process
jet fuel; Heating crops; Oil from renewable biomass and
oil. algae grown petroleum:
photosynthetically; Transesterification
Biogenic waste oils/ with or without
fats/greases; esterification pre-
Camelina sativa treatment;
oil; Distillers Esterification;
corn oil; Hydrotreating.
Distillers sorghum
oil; Commingled
distillers corn oil
and sorghum oil;
Canola/Rapeseed oil.
I................................ Renewable naphtha; Camelina sativa oil; Hydrotreating........... 5
LPG. Distillers sorghum
oil; Distillers
corn oil;
Commingled
distillers corn oil
and distillers
sorghum oil; Canola/
Rapeseed oil;
Biogenic waste oils/
fats/greases.
J................................ Ethanol............. Sugarcane........... Fermentation............ 5
K................................ Ethanol............. Crop residue; Slash, Biochemical conversion 3
pre-commercial process that uses
thinnings, and tree lignin from the
residue; renewable biomass
Switchgrass; feedstock to provide
Miscanthus; Energy all thermal and
cane; Arundo donax; electrical process
Pennisetum energy; Thermochemical
purpureum; conversion process that
Separated yard uses char, coke, or
waste; Biogenic syngas derived from the
components of renewable biomass
separated MSW; feedstock to provide
Cellulosic all thermal and
components of electrical process
separated food energy; Dry mill crop
waste; Cellulosic residue conversion
components of process that uses
annual cover crops. natural gas, biogas, or
crop residue for all
thermal process energy.
L................................ Cellulosic diesel; Crop residue; Slash, The following processes 7
Renewable jet fuel; pre-commercial that use lignin, char,
Heating oil. thinnings, and tree coke, or syngas derived
residue; Separated from the renewable
yard waste; biomass feedstock to
Biogenic components provide all thermal and
of separated MSW; electrical process
Cellulosic energy other than
components of natural gas to produce
separated food hydrogen for upgrading
waste. (maximum 0.5 Btu of
natural gas per Btu of
finished fuel):
Pyrolysis and
upgrading; Biochemical
conversion and
upgrading. The
following processes
that use lignin, char,
coke, or syngas derived
from the renewable
biomass feedstock to
provide all thermal and
electrical process
energy: Gasification
and upgrading; Direct
biochemical conversion.
[[Page 16492]]
M................................ Renewable gasoline; Crop residue; Slash, The following processes 3
Renewable gasoline pre-commercial that use lignin, char,
blendstock; Co- thinnings, and tree coke, or syngas derived
processed residue; Separated from the renewable
cellulosic diesel; yard waste; biomass feedstock to
Co-processed Biogenic components provide all thermal and
renewable jet fuel; of separated MSW; electrical process
Co-processed Cellulosic energy other than
heating oil. components of natural gas to produce
separated food hydrogen for upgrading
waste. (maximum 0.5 Btu of
natural gas per Btu of
finished fuel):
Pyrolysis and
upgrading; Biochemical
conversion and
upgrading. The
following processes
that use lignin, char,
coke, or syngas derived
from the renewable
biomass feedstock to
provide all thermal and
electrical process
energy: Gasification
and upgrading; Direct
biochemical conversion.
N................................ Renewable naphtha; Switchgrass; Gasification and 3
Renewable gasoline; Miscanthus; Energy upgrading process that
Renewable gasoline cane; Arundo donax; uses lignin, char,
blendstock; Co- Pennisetum coke, or syngas derived
processed purpureum; from the renewable
cellulosic diesel; Cellulosic biomass feedstock to
Co-processed components of provide all thermal and
renewable jet fuel; annual cover crops. electrical process
Co-processed energy.
heating oil.
O................................ Butanol............. Corn starch......... Fermentation; Dry mill 6
process using natural
gas, biomass, or biogas
for process energy.
P................................ Ethanol; Renewable Non-cellulosic Fermentation using 5
diesel; Renewable portions of natural gas, biogas, or
jet fuel; Heating separated food crop residue for
oil; Renewable waste; Non- thermal energy;
naphtha. cellulosic Hydrotreating;
components of Transesterification.
annual cover crops.
Q................................ Renewable CNG; Biogas from The following processes 3
Renewable LNG. landfills, that do not transport
municipal RNG or renewable CNG/
wastewater LNG by ocean-going
treatment facility vessel: Treatment and
digesters, compression; Treatment
agricultural and liquefaction.
digesters, and
separated MSW
digesters; Biogas
from the cellulosic
components of
biomass processed
in other waste
digesters.
R................................ Ethanol............. Grain sorghum....... Dry mill process using 6
natural gas or biogas
from landfills, waste
treatment plants, or
waste digesters for
process energy.
S................................ Ethanol............. Grain sorghum....... Dry mill process using 5
only biogas from
landfills, waste
treatment plants, or
waste digesters for
process energy and for
on-site production of
all electricity used at
the site other than up
to 0.15 kWh of
electricity from the
grid per gallon of
ethanol produced,
calculated on a per
batch basis.
T................................ Renewable CNG; Biogas from waste The following processes 5
Renewable LNG. digesters. that do not transport
RNG or renewable CNG/
LNG by ocean-going
vessel: Treatment and
compression; Treatment
and liquefaction.
U................................ Cellulosic diesel; Switchgrass; The following processes 7
Renewable jet fuel; Miscanthus; Energy that use lignin, char,
Heating oil. cane; Arundo donax; coke, or syngas derived
Pennisetum from the renewable
purpureum; biomass feedstock to
Cellulosic provide all thermal and
components of electrical process
annual cover crops. energy: Gasification
and upgrading; Direct
biochemical conversion.
----------------------------------------------------------------------------------------------------------------
* * * * *
0
20. Amend Sec. 80.1428 by revising paragraph (a) to read as follows:
Sec. 80.1428 General requirements for RIN distribution.
(a) RINs assigned to volumes of renewable fuel or RNG.
(1) Except as provided in Sec. Sec. 80.1429 and 80.125(d), no
person can separate a RIN that has been assigned to a volume of
renewable fuel or RNG pursuant to Sec. Sec. 80.1426(e) and 80.125(c),
as applicable.
(2) An assigned RIN with a K code of 1 cannot be transferred to
another person without simultaneously transferring a volume of
renewable fuel to that same person.
(3) Assigned gallon-RINs with a K code of 1 or 3 can be transferred
to another person based on the following:
(i) No more than 2.5 assigned gallon-RINs with a K code of 1 can be
transferred to another person with every gallon of renewable fuel
transferred to that same person.
(ii) For RNG, the transferor of assigned RINs with a K code of 3
must transfer RINs under Sec. 80.125(c).
(4) Any transfer of ownership of assigned RINs must be documented
on product transfer documents generated pursuant to Sec. 80.1453.
