[Federal Register Volume 90, Number 115 (Tuesday, June 17, 2025)]
[Proposed Rules]
[Pages 25784-25871]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2025-11128]
[[Page 25783]]
Vol. 90
Tuesday,
No. 115
June 17, 2025
Part III
Environmental Protection Agency
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40 CFR Parts 80 and 1090
Renewable Fuel Standard (RFS) Program: Standards for 2026 and 2027,
Partial Waiver of 2025 Cellulosic Biofuel Volume Requirement, and Other
Changes; Proposed Rule
Federal Register / Vol. 90 , No. 115 / Tuesday, June 17, 2025 /
Proposed Rules
[[Page 25784]]
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ENVIRONMENTAL PROTECTION AGENCY
40 CFR Parts 80 and 1090
[EPA-HQ-OAR-2024-0505; FRL-11947-01-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: Proposed rule.
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SUMMARY: Under the Clean Air Act (CAA), the 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. EPA is proposing the applicable volumes
and percentage standards for 2026 and 2027 for cellulosic biofuel,
biomass-based diesel (BBD), advanced biofuel, and total renewable fuel.
EPA is also proposing to partially waive the 2025 cellulosic biofuel
volume requirement and revise the associated percentage standard due to
a shortfall in cellulosic biofuel production. Finally, EPA is proposing
several regulatory changes to the RFS program, including reducing the
number of Renewable Identification Numbers (RINs) generated for
imported renewable fuel and renewable fuel produced from foreign
feedstocks and removing renewable electricity as a qualifying renewable
fuel under the RFS program (eRINs).
DATES:
Comments. Comments must be received on or before August 8, 2025.
Public Hearing. EPA will announce information regarding the public
hearing for this proposal in supplemental Federal Register document.
ADDRESSES: Comments. Submit your comments, identified by Docket ID No.
EPA-HQ-OAR-2024-0505, at http://www.regulations.gov. Follow the online
instructions for submitting comments. Once submitted, comments cannot
be edited or removed from the docket. EPA may publish any comment
received to its public docket. Do not submit to EPA's docket at https://www.regulations.gov any information you consider to be Confidential
Business Information (CBI) or other information whose disclosure is
restricted by statute. Multimedia submissions (audio, video, etc.) must
be accompanied by a written comment. The written comment is considered
the official comment and should include discussion of all points you
wish to make. EPA will generally not consider comments or comment
contents located outside of the primary submission (i.e., on the web,
cloud, or other file sharing system). Please visit https://www.epa.gov/dockets/commenting-epa-dockets for additional submission methods; the
full EPA public comment policy; information about CBI or multimedia
submissions; and general guidance on making effective comments.
EPA is specifically soliciting comment on numerous aspects of the
proposed rule. To facilitate comment on those portions of the rule, EPA
has indexed each comment solicitation with a unique identifier (e.g.,
``A-1'', ``A-2'', ``B-1'' . . .) to provide a consistent framework for
effective and efficient provision of comments. Accordingly, we ask that
commenters include the corresponding identifier when providing comments
relevant to that comment solicitation. We ask that commenters include
the identifier either in a heading or within the text of each comment,
to make clear which comment solicitation is being addressed. We
emphasize that we are not limiting comment to these identified areas
and encourage submission of any other comments relevant to this
proposed action.
FOR FURTHER INFORMATION 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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Category NAICS \a\ codes Examples of potentially 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,
liquified, 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 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 part 80. 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.
[[Page 25785]]
Preamble Acronyms and Abbreviations
Throughout this document the use of ``we,'' ``us,'' or ``our'' is
intended to refer to 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, 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
CARB California Air Resources Board
CKF corn kernel fiber
CNG compressed natural gas
CWC cellulosic waiver credit
DOE Department of Energy
DRIA Draft Regulatory Impact Analysis
EIA Energy Information Administration
EMTS EPA Moderated Transaction System
EU European Union
FOG fats, oils, and greases
GHG greenhouse gas
LCFS Low Carbon Fuel Standard
LNG liquified natural gas
MSW municipal solid waste
OPEC Organization of Petroleum Exporting Countries
RFS Renewable Fuel Standard
RIN Renewable Identification Number
RNG renewable natural gas
RVO Renewable Volume Obligation
STP standard temperature and pressure
UCO used cooking oil
USDA United States Department of Agriculture
WTI West Texas Intermediate
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 Authority
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
III. Alternative Volume Scenarios for Analysis and Baselines
A. Scope of Analysis
B. Production and Importation of Renewable Fuel
C. Volume Scenarios for 2026-2030
D. Baselines
E. Volume Changes Analyzed
IV. Analysis of Volume Scenarios
A. Energy Security
B. Costs
C. Climate Change
D. Jobs and Rural Economic Development
E. Agricultural Commodity Prices and Food Price Impacts
V. Proposed Volume Requirements for 2026 and 2027
A. Cellulosic Biofuel
B. Non-Cellulosic Advanced Biofuel
C. Biomass-Based Diesel
D. Conventional Renewable Fuel
E. Treatment of Carryover RINs
F. Summary of Proposed Volume Requirements
G. Request for Comment on Alternatives
H. Summary of the Assessed Impacts of the Proposed Volume
Standards
VI. Proposed Percentage Standards for 2026 and 2027
A. Calculation of Percentage Standards
B. Treatment of Small Refinery Volumes
C. Percentage Standards
VII. 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. Proposed Partial Waiver of the 2025 Cellulosic Biofuel Volume
Requirement
D. Calculation of Proposed 2025 Cellulosic Biofuel Percentage
Standard
VIII. Reduction in the Number of RINs Generated for Imported Fuels
and Feedstocks
A. Introduction and Rationale
B. Legal Authority
C. Implementation
IX. 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 Proposed Removal of Renewable Electricity
From the RFS Program
X. Other Changes to RFS Regulations
A. Renewable Diesel, Naphtha, and Jet Fuel Equivalence Values
B. RIN-Related Provisions
C. Percentage Standard Equations
D. Existing 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. Technical Amendments
XI. Request for Comments
A. Renewable Fuel Volumes and Analyses
B. Import RIN Reduction
C. Removal of Renewable Electricity From the RFS Program
D. Other RFS Program Amendments
E. Policy Considerations
XII. 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
XIII. Amendatory Instructions
XIV. Statutory Authority
I. Executive Summary
EPA initiated the RFS program in 2006 pursuant to the requirements
of the Energy Policy Act of 2005 (EPAct), which were codified in CAA
section 211(o). Congress subsequently amended the statutory
requirements in the Energy Independence and Security Act of 2007
(EISA). The statute sets 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 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 for prior years and an
analysis of specified statutory factors.
In this action, EPA is proposing 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 proposing a
number of regulatory changes, including reducing the number of RINs
generated for imported renewable fuel and renewable fuel produced from
foreign feedstocks and removing renewable electricity as a qualifying
renewable fuel under the RFS program (commonly referred to as eRINs).
This preamble describes our rationale for the proposed volume
requirements and regulatory changes and requests comment on the
proposals and supporting rationales, including on EPA's proposed
changes to the RFS program and any legitimate reliance interests that
EPA should consider during this rulemaking.
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\1\ EPA previously established volume requirements and
applicable percentage standards for 2023-2025 on July 12, 2023 (88
FR 44468) (the ``Set 1 Rule'').
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The volume requirements and regulatory changes proposed in this
action would strengthen the RFS program and sharpen the program's focus
on a central goal of the policy: supporting domestic production of
renewable fuels. Ensuring a growing
[[Page 25786]]
supply of domestically produced renewable fuels, particularly those
produced from domestically sourced feedstocks, 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 \2\ and the energy dominance pillar of EPA's ``Powering the Great
American Comeback'' initiative.\3\ The proposed modifications and
requirements in this action are responsive to input from key
agricultural and energy stakeholders on ways to bolster the RFS
program, and EPA looks forward to engaging with these and additional
interested stakeholders on the proposed changes.
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\2\ Executive Order 14154, ``Unleashing American Energy,''
January 20, 2025 (90 FR 8353; January 29, 2025).
\3\ 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 the United States Department of Agriculture (USDA)
and Department of Energy (DOE), EPA is proposing the volume
requirements for 2026 and 2027, as shown in Table I.A.1-1. The proposed
volumes represent significant increases from those established for
2023-2025, especially after accounting for the proposal to reduce the
number of RINs generated for imported renewable fuel and renewable fuel
produced from foreign feedstocks.
Table I.A.1-1--Volume Requirements for 2023-2027
[Billion RINs] \a\
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Volume requirement established in Set 1 Rule Proposed volume requirement
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2023 2024 2025 2026 2027
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Cellulosic biofuel.............. 0.84 \b\ 1.01 \c\ 1.19 1.30 1.36
Biomass-based diesel \d\........ 4.51 4.86 5.36 7.12 7.50
Advanced biofuel................ 5.94 6.54 7.33 9.02 9.46
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Total renewable fuel........ \e\ 20.94 21.54 22.33 24.02 24.46
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\a\ One RIN is equivalent to one ethanol-equivalent gallon of renewable fuel. Throughout this preamble, RINs are
generally used to describe total volumes in each of the four renewable fuel categories, while gallons are
generally used to describe volumes for individual types of biofuel (e.g., ethanol, biodiesel, renewable
diesel, etc.).
\b\ EPA originally established a cellulosic biofuel volume requirement of 1.09 billion gallons for 2024 in the
Set 1 Rule. EPA subsequently reduced this volume requirement to 1.01 billon RINs in a separate action.
\c\ EPA originally established a cellulosic biofuel volume requirement of 1.38 billion gallons for 2025 in the
Set 1 Rule. As described in Section VII, we are proposing to reduce this volume requirement to 1.19 billion
RINs in this action.
\d\ Through 2025, the BBD volume requirement was established in physical gallons rather than RINs. As described
in Section X.C, we are proposing to now specify the BBD volume requirement in RINs, consistent with the other
three renewable fuel categories, rather than physical gallons. For the sake of comparison, we have converted
the BBD volume requirements for 2023-2025 from physical gallons to RINs using the BBD conversion factor in 40
CFR 80.1405(c) of 1.6 RINs per gallon.
\e\ The total renewable fuel volume requirement for 2023 does not include the 0.25 billion RIN supplemental
standard.
In this action, we are proposing to specify the BBD volume
requirement in billion RINs, rather than billion gallons as in previous
RFS rules. To demonstrate the impact of this change, and to allow for
easier comparison to previous RFS rules, the BBD volume requirements
(in billion RINs) and the volume of BBD (in billion gallons) we project
would be supplied to satisfy the volume requirements are shown in Table
I.A.1-2. Finally, the quantities of renewable fuel we project would be
supplied to satisfy the volume requirements, after accounting for the
nested nature of the RFS volume requirements and the proposed import
RIN reduction provisions, are shown in Table I.A.1-3.
Table I.A.1-2--BBD Volume Requirements for 2023-2027
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Volume requirement established in the Set 1 Projected volume requirement
Rule -------------------------------
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2023 2024 2025 2026 2027
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BBD volume requirement (billion \a\ 4.51 \a\ 4.86 \a\ 5.36 7.12 7.50
RINs)..........................
Projected volume of BBD (billion 2.82 3.04 3.35 \b\ 5.61 \b\ 5.86
gallons).......................
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\a\ Billion RINs estimated assuming the average gallon of BBD generates 1.6 RINs.
\b\ Billion gallons estimated after accounting for the projected impacts of the proposed RIN reduction for
imported renewable fuel and renewable fuel produced from foreign feedstocks and the proposed revised
equivalence value for renewable diesel. We project that the average number of RINs generated for BBD will be
1.27 and 1.28 RINs per gallon in 2026 and 2027, respectively. These numbers are not proposed standards and are
presented for illustrative purposes only.
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Table I.A.1-3--Projected Supply of Renewable Fuels To Satisfy the Volume Requirements for 2023-2027
[Billion gallons]
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Projected volume in the Set 1 Rule Projected volume to meet the
------------------------------------------------ proposed volume requirements
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2023 2024 2025 2026 2027
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Cellulosic biofuel.............. 0.84 1.09 1.38 1.30 1.36
Biomass-based diesel............ 3.71 3.85 4.24 6.83 7.16
Other advanced biofuel \a\...... 0.23 0.23 0.23 0.19 0.19
Conventional renewable fuel..... \b\ 13.85 13.96 13.78 13.78 13.66
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Total renewable fuel........ \b\ 18.63 19.12 19.63 22.10 22.37
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\a\ Other advanced biofuel includes all advanced biofuels that to not qualify as cellulosic biofuel or BBD.
\b\ Volumes do not include the 0.25 billion RIN supplemental standard established for 2023.
As discussed above, CAA section 211(o) requires 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 robust analysis of the statutory
factors, we identified a set of renewable fuel volumes to analyze prior
to determining the appropriate volume requirements to establish under
the statute. We began by identifying two volume scenarios and then
analyzed the potential impacts of these volume scenarios on the factors
listed in the statute. The derivation of these volume scenarios is
discussed in Section III. Section IV discusses the analysis of the
volume scenarios for the statutory factors. Section V discusses our
conclusions regarding the appropriate volume requirements to propose in
light of the analyses conducted. Finally, Section VI discusses the
formulas and values used to calculate the proposed percentage
standards.
The BBD and advanced biofuel volumes we are proposing 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 2024. The proposed volumes reflect the
projected growth in the domestic supply of feedstocks, primarily
soybean oil, with smaller projected increases in other feedstocks
including used cooking oil and animal fats. Our focus on the growth in
domestic feedstocks when projecting the supply of BBD for 2026 and 2027
is in part due to the uncertainty in the quantity of imported fuels and
feedstocks that will be available to U.S. markets given various
factors, including the available supply of qualifying feedstocks and
demand for these feedstocks and fuels in other countries.
The cellulosic biofuel volumes we are proposing for 2026 and 2027
are slightly lower than the volumes we finalized for 2025.\4\ The
primary reasons for the decrease in the proposed volumes are
limitations on the quantities of compressed natural gas (CNG) and
liquified natural gas (LNG) derived from biogas projected to be used as
transportation fuel in these years. CNG/LNG derived from biogas
comprise most of the qualifying cellulosic biofuel we project will be
supplied through 2027. However, the proposed 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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\4\ As discussed in Section VII, we are also proposing to reduce
the previously established cellulosic biofuel volume requirement for
2025 in this action.
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The proposed volumes for total renewable fuel in 2026 and 2027
reflect an implied conventional biofuel volume of 15 billion gallons
each year. This is consistent with the implied conventional renewable
fuel volumes in the statutory tables for 2015-2022,\5\ as well as the
implied conventional biofuel volumes established for 2023-2025. We
recognize that while the supply of conventional biofuel in 2026 and
2027 will likely fall short of the implied 15-billion-gallon volume,
the proposed total renewable fuel volumes are still achievable through
the use of additional volumes of advanced biofuel beyond the volume
requirement for that category.
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\5\ CAA section 211(o)(2)(B)(i).
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The volume requirements that we are proposing in this action are
the basis for the calculation of percentage standards applicable to
producers and importers of gasoline and diesel unless they are waived
in a future action using one or more of the available waiver
authorities in CAA section 211(o)(7).
We believe that it is appropriate to propose volume requirements
for two years instead of a longer timeframe due to the increased
uncertainty of trying to project out further in the future, which
increases the likelihood of needing to adjust volumes in the future.
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. However, EPA is requesting
comment on whether it would be appropriate to set standards for more
than two years.
2. Partial Waiver of the 2025 Cellulosic Biofuel Volume Requirement
EPA is proposing to partially waive the 2025 cellulosic biofuel
volume requirement and revise the associated percentage standard due to
a shortfall in cellulosic biofuel production. As discussed in Section
VII, we currently project a 0.19 billion RIN shortfall in available
cellulosic biofuel in 2025. As such, we are proposing to use our CAA
section 211(o)(7)(D) ``cellulosic waiver authority'' to reduce the 2025
cellulosic biofuel volume from 1.38 billion RINs to 1.19 billion RINs.
The use of such waiver authority, if finalized, would also make
cellulosic waiver credits (CWCs) available for the 2025 compliance
year.
3. Reduction in the Number of RINs Generated for Imported Renewable
Fuel and Renewable Fuel Produced From Foreign Feedstocks
EPA is proposing to reduce the number of RINs generated for
imported renewable fuel and renewable fuel produced from foreign
feedstocks. In simple terms, we are proposing regulatory changes that
would mean a gallon of imported renewable fuel, or fuel produced from
foreign feedstocks, would generate half the number of RINs that the
same gallon of fuel would generate if produced in the U.S. from
domestic feedstocks. These proposed changes, described in Section VIII,
are in response to the dramatic increase in imported biofuels and
feedstocks used to produce biofuels in the U.S. observed
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in recent years and align with the statutory goals of bolstering
national energy independence. Imported renewable fuel and renewable
fuel produced from foreign feedstocks 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.
4. Removal of Renewable Electricity From the RFS Program
As described in Section IX, EPA is proposing to remove renewable
electricity as a qualifying renewable fuel under the RFS program
(commonly referred to as eRINs), thereby making it ineligible to
generate RINs. The proposed changes would find that renewable
electricity does not meet the definition of renewable fuel under CAA
section 211(o)(1)(J). On this basis, we are proposing to remove 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 proposing to remove the definition of ``renewable
electricity'' and the renewable electricity pathways in Table 1 of 40
CFR 80.1426 in connection with this policy change.
5. Other Regulatory Changes
EPA is also proposing additional regulatory changes in several
areas to strengthen our implementation of the RFS program. These
regulatory changes are discussed in greater detail in Section X 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 on pure or neat
biodiesel that is used as process heat or for power 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 testing requirements for biodiesel and
renewable diesel.
Other minor changes and technical corrections.
B. Impacts of This Rule
CAA section 211(o)(2)(B)(ii) requires EPA to assess several factors
when determining volume requirements for calendar years after 2022.
These factors are described in the introduction to this Executive
Summary, and each factor is discussed in detail in the Draft Regulatory
Impact Analysis (DRIA) accompanying this rule.\6\ However, the statute
does not specify how EPA must assess each factor. For two of these
statutory factors--costs and energy security--we provide monetized
estimates of the impacts of the proposed volume requirements. For the
other statutory factors, we are either unable to quantify impacts 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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\6\ ``RFS Program Standards for 2026 and 2027: Draft Regulatory
Impact Analysis,'' EPA-420-D-25-001, June 2025.
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EPA considered all statutory factors in developing this proposal,
including factors for which we provide monetized impacts, otherwise
quantified impacts, or provide a qualitative assessment of relevant
impacts, and we find that the proposed volumes are appropriate under
EPA's statutory authority as an outcome of balancing all relevant
factors. This approach is consistent with CAA section 211(o)(2)(B)(ii),
which requires the EPA 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 proposed rule can be found in
Section V.H. Table ES-1 in the DRIA 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 DRIA Chapters 4 through
10. For this proposed rule, we used data and projections from the U.S.
Energy Information Administration's (EIA's) Annual Energy Outlook 2023,
which was the most recent version available at the time we conducted
our analyses supporting this action.\7\ For the final rule, we intend
to update our analyses using the most recent available data and
projections from EIA and other sources.\8\
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\7\ EIA, ``Annual Energy Outlook 2023'' (AEO2023). https://www.eia.gov/outlooks/archive/aeo23.
\8\ On April 15, 2025, EIA issued ``Annual Energy Outlook 2025''
(AEO2025). https://www.eia.gov/outlooks/aeo.
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C. Policy Considerations
The RFS program is a critical policy tool to support the domestic
production of renewable fuels. This action seeks to get the RFS program
back on track by establishing renewable fuel volumes for 2027 by the
statutory deadline and aligning the incentives provided by the RFS
program with the statutory goals of increasing energy independence and
energy security. The proposed volumes for 2026 and 2027 reflect the
significant growth potential for renewable fuel production in the
United States using domestic feedstocks.
EPA is requesting comment on multiple aspects of this action,
including the proposed volume requirements, our technical analyses
supporting those volumes, our proposal to reduce the number of RINs
generated for imported renewable fuels and renewable fuels produced
from foreign feedstocks, the removal of renewable electricity as a
qualifying renewable fuel under RFS program, and the other proposed
regulatory amendments. We also recognize that while this proposal in an
important first step in getting the RFS program back on track,
opportunities remain to improve the RFS program. To that end, we are
requesting comment on a variety of potential changes to the RFS program
that EPA could consider in future actions that would increase the
program's ability to achieve the goals of EPAct and EISA. Our request
for comment includes, but is not limited to:
A general pathway for the production of renewable jet fuel
from corn ethanol, including the consideration of ways to reduce
emissions for this pathway such as the use of carbon capture and
storage, renewable natural gas for process energy and low-carbon
farming practices.
The definition of ``produced from renewable biomass.''
Additional 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. These comments
may include input on methods and data to improve our evaluation of the
environmental impacts associated with imported feedstocks such as used
cooking oil and tallow.
Program enhancements to increase the use of qualifying
woody-biomass to
[[Page 25789]]
produce renewable transportation fuel. We specifically request comment
on the extent to which the renewable biomass definition in 40 CFR 80.2
aligns with current wildfire risk potential and corresponds to wildfire
ignition behavior science and how to best maximize the eligibility of
woody biomass residues generated at sawmills and other forest products
manufacturing businesses that have not been adulterated by chemicals or
other non-wood contaminants.
An option to apply the import RIN reduction provisions to
imported renewable fuel and renewable fuel produced domestically from
foreign feedstock from only a subset of countries to reflect the
reduced economic, energy security, and environmental benefits of
imported renewable fuel and feedstock from those countries.
Any other modifications to the RFS program designed to
unleash the production of American energy.
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 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.\9\ Consultation is not required
where the action would have no effect on such species or habitat.
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\9\ 50 CFR 402.14.
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Consistent with ESA section 7(a)(2) and relevant implementing
regulations at 50 CFR part 402, EPA engaged in informal consultation
with the Services and completed a Biological Evaluation (BE) for the
Set 1 Rule.\10\ Supported by the analysis in the Set 1 Rule BE, EPA
determined that the Set 1 Rule was ``not likely to adversely affect''
listed species and their habitats. NMFS concurred with EPA's
determination on July 27, 2023, and FWS concurred with EPA's
determination on August 3, 2023, thereby concluding the agencies'
consultation obligations.\11\ For the rulemaking finalizing this
proposed action, EPA intends to develop a biological evaluation to
inform our assessment of the effects of this action, and in turn our
ESA consultation obligations.
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\10\ EPA, ``Biological Evaluation of the Renewable Fuel Standard
Set Rule and Addendum,'' EPA-420-R-23-029, May 2023 (the ``Set 1
Rule BE'').
\11\ The outcome of the Set 1 Rule ESA consultation is the
subject of pending litigation; oral argument was held on November 1,
2024, and we are awaiting the court's decision. See CBD v. EPA, et
al., Case No. 23-1177 (D.C. Cir.).
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II. Statutory Authority
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 the total renewable fuel,
advanced biofuel, and cellulosic biofuel through 2022, but allowed EPA
to waive the statutory volumes in certain circumstances. For years
after 2022, Congress provided EPA with the directive and authority to
establish the applicable renewable fuel volume requirements, as
described in this section.\12\ This section discusses EPA's 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.
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\12\ 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 Administrator shall, in
coordination with USDA and DOE,\13\ 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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\13\ In furtherance of this requirement, we will continue
periodic discussions with USDA and DOE on 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 biomass-based diesel);
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
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 provided EPA flexibility by enumerating factors that the
Administrator must consider without mandating any particular forms of
analysis or specifying how the EPA Administrator must weigh the various
factors against one another. Thus, as the CAA ``does not state what
weight should be accorded to the relevant factors,'' it ``give[s] EPA
considerable discretion to weigh and balance the various factors
required by statute.'' \14\ These factors were analyzed in the context
of the 2020-2022 RFS Rule that modified volumes under CAA section
211(o)(7)(F),\15\ which requires EPA to comply with the processes,
criteria, and standards in CAA section 211(o)(2)(B)(ii). EPA's
assessment of the factors in that rule was recently upheld by the D.C.
Circuit in Sinclair v. EPA.\16\ EPA has also considered these factors
in establishing the applicable volumes for 2023-2025 under CAA section
211(o)(2)(B)(ii) in the Set 1 Rule. Consistent with our past practice
in evaluating the factors,\17\ we have again determined that a holistic
balancing of the factors is appropriate.\18\
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\14\ Nat'l Wildlife Fed'n v. EPA, 286 F.3d 554, 570 (D.C. Cir.
2002) (analyzing factors within the Clean Water Act); accord
Riverkeeper, Inc. v. U.S. EPA, 358 F.3d 174, 195 (2d Cir. 2004)
(same); BP Exploration & Oil, Inc. v. EPA, 66 F.3d 784, 802 (6th
Cir. 1995) (same); see also Brown v. Watt, 668 F.3d 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 Secretary with discretion to weigh
the elements. . . .'') (addressing factors articulated in the Out
Continental Shelf Lands Act).
\15\ 87 FR 39600 (July 1, 2022).
\16\ 101 F.4th 871, 888-889 (D.C. Cir. 2024).
\17\ 87 FR 39600, 39607-08 (July 1, 2022).
\18\ 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
Administrator also has authority to consider ``other'' factors,
including both the implied
[[Page 25790]]
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, we have 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 (Section V.E).\19\
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\19\ 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 (DRIA Chapter 7).\20\
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\20\ 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.B).\21\
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\21\ 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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Soil quality (DRIA Chapter 4.3).\22\
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\22\ Soil quality is closely tied to water quality and is also
relevant to the impact of renewable fuels on the environment more
generally, such that this analysis also informs our analysis of the
statutory factor ``the impact of the production and use of renewable
fuels on the environment'' in CAA section 211(o)(2)(B)(ii)(I).
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Ecosystem services (DRIA Chapter 4.6).\23\
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\23\ Ecosystem services broadly consist of the many life-
sustaining benefits humans receive from nature, such as clean air
and water, fertile soil for crop production, pollination, and flood
control. Ecosystem services are discussed in DRIA Chapter 4 due to
linkages to potential environmental impacts from this rule.
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A consideration of costs and benefits (Section V.H).\24\
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\24\ The consideration of costs and benefits includes our
quantitative analysis of several statutory factors, including costs
and monetizable impacts on energy security.
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C. Statutory Conditions on Volume Requirements
As indicated above, the CAA affords the EPA Administrator
flexibility to consider and weigh each of the enumerated factors.
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 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 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.\25\ 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 EPA 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 proposing in this action for 2026 and 2027, shown
in Table I.A.1-1, exceed this 27.3 percent minimum, and thus they
satisfy this statutory requirement for each year.
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\25\ 87 FR 39601 (July 1, 2022).
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2. Cellulosic Biofuel
CAA section 211(o)(2)(B)(iv) requires that 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 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 EPA does not anticipate a need to further
lower the requirement through a waiver under CAA section
211(o)(7)(D).\26\ 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),'' EPA
``shall reduce the applicable volume of cellulosic biofuel required
under paragraph (2)(B) to the projected volume available during that
calendar year.'' Therefore, we are proposing 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 V, we are proposing cellulosic volumes for
2026 and 2027 at the projected volume available in each year,
respectively, consistent with our past actions in determining the
cellulosic biofuel volume.\27\ These projections, discussed further in
Sections III.B.1 and V.A, 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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\26\ 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).
\27\ See, e.g., 2020-2022 RFS Rule (87 FR 39600; July 1, 2022).
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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
proposing to partially waive the 2025 cellulosic biofuel volume
requirement in this action as discussed in Section VII. Nevertheless,
we have considered the cellulosic biofuel available in those years and
adjusted our methodology as discussed in Sections III.B.1 and V.A and
DRIA Chapter 7.1 to account for 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 EPA sets, which could negatively impact
investment in renewable fuel production in future years. In this
action, we propose changes to the methodology used to project
cellulosic biofuel volumes to avoid the need for waivers of the RFS
standards in the future.
[[Page 25791]]
3. Biomass-Based Diesel
EPA has established the BBD volume requirement under CAA section
211(o)(2)(B)(ii) for the years since 2013 because the statute only
provides 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 EPA must consider. In the years since 2012, EPA
has steadily increased the BBD volume requirement beyond 1.0 billion
gallons to 3.35 billion gallons in 2025. In this action, we are
proposing BBD volume requirements for 2026 and 2027 of 7.12 and 7.50
billion RINs respectively.\28\ 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 gallons and
reflect our proposal that imported renewable fuels and renewable fuels
produced from foreign feedstocks would generate fewer RINs.\29\
Nevertheless, the proposed BBD volume requirements guarantee that at
least 4.45 and 4.69 billion gallons of BBD would be used in 2026 and
2027 respectively,\30\ far greater than 1.0-billion-gallon minimum
requirement.
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\28\ As noted in Section I.A.1 and explained further in Section
X.C, we are proposing to specify the BBD volume requirement in RINs,
rather than gallons, as was the case in establishing the 2025 BBD
volume requirement of 3.35 billion physical gallons.
\29\ See Section VIII for more detail on the proposed RIN
reduction for renewable fuels and renewable fuels produced from
foreign feedstocks.
\30\ These volumes represent the lowest possible volume of BBD
that could be used to meet the proposed BBD volume requirements for
2026 and 2027. These numbers are calculated by dividing the proposed
BBD RIN requirements by 1.6, which is the number of RINs generated
for renewable diesel if produced by a domestic renewable fuel
producer using domestic feedstocks.
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D. Authority To Establish Volume Requirements and Percentage Standards
for Multiple Years
In this action, EPA is proposing 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 proposed action. The
statutory deadline for the 2026 applicable volume requirements passed
on October 31, 2024. The statutory deadline for promulgating the 2027
applicable volume requirements is October 31, 2025. We are proposing
this action with the intent to meet that statutory deadline for the
2027 applicable volume requirements and to fulfill our outstanding
obligation to establish the 2026 applicable volume requirements ahead
of the 2026 compliance year.
As to the percentage standards with which obligated parties must
comply, CAA section 211(o)(A)(i) and (iii) requires 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 EPA after 2022--are met. As
in the Set 1 Rule, EPA is also proposing to establish corresponding
percentage standards in this action.\31\
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\31\ 88 FR 44468, 44519-21 (July 14, 2023).
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In summary, we are proposing applicable volume requirements and
associated percentage standards for 2026 and 2027, as further described
in Sections V and VI.
E. Considerations Related to the Timing of This Action
In this action, we are proposing applicable volume requirements for
the 2026 compliance year after the statutory deadline to establish such
requirements.\32\ That deadline was October 31, 2024. EPA has in the
past also missed statutory deadlines 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 proposing to establish the 2026 standards in this action. In its
review of EPA's 2015 action establishing BBD volume requirements for
2014-2017,\33\ the D.C. Circuit found that EPA retains authority beyond
the statutory deadlines to promulgate volumes and annual standards,
even those that apply retroactively, so long as EPA exercises this
authority reasonably.\34\ EPA 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 EPA exercises this authority after the statutory
deadline, 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.\35\ 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.\36\ The court found that EPA properly balanced the
relevant considerations and had provided sufficient notice to parties
in establishing the applicable volume requirements for 2014-2017.\37\
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\32\ See CAA section 211(o)(2)(B)(ii), requiring EPA promulgate
applicable volume requirements no later than 14 months prior to the
first year in which they will apply.
\33\ 80 FR 77420, 77427-28, 77430-31 (December 14, 2015).
\34\ Americans for Clean Energy v. EPA, 864 F.3d 691 (D.C. Cir.
2017) (ACE) (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 Sinclair v. EPA, 101 F.4th 871 (D.C. Cir. 2024).
\35\ NPRA v. EPA, 630 F.3d 145, 164-65.
\36\ ACE, 864 F.3d at 721-22.
\37\ ACE, 864 F.3d at 721-23.
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In this action, we are proposing to exercise our authority to set
the applicable renewable fuel volume requirements for 2026 after the
statutory deadline to promulgate such volume requirements under CAA
section 211(o)(2)(B)(ii). We intend to finalize the 2026 standards
prior to the beginning of the 2026 compliance year (i.e., before
January 1, 2026) and do not expect those standards to apply
retroactively. In this proposal, we are providing obligated parties
notice of the proposed 2026 standards. Under the RFS regulations,
demonstrating compliance with the 2025 standards will not be required
until the next quarterly reporting deadline after the 2026 standards
are effective.\38\ Additionally, obligated parties will continue to
have the ability to use existing compliance flexibilities to comply
with the 2026 RFS standards, such as the use of carryover RINs and
carrying forward a deficit from one compliance year into the next.
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\38\ 40 CFR 80.1451(f)(1)(i)(A).
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F. Impact on Other Waiver Authorities
While we are proposing 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 waiver authorities
should circumstances so warrant.\39\ For example, the general waiver
authority under CAA section 211(o)(7)(A) provides that EPA may waive
the volume requirements in ``paragraph (2),'' which provides both the
statutory
[[Page 25792]]
applicable volume tables and 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, EPA has
the authority to modify the applicable volumes for 2023 and beyond in
future actions through the use of our waiver authorities.
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\39\ 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 EPA set the cellulosic biofuel volume requirements for
2023 and beyond based on the assumption that EPA will not need to waive
those volume requirements under the cellulosic waiver authority.
Because we are, in this action, proposing the applicable volume
requirements for 2026 and 2027 under the set authority, 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 EPA could use
both the set authority and the cellulosic waiver authority to establish
volumes at the same time in this action.
Proposing 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 EPA
reduces cellulosic volumes under the cellulosic waiver authority, EPA
is also required to make CWCs available under CAA section
211(o)(7)(D)(ii). In this rule we are proposing 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 EPA uses 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 proposing to establish the cellulosic
biofuel volume requirement based on the quantity of cellulosic biofuel
we project will used as transportation fuel in the U.S. each year.
G. Severability
We intend 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 percentage standards for the
other year. Each year's volume requirements and percentage standards
are supported by analyses for that year.
We intend for the revised cellulosic biofuel volume requirement and
percentage standard for 2025 in Section VII to be severable from the
volume requirements and percentage standards for the other years. The
cellulosic biofuel volume requirement and percentage standard for 2025
is supported by the analysis for that year.
We intend for the import RIN reduction in Section VIII to be
severable from the volume requirements and percentage standards for
2026 and 2027. While the regulatory amendments in Section VIII propose
to modify the number of RINs generated for imported renewable fuel and
renewable fuel produced from foreign feedstocks, our basis for
proposing the amendments in Section VIII is independent from the volume
requirements themselves. Additionally, we do not anticipate that
invalidation of the import RIN reduction would jeopardize compliance
with the volume requirements and percentage standards.
We also intend for the removal of renewable electricity from the
RFS program in Section IX and the regulatory amendments in Section X 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 EPA's analysis for the volume requirements
and percentage standards for any specific year. Further, each of the
regulatory amendments in Sections IX and X 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) is 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 proposed 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.
III. Alternative Volume Scenarios for Analysis and Baselines
In establishing volumes for 2026 and 2027, the statute requires
that EPA review the implementation of the RFS program in prior years
and analyze a specified set of factors (see Section II.B). Many of
those 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, we
have opted to develop alternative volume scenarios to analyze for each
category of renewable fuel. This section describes the factors we
considered when developing the volume scenarios for analysis. The
analyses of the impacts of the volume scenarios are summarized in
Section IV, and the volumes we are proposing based on these analyses
and a review of the implementation of the RFS program to date are
described in Section V. Note that neither of the volume scenarios we
developed for analytical purposes include the impacts of the proposed
import RIN reduction provisions described in Section VIII.
To develop the alternative volume scenarios for analysis, we first
assessed two fundamental factors: (1) The potential supply of these
fuels from both imports and domestic production; and (2) The ability
for these fuels to be used as qualifying transportation fuel in the
United States. Throughout this preamble, we use the term ``supply'' of
renewable fuel to refer to the quantity of qualifying renewable fuel
that can be used as transportation fuel, heating oil, or jet fuel in
the U.S. Unless otherwise noted, all historical data on the supply of
renewable fuel is based on data from the EPA Moderated Transaction
System (EMTS). The projected domestic production and importation of
renewable fuel and the use of renewable fuel as transportation fuel
closely align with two of the explicit statutory criteria: expected
annual rate of future commercial production of renewable fuel and
sufficiency of infrastructure to deliver and use renewable fuels. For
cellulosic biofuel and conventional renewable fuel, the volume
scenarios we chose to analyze are equal to the projected volumes of
these fuels we project will be used as qualifying transportation fuel
in 2026 and 2027. Our projections of the use of these fuels
[[Page 25793]]
assumes current ongoing 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 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. Further, unlike
cellulosic biofuel and conventional renewable fuel, which are primarily
produced from a single feedstock (biogas and corn starch,
respectively), non-cellulosic advanced biofuel can be produced from a
variety of different feedstocks, and the projected impacts of the
production of these fuels can vary depending on the feedstock used to
produce the fuel. Considering these complexities, we have developed two
different volume scenarios of non-cellulosic advanced biofuel for
analysis rather that attempt to identify a single volume scenario for
the projected supply of these fuels. These assessments are described in
greater detail in Sections III.B and C and DRIA Chapter 6.
We acknowledge that we are adopting a slightly different approach
to developing the volume scenarios for analysis in this action than we
did in the Set 1 Rule, in which EPA first identified ``candidate
volumes'' to analyze for each category of renewable fuel. These
candidate volumes were based primarily on a consideration of supply-
related factors, with a consideration of other relevant factors as
noted in the Set 1 Rule. The approach taken in this action, in which
multiple volume scenarios are analyzed, is designed to provide
additional information about the potential impacts of a broader range
of renewable fuel volume requirements.\40\ The analysis of multiple
scenarios allows EPA to consider different volumes scenarios for non-
cellulosic advanced biofuel, where the impacts may be more heterogenous
(e.g., the impacts are not expected to be consistent on a per-gallon
basis) across a range of potential qualifying fuels and volume
requirements.
---------------------------------------------------------------------------
\40\ We note that the two scenarios analyzed for this action
differ only in the BBD volumes. Considering different BBD volumes is
of the most interest due to the high degree of uncertainty in the
potential supply of this fuel through 2027 and the differences in
the projected impacts between different types of BBD.
---------------------------------------------------------------------------
The volume scenarios we analyzed for this action, as well as the
data that informed these volume scenarios, can be found in Sections
III.B and C. Sections III.D and E describe the baselines we considered
as points of reference for the analysis of the other statutory factors
(i.e., the ``No RFS'' baseline and the 2025 baseline) and the volume
changes calculated in comparison to that baseline, respectively.
A. Scope of Analysis
In Section II.D we discuss our statutory authority to establish RFS
volume requirements and percentage standards for multiple years in a
single action. As discussed in that section, we are proposing to
establish volume requirements and percentage standards for two years:
2026 and 2027. When developing the scenarios described in this section,
however, EPA had not yet determined either the number of years for
which to establish volumes in this action or the exact levels of the
proposed volumes. To preserve the opportunity to consider proposing an
action that would establish volumes for a greater number of years, we
developed scenarios for analysis through 2030. We also assessed a range
of potential fuel volumes to provide stakeholders with a more
comprehensive sense for the potential impacts of different volume
levels. The volume scenarios discussed in this section, as well as the
results of our analysis of these scenarios discussed in Section IV,
therefore consider a range of renewable fuel volumes through 2030. More
information on the projected impacts of the renewable fuel volume
requirements we are proposing for 2026 and 2027 can be found in Section
V and the DRIA.
B. Production and Importation of 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 2024. This growth has primarily been driven
by biogas-derived CNG/LNG, although small volumes of liquid cellulosic
biofuels, particularly ethanol produced from corn kernel fiber (CKF),
have also played a contributing role. In this section, we discuss our
analysis for projecting the production of qualifying cellulosic biofuel
for 2026-2030, along with key uncertainties associated with these
estimates. Additional details on our volume projections for cellulosic
biofuel can be found in DRIA Chapter 7.1.
[[Page 25794]]
[GRAPHIC] [TIFF OMITTED] TP17JN25.001
a. CNG/LNG Derived From Biogas
Biogas-derived CNG/LNG from qualifying sources must first be
collected and upgraded for vehicle use. The upgraded 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 is used to produce renewable fuel is defined as
``renewable natural gas'' (RNG).\41\ 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
``biogas-derived CNG/LNG'' to refer to both treated biogas and RNG when
used as a transportation fuel in CNG/LNG vehicles.
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\41\ 40 CFR 80.2.
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To project future volumes of biogas-derived CNG/LNG, we analyzed
two limiting factors: the estimated volume of RNG that could be
produced or captured and the estimated amount of biogas-derived CNG/LNG
that could be consumed as a transportation fuel. Our analysis indicates
that consumption (i.e., use as a transportation fuel), rather than
production, is likely to be the primary constraint on determining
volumes during 2026-2030.
To estimate consumption, we developed a projection of total CNG/LNG
transportation use based on vehicle sector data, including fuel
consumption rates, vehicle miles traveled, and fuel efficiency. Because
biogas-derived CNG/LNG can generate RINs only when used as a
transportation fuel, total CNG/LNG consumption--whether fossil- or
biogas-derived--represents the upper volume limit for biogas-derived
CNG/LNG RIN generation. However, full replacement of total CNG/LNG
usage with biogas-derived fuel is unlikely due to infrastructure
limitations, costs, and other challenges. To account for this, we
applied an efficiency factor to estimate the portion of total CNG/LNG
consumption that could realistically be met with biogas-derived fuel
and, in turn, the number of cellulosic RINs that could be generated.
Based on data from California's Low Carbon Fuel Standard (LCFS)
program, we assume that even in a fully saturated market,\42\ only 97
percent of total CNG/LNG transportation demand would be met with
biogas-derived CNG/LNG. As a result, we applied a 97 percent adjustment
to our total CNG/LNG consumption estimate to calculate the potential
total biogas-derived CNG/LNG volume. The results of this analysis are
shown in Table III.B.1.a-1 and are further described in DRIA Chapter
7.1.4.1.
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\42\ We use the term ``saturated market'' to describe a market
that consumes the maximum feasible amount of biogas-derived CNG/LNG
relative to its CNG/LNG vehicle population.
Table III.B.1.a-1--Estimated Consumption of Total CNG/LNG and the Estimated Quantity of Biogas-Derived CNG/LNG
[Million ethanol-equivalent gallons]
----------------------------------------------------------------------------------------------------------------
Total CNG/LNG Total biogas-derived
Year consumption CNG/LNG consumption
----------------------------------------------------------------------------------------------------------------
2026.......................................................... 1,210 1,174
2027.......................................................... 1,277 1,239
2028.......................................................... 1,349 1,309
2029.......................................................... 1,426 1,384
2030.......................................................... 1,509 1,464
----------------------------------------------------------------------------------------------------------------
[[Page 25795]]
Initial evidence of this shift towards a consumption-limited
baseline is already apparent. In 2023, RNG volumes were insufficient to
meet the cellulosic biofuel volume requirement established in the Set 1
Rule. This shortfall resulted in a 0.09 billion cellulosic RIN deficit
carried forward from 2023 into 2024. For 2024, RNG production--and
hence cellulosic RIN generation--again fell short of the required
volume. This led EPA to propose a partial waiver of the 2024 cellulosic
biofuel volume requirement.\43\ Similarly, as described in Section VII,
EPA currently projects a shortfall in cellulosic biofuel production for
2025 and is proposing to again partially waive the cellulosic biofuel
volume requirement for 2025. Thus, while EPA is still projecting
continued growth in cellulosic biofuel production, growth in cellulosic
RIN generation is likely to face significant constraints for the
foreseeable future, limited by the ability of fuel consumers to use RNG
as a qualifying transportation fuel.
---------------------------------------------------------------------------
\43\ 89 FR 100442 (December 12, 2024).
---------------------------------------------------------------------------
As a means of cross-checking this expected limitation on cellulosic
RIN generation, we also projected future RNG production. To estimate
this, we used an industry-wide projection methodology that has been
employed in the RFS standard-setting rules since 2018. This methodology
applies an industry-wide year-over-year growth rate to the current
biogas production rate. Specifically, we used RIN generation data from
the most recent 24 months and multiplied the observed growth rate
during that period by the most recent full calendar year of data
available. This growth rate was then repeatedly applied to each
progressive year to project future production. This approach was
previously used in the 2018,\44\ 2019,\45\ 2020-2022,\46\ and Set 1
(2023-2025) Rules. However, unlike the 2018-2022 Rules, the Set 1 Rule
relied on data from 2015-2022 rather than the previous 24 months. This
adjustment was made to account for the expected impact of the COVID-19
pandemic, which was believed at the time to have negatively affected
the market in 2020 and 2021. At the time of the Set 1 Rule analysis,
pre-pandemic growth rates were considered a more accurate reflection of
future biogas production potential, a view supported by stakeholders.
However, with the benefit of post-pandemic data, we have returned to
our prior methodology, basing projections on the most recent 24 months
of data instead of the data from 2015-2022, as described in DRIA
Chapter 7.1.4.2. Performing this analysis and comparing RNG production
to the consumption of RNG-derived CNG/LNG highlights a key point: for
all years from 2026-2030, projected RNG production is expected to
exceed the projected consumption of RNG-derived CNG/LNG, providing
further evidence that future cellulosic RIN generation is limited by
the ability of fuel consumers to use RNG as a qualifying transportation
fuel.
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\44\ 82 FR 58486 (December 12, 2017).
\45\ 83 FR 63704 (December 11, 2018).
\46\ 87 FR 39600 (July 1, 2022).
---------------------------------------------------------------------------
While RNG production is not expected to be a limiting factor in
determining volumes, the future production of RNG will ultimately
depend on market demand. Because of this, there is significant
uncertainty overall for the production of RNG. One notable source of
uncertainty is the potential for significant competing demands for RNG,
such as to produce RNG-based ammonia (e.g., for use as fertilizer) and
to produce RNG-based hydrogen for use in various process energy
applications. While the demand for these products over the 2026-2030
period is highly uncertain, substantial growth in these competing
demands for RNG have the potential to further limit the available
supply of RNG as a qualifying transportation fuel.
From our analysis of both RNG consumption and production, we
believe that cellulosic RIN generation from biogas-derived CNG/LNG
during 2026-2030 will be constrained by the total usage of CNG/LNG as
transportation fuel (i.e., the total amount of CNG/LNG that can be used
in the fleet of CNG- and LNG-powered vehicles). Accordingly, the
volumes presented in Table III.B.1.a-2 were used as the volume scenario
for biogas-derived CNG/LNG during this period. That said, we recognize
that there is considerable uncertainty in these volumes and that the
methodology used to determine these volumes are different than what we
have done in prior rules. Therefore, we request comment on our
projections for cellulosic biofuel production for 2026-2030,
specifically regarding our assessment of future CNG/LNG consumption. We
also request any additional data or information that could further
inform our projections for cellulosic biofuel production during this
period.
Table III.B.1.a-2--Estimated Volume of Biogas-Derived CNG/LNG
[Million ethanol-equivalent gallons]
------------------------------------------------------------------------
Year Volume
------------------------------------------------------------------------
2026....................................................... 1,174
2027....................................................... 1,239
2028....................................................... 1,309
2029....................................................... 1,384
2030....................................................... 1,464
------------------------------------------------------------------------
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 2030. One notable exception is the production of ethanol
from CKF, for which several companies have developed processes. Many of
these processes involve co-processing of both the starch and cellulosic
components of the corn kernel. However, to be eligible for generating
cellulosic RINs, facilities must accurately determine the amount of
ethanol produced specifically from the cellulosic portion 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,
EPA issued updated guidance on analytical methods that could be used to
quantify the amount of ethanol produced when co-processing CKF and corn
starch.\47\
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\47\ 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.
---------------------------------------------------------------------------
EPA has 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, EPA believes 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.
Additionally, while technology providers have indicated that using
analytical methods consistent with EPA
[[Page 25796]]
guidance can demonstrate that approximately 1.5 percent of ethanol
produced at existing corn ethanol facilities comes from cellulosic
biomass, data submitted to EPA by renewable fuel producers generating
cellulosic RINs for CKF ethanol shows that the current industry-wide
average among registered facilities is closer to 1 percent. Therefore,
for the purposes of this analysis, we are using a 1 percent conversion
rate.
The projected production of cellulosic ethanol from CKF, as shown
in Table III.B.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.\48\ We request comment on these
projected volumes, including our projections of the percentage of
ethanol producers that will generate cellulosic RINs for CKF ethanol
through 2027 and the proportion of ethanol from cellulose vs. starch at
these facilities.
---------------------------------------------------------------------------
\48\ A detailed discussion of the methodology used to project
cellulosic ethanol production from CKF can be found in DRIA Chapter
7.1.5.
Table III.B.1.b-1--Projected Production of Ethanol From CKF
[Million ethanol-equivalent gallons]
------------------------------------------------------------------------
Year Volume
------------------------------------------------------------------------
2026....................................................... 124
2027....................................................... 123
2028....................................................... 122
2029....................................................... 120
2030....................................................... 119
------------------------------------------------------------------------
c. Other Cellulosic Biofuels
We expect that commercial scale production of cellulosic biofuel in
the U.S. beyond CNG/LNG derived from biogas and ethanol produced from
CKF will be very limited in 2026-2030. There are several cellulosic
biofuel production facilities in various stages of development,
construction, and commissioning that may be capable of producing
commercial scale volumes of cellulosic biofuel by 2030. These
facilities primarily focus on producing 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. Since no parties have achieved consistent
production of liquid cellulosic biofuel in the U.S. or consistently
exported liquid cellulosic biofuel to the U.S., production and import
of liquid cellulosic biofuel in 2026-2030 is highly uncertain and
likely to be relatively small. For the volume scenarios we are
analyzing, we have projected no production of these fuels in 2026-2030.
2. Biomass-Based Diesel
CAA section 211(o)(1)(D) defines biomass-based diesel as renewable
fuel that is biodiesel 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.
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 biodiesel or renewable
diesel. Both of these fuels are replacements for petroleum diesel and
are produced from the same lipid-based feedstocks, a diverse category
that includes animal fats, used cooking oil, 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. From 2010-2018, the vast majority
of BBD supplied to the U.S. was biodiesel. Production and imports of
renewable diesel emerged in the U.S. in the early 2010s. Market share
for renewable diesel began a steady upward trend in 2019, and U.S.
domestic supply of these fuels has increased significantly over the
past several years. The supply of biodiesel has been relatively stable
since 2016 amidst the expansion of renewable diesel supply.
In 2023, the supply of renewable diesel exceeded the supply of
biodiesel for the first time (see Figure III.B.2-1). Unlike biodiesel,
which is often produced at relatively small facilities, renewable
diesel is generally produced at large facilities. While some renewable
fuel producers have built new production facilities, much of the
renewable diesel produced in the U.S. uses petroleum refining
infrastructure that has been converted to produce renewable diesel.
Because renewable diesel is more chemically similar to petroleum, it is
generally not subject to the same blending limits as biodiesel. This
has allowed very large volumes of renewable diesel to be supplied to
California and other states with incentives for biofuel use in addition
to the incentives provided by the RFS program. In future years we
expect to continue to see large increases in the supply of renewable
diesel due to the advantages in the economy of scale and the ability to
access markets with higher incentives, and a relatively steady supply
of biodiesel from established facilities with favorable local markets.
BILLING CODE 6560-50-P
[[Page 25797]]
[GRAPHIC] [TIFF OMITTED] TP17JN25.002
BILLING CODE 6560-50-C
There are also small volumes of renewable jet fuel and heating oil
that qualify as BBD.\49\ 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 reduction in GHGs in comparison
to petroleum-based fuels. The technology and feedstocks that can
currently be used to produce renewable jet fuel are often the same as
those used to produce renewable diesel. For example, the same process
that produces renewable diesel from lipids generally produces
hydrocarbons in the distillation range of jet fuel that can be
separated and sold as renewable jet fuel instead of being sold as
renewable diesel. While relatively little renewable jet fuel has been
produced since 2010--20 million gallons or less per year through 2023,
increasing to approximately 110 million gallons in 2024--opportunities
for increasing this category of advanced biofuel exist.
---------------------------------------------------------------------------
\49\ According to EMTS data renewable jet fuel supply ranged
from 0-20 million gallons per year from 2014-2023 and increased to
approximately 110 million gallons in 2024. Renewable jet fuel is
eligible to generate RINs per 40 CFR 80.1426(a)(1)(iv), provided all
other regulatory requirements are met.
---------------------------------------------------------------------------
A tax credit for renewable jet fuel for tax years 2023 and 2024,
often referred to as the ``sustainable aviation fuel credit'' or ``40B
credit,'' may have resulted in increasing volumes of renewable jet fuel
produced from existing renewable diesel production facilities. Another
low carbon transportation fuel tax credit, the ``clean fuel production
credit'' or ``45Z credit,'' is available for tax years 2025-2027, and
provides up to $1.75 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.\50\
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\50\ The equivalence values for renewable diesel and jet fuel
are similar. As discussed in Section X.A, we are proposing to revise
the renewable diesel equivalence value to be 1.6 RINs per gallon,
while also proposing to establish the renewable jet fuel equivalence
value to be 1.5 RINs per gallon.
---------------------------------------------------------------------------
In this rule we have not separately projected growth in renewable
jet fuel production, but we recognize that some of the projected growth
in renewable diesel production may instead be renewable jet fuel from
the same production facilities. Other renewable jet fuel production
technologies and production facilities (discussed briefly in Section
III.B.2.b) also being developed could enable the future production of
renewable jet fuel from new facilities and feedstocks that are not
expected to impact renewable diesel production.
The remainder of this section provides historical data on biodiesel
and renewable diesel production and production capacity, briefly
discusses potential feedstock limitations for
[[Page 25798]]
biodiesel and renewable diesel production in future years, and
summarizes our assessment of the rate of production and use of
qualifying BBD for 2026-2030, along with some of the uncertainties
associated with those volumes.\51\
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\51\ Further details on these volume projections can be found in
DRIA Chapter 7.2.
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a. Biodiesel
For most of the history of the RFS program, the largest volume of
BBD and advanced biofuel supplied in the program each year have been
from biodiesel. Domestic biodiesel production increased from
approximately 1.3 billion gallons in 2014 to approximately 1.8 billion
gallons in 2018. Since 2018, domestic biodiesel production decreased
slightly, to approximately 1.7 billion gallons in 2024.\52\ The U.S.
has also imported significant volumes of biodiesel in previous years
and 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.\53\ In August 2017, the U.S. announced tariffs
on biodiesel imported from Argentina and Indonesia.\54\ These tariffs
were subsequently confirmed in April 2018 and remain in place.\55\
Biodiesel imports started dropping in 2017 but have increased again in
recent years, reaching approximately 500 million gallons in 2023 and
reduced to 420 million gallons in 2024.\56\ More generally, overall
biodiesel supply in the U.S. has remained between 1.6 and 1.8 billion
gallons since 2016 (see Figure III.B.2-1).
---------------------------------------------------------------------------
\52\ Id.
\53\ 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.
\54\ 82 FR 40748 (Aug. 28, 2017).
\55\ 83 FR 18278 (April 26, 2018).
\56\ 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.
---------------------------------------------------------------------------
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 2024 was approximately 2.00 billion gallons per
year, roughly 0.3 billion gallons more than was utilized.\57\ 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. EIA reports that domestic
biodiesel production capacity was approximately 2.5 billion gallons as
recently as October 2021. This facility capacity data is collected by
EIA in monthly surveys, which suggests that this capacity represents
the production at facilities that are currently producing some volume
of biodiesel and likely does not include facilities that are inactive
or have closed, as these facilities are far less likely to complete a
monthly survey.
---------------------------------------------------------------------------
\57\ EIA, ``U.S. Biodiesel Production Capacity,'' Petroleum &
Other Liquids, April 30, 2025. https://www.eia.gov/dnav/pet/hist/LeafHandler.ashx?n=PET&s=M_EPOORDB_8BDPC_NUS_MMGL&f=M.
---------------------------------------------------------------------------
EPA separately collects facility capacity information through the
RFS program facility registration process. This data includes both
facilities that are currently producing biodiesel and those that are
inactive. EPA's data shows a total domestic biodiesel production
capacity of 2.9 billion gallons per year in April 2025, of which 2.6
billion gallons per year was at biodiesel facilities that generated
RINs in 2024.\58\ These estimates of domestic production capacity
strongly suggest that domestic biodiesel production capacity is
unlikely to limit domestic biodiesel production through 2030.
---------------------------------------------------------------------------
\58\ See ``BBD Registered Facility Capacity,'' available in the
docket for this action.
---------------------------------------------------------------------------
b. Renewable Diesel and Renewable Jet Fuel
Renewable diesel and renewable jet fuel are currently produced
using the same feedstocks and very similar production technologies, 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.\59\
Historically, greater incentives have been available for renewable
diesel production than for renewable jet fuel production, which has
meant that in practice most production facilities chose to maximize
renewable diesel production. In this section we have focused on
renewable diesel production, but we acknowledge that an increasing
portion of this fuel may be used as renewable jet fuel in future years.
---------------------------------------------------------------------------
\59\ Montana Renewables, ``Products.'' https://montanarenewables.com/products.
---------------------------------------------------------------------------
In the near term, we expect that 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'' (or ``ATJ'') process. To date EPA has 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 BBD RINs.\60\ 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 2030 as commercial scale production
of these fuels has been limited and no RINs have yet been generated for
these fuels. 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. Through 2027,
however, we expect that only relatively modest volumes of fuels might
be produced through these emerging technologies. We request comment on
the potential production volume of such renewable jet fuel through 2027
and any technical and economic data that would help inform our
understanding of the potential impacts of the production of renewable
jet fuel through the ATJ process on the statutory factors.
---------------------------------------------------------------------------
\60\ See EPA, ``Letter from EPA to LanzaJet, Inc.,'' January 12,
2023.
---------------------------------------------------------------------------
Renewable diesel has historically been produced and imported in
smaller quantities than biodiesel, as shown in Figure III.B.2-1. In
recent years, however, domestic production of renewable diesel has
increased significantly. Renewable diesel production facilities
generally have higher capital costs and production 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 cost of renewable diesel production can largely be
offset through the benefits of economies of scale, since renewable
diesel facilities tend to be much larger than biodiesel production
facilities.\61\ For example, according to EMTS data, in 2024, there
were 23 renewable diesel facilities that produced an average of 157
million gallons of renewable diesel per facility, compared to 71
biodiesel facilities that
[[Page 25799]]
produced an average of 29 million gallons of biodiesel per
facility.\62\
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\61\ See DRIA Chapter 10 for more detail on our assessment of
the cost to produce biodiesel and renewable diesel.
\62\ See ``Analysis of BBD RIN Generation by Facility Size,''
available in the docket for this action.
---------------------------------------------------------------------------
More importantly, because renewable diesel more closely resembles
petroleum diesel than biodiesel (both renewable diesel and petroleum
diesel are hydrocarbons while biodiesel is a methyl-ester), renewable
diesel can be blended at much higher concentrations with diesel than
biodiesel (it is for this reason that renewable diesel is sometimes
referred to as a ``drop-in'' fuel). 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 federal tax credit.\63\ 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.\64\ The Washington and Oregon programs
modeled from the California LCFS have generally mirrored this incentive
structure, and the emerging New Mexico program may do so as well. 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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\63\ 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.
\64\ 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.
---------------------------------------------------------------------------
Total domestic renewable diesel production capacity has increased
significantly in recent years from approximately 280 million gallons in
2017 \65\ to approximately 4.6 billion gallons at the end of 2024.\66\
Additionally, a number of parties have announced plans to build new
renewable diesel production capacity with the potential to begin
production in future years. 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.
---------------------------------------------------------------------------
\65\ Renewable diesel capacity based on facilities registered in
EMTS.
\66\ EIA, ``U.S. Total Biofuels Operable Production Capacity,''
Petroleum & Other Liquids, April 30, 2025. https://www.eia.gov/dnav/pet/pet_pnp_capbio_dcu_nus_m.htm.
---------------------------------------------------------------------------
EIA currently projects that renewable diesel production capacity
will continue to expand and could reach nearly 6 billion gallons by the
end of 2025.\67\ A recent report published by the National Renewable
Energy Laboratory 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.\68\ 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. In
future years we expect that competition for affordable qualifying
feedstocks may result in renewable diesel and biodiesel facilities
operating below their production capacity. Competition for qualifying
feedstocks could also result in reductions in overall biodiesel
production if larger renewable diesel facilities are able to out-
compete smaller biodiesel producers for feedstock. Further, even if
these facilities operate at levels close to their production capacity,
demand for renewable diesel and renewable jet fuel in other countries
may impact the quantity of these fuels available to U.S. markets.
---------------------------------------------------------------------------
\67\ 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.
\68\ 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.
---------------------------------------------------------------------------
In addition to domestic production of renewable diesel, the U.S.
has also imported renewable diesel, with nearly all of it produced from
fats, oils, and greases (FOG) and imported from Singapore.\69\ In more
recent years, the U.S. has also exported increasing volumes of
renewable diesel. In 2022-2024, renewable diesel exports exceeded
renewable diesel imports based on data collected through EMTS (see
Table III.B.2.b-1). This situation, wherein significant volumes of
renewable diesel are both imported and exported, is likely the result
of a number of factors, including the design of the biodiesel tax
credit (which is available to renewable diesel that is either produced
or used in the U.S. and thus eligible for exported volumes as well),
the varying structures of incentives for renewable diesel (with the
level of incentives varying depending on the feedstocks used to produce
the renewable diesel varying as well as by country), and logistical
considerations (renewable diesel may be imported and exported from
different parts of the country). Starting in 2025, the 45Z credit,
which consolidates and replaces the previous $1 per gallon credit for
blending biodiesel and renewable diesel into diesel fuel under 40A,
also provides a production credit for alternative fuels and sustainable
aviation fuel. Since the new 45Z credit is only available for fuel
produced in the United States, it may result in significantly decreased
renewable fuel imports and may in turn also decrease renewable fuel
exports as domestic producers seek to satisfy demand previously met by
imported renewable fuels.
---------------------------------------------------------------------------
\69\ 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.
Table III.B.2.b-1--Renewable Diesel Imports and Exports
[Million gallons]
----------------------------------------------------------------------------------------------------------------
Renewable diesel Renewable diesel
Year imports exports Net imports
----------------------------------------------------------------------------------------------------------------
2015................................................... 120 21 99
2016................................................... 165 40 125
2017................................................... 191 37 154
[[Page 25800]]
2018................................................... 176 80 96
2019................................................... 267 148 119
2020................................................... 280 223 57
2021................................................... 262 241 121
2022................................................... 311 326 -15
2023................................................... 361 414 -53
2024................................................... 430 581 -151
----------------------------------------------------------------------------------------------------------------
c. Domestic BBD Feedstocks
When considering the potential production and import of biodiesel
and renewable diesel in future years and the likely impacts of
renewable diesel production, the availability of feedstocks is a key
consideration. Currently, biodiesel and renewable diesel in the U.S.
are produced from a number of different feedstocks, including FOG,
distillers corn oil, and virgin vegetable oils such as soybean oil and
canola oil.
[GRAPHIC] [TIFF OMITTED] TP17JN25.003
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.\70\ 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, indicating that the increase in oil production was likely
driven by the increasing demand for biofuel. However, as the production
of renewable diesel has increased in recent years it appears that
demand for soybean oil is growing faster than demand for soybean meal.
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, however, 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).\71\
---------------------------------------------------------------------------
\70\ USDA, ``Oil Crops Yearbook,'' March 2025. https://www.ers.usda.gov/data-products/oil-crops-yearbook.
\71\ Id.
---------------------------------------------------------------------------
Through 2020, most of the renewable diesel produced in the U.S. was
made from FOG and distillers corn oil, with smaller volumes produced
from soybean oil.\72\ While some biodiesel production facilities are
unable to use FOG and distillers corn oil without additional capital
investment, renewable diesel production facilities are generally able
to use them. Additionally, through 2024 the vast majority of renewable
diesel consumed in the U.S. is used in
[[Page 25801]]
California due to the combined value of RFS and LCFS incentives
(together with the blenders' tax credit). Under California's LCFS
program, renewable diesel produced from FOG and distillers corn oil
receive more credits than renewable diesel produced from soybean oil
and canola oil.
---------------------------------------------------------------------------
\72\ In December 2022, EPA approved generally applicable
pathways for renewable diesel produced from canola oil (87 FR 73956;
December 2, 2022). Use of canola oil to produce renewable diesel for
consumption in the U.S. was therefore rare before 2023, but has
gradually become more common in recent years.
---------------------------------------------------------------------------
Available volumes of FOG (including used cooking oil 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. FOG 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. Because the
production of FOG is generally not responsive to increased demand and
most of the available domestic FOG is currently used for biofuel
production or in other industries, we expect the availability of FOG to
increase slowly, consistent with the observed trend in recent years.
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.B.4), 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 renewable diesel production in
future years increases rapidly as suggested by the large production
capacity announcements, 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.
Greater volumes of soybean oil are projected to be produced from
new or expanded soybean crushing facilities through 2030. Several
parties have announced plans to expand existing soybean crushing
capacity or build new soybean crushing facilities. Public announcements
of new and expanded soybean crushing capacity suggest that domestic
soybean crush capacity could increase by approximately 1.5 million
bushels of soybeans per day from 2024 through 2026.\73\ An increase in
the domestic crush capacity of this magnitude would 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.\74\ Similarly, an assessment of potential BBD
feedstocks in future years prepared for the National Oilseed Processors
Association by S&P Global estimated that increases in domestic soybean
oil production could support the production of an additional 1 billion
gallons of BBD from 2023 to 2027.\75\ Most of the publicly announced
expansion in soybean crush capacity is scheduled to occur in the next
few years, through 2027. Recent data suggests that the domestic soybean
crushing industry is capable of continuing to add significant capacity
in future years, but that any investment in domestic soybean crushing
is highly dependent on demand for soybean oil (and soybean meal) from
biofuel producers and other markets.\76\
---------------------------------------------------------------------------
\73\ Futrell, Crystal, ``US Soybean Crush Capacity on the
Rise,'' World-Grain.com, January 5, 2024. https://www.world-grain.com/articles/19463-us-soybean-crush-capacity-on-the-rise.
\74\ This estimate assumes a soybean oil yield of 11 lbs per
bushel of soybeans and 1 gallon of BBD per 7.75 lbs of soybean oil.
\75\ S&P Global, ``Availability of Feedstocks for Biofuel Use--
Key Highlights,'' July 2024.
\76\ See DRIA Chapter 7.2 for a further discussion of this
topic.
---------------------------------------------------------------------------
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.
Alternatively, increased demand for soybeans from new or expanded
crushing facilities could be met through increased soybean production
in the U.S. 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 renewable
diesel. Were this diversion to occur, non-qualifying feedstocks (e.g.,
palm oil 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.
d. Imported BBD Feedstocks
In addition to processing domestic feedstocks such as distillers
corn oil and soybean oil, a number of domestic BBD producers produce
BBD from imported feedstocks. In recent years, and as multiple
stakeholders have noted to EPA, the market has seen a significant
increase in the quantity of imported BBD feedstocks. Imports of
feedstocks that are often considered wastes or by-products of other
industries, such as used cooking oil and tallow, have seen the greatest
increase in recent years. Figure III.B.2.d-1 shows total imports of
common BBD feedstocks through 2024. Figure III.B.2.d-2 shows the total
volumes of domestic BBD produced from domestic feedstocks, domestic BBD
produced from imported feedstocks, and imported BBD.
BILLING CODE 6560-50-P
[[Page 25802]]
[GRAPHIC] [TIFF OMITTED] TP17JN25.004
[GRAPHIC] [TIFF OMITTED] TP17JN25.005
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 25803]]
incentive programs for biofuels in the U.S. relative to other
countries' polices. As noted in Section III.B.2.b, the production
capacity for renewable diesel and renewable jet fuel has increased
rapidly and is expected to continue to 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. While some of this demand has been met by the
increasing production of domestic feedstocks, domestic feedstock
production has not grown as quickly as has the production capacity for
renewable diesel and renewable jet fuel. Renewable diesel and renewable
jet fuel producers have thus turned to imports to source the feedstocks
needed to support increased BBD production.
At the same time domestic demand for these feedstocks has been
increasing, the supply available to import from other countries has
also been increasing. For example, we project that production of canola
oil will increase in future years due to expanding canola crushing
capacity in Canada.\77\ 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.\78\ These regulations are expected to increase
demand for biofuels and biofuel feedstocks in Canada, and therefore
also impact the quantities of canola oil and other feedstocks available
for export to the U.S.
---------------------------------------------------------------------------
\77\ Some of the projected expansion in soybean crushing
capacity discussed in Section III.B.2.c 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.
\78\ 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.
---------------------------------------------------------------------------
The incentives available in foreign countries to encourage the
production and use of BBD are also changing. In response to the
increase in the prices of energy and agricultural commodities caused by
the Russian invasion of Ukraine in February 2022, a number of
countries, including Croatia, Czech Republic, Finland, Latvia, Poland,
and Sweden, temporarily reduced biofuel mandates and/or the penalties
for not fulfilling the mandates.\79\ The reduction in demand from these
countries resulted in an increase in the available feedstock supply to
the U.S.
---------------------------------------------------------------------------
\79\ USDA, ``Biofuel Mandates in the EU by Member State--2024,''
June 27, 2024.
---------------------------------------------------------------------------
At the same time, the European Union (EU) in recent years took
actions to discourage the importation of used cooking oil (UCO) and
biodiesel produced from UCO from China, which had previously been
supplied in significant volumes. On December 20, 2023, the EU announced
an anti-dumping investigation on biodiesel imported from China.\80\
This investigation resulted in provisional duties on biodiesel from
China sold in the EU, which were announced in July 2024.\81\ The anti-
dumping investigation and resulting fiscal duties on biodiesel imported
from China from the EU opened up an opportunity for increased exports
of UCO (the primary feedstock used to produce biodiesel in China
previously exported to the EU) from China to the U.S.
---------------------------------------------------------------------------
\80\ 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.
\81\ 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.
---------------------------------------------------------------------------
Finally, incentive programs for biofuels in the U.S. have
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 wastes or by-
products 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 likely played a role in biofuel
producers seeking to import UCO and tallow from foreign countries
rather than increasing their use of domestic soybean oil to maximize
their generation of credits under these programs.
Changes to the RFS program have also contributed to the observed
increase in feedstock imports. In December 2022, EPA approved generally
applicable pathways for certain fuels, including renewable diesel, that
are produced from qualifying canola oil.\82\ The ability for renewable
diesel producers to generate RINs for renewable diesel produced from
canola oil created a new demand for canola oil in the U.S.
---------------------------------------------------------------------------
\82\ 87 FR 73956 (December 2, 2022).
---------------------------------------------------------------------------
Together, the trends and policy factors described above
collectively contributed to increasing imports of BBD feedstocks since
2021. We discuss the impact of these dynamics, and a proposed response
to them in the RFS program, in Section VIII.
e. Summary
BBD (including biodiesel, renewable diesel, and renewable jet fuel)
has been the fastest growing category of renewable fuel in the RFS
program since 2021, with nearly all of the growth coming from renewable
diesel. While the domestic supply of BBD feedstocks continues to grow,
in recent years imported BBD and BBD produced from imported feedstocks
have accounted for an increasing share of the total supply of BBD. BBD
production capacity currently exceeds actual production and imports of
these fuels by a significant margin, and ongoing investment is expected
to result in significantly higher production capacity in future years,
particularly for renewable diesel and renewable jet fuel. Further,
because of the high blending rates for BBD in general and renewable
diesel in particular, the use of BBD in the U.S. is unlikely to be
constrained by limitations related to the ability to distribute these
fuels or consume them in existing and future diesel engines.
In the absence of constraints related to the production capacity
and the ability for the market to distribute and use BBD, the factors
most likely to have the largest impact on the quantity of BBD required
under the RFS program--in light of our analysis of the statutory
factors--is the availability of affordable qualifying feedstocks,
competition for those feedstocks for other uses, and competition for
them abroad. The
[[Page 25804]]
sources of the feedstocks used to produce BBD also indirectly impact
other factors, as the environmental and economic impacts of supplying
additional volumes of BBD to the U.S. differ depending on the
feedstocks used to produce the BBD and the likely alternative use of
those feedstocks. For example, the projected economic and environmental
impacts of increasing BBD production vary depending on whether the
feedstock used to produce the BBD was 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 countries.
In developing the volume scenarios for analysis in this action, we
have therefore not attempted to identify the absolute maximum quantity
of BBD that could be produced utilizing all potentially available
production capacity and used in the U.S. Instead, we have developed two
volume scenarios that reflect different growth rates for the quantity
of BBD used in the U.S. based on our projections of the potential
growth in available feedstocks. Both scenarios start with an updated
projection of the supply of BBD to the U.S. which reflects the expected
market conditions for 2025 based on the most recent available data at
the time these scenarios were developed.\83\ The low growth scenario
increases the supply of BBD by 500 million RINs each year, a quantity
approximately equal to our projection of the potential for growth in
waste and byproduct feedstocks such as UCO and tallow, primarily from
foreign sources. The high growth scenario increases the supply of BBD
by 1 billion RINs each year, a quantity approximately equal to our
projection of the potential growth for waste and byproduct feedstocks
(primarily imported) and potential growth in virgin vegetable oil
production that could be available to biofuel producers from the U.S.
and Canada. These two scenarios are summarized in Table III.B.2.e-1 (in
billion RINs) and III.B.e-2 (in billion gallons). More detail on the
development of these scenarios can be found in DRIA Chapters 3 and 6.
---------------------------------------------------------------------------
\83\ Note that the quantity of BBD expected to be supplied in
2025 based on the available data (7.91 billion RINs) is
significantly higher than the quantity of BBD projected to be used
in 2025 in the Set 1 Rule (6.88 billion RINs). See DRIA Chapter 7.2
for more detail on the projected BBD supply for 2025.
Table III.B.2.e-1--BBD Volume Scenarios
[Billion RINs]
----------------------------------------------------------------------------------------------------------------
Scenario 2025 2026 2027 2028 2029 2030
----------------------------------------------------------------------------------------------------------------
Low Growth........................ 7.91 8.41 8.91 9.41 9.91 10.41
High Growth....................... 7.91 8.91 9.91 10.91 11.91 12.91
----------------------------------------------------------------------------------------------------------------
Table III.B.2.e-2--BBD Volume Scenarios
[Billion gallons]
----------------------------------------------------------------------------------------------------------------
Scenario 2025 2026 2027 2028 2029 2030
----------------------------------------------------------------------------------------------------------------
Low Growth........................ 5.08 5.39 5.70 6.01 6.33 6.64
High Growth....................... 5.08 5.70 6.33 6.95 7.58 8.20
----------------------------------------------------------------------------------------------------------------
3. Other Advanced Biofuel
In addition to BBD, other renewable fuels that qualify as advanced
biofuel have been consumed 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 renewable diesel that does not qualify as BBD.\84\
However, these biofuels have been consumed in much smaller quantities
than biodiesel and renewable diesel in the past or have been highly
variable.
---------------------------------------------------------------------------
\84\ Renewable diesel produced through coprocessing vegetable
oils or animal fats with petroleum cannot be categorized as BBD but
remains advanced biofuel. 40 CFR 80.1426(f)(1).
---------------------------------------------------------------------------
To estimate the volumes of these other advanced biofuels that may
be available in 2026-2030, we used the same general methodology as in
the Set 1 Rule, which EPA originally presented in the Set 1 Rule. We
projected the supply of these other advanced biofuels by including data
on the supply of these fuels from 2023 (the most recent data available
at the time the volume scenarios were defined). This 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.B.3-1. 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.B.3-1 for all years in the volume scenarios for analysis (i.e.,
2026-2030).
Table III.B.3-1--Estimate of Annual Consumption of Other Advanced (D5)
Biofuel
[Million RINs] \a\
------------------------------------------------------------------------
Fuel Volume
------------------------------------------------------------------------
Imported sugarcane ethanol........................... 58
Domestic ethanol..................................... 28
[[Page 25805]]
CNG/LNG.............................................. 6
Heating oil.......................................... 3
Naphtha \b\.......................................... 43
Renewable diesel \c\................................. 111
------------------
Total............................................ 249
------------------------------------------------------------------------
\a\ This table does not include fuels that qualify as cellulosic biofuel
or BBD.
\b\ While renewable naphtha is generally a co-product of renewable
diesel production, the supply of renewable naphtha has not increased
in line with the observed increases in renewable diesel production.
\c\ Includes renewable diesel that is co-processed with petroleum, which
does not qualify as BBD.
4. 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 project volumes of conventional renewable fuel for 2026-2030, we
focused primarily on projecting volumes of corn ethanol consumed via
motor gasoline use across all gasoline blends with varying
concentrations of ethanol (i.e., E10, E15, E85). We also investigated
potential volumes of non-advanced biodiesel and renewable diesel.
a. Corn Ethanol
Ethanol made from corn starch has dominated the renewable fuels
market on a volume basis in the past and is expected to continue to do
so for the years addressed by this rulemaking.\85\ 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.
---------------------------------------------------------------------------
\85\ 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 early 2024, domestic corn ethanol production capacity
exceeded 18 billion gallons.86 87 Actual production of corn
ethanol in the U.S. was approximately 16.2 billion gallons in 2024, up
from approximately 15.6 billion gallons in 2023.\88\
---------------------------------------------------------------------------
\86\ Renewable Fuels Association, ``2024 Ethanol Industry
Outlook,'' February 19, 2024.
\87\ EIA, ``U.S. Fuel Ethanol Plant Production Capacity,''
Petroleum & Other Liquids, August 15, 2024. https://www.eia.gov/petroleum/ethanolcapacity.
\88\ EIA, ``Monthly Energy Review,'' Total Energy, March 2025.
https://www.eia.gov/totalenergy/data/monthly/archive/00352503.pdf.
---------------------------------------------------------------------------
The expected annual rate of future commercial production of corn
ethanol will continue to be driven primarily by gasoline demand in
2026-2030, 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.\89\ 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.
---------------------------------------------------------------------------
\89\ Transportation Energy Institute, ``The Case of E15,''
February 2018.
---------------------------------------------------------------------------
Despite this steady growth, there remains excess of production
capacity of ethanol and corn feedstock in comparison to the ethanol
volumes that we estimate will be consumed domestically during 2026-
2030, given constraints on U.S. ethanol consumption as described in
Section III.B.5. Thus, as was the case with the Set 1 Rule, we do not
expect production capacity to be a limiting factor for meeting the
volume scenarios analyzed in this action.
b. Biodiesel and Renewable Diesel
Other than corn 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. was
imported, with the only exceptions being less than 15 million gallons
per year produced domestically between 2014 and 2024. 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
[[Page 25806]]
to the U.S.). While some sparse generation of D6 RINs \90\ 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 DRIA 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 versus other markets. While there exists
some potential for growth across the period covered by this proposed
rule, we are not projecting any increased volumes of these fuels will
be used in 2026-2030.