(i) The RIN must be recorded on the product transfer document used
to transfer ownership of the volume of renewable fuel or a volume of
RNG to another person; or
(ii) The RIN must be recorded on a separate product transfer
document transferred to the same person on the
[[Page 16493]]
same day as the product transfer document used to transfer ownership of
the volume of renewable fuel or a volume of RNG.
* * * * *
0
21. Amend Sec. 80.1429 by revising paragraphs (b)(5)(i),
(b)(5)(ii)(B), and (c) to read as follows:
Sec. 80.1429 Requirements for separating RINs from volumes of
renewable fuel or RNG.
* * * * *
(b) * * *
(5)(i) Any party that produces, imports, owns, sells, or uses a
volume of biogas for which RINs have been generated in accordance with
Sec. 80.1426(f) must separate any RINs that have been assigned to that
volume of biogas if all the following conditions are met:
(A) The party designates the biogas as transportation fuel.
(B) The biogas is used as transportation fuel.
(ii) * * *
(B) Only an RNG RIN separator may separate the RINs that have been
assigned to a volume of RNG after meeting all applicable requirements
in Sec. 80.125(d)(2).
* * * * *
(c) The party responsible for separating a RIN from a volume of
renewable fuel or RNG must change the K code in the RIN from a value of
1 or 3, as applicable, to a value of 2 prior to transferring the RIN to
any other party.
* * * * *
0
22. Amend Sec. 80.1431 by revising paragraph (a)(1)(ix) and adding
paragraph (a)(1)(xi) to read as follows:
Sec. 80.1431 Treatment of invalid RINs.
(a) * * *
(1) * * *
(ix) Was generated for a prohibited act under Sec. 80.1460(b).
* * * * *
(xi) Was otherwise improperly generated.
* * * * *
Sec. 80.1435 [Amended]
0
23. Amend Sec. 80.1435 by, in paragraph (b)(2)(ii), removing the text
``RIN gallons'' and adding, in its place, the text ``gallon-RINs''.
0
24. Amend Sec. 80.1441 by adding paragraphs (e)(2)(iv) and (v) to read
as follows:
Sec. 80.1441 Small refinery exemption.
* * * * *
(e) * * *
(2) * * *
(iv) A refinery that is granted a small refinery exemption under
this section must still submit reports under Sec. 80.1451(a) for the
compliance year for which it was granted an exemption, including annual
compliance reports. Such exempt small refineries must submit annual
compliance reports containing all the information specified in Sec.
80.1451(a)(1) by the applicable compliance deadline specified in Sec.
80.1451(f)(1)(i).
(v) A refinery that is granted a small refinery exemption under
this section must still comply with any deficit RVOs carried forward
from the previous compliance year.
* * * * *
0
25. Amend Sec. 80.1442 by adding paragraphs (h)(6) and (7) to read as
follows:
Sec. 80.1442 What are the provisions for small refiners under the RFS
program?
* * * * *
(h) * * *
(6) A refiner that is granted a small refiner exemption under this
section must still submit reports under Sec. 80.1451(a) for the
compliance year for which it was granted an exemption, including annual
compliance reports. Such exempt small refiners must submit annual
compliance reports containing all the information specified in Sec.
80.1451(a)(1) by the applicable compliance deadline specified in Sec.
80.1451(f)(1)(i).
(7) A refiner that is granted a small refiner exemption under this
section must still comply with any deficit RVOs carried forward from
the previous compliance year.
* * * * *
Sec. 80.1444 [Amended]
0
26. Amend Sec. 80.1444 by, in paragraph (b), removing the text ``in
Sec. 80.1401''.
0
27. Amend Sec. 80.1449 by:
0
a. Revising paragraphs (a) introductory text, (a)(1), (a)(4)(i) and
(iii), and (b);
0
b. Removing paragraph (d); and
0
c. Redesignating paragraph (e) as paragraph (d).
The revisions read as follows:
Sec. 80.1449 What are the Production Outlook Report requirements?
(a) By June 1 of each year, a registered renewable fuel producer or
importer must submit and an unregistered renewable fuel producer may
submit all of the following information for each of its facilities, as
applicable, to EPA:
(1) If currently registered, any planned changes to the type, or
types, of renewable fuel expected to be produced or imported at each
facility owned by the renewable fuel producer or importer.
* * * * *
(4) * * *
(i) Nameplate production capacity and, if applicable, permitted
production capacity.
* * * * *
(iii) If currently registered, any planned changes to feedstocks,
biointermediates, and production processes to be used at each
production facility.
* * * * *
(b) The information listed in paragraph (a) of this section must
include the reporting party's best annual projection estimates for the
five following calendar years.
* * * * *
0
28. Amend Sec. 80.1450 by:
0
a. Revising the last sentence in paragraph (a); and
0
b. Revising paragraphs (b)(1)(iv)(A)(2), (b)(1)(v) introductory text,
(b)(1)(v)(A), (b)(1)(v)(B)(1) introductory text, (b)(1)(v)(D)
introductory text, (b)(1)(v)(D)(1), (b)(1)(vi)(B), (b)(1)(xi),
(b)(1)(xii) introductory text, (b)(1)(xii)(A), (b)(2) introductory
text, (g)(10) introductory text, and (g)(10)(i).
The revisions read as follows:
Sec. 80.1450 What are the registration requirements under the RFS
program?
(a) * * * Registration information must be submitted and accepted
by EPA at least 60 days prior to RIN ownership.
(b) * * *
(1) * * *
(iv) * * *
(A) * * *
(2) The name and address of the company supplying each process heat
fuel to the renewable fuel production facility, foreign ethanol
production facility, or biointermediate production facility.
* * * * *
(v) The following records that support the facility's baseline
volume or, for foreign ethanol production facilities, their production
volume:
(A) For all facilities except those described in paragraph
(b)(1)(v)(B) of this section, copies of the most recent applicable air
permits issued by the U.S. Environmental Protection Agency, state,
local air pollution control agencies, or foreign governmental agencies
and that govern the construction and/or operation of the renewable fuel
or foreign ethanol production facility.
(B) * * *
(1) Applicable air permits issued by EPA, state, local air
pollution control agencies, or foreign governmental agencies that
govern the construction
[[Page 16494]]
and/or operation of the renewable fuel production facility that were:
* * * * *
(D) For all facilities producing renewable fuel from biogas, submit
all relevant information in Sec. 80.1426(f)(10) or (11), including:
(1) Copies of all contracts or affidavits, as applicable, that
follow the track of the biogas/CNG/LNG from its original source, to the
producer that processes it into renewable fuel, and finally to the end
user that will actually use the renewable CNG/LNG for transportation
purposes.
* * * * *
(vi) * * *
(B) Applicable air permits issued by the U.S. Environmental
Protection Agency, state, local air pollution control agencies, or
foreign governmental agencies that governed the construction and/or
operation of the renewable fuel production facility during construction
and when first operated.