---------------------------------------------------------------------------
\90\ The D codes given for each component category are defined
in 40 CFR 80.1425(g). D codes are used to identify the statutory
categories that can be fulfilled with each component category
according to 40 CFR 80.1427(a)(2). D6 RINs satisfy only the
``renewable fuel'' category.
---------------------------------------------------------------------------
5. Ethanol Consumption
Ethanol consumption in the U.S. is dominated by E10, with higher-
level ethanol blends such as E15 and E85 being used in much smaller
quantities. The total volume of ethanol that can be consumed--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 these three ethanol blends and for E0. The
distribution of consumption for these different gasoline blends is best
reflected by measuring the observed poolwide ethanol concentration.
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. 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 2026-2030.
[GRAPHIC] [TIFF OMITTED] TP17JN25.006
For this action, new volume data from USDA's Higher Blends
Infrastructure Incentive Program (HBIIP) \91\ 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.\92\ 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.\93\ 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 six aforementioned States, HBIIP, and industry
partners has enabled an updated and simplified methodology for
producing the ethanol volume projections in this action.
---------------------------------------------------------------------------
\91\ USDA, ``Higher Blends Infrastructure Incentive Program,''
May 2023. https://www.rd.usda.gov/hbiip.
\92\ See DRIA Chapter 7.5.1 for more information on our
projections of ethanol concentration in the gasoline pool.
\93\ 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) \94\ and the California Air
Resources Board (CARB) \95\ for 2021-2023, we produced
[[Page 25807]]
forecasts of expected growth in station counts and throughputs out to
2030 for each gasoline-ethanol blend other than E10. We then used these
forecasts to project the total fuel volume for these gasoline-ethanol
blends (E0, E15, and E85) for 2026-2030 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 projected volumes of E0,
E15, and E85.
---------------------------------------------------------------------------
\94\ AFDC, ``Historical Alternative Fueling Station Counts.''
https://afdc.energy.gov/stations/states.
\95\ CARB, ``Annual E85 Volumes,'' April 11, 2025.
---------------------------------------------------------------------------
Total ethanol consumption is the sum of ethanol blended with
gasoline (E0) to create E10, E15, and E85.\96\ The ethanol portion of
the projected total consumption for each fuel blend (i.e., total
ethanol consumption) is shown in Table III.B.5-1. 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.
---------------------------------------------------------------------------
\96\ See DRIA Chapter 7.5.1 for a more comprehensive discussion
of the methodology employed to produce the total ethanol consumption
projection.
Table III.B.5-1--Projected Ethanol Concentration and Consumption
----------------------------------------------------------------------------------------------------------------
Projected ethanol Projected ethanol consumption
Year concentration (%) (million gallons)
----------------------------------------------------------------------------------------------------------------
2026............................................... 10.54 13,993
2027............................................... 10.58 13,871
2028............................................... 10.60 13,724
2029............................................... 10.67 13,558
2030............................................... 10.71 13,377
----------------------------------------------------------------------------------------------------------------
C. Volume Scenarios for 2026-2030
Based on the analyses described in Section III.B, we developed two
different volume scenarios for 2026-2030 that we then used to analyze
the expected impacts of the statutory factors. This section describes
the volume scenarios, while Section IV summarizes the results of the
analyses we performed. The volumes we are proposing in this action
based on the analysis of the statutory factors are described in Section
V.
Both of the volume scenarios developed for this action represent
growth in the advanced biofuel and total renewable fuel categories
relative to the volume of these fuels we expect to be supplied in 2025.
Further, both scenarios are identical in the quantities of cellulosic
biofuel, advanced biofuel other than BBD, and conventional renewable
fuel we project will be supplied. Where the scenarios differ is in the
quantity of BBD we project will be supplied in each year. Throughout
this action we refer to these two scenarios as the Low Volume Scenario
and the High Volume Scenario (or collectively, ``the Volume
Scenarios''), though we note that even the Low Volume Scenario
represents an annual growth rate of 500 million RINs per year of BBD.
In developing the Volume Scenarios, we have considered the implied
volumes for each component category of renewable fuel (cellulosic
biofuel, non-cellulosic advanced biofuel, and conventional renewable
fuel) in the statutory tables through 2022. While these volumes are not
binding on the volume requirements in future years, they do provide an
indication of statutory intent. We also considered the statutory intent
of the RFS program to increase renewable fuel volumes over time, along
with other factors enumerated in the statute to inform the proposed
volumes.
Given the nested nature of the statutory renewable fuel categories,
we have largely framed our assessment of volumes in terms of the
component categories rather than in terms of the statutory categories
(cellulosic biofuel, advanced biofuel, total renewable fuel). The
statutory categories are those addressed in CAA section
211(o)(2)(B)(i)-(iii), and cellulosic and advanced biofuel are nested
within the overall total renewable fuel category. 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.
1. Cellulosic Biofuel
In determining the cellulosic biofuel volume scenario, 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. While notable on its own, it is 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 volume increases
tapered off in recent years with a final increment in 2022. Thus, the
clear focus of the statute, and CAA section 211(o)(1)(E) in particular,
by 2022 was on growth in cellulosic biofuel volumes, which have the
greatest GHG reduction threshold requirement in the statute.\97\
---------------------------------------------------------------------------
\97\ Cf. CAA section 211(o)(1)(B)(i), (D), (2)(A)(i). See also
definition of ``cellulosic biofuel'' in 40 CFR 80.2.
---------------------------------------------------------------------------
This increasing emphasis in the statute on cellulosic biofuel over
time is likely due to some or all of the following factors:
Expectations that cellulosic biofuel has significant
potential to reduce GHG emissions (cellulosic biofuels are required to
reduce GHG emissions by 60
[[Page 25808]]
percent relative to the gasoline or diesel fuel they displace);
That cellulosic biofuel feedstocks could be produced or
collected with relatively few negative environmental impacts;
That the feedstocks would be comparable or cheaper in cost
relative to other fuel feedstocks, allowing for lower cost biofuels to
be produced than those produced from feedstocks without other primary
uses such as food; and
That the technological breakthroughs needed to convert
cellulosic feedstocks into biofuel were likely imminent.
As discussed in Section II.C, CAA section 211(o)(2)(B)(iv) requires
that EPA determine the cellulosic biofuel volume requirement such that
EPA will not need to waive the volumes under CAA section 211(o)(7)(D).
The cellulosic biofuel volumes are the same for both the Low and
High Volume Scenarios and represent the projected amount of qualifying
biofuel expected to be used as transportation fuel in the U.S. for
2026-2030, accounting for incentives provided by the RFS program and
other state and federal programs. The cellulosic biofuel volume
scenario for 2026-2030 is shown in Table III.C.1-1. Because the
technical, economic, and regulatory challenges related to cellulosic
biofuel production vary significantly between the various types of
cellulosic biofuel, we have shown the volumes for ethanol from corn
kernel fiber and CNG/LNG derived from biogas separately.
Table III.C.1-1--Cellulosic Biofuel Volume Scenario
[Million RINs]
----------------------------------------------------------------------------------------------------------------
2026 2027 2028 2029 2030
----------------------------------------------------------------------------------------------------------------
RNG use as CNG/LNG.............. 1,174 1,239 1,309 1,384 1,464
Ethanol from CKF................ 124 123 122 120 119
-------------------------------------------------------------------------------
Total cellulosic biofuel.... 1,298 1,362 1,431 1,504 1,583
----------------------------------------------------------------------------------------------------------------
2. Non-Cellulosic Advanced Biofuel
Although there are no volume targets in the statute for years after
2022, the statutory volume targets for prior years represent a useful
point of reference in the consideration of volumes that may be
appropriate for 2026-2030. For non-cellulosic advanced biofuel, the
implied statutory requirement in CAA section 211(o)(2)(B) increased in
every year between 2009 and 2019. It then remained at 4.5 billion
gallons for three years before finally rising to 5.0 billion gallons in
2022. In the Set 1 Rule, EPA further increased the implied volume of
non-cellulosic advanced biofuel over the course of three years to a
total of 5.95 billion RINs in 2025. However, the market has
outperformed these standards to date primarily through higher than
anticipated imports of non-cellulosic advanced biofuels and their
feedstocks. In recognition of this, the volumes for non-cellulosic
advanced biofuel in the Volume Scenarios are higher than the non-
cellulosic biofuel volumes in the Set 1 Rule, starting with an updated
projection of supply for 2025.
For 2026-2030, we anticipate that a key factor in the growth in the
production of advanced biodiesel and renewable diesel (the two non-
cellulosic advanced biofuels projected to be available in the greatest
quantities through 2030) will be the availability of feedstocks as
discussed in Section III.B.2. In light of the significant uncertainties
related to the supply of qualifying feedstock in these years, we
developed two scenarios for the potential supply of advanced biodiesel
and renewable diesel: a low growth scenario and a high growth scenario.
These two volume scenarios, when combined with our projection of the
available supply of other advanced biofuels discussed in Section
III.B.3, are the bases for the two non-cellulosic advanced biofuel
volume scenarios that differentiate the Low Volume Scenario from the
High Volume Scenario.
Table III.C.2-1--Total Non-Cellulosic Advanced Biofuel Volume Scenarios
[Billion RINs]
--------------------------------------------------------------------------------------------------------------------------------------------------------
2025 (Set 2025
1) \a\ (Proj.) \b\ 2026 2027 2028 2029 2030
--------------------------------------------------------------------------------------------------------------------------------------------------------
Low Volume Scenario
--------------------------------------------------------------------------------------------------------------------------------------------------------
BBD............................................................... 6.88 7.91 8.41 8.91 9.41 9.91 10.41
Other advanced biofuel............................................ 0.29 0.25 0.25 0.25 0.25 0.25 0.25
-------------------------------------------------------------------------------------
Total con-cellulosic advanced biofuel......................... 7.17 8.16 8.66 9.16 9.66 10.16 10.66
--------------------------------------------------------------------------------------------------------------------------------------------------------
High Volume Scenario
--------------------------------------------------------------------------------------------------------------------------------------------------------
BBD............................................................... 6.88 7.91 8.91 9.91 10.91 11.91 12.91
Other advanced biofuel............................................ 0.29 0.25 0.25 0.25 0.25 0.25 0.25
-------------------------------------------------------------------------------------
Total con-cellulosic advanced biofuel......................... 7.17 8.16 9.16 10.16 11.16 12.16 13.16
--------------------------------------------------------------------------------------------------------------------------------------------------------
\a\ Volumes of BBD and other advanced biofuels projected to be used to meet the RFS volume requirements in the Set 1 Rule
\b\ Volumes of BBD and other advanced biofuels projected to be used in 2025 based on data available through May 2024.
[[Page 25809]]
3. Conventional Renewable Fuel
The conventional renewable fuel volume scenario represents 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 national 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
from 2026-2030 can be estimated from the total ethanol consumption
projections from Table III.B.5-1 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.C.3-1. We do not
currently project that non-ethanol conventional renewable fuels will be
supplied to the U.S. under the RFS program in 2026-2030.
Table III.C.3-1--Ethanol Consumption Volume Scenario
[Million gallons]
----------------------------------------------------------------------------------------------------------------
2026 2027 2028 2029 2030
----------------------------------------------------------------------------------------------------------------
Cellulosic ethanol.............. 126 125 124 122 120
Imported sugarcane ethanol...... 58 58 58 58 58
Domestic advanced ethanol....... 28 28 28 28 28
Conventional ethanol............ 13,781 13,660 13,514 13,350 13,170
-------------------------------------------------------------------------------
Total ethanol consumption... 13,993 13,871 13,724 13,558 13,377
----------------------------------------------------------------------------------------------------------------
4. Summary
Many of the factors we are statutorily obligated to analyze under
CAA section 211(o)(2)(B)(ii) when setting volume standards for the RFS
program are difficult to analyze in the abstract, particularly those
related to economic and environmental impacts. For this reason, we
opted to develop volume scenarios to analyze for each category of
renewable fuel, which are summarized in Tables III.C.4-1 and 2. Note
that neither of these volume scenarios include the impacts of the
proposed import RIN reduction provisions described in Section VIII.
Table III.C.4-1--Low Volume Scenario
[Million RINs]
----------------------------------------------------------------------------------------------------------------
2026 2027 2028 2029 2030
----------------------------------------------------------------------------------------------------------------
Cellulosic biofuel (D3 & D7).... 1,298 1,362 1,431 1,504 1,583
Biomass-based diesel (D4)....... 8,410 8,910 9,410 9,910 10,410
Other advanced biofuel (D5)..... 249 249 249 249 249
Conventional renewable fuel (D6) 13,783 13,662 13,516 13,352 13,172
----------------------------------------------------------------------------------------------------------------
Table III.C.4-2--High Volume Scenario
[Million RINs]
----------------------------------------------------------------------------------------------------------------
2026 2027 2028 2029 2030
----------------------------------------------------------------------------------------------------------------
Cellulosic biofuel (D3 & D7).... 1,298 1,362 1,431 1,504 1,583
Biomass-based diesel (D4)....... 8,910 9,910 10,910 11,910 12,910
Other advanced biofuel (D5)..... 249 249 249 249 249
Conventional renewable fuel (D6) 13,783 13,662 13,516 13,352 13,172
----------------------------------------------------------------------------------------------------------------
To inform the volumes we are proposing for 2026 and 2027, we
analyzed these volume scenarios according to the factors required under
the statute in CAA section 211(o)(2)(B)(ii). A summary of several of
these analyses is described in Section IV and discussed in greater
detail in the DRIA. Details of the individual biofuel types and
feedstocks that make up these volume scenarios are provided in the DRIA
Chapter 3. In Section V, we discuss the proposed volume requirements
based on a consideration of all the factors that we analyzed.
D. Baselines
To estimate the impacts of the Volume Scenarios, we must identify
an appropriate baseline(s). The baseline reflects the use of renewable
fuels absent the proposed action or RFS program (i.e., the alternative
collection of biofuel volumes by feedstock, production process (where
appropriate), biofuel type, and use that would be anticipated to occur
after 2025 in the absence of proposed standards), and acts as the point
of reference for assessing the impacts. To this end, we have developed
a ``No RFS'' scenario that we used as the baseline for analytical
purposes (hereafter the ``No RFS Baseline''), which reflects a world
without the RFS program. Many of the same supply-related factors that
we used to develop the Volume Scenarios were also relevant in
developing the No RFS Baseline.
We also consider a 2025 baseline that in some cases may be more
informative in understanding the impacts of the Volume Scenarios
relative to the status quo. We further discuss alternative baselines to
describe our reasoning for the public and interested stakeholders, and
because we understand there are differing, informative baselines that
could be used in this type of analysis.
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
[[Page 25810]]
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 Volume Scenarios. Such a ``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.'' \98\
---------------------------------------------------------------------------
\98\ Office Management and Budget, ``Circular A-4,'' September
17, 2003.
---------------------------------------------------------------------------
Importantly, a ``No RFS'' baseline would not be equivalent to a
market scenario wherein no renewable fuels were 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 2026-20230 in
the absence of the RFS program. Federal, State, and local tax credits,
incentives, and support payments will 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 2026-2030 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-
2030, 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 2026-2030 compares the
projected renewable fuel cost with the projected cost for the fossil
fuel it displaces, at the point that the renewable fuel is blended with
the fossil fuel, to assess whether the renewable fuel provides an
economic advantage to blenders. The comparison is performed at the
point that the renewable fuel is blended with the fossil fuel 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 cost analysis described
in Section IV.C, but there are several differences. The primary
difference is that the No RFS Baseline economic analysis was conducted
from the fuels industry's perspective, 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
reflects the overall cost impacts on society at large.\99\ 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:
---------------------------------------------------------------------------
\99\ See Section IV.C and DRIA 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.\100\
---------------------------------------------------------------------------
\100\ 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 so obvious to vehicle owners 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 this
bias and they must consider this in their decisions to blend and sell
E85.\101\
---------------------------------------------------------------------------
\101\ See DRIA Chapter 2 for further discussion of this topic.
---------------------------------------------------------------------------
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 cost) 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 credit that
biodiesel and renewable diesel producers were able to claim under
40A.\102\ In the case of higher 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 50
percent due to the HBIIP program.
---------------------------------------------------------------------------
\102\ See DRIA Chapter 1 for a further discussion of the 45Z tax
credit.
---------------------------------------------------------------------------
In addition, there are a number of State programs that create
subsidies for biodiesel and renewable diesel fuel, the largest being
offered by California and Oregon through their LCFS programs.\103\ 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.\104\ To account for the
various State assumptions, it was necessary to model the cost of using
these biofuels on a State-by-State basis.
---------------------------------------------------------------------------
\103\ 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.
\104\ In light of the fluid situation with respect to a 1-psi
RVP waiver for E15 or actions to remove the 1-psi wavier for E10 in
eight 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
[[Page 25811]]
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 shutdown. 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 have in the absence of the RFS program, we made two key
assumptions. First, the economics for biodiesel and renewable diesel
were modeled starting in 2009 and the trend in its 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 economic analysis for cellulosic biofuels,
including cellulosic ethanol, corn kernel fiber ethanol, and biogas.
Since the volumes of these biofuels were much smaller, a more
generalized approach was used in lieu of the detailed state-by-state
analysis conducted for corn ethanol, biodiesel, and renewable diesel
fuel.
The No RFS Baseline for 2026-2030 is summarized in Table III.D.1-
1.\105\
---------------------------------------------------------------------------
\105\ See DRIA Chapter 2 for a more complete description of the
No RFS Baseline and its derivation.
Table III.D.1-1--No RFS Baseline
[Million RINs]
----------------------------------------------------------------------------------------------------------------
2026 2027 2028 2029 2030
----------------------------------------------------------------------------------------------------------------
Cellulosic biofuel (D3 & D7).... 582 619 659 702 749
Biomass-based diesel (D4)....... 3,156 3,310 3,429 3,614 3,753
Other advanced biofuel (D5)..... 197 197 197 197 197
Conventional renewable fuel (D6) 13,571 13,434 13,278 13,099 12,906
----------------------------------------------------------------------------------------------------------------
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 economic
without the RFS program. E85 is economic in some of the years before,
during, and after the years 2026-2030 in the State of California; \106\
thus, we assumed that E85 would be consumed in California without the
RFS program.\107\ While E85 is economic in New York, which offers a
large E85 blending subsidy, the volume of E85 sold in New York is very
small even with the RFS program in place; therefore, we ignored E85
sales in New York. Conversely E15 is not economic without the RFS
program due to the 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 CNG from biogas
and imported sugarcane ethanol are projected to be consumed in
California due to the economic support provided by their LCFS.
---------------------------------------------------------------------------
\106\ Our analysis indicated that E85 was also economic compared
to gasoline in Oregon; however, because there are only five stations
offering E85 in Oregon, we did not include E85 sold in Oregon in the
No RFS Baseline.
\107\ Since E85 is borderline economic 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 economic than corn ethanol.
---------------------------------------------------------------------------
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.
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 have used previous year
standards as a baseline against which to compare the projected impacts
of the proposed volumes 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). We note that in developing the proposed volume requirements in
this action, we considered updated projections of biofuel production in
2025, which are significantly higher than the 2025 Baseline shown below
that is used as a point of comparison in some of our analyses.
The 2025 volume requirements were finalized in the Set 1 Rule and
the volumes we projected to be used to satisfy these requirements are
shown in Table III.D.3-1.\108\
---------------------------------------------------------------------------
\108\ More details on the 2025 Baseline can be found in DRIA
Chapter 2.
[[Page 25812]]
Table III.D.3-1--2025 Baseline
[Million RINs]
------------------------------------------------------------------------
Volume
------------------------------------------------------------------------
Cellulosic biofuel (D3 & D7)......................... 1,376
Biomass-based diesel (D4)............................ 6,881
Other advanced biofuel (D5).......................... 290
Conventional renewable fuel (D6)..................... 13,939
------------------------------------------------------------------------
E. Volume Changes Analyzed
In general, our analysis of the impacts of the Volume Scenarios was
based on the differences between the No RFS Baseline and our assessment
of how the market would respond to the Low and High Volume Scenarios.
Those differences are shown in Tables III.E-1 and 2.\109\ Note that
this approach is squarely focused on the differences in volumes between
the No RFS Baseline and the Volume Scenarios; our analysis does not, in
other words, assess impacts from total renewable fuel use in the U.S.
As noted above, we also consider the impacts of this action relative to
the 2025 Baseline for some of our analyses. The changes in renewable
fuel consumption relative to the 2025 Baseline are shown in in Tables
III.E-3 and 4.
---------------------------------------------------------------------------
\109\ See DRIA Chapter 2 for more details of this assessment,
including a more precise breakout of those differences.
Table III.E-1--Changes in Renewable Fuel Consumption--Low Volume Scenario vs. No RFS Baseline
[Million RINs]
----------------------------------------------------------------------------------------------------------------
2026 2027 2028 2029 2030
----------------------------------------------------------------------------------------------------------------
Cellulosic biofuel (D3 & D7).... 716 743 772 802 834
Biomass-Based Diesel (D4)....... 5,255 5,600 5,981 6,297 6,658
Other Advanced Biofuel (D5)..... 52 52 52 52 52
Conventional Renewable Fuel (D6) 212 228 238 252 266
----------------------------------------------------------------------------------------------------------------
Table III.E-2--Changes in Renewable Fuel Consumption--High Volume Scenario vs. No RFS Baseline
[Million RINs]
----------------------------------------------------------------------------------------------------------------
2026 2027 2028 2029 2030
----------------------------------------------------------------------------------------------------------------
Cellulosic biofuel (D3 & D7).... 716 743 772 802 834
Biomass-Based Diesel (D4)....... 5,755 6,600 7,481 8,297 9,158
Other Advanced Biofuel (D5)..... 52 52 52 52 52
Conventional Renewable Fuel (D6) 212 228 238 252 266
----------------------------------------------------------------------------------------------------------------
Table III.E-3--Changes in Renewable Fuel Consumption--Low Volume Scenario vs 2025 Baseline
[Million RINs]
----------------------------------------------------------------------------------------------------------------
2026 2027 2028 2029 2030
----------------------------------------------------------------------------------------------------------------
Cellulosic biofuel (D3 & D7).... -78 -14 55 128 207
Biomass-Based Diesel (D4)....... 1,529 2,029 2,529 3,029 3,529
Other Advanced Biofuel (D5)..... -41 -41 -41 -41 -41
Conventional Renewable Fuel (D6) -156 -277 -423 -587 -767
----------------------------------------------------------------------------------------------------------------
Table III.E-4.--Changes in Renewable Fuel Consumption--High Volume Scenario vs. 2025 Baseline
[Million RINs]
----------------------------------------------------------------------------------------------------------------
2026 2027 2028 2029 2030
----------------------------------------------------------------------------------------------------------------
Cellulosic biofuel (D3 & D7).... -78 -14 55 128 207
Biomass-Based Diesel (D4)....... 2,029 3,029 4,029 5,029 6,029
Other Advanced Biofuel (D5)..... -41 -41 -41 -41 -41
Conventional Renewable Fuel (D6) -156 -277 -423 -587 -767
----------------------------------------------------------------------------------------------------------------
IV. Analysis of Volume Scenarios
As described in Section II.B, the statute specifies a number of
factors that EPA must analyze in making a determination of the
appropriate volume requirements to establish for years after 2022 (and
for BBD, years after 2012).\110\ In this section, we provide a summary
of the analysis of a selection of factors, including climate change,
energy security, costs, employment, and economic impacts for
[[Page 25813]]
the Volume Scenarios, along with some implications of those analyses.
We provide a summary of our consideration of all factors in determining
the proposed volume requirements in Section V.
---------------------------------------------------------------------------
\110\ A full description of the analysis for all factors is
provided in the DRIA.
---------------------------------------------------------------------------
A. Energy Security
Changes in the required volumes of renewable fuel can affect the
financial and security-related risks associated with U.S. trade in
crude oil and petroleum products, including both imports and exports
(hereafter referred to collectively as ``net petroleum imports''),
which, in turn, would have a direct impact on the national energy
security of the U.S. Likewise, the required volumes of renewable fuel
may lead to changes in imports and exports of renewable fuels and
renewable fuel feedstocks that can also impact U.S. energy security.
U.S. energy security is often defined as the continued availability
of energy sources at an acceptable price.\111\ Energy independence can
be achieved by reducing the sensitivity or reliance of an economy to
energy imports and foreign energy markets to the point where the costs
of depending on foreign energy are so small that they have minimal
effects on economic, military, or foreign policies.\112\ A central goal
of U.S. energy policy for decades has been to lower U.S. oil imports
and, thus, become less reliant on foreign oil suppliers. Similarly, as
described in Section VIII, we are also proposing to reduce the number
of RINs generated for imported renewable fuel and renewable fuel
produced from foreign feedstocks, which is intended to reduce America's
reliance on such fuels in future years consistent with the statutory
goals of energy security and independence.
---------------------------------------------------------------------------
\111\ IEA, ``Energy Security.'' https://www.iea.org/topics/energy-security.
\112\ 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.
---------------------------------------------------------------------------
The U.S. has witnessed a significant change in its exposure to the
world oil market since the initiation of the RFS2 program in 2010,
which has implications for U.S. energy security. In 2010, U.S. net
imports of petroleum were roughly 9.4 million barrels a day
(MMBD).\113\ However, over the past decade, mainly as a result of the
increased domestic production of oil, particularly ``tight'' (i.e.,
shale) oil, as well as increases in renewable fuels, the U.S. has
gradually shifted from a large net petroleum importer to a modest net
petroleum exporter.\114\ By 2023, U.S. net petroleum exports were
roughly 1.7 MMBD of petroleum.\115\ For 2026-2030, EIA anticipates that
the U.S. will continue the long-term shift from being a large net
petroleum importer, as it was in the 2010 decade, to a modest net
petroleum exporter of roughly 2.4 MMBD.\116\
---------------------------------------------------------------------------
\113\ 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.
\114\ EIA, ``Where our oil comes from,'' Oil and petroleum
products explained, June 11, 2024. https://www.eia.gov/energyexplained/oil-and-petroleum-products/where-our-oil-comes-from-in-depth.php.
\115\ EIA, ``U.S. Net Imports of Crude Oil and Petroleum
Products,'' Petroleum & Other Liquids, May 30, 2025. https://www.eia.gov/dnav/pet/hist/LeafHandler.ashx?n=pet&s=mttntus2&f=a.
\116\ AEO2023, Table 11--Petroleum and Other Liquids Supply and
Disposition.
---------------------------------------------------------------------------
In recent years, however, a substantial quantity of imports of
renewable fuels and renewable fuel feedstocks have been used to meet
the RFS volume obligations. In particular, there has been a recent
expansion of imports of BBD feedstocks since 2021, as can be seen in
Figure III.B.2.d-2. This shift, which has been driven by a confluence
of factors (as discussed in Section III.B.2), can have implications for
the U.S.'s energy security and energy independence.
Despite the long-term shift in the U.S.'s net petroleum trade
position, energy security risks remain for the U.S. There are three
main reasons why energy security is still a concern. First, oil and
renewable fuels and renewable fuel feedstocks are globally traded
commodities. As a result, price shocks for these commodities can be
transmitted globally even if a country is a net exporter of a
commodity. For example, since the U.S. is a large consumer of oil, an
oil price shock would raise the price of oil and oil products and could
cause broad adverse effects on the economy, even though the U.S. is an
overall net petroleum exporter. Second, many U.S. refineries rely
significantly or exclusively on imports of heavy crude oil, which could
be subject to international supply disruptions. In 2024, gross
petroleum imports totaled roughly 8.4 MMBD.\117\ Likewise, there has
been an expansion in imported feedstocks for BBD in recent years.
Third, oil exporters with a large share of global production can raise
or lower the price of oil by exerting their market power through the
Organization of Petroleum Exporting Countries (OPEC) to alter oil
supply relative to demand. All three of the factors listed above
contribute to the vulnerability of the U.S. economy to episodic fuel
supply shocks and price spikes, even though EIA projects the U.S. will
continue to be a net petroleum exporter through 2026-2030.
---------------------------------------------------------------------------
\117\ 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.
---------------------------------------------------------------------------
Oil markets can be subject to episodic periods of price instability
due to world oil market disruptions. The most recent world oil price
shock started in the beginning of 2022, when world oil prices and price
volatility rose fairly rapidly, in large part as a response to oil
supply concerns with Russia's invasion of Ukraine beginning on February
24, 2022.\118\ For example, the West Texas Intermediate (WTI) crude oil
price rose from roughly $76 per barrel on January 3, 2022, to roughly
$124 per barrel on March 8, 2022, a 63 percent increase.\119\
Conversely, by September 9, 2024, the WTI crude oil price had fallen
back to $70/barrel, a somewhat lower price than before the Russian
invasion of Ukraine.\120\ Oil prices at present are relatively low
mainly because of projected slowdown in world oil demand growth,
particularly in China.\121\ Crude oil prices (i.e., the WTI crude oil
price) are projected to be mostly flat over 2026-2027, in the $85-86
per barrel (2022$) range.\122\
---------------------------------------------------------------------------
\118\ EIA, ``Crude oil prices increased in first-half 2022 and
declined in second-half 2022,'' Today in Energy, January 4, 2023.
https://www.eia.gov/todayinenergy/detail.php?id=55079.
\119\ EIA, ``Spot Prices,'' Petroleum & Other Liquids, May 14,
2025. https://www.eia.gov/dnav/pet/pet_pri_spt_s1_d.htm.
\120\ Id.
\121\ EIA, ``Short-Term Energy Outlook,'' September 2024.
https://www.eia.gov/outlooks/steo/archives/sep24.pdf.
\122\ AEO2023, Table 12--Petroleum and Other Liquids Prices.
---------------------------------------------------------------------------
EPA has worked with Oak Ridge National Laboratory (ORNL) to
understand the energy security implications of reducing U.S. net
petroleum imports and, more generally, exposure of the U.S. economy to
global oil markets. ORNL has developed approaches for evaluating the
social costs/impacts and energy security implications of oil imports,
labeled the ``oil import premium'' or ``oil security premium.'' ORNL's
methodology estimates two distinct costs/impacts of importing petroleum
into the U.S., 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., the macroeconomic disruption/adjustment costs);
and (2) The impacts that changes in U.S. net oil imports have on
overall U.S. oil demand and subsequent
[[Page 25814]]
changes in the world oil price (i.e., the ``demand'' or ``monopsony''
impacts).\123\
---------------------------------------------------------------------------
\123\ Monopsony impacts stem from changes in the demand for
imported oil, which changes the price of all imported oil.
---------------------------------------------------------------------------
As has been the case for past RFS rulemakings, we consider the
monopsony impacts estimated by the ORNL methodology to be a transfer
payment, and thus exclude it from the estimated quantified benefits of
the Volume Scenarios.\124\ Thus, we only consider the macroeconomic
disruption/adjustment cost component of the net oil import premiums
(i.e., labeled ``macroeconomic oil security premiums'' below) estimated
using ORNL's methodology.
---------------------------------------------------------------------------
\124\ See DRIA Chapter 6.4.2 for more discussion of EPA's
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.
---------------------------------------------------------------------------
For this action, EPA and ORNL have worked together to revise the
U.S. oil import premiums based upon recent energy security literature
and oil price projections and energy market and economic trends from
AEO2023.\125\ EPA and ORNL have continuously updated oil import premium
estimates to account for increasing domestic shale oil production, as
well as other evolving U.S. and world oil market trends, since the RFS2
Rule in 2010. We do not consider military cost impacts from reduced oil
use from the Volume Scenarios due to methodological issues in
quantifying these impacts.\126\
---------------------------------------------------------------------------
\125\ See DRIA 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.
\126\ See DRIA Chapter 6.3 for a discussion of the difficulties
in quantifying military cost impacts.
---------------------------------------------------------------------------
To calculate the energy security benefits of the Volume Scenarios,
we are using the ORNL macroeconomic oil security premiums combined with
estimates of annual reductions in U.S. net petroleum imports
attributable to the changes in renewable fuel volumes.\127\ Table IV.A-
1 presents the macroeconomic oil security premiums and the total energy
security benefits for the Volume Scenarios. The macroeconomic oil
security premiums range from $3.65 per barrel in 2026 to $3.92 per
barrel in 2030. In terms of cents per gallon, the macroeconomic oil
security premiums range from 8.6 cents per gallon in 2026 to 9.3 cents
per gallon in 2030.
---------------------------------------------------------------------------
\127\ See DRIA Chapter 6.4.1 for a discussion of the methodology
used to estimate changes in U.S. annual net petroleum imports from
the Volume Scenarios.
Table IV.A-1--Macroeconomic Oil Security Premiums and Total Undiscounted Energy Security Benefits for the Volume
Scenarios a
----------------------------------------------------------------------------------------------------------------
Macroeconomic oil Total energy security Total energy security
security premiums benefits--Low Volume benefits--High Volume
Year (2022$/barrel of Scenario (millions Scenario (millions
reduced imports) 2022$) 2022$)
----------------------------------------------------------------------------------------------------------------
2026.................................. $3.65 ($0.47-$6.89) $138 ($18-$261) $151 ($19-$284)
2027.................................. 3.73 (0.51-7.02) 150 (21-283) 176 (24-331)
2028.................................. 3.78 (0.51-7.15) 162 (22-307) 201 (27-380)
2029.................................. 3.87 (0.54-7.31) 175 (24-331) 228 (32-430)
2030.................................. 3.92 (0.51-7.46) 187 (24-357) 254 (33-484)
----------------------------------------------------------------------------------------------------------------
\a\ Top values in each cell are the mean values, while the values in parentheses define 90 percent confidence
intervals.
B. Costs
1. Methodology
This section provides a brief discussion of the methodology used to
estimate the cost impacts for the renewable fuels expected to be used
for the Volume Scenarios, as well as for the proposed volume standards,
all relative to the No RFS Baseline. A more detailed discussion of how
we estimated the renewable fuel costs, as well as the fossil fuel costs
being displaced, can be found in DRIA Chapter 10.
The cost analysis compared the cost of biofuels attributable to the
RFS program to the cost of the fossil fuel it displaces. The net
estimated cost impacts are total social costs, excluding any subsidies
and transfer payments, and thus are incrementally added to all other
societal costs. They do not include benefits and other factors, such as
the potential impacts on soil and water quality or potential GHG
reduction benefits. The cost of each biofuel and fossil fuel being
displaced can be divided into various subcomponents:
Production cost: biofuel feedstock cost is usually the
most prominent factor.
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 incorporates 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
AEO2023.\128\
---------------------------------------------------------------------------
\128\ 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.
---------------------------------------------------------------------------
2. Estimated Cost Impacts
In this section, we summarize the overall results of our cost
analysis based on changes in the use of renewable fuels that displace
fossil fuel use for the Volume Scenarios; the costs for the proposed
volume standards are
[[Page 25815]]
summarized in Section V.H.4). The renewable fuel costs estimated and
presented here and in Section V.H.4 are the societal costs ultimately
borne by the consumers and do not reflect transfer payments between
parties in the market (e.g., tax subsidies for renewable fuels and RFS
compliance costs), which are not relevant under a societal cost
analysis.\129\ A detailed discussion of the renewable fuel costs
relative to the fossil fuel costs can be found in DRIA Chapter 10.
---------------------------------------------------------------------------
\129\ Note that in developing the No RFS Baseline we did
consider available subsidies other than those provided by the RFS
program in determining the volume of renewable fuels that would be
used in the absence of the RFS program.
---------------------------------------------------------------------------
Table IV.B.2-1 provides the total estimated annual cost of the
Volume Scenarios while Table IV.B.2-2 provides the per-unit cost (e.g.,
per gallon or per thousand cubic feet) of the biofuel. For both the
total and per-unit cost, the cost of the total change in renewable fuel
volume is expressed over the gallons of the respective fossil fuel in
which it is blended. For example, the costs associated with corn
ethanol relative to that of gasoline are reflected as a cost over the
entire gasoline pool, and biodiesel and renewable diesel costs are
reflected as a cost over the diesel fuel pool. Biogas displaces natural
gas use as CNG in trucks, so it is reported relative to natural gas
supply. Since the entire gasoline and diesel fuel pool of each refinery
is subject to the RFS program, we also amortize the entire renewable
fuels cost over the combined gasoline and diesel fuel pool.
Table IV.B.2-1--Total Social Costs Relative to No RFS Baseline
[Millions 2022$] \a\
----------------------------------------------------------------------------------------------------------------
Low Volumes Scenario High Volumes Scenario
---------------------------------------------------------------
2026 2027 2026 2027
----------------------------------------------------------------------------------------------------------------
Gasoline........................................ 188 206 188 206
Diesel.......................................... 5,030 4,436 5,615 5,642
Natural Gas..................................... -150 -165 -150 -165
---------------------------------------------------------------
Total....................................... 5,068 4,477 5,653 5,683
----------------------------------------------------------------------------------------------------------------
\a\ Total cost of the renewable fuel expressed over the fossil fuel it is blended into.
Table IV.B.2-2--Per-Unit Costs Relative to No RFS Baseline
[2022$]
----------------------------------------------------------------------------------------------------------------
Low Volumes Scenario High Volumes Scenario
Units ---------------------------------------------------------------
2026 2027 2026 2027
----------------------------------------------------------------------------------------------------------------
Gasoline...................... [cent]/gal...... 0.14 0.16 0.14 0.16
Diesel........................ [cent]/gal...... 9.59 8.54 10.71 10.86
Natural Gas................... [cent]/thousand -0.50 -0.57 -0.50 -0.57
ft\3\.
Gasoline and Diesel........... [cent]/gal...... 2.76 2.46 3.07 3.12
----------------------------------------------------------------------------------------------------------------
\a\ Per-gallon or per thousand cubic feet cost of the renewable fuel expressed over the fossil fuel it is
blended into; the last row expresses the cost over the obligated pool of gasoline and diesel fuel.
The biofuel costs are 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 IV.B.2-2.\130\ As described more
fully in DRIA 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 and agricultural feedstock price
forecasts, any attempt to identify such a threshold value is extremely
difficult. Nevertheless, in Section V we consider the directional cost
inferences along with the other factors that we analyzed in the context
of our discussion of the proposed volumes for 2026 and 2027.
---------------------------------------------------------------------------
\130\ Natural gas shows a cost savings despite the fact that
renewable natural gas is more expensive than fossil natural gas.
This is because the proposed cellulosic volume standard is estimated
to cause a smaller RNG volume in 2026 and 2027 compared to either
the No RFS Baseline or the 2025 Baseline.
---------------------------------------------------------------------------
The costs presented in this section are solely for the Volume
Scenarios relative to the No RFS Baseline, whereas Section V.H.4
contains the estimated costs for the proposed volume standards. DRIA
Chapter 10 contains summaries of the costs of all the scenarios
modeled, including the Volume Scenarios relative to the 2025 Baseline,
which are not summarized here.
C. 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,
EPA shall include ``an analysis of . . . the impact of the production
and use of renewable fuels on . . . climate change.'' As such, we have
undertaken an assessment of the potential climate impacts of volume
standards consistent with the Volume Scenarios. This analysis considers
impacts of such volume standards for three years--2026, 2027, and
2028--relative to the No RFS Baseline.
Cumulative emissions impact estimates for a thirty-year analytical
time period are presented in Table IV.C-1. This section of the preamble
contains only a brief synopsis of the results of our analysis; a full
description of the methods of analysis, models, scenarios, estimated
GHG emissions impacts by year, and uncertainties considered is
presented in DRIA Chapter 5.