* * * * *
(xi) For a producer of renewable fuel oil:
(A) An affidavit from the producer of the renewable fuel oil
stating that the renewable fuel oil for which RINs have been generated
will be sold for the purposes of heating or cooling interior spaces of
homes or buildings to control ambient climate for human comfort, and no
other purpose.
(B) Affidavits from the final end user or users of the renewable
fuel oil stating that the renewable fuel oil is being used or will be
used for purposes of heating or cooling interior spaces of homes or
buildings to control ambient climate for human comfort, and no other
purpose, and acknowledging that any other use of the renewable fuel oil
would violate EPA regulations and subject the user to civil and/or
criminal penalties under the Clean Air Act.
(xii) For a producer or importer of any renewable fuel other than
ethanol, biodiesel, renewable gasoline, renewable jet fuel, renewable
diesel that meets paragraph (1) of the definition for renewable diesel,
biogas-derived renewable fuel, or RNG, all the following:
(A) A description of the renewable fuel and how it will be blended
to into gasoline or diesel fuel to produce a transportation fuel,
heating oil, or jet fuel that meets all applicable standards.
* * * * *
(2) An independent third-party engineering review and written
report and verification of the information provided pursuant to
paragraph (b)(1) of this section and Sec. 80.135, as applicable. The
report and verification must be based upon a review of relevant
documents and a site visit conducted within the six months prior to
submission of the registration information. The report and verification
must separately identify each item required by paragraph (b)(1) of this
section, describe how the independent third-party evaluated the
accuracy of the information provided, state whether the independent
third-party agrees with the information provided, and identify any
exceptions between the independent third-party's findings and the
information provided.
* * * * *
(g) * * *
(10) Registration renewal. Registrations for independent third-
party auditors expire December 31 of every other calendar year.
Previously approved registrations will renew automatically if all the
following conditions are met:
(i) The independent third-party auditor resubmits all information,
updated as necessary, described in paragraphs (g)(1) through (7) of
this section no later than October 31 before the calendar year that
their registration expires.
* * * * *
0
29. Amend Sec. 80.1451 by:
0
a. Revising paragraph (b)(1)(ii)(L);
0
b. Removing and reserving paragraph (b)(1)(ii)(P);
0
c. Revising paragraph (b)(1)(ii)(Q) and paragraph (b)(1)(ii)(T)
introductory text;
0
d. Removing paragraph (c)(2)(ii)(D)(14);
0
e. Revising paragraph (f)(1)(i)(A) introductory text;
0
f. Adding paragraph (f)(1)(i)(C); and
0
g. In paragraph (g)(1)(viii), removing the text ``D-code'' and adding,
in its place, the text ``D code''.
The revisions and addition read as follows:
Sec. 80.1451 What are the reporting requirements under the RFS
program?
* * * * *
(b) * * *
(1) * * *
(ii) * * *
(L) Each process, feedstock, and biointermediate used and
proportion of renewable volume attributable to each process, feedstock,
and biointermediate, as applicable.
* * * * *
(Q) Producers or importers of renewable fuel produced at facilities
that use biogas for process heat as described in Sec. 80.1426(f)(12),
shall report the total energy supplied to the renewable fuel production
facility, in MMBtu based on metering of gas volume.
* * * * *
(T) Producers or importers of any renewable fuel other than
ethanol, biodiesel, renewable gasoline, renewable jet fuel, renewable
diesel that meets paragraph (1) of the definition for renewable diesel,
biogas-derived renewable fuel, or RNG, must report, on a quarterly
basis, all the following for each volume of fuel:
* * * * *
(f) * * *
(1) * * *
(i) * * *
(A) Except as specified in paragraphs (f)(1)(i)(B) and (C) of this
section, obligated parties must submit annual compliance reports by
whichever of the following dates is latest:
* * * * *
(C) If EPA publishes a document in the Federal Register that
proposes to revise a renewable fuel standard in Sec. 80.1405(a),
annual compliance reports for that compliance year must be submitted by
the following date, as applicable:
(1) If EPA publishes a document in the Federal Register that
finalizes the proposed revision to the renewable fuel standard in Sec.
80.1405(a), whichever of the following dates is latest:
(i) The next quarterly reporting deadline under paragraph (f)(2) of
this section after the date the revised renewable fuel standard becomes
effective in Sec. 80.1405(a).
(ii) The applicable compliance reporting deadline under paragraph
(f)(1)(i)(A) or (B) of this section.
(2) If EPA publishes a document in the Federal Register that
withdraws the proposed revision to the renewable fuel standard in Sec.
80.1405(a), whichever of the following dates is latest:
(i) The next quarterly reporting deadline under paragraph (f)(2) of
this section that is 60 days after the date the withdrawal is published
in the Federal Register.
(ii) The applicable compliance reporting deadline under paragraph
(f)(1)(i)(A) or (B) of this section.
(3) If EPA does not publish a document in the Federal Register that
either finalizes or withdraws the proposed revision to the renewable
fuel standard in Sec. 80.1405(a) within 12 months after the date the
proposed rule was published in the Federal Register, whichever of the
following dates is latest:
(i) The next quarterly reporting deadline under paragraph (f)(2) of
this section that is 12 months after the date the proposed rule was
published in the Federal Register.
[[Page 16495]]
(ii) The applicable compliance reporting deadline under paragraph
(f)(1)(i)(A) or (B) of this section.
* * * * *
0
30. Amend Sec. 80.1452 by:
0
a. Revising paragraphs (a), (b) introductory text, and (b)(1), (2),
(4), and (11);
0
b. Redesignating paragraph (b)(18) as paragraph (b)(19) and adding new
paragraph (b)(18); and
0
c. Revising paragraph (c) introductory text.
The revisions and addition read as follows:
Sec. 80.1452 What are the requirements related to the EPA Moderated
Transaction System (EMTS)?
(a) Each party required to submit information under this section
must establish an account with the EPA Moderated Transaction System
(EMTS) at least 60 days prior to engaging in any RIN transactions.
(b) Each time a RIN generator assigns RINs to a batch of renewable
fuel or RNG pursuant to Sec. Sec. 80.125(c) and 80.1426(e), as
applicable, all the following information must be submitted to EPA via
the submitting party's EMTS account within five (5) business days of
the date of RIN assignment. EPA in its sole discretion may allow a RIN
generator to submit information under this paragraph (b) outside the 5-
business-day deadline.
(1) The name of the RIN generator.
(2) The EPA company registration number of the renewable fuel
producer, RNG producer, or foreign ethanol producer, as applicable.
* * * * *
(4) The EPA facility registration number of the facility at which
the renewable fuel producer, RNG producer, or foreign ethanol producer
produced the batch, as applicable.
* * * * *
(11) The volume of ethanol denaturant, if applicable, and
applicable equivalence value of each batch.