[[Page 25816]]
Table IV.C-1--Cumulative Net Emissions Through 2055 for the Volume
Scenarios Relative to No RFS Baseline
[Millions of metric tons CO2e emissions]
------------------------------------------------------------------------
Scenario Cumulative Emissions
------------------------------------------------------------------------
Low Volume..................................... -672 to -339
High Volume.................................... -759 to -247
------------------------------------------------------------------------
Scenarios in the climate change analysis produce annual emissions
estimates for a 30-year analytical scenario duration. Additional
information about analytical methods for estimating GHG emissions
impacts can be found in DRIA Chapter 5; we note that the analysis for
this rulemaking relies on an updated methodology for assessing climate
change impacts under CAA section 211(o)(2)(B)(ii)(I), details of which
can also be found in DRIA Chapter 5. We request comment on our analysis
of the GHG emissions impacts of the proposed volume standards, and
whether factors in addition to GHG emissions, such as other drivers of
climate change and other considerations fitting within the term
``climate change,'' are relevant to the analysis. In addition to
requesting comment on this analysis in general, including the updated
methodology, we specifically request comment on the following aspects:
The methods for evaluating crop-based fuels and waste- and
byproduct-based fuels.
The use of economic models for assessing the potential
market-mediated impacts associated with crop-based fuels.
The scenarios used in this analysis, including the
analytical duration, and assumed future (post-2027) biofuel consumption
levels for both the policy and baseline scenarios.
D. Jobs and Rural Economic Development
In this section, we summarize our estimates of the impacts of the
Volume Scenarios on jobs and rural economic development (both include
direct, indirect, and induced impacts).\131\ This includes details
regarding potentially offsetting impacts to the economy that may stem
from the expansion of renewable fuels. While we acknowledge these
impacts, an attempt at formally quantifying or modeling them to
generate an estimate of the net impacts to the entire U.S. economy is
beyond the scope of this analysis.
---------------------------------------------------------------------------
\131\ These analyses are described in detail in DRIA Chapter 9.
---------------------------------------------------------------------------
To estimate the impacts on jobs, we applied two analytical
approaches common in the literature. The first is a basic ``rule-of-
thumb'' type approach that uses job and income impact estimates from
previous studies, expressed in jobs and/or dollars per unit of biofuel
production, and multiplies these estimated impacts by the projected
volumes to arrive at employment estimates. This approach is taken to
produce estimates for the impacts of the quantities of ethanol, BBD,
and RNG fuels in the Volume Scenarios relative to the No RFS Baseline.
The second is a slightly more nuanced approach that relies on the
use of an input-output modeling methodology developed specifically for
analysis of dry mill corn ethanol, which is applied only to the volumes
of that fuel in the Volume Scenarios relative to the No RFS Baseline.
These estimates are summarized in Tables IV. D-1 and 2. In some cases,
we have developed ranges of impacts for fuel volumes based on
uncertainty regarding how the volumes will be provided. For example,
volumes associated with new production capacity would also be
associated with some number of temporary construction jobs, while
expanded capacity utilization at existing facilities would not. These
ranges of potential impacts are summarized in tables in DRIA Chapter 9,
along with detailed explanations of the associated methodology. For the
corn ethanol case alone, we present the results of these two analyses
coequally here and request comment regarding approaches to estimating
the employment impacts of ethanol for the final rule. Both sets of
estimates (i.e., our rule-of-thumb analysis and our analysis using an
input-output model for the case of ethanol) have been computed based on
changes from the No RFS Baseline and the results we present should be
interpreted as additive gross jobs relative to that baseline. However,
were these analyses to be carried out relative to the 2025 Baseline,
some of these computed estimates would then be interpreted as jobs at
risk were the RFS program discontinued.
We estimate that all three categories of renewable fuel we
analyzed--ethanol, BBD, and RNG--are associated with increases in jobs
to varying degrees. We observe that RNG appears to be associated with
the highest number of direct jobs created per unit of biofuel. However,
BBD is projected to have the highest job creation impact overall,
primarily due to substantially higher production increases relative to
the 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, mainly due to substantially higher
production increases relative to the 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, largely due
to substantially higher production increases relative to the baseline.
Tables IV.D-1 and 2 summarize the estimated economy-wide job
impacts and rural GDP impacts (both include direct, indirect, and
induced impacts) associated with the volumes of ethanol, BBD, and RNG
attributable to the Low Volume Scenario and High Volume Scenario,
respectively. The estimates of rural GDP impacts are actual values as
opposed to discounted values, implying that they do not reflect the
time value of money.
[[Page 25817]]
Table IV.D-1--Economy-Wide Jobs and Rural Economic Development in the Low Volume Scenario Relative to No RFS Baseline
[Number of jobs in full-time equivalents; million 2022$, undiscounted]
--------------------------------------------------------------------------------------------------------------------------------------------------------
RNG BBD Ethanol a
-------------------------------------------------------------------------------------------
Year Rural economic Rural economic Rural economic
Jobs development Jobs development Jobs development
--------------------------------------------------------------------------------------------------------------------------------------------------------
2026........................................................ 19,504 $1,072.16 64,793 $6,840.04 5,332 $366.19
2027........................................................ 20,240 1,112.59 68,931 7,276.90 5,735 393.83
2028........................................................ 21,030 1,156.02 73,491 7,758.25 5,986 411.10
2029........................................................ 21,847 1,200.94 77,265 8,156.68 6,338 435.29
2030........................................................ 22,718 1,248.86 81,576 8,611.74 6,690 459.47
--------------------------------------------------------------------------------------------------------------------------------------------------------
\a\ For the corn ethanol case alone, using NREL's JEDI module for dry mill corn ethanol we were able to generate employment and income estimates under
alternative scenarios and also carry out a sensitivity analysis. See DRIA Chapter 9 for more details.
Table IV.D-2--Economy-Wide Jobs and Rural Economic Development in the High Volume Scenario Relative to No RFS Baseline
[Number of jobs in full-time equivalents; million 2022$, undiscounted]
--------------------------------------------------------------------------------------------------------------------------------------------------------
RNG BBD Ethanol a
-------------------------------------------------------------------------------------------
Year Rural economic Rural economic Rural economic
Jobs development Jobs development Jobs development
--------------------------------------------------------------------------------------------------------------------------------------------------------
2026........................................................ 19,504 $1,072.16 70,790 $7,473.08 5,332 $366.19
2027........................................................ 20,240 1,112.59 80,905 8,540.95 5,735 393.83
2028........................................................ 21,030 1,156.02 91,461 9,655.34 5,986 411.10
2029........................................................ 21,847 1,200.94 101,213 10,684.78 6,338 435.29
2030........................................................ 22,718 1,248.86 111,520 11,772.88 6,690 459.47
--------------------------------------------------------------------------------------------------------------------------------------------------------
\a\ For the corn ethanol case alone, using NREL's JEDI module for dry mill corn ethanol we were able to generate employment and income estimates under
alternative scenarios and also carry out a sensitivity analysis. See DRIA Chapter 9 for more details.
We request comment on our approaches to estimating jobs and rural
economic development impacts associated with renewable fuels.
These estimates for the various categories of biofuels are subject
to the limitations and assumptions of the methods employed. They are
not meant to be exact estimates, but rather to provide an estimate of
general magnitude. In addition, while we estimate that production and
consumption of these biofuels will lead to higher jobs and rural GDP in
some sectors of the economy, this will likely involve some migration in
jobs and rural GDP from other sectors. As such, we anticipate that
there would be job and rural GDP losses as well in some sectors.
Likewise, investments in rural development may involve some shifting of
capital from one sector to another. We do not account for any such
losses in our analysis. In other words, our estimates for jobs and
rural development impacts are gross estimates and not net estimates.
The existing literature also shows, in the long run, environmental
regulation such as the RFS program typically affects the distribution
of employment among industries rather than the general employment
level.132 133 The expectation is that there will be a
movement of labor towards jobs that are associated with greater
environmental protection, and away from those that are not. Even if
impacts are small after long-run market adjustments to full employment,
many regulatory actions move workers in and out of jobs and industries,
which are potentially important distributional impacts of environmental
regulations.\134\
---------------------------------------------------------------------------
\132\ Arrow, Kenneth J., Maureen L. Cropper, George C. Eads,
Robert W. Hahn, Lester B. Lave, Roger G. Noll, Paul R. Portney, et
al. ``Benefit-Cost Analysis in Environmental, Health, and Safety
Regulation,'' American Enterprise Institute, The Annapolis Center,
and Resources for the Future, 1996.
\133\ Hafstead, Marc a. C., and Roberton C. Williams. ``Jobs and
Environmental Regulation.'' Environmental and Energy Policy and the
Economy 1 (January 1, 2020): 192-240. https://doi.org/10.1086/706799.
\134\ Walker, W. Reed. ``The Transitional Costs of Sectoral
Reallocation: Evidence From the Clean Air Act and the Workforce*.''
The Quarterly Journal of Economics 128, no. 4 (August 15, 2013):
1787-1835. https://doi.org/10.1093/qje/qjt022.
---------------------------------------------------------------------------
For the final rule, we intend to carry out a more robust modeling
exercise that may capture more of these nuances. We request comments on
the types of approaches which would be appropriate to apply in
conducting such an analysis.
E. Agricultural Commodity Prices and Food Price Impacts
In this section, we summarize the projected impacts of the Volume
Scenarios on agricultural commodity and food prices. A detailed
explanation of the methods used to estimate these impacts can be found
in DRIA Chapter 9.
To assess the potential impact on corn prices, we used a
literature-based estimate that corn prices increase by 3 percent for
every additional billion gallons of corn ethanol produced.\135\ We
multiplied the projected corn price by the 3 percent per-billion-gallon
increase to estimate the price change per bushel. This value was then
applied to the difference in corn ethanol volumes between each Volume
Scenario and the No RFS Baseline. Table IV.E-1 summarizes the results
of the projected impact of increased corn ethanol production on corn
prices under the Volume Scenarios.\136\
---------------------------------------------------------------------------
\135\ Condon, Nicole, Heather Klemick, and Ann Wolverton.
``Impacts of Ethanol Policy on Corn Prices: A Review and Meta-
analysis of Recent Evidence.'' Food Policy 51 (January 13, 2015):
63-73. https://doi.org/10.1016/j.foodpol.2014.12.007.
\136\ The volume of corn ethanol is the same under the Low and
High Volume Scenarios; therefore, the results shown in Table IV.E-1
are the same for both Volume Scenarios.
[[Page 25818]]
Table IV.E-1--Projected Impact of Volume Scenarios on Corn Prices Relative to No RFS Baseline
----------------------------------------------------------------------------------------------------------------
Units 2026 2027 2028 2029 2030
----------------------------------------------------------------------------------------------------------------
Baseline Corn Price \a\...... $/Bushel........ $3.97 $4.07 $4.17 $4.27 $4.30
Corn Price Increase Relative $/Bushel........ 0.03 0.03 0.03 0.03 0.03
to No RFS Baseline.
----------------------------------------------------------------------------------------------------------------
\a\ Corn prices are from the USDA Agricultural Projections to 2034 (February 2025). Prices represent the average
price for a calendar year. For corn, the price is calculated using \1/3\ of the price for the first
agricultural marketing year (e.g., 2025/2026 for 2026) and \2/3\ of the price for the second agricultural
marketing year (e.g., 2026/2027 for 2026).
To determine the potential impact of the Volume Scenarios on
soybean oil and meal prices, we calculated projected price effects for
2026-2030 relative to the No RFS Baseline. These projections assume a
35.7 percent increase in the price of a pound of soybean oil per
billion gallons of biofuel produced and a 7.94 percent decrease in the
price of a short ton of soybean meal per billion gallons of biofuel
produced.\137\ We multiplied the projected soybean oil and meal prices
by their respective percentage changes per billion gallons of biofuel
to estimate the price impact per unit. These values were then applied
to the difference in biofuel volumes between each Volume Scenario and
the No RFS Baseline. This analysis provides an estimate of how
increased soy-based biofuel production impacts soybean oil and soybean
meal prices under each Volume Scenario. The results from this analysis
are presented in Tables IV.E-2 and 3 for the Low and High Volume
Scenarios, respectively.
---------------------------------------------------------------------------
\137\ Lusk, Jayson L. ``Food and Fuel: Modeling Food System Wide
Impacts of Increase in Demand for Soybean Oil,'' November 10, 2022.
Table IV.E-2--Projected Impact of the Low Volume Scenario on Soybean Oil and Meal Prices Relative to the No RFS Baseline
--------------------------------------------------------------------------------------------------------------------------------------------------------
Units 2026 2027 2028 2029 2030
--------------------------------------------------------------------------------------------------------------------------------------------------------
Baseline Soybean Oil Price \a\.............. $/Pound................... $0.39 $0.37 $0.37 $0.36 $0.36
Soybean Oil Price Increase Relative to No $/Pound................... 0.26 0.26 0.26 0.26 0.26
RFS Baseline.
Baseline Soybean Meal Price \a\............. $/Ton..................... 324 331 339 347 355
Soybean Meal Price Change Relative to No RFS $/Ton..................... -49 -51 -53 -55 -58
Baseline.
--------------------------------------------------------------------------------------------------------------------------------------------------------
\a\ Soybean oil and meal prices are from the USDA Agricultural Projections to 2034 report. Prices represent the average price for a calendar year. For
soybean oil, the price is calculated using \1/4\ of the price for the first agricultural marketing year (e.g., 2025/2026 for 2026) and \3/4\ of the
price for the second agricultural marketing year (e.g., 2026/2027 for 2026).
Table IV.E-3--Projected Impact of the High Volume Scenario on Soybean Oil and Meal Prices Relative to the No RFS Baseline
--------------------------------------------------------------------------------------------------------------------------------------------------------
Units 2026 2027 2028 2029 2030
--------------------------------------------------------------------------------------------------------------------------------------------------------
Baseline Soybean Oil Price \a\.............. $/Pound................... $0.39 $0.37 $0.37 $0.36 $0.36
Soybean Oil Price Increase Relative to No $/Pound................... 0.29 0.31 0.34 0.37 0.40
RFS Baseline.
Baseline Soybean Meal Price \a\............. $/Ton..................... 324 331 339 347 355
Soybean Meal Price Change Relative to No RFS $/Ton..................... -54 -62 -70 -79 -88
Baseline.
--------------------------------------------------------------------------------------------------------------------------------------------------------
\a\ Soybean oil and meal prices are from the USDA Agricultural Projections to 2034 report. Prices represent the average price for a calendar year. For
soybean oil, the price is calculated using \1/4\ of the price for the first agricultural marketing year (e.g., 2025/2026 for 2026) and \3/4\ of the
price for the second agricultural marketing year (e.g., 2026/2027 for 2026).
In addition to estimating the price impacts on corn, soybean oil,
and soybean meal, we also assessed price changes for other feed
grains--grain sorghum, barley, and oats--as well as distillers grains.
These commodities were included in this analysis because they have
historically competed with corn in the feed market and, to a lesser
extent, for planted acreage. These price changes were estimated using
historical price relationships with corn, and the analysis found only
minimal impacts on the other grains.\138\
---------------------------------------------------------------------------
\138\ See DRIA Chapter 9 for more information.
---------------------------------------------------------------------------
Additionally, the impact on commodity prices described above may,
in turn, have downstream effects on food prices and other products
derived from these commodities. To estimate the effect on total food
expenditures, we combined these projected price changes with forecasts
of commodity use for food production.\139\ Because commodity costs
typically represent a small portion of total food prices, the
anticipated effect of this action on food prices is relatively modest,
as shown in Table IV.E-4.
---------------------------------------------------------------------------
\139\ Commodity use for food production estimated using USDA
Agricultural Projections to 2034. See DRIA Chapter 9 for further
detail on this analysis.
[[Page 25819]]
Table IV.E-4--Impact of Volume Scenarios on Total Food Expenditures \a\
----------------------------------------------------------------------------------------------------------------
Units 2026 2027 2028 2029 2030
----------------------------------------------------------------------------------------------------------------
Low Volume Scenario
----------------------------------------------------------------------------------------------------------------
Change in Food Expenditures.......... Million $.............. $1,938 $1,802 $1,723 $1,648 $1,601
Projected Food Expenditure Increase.. $ per Consumer Unit.... $14.41 $13.40 $12.80 $12.25 $11.90
Percent Change in Food Expenditures.. Percent................ 0.14 0.13 0.13 0.12 0.12
----------------------------------------------------------------------------------------------------------------
High Volume Scenario
----------------------------------------------------------------------------------------------------------------
Change in Food Expenditures.......... Million $.............. $2,129 $2,141 $2,187 $2,213 $2,260
Projected Food Expenditure Increase.. $ per Consumer Unit.... $15.82 $15.92 $16.25 $16.45 $16.79
Percent Change in Food Expenditures.. Percent................ 0.16 0.16 0.16 0.16 0.17
----------------------------------------------------------------------------------------------------------------
\a\ Data from the U.S. Bureau of Labor Statistics, Consumer Expenditures--2023, Table A. Average income and
expenditures of all consumer units, 2021-23.
V. Proposed Volume Requirements for 2026 and 2027
As required by CAA section 211(o)(2)(B)(ii), we have reviewed the
implementation of the RFS program in prior years and have analyzed a
specified set of factors. The proposed volume requirements for 2026 and
2027 (the ``Proposed Volumes'') are informed by our technical analyses
of the Volume Scenarios, which are summarized in Section IV. Further
details of all analyses performed for this action are provided in the
DRIA.
In this section, we summarize and discuss the implications of our
analyses and any other relevant information that apply to each of three
different component categories of biofuel: cellulosic biofuel, non-
cellulosic advanced biofuel, and conventional renewable fuel. These
three components combine to produce the statutory categories: the
advanced biofuel volume requirement is equal to the sum of cellulosic
biofuel and non-cellulosic advanced biofuel, while the total renewable
fuel volume requirement is equal to the sum of advanced biofuel and
conventional renewable fuel.\140\ In Section V.C we discuss our
approach to the BBD standard in light our analysis of the non-
cellulosic advanced biofuel component category, the vast majority of
which we project will be comprised of BBD.
---------------------------------------------------------------------------
\140\ These combinations are set forth in CAA section
211(o)(2)(B)(i)(I)-(III). In addition, the determination of the
appropriate volume requirements for BBD is treated separately in
Section V.C.
---------------------------------------------------------------------------
In general, the volume requirements we are proposing for 2026 and
2027 are designed to provide significant support for the continued
growth in the production and use of renewable fuels. While the Proposed
Volumes (expressed in billion RINs) are similar to the Low Volume
Scenario and lower than the High Volume Scenario, we project that the
Proposed Volumes would result in significantly higher renewable fuel
production and consumption in the U.S. than either the Low or High
Volume Scenario, particularly for domestic renewable fuel, due to the
proposed import RIN reduction provisions.\141\ Our assessment of the
expected annual rate of future commercial production of renewable fuels
indicates that continued growth in the production and use of renewable
fuels is not only possible but expected if supported through the RFS
program. Increasing the production of renewable fuels furthers the
goals of the RFS program by increasing the energy independence and
energy security of the U.S. Further, increasing production of renewable
fuels, particularly those produced from domestic feedstocks, can have
significant positive impacts on employment and economic activity in
rural areas.
---------------------------------------------------------------------------
\141\ See DRIA Chapter 3 for more detail on the quantities and
types of renewable fuel we project would be supplied to meet the
Proposed Volumes and the Volume Scenarios.
---------------------------------------------------------------------------
We note that while we do not separately discuss each of the
statutory factors for each component category in this section, we have
analyzed all the statutory factors. However, 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, 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.
Air quality impacts are driven primarily by biofuel type (e.g.,
ethanol, biodiesel) rather than by biofuel category (e.g., advanced
biofuel, cellulosic biofuel), and energy security impacts are driven by
the amount of fossil fuel energy displaced. 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 EPA to analyze certain factors, without
specifying how that analysis must be conducted. In addition, the
statute directs EPA to analyze the ``program'' and the impacts of
``renewable fuels'' generally, further indicating that Congress
intended to provide EPA with the discretion to decide how and at what
level of specificity to analyze the statutory factors. This section
supplements the analyses discussed in Sections III and IV by providing
a narrative summary of how we used the results of our analyses of the
Volume Scenarios to derive the volumes we are proposing in this action.
A. Cellulosic Biofuel
In EISA, Congress set increasing targets for cellulosic biofuel,
aiming to reach 16 billion gallons by 2022. 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. 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, EPA remains
committed to supporting the advancement and commercialization of these
fuels.
Cellulosic biofuels, particularly those produced from waste or
residue materials, have the potential to significantly reduce GHG
emissions from the transportation sector. In many cases cellulosic
biofuel can be produced without impacting current land use and with
little to no impact on other environmental factors, such as air and
[[Page 25820]]
water quality. The proposed cellulosic biofuel volumes are intended to
support the continued development and commercial-scale deployment of
cellulosic biofuels while steadily increasing production, consistent
with the growth envisioned by EISA and our evaluation of the relevant
statutory factors.
As outlined in Section III, the Volume Scenarios reflect the
projected growth in cellulosic biofuel production and use in the
transportation sector through 2030, accounting for potential
constraints in both the production and use of cellulosic biofuel. We
then evaluated the Volume Scenarios using additional statutory factors.
The results of these evaluations are summarized here and detailed
further in the DRIA. Our analysis suggests that cellulosic biofuels
offer several significant benefits, including the potential for
exceptionally low lifecycle GHG emissions that meet or exceed the 60
percent GHG reduction threshold for cellulosic biofuel.\142\ These
benefits largely arise because the majority of feedstocks projected for
use in cellulosic biofuel production are either waste materials (e.g.,
CNG/LNG derived from biogas) or residues (e.g., cellulosic diesel and
heating oil from tree residue). The processing of these otherwise
unused feedstocks into transportation fuel is also likely to result in
increased employment and have a positive economic impact, particularly
in the communities where the cellulosic biofuel production facilities
are located.
---------------------------------------------------------------------------
\142\ CAA section 211(o)(1)(E).
---------------------------------------------------------------------------
The feedstocks currently used and expected to be used through 2027,
particularly biogas used for CNG/LNG production, are not anticipated to
cause substantial land use changes that could lead to negative
environmental impacts. None of the cellulosic biofuel feedstocks
expected to be used to produce liquid cellulosic biofuels through 2027
(including corn kernel fiber, mill residue, and separated MSW) are
produced with the intention that they be used as feedstocks for
cellulosic biofuel production. Because of this, using these feedstocks
to produce liquid cellulosic biofuel is not expected to have
significant adverse impacts related to several of the statutory
factors, including the conversion of wetlands, ecosystems and wildlife
habitat, soil and water quality, the price and supply of agricultural
commodities, and food prices through 2027.
Cellulosic biofuels are also expected to provide significant
economic development benefits. The production of these fuels supports
local economies, creating jobs in biofuel facilities and related
distribution networks. By encouraging the cellulosic biofuel market,
the U.S. strengthens its energy independence and reduces reliance on
foreign fuels, while fostering economic resilience.
Although both liquid cellulosic biofuels and CNG/LNG from biogas
are produced from wastes or by-product feedstocks, they differ
significantly in terms of production costs and market competitiveness.
Liquid cellulosic biofuels face high production costs due to low fuel
yields per ton of feedstock and the substantial capital investment
required for production facilities. Consequently, their economic
viability, at least in the short term (through 2027), will likely
depend on high cellulosic RIN prices and supportive programs such as
California's LCFS program and the 45Z tax credit to enable them to
compete with petroleum-based fuels. In contrast, CNG/LNG derived from
biogas sourced from landfills, wastewater treatment facilities, and
agricultural digesters can be more cost competitive with fossil fuels.
In certain cases, such as larger landfills, CNG/LNG production costs
can even approach those of conventional natural gas. Nonetheless, most
biogas-derived fuels, and particularly those from new sources, rely on
financial incentives to remain competitive. Given their relatively
lower production costs and mature technology, and in combination with
the high financial incentive created by the RFS program in addition to
that from State LCFS programs and tax credits, CNG/LNG from biogas is
expected to remain the dominant form of cellulosic biofuel through
2027. The combination of high RIN prices and the growing volume of CNG/
LNG used as transportation fuel and the high cellulosic RIN prices that
refiners must recover through fuel sales leads to an expected increase
in gasoline and diesel prices.
Our analysis of the statutory factors indicates that the benefits
of increasing cellulosic biofuel volumes outweigh the potential
downsides. To maximize these advantages, we are proposing cellulosic
biofuel volumes through 2027 at levels that align with projected growth
in the consumption of CNG/LNG as transportation fuel from 2026 to 2027.
These proposed volumes, based on the most current data at the time of
this action, represent a well-informed estimate of the achievable
growth in cellulosic biofuel production during this period. We believe
that these volumes would 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).
Table V.A-2--Proposed Cellulosic Biofuel Volumes a
[Million RINs]
------------------------------------------------------------------------
2026 2027
------------------------------------------------------------------------
CNG/LNG Derived from Biogas............. 1,170 1,360
Ethanol from CKF........................ 120 120
Total Cellulosic Biofuel............ 1,300 1,360
------------------------------------------------------------------------
\a\ All volumes rounded to the nearest 10 million RINs.
We also acknowledge the uncertainty in forecasting cellulosic
biofuel volumes. If actual cellulosic biofuel production and imports
fall significantly below the required volume, resulting in a RIN
shortfall, obligated parties may lack sufficient cellulosic RINs to
meet their RFS obligations. This could lead to some parties carrying
forward compliance deficits, and if production and imports continue to
lag targets, non-compliance could become a risk. Conversely, if
cellulosic biofuel production and imports exceed the required volumes,
resulting in a RIN surplus and lower prices for cellulosic biofuels and
cellulosic RINs. This scenario could undermine investments in
cellulosic biofuel production, with the simple possibility of such a
surplus potentially discouraging future investments. Using the best
available data, we believe the proposed cellulosic biofuel volumes are
reasonable and achievable, as well as consistent with the statutory
requirement in CAA section 211(o)(2)(B)(iv) that EPA
[[Page 25821]]
determine the cellulosic biofuel volume such that EPA need not waive
the cellulosic biofuel standard under CAA section 211(o)(7)(D).\143\
Therefore, we are proposing volumes that represent the projected volume
available in 2026 and 2027. We request comment on our proposed
cellulosic biofuel volumes for 2026 and 2027, especially regarding our
assessment of future CNG/LNG consumption. In addition, we recognize
that the methodology used to determine the proposed cellulosic biofuel
volumes in this rulemaking differs from past approaches, so we also
request comment on the methodology used to arrive at those volumes. We
also request any further data or insights that could enhance our
projections for cellulosic biofuel production in 2026 and 2027.
---------------------------------------------------------------------------
\143\ See DRIA Chapter 7.1 for further information on the
methodology EPA used to project the supply of cellulosic biofuel in
2026 and 2027.
---------------------------------------------------------------------------
B. 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. The applicable standards for 2022 similarly include five
billion gallons of non-cellulosic advanced biofuel. In the Set 1 Rule,
EPA continued to grow the implied non-cellulosic advanced biofuel
category, which reached 5.95 billion gallons in 2025.
As discussed in Sections III.B.2 and 3, we developed volume
scenarios for non-cellulosic advanced biofuel based on a consideration
of the quantities of these fuels potentially able to be supplied to the
U.S. market. This process included consideration of the supply of these
fuels in 2023 and the months in 2024 for which data were available and
the projected future projection and import of non-cellulosic advanced
biofuels in future years. The non-cellulosic advanced biofuel volumes
in the Volume Scenarios reflect significantly different growth rates
for this category (500 million RINs per year vs. 1 billion RINs per
year). These volume scenarios were designed to enable us to consider
the likely impacts of different volume requirements for non-cellulosic
advanced biofuel. They also reflect the significant uncertainty in the
volume of these fuels that could be supplied to the U.S. in future
years. We then analyzed the Volume Scenarios according to the statutory
factors.
In this action we are proposing volume requirements for 2026 and
2027 that reflect 500 million RIN annual increases in the projected
supply of non-cellulosic advanced biofuel. These increases are relative
to the volume of non-cellulosic advanced biofuel we project will be
supplied to the U.S. in 2025 based on available data, which is
significantly higher than the volumes of these fuels we projected would
be supplied in 2025 in the Set 1 Rule. Our decision to propose volumes
consistent with Low Volume Scenario is based on our assessment of the
impacts of biofuels produced from domestic feedstocks on the statutory
factors and our projection of the quantity of qualifying feedstocks
available to biofuel producers. Our assessment of the statutory
factors, and how these assessments support the proposed non-cellulosic
advanced biofuel volumes, are summarized in the remainder of this
section, and are discussed in greater detail in the DRIA.
A key consideration in determining the proposed non-cellulosic
advanced biofuel volumes is our proposal in this action to reduce the
number of RINs generated for imported renewable fuels and renewable
fuels produced from foreign feedstocks by 50 percent, as discussed in
Section VIII. While much of the renewable fuel eligible to generate
RINs under the RFS program is produced by domestic producers from
domestic feedstocks--including the vast majority of all cellulosic
biofuel and conventional renewable fuel--we estimate that nearly 50
percent of all non-cellulosic advanced biofuel was imported or produced
from foreign feedstocks in 2024.\144\ The 500 million RIN annual growth
rate that forms the basis for our proposed non-cellulosic advanced
biofuel volumes is approximately equal to our projection of the annual
increase in the production of domestic feedstocks that can be used to
produce these fuels. This approach provides a strong incentive to
increase the production of domestic renewable fuels from domestic
feedstocks. It also allows for domestic biofuel producers to continue
to use foreign feedstocks where it is advantageous to do so, while
incentivizing these producers to source increasing quantities of
domestic feedstocks over time.
---------------------------------------------------------------------------
\144\ See DRIA Chapter 3.2 for more detail on EPA's estimate of
domestic vs. imported biofuels and feedstocks in 2024.
---------------------------------------------------------------------------
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. While the impacts of non-cellulosic advanced biofuels on the
statutory factors vary depending on the fuel type, production process,
where the fuel is produced (e.g., domestically vs. in a foreign
country), and the feedstock used to produce the fuel, all advanced
biofuels have the potential to provide significant GHG reductions.
These 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 EPA for 2025 (5.95 billion RINs)
may be appropriate.
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 together the two fuels are expected to
continue to do so through 2027 due to the limited production and import
of other types of non-cellulosic advanced biofuels.\145\ We have
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.\146\
---------------------------------------------------------------------------
\145\ See DRIA Chapters 7.2 through 7.4.
\146\ 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 consumption
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 other factors, the projected impacts vary
significantly depending on whether the feedstock used to produce the
fuel is a waste or byproduct (e.g., used cooking oil) or an
agricultural commodity (e.g., soybean oil) and whether it is sourced
domestically or imported.
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 all 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
[[Page 25822]]
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 suggest that higher volumes of biodiesel and
renewable diesel may be appropriate in future years.
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.\147\
Biodiesel and renewable diesel produced from vegetable oils are
expected to directionally 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. Higher vegetable oil prices are
also expected to result in higher prices for products that use them as
inputs.
---------------------------------------------------------------------------
\147\ 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 DRIA Chapter 10 for a further discussion of our cost
estimates.
---------------------------------------------------------------------------
Finally, the projected impacts on some of the statutory factors are
expected to vary significantly depending on the feedstock used to
produce the biodiesel or renewable diesel. We have generally assumed
that biofuels produced from wastes or byproducts 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.\148\ Because of this assumption, biofuels produced from wastes
or byproducts 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. We
request comment on the potential impact of increased demand for these
feedstocks on global crop production, and the implications for the
estimated GHG emissions of biofuels produced from these feedstocks.
---------------------------------------------------------------------------
\148\ 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 waste or byproduct 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 of these feedstocks that
will be available to the U.S. in future years.
1. Assessment of Available Feedstocks
Biodiesel and renewable diesel produced from 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 are expected to have
lower GHG emission benefits than biofuels produced from wastes or
byproducts. 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. Because the supply of these feedstocks is less
dependent on imports and there are relatively fewer incentives and
lower demand for biofuels produced from vegetable oils, we have greater
confidence in projecting the potential supply of these feedstocks in
future years.
Our analysis of the Volume Scenarios indicated likely differences
in impacts on the statutory factors between growth in the supply of
biodiesel and renewable diesel produced from wastes or byproducts such
as UCO and tallow (primarily imported from foreign countries) and those
produced from virgin vegetable oils (primarily from the U.S.). 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 proposed non-cellulosic advanced biofuel volumes. As discussed
further in the remainder of this section, there is relatively less
uncertainty in the projected availability of vegetable oils than there
is in the projected availability of wastes or byproducts such as UCO
and tallow. 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 and other productive uses
in other countries.
a. Vegetable Oils
The available supply of vegetable oils to domestic biofuel
producers is generally a function of the potential for increased
production of these feedstocks in the U.S. and Canada, though some
small imports from other countries do occur. 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. Based on the observed increases in soybean and
canola crush capacity in recent years and publicly available
information on expansions underway, we can reasonably project the rate
of growth in the soybean and canola crush industry through 2027,
assuming continued demand for the vegetable oils produced from these
facilities is sufficient to support ongoing investment in crush
capacity.
For distillers corn oil, soybean oil, and canola oil, the primary
source of uncertainty in the supply of these feedstocks to domestic
biofuel producers is the demand for these feedstocks in markets other
than biofuel production in the U.S. With the exception of imports of
canola oil from Canada, imports of distillers corn oil, soybean oil,
and canola oil from countries other than Canada have been
[[Page 25823]]
relatively small in recent years and are not expected to increase
through 2027. Consistent with the observed historical trends, we
currently project the potential for increasing imports of canola oil
from Canada but do not project any significant changes to the import of
distillers corn oil, soybean oil, or canola oil from countries other
than Canada due to limited global production, relatively high tariffs
on imports, and high demand in food markets respectively. Any increases
to the supply of these feedstocks to biofuel producers would require
diverting these feedstocks from current markets. While this is
possible, we project any shifts of these vegetable oils from current
markets through 2027 to be limited. Since 2015, the use of soybean oil
and canola oil in the U.S. in markets other than biofuel production has
remained fairly consistent despite the significant increase in the use
of these oils for biofuel production.\149\ This suggests that these
oils have a higher value in non-biofuel markets (e.g., food) and are
unlikely to be diverted from these markets in significant quantities
due to higher demand for biofuel production in the near term. While the
U.S. has historically been a net exporter of soybean oil, data for the
2023/24 agricultural marketing year indicates that net exports of
soybean oil were near zero \150\ and therefore opportunities to divert
soybean oil from export markets are very limited.
---------------------------------------------------------------------------
\149\ USDA, ``Oil Crops Yearbook,'' March 2025. https://www.ers.usda.gov/data-products/oil-crops-yearbook.
\150\ Id.
---------------------------------------------------------------------------
b. Animal Fats and UCO
In addition to vegetable oils, the other primary sources of
feedstocks for biodiesel and renewable diesel production are animal
fats (such as tallow) and UCO. In the U.S., collection and productive
use of these feedstocks is well established. Most of the economically
recoverable UCO and animal fats in the U.S. are currently collected and
productively used, primarily for biofuel production.\151\ We project
that the supply of these feedstocks will continue to grow, but that the
rate of growth in the availability of these feedstocks from domestic
markets will be modest, growing with domestic meat production and the
use of vegetable oil for food production.
---------------------------------------------------------------------------
\151\ 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.
The uncertainty is associated both with the quantity of these materials
that can be economically collected and competition for available
feedstocks and biofuels produced from these feedstocks in other
countries.
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.\152\ 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) and the
diversion of animal fats for existing uses to biofuel production. We
note, however, that 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.\153\
---------------------------------------------------------------------------
\152\ Food and Agriculture Organization of the United Nations,
``World Food and Agriculture--Statistical Yearbook 2023,'' 2023.
https://doi.org/10.4060/cc8166en.
\153\ 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 in the U.S.\154\ 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.\155\ 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).\156\ The
study noted that even greater UCO collection is possible by 2027 with
economic incentives sufficient to encourage the collection of UCO in
countries where it is currently not being collected.\157\
---------------------------------------------------------------------------
\154\ Global Data, ``UCO Supply Outlook,'' August 2023.
\155\ Id.
\156\ Id.
\157\ Id.
---------------------------------------------------------------------------
In addition to the uncertainty related to the global collection of
animal fats and UCO, there is also significant uncertainty related to
the markets where these feedstocks and biofuels produced from them will
be used. Because biodiesel and renewable diesel generally cost more to
produce than the petroleum fuels they displace, demand for these fuels
is primarily driven by the incentives available to the producers and/or
blenders of these fuels. Many countries around the world offer
incentives or have imposed mandates for the use of biodiesel and
renewable diesel. These incentives vary significantly from country to
country, both in magnitude and in structure. For example, some
countries provide the same incentive for all gallons of qualifying
biofuel, while other countries provide increasing incentives for
biofuels that provide greater GHG reductions, such as the waste
feedstock derived fuels.
Because incentives are often greatest for animal fats and UCO
feedstocks and biofuels produced from them, the market for these fuels
is subject to greater volatility based on changes in biofuel policies
than are vegetable oils and biofuels produced from vegetable oils. For
example, in California's LCFS program, biofuels produced from animal
fats and UCO generally have a lower carbon intensity and thus generate
more credits than biofuels produced from vegetable oils such as soybean
oil and canola oil. The EU's RED II places no restrictions on the
crediting of biofuels produced from animal fats and UCO while the
crediting of biofuels produced from food and feed crops is limited to a
maximum of 7 percent of the consumption in the road and rail transport
sector in each member state.\158\ Because biofuels and biofuel
feedstocks are globally traded commodities, the incentives available
for the production and use of these
[[Page 25824]]
biofuels can and historically have had a significant impact on where
these products are used. A greater or smaller portion of the available
global supply of animal fats and UCO could be available to U.S. biofuel
producers depending on whether the incentives available to biofuel
producers are higher or lower than those offered by other countries.
---------------------------------------------------------------------------
\158\ European Commission, ``Renewable Energy--Recast to 2030
(RED II).''
---------------------------------------------------------------------------
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.\159\ 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.\160\ 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. There is potential for
increased consumption of these fuels and feedstocks domestically in
China in future years, should the government, for example, choose to
increase incentives for the production and use of renewable jet fuel.
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.
---------------------------------------------------------------------------
\159\ UN Comtrade Database, Trade Data, HS Code 1518.
\160\ Id.
---------------------------------------------------------------------------
2. Proposed Non-Cellulosic Advanced Biofuel Volumes
Based on our analyses of all the statutory factors, we are
proposing volumes for 2026 and 2027 that reflect 500 million RIN annual
increases in the projected supply of non-cellulosic advanced biofuel
relative to the projected supply of these fuels in 2025. These volumes
reflect our consideration of the impacts of these fuels on the
statutory factors, including the potential increases in employment and
economic impacts associated with the increased production of these
fuels (particularly those produced from domestic feedstocks) and the
potential for GHG reductions that may result from their use. The
proposed non-cellulosic advanced biofuel volumes also reflect our
consideration of the projected potential increases in biodiesel and
renewable diesel production and supply based primarily on our
assessment of the 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 proposed non-
cellulosic advanced biofuel volumes could be supplied from domestic
sources and therefore are not dependent on increases in the quantity of
imported feedstocks in future years. The proposed reduction in the
number of RINs generated for imported renewable fuels and renewable
fuels produced from foreign feedstocks significantly increase the
likelihood that the increase in the supply of non-cellulosic biofuels
through 2027 will be supplied by domestic biofuel producers using
domestic feedstocks. Through 2027, we project that imported renewable
fuels and feedstocks will continue to contribute towards the total
supply of non-cellulosic advanced biofuels, but that the relative share
of imported renewable fuels and feedstocks will decrease in future
years as domestic supplies increase in response to the incentives
provided by the RFS program. We acknowledge, however, that the impact
of the proposed import RIN reduction provisions on imports of
biodiesel, renewable diesel, and feedstocks used to produce these fuels
is uncertain. We request comment on the impact of the proposed import
RIN reduction provisions on imports of biodiesel, renewable diesel, and
feedstocks used to produce these fuels.\161\
---------------------------------------------------------------------------
\161\ See DRIA Chapter 3.2 for our assessment of the likely
impacts of this proposed rule, including the impact of the proposed
import RIN reduction.
---------------------------------------------------------------------------
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 EPA to
reduce the volume requirements in the future, undermining the market
stability the RFS program is designed to provide. Finally, increasing
demand for feedstocks could result in the diversion of qualifying
feedstocks from existing uses and increased demand for substitutes such
as palm oil. We request comment on whether higher or lower volumes of
non-cellulosic advanced biofuel may be appropriate for 2026 and 2027.
While we have determined that it is reasonable to propose volumes
for 2026 and 2027 that reflect 500 million RIN annual increases in the
projected supply of non-cellulosic advanced biofuel, we are not
proposing the advanced biofuel volume requirements for 2026 and 2027 at
a level equal to the sum of cellulosic biofuel and non-cellulosic
advanced biofuel volumes in this scenario. Consistent with the approach
taken by EPA in the Set 1 Rule, and as discussed in greater detail in
Section V.D, we are proposing 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
proposed conventional renewable fuel volume of 15 billion gallons.
We project that the most likely source of non-ethanol biofuel will
be biodiesel and renewable diesel that qualifies as BBD. 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 proposed non-cellulosic advanced biofuel volumes.
Therefore, the proposed non-cellulosic advanced biofuel volumes are
equal to the Low Volume Scenario less the volume projected to be needed
to meet the shortfall in the proposed conventional renewable fuel
volume. The proposed non-cellulosic advanced
[[Page 25825]]
biofuel volumes for 2026 and 2027 are summarized in Table V.B.2-1.
Table V.B.2-1--Proposed Non-Cellulosic Advanced Biofuel Volumes
[Million RINs] \a\
------------------------------------------------------------------------
2026 2027
------------------------------------------------------------------------
Non-cellulosic biofuel volume (total 8,940 9,440
supply)................................
Needed to meet the implied conventional 1,220 1,340
volume.................................
Available for the advanced biofuel 7,720 8,100
standard...............................
------------------------------------------------------------------------
\a\ All volumes rounded to the nearest 10 million RINs.
C. Biomass-Based Diesel
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.
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 DRIA.
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 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 new 45Z credit
may support the production and use of 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 proposed 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 proposing 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. We request comment on this 600 million RIN amount and whether a
higher or lower number would be appropriate. The proposed BBD volumes
are shown in Table V.C-1.
Note that, unlike in previous years, the BBD volume requirement is
expressed in RINs rather than physical gallons. As discussed in Section
X.C, we are proposing to make 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. This
change also reflects the increasing uncertainty in the relationship
between the number of gallons of BBD that will be needed to satisfy the
percentage standards due to the proposed reduction in the number of
RINs generated for imported renewable fuels and renewable fuels
produced from foreign feedstocks.\162\
---------------------------------------------------------------------------
\162\ See Section VIII.
Table V.C-1--Proposed BBD Volumes
[Million RINs] \a\
------------------------------------------------------------------------
2026 2027
------------------------------------------------------------------------
BBD..................................... 7,120 7,500
Opportunity for advanced biofuel other 600 600
than BBD...............................
-------------------------------
Total non-cellulosic advanced 7,720 8,100
biofuel............................
------------------------------------------------------------------------
\a\ All volumes rounded to the nearest 10 million RINs.
D. Conventional Renewable Fuel
Although Congress had intended cellulosic biofuel to become the
most widely used renewable fuel by 2022, 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
[[Page 25826]]
program, caused it to quickly saturate the gasoline supply shortly
after the RFS program began. Indeed, corn ethanol has been added to
nearly every gallon of gasoline used for transportation in the United
States ever since.
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. EPA has used 15 billion
gallons of conventional renewable fuel in calculating the applicable
percentage standards for several recent years, most recently for 2023-
2025 in the Set 1 Rule.
As discussed in Section III.B.5, 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 over time in line with likely vehicle
efficiency improvements.
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 choose to propose 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, EPA's analysis of several of
the statutory factors also highlights, in our view, 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 help provide some longer-term incentives for the market to
invest in the necessary infrastructure. 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 discussed in Section IV.B.
Most corn ethanol production occurs in facilities that commenced
construction prior to December 19, 2007. This fuel is ``grandfathered''
under the provisions of 40 CFR 80.1403 and thus is not required to
achieve a 20 percent reduction in GHGs in comparison to gasoline,
pursuant to CAA section 211(o)(2)(A)(i). Nevertheless, based on both
our assessment of corn ethanol in the RFS2 Rule and our assessment of
GHG impacts for this rule, summarized in Section IV.A, corn ethanol
provides GHG reductions in comparison to gasoline. Greater volumes of
ethanol consumed thus correspond to greater GHG reductions than would
be the case if gasoline was consumed instead of ethanol.
We are projecting that total ethanol consumption will be lower in
2026 and 2027 than it was in previous years despite the increase in
consumption of E15 and E85, as discussed in Sections III. 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 proposing to set the implied conventional renewable
fuel volume requirement for 2026 and 2027 at 15 billion gallons.
Table V.D-1--Proposed Conventional Renewable Fuel Volumes
[Million RINs] \a\
------------------------------------------------------------------------
2026 2027
------------------------------------------------------------------------
Conventional ethanol.................... 13,780 13,660
Non-cellulosic advanced biofuel (beyond 1,220 1,340
what is needed to meet the advanced
biofuel volume requirement)............
-------------------------------
Total conventional renewable fuel... 15,000 15,000
------------------------------------------------------------------------
\a\ All volumes rounded to the nearest 10 million RINs.
E. Treatment of Carryover RINs
In our assessment of supply-related factors, we focused on those
factors that could directly or indirectly impact the consumption of
renewable fuel in the U.S. and thereby determined 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
[[Page 25827]]
determining appropriate levels for the volume scenarios and,
ultimately, the Proposed Volumes.
CAA section 211(o)(5) requires that 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. EPA 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
renewable volume obligation (RVO).\163\ For the collective supply of
carryover RINs to be preserved from one year to the next, 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, vintage 2026 RINs can then be saved for use toward
2027 compliance.
---------------------------------------------------------------------------
\163\ 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.\164\ 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.\165\ 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.
---------------------------------------------------------------------------
\164\ See, e.g., 72 FR 23904 (May 1, 2007).
\165\ 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 EPA has
considered the need to use its 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.\166\
---------------------------------------------------------------------------
\166\ 79 FR 49793-95 (August 15, 2013).
---------------------------------------------------------------------------
1. Projected Number of Available Carryover RINs
The projected number of available carryover RINs after compliance
with the 2023 standards (i.e., the number of carryover RINs available
for compliance with the 2024 standards) is summarized in Table V.E.1-
1.\167\ This is the most recent year for which complete RFS compliance
data was available at the time of this proposal.
---------------------------------------------------------------------------
\167\ The calculations performed to project the number of
available carryover RINs can be found in DRIA Chapter 1.8.
Table V.E.1-1--Projected 2023 Carryover RINs
[Million RINs]
----------------------------------------------------------------------------------------------------------------
Absolute 2023 Effective 2023
RFS standard RIN type carryover RINs \a\ carryover RINs \b\
----------------------------------------------------------------------------------------------------------------
Cellulosic Biofuel........................ D3+D7....................... 30 0
Non-Cellulosic Advanced Biofuel \c\....... D4+D5....................... 740 410
Conventional Renewable Fuel \d\........... D6.......................... 400 0
Total Renewable Fuel.................. All D Codes................. 1,170 \e\ 0
----------------------------------------------------------------------------------------------------------------
\a\ Represents the absolute number of 2023 carryover RINs that are available for compliance with the 2024
standards and does not account for deficits carried forward from 2023 into 2024.
\b\ Represents the effective number of 2023 carryover RINs that are available for compliance with the 2024
standards after accounting for deficits carried forward from 2023 into 2024. Standards for which deficits
exceed the number of available carryover RINs are represented as zero.
\c\ Non-cellulosic advanced biofuel is not an RFS standard category but is calculated by subtracting the number
of cellulosic RINs from the number of advanced RINs.
\d\ Conventional renewable fuel is not an RFS standard category but is calculated by subtracting the number of
advanced RINs from the number of total renewable fuel RINs.
[[Page 25828]]
\e\ This total reflects the fact that for some categories deficits exceed the absolute number of available
carryover RINs such that the total volume of effective carryover RINs is zero.
Assuming that the market exactly meets the 2024 and 2025 standards
with new RIN generation, these are also the number of carryover RINs
that would be available for 2026 and 2027. While we project that the
volume requirements in 2024 and 2025 and the volume scenarios for 2026
and 2027 could be achieved without the use of carryover RINs, there is
nevertheless some uncertainty about how the market would 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
particular, as discussed in DRIA Chapter 1.8, the number of available
carryover RINs has decreased significantly in recent years. While on an
absolute basis there should still be RINs available to purchase in the
marketplace, as shown in Table III.C.4.a-1, in reality the magnitude of
compliance deficits is even larger, making their availability less
certain. Furthermore, 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
available carryover RINs could be larger or smaller than the number
projected in Table V.E.1-1.
We continue to believe that carryover RINs serve a vital
programmatic function, but also acknowledge that the effective number
of cellulosic and conventional renewable fuel carryover RINs is zero,
and that the effective number of non-cellulosic advanced biofuel
carryover RINs is significantly lower than it has been in recent years
and may be necessary to make up for the significant conventional
biofuel deficits. Should the market fall short of the volumes we are
finalizing, obligated parties will continue to be able to carry forward
a RIN deficit from one year into the next, although they may not carry
forward a deficit for consecutive years. Conversely, should the market
over-comply with the standards we are finalizing, the number of
available carryover RINs could again grow.
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 scenarios that we analyzed or the volume
requirements that we are proposing for 2026 and 2027. Doing so would be
equivalent to intentionally drawing down the number of available
carryover RINs in setting those volume requirements. After due
consideration, we do not believe that this would be appropriate and we
propose to avoid intentionally drawing down any portion of the
projected number of available carryover RINs in the Proposed 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 EPA exercises its
discretion under its statutory authorities.
Furthermore, in this action we are proposing to prospectively
establish 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 proposing
to set the 2026 and 2027 volume requirements at levels that would
intentionally draw down the projected number of available carryover
RINs.
We are not determining that the number of carryover RINs projected
in Table V.E.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 case-by-case 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.
F. Summary of Proposed Volume Requirements
For the reasons described above, we are proposing RFS volume
requirements based on the three component categories discussed above.
The volumes for each of the component categories (sometimes referred to
as implied volume requirements) are summarized in Table V.F-1. Table
V.F-1 also includes the proposed 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 V.C.
[[Page 25829]]
Table V.F-1: Proposed Volume Requirements for Component Categories and
BBD
[Billion RINs] \a\
------------------------------------------------------------------------
2026 2027
------------------------------------------------------------------------
Cellulosic biofuel................ 1.30 1.36
Biomass-based diesel.............. 7.12 7.50
Non-cellulosic advanced biofuel... 7.72 8.10
Conventional renewable fuel....... 15.00 15.00
------------------------------------------------------------------------
\a\ All volumes rounded to the nearest 0.01 billion RINs.
The proposed 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 V.F-2.
Table V.F-2--Proposed Volume Requirements for Statutory Categories
[Billion RINs] \a\
------------------------------------------------------------------------
2026 2027
------------------------------------------------------------------------
Cellulosic biofuel............................ 1.30 1.36
Biomass-based diesel.......................... 7.12 7.50
Advanced biofuel.............................. 9.02 9.46
-------------------------
Total renewable fuel...................... 24.02 24.46
------------------------------------------------------------------------
\a\ All volumes rounded to the nearest 0.01 billion RINs.
We believe that these volume requirements will preserve and
substantially build upon the gains made through biofuels in previous
years. These proposed volume requirements, in combination with the
proposed import RIN reduction provisions, would continue to support the
domestic renewable fuel industry and help move the U.S. towards greater
energy independence and energy security. These proposed volume
standards are expected to drive increased employment and economic
impact in the U.S. and are projected to achieve additional reductions
in GHG emissions from the transportation sector. The proposed volume
requirements would 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.
G. Request for Comment on Alternatives
We request comment on alternative volume requirements for each of
the statutory categories of renewable fuel for 2026 and 2027, including
volumes both higher and lower than we are proposing and appropriate
volumes if the proposed provisions to reduce the number of RINs
generated for imported renewable fuel and renewable fuel produced from
foreign feedstocks are not finalized. Our analysis of the Low and High
Volume Scenarios summarized in Section IV and presented in greater
detail in the DRIA provides an indication of the potential impacts of
alternative volumes. Note that while the Proposed Volumes (expressed in
billion RINs) are similar to the Low Volume Scenario and lower than the
High Volume Scenario, we project that the Proposed Volumes would result
in significantly higher renewable fuel production and consumption in
the U.S. than either the Low or High Volume Scenario, particularly for
domestic renewable fuel, due to the proposed import RIN reduction
provisions.
We also request that commenters provide any data or analysis that
would support alternative volumes for these years. In particular, we
request comment on our proposed approach of accounting for the
projected shortfall in the supply of conventional renewable fuel
relative to the 15-billion-gallon implied volume when establishing the
volume requirements for advanced biofuel and BBD (see Section V.B for a
description of this approach). We request comment on the advantages and
disadvantages of establishing BBD and advanced biofuel volume
requirements at levels at or closer to the projected supplies of these
fuels, as has been suggested by some stakeholders, and the implications
of doing so on the implied volume of conventional renewable fuel if
such an approach were adopted.
H. Summary of the Assessed Impacts of the Proposed Volume Standards
CAA section 211(o)(2)(B)(ii) requires EPA to assess specific
factors when determining volume requirements for calendar years after
2022. These factors are described in Section I and each factor is
discussed in detail in the DRIA. However, the statute does not specify
how EPA must assess each factor or address whether the EPA
Administrator should monetize particular factors, quantify particular
factors, or analyze particular factors qualitatively in reaching a
determination. For several of these statutory factors--costs and energy
security--we provide estimates of the monetized impacts of the proposed
volume standards. For the other statutory factors, we are either unable
to quantify impacts, 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 and
are also unable to compare all quantitative impacts on a consistent
basis. Our assessments of the impacts of the proposed volume standards
mirrors our assessment of the Volume Scenarios discussed in Section IV.
That is, we compared the difference in estimated outcomes under the
proposed volume standards to the estimated outcomes under the No RFS
Baseline.
Assessed effects of the proposed volume standards on the factors
enumerated below differ in the directions of their respective impacts.
That is, some assessments show benefits of the proposed volume
standards from the factor(s) in question, others show negative impacts,
while still others show impacts with ambiguous or different directional
effects. Factors with analyses showing benefits of the proposed volume
standards include impacts on jobs, rural economic development, energy
security benefits, and the potential for climate benefits. Assessed
factors with analyses indicating costs or directionally negative
effects of the proposed volume standards include impacts on fuel costs,
water and soil resources, and impacts of induced land use change on
ecosystems. Our assessment of the effects of the proposed volume
standards on other factors show ambiguous or mixed directional impacts.
These factors include effects on the supply and price of some
agricultural commodities, air quality impacts, and impacts on
infrastructure. All the statutory factors are taken under
consideration, as is required by the statute, regardless of whether we
were able to quantify or
[[Page 25830]]
monetize the impact under the proposed volume standards on each of the
statutory factors.
1. Jobs and Rural Economic Development
In this section, we summarize our estimates of the impacts of the
Proposed Volumes on economy-wide employment and rural economic
development (both include direct, indirect, and induced impacts). These
analyses are described in detail in DRIA Chapter 9.
To estimate the impact of this proposed rule on jobs (relative to
the No RFS baseline), we applied the same two analytical approaches
described in Section IV.D--the ``rule-of-thumb'' approach and the use
of input-output modeling where feasible. These results are summarized
in Table V.H.1-1. For the corn ethanol case, using the results from the
IO analysis we have developed ranges of impacts for fuel volumes based
on uncertainty regarding how the volumes will be provided. For example,
volumes associated with new production capacity would also be
associated with some number of temporary construction jobs, while
expanded capacity utilization at existing facilities would not. These
ranges of potential impacts are summarized in tables in Chapter 9 along
with detailed explanations of the associated methodology.
We estimate that all three categories of renewable fuel we
analyzed--ethanol, BBD, and RNG--are associated with increases in jobs
to varying degrees. We observe that RNG appears to be associated with
the highest number of direct jobs created per unit of biofuel. However,
BBD is projected to have the highest job creation impact overall,
primarily due to substantially higher production increases relative to
the 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, mainly due to substantially higher
production increases relative to the 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, largely due
to substantially higher production increases relative to the baseline.
Table V.H.1-1 summarizes the estimated economy-wide job impacts and
rural GDP impacts (including direct, indirect, and induced impacts)
associated with the proposed volumes of ethanol, BBD, and RNG. These
estimates of rural GDP impacts are actual values as opposed to
discounted values, implying that they do not reflect the time value of
money.
Table V.H.1-1--Job Creation and Rural GDP Impacts of Proposed Volumes
[FTE; million 2022$]
----------------------------------------------------------------------------------------------------------------
2026 2027
---------------------------------------------------------------------
Fuel type Rural economic Rural economic
Jobs development Jobs development
----------------------------------------------------------------------------------------------------------------
RNG....................................... 19,504 1,072.16 20,240 1,112.59
BBD....................................... 92,285 9,742.30 96,749 10,213.54
Ethanol \a\............................... 5,332 366.19 5,735 393.83
---------------------------------------------------------------------
Total................................. 117,121 11,180.66 122,723 11,719.96
----------------------------------------------------------------------------------------------------------------
\a\ For the corn ethanol case alone, using NREL's JEDI module for dry mill corn ethanol we were able to generate
employment and income estimates under alternative scenarios and also carry out a sensitivity analysis. Please
refer to DRIA Chapter 9 for more details.
Our estimates are subject to the limitations and assumptions of the
methods employed. They are not meant to be exact estimates, but rather
to provide an estimate of general magnitude. In addition, our estimates
for jobs and rural development impacts are gross estimates and not net
estimates. To be more accurate, the job estimates are labor demand in
the directly regulated industry. We also acknowledge that, in the long
run, environmental regulations such as the RFS program typically affect
the distribution of employment among industries rather than the general
employment level.
We request comment on our approaches to estimating jobs and rural
economic development impacts associated with renewable fuels.
2. Energy Security
Our analysis shows that the Proposed Volumes would have a positive
impact on energy security by reducing U.S. reliance on foreign sources
of energy. Monetized energy security impacts of the Proposed Volumes
are summarized in Table V.H.2-1. Energy security and methods of
quantifying energy security impacts are discussed in Section IV.A and
DRIA Chapter 6.
Table V.H.2-1--Energy Security Impacts Estimates of the Proposed Volumes
[Million 2022$]
------------------------------------------------------------------------
3% Discount rate 7% Discount rate
------------------------------------------------------------------------
Present value (2025)........ $387 $366
Annualized value \a\........ 202 202
------------------------------------------------------------------------
\a\ Computing annualized costs and benefits from present values spreads
the costs and benefits equally over each period, taking account of the
discount rate. The annualized value equals the present value divided
by the sum of discount factors.
[[Page 25831]]
3. Climate Change
Our analysis of the effects of the Proposed Volumes on climate
change shows a range of potential GHG emissions impacts, from 29
million metric tons of cumulative CO2e reductions through
2055 (1 million metric tons annual average reductions) to 491 million
metric tons of cumulative CO2e reductions through 2055 (16
million metric tons annual average reductions). Although these
reductions are notable, the uncertainties involved in implementation
and the causal relationship between these emissions and climate change
considerations make it difficult to evaluate the extent to which such
reductions will meaningfully impact climate change. Methods for
estimating climate impacts are discussed in DRIA Chapter 5.
4. Fuel Costs
The methodology used to estimate fuel costs is summarized in
Section IV.B, while a detailed summary of the methodology is contained
in DRIA Chapter 10. The estimated fuel costs for the Proposed Volumes
(including the impacts of the proposed import RIN reduction provisions)
are presented in Tables V.H.4-1 through 3, while the estimated fuel
costs for the Volume Scenarios are summarized in Section IV.B.2.\168\
Fuel costs represent the costs of producing and using biofuels relative
to the petroleum fuels they displace. The net estimated cost impacts
are total social costs, excluding any subsidies and transfer payments,
and thus are incrementally added to all other societal costs. They do
not include benefits and other factors, such as the potential impacts
on soil and water quality or potential GHG reduction benefits. See DRIA
Chapter 10.4.2 for more detail on the estimated costs of this action.
---------------------------------------------------------------------------
\168\ More detailed information on the costs for the Proposed
Volumes is available in DRIA Chapter 10.4.2.
Table V.H.4-1--Aggregated Total Social Costs Relative to the No RFS
Baseline
[Million 2022$] \a\
------------------------------------------------------------------------
2026 2027
------------------------------------------------------------------------
Gasoline.......................... 188 206
Diesel............................ 7,456 5,871
Natural Gas....................... -150 -142
-------------------------------------
Total......................... 7,494 5,936
------------------------------------------------------------------------
\a\ Total cost of the renewable fuel expressed over the fossil fuel it
is blended into.
Table V.H.4-2--Per-Unit Costs Relative to No RFS Baseline
[2022$] \a\
----------------------------------------------------------------------------------------------------------------
Units 2026 2027
----------------------------------------------------------------------------------------------------------------
Gasoline...................................... [cent]/gal...................... 0.14 0.16
Diesel........................................ [cent]/gal...................... 14.22 11.30
Natural Gas................................... [cent]/thousand ft\3\........... -0.50 -0.49
Gasoline and Diesel........................... [cent]/gal...................... 4.07 3.26
----------------------------------------------------------------------------------------------------------------
\a\ Per-gallon or per thousand cubic feet cost of the renewable fuel expressed over the fossil fuel it is
blended into; the last row expresses the cost over the obligated pool of gasoline and diesel fuel.
Table V.H.4-3--Estimated Discounted Fuel Costs Impacts of the Proposed
Volumes
[Million 2022$]
------------------------------------------------------------------------
3% Discount rate 7% Discount rate
------------------------------------------------------------------------
Present value (2025)........ $12,871 $12,188
Annualized value \a\........ 6,726 6,741
------------------------------------------------------------------------
\a\ Computing annualized costs and benefits from present values spreads
the costs and benefits equally over each period, taking account of the
discount rate. The annualized value equals the present value divided
by the sum of discount factors.
5. Cost to Transport Goods
We also estimated the impact of the Proposed Volumes on the cost to
transport goods. However, it is not appropriate to use the social cost
for this analysis as the fuel prices include a number of other factors,
such as state and federal incentives, that we do not consider in our
social cost estimates. The per-unit costs from Table V.H.4-2 are
adjusted to reflect RIN price impacts and account for the biofuel
subsidies and other market factors, and the resulting values can be
thought of as retail costs. 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.\169\ Table
V.H.5-1 summarizes the estimated impacts of the Proposed Volumes
(including the impacts of the proposed import RIN reduction provisions)
on gasoline and diesel fuel prices at retail when the costs of each
biofuel is amortized over the fossil fuel it displaces. We note that
while the Proposed Volumes for 2026 and 2027 are higher than the 2025
baseline, the projected costs of this proposed rule are less than the
2025 baseline. This is primarily due to lower feedstock prices
resulting in lower projected costs of production for renewable fuels in
2026 and 2027 relative to 2025.
---------------------------------------------------------------------------
\169\ See DRIA Chapter 10.5 for more detailed information on our
estimates of the fuel price impacts of this action.
[[Page 25832]]
Table V.H.5-1--Estimated Effect of Proposed Volumes on Retail Fuel
Prices
[[cent]/gal]
------------------------------------------------------------------------
2026 2027
------------------------------------------------------------------------
Relative to No RFS Baseline:
Gasoline...................... 4.4 4.7
Diesel........................ 9.1 10.6
Relative to 2025 Baseline:
Gasoline...................... 0.0 0.0
Diesel........................ -1.0 -0.2
------------------------------------------------------------------------
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 V.H.5-1, the largest
projected price increase is 10.6[cent] per gallon for diesel fuel in
2027 for the No RFS Baseline.
The impact of fuel price increases on the price of goods can be
estimated based on a USDA study that analyzed the impact of fuel prices
on the wholesale price of produce.\170\ Applying the price correlation
from the USDA study indicates that the 10.6[cent] per gallon diesel
fuel cost increase raises retail prices by about 2.7 percent, which
would then increase the wholesale price of produce by about 0.7
percent. If produce being transported by a diesel truck costs $3 per
pound, the increase in that product's price would be $0.02 per
pound.\171\ 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.
---------------------------------------------------------------------------
\170\ USDA, ``How Transportation Costs Affect Fresh Fruit and
Vegetable Prices,'' Economic Research Report 160, November 2013.
\171\ Coupons.com, ``Comparing Prices on Groceries,'' May 4,
2021.
---------------------------------------------------------------------------
6. Conversion of Natural Lands, Water, Soil, and Ecosystem Impacts
Increases in volumes--particularly BBD volumes--attributable to
this action 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 habitat. This is discussed further
in DRIA Chapters 4.2 through 4.5.
7. Infrastructure
We evaluated the Proposed 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 Proposed Volumes and
potential changes that could occur with volume increase and future
demand. Based on our analysis, we project that the proposed renewable
fuel volumes will 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 DRIA Chapter 8.
8. Commodity Supply
We project that the supply of commodities used for biofuel
production, 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 most of the increase in the use of
agricultural commodities used for biofuel production will be met by
increased production of these feedstocks rather than diversion from
existing markets. See DRIA 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 air pollutant
concentrations due to the Proposed 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 pollutants in specific
locations across the U.S. Air quality impacts are discussed further in
DRIA Chapter 4.1.
10. Food and Commodity Prices
Our analysis indicates that the Proposed Volumes would have only a
minimal impact on agricultural commodity and food prices, with any
resulting price increases expected to be small. A summary of the
estimated impacts is provided in Table V.H.10-1, and further discussion
can be found in DRIA Chapters 9.3 and 9.4.
Table V.H.10-1--Estimated Effect of Proposed Volumes on Food and Agricultural Commodity Prices
----------------------------------------------------------------------------------------------------------------
Units 2026 2027
----------------------------------------------------------------------------------------------------------------
Corn Price Increase........................... $ per bushel.................... $0.03 $0.03
Soybean Oil Price Increase.................... $ per pound..................... 0.33 0.36
Soybean Meal Price Change..................... $ per short ton................. -63 -71
Projected Food Expenditure Increase........... $ per Consumer Unit............. 17.97 18.00
----------------------------------------------------------------------------------------------------------------
VI. Proposed Percentage Standards for 2026 and 2027
EPA implements the nationally applicable volume requirements by
establishing percentage standards that apply to obligated parties.\172\
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
[[Page 25833]]
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 separate standards under
the RFS program, there are likewise four separate RVOs applicable to
each obligated party for each year. As described in Section II.D, EPA
establishes applicable percentage standards for multiple future years
after 2022 in a single action for as many years as it establishes
volume requirements. The renewable fuel volumes used to determine the
2026 and 2027 percentage standards are shown in Table V.F-2.
---------------------------------------------------------------------------
\172\ See 40 CFR 80.1407 and 75 FR 14670 (March 26, 2010). As
discussed in the Set 1 Rule, EPA 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).
---------------------------------------------------------------------------
A. Calculation of Percentage Standards
The formulas used to calculate the percentage standards applicable
to obligated parties are provided in 40 CFR 80.1405(c). 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 gasoline and diesel projections provided by
EIA--specifically AEO2023, as this is the most recent projection from
EIA that covers 2026 and 2027.\173\ However, these projections include
volumes of renewable fuel (e.g., ethanol, biodiesel, renewable diesel)
used in gasoline and 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 projections of gasoline
and diesel as part of the percentage standard equations.\174\
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\173\ EIA recently issued AEO2025 on April 15, 2025. We intend
to use these updated projections in the final rule.
\174\ Further adjustments of these projections are discussed in
``Calculation of Proposed 2026 and 2027 RFS Percentage Standards,''
available in the docket for this action. Discussion of the overall
gasoline and diesel projection adjustment factor is discussed in RFS
Set 1 RIA Chapter 1.11. We may update this adjustment factor for the
final rule after further evaluating the projections and
methodologies used in AEO2025.
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B. Treatment of Small Refinery Volumes
In CAA section 211(o)(9), Congress provided for qualifying small
refineries to be temporarily exempt from RFS compliance through
December 31, 2010. Congress also provided in CAA section
211(o)(9)(A)(ii)(II) and (B)(i) that small refineries could receive an
extension of the exemption beyond 2010 based either on the results of a
required Department of Energy (DOE) study or in response to individual
petitions demonstrating that the small refinery suffered
``disproportionate economic hardship.''
There is currently significant uncertainty regarding the number of
small refinery exemption (SRE) petitions that could be granted for 2026
and 2027. While we stated that ``we anticipate that no SREs will be
granted for these future years'' in the Set 1 Rule (referring to 2023-
2025) due to the SRE Denial Actions that had recently been issued,\175\
subsequent court cases invalidated those actions.\176\ As a result, the
SRE Denial Actions were vacated and the majority of the SRE petitions
decided therein were remanded back to EPA. We have yet to take further
action on these petitions and are still determining how we will
evaluate and decide those petitions, which would then inform how we
would evaluate and decide any SRE petitions received for 2026 and 2027.
We expect to communicate our policy regarding SRE petitions going
forward before finalization of this rule.
---------------------------------------------------------------------------
\175\ EPA, ``April 2022 Denial of Petitions for RFS Small
Refinery Exemptions,'' EPA-420-R-22-005, April 2022; EPA, ``June
2022 Denial of Petitions for RFS Small Refinery Exemptions,'' EPA-
420-R-22-011, June 2022.
\176\ Calumet Shreveport Refining, LLC et al. v. EPA, 86 F.4th
1121 (5th Cir. 2023); Sinclair Wyoming Ref. Co.et al. v. EPA, 114
F.4th 693 (D.C. Cir. 2024).
---------------------------------------------------------------------------
While there remains uncertainty in the volume of gasoline and
diesel that will be exempt in 2026 and 2027, we have developed an
upper- and lower-bound estimate of this exempt volume. We currently
project that there are approximately 34 qualifying and operational
small refineries producing up to approximately 18 billion gallons of
gasoline and diesel each year, or about 10 percent of the total
reported volume of obligated gasoline and diesel. Therefore, the
potential range of exempt volumes from SREs that could be included in
the calculation specified by 40 CFR 80.1405(c) for 2026 and 2027 ranges
from zero gallons (if EPA denied all SRE petitions) to 18 billion
gallons (if EPA granted all SRE petitions).
We have used these estimates to calculate both an upper- and lower-
bound on the potential percentage standards for 2026 and 2027. While we
are still developing our new approach to evaluating SRE petitions, for
purposes of the proposed percentage standards in this action, we have
used a volume of 18 billion gallons of exempt gasoline and diesel
(i.e., all small refineries would be exempt from having to comply with
their 2026 and 2027 RFS obligations). We have also calculated what the
percentage standards would be if there were zero gallons of exempt
gasoline and diesel (i.e., all small refineries would have to comply
with their 2026 and 2027 RFS obligations). We expect that by the time
we finalize the standards for 2026 and 2027, we will have determined
our new approach to evaluating and deciding SRE petitions and will use
that new approach to inform our projection of the exempt volumes of
gasoline and diesel. In the meantime, these upper- and lower-bound
estimates provide stakeholders with a range of plausible outcomes on
which to provide comment. We note that a higher projection of exempt
volumes of gasoline and diesel would increase the percentage standards
and thus the individual RVOs for non-exempt obligated parties. Finally,
we note that regardless of the new approach for evaluating SRE
petitions, we do not plan to revise the percentage standards once
finalized to account for any subsequent changes to that policy or other
inaccuracies in the projection of exempt volumes of gasoline and
diesel.\177\
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\177\ 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.
---------------------------------------------------------------------------
This proposed rule, consistent with our regulations, proposes to
project the exempt volume of gasoline and diesel associated with SREs
for the 2026 and 2027 compliance years only. This proposed rule does
not address any exempt volume from the potential grant of SREs for
prior compliance years (i.e., 2025 and earlier). Comments on exemptions
for compliance years other than 2026 and 2027 will be treated as beyond
the scope of this action.
C. 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(c).\178\ Using
the volumes shown in Table V.F-2 and assuming 18 billion gallons of
exempt gasoline and diesel to represent the upper-bound estimate, we
have calculated the proposed percentage standards for 2026 and 2027, as
shown in Table VI.C-1.\179\ These percentage standards are included in
the proposed regulations at 40 CFR 80.1405(a) and would apply to
producers and importers
[[Page 25834]]
of gasoline and diesel. We have also calculated what the percentage
standards for 2026 and 2027 would be assuming zero gallons of exempt
gasoline and diesel, representing the lower-bound estimate of the
standards, also as shown in Table VI.C-1.
---------------------------------------------------------------------------
\178\ As described in Section X.C, we are proposing revisions
and clarifications to the percentage standard equations.
\179\ See ``Calculation of Proposed 2026 and 2027 RFS Percentage
Standards,'' available in the docket for this action.
Table VI.C-1--Proposed Percentage Standards for 2026 and 2027
----------------------------------------------------------------------------------------------------------------
Lower-bound estimate (0 gal exempt Upper-bound estimate (18 bil gal
G+D) exempt G+D)
---------------------------------------------------------------------------
2026 (%) 2027 (%) 2026 (%) 2027 (%)
----------------------------------------------------------------------------------------------------------------
Cellulosic biofuel.................. 0.77 0.82 0.87 0.92
Biomass-based diesel................ 4.24 4.52 4.75 5.07
Advanced biofuel.................... 5.37 5.70 6.02 6.40
Renewable fuel...................... 14.30 14.74 16.02 16.54
----------------------------------------------------------------------------------------------------------------
VII. Partial Waiver of the 2025 Cellulosic Biofuel Volume Requirement
In the Set 1 Rule, EPA promulgated RFS volume requirements and
percentage standards for 2023-2025. As part of that rulemaking, EPA
projected that 1.38 billion cellulosic RINs would be generated in 2025
and used that volume to establish the 2025 cellulosic biofuel
percentage standard of 0.81 percent.\180\ This projection was largely
based on the assumption that cellulosic RIN generation was primarily
constrained by cellulosic biofuel production and was therefore set
equal to projected production. However, we have now determined that the
main limitation for cellulosic RIN generation is the number of vehicles
capable of using cellulosic biofuel as transportation fuel.\181\
Consequently, we have updated our cellulosic biofuel projection
methodology to be constrained by the total consumption of vehicles
capable of using cellulosic biofuel. Based on this change, we now
project that only 1.19 billion cellulosic RINs will be generated in
2025, a shortfall of 0.19 billion RINs from the 1.38 billion RINs
projected in the Set 1 Rule. Due to this shortfall and reasons further
explained in Sections VII.A through C, we are proposing to partially
waive the 2025 cellulosic biofuel volume requirement to 1.19 billion
RINs (the projected cellulosic RIN generation in 2025) using the CAA
section 211(o)(7)(D) ``cellulosic waiver authority.''
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\180\ 40 CFR 80.1405(a).
\181\ See Section VII.B and DRIA Chapter 7.1.3.
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We currently project that the supply of advanced biofuel and total
renewable fuel in 2025 will exceed the required volumes by a
significant margin, despite the projected shortfall in cellulosic
biofuel. Given the projected surplus of 2025 advanced RINs, we are not
proposing to waive 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 paragraph
(3)(A),'' EPA ``shall reduce the applicable volume of cellulosic
biofuel required under paragraph (2)(B) to the projected volume
available during that calendar year'' and that this reduction shall be
made ``not later than November 30 of the preceding calendar year.'' For
those years in which EPA ``makes such a reduction,'' the statute
further provides that 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 EPA exercises its cellulosic waiver
authority, the determination of whether to correspondingly reduce the
total renewable fuel or advanced biofuel requirements is discretionary.
When EPA determines 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), EPA is then required
to reduce the applicable volume of cellulosic biofuel for that calendar
year. Pursuant to this provision, EPA set 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. EPA was
challenged regarding its interpretation of this statutory provision,
leading the D.C. Circuit to evaluate various aspects of EPA's
implementation of its cellulosic waiver authority.\182\ In 2013 in API,
the court held that EPA must take a ``neutral aim at accuracy'' in
determining the projected volume of cellulosic biofuel available.\183\
In API and Alon Refining Krotz Springs, Inc. v. EPA, the D.C. Circuit
upheld EPA's decision to use the Energy Information Administration's
(EIA's) projected volume of cellulosic biofuel production to inform
EPA's projection, without requiring ``slavish adherence by EPA to the
EIA estimate.'' \184\ In Sinclair Wyoming Refining Co. LLC, et al. v.
EPA, the D.C. Circuit upheld EPA's reading of the statutory phrase
``projected volume available'' to exclude carryover RINs.\185\
---------------------------------------------------------------------------
\182\ See, e.g., American Petroleum Institute v. EPA, 706 F.3d
474, 479 (D.C. Cir. 2013) (``API'') (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); Americans for Clean Energy v. EPA, 864 F.3d 691, 730 (D.C.
Cir. 2017) (``ACE'') (determining EPA's use of the cellulosic waiver
authority to reduce advanced and total renewable fuel was
reasonable); Sinclair Wyoming Refining Co. LLC, et al. v. EPA, 101
F.4th 871, 883 (2024) (``Sinclair'') (rejecting biofuels producers'
challenge that EPA must include carryover cellulosic RINs in its
determination of `` projected volume available during that calendar
year'').
\183\ API, 706 F.3d at 476.
\184\ Alon Refining Krotz Springs, Inc. v. EPA, 396 F.3d 628,
660 (D.C. Cir. 2019); API, 607 F.3d at 478.
\185\ Sinclair, 101 F.4th at 883-86.
---------------------------------------------------------------------------
EPA is proposing to implement 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 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. EPA has implemented the cellulosic
waiver authority to reduce the cellulosic biofuel volume after the
November 30 deadline on several
[[Page 25835]]
occasions.\186\ No party has specifically challenged EPA's use of the
cellulosic waiver authority after the November 30 deadline, but
petitioners have unsuccessfully challenged EPA's late issuance of
standards under other RFS provisions. The D.C. Circuit has concluded
that EPA retains the ability to issue late standards even when it acts
after the statutory deadlines have passed.\187\ We therefore rely on
our past practice in implementing the RFS program and favorable case
law to implement the cellulosic waiver 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.
---------------------------------------------------------------------------
\186\ 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).
\187\ See ACE, 864 F.3d at 721.
---------------------------------------------------------------------------
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. EPA
believes 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 EPA acts in a timely manner by
November 30 of the preceding year and when 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 EPA from acting after November 30.\188\
---------------------------------------------------------------------------
\188\ 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 EPA ``shall reduce the applicable
volume of cellulosic biofuel required under paragraph (2)(B) to the
projected volume available during that calendar year.'' EPA 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 EPA shall reduce the volume when the requisite
conditions are met.\189\
---------------------------------------------------------------------------
\189\ EPA acknowledges that it did not waive the 2023 cellulosic
biofuel volume requirement. See https://www.epa.gov/renewable-fuel-standard-program/epa-denial-petition-partial-waiver-2023-cellulosic-biofuel.