* * * * *
(18) Starting January 1, 2027, the type of RIN generation protocol
used when assigning RINs to the associated renewable fuel volume.
* * * * *
(c) Each time any party sells, separates, or retires RINs, all the
following information must be submitted to EPA via the submitting
party's EMTS account within five (5) business days of the reportable
event. Each time any party purchases RINs, all the following
information must be submitted to EPA via the submitting party's EMTS
account within ten (10) business days of the reportable event. The
reportable event for a RIN purchase or sale occurs on the date of
transfer per Sec. 80.1453(a)(4). The reportable event for a RIN
separation or retirement occurs on the date of separation or retirement
as described in Sec. 80.1429 or Sec. 80.1434. EPA in its sole
discretion may allow a party to submit information under this paragraph
(c) outside the applicable 5- or 10-business-day deadline.
* * * * *
0
31. Amend Sec. 80.1453 by revising paragraphs (a)(12)(v) and (vii) and
(d) to read as follows:
Sec. 80.1453 What are the product transfer document (PTD)
requirements for the RFS program?
(a) * * *
(12) * * *
(v) Renewable naphtha. ``This volume of neat or blended renewable
naphtha is designated and intended for use as transportation fuel or
jet fuel in the 48 U.S. contiguous states and Hawaii. This naphtha may
only be used as a gasoline blendstock, E85 blendstock, or jet fuel. Any
person exporting this fuel is subject to the requirements of 40 CFR
80.1430.''.
* * * * *
(vii) Renewable fuels other than ethanol, biodiesel, heating oil,
renewable diesel, naphtha, or butanol. ``This volume of neat or blended
renewable fuel is designated and intended to be used as transportation
fuel, heating oil, or jet fuel in the 48 U.S. contiguous states and
Hawaii. Any person exporting this fuel is subject to the requirements
of 40 CFR 80.1430.''.
* * * * *
(d) For renewable fuel oil, the PTD of the renewable fuel oil shall
state: ``This volume of renewable fuel oil is designated and intended
to be used to heat or cool interior spaces of homes or buildings to
control ambient climate for human comfort. Do NOT use for process heat
or cooling or any other purpose, as these uses are prohibited pursuant
to 40 CFR 80.1460(g).''.
* * * * *
0
32. Amend Sec. 80.1454 by:
0
a. Revising paragraphs (a) introductory text, (b) introductory text,
(b)(3)(ix), (b)(8), and (c)(1) introductory text;
0
b. In paragraph (d)(4)(ii)(B), removing the text ``renewable fuel
facility'' and adding, in its place, the text ``renewable fuel
production facility'';
0
c. In paragraph (g) introductory text, removing the text ``U.S.
agricultural land as defined in Sec. 80.1401'' and adding, in its
place, the text ``agricultural land'';
0
d. In paragraph (g)(2)(ii)(B), removing the text ``renewable fuel
facility'' and adding, in its place, the text ``renewable fuel
production facility'';
0
e. Revising and republishing paragraph (k)(1);
0
f. Revising paragraphs (k)(2) introductory text, (l) introductory text,
(l)(2), and (l)(3)(iv);
0
g. Removing paragraph (m)(8); and
0
h. Redesignating paragraphs (m)(9) through (11) as paragraphs (m)(8)
through (10).
The revisions read as follows:
Sec. 80.1454 What are the recordkeeping requirements under the RFS
program?
(a) Requirements for obligated parties and exporters of renewable
fuel. Any obligated party or exporter of renewable fuel must keep all
the following records:
* * * * *
(b) Requirements for all producers of renewable fuel. In addition
to any other applicable records a renewable fuel producer must maintain
under this section, any domestic or RIN-generating foreign producer of
a renewable fuel must keep all the following records:
* * * * *
(3) * * *
(ix) All facility-determined values used in the calculations under
Sec. 80.1426 and the data used to obtain those values.
* * * * *
(8) A producer of renewable fuel oil must keep copies of all
contracts which describe the renewable fuel oil under contract with
each end user.
* * * * *
(c) * * *
(1) Any RIN-generating foreign producer or importer of renewable
fuel must keep records of feedstock purchases and transfers associated
with renewable fuel for which RINs are generated, sufficient to verify
that feedstocks used are renewable biomass.
* * * * *
(k) * * *
(1) Pathways involving feedstocks other than grain sorghum. A
renewable fuel producer that generates RINs for renewable CNG/LNG
pursuant to Sec. 80.1426(f)(10) or (11), or that uses process heat
from biogas to produce renewable fuel pursuant to Sec. 80.1426(f)(12)
must keep all the following additional records:
(i) Documentation recording the sale of renewable CNG/LNG for use
as transportation fuel relied upon in Sec. 80.1426(f)(10) or (11), or
for use of biogas for process heat to make renewable fuel as relied
upon in Sec. 80.1426(f)(12), and the transfer of title of the biogas/
CNG/LNG from the point of biogas production to the facility that
[[Page 16496]]
sells or uses the fuel for transportation purposes.
(ii) Documents demonstrating the volume and energy content of
biogas/CNG/LNG relied upon under Sec. 80.1426(f)(10) that was
delivered to the facility that sells or uses the fuel for
transportation purposes.
(iii) Documents demonstrating the volume and energy content of
biogas/CNG/LNG relied upon under Sec. 80.1426(f)(11), or biogas relied
upon under Sec. 80.1426(f)(12) that was placed into the commercial
distribution.
(iv) Documents demonstrating the volume and energy content of
biogas relied upon under Sec. 80.1426(f)(12) at the point of
distribution.
(v) Affidavits, EPA-approved documentation, or data from a real-
time electronic monitoring system, confirming that the amount of the
biogas/CNG/LNG relied upon under Sec. 80.1426(f)(10) and (11) was used
for transportation purposes only, and for no other purpose. The RIN
generator must obtain affidavits, or monitoring system data under this
paragraph (k), at least once per calendar quarter.
(vi) The biogas producer's Compliance Certification required under
Title V of the Clean Air Act.
(vii) Any other records as requested by EPA.
(2) Pathways involving grain sorghum as feedstock. A renewable fuel
producer that produces fuel pursuant to a pathway that uses grain
sorghum as a feedstock must keep all the following additional records,
as appropriate:
* * * * *
(l) Additional requirements for producers or importers of any
renewable fuel other than ethanol, biodiesel, renewable gasoline,
renewable diesel, biogas-derived renewable fuel, or RNG. A renewable
fuel producer that generates RINs for any renewable fuel other than
ethanol, biodiesel, renewable gasoline, renewable jet fuel, renewable
diesel that meets paragraph (1) of the definition for renewable diesel,
biogas-derived renewable fuel, or RNG must keep all the following
additional records:
* * * * *
(2) Contracts and documents memorializing the sale of renewable
fuel to parties who blend the fuel into gasoline or diesel fuel to
produce a transportation fuel, heating oil, or jet fuel, or who use the
renewable fuel in its neat form for a qualifying fuel use.