---------------------------------------------------------------------------
CAA section 211(o)(7)(D)(ii) directs EPA to make cellulosic waiver
credits (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 \190\ 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.\191\ 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.\192\
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\190\ 40 CFR 80.1456.
\191\ 72 FR 14726-27 (March 26, 2010).
\192\ See, e.g., 85 FR 7025 (February 6, 2020); 87 FR 39616
(July 1, 2022).
---------------------------------------------------------------------------
CAA section 211(o)(7)(D) provides that EPA may reduce the
applicable volume of total renewable fuel and advanced biofuel in years
when 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 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.\193\
---------------------------------------------------------------------------
\193\ Monroe v. EPA, 750 F.3d 909, 915 (2014). See, also, ACE at
721.
Using this discretion, EPA has, in the past, declined to reduce the
advanced biofuel and total renewable fuel volumes in certain
circumstances.\194\ In other circumstances, EPA has reduced the
advanced biofuel and total renewable fuel volumes using this
authority.\195\ It is worth noting that 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, EPA reduced the cellulosic biofuel volume by over 15 billion
gallons for 2022. Had EPA 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 EPA set the volume
requirements using our set authority, the partial waiver of the
cellulosic biofuel volume requirement is significantly smaller than in
prior years (0.19 billion gallons), in part due to the fact that
instead of starting with a statutory table volume set by Congress many
years ago, EPA itself established the volume requirements in 2023 under
the set authority. As discussed further in Section VII.B, we are not
proposing to adjust the 2025 total renewable fuel and advanced biofuel
volumes because those volumes are likely to be achieved in the market.
---------------------------------------------------------------------------
\194\ See, e.g., 78 FR 49794, 49811 (August 15, 2013).
\195\ See, e.g., 80 FR 77420 (December 14, 2015). 81 FR 89746
(December 12, 2016).
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B. Assessment of Cellulosic RINs Available for Compliance in 2025
Currently, nearly all cellulosic RINs are generated from the
production and use of biogas-derived CNG and LNG.\196\ To project total
cellulosic RIN generation for 2025, we first estimated the number of
CNG/LNG vehicles and their corresponding average consumption. Because
biogas-derived CNG/LNG generates RINs only when used as transportation
fuel, total CNG/LNG consumption--whether fossil- or biogas-derived--
sets the upper limit for potential RIN generation from biogas-derived
CNG/LNG. However, full replacement of total CNG/LNG usage with biogas-
derived fuel is unlikely due to infrastructure limitations, costs, and
[[Page 25836]]
other challenges. To account for this, we applied an efficiency factor
to estimate the portion of total CNG/LNG consumption that could
realistically be met with biogas-derived fuel and, in turn, the number
of cellulosic RINs that could be generated.\197\ While the majority of
cellulosic biofuel comes from biogas-derived CNG/LNG, small volumes of
liquid cellulosic biofuel have also contributed to total cellulosic
volumes and were therefore included in this estimate.\198\ Based on
this updated projection methodology, we estimate that cellulosic RIN
generation for 2025 will be 1.19 billion RINs.\199\
---------------------------------------------------------------------------
\196\ More than 95 percent of all cellulosic RINs generated in
2024 were attributed to CNG/LNG derived from biogas. See ``Total Net
Generation'' RIN data table at: https://www.epa.gov/fuels-registration-reporting-and-compliance-help/rins-generated-transactions.
\197\ See DRIA Chapter 7.1.3 and 7.1.4 for information on the
analysis for 2025 biogas-derived CNG/LNG volumes.
\198\ See DRIA Chapter 7.1.3 and 7.1.5 for information on the
analysis for 2025 liquid cellulosic biofuel volumes.
\199\ We intend to consider additional cellulosic RIN generation
data throughout the remainder of 2025 as it becomes available to
inform any final action.
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C. Proposed Partial Waiver of the 2025 Cellulosic Biofuel Volume
Requirement
1. 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 VII.A. EPA has determined
that ``the projected volume of cellulosic biofuel production is less
than the minimum applicable volume'' for 2025. In the Set 1 Rule, EPA
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.\200\ 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,\201\ when obligated parties
report to EPA their 2025 gasoline and diesel production and import
volumes.\202\ 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.\203\ We currently estimate that
only 1.19 billion cellulosic RINs are projected to be generated in
2025, representing the projected volume of cellulosic biofuel available
in 2025.\204\ This is 0.19 billion fewer RINs than the 1.38 billion
RINs needed to comply with the original 2025 cellulosic biofuel
standard, a shortfall of approximately 14 percent. We therefore find
that the circumstances have triggered the need for implementation of
the cellulosic waiver authority for 2025.
---------------------------------------------------------------------------
\200\ 88 FR 44470-71 (July 12, 2023).
\201\ 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).
\202\ 40 CFR 80.1451 and 80.1427(a).
\203\ 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, EPA 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).
\204\ See DRIA Chapter 7.1.3.
---------------------------------------------------------------------------
When EPA determines that a waiver of the cellulosic biofuel volume
requirement is appropriate under CAA section 211(o)(7)(D)(i), 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.\205\ EPA has 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.''
\206\ In determining the ``projected volume available,'' EPA must take
a ``neutral aim at accuracy.'' \207\
---------------------------------------------------------------------------
\205\ Sinclair, 101 F.4th at 883-86.
\206\ See, e.g., 87 FR 39600 (July 1, 2022); see also Sinclair,
101 F.4th at 883-86.
\207\ API v. EPA, 706 F.3d 474, 479 (D.C. Cir. 2013).
---------------------------------------------------------------------------
As discussed in Section VII.B, the projected volume of cellulosic
biofuel available in 2025 is 1.19 billion RINs. Thus, when the
cellulosic waiver authority is applied, EPA is only able to reduce the
2025 cellulosic biofuel volume to the projected volume available of
1.19 billion RINs. However, in accordance with the statute, EPA is 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.\208\ 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 unable to acquire sufficient cellulosic RINs to comply
with their 2025 cellulosic biofuel obligations--plus any cellulosic RIN
deficit carried from 2024--would be able to purchase CWCs to cover the
shortfall.\209\
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\208\ 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
EPA's website at: https://www.epa.gov/renewable-fuel-standard-program/cellulosic-waiver-credits-under-renewable-fuel-standard-program.
\209\ 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.
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Given that ``the projected volume of cellulosic biofuel production
is less than the minimum applicable volume'' for 2025, we are proposing
to implement the cellulosic waiver authority to waive the 2025
cellulosic biofuel volume requirement to 1.19 billion RINs, a reduction
of 0.19 billion RINs from the original volume requirement of 1.38
billion RINs. This proposed volume requirement matches the projected
cellulosic RIN generation for 2025 of 1.19 billion RINs.\210\
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\210\ We intend to consider additional cellulosic RIN generation
data throughout the remainder of 2025 as it becomes available to
inform any final action.
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Finally, CAA section 211(o)(7)(D) provides that EPA may reduce the
applicable volume of total renewable fuel and advanced biofuel in years
when 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 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.\211\ We
currently have insufficient data from 2025 to adequately project the
supply of advanced biofuel and total renewable fuel in 2025. Data from
previous years, however, indicate that there will likely be a
sufficient supply of RINs to meet the advanced biofuel and total
renewable fuel volume requirements. In 2023, advanced and total RIN
generation (8.99 billion RINs and 23.82 billion RINs, respectively)
significantly exceeded the required volumes (5.94 billion RINs and
21.54 billion RINs, respectively).\212\ Similarly, advanced
[[Page 25837]]
and total RIN generation in 2024 (10.42 billion RINs and 25.30 billion
RINs, respectively) exceeded not only the 2024 volume requirements
(6.54 billion RINs and 21.54 billion RINs, respectively) but also the
2025 volume requirements (7.33 billion RINs and 22.33 billion RINs,
respectively).\213\ These RIN generation numbers indicate that the
market is capable of meeting the 2025 advanced biofuel and total
renewable volume requirements after accounting for the projected
shortfall in cellulosic biofuel. Further, even if the market falls
short of the volume requirements in 2025, the significant oversupply of
RINs in previous years indicates that there will be sufficient
carryover RINs to make up for any shortfall in 2025.
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\211\ ACE, 864 F.3d at 730-734; see also Monroe Energy, LLC v.
EPA, 750 F.3d 909 (D.C. Cir. 2014).
\212\ See ``Total Net Generation'' RIN data table at: https://www.epa.gov/fuels-registration-reporting-and-compliance-help/rins-generated-transactions. This table includes all reported RINs that
were generated and not otherwise retired due to RIN generation error
(i.e., an invalid RIN). Thus, the volume of RINs in this table is
the volume of RINs that have been made available for compliance with
the RFS standards.
\213\ Id.
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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 is projected to provide
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.\214\
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\214\ 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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2. Economic Impact
The proposed partial waiver of the 2025 cellulosic biofuel volume
requirement is expected to have an economic impact. However,
quantitatively projecting the economic impact of this reduction is
challenging for several reasons. First, the proposed partial waiver is
due to a shortfall in the projected volume of cellulosic biofuel in
2025. Because of this, higher volumes of cellulosic RINs cannot simply
be made available at greater prices; instead, obligated parties will be
unable to purchase additional quantities of 2025 cellulosic RINs at any
price. The potential economic impact of this action is further
complicated by the fact that while some obligated parties can defer
some or all of their 2025 cellulosic biofuel obligation to 2026, other
obligated parties that carry cellulosic RIN deficits from 2024 into
2025 will be required to fully satisfy their cellulosic biofuel
obligations in 2025, including the cellulosic RIN deficits carried
forward from 2024. Any party that fails to do so would likely be in
non-compliance and could be subject to penalties.\215\
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\215\ We recognize that the cellulosic waiver authority is
mandatory, and thus would avoid the potential noncompliance and lack
of RINs described herein. Nevertheless, we describe these potential
outcomes to illustrate the difficulty in calculating the cost
savings of the action.
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Despite the complications associated with estimating the economic
impacts of this action, we can determine that it would result in cost
savings. We are proposing to reduce only the 2025 cellulosic biofuel
volume. Because we are not proposing to reduce the 2025 advanced
biofuel and total renewable fuel volumes, this action would effectively
replace the reduced cellulosic biofuel volume with additional volumes
of advanced biofuel, which generally has a lower marginal cost than
cellulosic biofuel.\216\
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\216\ The nested nature of the RFS program allows cellulosic
biofuel to be used to meet the advanced biofuel and total renewable
fuel volume requirements. Any cellulosic biofuel that can be
supplied beyond the required volume can be used in place of advanced
biofuel.
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Finally, we can reasonably project that because this action would
reduce demand for cellulosic RINs, it is expected to directionally
decrease cellulosic RIN prices. The exact magnitude of this price
reduction depends on a wide range of market factors that prevent us
from quantitively projecting a RIN price impact. At the same time,
because this action incrementally increases demand for advanced RINs,
it is projected to directionally increase BBD and advanced RIN prices.
We note, however, that this price impact is expected to be relatively
small, as this action would increase demand for advanced biofuel by the
magnitude of the proposed partial waiver of the 2025 cellulosic biofuel
volume requirement (0.19 billion RINs).
D. Calculation of Proposed 2025 Cellulosic Biofuel Percentage Standard
As described in Section VII.C, we are proposing to implement the
cellulosic waiver authority to partially waive the 2025 cellulosic
biofuel volume requirement from 1.38 billion RINs to 1.19 billion RINs.
As described in Section VI, 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(c). Using the same values
from the Set 1 Rule for the variables in this formula other than
RFVCB (the cellulosic biofuel volume),\217\ we have
calculated the proposed revised cellulosic biofuel percentage standard
for 2025 to be 0.70 percent, down from 0.81 percent.\218\ This
percentage standard is included in the proposed regulations at 40 CFR
80.1405(a) and would apply to producers and importers of gasoline and
diesel.
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\217\ 88 FR 44519-21 (July 12, 2023).
\218\ See ``Calculation of Proposed 2025 Cellulosic Biofuel
Percentage Standard,'' available in the docket for this action.
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VIII. Reduction in the Number of RINs Generated for Imported Fuels and
Feedstocks
A. Introduction and Rationale
In this action, we are proposing an ``import RIN reduction'' for
imported renewable fuel and renewable fuel produced domestically from
foreign feedstocks.\219\ Under this proposed approach, renewable fuel
producers and importers would generate 50 percent fewer RINs than they
generate for the same volume of import-based renewable fuel under the
current RFS regulations for RINs generated in 2026 and later years. The
proposed approach would not affect RINs generated in 2025 or earlier
years. Renewable fuel produced by domestic renewable fuel producers
using domestic feedstocks would continue to generate the same number of
RINs that they currently do. The import RIN reduction would apply to
all foreign-produced renewable fuel, regardless of whether those fuels
are produced from domestic or foreign feedstocks. The reduction of RINs
generated for import-based renewable fuel reflects the reduced
economic, energy security, and environmental benefits provided by these
fuels relative to renewable fuels produced domestically using domestic
feedstocks.
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\219\ Throughout this section we refer to imported renewable
fuel and renewable fuel produced domestically from foreign
feedstocks collectively as ``import-based renewable fuel'' and RINs
generated for these types of renewable fuel as ``import RINs.'' We
also refer to renewable fuel produced domestically from domestic
feedstocks as ``domestic-based renewable fuel.''
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This proposal is intended to support the statutory goals of energy
independence and the Administration's broader economic vision of
strengthening American energy independence and bolstering domestic
agricultural markets. By implementing an import RIN reduction, EPA aims
to reduce America's reliance on import-based renewable fuels, enhance
energy
[[Page 25838]]
security, promote domestic-based renewable fuel production, and keep
more of the economic benefits of the RFS program within the U.S., while
accomplishing the broader goals of the RFS program. We believe that an
import RIN reduction would align the RFS program with these goals. We
are also requesting comment on whether a higher or lower import RIN
reduction factor (i.e., more or less than the proposed 50 percent
reduction) would be appropriate.
The RFS program began in 2006 pursuant to the requirements of
EPAct, the stated purpose of which was to ``ensure jobs for our future
with secure, affordable, and reliable energy.'' \220\ The statutory
requirements of EPAct were codified in CAA section 211(o) and were
subsequently amended by EISA, the purpose of which was to ``move the
United States toward greater energy independence and security, to
increase the production of clean renewable fuels, to protect consumers,
to increase the efficiency of products, buildings, and vehicles, to
promote research on and deploy greenhouse gas capture and storage
options, and to improve the energy performance of the Federal
Government, and for other purposes.'' \221\ From the purpose statements
in these two enactments, where Congress' focus is clearly on American
jobs, American energy independence and security, and increasing the
production of American clean renewable fuels, it is evident that
Congress intended the RFS program to be a program for the benefit of
the American people generally and for certain important segments of the
American domestic economy specifically. We believe it is consistent
with this Congressional intent to take steps to ensure that most of the
economic value of the RFS program flows to American fuel and feedstock
producers rather than their foreign competitors.
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\220\ Public Law 109-58, 119 Stat. 594.
\221\ Public Law 110-140, 121 Stat. 1492.
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From the inception of the RFS program, EPA has allowed for imported
renewable fuel and renewable fuel produced domestically from foreign
feedstocks to generate RINs, provided EPA is assured that certain
statutory criteria have been met. EPA thus acknowledges that we have
historically placed import-based renewable fuel on an equal footing
with domestic-based renewable fuel. The number of RINs generated for
import-based renewable fuel has been the same as the number of RINs
generated for domestic-based renewable fuel.
While EPA has historically treated import-based renewable fuel as
equal to domestic-based renewable fuel, there is nothing in CAA section
211(o) that requires providing the same benefits to foreign entities as
domestic entities. CAA section 211(o)(5)(A) simply provides that EPA's
regulations must provide ``for the generation of an appropriate amount
of credits'' by entities covered by the RFS program, without further
specifying how ``an appropriate amount of credits'' should be
determined. The term ``appropriate'' necessarily leaves agencies with
flexibility to implement statutory programs, so long as that discretion
is exercised consistent with the context and structure in which the
term appears.\222\
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\222\ Michigan v. EPA, 576 U.S. 743, 752 (2015).
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In this action, EPA is proposing to modify the treatment of import-
based renewable fuels under the RFS program for the reasons discussed
below and in Section VIII.B. EPA requests comment on this issue and on
any relevant statutory interpretation issues that bear on EPA's
authority to differentiate among suppliers when assigning RINs for
reasons based on the statutes' language, legislative history, and
purposes.
1. Aligning the RFS Program With America's Economic Interests To
Support Domestic Agriculture and Rural Economies
As noted above, the purpose statements of both EPAct and EISA make
it clear that Congress intended the RFS program to, among other goals
discussed further below, support American agriculture and strengthen
rural economies in the U.S. While the RFS program has furthered these
goals, the recent influx of imported renewable fuels and feedstocks
threatens those gains and the RFS program's ability to build on them.
In 2021, import-based renewable fuel accounted for approximately 25
percent of the total biodiesel and renewable diesel supply. By 2024,
such imports surged to nearly 45 percent of the U.S. biodiesel and
renewable diesel market.\223\ By volume and value, much of this supply
comes from countries such as China and Brazil rather than supporting
American feedstock producers.
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\223\ See Section III.B.2 and DRIA Chapter 3.2 for more
information on EPA's estimate of imported vs. domestic supplies of
BBD in 2024.
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EPA is concerned that the increasing amounts of foreign feedstocks,
such as UCO and animal fats from China, Southeast Asia, and South
America, may be displacing U.S.-produced feedstocks like corn and
soybean oil in the renewable fuels market. This shift comes at a time
when American farmers are already struggling due to declining revenues.
According to USDA, net farm income is projected to fall by
approximately $32 billion from 2022 to 2024.\224\ Without EPA
intervention, these relatively cheap imports will continue to undercut
U.S. producers, reducing the economic value of the RFS program to
American feedstock and fuel producers, weakening support for rural
economies, and further harming U.S. farmers.
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\224\ USDA, ``Net Cash Income,'' Farm Income and Wealth
Statistics, February 6, 2025. https://data.ers.usda.gov/reports.aspx?ID=4024.
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The import RIN reduction proposed in this action would help
American farmers by ensuring demand for domestic-based renewable fuels.
Renewable fuel producers would be able to generate more RINs (and thus
realize greater RIN value) for renewable fuels produced from domestic
feedstocks relative to foreign feedstocks. This dynamic would increase
the willingness for domestic renewable producers to pay higher prices
for domestic feedstocks relative to foreign feedstocks because, all
else equal, they would be able to generate higher revenue for fuels
produced from domestic feedstocks. In turn, the higher prices offered
for domestic feedstocks would increase the revenue of domestic
feedstock producers and provide incentives for increased production of
domestic feedstocks. By ensuring support for domestic feedstocks and
fuels, it is our expectation that the proposed approach will revitalize
domestic demand for American crops, stabilize farm incomes, and
stimulate economic growth in rural communities.
Consistent with our understanding of the original Congressional
intent for the RFS program, EPA believes any economic benefits derived
from the RFS program should be retained in the U.S. to the maximum
extent practicable. We do not believe that Congress intended to create
a program to benefit foreign producers. However, there is significant
concern that the increased importation of feedstocks and fuels observed
above may indicate that such foreign producers are benefiting from the
economic incentives intended to stimulate rural American communities.
As a U.S. federal program, the RFS program was designed to promote
American agricultural prosperity. The proposed import RIN reduction
provisions further that goal and ensures American farmers and domestic
[[Page 25839]]
renewable fuel producers remain the primary beneficiaries of the RFS
program.
2. Strengthening U.S. Energy Security and Energy Independence
Reducing U.S. dependence on foreign energy sources is a cornerstone
of this Administration's energy policy. As discussed in detail in
Section IV and DRIA Chapter 6, it is also a foundational goal of the
RFS program. Although import-based renewable fuels contribute to U.S.
energy supply and help to hedge against reliance on foreign fossil fuel
producers, reliance on these imports risks creating the exact
vulnerabilities that the RFS program was intended to forestall. Global
supply chain disruptions, trade disputes, and geopolitical instability
can impact the renewable fuel and feedstock markets, leading to
increased price volatility across the RIN market, renewable fuel and
feedstock markets, and gasoline and diesel markets.
The import RIN reduction would encourage greater investment in
domestic-based renewable fuel production. By putting America's farmers
and renewable fuel producers first, the proposed import RIN reduction
provisions would also strengthen America's energy independence and
resilience by reducing exposure to global market disruptions and
securing self-reliance in the supply of domestic-based renewable fuels.
3. Protecting the Environment
The core objective of EPA--to protect human health and the
environment--is also the focus of our administration of the RFS
program. We believe that allowing import-based renewable fuels to have
equal RIN generation potential undermines this goal, particularly when
there are concerns over the validity of imported feedstocks.
One of the most widely used feedstocks used to produce import-based
renewable fuels is UCO. Substantial challenges already exist regarding
EPA's ability to verify whether the requirements for imported UCO under
the RFS program have been satisfied. Recently, industry experts have
raised additional concerns that some UCO shipments may be fraudulently
labeled or adulterated with unused palm oil. Propagation of palm trees
for oil production has devastating environmental costs and undermines
the GHG emissions-reduction goals of the RFS program.\225\ These
concerns contributed to the decision by the U.S. Department of Treasury
and Internal Revenue Service to not include pathways for imported UCO
in the initial 45ZCF-GREET model, making these fuels ineligible to
generate tax credits under that program.\226\ Similar concerns have led
the EU to consider suspending the mandatory recognition of the
certification of waste-based biofuels by the International
Sustainability and Carbon Certification.\227\
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\225\ S&P Global, ``New Biofuel Data Triggers Fresh Fraud
Concerns Over EU Imports,'' December 14, 2023.
\226\ Notice 2025-10, 2025-6 I.R.B. 682 (Feb. 3, 2025).
\227\ The Maritime Executive, ``EU Scrutinizes Fraud in
Certification of Biofuels,'' March 30, 2025.
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The proposed import RIN reduction provisions would not prohibit
imports but would instead signal to market participants that domestic-
based renewable fuels--manufactured under closely monitored U.S.
environmental standards--are preferable. By rewarding domestic-based
renewable fuels with full RIN generation potential, EPA would reinforce
environmental protection and strengthen the integrity of the RFS
program without sacrificing the flexibility to utilize import-based
renewable fuels when necessary.
4. Safeguarding the Original Intent of the RFS Program
In sum, the RFS program was designed with clear objectives: to
reduce GHG emissions, expand the U.S. renewable fuel sector in support
of domestic producers and rural economies, and decrease reliance on
foreign energy. However, the rising share of import-based renewable
fuel undermines these goals by:
Redirecting the economic benefits of the program away from
American farmers and rural communities.
Increasing America's exposure to volatile global fuel and
commodity trade dynamics.
Increasing America's reliance on foreign sources of fuel
and supplies necessary to produce fuel domestically.
By implementing the proposed import RIN reduction, EPA seeks to
restore the benefits of the RFS program to its originally intended
recipients. This approach would ensure that the program continues to
achieve these important goals while prioritizing domestic economic
prosperity.
B. Legal Authority
Historically, EPA used ``equivalence values'' to determine how many
RINs a given quantity of renewable fuel generates.\228\ In doing so, we
relied on CAA section 211(o)(5) to justify our method for allocating
RIN values for different renewable fuels. The equivalence values were
calculated based on the renewable fuel's energy content relative to a
gallon of ethanol, such that renewable fuels with a greater energy
potential were allowed to generate a more than one RIN per gallon.\229\
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\228\ See, e.g., 72 FR 23900, 23918-23922 (May 1, 2007) and 75
FR 14670, 14709-10, 14716-18 (March 26, 2010).
\229\ Id. We note that in this action we are not reopening our
approach to providing equivalence values established in the RFS2
Rule, nor any other equivalence values (other than those discussed
in Section X.A). Comments about equivalence values more generally
will be treated as beyond the scope of this action.
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We propose using the same statutory language to justify reduced RIN
generation for import-based renewable fuel. Section 211(o)(5)(A) states
that EPA ``shall provide'' for ``the generation of an appropriate
amount of credits by any person that refines, blends, or imports . . .
a quantity of renewable fuel'' and ``for the generation of an
appropriate amount of credits for biodiesel.'' In establishing
equivalence values, EPA highlighted these statutory provisions as
``evidence that Congress did not limit this program solely to a
straight volume measurement of gallons in the context of the RFS
program.'' \230\ Similarly, in this action we propose to find that the
statutory language ``appropriate amount of credits'' alongside the same
subsection's differentiation among parties who ``refine[ ], blend[ ],
or import[ ]'' renewable fuel allows EPA to determine that imported
renewable fuel (and renewable fuel made from foreign feedstocks) may be
assigned a lesser amount of credits as EPA determines is appropriate.
We additionally rely on the language in CAA section 211(o)(5)(A)(ii) to
determine that imported biodiesel (and biodiesel made from foreign
feedstocks) may be assigned a lesser amount of credits as EPA
determines is appropriate. As noted above, the term ``appropriate'' is
broad and flexible, and courts have recognized that Congress uses it to
leave agencies with flexibility to administer statutory programs
consistent with relevant context and structure.\231\
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\230\ 72 FR 23900, 23919 (May 1, 2007).
\231\ See, e.g., Michigan, 576 U.S. at 752.
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In doing so, EPA is not advancing a new interpretation of CAA
section 211(o)(5)(A). Rather, we are proposing a change in policy
consistent with EPA's existing understanding of that provision's
delegation of discretion. This new policy would further delineate the
amount of credits (i.e., RINs) that are ``appropriate'' for volumes of
renewable fuel depending on whether they are
[[Page 25840]]
imported--a factor the statute explicitly names as relevant to that
consideration.\232\ CAA section 211(o)(5)(A) is the kind of clear
Congressional delegation of discretion that ``leaves [the] agenc[y]
with flexibility'' signaled by specific terms such as ``appropriate.''
\233\ Although EPA has previously chosen to use this discretion to
assign equivalence values for RIN generation based on a fuel's energy
content, this was not an exclusive understanding of how EPA might
determine the ``appropriate'' amount of credits to award. EPA may also
determine that the ``appropriate amount of credits'' awarded for ``a
quantity of renewable fuel'' should vary on other bases, including
whether the credits are awarded to a ``person that refines, blends, or
imports'' the fuel. Consistent with that understanding, we are
proposing to appropriately reduce the RIN value for imported renewable
fuel and renewable fuel made from foreign feedstocks.
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\232\ ``[W]hen a particular statute delegates authority to an
agency consistent with constitutional limits, courts must respect
the delegation, while ensuring that the agency acts within it.''
Loper Bright Enters. v. Raimondo, 603 U.S. 369, 413 (2024).
\233\ Id. at 394-95 (quoting Michigan, 576 U.S. at 752).
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In proposing this policy change, EPA is observing the relevant
procedural standards by acknowledging how the new policy departs from
the status quo; by demonstrating the new policy is permissible under
the statute and that ``there are good reasons for it;'' and by
asserting, as this section does, that the agency believes the new
policy is an improvement upon the status quo.\234\ EPA requests comment
on this change in policy, including on any legitimate reliance
interests on the prior policy that EPA should consider during this
rulemaking.\235\
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\234\ FCC v. Fox Television Stations, Inc., 556 U.S. 502, 515
(2009).
\235\ Id.
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C. Implementation
To implement the proposed import RIN reduction for import-based
renewable fuel, we are proposing to specify under 40 CFR 80.1426(a)
that the following parties must reduce the number of RINs generated for
the specified renewable fuel by 50 percent:
RIN-generating foreign producers, for all renewable fuel
produced.
RIN-generating importers of renewable fuel, for all
imported renewable fuel.
Domestic renewable fuel producers, for all renewable fuel
produced from foreign feedstocks or foreign biointermediates.
We believe this is the most straightforward way to implement the
proposed import RIN reduction, rather than proposing a separate set of
RIN generation equations for import RINs. We request comment on the
proposed import RIN generation requirement, and whether there are
alternative RIN generation approaches that we should consider for
implementing the import RIN reduction.
Since we are proposing that the import RIN reduction would apply to
all foreign-produced renewable fuel, regardless of whether it is
produced from domestic or foreign feedstocks, we are not proposing any
additional requirements for RIN-generating importers of renewable fuel
and RIN-generating foreign renewable fuel producers. They would only be
able to generate import RINs for the renewable fuel they produce or
import, and thus no changes would be necessary in their registration,
recordkeeping, reporting, or attest engagement requirements.
However, there remain potential concerns regarding mislabeling of
foreign feedstocks under the RFS program. We are concerned that bad
actors may try to claim foreign feedstock as domestic to gain a
financial benefit. Thus, to ensure that domestic renewable fuel
producers are generating the appropriate number of RINs for each batch
of renewable fuel they produce, we are proposing several changes to
their recordkeeping, reporting, attest engagement, and quality
assurance plan (QAP) requirements that we believe are minimally onerous
while protecting domestic feedstock producers. First, we are proposing
that all domestic renewable fuel producers be required to keep records
of feedstock purchases and transfers (e.g., bills of sale, delivery
receipts) that identify the feedstock point of origin for each
feedstock (i.e., domestic or foreign). We expect that most domestic
renewable fuel producers already keep such records as part of their
existing business practices or other existing RFS recordkeeping
requirements, and thus there should be no additional recordkeeping
burden for most of these producers.
Feedstock point of origin would depend on the feedstock type but
would generally be considered to be the location, either domestic or
foreign, where a feedstock is grown, produced, generated, extracted,
collected, or harvested. More specifically, we are proposing the
following specific provisions related to what is considered the
``feedstock point of origin'' for each feedstock type:
For planted crops, cover crops, or crop residue (including
starches, cellulosic, and non-cellulosic components thereof), the
location of the feedstock supplier that supplied the feedstock to the
renewable fuel producer or biointermediate producer (e.g., grain
elevator).
For oil derived from planted crops, cover crops, or algae,
the location where the oil is extracted from the planted crop, cover
crop, or algae (e.g., crushing facility).
For biogenic waste oils/fats/greases, separated yard
waste, separated food waste, or MSW (including the components thereof),
the location of the establishment where the waste is collected (e.g.,
restaurant, food processing facility).
For biogas, the location of the landfill or digester that
produces the biogas.
For planted trees, tree residue, slash, pre-commercial
thinnings, or other woody biomass, the location where the woody biomass
is harvested.
For all other feedstocks, the location where the feedstock
is grown, produced, or generated, as applicable.
Second, we are proposing that domestic renewable fuel producers
would need to report the feedstock point of origin (i.e., domestic or
foreign) as part of their renewable fuel batch reports under 40 CFR
80.1451(b)(1)(ii)(L). This would help ensure that domestic renewable
fuel producers are generating the correct number of RINs for their
renewable fuel.
Finally, we are proposing to add clarifying language for attest
engagement auditors and QAP providers regarding verifying feedstock
points of origin. For attest engagements, we are proposing to clarify
that the existing requirement for auditors to ``[v]erify that
feedstocks were properly identified'' in batch reports also includes
verifying that the feedstock point of origin was correctly
reported.\236\ Similarly, for QAP, we are also proposing to clarify
that the existing requirements for QAP providers to ``[v]erify that
appropriate RIN generation calculations are being followed'' include
ensuring that the value applied reflects the feedstock's point of
origin.\237\ These clarifications would ensure that attest auditors and
QAP providers verify that RINs are properly generated by domestic
renewable fuel producers with domestic feedstocks.
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\236\ 40 CFR 80.1464(b)(1)(v)(B).
\237\ 40 CFR 80.1469(c)(3)(vii).
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We request comment on both the proposed recordkeeping, reporting,
attest engagement, and QAP requirements and the definition of
``feedstock point of origin,'' particularly
[[Page 25841]]
on the proposed origin locations for each feedstock type and whether
there are any other feedstock types that should have specified origin
locations.
IX. Removal of Renewable Electricity From the RFS Program
While EPA has, in the past, taken actions to allow RIN generation
for renewable electricity (commonly referred to as eRINs), in this
action we are proposing to remove renewable electricity as a qualifying
renewable fuel under the RFS program and the implementing regulations
that allow for renewable electricity to generate RINs.
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 non-liquid biofuels, such as those produced from
biogas, may qualify as renewable fuel. Thus, renewable fuels under the
RFS program can be broadly categorized as liquid biofuels, such as
ethanol or biodiesel, or non-liquid biofuels, such as renewable CNG/LNG
that is produced from qualifying biogas (that is in turn produced from
qualifying renewable biomass), so long as these fuels are used as
transportation fuel. Non-liquid renewable fuels have played a part in
the RFS program since the RFS2 Rule was promulgated in 2010. In that
final rule, EPA 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, EPA 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[ ].'' \238\ 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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\238\ 74 FR 14670, 14686 (March 26, 2010).
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Pursuant to the determination that renewable electricity is, in
certain circumstances, a qualifying renewable fuel, EPA also, in the
RFS2 Rule, 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 made
from renewable biomass and used as transportation fuel. In doing so,
EPA discussed the relevant differences between liquid and non-liquid
renewable fuels and established regulatory provisions for renewable
electricity that recognized those distinctions.\239\
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\239\ 75 FR 14670, 14729 (March 26, 2010).
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In 2010, EPA also promulgated a definition of ``renewable
electricity'' to ``clarify that electricity must meet the definition of
renewable fuel in order to qualify for RINs.'' \240\ In 2014, EPA
established novel RIN-generating pathways for electricity produced from
biogas from landfills and waste digesters.\241\ These pathways
currently exist in Rows Q and T of Table 1 to 40 CFR 80.1426. In the
same 2014 rulemaking, EPA updated the regulations governing RIN
generation for renewable electricity; it is these 2014 RIN generation
provisions that currently exist in the regulations at 40 CFR
80.1426(f)(10)(i) and (f)(11)(i). 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.\242\
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\240\ 75 FR 26026, 26031 (May 10, 2010).
\241\ 79 FR 42128 (July 18, 2014).
\242\ 40 CFR 80.1426(f)(10)(i), (f)(11)(i).
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Even though renewable electricity has been part of the RFS program
since 2010, and a pathway has existed since 2014 for renewable
electricity produced from biogas, EPA has not, to date, registered any
party to generate RINs for renewable electricity. Since 2014, several
stakeholders have submitted registration requests to generate RINs for
renewable electricity produced from biogas. EPA has reviewed these
registration requests and met with a range of stakeholders. However, as
early as 2016, EPA recognized that structuring a framework to allow for
the generation of RINs for renewable electricity produced from biogas
under the RFS program presented unique, unanticipated policy and
implementation questions that would need to be resolved prior to
registering any party, particularly in light of the competing policy
preferences of stakeholders.\243\ Based on (1) our review of
registration requests, (2) information gathered from stakeholders via
both comments provided in response to EPA requests and ongoing
discussions, and (3) an analysis of how to best incorporate renewable
electricity into the RFS program, we concluded that EPA's existing
regulations governing the generation of RINs for renewable electricity
produced from biogas were insufficient to guarantee overall
programmatic integrity, especially in light of the range of different
and often competing approaches proposed by registrants.\244\
Specifically, because the regulations allow any party that can
demonstrate compliance with the applicable requirements to be the RIN
generator, it is possible under the current regulations for multiple
parties (from independent registrations) to claim RIN generation for
the same quantity of renewable electricity. Such double counting is
contrary to the regulations themselves and further undermines EPA's
ability to ensure that the statutory volumes are met.\245\ As a result,
we determined that a new regulatory program would be necessary to allow
the generation of RINs representing renewable electricity. The ``eRIN''
regulatory program for renewable electricity proposed in December 2022
as part of the Set 1 NPRM was intended to revise the existing
regulations governing renewable electricity to allow RIN generation
under these pathways.\246\ 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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\243\ See, e.g., 81 FR 80828, 80890-96 (November 16, 2016).
\244\ Id.; 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).
\245\ See CAA section 211(o)(2)(A)(i) (EPA's regulations must
``ensure that transportation fuel sold or introduced into commerce
in the United States . . . on an annual average basis, contains at
least the applicable volume of renewable fuel, advanced biofuel,
cellulosic biofuel, and biomass-based diesel . . .'').
\246\ 87 FR 80582 (December 30, 2022).
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B. Statutory Basis for Removal of Renewable Electricity From the RFS
Program
EPA is proposing to remove renewable electricity as a qualifying
renewable fuel from the RFS program. As discussed in Section IX.A,
although EPA in the RFS2 Rule determined that
[[Page 25842]]
electricity could participate in the RFS program and promulgated
regulations for the generation of RINs for renewable electricity, no
RINs representing renewable electricity have ever been generated. In
this action, we are proposing to reverse the determination in the RFS2
Rule that renewable electricity is eligible to generate RINs under the
RFS program.
We are proposing to remove renewable electricity from the RFS
program on the ground 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.'' EPA has 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.\247\ While EPA previously, in 2010, assumed that
renewable electricity could meet this definition, we are now revisiting
the statutory analysis based on the text of the statute and consistent
with intervening Supreme Court decisions on standards for statutory
interpretation.
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\247\ 87 FR 80582, 80634 (December 30, 2022); 87 FR 73956-57
(December 2, 2022) (discussing what fuels can generate RINs).
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EPA's 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 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,''
both of which imply that there must be a measurable physical volume of
fossil fuel that is present in a transportation fuel and that volume
must be ``replace[d] or reduce[d]'' by the renewable fuel. Because
electricity cannot replace or reduce a volume of fossil fuel that is
present in a motor vehicle or motor vehicle engine, it does not meet
the definition of renewable fuel in the statute. That is, electricity
is not fungible with a fossil fuel in a motor vehicle or motor vehicle
engine.
In contrast, biogas that is cleaned up into RNG (and then
compressed into CNG/LNG) can replace and reduce fossil natural gas that
is present in a motor vehicle or motor vehicle engine that runs on CNG/
LNG, and therefore satisfies this portion of the renewable fuel
definition. But because electricity cannot physically displace fossil
fuel present in a motor vehicle or motor vehicle engine, it does not.
Biogas-generated electricity does not result in a physical reduction in
the ``quantity of fossil fuel present in a transportation fuel,'' nor
is the biogas that is replacing fossil natural gas itself present in a
transportation fuel in ``motor vehicles, motor vehicle engines, nonroad
vehicles, or nonroad engines.'' Instead, the biogas is burned at an
electric generating unit, and the resulting electricity is transmitted
on the grid for use to charge batteries present in motor vehicles. The
use of the term ``present in transportation fuel'' indicates that the
requirement intends to increase the renewable fuel contained within
fossil-fuel transportation fuel itself, not to substitute electricity
for such fuel.
Additionally, we note that ``electricity'' is not mentioned by name
in CAA section 211(o), in contrast to over fifty references to liquid
fuels. The RFS 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. Although there is no statutory definition of ``fuel''
under the RFS program, the widely accepted definition is ``a material
used to produce heat or power by burning.'' \248\ Electricity, which is
an energy carrier and not a fuel under this paradigm, cannot be burned
nor can it be measured in physical units. The frequent references to
physical units in the RFS statutory language, along with the inability
of electricity to be quantified by the referenced units, implies that
the RFS was intended to only include liquid and gaseous fuels. Thus, we
are also proposing to determine that electricity does not qualify as a
fuel under the RFS program.
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\248\ See, e.g., EPA, ``Definition of Fuel,'' September 25,
2024. https://www.epa.gov/rmp/definition-fuel. See also, Merriam-
Webster definition of fuel, available at https://www.merriam-webster.com/dictionary/fuel.
---------------------------------------------------------------------------
C. Implementation of Proposed Removal of Renewable Electricity From the
RFS Program
Our proposed determination that electricity is not a renewable fuel
is effectuated in several ways. First, we are proposing to remove the
definition of ``renewable electricity'' from the definitions in 40 CFR
80.2. Second, we are proposing to remove 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 RIN separation requirements in 40
CFR 80.1429, and all associated registration, reporting, and
recordkeeping requirements in 40 CFR 80.1450, 80.1451, and 80.1454.