(3) * * *
(iv) A description of the finished fuel, and a statement that the
fuel meets all applicable standards and was sold for use as a
transportation fuel, heating oil, or jet fuel.
* * * * *
0
33. Amend Sec. 80.1460 by:
0
a. Revising paragraph (b)(4);
0
b. Adding paragraph (b)(9); and
0
c. Revising paragraph (g).
The revisions and addition read as follows:
Sec. 80.1460 What acts are prohibited under the RFS program?
* * * * *
(b) * * *
(4)(i) Transfer to any person an assigned RIN with a K code of 1
without transferring an appropriate volume of renewable fuel to the
same person on the same day.
(ii) Take title to an assigned RIN with a K code of 3 without
taking title to a corresponding volume of RNG.
* * * * *
(9) Generate a RIN for fuel that is used for process heat or
electricity generation, except as specified in Sec. 80.1426(f)(12).
* * * * *
(g) Failing to use a renewable fuel oil for its intended use. No
person shall use renewable fuel oil for which RINs have been generated
in an application other than to heat or cool interior spaces of homes
or buildings to control ambient climate for human comfort.
* * * * *
0
34. Amend Sec. 80.1461 by adding paragraph (g) to read as follows:
Sec. 80.1461 Who is liable for violations under the RFS program?
* * * * *
(g) Importer joint and several liability. Any person meeting the
definition of an importer under this subpart is jointly and severally
liable for any violation of this subpart.
0
35. Amend Sec. 80.1469 by:
0
a. Removing paragraphs (a) and (b);
0
b. Redesignating paragraphs (c) through (f) as paragraphs (a) through
(d); and
0
c. Revising newly redesignated paragraphs (a) introductory text,
(a)(1)(vii), (a)(3)(vii), (a)(5), (c)(1), (d)(1) introductory text, and
(d)(2).
The revisions read as follows:
Sec. 80.1469 Requirements for Quality Assurance Plans.
* * * * *
(a) QAP Requirements. All components specified in this paragraph
(a) require quarterly monitoring, except for paragraph (a)(4)(iii) of
this section which must be done annually.
(1) * * *
(vii) Feedstock(s) and biointermediate(s) are not renewable fuel
for which RINs were previously generated unless the RINs were generated
under Sec. 80.1426(c)(6). For renewable fuels that have RINs generated
under Sec. 80.1426(c)(6), verify that renewable fuels used as a
feedstock meet all applicable requirements of this paragraph (a)(1).
* * * * *
(3) * * *
(vii) Verify that appropriate RIN generation calculations are being
followed under Sec. 80.1426.
* * * * *
(5) Representative sampling. Independent third-party auditors may
use a representative sample of batches of renewable fuel or
biointermediate in accordance with the procedures described in 40 CFR
1090.1805 for all components of this paragraph (a) except for
paragraphs (a)(1)(ii) and (iii), (a)(2)(ii), (a)(3)(vi), and (a)(4)(ii)
and (iii) of this section. If a facility produces both a renewable fuel
and a biointermediate, the independent third-party auditor must select
separate representative samples for the renewable fuel and
biointermediate.
* * * * *
(c) * * *
(1) Each independent third-party auditor must annually submit a
general and at least one pathway-specific QAP to the EPA which
demonstrates adherence to the requirements of paragraphs (a) and (b) of
this section and request approval on forms and using procedures
specified by EPA.
* * * * *
(d) * * *
(1) A new QAP must be submitted to EPA according to paragraph (c)
of this section and the independent third-party auditor must update
their registration according to Sec. 80.1450(g)(9) whenever any of the
following changes occur at a renewable fuel or biointermediate
production facility audited by an independent third-party auditor and
the auditor does not possess an appropriate pathway-specific QAP that
encompasses the change:
* * * * *
(2) A QAP ceases to be valid as the basis for verifying RINs or a
biointermediate under a new pathway until a new pathway-specific QAP,
submitted to the EPA under this paragraph (d), is approved pursuant to
paragraph (c) of this section.
Sec. 80.1470 [Removed and Reserved]
0
36. Remove and reserve Sec. 80.1470.
0
37. Amend Sec. 80.1471 by revising paragraphs (b)(3), (e), and (f) to
read as follows:
[[Page 16497]]
Sec. 80.1471 Requirements for QAP auditors.
* * * * *
(b) * * *
(3) The independent third-party auditor must not own, buy, sell, or
otherwise trade RINs unless required to replace an invalid RIN pursuant
to Sec. 80.1474.
* * * * *
(e) The independent third-party auditor must identify RINs
generated from a renewable fuel producer or foreign renewable fuel
producer as having been verified under a QAP.
(1) For RINs verified under a QAP pursuant to Sec. 80.1469, RINs
must be designated as Q-RINs and must be identified as having been
verified under a QAP in EMTS.
(2) The independent third-party auditor must not identify RINs
generated from a renewable fuel producer or foreign renewable fuel
producer as having been verified under a QAP if a revised QAP must be
submitted to and approved by the EPA under Sec. 80.1469(d).
(3) The independent third-party auditor must not identify RINs
generated for renewable fuel produced using a biointermediate as having
been verified under a QAP unless the biointermediate used to produce
the renewable fuel was verified under an approved QAP pursuant to Sec.
80.1477.
(f)(1) Auditors may only verify RINs that have been generated after
the audit required under Sec. 80.1472 has been completed. Auditors may
only verify biointermediates that were produced after the audit
required under Sec. 80.1472 has been completed. Auditors must only
verify RINs generated from renewable fuels produced from
biointermediates after the audit required under Sec. 80.1472 has been
completed for both the biointermediate production facility and the
renewable fuel production facility.
(2) Verification of RINs or biointermediates may continue for no
more than 200 days following an on-site visit or 380 days after an on-
site visit if a previously EPA-approved remote monitoring system is in
place at the renewable fuel production facility.
* * * * *
0
38. Revise and republish Sec. 80.1472 to read as follows:
Sec. 80.1472 Requirements for quality assurance audits.
(a) General requirements. (1) An audit must be performed by an
auditor who meets the requirements of Sec. 80.1471.
(2) An audit must be based on a QAP per Sec. 80.1469.
(3) Each audit must verify every element contained in an applicable
and approved QAP.
(4) Each audit must include a review of documents generated by the
renewable fuel producer or biointermediate producer.
(b) On-site visits. (1) As applicable, the independent third-party
auditor must conduct an on-site visit at the renewable fuel production
facility, foreign ethanol production facility, or biointermediate
production facility:
(i) At least two times per calendar year; or
(ii) In the event an auditor uses a remote monitoring system
approved by the EPA, at least one time per calendar year.