EPA requests comment on its statutory analyses and on its proposed
conclusions that: (1) Renewable electricity does not meet the
definition of renewable fuel because it does not ``replace or reduce
the quantity of fossil fuel present in a transportation fuel,'' and (2)
Electricity is not a fuel under the RFS program. EPA further requests
comment on its proposed decision, based on these analyses and
conclusions, to remove from the RFS regulations all provisions related
to renewable electricity including, but not limited to the definition
of and pathways for renewable electricity and the generation of RINs
for renewable electricity.
X. Other Changes to RFS Regulations
A. Renewable Diesel, Naphtha, and Jet Fuel Equivalence Values
We are proposing to revise 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. By not accounting for the hydrogen produced from fossil
natural gas in these fuels, we are effectively allowing these
hydrotreated fuels to generate RINs for non-renewable content. This
approach 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
[[Page 25843]]
generally comprised partially of fossil fuel-based methanol).\249\
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\249\ 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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To properly account for the fossil-derived hydrogen found in most
renewable diesel, naphtha, and jet fuel, we are proposing to reduce the
equivalence values for these fuels. Specifically, we are proposing to
reduce the equivalence value for renewable diesel specified in 40 CFR
80.1415(b) to 1.6. We are also proposing to specify equivalence values
of 1.4 for renewable naphtha and 1.6 for renewable jet fuel.
Equivalence values for these fuels are not currently specified in 40
CFR 80.1415(b), but are instead determined on a facility-by-facility
basis using an equation specified in 40 CFR 80.1415(c). Previously
approved equivalence values for naphtha range from 1.4 to 1.5 with the
majority approved at 1.5, and for renewable jet fuel range from 1.6 to
1.7, with the majority approved at 1.6.\250\
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\250\ 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 proposed equivalence values for renewable diesel, naphtha, and
jet fuel are based on our technical assessment of the proportion of
these fuels that are derived from renewable biomass and would better
align the equivalence values of these fuels with the approach used for
other biofuels that contain non-renewable content described above.\251\
We note, however, that producers or importers would continue to be able
to submit an application for an alternative equivalence value pursuant
to 40 CFR 80.1415(b)(7).
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\251\ See ``Calculation of Proposed Equivalence Values for
Renewable Diesel, Naphtha, and Jet Fuel,'' available in the docket
for this action.
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We recognize that the proportion of these fuels that is produced
from renewable biomass will vary slightly depending on a number of
factors, such as the feedstock used to produce the renewable diesel,
naphtha, or jet fuel. An alternative approach to reducing the
equivalence values for these fuels as proposed would be to require each
renewable fuel producer to determine the proportion of the renewable
diesel, naphtha, or jet fuel that is produced from renewable feedstock
on a batch-by-batch basis. This alternative approach would require a
significant investment from both EPA and the renewable fuel producer to
determine an acceptable methodology for calculating the renewable
content of these fuels in the absence of a direct measurement technique
and to execute the agreed-upon protocols on an ongoing basis. We do not
expect that the number of RINs generated under this alternative
approach would vary sufficiently from those under our proposed approach
such that the additional burden on the renewable fuel producer would be
warranted.
We also acknowledge that the proportion of these fuels that is
produced from renewable biomass will vary slightly depending on the
definition of ``produced from renewable biomass.'' In this action we
are not proposing a definition of produced from renewable biomass.
Nevertheless, we believe it is appropriate to propose revised
equivalence values for renewable diesel, naphtha, and jet fuel prior to
resolving the definition of produced from renewable biomass. The
difference in the proportion of these fuels that can be considered
produced from renewable biomass using an energy-based approach and a
mass-based approach, the two primary approaches to the definition of
produced from renewable biomass considered in the Set 1 Rule, are
relatively small.\252\ In light of the similar outcomes for these fuels
between the two approaches, it is not appropriate to continue to allow
these fuels to generate a greater number of RINs than would be the case
under either approach to the definition of produced from renewable
biomass.
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\252\ Id.
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We would intend to implement these proposed changes by deactivating
any pathways with these impacted equivalence values prior to the
effective date of the final rule (typically 60 days after publication
of the final rule in the Federal Register. To avoid any disruption,
currently registered renewable fuel producers utilizing these impacted
pathways would need to update their registrations with EPA by the
effective date.
We are requesting comment on alternative approaches to recognizing
and accounting for the non-renewable content found in most renewable
diesel, naphtha, and jet fuel. We are also aware that some producers of
renewable diesel, naphtha, and jet fuel have explored producing these
fuels using hydrogen that is produced from qualifying renewable biomass
rather than from fossil natural gas. We are not proposing new pathways
or equivalence values for parties using renewable hydrogen to produce
renewable diesel, naphtha, or jet fuel in this action as significant
outstanding issues remain. These issues include developing an approach
to evaluating the lifecycle GHG emissions for hydrogen used in
renewable diesel naphtha, and jet fuel production and how to account
for renewable hydrogen used in a hydrotreating process that is not
incorporated into the fuel. However, we are requesting comment on how
to recognize the potential for greater renewable content that can be
achieved using renewable hydrogen in a future action.
B. RIN-Related Provisions
1. RIN Generation and Assignment
Since EPA 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 are proposing regulations
to specify when RINs must be generated and assigned both for renewable
fuel and for RNG. Specifically, we are proposing in 40 CFR
80.1426(f)(18) that RINs for most renewable fuels 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, the point
of importation into the covered location.
We are also proposing 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 when title is transferred
from the foreign producer to the RIN-generating importer.
Furthermore, we are proposing in 40 CFR 80.1426(e) that, except for
RNG and 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 proposing that RINs for
RNG and renewable fuels
[[Page 25844]]
that are gaseous at STP must be assigned to a volume of RNG or
renewable fuel at the same time the RIN is generated for the RNG or
renewable fuel. We request comment on these proposed deadlines for RIN
generation and assignment.
2. Pure and Neat Biodiesel Used for Process Heat or Power Generation
The CAA and RFS regulations prohibit RIN generation for fuel that
does not replace or reduce the quantity of fossil fuel present in a
transportation fuel, heating oil, or jet fuel. Pure biodiesel (i.e.,
B100) or neat biodiesel (i.e., B99) used for process heat or power
generation is not a transportation fuel or jet fuel and does not
qualify as heating oil under paragraph (1) of the definition of heating
oil under 40 CFR 80.2 because: (1) It is not commonly or commercially
known as heating oil, and (2) It is not sold for use in furnaces,
boilers, or similar applications.\253\ As to the first criterion, pure
or neat biodiesel is not commonly known as heating oil and has several
natural qualities that make it problematic as a heating oil, the
primary issue being that biodiesel gels at low temperatures and could
negatively impact the equipment being fueled by biodiesel (e.g., by
clogging filters). As to the second criterion, pure or neat biodiesel
is not typically sold for use in furnaces, boilers, or similar
applications. Therefore, biodiesel producers that use some of the
biodiesel they produce for process heat or that sell biodiesel to power
plants cannot generate RINs on the volumes used for process heat or
power generation. As such, we are proposing to clarify that RINs cannot
be generated for pure or neat biodiesel that is used for process heat
or power generation by 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.'' We request comment on the proposed clarification that
RINs cannot be generated for pure or neat biodiesel used for process
heat or power generation.
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\253\ EPA has already made clear that fuel oils used for process
heat or power generation do not qualify as heating oil under
paragraph (2) of the definition of ``heating oil'' under 40 CFR
80.2. 78 FR 62462 (October 22, 2013).
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C. Percentage Standard Equations
We are proposing several changes to the percentage standard
equations in 40 CFR 80.1405(c).\254\ First, we are proposing to clarify
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 currently 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).\255\ 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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\254\ EPA's proposed changes to the percentage standard formulas
are limited to the changes proposed here. We are not seeking comment
on or reopening any other aspects of the percentage standard
formulas, including the factors that project exempt volumes of
gasoline and diesel due to small refinery exemptions.
\255\ 75 FR 14709-10, 16-18 (March 26, 2010).
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Second, we are proposing to change 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.\256\ 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 multiplier'') 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 multiplier (either 1.5 (from 2010-
2022) or 1.6 (from 2023-2025)). As discussed in Sections III and V,
since the promulgation of the RFS2 Rule, fuels other than biodiesel and
with different equivalence values than biodiesel, most prominently
renewable diesel, have become significant contributors to the BBD
volume requirement. This 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. Our proposal to reduce the number of RINs generated for
imported renewable fuel and renewable fuel produced from foreign
feedstocks (discussed in Section VIII) would further complicate this
issue.
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\256\ 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).
---------------------------------------------------------------------------
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 proposing to revise the definition of RFVBBD,i to
specify that the BBD volume requirement is expressed in gallon-RINs
rather than gallons. We believe that specifying the BBD volume
requirement in gallon-RINs would reduce confusion among stakeholders
regarding how to interpret the BBD volume requirement and how the BBD
percentage standard is calculated.
Consistent with this proposed clarification, we are also proposing
to revise the BBD percentage standard to remove the 1.6 multiplier. By
specifying the BBD volume requirement in RIN gallons, the BBD
multiplier would no longer be necessary to convert from physical
gallons of BBD to gallon-RINs. This would also eliminate the need to
track the average equivalence value of BBD to adjust the BBD multiplier
in the future, which EPA recently revised from 1.5 to 1.6 in the Set 1
Rule due to increased production volumes of renewable diesel relative
to biodiesel.\257\
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\257\ 88 FR 44545-47 (July 12, 2023).
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We are also proposing to remove the terms GSi,
DSi, RGSi, and RDSi from the
percentage standard equations. These terms relate to the use of
gasoline, diesel, or renewable fuels contained in gasoline or 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
[[Page 25845]]
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 EPA to opt-in to the RFS program under Sec.
80.1443.'' \258\ 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.
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\258\ 40 CFR 80.2.
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Finally, we are proposing to revise the definitions of
RGi and RDi (the amounts of renewable fuel
projected to be blended into 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 blended into gasoline and diesel. While the
EIA projections of gasoline and diesel used by EPA 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 diesel
and renewable fuels blended into diesel (e.g., biodiesel and renewable
diesel). Thus, were we to use these projections to calculate the
percentage standards, we would use the petroleum-based diesel
projection for Di and a value of zero for RDi, as
the Di projection does not contain any renewable fuel.\259\
We believe this clarification makes clear how we would calculate the
percentage equations under this potential future scenario. We request
comment on these proposed changes to the percentage standard equations.
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\259\ Note that the proposed percentage standards in this action
are calculated using projections from AEO2023, which does include
renewable fuels in its projections of gasoline and diesel.
---------------------------------------------------------------------------
D. Existing Renewable Fuel Pathways
Table 1 to 40 CFR 80.1426 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
type, feedstock, and process) described in Table 1 may submit a
registration application to EPA.\260\ Table 1 lists an applicable RIN D
code for each approved pathway based on the type of fuel produced,
whether it is produced from cellulosic biomass, and whether it
satisfies the statutory 20 percent, 50 percent, or 60 percent lifecycle
GHG emissions reduction threshold. In Section X.D.1, we are proposing
clarifications to certain pathways in Table 1. In Section X.D.2, we are
proposing to add pathways to Table 1 for naphtha and liquefied
petroleum gas (LPG) produced from biogenic waste oils, fats and
greases. We request comment on all these proposed changes to the
eligible fuel pathways in Table 1.
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\260\ Note that an individual row in Table 1 can include
multiple fuel pathways.
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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,\261\ the CAA also requires that qualifying
biofuels meet the lifecycle GHG reduction threshold specified for the
applicable category of renewable fuel.\262\ The CAA further requires
EPA to determine the lifecycle GHG emissions for renewable fuels.\263\
EPA has evaluated the lifecycle emissions associated with fuel pathways
and listed the pathways it has analyzed that satisfy the statutory GHG
reduction criteria in Table 1 to 40 CFR 80.1426. To do so, EPA
necessarily evaluates particular feedstocks that are put through
particular production processes to produce particular fuels. Thus, an
approved pathway in Table 1 signifies that EPA has determined that the
specific combination of elements we evaluated meets the applicable GHG
reduction threshold.
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\261\ CAA section 211(o)(1)(J).
\262\ CAA sections 211(o)(1)(B), (D), (E); 211(o)(2)(A)(i).
\263\ CAA section 211(o)(1)(H).
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In 2010 when EPA promulgated the initial set of pathways in Table 1
as part of the RFS2 Rule, the range of commercially available
technologies for producing renewable fuels was relatively limited, but
there was an expectation that other nascent technologies would be
developed over time to the point of commercialization. Given the
information available at the time, EPA believed that the lifecycle
analyses it had conducted for certain pathways provided sufficient
basis to approve other pathways with similar feedstocks, production
process technologies, and fuels.\264\ For example, based on the
biochemical and thermochemical production processes that we modeled for
producing ethanol from switchgrass and corn stover, EPA included
several other cellulosic feedstocks in Rows K and L of Table 1 and
described the production process as ``Any.'' Thus, some of the pathway
descriptions in Table 1 are quite broad (i.e., they provide that the
approved pathway can include ``any'' production process).
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\264\ For example, see discussion of ``assessments of similar
feedstocks sources'' at 75 FR 14792-14797 (March 26, 2010).
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However, over the life of the RFS program, many fuel production
processes have been developed that vary from those assumed in the
original assessments underlying the pathways listed in Table 1 more
than we anticipated in the RFS2 Rule. Indeed, some of the fuel
production process technologies that parties are now wishing to
register under ``any'' pathways have little connection to the processes
EPA evaluated as the basis for including a given pathway in Table 1. In
some cases, the GHG emissions performance of such new processes may be
significantly worse than the processes we analyzed for the RFS2 Rule or
the notional processes we anticipated might be developed in the future.
These new processes may therefore not meet the applicable GHG emissions
threshold. For example, we have received petitions for 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 very little natural gas or grid electricity, relying instead
on cellulosic renewable biomass (e.g., lignin) for process energy.
Given the possibility that some pathways fitting the description in
Table 1 might not actually meet the corresponding statutory GHG
reduction requirement, we believe it is inappropriate to continue
allowing ``any'' production process under certain Table 1 pathways.
Therefore, we are proposing changes to Table 1 and the RFS regulations
to clarify certain fuel pathways in Table 1 and to replace the ``any''
terminology with more precise language.
More specifically, to further clarify the scope of currently
approved pathways, we are proposing to add more precise language to the
description of rows in Table 1 that include the term ``any'' to
describe the production process requirements, which are Rows
[[Page 25846]]
K, L, M, P, Q, and T. Currently, Rows K and L list the production
process requirements as ``Any process that converts cellulosic biomass
to fuel,'' Row M includes ``any process utilizing biogas and/or biomass
as the only process energy sources which converts cellulosic biomass to
fuel,'' and Rows P, Q, and T list the production process requirements
as ``Any.'' As discussed below, we are proposing to replace some or all
of the current language in each of these rows with a description of the
production process requirements that EPA evaluated for the
corresponding lifecycle GHG assessment and that we determined meet the
applicable GHG reduction threshold. Renewable fuel production
facilities that do not satisfy the updated production process
requirements may petition EPA pursuant to the petition process at 40
CFR 80.1416 to request EPA's evaluation of the lifecycle GHG emissions
associated with their fuel.
a. Rows K and L
We are proposing to edit the production process descriptions in
Rows K and L to clarify the production process technologies that
qualify under these rows. For Row K, we are proposing to clarify that
the qualifying production processes are: (1) A biochemical fermentation
process that uses cellulosic biomass for all electricity and thermal
process energy; (2) A thermochemical gasification process that uses
cellulosic biomass for nearly all thermal and electrical process energy
needs; or (3) A dry mill fermentation process that converts corn or
grain sorghum kernel fiber to ethanol. For Row L, we are proposing to
clarify that the qualifying production process technology is a Fischer-
Tropsch process that uses cellulosic biomass for nearly all electrical
and thermal process energy. Below, we discuss these clarifications in
more detail.
For the RFS2 Rule, EPA's evaluation of the emissions associated
with the feedstock to fuel conversion stage of the lifecycle was based
on process modeling conducted by the National Renewable Energy
Laboratory (NREL).265 266 267 268 The NREL process modeling
evaluated conversion of corn stover, switchgrass and hybrid poplar
feedstocks through biochemical and thermochemical processes. Instead of
conducting process modeling for each possible type of biomass, of which
there are a wide variety, NREL categorized the potential feedstocks as
crop residue, dedicated biomass crops, and woody biomass. NREL modeled
corn stover as representative of all crop residues, switchgrass as
representative of all purpose-grown energy grasses, and hybrid poplar
as representative of all woody biomass feedstocks. In the RFS2
Rule,\269\ the Pathways I Rule,\270\ and the Additional Pathways
Rule,\271\ EPA applied the NREL process modeling to evaluate the
biofuel conversion emissions associated with all the feedstocks
currently listed in Rows K and L.\272\ For the reasons discussed in
those rules, EPA is confident that the process technologies evaluated
are relevant for all these feedstocks and supports the qualification of
fuels produced from these feedstocks and process technologies for D3 or
D7 RINs. Thus, we believe it is appropriate for our proposed revisions
to the production process requirements for Rows K and L to apply for
fuels produced from all the feedstocks listed in those rows.
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\265\ Tao, Ling, and Andy Aden. ``Techno-economic Modeling to
Support the EPA Notice of Proposed Rulemaking (NOPR),'' NREL,
November 3, 2008. Docket Item No. EPA-HQ-OAR-2005-0161-0844.
\266\ Aden, Andy. ``Mixed Alcohols from Woody Biomass--2010,
2015, 2022,'' NREL, December 3, 2009. Docket Item No. EPA-HQ-OAR-
2005-0161-3034.
\267\ Aden, Andy. ``Feedstock Considerations and Impacts on
Biorefining,'' NREL, December 10, 2009. Docket Item No. EPA-HQ-OAR-
2005-0161-3044.
\268\ Davis, Ryan. ``Techno-economic analysis of current
technology for Fischer-Tropsch fuels production,'' NREL, August 14,
2009. Docket Item No. EPA-HQ-OAR-2005-0161-3035.
\269\ 75 FR 14793-95 (March 26, 2010).
\270\ 78 FR 14201-06 (March 5, 2013).
\271\ 78 FR 41705-09 (July 11, 2013).
\272\ Crop residue; slash, pre-commercial thinnings, and tree
residue; switchgrass; miscanthus; energy cane; Arundo donax;
Pennisetum purpureum; separated yard waste; biogenic components of
separated MSW; cellulosic components of separated food waste;
cellulosic components of annual cover crops.
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We are proposing changes to Row K based on the biochemical
production processes that we evaluated in the RFS2 Rule. For the RFS2
rule, we evaluated the lifecycle GHG emissions associated with a
biochemical cellulosic ethanol production process with four major
process steps: (1) Conversion of feedstocks to sugar; (2) Fermentation
of sugar to ethanol; (3) Ethanol recovery; and (4) Residue utilization
for process energy through a combined heat and power system. A key
assumption in the NREL evaluation is that residues from steps 1-3 would
be utilized in step 4 to produce heat, steam, and electricity and meet
all of the facility's needs for these inputs. The modeling assumed that
combusting the residues in a fluidized bed combustor would provide
adequate heat, steam, and electricity for steps 1-3, with excess
electricity sold to the grid. The residue materials considered in our
evaluation were materials left over after the processing of the
cellulosic biomass feedstock, including lignin, concentrated syrup, and
biogas from wastewater treatment. In particular, the lignin residue was
assumed to be the main source of fuel energy to the combined heat and
power system.
For the crop residue ethanol via a biochemical process based on
analysis assuming corn stover feedstock, we estimated a 129 percent GHG
reduction relative to the gasoline baseline (i.e., net negative GHG
emissions due to exported electricity displacing grid average
electricity). For switchgrass ethanol, the corresponding estimate was a
110 percent GHG reduction. Based on these estimates and considering
background data updates since 2010, we remain confident that a
biochemical process using the residues of the production process (e.g.,
lignin, syrup, biogas) for all heat and excess power generation would
meet the 60 percent GHG reduction threshold for D3 RINs. However, if we
were to change the 2010 analysis to assume natural gas is used for
process heat and power, the corresponding GHG reduction estimates would
be 56 percent for corn stover ethanol and 41 percent for switchgrass
ethanol. Thus, our determination that these pathways satisfy the 60
percent threshold is dependent on the assumption that biomass residues
will be used for process energy and power.
For these reasons, we are proposing to revise the production
process column of Row K to include, ``Biochemical fermentation process
that converts cellulosic biomass to ethanol; only includes processes
that use the lignin and other biogenic feedstock residues from the
fermentation and ethanol production processes for all thermal and
electrical process energy and are net exporters of electricity to the
grid.''
We are also proposing changes to Row K of Table 1 to 40 CFR 80.1426
based on the thermochemical production processes that we evaluated in
the RFS2 Rule. The RFS2 Rule evaluated pathways for cellulosic ethanol
produced via a thermochemical process. Our evaluation of these pathways
relied on process modeling by NREL. The process modeled by NREL
includes biomass gasification, syngas refining, mixed alcohol synthesis
and distillation. The NREL modeling assumed that tar from the biomass
gasification and a slipstream of unrefined syngas would be combusted to
provide all required process heat, precluding the need to purchase
natural gas or other fossil fuels for almost all the energy needs for
the process.
[[Page 25847]]
Specifically, the NREL modeling assumes that the biomass residue
provides 99.8 percent of the process energy with a very small amount of
diesel use.
For corn stover ethanol via a thermochemical process, in 2010 we
estimated a 92 percent reduction relative to the gasoline baseline. For
switchgrass ethanol, the corresponding estimate was a 72 percent GHG
reduction. Based on these estimates, we remain confident that a
biochemical process using biomass residues for almost all heat and
excess power generation will meet the 60 percent GHG reduction
threshold for D3 RINs. However, if we were to change the 2010 analysis
to assume natural gas is used for process heat and power, the
corresponding GHG reduction estimates would be 16 percent for corn
stover and 2 percent for switchgrass. Thus, our determination that
these pathways satisfy the 60 percent threshold (or even the 20 percent
threshold) is dependent on the assumption that biomass residues will be
used for process energy and power. For these reasons, we are proposing
to revise the production process column of Row K to include,
``Thermochemical gasification process that converts cellulosic biomass
to ethanol and uses a portion of the feedstock for over 99% of thermal
and electrical process energy.''
We are also proposing changes to Row K of Table 1 to 40 CFR 80.1426
based on the CKF to ethanol process evaluated in the Pathways II
Rule.\273\ In the 2014 Pathways II rule, EPA evaluated ethanol produced
from CKF at dry mill ethanol plants. EPA determined that CKF qualifies
as a predominately cellulosic crop residue and ethanol produced from
corn kernel fiber through a dry mill process is covered by Row K of
Table 1. EPA's evaluation for these pathways was limited to dry mill
ethanol plants. This evaluation did not consider the possibility that
such plants could be coal fired, which would substantially increase the
lifecycle GHG emissions. As part of that rulemaking, EPA also
determined that kernel fiber from grain sorghum is a predominately
cellulosic crop residue that may be converted to ethanol in the same
way as corn kernel fiber. Grain sorghum kernel fiber and CKF are very
similar in terms of how they are produced and converted to ethanol such
that it is reasonable to extend our lifecycle analysis of ethanol
produced from CKF to ethanol produced from grain sorghum kernel fiber.
For these reasons, we are proposing to revise the production process
column of Row K to include, ``Dry mill process that converts corn or
grain sorghum kernel fiber to ethanol and uses natural gas, biogas, or
crop residue for all thermal process energy.''
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\273\ 79 FR 42128 (July 18, 2014).
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We are proposing changes to Row L of Table 1 to 40 CFR 80.1426
based on the Fischer-Tropsch processes that we evaluated in the RFS2
rule. EPA evaluated the lifecycle GHG emissions associated with diesel,
jet fuel, and heating oil produced from corn stover and switchgrass via
a Fischer-Tropsch process for the RFS2 Rule. The lifecycle analysis for
these pathways relied on process modeling by NREL. The NREL process
modeling assumed that the feedstock is dried and gasified, the
resulting syngas is cleaned and reformed, wax is sent to a
hydrocracker, and the light hydrocarbons and hydrocracker products are
sent to a fractionator to separate diesel from other coproducts. The
NREL modeling assumed that almost all (99.8 percent) of the steam and
power requirements are satisfied internally through biomass and syngas
combustion, with the small remainder of energy needs met with grid
electricity and conventional diesel.
For diesel fuel produced from corn stover through a Fischer-Tropsch
process, in 2010 we estimated a 91 percent reduction relative to the
gasoline baseline. For diesel produced from switchgrass through a
Fischer-Tropsch process, the corresponding estimate was a 71 percent
GHG reduction. Based on these estimates, we remain confident that a
Fischer-Tropsch diesel process using residues (e.g., lignin, syrup,
biogas) for all heat and excess power generation will meet the 60
percent GHG reduction threshold for D3 RINs. However, if were to change
the 2010 analysis to assume natural gas is used for process heat and
power, the lifecycle GHG emissions for these fuels would be greater
than the lifecycle GHG emissions associated with the diesel baseline:
25 percent greater for switchgrass-based diesel and 5 percent greater
for stover-based diesel. Thus, our determination that these pathways
satisfy the applicable GHG reductions thresholds are dependent on the
assumption that feedstock residues generated during the fuel production
process will be used for process energy and power. For these reasons,
we are proposing to revise the production process column of Row L to
say, ``Fischer-Tropsch process that converts cellulosic biomass to fuel
and uses a portion of the feedstock for over 99% of thermal and
electrical process energy.''
b. Row M
We are proposing changes to Row M to define the qualifying process
technologies more precisely to ensure that fuels produced through Row M
satisfy the statutory criteria for RIN generation. In the Pathways I
Rule, we approved the pathways in Row M for cellulosic biofuels
produced from residue, byproduct and cover crop feedstocks through
multiple biochemical and thermochemical processes.\274\ These approvals
were based on our lifecycle emissions modeling of the following
production process technologies: (1) Thermochemical processes including
pyrolysis and upgrading; (2) Thermochemical gasification and upgrading;
(3) Direct biological conversion, and (4) Biological conversion and
upgrading. In that rule, we extended the modeling results of these
specific process technologies to ``any process utilizing biogas and/or
biomass as the only process energy sources which converts cellulosic
biomass to fuel.'' At the time, we explained that extending the
modeling in this way was based on the premise that the process
assumptions we modeled at the time were relatively conservative, and we
expected the industry to improve and potentially exceed the energy
efficiencies we modeled. For example, we stated that ``[t]echnology
changes in the future are likely to increase efficiency to maximize
profits, while also lowering lifecycle GHG emissions.'' \275\ While
these predictions made in 2013 may eventually come to pass, our
experience over the 12 years since then has reduced our confidence that
``any'' process using these feedstocks and types of process energy will
satisfy the statutory emissions reduction requirements. We are more
cautious now because the process configurations we modeled in 2013 to
support the Row M pathways have not been commercialized. Furthermore,
new fuel pathway petitions submitted pursuant to 40 CFR 80.1416 and
pathway screening tool submissions indicated that, rather than
exceeding the process efficiencies we modeled in 2013, some projects
under consideration may be less energy efficient than we projected. For
these reasons, we are no longer confident that the fuel and feedstock
combinations listed in Row M produced through ``any process utilizing
biogas and/or biomass as the only process energy sources which converts
cellulosic biomass to
[[Page 25848]]
fuel'' would satisfy the statutory 60 percent GHG reduction requirement
to qualify for D3 RINs. Thus, we are proposing to remove the ``any
process'' language from Row M, while leaving in place the following
processes that convert cellulosic biomass to fuel using natural gas,
biogas, or biomass as the only process energy sources: (1) Catalytic
pyrolysis and upgrading; (2) Gasification and upgrading; (3) Thermo-
catalytic hydrodeoxygenation and upgrading; (4) Direct biological
conversion; (5) Biological conversion and upgrading. To our knowledge,
this action would not adversely affect any currently operating
facilities.
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\274\ 78 FR 14190 (March 5, 2013).
\275\ 78 FR 14213 (March 5, 2013).
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c. Row P
We are proposing changes to Row P based on analyses undertaken by
EPA for prior rulemakings. Row P includes ethanol, renewable diesel,
jet fuel, heating oil, and naphtha produced from the non-cellulosic
portions of separated food waste and non-cellulosic components of
annual cover crops. EPA evaluated and approved pathways for ethanol,
renewable diesel, jet fuel, heating oil, and naphtha produced from the
non-cellulosic portions of separated food waste and non-cellulosic
components of annual cover crops assuming that the ethanol would be
produced through a fermentation process, and the other fuels would be
produced through a hydrotreating or transesterification process.
Fermentation processes use a significant amount of thermal energy
(e.g., for feedstock heating and distillation) and our evaluation
assumed that these facilities would be fired with natural gas or other
fuels with similar or lower lifecycle GHG emissions such as biogas or
crop residue. For these reasons, we are proposing to revise the
production process column of Row P to say, ``Fermentation using natural
gas, biogas, or crop residue for thermal energy; Hydrotreating;
Transesterification.''
d. Rows Q and T
We are proposing changes to Rows Q and T based on analyses
undertaken by EPA for prior rulemakings. EPA's evaluation of renewable
CNG produced from biogas assumed the biogas would be treated to
increase biomethane concentration and reduce impurities such as carbon
dioxide, nitrogen, oxygen, and volatile organic compounds, and the
resulting treated biogas would be compressed for vehicle fueling or
pipeline injection. Thus, for the renewable CNG pathways, we are
proposing to revise the production process column of Rows Q and T to
say, ``CNG production from treated biogas via compression.''
EPA's evaluation of renewable LNG produced from biogas assumed the
same biogas treatment as the renewable CNG pathways, and the resulting
biomethane would undergo liquefaction (i.e., biomethane condensed to
liquid form by reducing its temperature to approximately minus 260
degrees Fahrenheit at ambient pressure), producing renewable LNG. Thus,
for the renewable LNG pathways, we are proposing to revise the
production process column of Row Q to say, ``LNG production from
treated biogas via liquefaction.''
Furthermore, the analyses EPA undertook that form the basis for the
Rows Q and T pathways assumed the renewable CNG would be transported
via pipeline and that the renewable LNG would be used as a
transportation fuel within a relatively short time after it was
produced. After the LNG is produced there are boil-off emissions of
approximately 0.1 to 0.15 percent per day associated with evaporation
during transport, storage, and fueling. Thus, renewable LNG that is
transported or stored for a long time before use as transportation fuel
has higher lifecycle GHG emissions and is outside the bounds of our
analysis. We assume that renewable LNG produced in North America would
be used relatively soon after production. CNG that is produced outside
of North America would involve additional non-pipeline transportation
emissions that were not considered in EPA's lifecycle analysis. For
these reasons, we are proposing to clarify that the production process
requirements for Rows Q and T are limited to processes that occur in
North America.\276\
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\276\ For further information on the lifecycle emissions
estimates discussed in this section, see ``Lifecycle Emissions
Estimates Related to Clarifications to Table 1 Pathways,'' available
in the docket for this action.
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e. Conclusion
These regulatory clarifications to Table 1 to 40 CFR 80.1426 do not
affect renewable fuel producers that have successfully registered for
any of the existing fuel pathways listed in Table 1. Prior registration
applications were reviewed and accepted based on EPA's engineering
judgement and interpretation of the fuel pathways in Table 1, including
EPA's consideration of the bounds of the lifecycle analysis that formed
the basis for the approved pathways. If finalized, the regulatory
clarifications proposed in this action would not change the status of
any of these prior registrations.
We believe the proposed Table 1 revisions discussed in this section
would benefit renewable fuel project developers by giving them
additional clarity on what process technologies qualify under the
existing renewable fuel pathways. Although we strive to describe the
pathways in Table 1 in a precise manner that aligns with the lifecycle
analysis that supports each pathway, we recognize that there will
likely still be some cases where it is not clear whether a particular
process technology qualifies for a particular fuel pathway in Table 1.
Fuel producers seeking to determine if their fuel fits within the
bounds of a pathway listed in Table 1 can contact EPA through the
pathway screening tool for clarification.\277\ 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 generating
RINs. To provide additional clarity regarding the criteria that EPA
will apply to determine whether a feedstock, fuel, or production
technology qualifies for an existing Table 1 pathway, we propose to add
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 GHG reduction requirement.'' Again, producers that are
unsure if their fuel qualifies under an existing pathway may use the
pathway screening tool process to receive clarification from EPA, and
producers of a fuel that does not fit within the bounds of an existing
pathway may petition EPA, pursuant to the petition process at 40 CFR
80.1416, requesting EPA's evaluation of the lifecycle GHG emissions
associated with their fuel.
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\277\ EPA, ``Renewable Fuel Pathway Screening Tool.'' https://www.epa.gov/renewable-fuel-standard-program/forms/renewable-fuel-pathway-screening-tool.
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2. Adding Waste Fats, Oils, and Greases as Feedstock for Producing
Renewable Naphtha and LPG
We are proposing to add generally applicable fuel pathways to Table
1 to 40 CFR 80.1426 for renewable naphtha and liquefied petroleum gas
(LPG) produced from biogenic waste oils, fats, and greases through a
hydrotreating process to qualify for D5 (advanced
[[Page 25849]]
biofuel) RINs. Specifically, we are proposing to add ``Biogenic waste
oils/fats/greases'' to the feedstock column in Row I of Table 1. As
discussed below, we are proposing to add these fuel pathways based on
our finding that they satisfy the statutory 50 percent GHG reduction
threshold to qualify as advanced biofuel.
In the RFS2 Rule, we approved fuel pathways, in Rows F and H, for
biodiesel and renewable diesel produced from biogenic waste oils, fats,
and greases through a hydrotreating process to qualify for D4 RINs.
These pathway approvals were based on our estimate that biodiesel
produced from UCO (also called waste grease or yellow grease in the
RFS2 Rule) reduced lifecycle GHG emissions by over 80 percent compared
to the petroleum baseline.\278\ In the Pathways I Rule, we added ``jet
fuel'' and ``heating oil'' to the fuel type column of Rows F and H of
Table 1. The approval of these jet fuel and heating oil pathways was
based on extending the prior determinations to renewable diesel as the
same facilities often produce renewable diesel and jet fuel as
coproducts.\279\ It is also common for hydrotreating facilities to
produce naphtha and LPG as coproducts along with renewable diesel and
jet fuel. In the Pathways I Rule, we also approved Row I for naphtha
and LPG produced from camelina oil through a hydrotreating process
based on the lifecycle analysis of camelina oil pathways that was
conducted in support of that rule.
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\278\ 75 FR 14789 (March 26, 2010).
\279\ 78 FR 14201 (March 5, 2013).
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In 2018, we approved a facility-specific petition, submitted
pursuant to the petition process at 40 CFR 80.1416, for naphtha and LPG
produced from biogenic waste oils, fats, and greases at the Renewable
Energy Group hydrotreating facility in Geismar, Louisiana, to qualify
for D5 RINs.\280\ As part of that determination, we estimated that
naphtha and LPG produced from UCO at this facility would reduce
lifecycle GHG emissions by 76 percent relative to the statutory
petroleum baseline. Based on our prior and current evaluations, we
believe that, as a general matter, facilities producing renewable
naphtha and LPG from biogenic waste oils, fats, and greases, such as
UCO and animal tallow, through a hydrotreating process will satisfy the
50 percent GHG reduction threshold for these fuels. Thus, we are
proposing to add these pathways to Row I of Table 1 rather than
approving them on a more time consuming and burdensome facility-
specific basis.
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\280\ EPA, ``Letter from EPA to Renewable Energy Group, Inc.,''
April 13, 2017.
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E. Updates to Definitions
1. New Definitions
The RFS regulations currently do 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 are proposing to
define each of these terms in this action. We are proposing to define a
renewable fuel producer as ``any person that owns, leases, operates,
controls, or supervises a facility where renewable fuels are
produced.'' This proposed definition is consistent with other
definitions of regulated parties under the RFS program. We are
proposing to define 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 meets
ASTM D7566.'' These proposed definitions are consistent with other
definitions of renewable fuels under the RFS program.
We believe these proposed definitions will provide more clarity to
both the regulated community and the public. We request comment on the
proposed definitions.
2. Revised Definitions
Because we are proposing to reduce the RINs that are generated on
foreign renewable fuel and renewable fuel made from foreign feedstocks,
and given the complex nature of global supply chains, we believe it is
necessary to update the definitions of foreign renewable fuel producers
and importers. These proposed 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 is currently
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 is ambiguous 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 proposing that a foreign renewable fuel
producer instead be defined 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 is 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 proposing to revise 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 proposing to add 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 newly proposed import RIN reduction
provisions. The proposed change is consistent with the liability
framework for other parties participating in the RFS program and the
liability framework that applies in EPA's 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.
We request comment on the revised definitions of ``foreign
renewable fuel producer'' and ``importer.'' We also request comment on
the joint and several liability provision applicable to importers of
renewable fuel.
3. New Biointermediates
In the 2020-2022 RFS Rule, we established provisions for
biointermediates to be used to produce qualifying renewable fuels and
listed in the regulations specific biointermediates that are allowed
under the RFS program.\281\ 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 this action, we are proposing to add two more biointermediates.
These new biointermediates were requested in
[[Page 25850]]
two separate petitions for rulemaking submitted to EPA in 2023 and
2024.\282\ First, we are proposing to add activated sludge, which is
waste sludge from a secondary wastewater treatment process involving
oxygen and microorganisms. One petitioner suggested that activated
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 proposing to add 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 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 request comment on these proposed additions.
---------------------------------------------------------------------------
\281\ 87 FR 39600 (July 1, 2022).
\282\ ``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.
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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. We
are proposing to clarify that such exempt small refineries must file an
annual compliance report.
While an exempt small refinery does not have to retire RINs to
comply with an RVO, it still produces gasoline or diesel fuel that is
used as transportation fuel in the United States and thus this fuel is
included in EIA's projections of nationwide gasoline and diesel fuel
consumption. EPA uses 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 fuel reported by obligated parties in their annual
compliance reports and EIA's reported actual volumes of gasoline and
diesel fuel consumed.\283\ In order for EPA to have a complete picture
of the actual volume of gasoline and diesel fuel 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 EPA's gasoline and diesel fuel projections in
future standard-setting actions and better ensure that there is not
overcompliance by obligated parties.\284\ Therefore, we are proposing
to clarify 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 would need to report their actual annual
production of gasoline and diesel fuel that would otherwise be
obligated fuel. In addition, we are also proposing 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. We request comment on the proposed
clarifications.
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\283\ RFS Set 1 RIA, Chapter 1.11.
\284\ Without gasoline and diesel fuel production volumes from
exempt small refineries, EPA is more likely to underestimate the
actual amount of gasoline and diesel fuel 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.
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2. Compliance Report Updates
We are proposing several changes to requirements related to
compliance reports. Generally, these changes are intended to reduce
burden, support implementation, or to improve the quality of
information submitted to EPA under 40 CFR 80.1449, 80.1451, and
80.1452.
Currently, 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 proposing to remove this
quarterly reporting requirement under 40 CFR 80.1451 and to also update
the associated requirement under 40 CFR 80.1428(a)(4).
Renewable fuel producers are required to submit an annual
``production outlook report'' that currently includes a monthly or
annual projection in future years. We are proposing to only require
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 proposing to
update or remove other outdated language under 40 CFR 80.1449.