(2) An on-site visit specified in paragraph (b)(1)(i) of this
section must occur no more than:
(i) 200 days after the previous on-site visit. The 200-day period
must start the day after the previous on-site visit ends; or
(ii) 380 days after the previous on-site visit if a previously
approved (by EPA) remote monitoring system is in place at the renewable
fuel production facility, foreign ethanol production facility, or
biointermediate production facility, as applicable. The 380-day period
must start the day after the previous on-site visit ends.
(3) An on-site visit must include verification of all QAP elements
that require inspection or evaluation of the physical attributes of the
renewable fuel production facility, foreign ethanol production
facility, or biointermediate production facility, as applicable.
(4) The on-site visit must be overseen by a professional engineer,
as specified in Sec. 80.1450(b)(2)(i)(A) and (B).
0
39. Amend Sec. 80.1473 by:
0
a. Revising paragraph (a);
0
b. Removing paragraphs (c) and (d);
0
c. Redesignating paragraphs (e) and (f) as paragraphs (c) and (d);
0
d. Revising newly redesignated paragraphs (c) introductory text,
(c)(1), and (d).
The revisions read as follows:
Sec. 80.1473 Affirmative defenses.
(a) Criteria. Any person who engages in actions that would be a
violation of the provisions of either Sec. 80.1460(b)(2) or (c)(1),
other than the generator of an invalid RIN, will not be deemed in
violation if the person demonstrates that the criteria under paragraph
(c) of this section are met.
* * * * *
(c) Asserting an affirmative defense for invalid Q-RINs. To
establish an affirmative defense to a violation of Sec. 80.1460(b)(2)
or (c)(1) involving invalid Q-RINs, the person must meet the
notification requirements of paragraph (d) of this section and prove by
a preponderance of evidence all the following:
(1) The RIN in question was verified through a quality assurance
audit pursuant to Sec. 80.1472 using an approved QAP as specified in
Sec. 80.1469.
* * * * *
(d) Notification requirements. A person asserting an affirmative
defense to a violation of Sec. 80.1460(b)(2) or (c)(1), arising from
the transfer or use of an invalid Q-RIN must submit a written report to
the EPA via the EMTS support line ([email protected]),
including all pertinent supporting documentation, demonstrating that
the requirements of paragraph (c) of this section were met. The written
report must be submitted within 30 days of the person discovering the
invalidity.
0
40. Amend Sec. 80.1474 by:
0
a. Removing paragraphs (a)(1) and (2);
0
b. Redesignating paragraphs (a)(3) and (4) as paragraphs (a)(1) and
(2);
0
c. Revising paragraphs (b)(5) and (d)(2);
0
d. Removing paragraph (e);
0
e. Redesignating paragraphs (f) and (g) as paragraphs (e) and (f).
The revisions read as follows:
Sec. 80.1474 Replacement requirements for invalidly generated RINs.
* * * * *
(b) * * *
(5) Within 60 days of receiving a notification from the EPA that a
PIR generator has failed to perform a corrective action required
pursuant to this section, the party that owns the invalid RIN is
required to do one of the following:
(i) Retire the invalid RIN.
(ii) If the invalid RIN has already been used for compliance with
an obligated party's RVO, correct the RVO to subtract the invalid RIN.
* * * * *
(d) * * *
(2) The number of RINs retired must be equal to the number of PIRs
or invalid RINs being replaced, subject to paragraph (e) of this
section if applicable.
* * * * *
0
41. Amend Sec. 80.1476 by revising paragraph (h)(1) to read as
follows:
Sec. 80.1476 Requirements for biointermediate producers.
* * * * *
(h) * * *
(1) Each biointermediate producer must assign a number (the ``batch
number'') to each batch of biointermediate consisting of their EPA-
issued company registration number,
[[Page 16498]]
the EPA-issued facility registration number, the last two digits of the
compliance year in which the batch was produced, and a unique number
for the batch during the compliance year (e.g., 4321-54321-25-000001).
* * * * *
0
42. Amend Sec. 80.1477 by revising paragraphs (b) and (c) to read as
follows:
Sec. 80.1477 Requirements for QAPs for biointermediate producers.
* * * * *
(b) QAPs approved by EPA to verify biointermediate production must
meet the requirements in Sec. 80.1469, as applicable.
(c) Quality assurance audits, when performed, must be conducted in
accordance with the requirements in Sec. 80.1472.
* * * * *
0
43. Amend Sec. 80.1479 by revising paragraphs (c)(2) to read as
follows:
Sec. 80.1479 Alternative recordkeeping requirements for separated
yard waste, separated food waste, separated MSW, and biogenic waste
oils/fats/greases.
* * * * *
(c) * * *
(2) The independent third-party auditor must conduct a site visit
of each feedstock aggregator's establishment as specified in Sec.
80.1471(f). Instead of verifying RINs with a site visit of the
feedstock aggregator's establishment every 200 days as specified in
Sec. 80.1471(f)(2), the independent third-party auditor may verify
RINs with a site visit every 380 days.
* * * * *
PART 1090--REGULATION OF FUELS, FUEL ADDITIVES, AND REGULATED
BLENDSTOCKS
0
44. The authority citation for part 1090 continues to read as follows:
Authority: 42 U.S.C. 7414, 7521, 7522-7525, 7541, 7542, 7543,
7545, 7547, 7550, and 7601.
Subpart A--General Provisions
0
45. Amend Sec. 1090.80 by:
0
a. In the definition for ``Diesel fuel'', revising paragraph (2);
0
b. Removing the definition for ``Nonpetroleum (NP) diesel fuel'' and
adding, in its place, a definition for ``Nonpetroleum diesel fuel'';
and
0
c. In the definition for ``Responsible corporate officer (RCO)'',
revising the last sentence.
The revisions and addition read as follows:
Sec. 1090.80 Definitions.
* * * * *
Diesel fuel * * *
(2) Any fuel (including nonpetroleum diesel fuel or a fuel blend
that contains nonpetroleum diesel fuel) that is intended or used to
power a vehicle or engine that is designed to operate using diesel
fuel.
* * * * *
Nonpetroleum diesel fuel means renewable diesel fuel or biodiesel.
Nonpetroleum diesel fuel also includes other renewable fuel under 40
CFR part 80, subpart M, that is used or intended for use to power a
vehicle or engine that is designed to operate using diesel fuel or that
is made available for use in a vehicle or engine designed to operate
using diesel fuel.
* * * * *
Responsible corporate officer (RCO) * * * Examples of positions in
non-corporate business structures that qualify are owner, chief
executive officer, or president.
* * * * *
0
46. Amend Sec. 1090.95 by revising and republishing paragraphs (a) and
(c) to read as follows:
Sec. 1090.95 Incorporation by reference.
(a) Certain material is incorporated by reference into this part
with the approval of the Director of the Federal Register under 5
U.S.C. 552(a) and 1 CFR part 51. All approved incorporation by
reference (IBR) material is available for inspection at the U.S. EPA
and at the National Archives and Records Administration (NARA). Contact
the U.S. EPA at: U.S. EPA, Air and Radiation Docket and Information
Center, WJC West Building, Room 3334, 1301 Constitution Ave. NW,
Washington, DC 20460; (202) 566-1742; [email protected]. For
information on the availability of this material at NARA, visit
www.archives.gov/federal-register/cfr/ibr-locations or email
[email protected]. The material may be obtained from the sources
in the following paragraphs of this section.
* * * * *
(c) ASTM International (ASTM), 100 Barr Harbor Dr., P.O. Box C700,
West Conshohocken, PA 19428-2959; (877) 909-2786; www.astm.org.
(1) ASTM D86-23ae2, Standard Test Method for Distillation of
Petroleum Products and Liquid Fuels at Atmospheric Pressure,
approved December 1, 2023 (ASTM D86); IBR approved for Sec.
1090.1350(b).
(2) ASTM D287-22, Standard Test Method for API Gravity of Crude
Petroleum and Petroleum Products (Hydrometer/Method), approved
December 1, 2022 (ASTM D287); IBR approved for Sec. 1090.1337(d).
(3) ASTM D975-24a, Standard Specification for Diesel Fuel, approved
August 1, 2024 (ASTM D975); IBR approved for Sec. 1090.80.
(4) ASTM D976-21e1, Standard Test Method for Calculated Cetane Index
of Distillate Fuels, approved November 1, 2021 (ASTM D976); IBR
approved for Sec. 1090.1350(b).
(5) ASTM D1298-24, Standard Test Method for Density, Relative
Density, or API Gravity of Crude Petroleum and Liquid Petroleum
Products by Hydrometer Method, approved November 1, 2024 (ASTM
D1298); IBR approved for Sec. 1090.1337(d).
(6) ASTM D1319-20a, Standard Test Method for Hydrocarbon Types in
Liquid Petroleum Products by Fluorescent Indicator Adsorption,
approved August 1, 2020 (ASTM D1319); IBR approved for Sec.
1090.1350(b).
(7) ASTM D2163-23e1, Standard Test Method for Determination of
Hydrocarbons in Liquefied Petroleum (LP) Gases and Propane/Propene
Mixtures by Gas Chromatography, approved March 1, 2023 (ASTM D2163);
IBR approved for Sec. 1090.1350(b).
(8) ASTM D2622-24a, Standard Test Method for Sulfur in Petroleum
Products by Wavelength Dispersive X-ray Fluorescence Spectrometry,
approved December 1, 2024 (ASTM D2622); IBR approved for Sec. Sec.
1090.1350(b); 1090.1360(d); 1090.1375(c).
(9) ASTM D3231-25, Standard Test Method for Phosphorus in Gasoline,
approved May 1, 2025 (ASTM D3231); IBR approved for Sec.
1090.1350(b).
(10) ASTM D3237-22, Standard Test Method for Lead in Gasoline by
Atomic Absorption Spectroscopy, approved October 1, 2022 (ASTM
D3237); IBR approved for Sec. 1090.1350(b).
(11) ASTM D3606-24a, Standard Test Method for Determination of
Benzene and Toluene in Spark Ignition Fuels by Gas Chromatography,
approved November 1, 2024 (ASTM D3606); IBR approved for Sec.
1090.1360(c).
(12) ASTM D4052-22, Standard Test Method for Density, Relative
Density, and API Gravity of Liquids by Digital Density Meter,
approved May 1, 2022 (ASTM D4052); IBR approved for Sec.
1090.1337(d) and (f).
(13) ASTM D4057-22, Standard Practice for Manual Sampling of
Petroleum and Petroleum Products, approved May 1, 2022 (ASTM D4057);
IBR approved for Sec. Sec. 1090.1335(b); 1090.1605(b).
(14) ASTM D4177-22e1, Standard Practice for Automatic Sampling of
Petroleum and Petroleum Products, approved July 1, 2022 (ASTM
D4177); IBR approved for Sec. Sec. 1090.1315(a); 1090.1335(c).
(15) ASTM D4737-21, Standard Test Method for Calculated Cetane Index
by Four Variable Equation, approved November 1, 2021 (ASTM D4737);
IBR approved for Sec. 1090.1350(b).
(16) ASTM D4806-25, Standard Specification for Denatured Fuel
Ethanol, approved April 1, 2025 (ASTM D4806); IBR approved for Sec.
1090.1395(a).
[[Page 16499]]
(17) ASTM D4814-25a, Standard Specification for Automotive Spark-
Ignition Engine Fuel, approved December 15, 2025 (ASTM D4814); IBR
approved for Sec. Sec. 1090.80; 1090.1395(a).
(18) ASTM D5134-21 (Reapproved 2025), Standard Test Method for
Detailed Analysis of Petroleum Naphthas through n-Nonane by
Capillary Gas Chromatography, approved October 1, 2025 (ASTM D5134);
IBR approved for Sec. 1090.1350(b).
(19) ASTM D5186-24, Standard Test Method for Determination of the
Aromatic Content and Polynuclear Aromatic Content of Diesel Fuels By
Supercritical Fluid Chromatography, approved July 1, 2024 (ASTM
D5186); IBR approved for Sec. 1090.1350(b).
(20) ASTM D5191-22, Standard Test Method for Vapor Pressure of
Petroleum Products and Liquid Fuels (Mini Method), approved July 1,
2022 (ASTM D5191); IBR approved for Sec. 1090.1360(d).
(21) ASTM D5453-25, Standard Test Method for Determination of Total
Sulfur in Light Hydrocarbons, Spark Ignition Engine Fuel, Diesel
Engine Fuel, and Engine Oil by Ultraviolet Fluorescence, approved
July 1, 2025 (ASTM D5453); IBR approved for Sec. 1090.1350(b).
(22) ASTM D5500-20a, Standard Test Method for Vehicle Evaluation of
Unleaded Automotive Spark-Ignition Engine Fuel for Intake Deposit
Formation, approved June 1, 2020 (ASTM D5500); IBR approved for
Sec. 1090.1395(c).
(23) ASTM D5599-22, Standard Test Method for Determination of
Oxygenates in Gasoline by Gas Chromatography and Oxygen Selective
Flame Ionization Detection, approved April 1, 2022 (ASTM D5599); IBR
approved for Sec. 1090.1360(d).
(24) ASTM D5769-25, Standard Test Method for Determination of
Benzene, Toluene, and Total Aromatics in Finished Gasolines by Gas
Chromatography/Mass Spectrometry, approved October 1, 2025 (ASTM
D5769); IBR approved for Sec. Sec. 1090.1350(b); 1090.1360(d).
(25) ASTM D5842-23, Standard Practice for Sampling and Handling of
Fuels for Volatility Measurement, approved October 1, 2023 (ASTM
D5842); IBR approved for Sec. 1090.1335(d).
(26) ASTM D5854-25, Standard Practice for Mixing and Handling of
Liquid Samples of Petroleum and Petroleum Products, approved July 1,
2025 (ASTM D5854); IBR approved for Sec. 1090.1315(a).
(27) ASTM D6201-19a, Standard Test Method for Dynamometer Evaluation
of Unleaded Spark-Ignition Engine Fuel for Intake Valve Deposit
Formation, approved December 1, 2019 (ASTM D6201); IBR approved for
Sec. 1090.1395(a).
(28) ASTM D6259-23, Standard Practice for Determination of a Pooled
Limit of Quantitation for a Test Method, approved May 1, 2023 (ASTM
D6259); IBR approved for Sec. 1090.1355(b).
(29) ASTM D6299-25a, Standard Practice for Applying Statistical
Quality Assurance and Control Charting Techniques to Evaluate
Analytical Measurement System Performance, approved July 1, 2025
(ASTM D6299); IBR approved for Sec. Sec. 1090.1300(d);
1090.1370(c); 1090.1375(a), (b), (c), and (d); 1090.1450(c).
(30) ASTM D6550-25, Standard Test Method for Determination of Olefin
Content of Gasolines by Supercritical-Fluid Chromatography, approved
October 1, 2025 (ASTM D6550); IBR approved for Sec. 1090.1350(b).
(31) ASTM D6667-21, Standard Test Method for Determination of Total
Volatile Sulfur in Gaseous Hydrocarbons and Liquefied Petroleum
Gases by Ultraviolet Fluorescence, approved April 1, 2021 (ASTM
D6667); IBR approved for Sec. Sec. 1090.1360(d); 1090.1375(c).
(32) ASTM D6708-24, Standard Practice for Statistical Assessment and
Improvement of Expected Agreement Between Two Test Methods that
Purport to Measure the Same Property of a Material, approved March
1, 2024 (ASTM D6708); IBR approved for Sec. Sec. 1090.1360(c);
1090.1365(d) and (f); 1090.1375(c).
(33) ASTM D6729-25, Standard Test Method for Determination of
Individual Components in Spark Ignition Engine Fuels by 100 Metre
Capillary High Resolution Gas Chromatography, approved October 1,
2025 (ASTM D6729); IBR approved for Sec. 1090.1350(b).
(34) ASTM D6730-22, Standard Test Method for Determination of
Individual Components in Spark Ignition Engine Fuels by 100-Metre
Capillary (with Precolumn) High-Resolution Gas Chromatography,
approved November 1, 2022 (ASTM D6730); IBR approved for Sec.
1090.1350(b).
(35) ASTM D6751-24, Standard Specification for Biodiesel Fuel
Blendstock (B100) for Middle Distillate Fuels, approved March 1,
2024 (ASTM D6751); IBR approved for Sec. Sec. 1090.300(a);
1090.1350(b).
(36) ASTM D6792-25, Standard Practice for Quality Management Systems
in Petroleum Products, Liquid Fuels, and Lubricants Testing
Laboratories, approved November 1, 2025 (ASTM D6792); IBR approved
for Sec. 1090.1450(c).
(37) ASTM D7717-11 (Reapproved 2021), Standard Practice for
Preparing Volumetric Blends of Denatured Fuel Ethanol and Gasoline
Blendstocks for Laboratory Analysis, approved October 1, 2021 (ASTM
D7717); IBR approved for Sec. 1090.1340(b).
(38) ASTM D7777-24, Standard Test Method for Density, Relative
Density, or API Gravity of Liquid Petroleum by Portable Digital
Density Meter, approved July 1, 2024 (ASTM D7777); IBR approved for
Sec. 1090.1337(d).
* * * * *
Subpart C--Gasoline Standards
0
47. Effective April 28, 2026, amend Sec. 1090.215 by revising table 2
to paragraph (b)(3)(ii) to read as follows:
Sec. 1090.215 Gasoline RVP standards.
* * * * *
(b) * * *
(3) * * *
(ii) * * *
Table 2 to Paragraph (b)(3)(ii)--Areas Excluded From the Ethanol 1.0 psi
Waiver
------------------------------------------------------------------------
State Counties Effective date
------------------------------------------------------------------------
Illinois.................... All................. April 28, 2025.
Iowa........................ All................. April 28, 2025.
Minnesota................... All................. April 28, 2025.
Missouri.................... All................. April 28, 2025.
Nebraska.................... All................. April 28, 2025.
South Dakota................ All except Butte, April 28, 2025.
Custer, Fall River,
Harding, Lawrence,
Meade, Oglala
Lakota, Pennington,
and Perkins.
South Dakota................ Butte, Custer, Fall April 28, 2026.
River, Harding,
Lawrence, Meade,
Oglala Lakota,
Pennington, and
Perkins.
Wisconsin................... All................. April 28, 2025.
------------------------------------------------------------------------
* * * * *
Subpart D--Diesel Fuel and ECA Marine Fuel Standards
0
48. Amend Sec. 1090.300 by adding paragraph (a)(3) to read as follows:
Sec. 1090.300 Overview and general requirements.
(a) * * *
(3) Biodiesel that meets ASTM D6751 (incorporated by reference, see
[[Page 16500]]
Sec. 1090.95) is not subject to the cetane index or aromatic content
standards in Sec. 1090.305(c). Biodiesel blends or biodiesel that does
not meet ASTM D6751 remain subject to the cetane index or aromatic
content standards in Sec. 1090.305(c).
* * * * *
0
49. Amend Sec. 1090.305 by revising paragraph (a) to read as follows:
Sec. 1090.305 ULSD standards.
(a) Overview. Except as specified in Sec. 1090.300(a), all diesel
fuel (including nonpetroleum diesel fuel) must meet the ULSD per-gallon
standards of this section.
* * * * *
Subpart N--Sampling, Testing, and Retention
0
50. Amend Sec. 1090.1310 by revising paragraph (b)(1) to read as
follows:
Sec. 1090.1310 Testing to demonstrate compliance with standards.
* * * * *
(b) * * *
(1) Diesel fuel. Perform testing for each batch of ULSD (including
nonpetroleum diesel fuel), 500 ppm LM diesel fuel, and ECA marine fuel
to demonstrate compliance with sulfur standards.
* * * * *
0
51. Amend Sec. 1090.1337 by revising paragraph (e) to read as follows:
Sec. 1090.1337 Demonstrating homogeneity.
* * * * *
(e) For testing of diesel fuel (including nonpetroleum diesel fuel)
and ECA marine fuel to meet the standards in subpart D of this part,
demonstrate homogeneity using one of the procedures specified in
paragraph (d)(1) or (2) of this section.
* * * * *
[FR Doc. 2026-06275 Filed 3-31-26; 8:45 am]
BILLING CODE 6560-50-P