Additionally, producers or importers of biogas used for
transportation fuel are currently 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 reporting requirements under 40 CFR 80.1451(b)(1)(ii)(P)
are similar to other existing reporting requirements under 40 CFR
80.140. We are therefore proposing to remove this separate quarterly
reporting requirement 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 EPA's website. We are proposing to also add a ``reason
code'' to generate transactions for similar purposes and updating other
language under 40 CFR 80.1452 to improve consistency. Examples of new
reason codes include feedstock point of origin identification, co-
processed batches, and remedial actions.
3. Third-Party Auditor Registration Renewal
We are proposing to change the frequency that independent third-
party auditors are required to renew their registrations. Currently, a
third-party auditor's registration expires each year on December 31.
However, we have found that there is significant burden on both 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 would be
more appropriate. This length of time would still ensure that we are
regularly reviewing auditor registrations, while also reducing burden
on EPA and auditors. Thus, we are proposing that a
[[Page 25851]]
third-party auditor's registration would expire on December 31 every
other year. We request comment on the proposed change to the
registration renewal requirement for independent third-party auditors.
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 current regulations do not specify when such site visits
need to occur. Recently, EPA has received some engineering reviews
where the site visit was over a year old. Therefore, we are proposing
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. We request comment on the proposed change to the
engineering review site visit requirement.
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.\285\ Stakeholders have subsequently provided feedback to 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, we are proposing
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
would also provide additional flexibility to RNG producers that use the
biogas batches as part of their RNG RIN generation. We request comment
on this proposed flexibility, including how this change impacts RNG RIN
generation and separation, as well as on the RNG RIN period of
production.
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\285\ 40 CFR 80.105(j)(1) and 80.140(b)(2).
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G. New Approved Measurement Protocols
We are proposing to add additional measurement protocols to the
list of approved methods for measuring the volume of RNG or treated
biogas. EPA has already accepted all these methods through alternative
measurement protocols. The methods we are proposing to add under 40 CFR
80.155(a) are the following:
AGA Report No. 3.
AGA Report No. 9.
AGA Report No. 11 or API MPMS 14.9.
ASME MFC-5.1
ASME MFC-21.2.
ANSI B109.3.
ISO 5167-1 and ISO 5167-2, ISO 5167-4, or ISO 5167-5.
ISO 17089-2.
We are also proposing that flow meters used to measure the volume
of RNG or treated biogas must be tested and calibrated under OIML R137-
1 and 2. Relatedly, we are proposing that if a given flow meter is
calibrated with a fluid other than natural gas, the equivalency to
biogas flow or natural gas flow, respectively, must be demonstrated at
the time of registration.
In addition, under 40 CFR 80.155(b)(2)(v), we are proposing to add
EPA Method TO-15 and ASTM D1945 as additional methods that can be used
for hydrocarbon analysis of biogas and RNG samples. Currently, only EPA
Method 18 is specified for hydrocarbon analysis.
We request comment on the adding the proposed methods and whether
there are any additional methods we should add to the list of approved
methods.
H. Biodiesel and Renewable Diesel Requirements
We are not proposing any changes to the sulfur standards for
biodiesel or renewable diesel in this action. However, we are again
reiterating that biodiesel and renewable diesel producers must comply
with all of EPA's 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.\286\ This also 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.
---------------------------------------------------------------------------
\286\ EPA has previously made clear that biodiesel producers
must comply with all of EPA's regulatory requirement 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.
---------------------------------------------------------------------------
Further, the definition of biodiesel under 40 CFR 80.2 requires
that the fuel ``meet ASTM D6571,'' which means that each batch of
biodiesel must be tested for and meet all parameters specified in ASTM
D6751. The ASTM D6751 specification was imposed to ensure that
biodiesel for which RINs are generated is of a sufficient quality to be
used as transportation fuel. To ensure that all biodiesel for which
RINs are generated is fit to be used as transportation fuel, each batch
must be tested for and meet ASTM D6751.
To further make clear that all the above requirements apply to
biodiesel and renewable diesel, we are proposing clarifying language at
40 CFR 1090.300(a), 1090.305(a), 1090.1310(b)(1), and 1090.1337(e). We
request comment on these proposed clarifications in 40 CFR part 1090
relating to biodiesel and renewable diesel.
I. Technical Amendments
We are proposing 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 X.I-1.
Table X.I-1--Miscellaneous Technical Corrections and Clarifications to
RFS Regulations
------------------------------------------------------------------------
Part and section of Title 40 Description of revision
------------------------------------------------------------------------
Sec. Sec. 80.2, Clarifying the definition of ``Assigned
80.1425(a)(3), RIN'' and implementing regulations that
80.1426(e)(3), assigned RINs for RNG have a K code of
80.1428(a)(3), 80.1429(c), 3.
80.1460(b)(4).
Sec. 80.2.................. Clarifying the definition of
``Biodiesel'' to state that it must be
renewable fuel.
Sec. 80.2.................. Clarifying the definition of ``Diesel
fuel'' by adding renewable diesel as an
example of a non-distillate diesel fuel.
[[Page 25852]]
Sec. 80.2.................. Clarifying that parties must use ASTM D86
to measure T90 in the definition of
``MVNRLM diesel fuel''.
Sec. Sec. 80.2, Removing the definition of ``Non-ester
80.1426(f)(17), renewable diesel'' and replacing it with
80.1450(b)(1)(xii), a definition of ``Renewable diesel''.
80.1451(b)(1)(ii)(T),
80.1454(l).
Sec. Sec. 80.2 Replacing text in existing regulations to
80.1426(c)(7), Table 1 to use the new definition of ``renewable
80.1426, 80.1450(b)(1)(xi), fuel oil.''
80.1453(d), 80.1454(b)(8),
80.1460(g).
Sec. Sec. 80.2, Replacing text in existing regulations to
80.1426(f)(17), Table 1 to use the new definition of ``renewable
80.1426, 80.1450(b)(1)(xii), jet fuel.''
80.1451(b)(1)(ii)(T),
80.1454(l).
Sec. Sec. 80.2, 80.1454, Removing expired Option A and Option B
80.1469, 80.1470, 80.1471, QAP provisions.
80.1472, 80.1473, 80.1474,
80.1477, 80.1479.
Sec. Sec. 80.12 and Updating numerous ASTM standards and
1090.95. methods to the latest versions (see
Section IX.J for list of methods).
Sec. Sec. 80.105(j)(3), Clarifying that batch numbers for biogas,
80.110(j)(3), and RNG, biogas-derived renewable fuel, and
80.1476(h)(1). biointermediates do not need to be
numbered sequentially but must be unique
in a compliance period.
Sec. 80.125(d)(4).......... Clarifying that RNG RIN separators must
separate RINs equal to or less than the
total volume of RNG used as renewable
CNG/LNG.
Sec. 80.125(e)(2).......... Clarifying when assigned RINs for a
volume of RIN must be retired and
removing an example that was
inconsistent with the specified
regulatory requirements.
Sec. Clarifying that biogas is ``produced,''
80.135(c)(10)(vi)(A)(5). not ``generated.''
Sec. 80.1426(f)(8)......... Clarifying that the batch volume
standardization equations apply to
liquid renewable fuels and liquid
biointermediates.
Table 1 to Sec. 80.1426, Replacing text in existing regulations to
80.1453(a)(12)(v). use the new definition of ``renewable
naphtha.''
Sec. 80.1449(a)(4)(i)...... Replacing existing and planned production
capacity with nameplate and permitted
production capacity.
Sec. 80.1452(b) and (c).... Clarifying that EPA may allow a party to
submit RIN assignment or transaction
information to EMTS outside the
applicable 5- or 10-business-day
deadline.
Sec. 80.1454(b)(3)(ix)..... Clarifying that records must be kept for
all calculations under 80.1426.
Sec. 1090.80............... Replacing references to ``NP diesel
fuel'' with ``nonpetroleum diesel
fuel.''
Sec. 1090.80............... Clarifying the definition of
``Responsible corporate officer (RCO)''
by removing ``operations manager'' as an
example of an RCO.
Sec. Sec. 80.2, 80.3, Correcting typographical, grammatical,
80.1405, 80.1407, 80.1415, and consistency errors.
80.1426, 80.1429, 80.1435,
80.1444, 80.1450, 80.1451,
80.1452, 80.1453, 80.1454.
------------------------------------------------------------------------
XI. Request for Comments
We solicit comments on this proposed action. Specifically, we are
soliciting comment on the following:
A. Renewable Fuel Volumes and Analyses
The proposed cellulosic biofuel, BBD, advanced biofuel,
and total renewable fuel volume requirements for 2026 and 2027 (A-1).
Alternative volume requirements for each of the statutory
categories of renewable fuel for 2026 and 2027, including any data or
analysis that would support alternative volumes for these years (A-2).
The assessments and methodologies used to project volumes
of cellulosic biofuel (A-3).
The appropriate volume of non-cellulosic advanced biofuel
for 2026 and 2027 (A-4).
The potential production volume and impacts of renewable
jet fuel on the statutory factors (A-5).
Our proposed approach of accounting for the projected
shortfall in the supply of conventional renewable fuel relative to the
15-billion-gallon implied volume when establishing the volume
requirements for advanced biofuel and BBD (A-6).
The advantages and disadvantages of establishing BBD and
advanced biofuel volume requirements at levels at or closer to the
projected supplies of these fuels and the implications of doing so on
the total renewable fuel volume if such an approach were adopted (A-7).
Our analysis of the statutory factors in CAA section
211(o)(2)(B)(ii), including the approaches to estimating jobs and rural
economic development impacts associated with renewable fuels and the
types of approaches that would be appropriate to apply in analyzing net
jobs and rural development impacts (A-8).
B. Import RIN Reduction
The appropriateness of the proposed import RIN reduction
factor (i.e., more or less than the proposed 50 percent reduction) (B-
1).
The proposed import RIN generation requirement, and
whether there are alternative RIN generation approaches that we should
consider (B-2).
The proposed import RIN reduction recordkeeping,
reporting, attest engagement, and QAP requirements (B-3).
The proposed definition of ``feedstock point of origin,''
particularly on the proposed origin locations for each feedstock type
and whether there are any other feedstock types that should have
specified origin locations (B-4).
C. Removal of Renewable Electricity From the RFS Program
The statutory analyses and proposed conclusions that: (1)
Renewable electricity does not meet the definition of renewable fuel
because it does not ``replace or reduce the quantity of fossil fuel
present in a transportation fuel,'' and (2) Electricity is not a fuel
under the RFS program (C-1).
The proposed removal from the RFS regulations all
provisions related to renewable electricity, including but not limited
to the definition of and pathways for renewable electricity and
[[Page 25853]]
the generation of RINs for renewable electricity (C-2).
D. Other RFS Program Amendments
The other proposed amendments to the RFS program,
including: the equivalence values for renewable diesel, naphtha, and
jet fuel; the changes to the percentage standards equations; and the
changes and additions to the pathways in Table 1 to 40 CFR 80.1426 (D-
1).
E. Policy Considerations
Where applicable, any legitimate reliance interests
impacted by EPA's proposed changes in policy. (E-1)
A general pathway for the production of renewable jet fuel
from corn ethanol, including the consideration of technologies that
could reduce the GHG emissions for this pathway such as the use of
carbon capture and storage and renewable natural gas for process energy
(E-2).
The definition of ``produced from renewable biomass'' (E-
3).
Additional program amendments to ensure the validity of
imported renewable fuels and feedstocks (E-4).
Program enhancements to increase the use of qualifying
woody-biomass to produce renewable transportation fuel (E-5).
An option to apply the import RIN reduction provisions to
imported renewable fuel and renewable fuel produced domestically from
foreign feedstock from only a subset of countries to reflect the
reduced economic, energy security, and environmental benefits of
imported renewable fuel and feedstocks from those countries (E-6).
Any other modifications to the RFS program designed to
unleash the production of American energy (E-7).
XII. 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, EPA,
submitted this action to the Office of Management and Budget (OMB) for
Executive Order 12866 review. Documentation of any changes made in
response to the Executive Order 12866 review is available in the
docket. EPA prepared an analysis of the potential costs and benefits
associated with this action. This analysis is presented in DRIA Chapter
10.6, available in the docket for this action.
B. Executive Order 14192: Unleashing Prosperity Through Deregulation
This action is expected to be an Executive Order 14192 regulatory
action. Details on the estimated costs of this proposed rule can be
found in EPA's analysis of the potential costs and benefits associated
with this action in DRIA Chapter 10.6, available in the docket for this
action.
C. Paperwork Reduction Act (PRA)
The information collection activities in this proposed 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 7804.01. You can
find a copy of the ICR in the docket for this rule, and it is briefly
summarized here.
The proposed 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 proposed rule
proposes recordkeeping and reporting for domestic renewable fuel
producers to implement the proposed RIN reduction for import-based
renewable fuel. We anticipate the increase in burden related to
identifying feedstock as foreign or domestic will be very small because
the parties already are required to keep underlying records and provide
reports for the RFS program, generally. General recordkeeping and
reporting for the RFS program is contained in the Renewable Fuel
Standard program ICR, OMB Control Number 2060-0725 (expires November
30, 2025).
Certain information submitted to EPA may be claimed as confidential
business information (CBI) and such information will be handled in
accordance with the requirements of 40 CFR parts 2 and 80.
Respondents/affected entities: renewable fuel producers, third
party auditors (attest engagements), QAP auditors.
Respondent's obligation to respond: Mandatory, under 40 CFR part
80.
Estimated number of respondents: 2,307.
Frequency of response: Quarterly, annual, on occasion/as needed.
Total estimated burden: 7,244 hours (per year). Burden is defined
at 5 CFR 1320.3(b).
Total estimated cost: $20,323, all purchased services and including
$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.
Submit your comments on the Agency's need for this information, the
accuracy of the provided burden estimates and any suggested methods for
minimizing respondent burden to the EPA using the docket identified at
the beginning of this rule. The EPA will respond to any ICR-related
comments in the final rule. You may also send your ICR-related comments
to OMB's Office of Information and Regulatory Affairs using the
interface at www.reginfo.gov/public/do/PRAMain. Find this particular
information collection by selecting ``Currently under Review--Open for
Public Comments'' or by using the search function. OMB must receive
comments no later than July 17, 2025.
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.
EPA believes 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 proposed 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.\287\ 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, including
small entities, 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
[[Page 25854]]
would be expected in the absence of the RFS program.\288\ 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 far less than 1 percent of the value of their sales.\289\
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\287\ See DRIA Chapter 11.
\288\ For a further discussion of the ability of obligated
parties to recover the cost of RINs, see EPA, ``Denial of Petitions
for Rulemaking to Change the RFS Point of Obligation,'' EPA-420-R-
17-008, November 2017.
\289\ A cost-to-sales ratio of 1 percent represents a typical
agency threshold for determining the significance of the economic
impact on small entities. See ``Final Guidance for EPA Rulewriters:
Regulatory Flexibility Act as amended by the Small Business
Regulatory Enforcement Fairness Act,'' November 2006.
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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.
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.'' \290\ EPA regulations provide
the same relief to small refiners that are not eligible for small
refinery relief.\291\ In the RFS2 Rule, we discussed other potential
small entity flexibilities that had been suggested by the Small
Business Regulatory Enforcement Fairness Act (SBREFA) panel or through
comments, but we did not adopt them, in part because we had serious
concerns regarding our authority to do so.\292\
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\290\ 40 CFR 80.1441(e)(2).
\291\ 40 CFR 80.1442(h).
\292\ 75 FR 14858-62 (March 26, 2010).
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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.
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, 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 IV and DRIA 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 a significant regulatory action under section 3(f)(1) of
Executive Order 12866, and EPA believes that the environmental health
or safety risks of the pollutants impacted by this action may have a
disproportionate effect on children. An assessment of the environmental
impacts from this rule is include in DRIA Chapter 4.
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 proposes to establish 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 IV and DRIA 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.
In accordance with the requirements of 1 CFR 51.5, we are proposing
to incorporate by reference the use of certain standards and test
methods from the American Gas Association (AGA), American National
Standards Institute (ANSI), American Petroleum Institute (API),
American Society of Mechanical Engineers (ASME), ASTM International
(ASTM), International Organization for Standardization (ISO),
International Organization of Legal Metrology (OIML), and 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 (212) 642-4980; 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; the OIML website
(www.oiml.org) or by calling OIML at +33 1 4878 1282; and the EPA
website (www.epa.gov) or by calling EPA at (202) 272-0167. We are
proposing to
[[Page 25855]]
incorporate by reference the following standards:
------------------------------------------------------------------------
Organization and standard or Part and section
test method of Title 40 Summary
------------------------------------------------------------------------
AGA Report No. 3 Part 1, Sec. Sec. This standard
Orifice Metering of Natural 80.12 and 80.155. describes
Gas and Other Related engineering
Hydrocarbon Fluids-- equations,
Concentric, Square-edged installation
Orifice Meters Part 1: requirements, and
General Equations and uncertainty
Uncertainty Guidelines, 4th estimations of
Edition, including Errata square-edged orifice
July 2013, Reaffirmed, July meters in measuring
2022. the flow of natural
gas and similar
fluids.
AGA Report No. 3 Part 2, Sec. Sec. This standard
Orifice Metering of Natural 80.12 and 80.155. describes design and
Gas and Other Related installation of
Hydrocarbon Fluids-- square-edged orifice
Concentric, Square-edged meters for measuring
Orifice Meters Part 2: flow of natural gas
Specification and and similar fluids.
Installation Requirements,
5th Edition, March 2016.
AGA Report No. 3 Part 3, Sec. Sec. This standard
Orifice Metering of Natural 80.12 and 80.155. describes
Gas and Other Related applications using
Hydrocarbon Fluids-- square-edged orifice
Concentric, Square-edged meters for measuring
Orifice Meters Part 3: flow of natural gas
Natural Gas Applications, 4th and similar fluids.
Edition, Reaffirmed, June
2021.
AGA Report No. 3 Part 4, Sec. Sec. This standard
Orifice Metering of Natural 80.12 and 80.155. describes the
Gas and Other Related development of
Hydrocarbon Fluids-- equations for
Concentric, Square-edged coefficient of
Orifice Meters Part 4-- discharge, including
Background, Development, a calculation
Implementation Procedure, and procedure, for
Example Calculations, 4th square-edged orifice
Edition, October 2019. meters measuring
flow of natural gas
and similar fluids.
AGA Report No. 9, Measurement Sec. Sec. This standard
of Gas by Multipath 80.12 and 80.155. describes procedures
Ultrasonic Meters, 2nd and guidelines for
Edition, April 2007. measuring natural
gas by turbine
meters.
AGA Report No. 11, Measurement Sec. Sec. This standard
of Natural Gas by Coriolis 80.12 and 80.155. describes procedures
Meter, 2nd Edition, February and guidelines for
2013. measuring natural
gas by Coriolis
meters.
ANSI B109.3-2019 (R2024), Sec. Sec. This document
Rotary-Type Gas Displacement 80.12 and 80.155. describes a basic
Meters, February 5, 2019, standard for safe
Reaffirmed April 26, 2024. operation,
substantial and
durable
construction, and
acceptable
performance for
rotary-type gas
displacement meters.
API MPMS 14.9-2013, Sec. Sec. This standard
Measurement of Natural Gas by 80.12 and 80.155. describes procedures
Coriolis Meter, 2nd Edition, and guidelines for
February 2013. measuring natural
gas by Coriolis
meters.
ASME MFC-5.1-2011 (R2024), Sec. Sec. This standard
Measurement of Liquid Flow in 80.12 and 80.155. describes procedures
Closed Conduits Using Transit- and guidelines for
Time Ultrasonic Flowmeters, measuring liquid
June 17, 2011, Reaffirmed flow by ultrasonic
2024. flowmeters.
ASME MFC[hyphen]21.2-2010 Sec. Sec. This standard
(R2018), Measurement of Fluid 80.12 and 80.155. describes guidelines
Flow by Means of Thermal for the quality,
Dispersion Mass Flowmeters, description,
January 10, 2011, Reaffirmed principle of
2018. operation,
selection,
installation, and
flow calibration of
thermal dispersion
flowmeters for the
measurement of the
mass flow rate and
volumetric flow rate
of the flow of a
fluid in a closed
conduit.
ASTM D86-23ae2, Standard Test Sec. Sec. This updated standard
Method for Distillation of 80.2, 80.12, describes how to
Petroleum Products and Liquid 1090.95, and perform distillation
Fuels at Atmospheric 1090.1350(b). measurements for
Pressure, approved December gasoline and other
1, 2023. petroleum products.
ASTM D287-22, Standard Test Sec. Sec. This updated standard
Method for API Gravity of 1090.95 and describes how to
Crude Petroleum and Petroleum 1090.1337(d). measure the density
Products (Hydrometer Method), of fuels and other
approved December 1, 2022. petroleum products,
expressed in terms
of API gravity.
ASTM D975-24a, Standard Sec. Sec. This updated standard
Specification for Diesel 80.2, 80.12, describes the
Fuel, approved August 1, 2024. 80.1426(f), characteristic
80.1450(b), values for several
80.1451(b), and parameters to be
80.1454(l). considered suitable
as diesel fuel.
ASTM D976-21e1, Standard Test Sec. Sec. This updated standard
Method for Calculated Cetane 1090.95 and describes how to
Index of Distillate Fuels, 1090.1350(b). calculate cetane
approved November 1, 2021. index for a sample
of diesel fuel and
other distillate
fuels.
ASTM D1945-14 (Reapproved Sec. Sec. This standard
2019), Standard Test Method 80.12 and 80.155. describes how to
for Analysis of Natural Gas determine the
by Gas Chromatography, chemical composition
approved December 1, 2019. of natural gas using
gas chromatography.
ASTM D2622-24a, Standard Test Sec. Sec. This updated standard
Method for Sulfur in 1090.95, describes how to
Petroleum Products by 1090.1350(b), measure the sulfur
Wavelength Dispersive X-ray 1090.1360(d), content in gasoline,
Fluorescence Spectrometry, and 1090.1375(c). diesel fuel, and
approved December 1, 2024. other petroleum
products.
ASTM D3588-98 (Reapproved Sec. Sec. This updated standard
2024)e1, Standard Practice 80.12 and describes the
for Calculating Heat Value, 80.155(b) and calculation protocol
Compressibility Factor, and (f).. for aggregate
Relative Density of Gaseous properties of
Fuels, reapproved May 1, 2024. gaseous fuels from
compositional
measurements.
ASTM D3606-24a, Standard Test Sec. Sec. This updated standard
Method for Determination of 1090.95 and describes how to
Benzene and Toluene in Spark 1090.1360(c). measure the benzene
Ignition Fuels by Gas content of gasoline
Chromatography, approved and similar fuels.
November 1, 2024.
ASTM D4057-22, Standard Sec. Sec. This updated standard
Practice for Manual Sampling 80.8(a) and describes procedures
of Petroleum and Petroleum 80.12. for drawing samples
Products, approved May 1, of fuel and other
2022. petroleum products
from storage tanks
and other containers
using manual
procedures.
[[Page 25856]]
ASTM D4177-22e1, Standard Sec. Sec. This updated standard
Practice for Automatic 80.8(b) and describes procedures
Sampling of Petroleum and 80.12. for using automated
Petroleum Products, approved procedures to draw
July 1, 2022. fuel samples for
testing.
ASTM D4737-21, Standard Test Sec. Sec. This updated standard
Method for Calculated Cetane 1090.95 and describes how to
Index by Four Variable 1090.1350(b). calculate cetane
Equation, approved November index for a sample
1, 2021. of diesel fuel and
other distillate
fuels.
ASTM D4806-21a, Standard Sec. Sec. This updated standard
Specification for Denatured 1090.95 and describes the
Fuel Ethanol for Blending 1090.1395(a). characteristic
with Gasolines for Use as values for several
Automotive Spark-Ignition parameters to be
Engine Fuel, approved October considered suitable
1, 2021. as denatured fuel
ethanol for blending
with gasoline.
ASTM D4814-24b, Standard Sec. Sec. This updated standard
Specification for Automotive 1090.95, describes the
Spark-Ignition Engine Fuel, 1090.80, and characteristic
approved December 1, 2024. 1090.1395(a). values for several
parameters to be
considered suitable
as gasoline.
ASTM D5134-21, Standard Test Sec. Sec. This updated standard
Method for Detailed Analysis 1090.95 and describes how to
of Petroleum Naphthas through 1090.1350(b). measure benzene in
n-Nonane by Capillary Gas butane, pentane, and
Chromatography, approved other light-end
December 1, 2021. petroleum compounds.
ASTM D5453-24, Standard Test Sec. Sec. This updated standard
Method for Determination of 1090.95 and describes how to
Total Sulfur in Light 1090.1350(b). measure the sulfur
Hydrocarbons, Spark Ignition content of neat
Engine Fuel, Diesel Engine ethanol and other
Fuel, and Engine Oil by petroleum products.
Ultraviolet Fluorescence,
approved October 15, 2024.
ASTM D5842-23, Standard Sec. Sec. This updated standard
Practice for Sampling and 80.8(c), 80.12, describes procedures
Handling of Fuels for 1090.95, and for drawing samples
Volatility Measurement, 1090.1335(d). of gasoline and
approved October 1, 2023. other fuels from
storage tanks and
other containers
using manual
procedures to
prepare samples for
measuring vapor
pressure.
ASTM D5854-19a, Standard Sec. Sec. This updated standard
Practice for Mixing and 80.8(d) and describes procedures
Handling of Liquid Samples of 80.12. for handling,
Petroleum and Petroleum mixing, and
Products, approved May 1, conditioning
2019. procedures to
prepare
representative
composite samples.
ASTM D6259-23, Standard Sec. Sec. This updated standard
Practice for Determination of 1090.95 and describes procedures
a Pooled Limit of 1090.1355(b). to determine how to
Quantitation for a Test evaluate parameter
Method, approved May 1, 2023. measurements at very
low levels,
including a
laboratory limit of
quantitation that
applies for a given
facility.
ASTM D6708-24, Standard Sec. Sec. This updated standard
Practice for Statistical 1090.95, describes
Assessment and Improvement of 1090.1360(c), statistical criteria
Expected Agreement Between 1090.1365(d) and to evaluate whether
Two Test Methods that Purport (f), and an alternative test
to Measure the Same Property 1090.1375(c). method provides
of a Material, approved March results that are
1, 2024. consistent with a
reference procedure.
ASTM D6729-20, Standard Test Sec. Sec. This updated standard
Method for Determination of 1090.95 and describes how to
Individual Components in 1090.1350(b). determine the
Spark Ignition Engine Fuels benzene content of
by 100 Metre Capillary High butane and pentane.
Resolution Gas
Chromatography, approved June
1, 2020.
ASTM D6730-22, Standard Test Sec. Sec. This updated standard
Method for Determination of 1090.95 and describes how to
Individual Components in 1090.1350(b). determine the
Spark Ignition Engine Fuels benzene content of
by 100-Metre Capillary (with butane and pentane.
Precolumn) High-Resolution
Gas Chromatography, approved
November 1, 2022.
ASTM D6751-24, Standard Sec. Sec. This standard
Specification for Biodiesel 1090.95, describes the
Fuel Blendstock (B100) for 1090.300(a), and characteristics of
Middle Distillate Fuels, 1090.1350(b). biodiesel.
approved March 1, 2024.
ASTM D6792-23c, Standard Sec. Sec. This updated standard
Practice for Quality 1090.95 and describes principles
Management Systems in 1090.1450(c). for ensuring quality
Petroleum Products, Liquid for laboratories
Fuels, and Lubricants Testing involved in
Laboratories, approved parameter
November 1, 2023. measurements for
fuels and other
petroleum products.
ASTM D6866-24a, Standard Test Sec. Sec. This updated standard
Methods for Determining the 80.12, describes the
Biobased Content of Solid, 80.155(b), radiocarbon dating
Liquid, and Gaseous Samples 80.1426(f), and test method to
Using Radiocarbon Analysis, 80.1430(e). determine the
approved December 1, 2024. renewable content of
biogas and RNG.
ASTM D7717-11 (Reapproved Sec. Sec. This updated standard
2021), Standard Practice for 1090.95 and describes the
Preparing Volumetric Blends 1090.1340(b). procedures for
of Denatured Fuel Ethanol and blending denatured
Gasoline Blendstocks for fuel ethanol with
Laboratory Analysis, approved gasoline to prepare
October 1, 2021. a sample for
testing.
ASTM D7777-24, Standard Test Sec. Sec. This updated standard
Method for Density, Relative 1090.95 and describes how to
Density, or API Gravity of 1090.1337(d). measure the density
Liquid Petroleum by Portable of fuels and other
Digital Density Meter, petroleum products,
approved July 1, 2024. expressed in terms
of API gravity.
ASTM E711-23e1, Standard Test Sec. Sec. This updated standard
Method for Gross Calorific 80.12 and describes the
Value of Refuse-Derived Fuel 80.1426(f). procedures for
by the Bomb Calorimeter, determination of the
approved April 1, 2023. gross calorific
value of a prepared
analysis sample of
solid forms of
refuse-derived fuel
by the bomb
calorimeter method.
ASTM E870-24, Standard Test Sec. Sec. This updated standard
Methods for Analysis of Wood 80.12 and describes the
Fuels, approved October 1, 80.1426(f). proximate analysis,
2024. ultimate analysis,
and the
determination of the
gross caloric value
of wood fuels.
[[Page 25857]]
ISO 5167-1:2022, Measurement Sec. Sec. This standard
of fluid flow by means of 80.12 and 80.155. establishes the
pressure differential devices general principles
inserted in circular cross- for methods of
section conduits running measurement and
full, Part 1: General computation of the
principles and requirements, flow rate of fluid
3rd Edition, June 2022. flowing in a conduit
by means of pressure
differential devices
when they are
inserted into a
circular cross-
section conduit
running full.
ISO 5167-2:2022, Measurement Sec. Sec. This standard
of fluid flow by means of 80.12 and 80.155. specifies the
pressure differential devices geometry and method
inserted in circular cross- of use of orifice
section conduits running plates when they are
full, Part 2: Orifice plates, inserted in a
2nd Edition, June 2022. conduit running full
to determine the
flow rate of the
fluid flowing in the
conduit.
ISO 5167-4:2022, Measurement Sec. Sec. This standard
of fluid flow by means of 80.12 and 80.155. specifies the
pressure differential devices geometry and method
inserted in circular cross- of use of Venturi
section conduits running tubes when they are
full, Part 4: Venturi tubes, inserted in a
2nd Edition, June 2022. conduit running full
to determine the
flow rate of the
fluid flowing in the
conduit.
ISO 5167-5:2022, Measurement Sec. Sec. This standard
of fluid flow by means of 80.12 and 80.155. specifies the
pressure differential devices geometry and method
inserted in circular cross- of use of cone
section conduits running meters when they are
full, Part 5: Cone meters, inserted in a
2nd Edition, October 2022. conduit running full
to determine the
flow rate of the
fluid flowing in the
conduit.
ISO 17089-2:2012, Measurement Sec. Sec. This standard
of fluid flow in closed 80.12 and 80.155. specifies
conduits--Ultrasonic meters requirements and
for gas, Part 2: Meters for recommendations for
industrial applications, 1st ultrasonic gas
Edition, October 2012. meters, which
utilize acoustic
signals to measure
the flow in the
gaseous phase in
closed conduits.
OIML R 137-1 and 2, Gas Sec. Sec. This standard
meters, Part 1: Metrological 80.12 and 80.155. specifies testing
and technical requirements and calibration
and Part 2: Metrological requirements for gas
controls and performance meters.
tests, Edition 2012,
Including Amendment 2014.
EPA Compendium Method TO-15, Sec. Sec. This standard
Determination Of Volatile 80.12 and 80.155. specifies sampling
Organic Compounds (VOCs) In and analytical
Air Collected In Specially- procedures for
Prepared Canisters And identifying and
Analyzed By Gas measuring VOCs using
Chromatography/Mass gas chromatography/
Spectrometry (GC/MS), Second mass spectrometry.
Edition, January 1999.
------------------------------------------------------------------------
AGA, ASME, ANSI, API, ASTM, ISO, and OIML regularly publish updated
versions of their standards and test methods, with the potential that
there will be a published version of one or more of the documents
listed above before we adopt the final rule that is more recent than
the documents we identify in this proposed rule. For any such updated
versions, we will consider including a reference to the latest document
when we finalize the revisions covered by this proposed rule.
XIII. 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 EPA was making.
Due to the extensive number of technical and conforming amendments
included in this action, however, EPA is utilizing OFR's new amendatory
instruction ``revise and republish'' for revisions proposed in this
action.\293\ Therefore, instead of the past practice of piecemeal
amendments for revisions to the CFR, EPA is 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, EPA has created a red-line version of
40 CFR part 80 that incorporates the proposed 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
proposed regulatory text changes. EPA is not reopening for comment
those unchanged provisions. Republishing provisions that are unchanged
in this action is consistent with guidance from OFR.
---------------------------------------------------------------------------
\293\ 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.
---------------------------------------------------------------------------
XIV. 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 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 additives, Gasoline, Imports,
Incorporation by reference, Oil imports, Petroleum, Renewable fuel.
Lee Zeldin,
>Administrator.
For the reasons set forth in the preamble, EPA proposes to amend 40
CFR parts 80 and 1090 as follows:
PART 80--REGULATION OF FUELS AND FUEL ADDITIVES
0
1. 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
2. Amend Sec. 80.2 by:
0
a. Adding the definition ``Activated sludge'' in alphabetical order;
0
b. Removing the definition ``A-RIN'';
[[Page 25858]]
0
c. Revising the definitions ``Assigned RIN'' and ``Biodiesel'';
0
d. Adding paragraphs (5)(x) and (xi) in the definition
``Biointermediate'';
0
e. Revising paragraph (1)(ii) in the definition ``Biomass-based
diesel'';
0
f. Removing the definition ``B-RIN'';
0
g. Revising the definition ``Cellulosic diesel'';
0
h. Adding the definition ``Converted oils'' in alphabetical order;
0
i. Revising the definition ``Co-processed cellulosic diesel'';
0
j. Revising paragraph (1)(ii) in the definition ``Diesel fuel'';
0
k. Adding the definition ``Feedstock point of origin'' in alphabetical
order;
0
l. Revising the definitions ``Foreign renewable fuel producer'',
``Heating oil'', and ``Importer'';
0
m. Removing the definition ``Interim period'';
0
n. Revising the definition ``MVNRLM diesel fuel'';
0
o. Removing the definition ``Non-ester renewable diesel'';
0
p. Adding the definition ``Renewable diesel'' in alphabetical order;
0
q. Removing the definition ``Renewable electricity''; and
0
r. Adding the definitions ``Renewable fuel oil'' and ``Renewable jet
fuel'' in alphabetical order;
0
s. Revising the definition ``Renewable liquefied natural gas or
renewable LNG''; and
0
t. Adding the definition ``Renewable naphtha'' in alphabetical order.
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.
* * * * *
Cellulosic diesel is any renewable fuel which meets both the
definitions of cellulosic biofuel and biomass-based diesel. Cellulosic
diesel includes renewable fuel oil and renewable jet fuel produced from
cellulosic feedstocks.
* * * * *
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 is any renewable fuel that meets the
definition of cellulosic biofuel and meets all the requirements of
paragraph (1) of this definition:
(1) (i) Is a transportation fuel, transportation fuel additive,
heating oil, or jet fuel.
(ii) Meets the definition of either biodiesel or renewable diesel.
(iii) Is registered as a motor vehicle fuel or fuel additive under
40 CFR part 79, if the fuel or fuel additive is intended for use in a
motor vehicle.
(2) Co-processed cellulosic diesel includes all the following:
(i) Renewable fuel oil and renewable jet fuel produced from
cellulosic feedstocks.
(ii) Cellulosic biofuel produced from cellulosic feedstocks co-
processed with petroleum.
* * * * *
Diesel fuel * * *
(1) * * *
(ii) A non-distillate fuel other than residual fuel with comparable
physical and chemical properties (e.g., biodiesel, renewable diesel).
* * * * *
Feedstock point of origin means the location, either domestic or
foreign, where a feedstock is produced, generated, extracted,
collected, or harvested. This location is determined as follows:
(1) For planted crops, cover crops, or crop residue (including
starches, cellulosic, and non-cellulosic components thereof), the
location of the feedstock supplier that supplied the feedstock to the
renewable fuel producer or biointermediate producer (e.g., grain
elevator).
(2) For oil derived from planted crops, cover crops, or algae, the
location where the oil is extracted from the planted crop, cover crop,
or algae (e.g., crushing facility).
(3) For biogenic waste oils/fats/greases, separated yard waste,
separated food waste, or MSW (including the components thereof), the
location of the establishment where the waste is collected (e.g.,
restaurant, food processing facility).
(4) For biogas, the location of the landfill or digester that
produces the biogas.
(5) For planted trees, tree residue, slash, pre-commercial
thinnings, or other woody biomass, the location where the woody biomass
is harvested.
(6) For all other feedstocks, the location where the feedstock is
produced, generated, extracted, collected, or harvested, as applicable.
* * * * *
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.
* * * * *
Heating oil means a product that meets one of the definitions in
paragraph (1) of this definition:
(1)(i) Any No. 1, No. 2, or non-petroleum diesel blend that is sold
for use in furnaces, boilers, 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.
(ii) Any fuel oil that is used to heat or cool interior spaces of
homes or buildings to control ambient climate for human comfort. The
fuel oil must be liquid at STP and contain no more than 2.5% mass
solids.
(2) Pure biodiesel (i.e., B100) or neat biodiesel (i.e., B99) that
is used for process heat or power generation is not heating oil.
Importer means any person who imports transportation fuel or
renewable fuel into the covered location from an area outside of
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
[[Page 25859]]
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.
(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 of heating oil.
* * * * *
Renewable jet fuel means jet fuel that is renewable fuel and that
meets ASTM D7566 (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
3. Amend Sec. 80.3 by revising entry LNG to read as follows:
Sec. 80.3 Acronyms and abbreviations.
* * * * *
LNG............................ Liquefied natural gas.
* * * * *
------------------------------------------------------------------------
0
4. 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 U.S. EPA and at the National
Archives and Records Administration (NARA). Contact 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. For information on the availability of this material at
NARA, visit: www.archives.gov/federal-register/cfr/ibr-locations.html
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 (``AGA
Report No. 3 Part 1''); 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 (``AGA Report No. 3 Part 2''); 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 (``AGA Report No. 3 Part 3''); IBR approved for Sec. 80.155(a).
(4) AGA Report No. 3 Part 1, 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 (``AGA Report No. 3
Part 4''); IBR approved for Sec. 80.155(a).
(5) AGA Report No. 9, Measurement of Gas by Multipath Ultrasonic
Meters, 2nd Edition, April 2007 (``AGA Report No. 9); IBR approved for
Sec. 80.155(a).
(6) AGA Report No. 11, Measurement of Natural Gas by Coriolis
Meter, 2nd Edition, February 2013 (``AGA Report No. 11); IBR approved
for Sec. 80.155(a).
(b) American National Standards Institute (ANSI), 1899 L Street NW,
11th Floor, Washington, DC 20036; (202) 293-8020; www.ansi.org.
(1) ANSI B109.3-2019 (R2024), Rotary-Type Gas Displacement Meters,
February 5, 2019, Reaffirmed April 16, 2024 (``ANSI B109.3''); IBR
approved for Sec. 80.155(a).
(2) [Reserved]
(c) 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 (``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 1 to paragraph (a):
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.
(d) American Public Health Association (APHA), 1015 15th Street NW,
Washington, DC 20005; (202) 777-2742; www.standardmethods.org.
[[Page 25860]]
(1) SM 2540, Solids, revised June 10, 2020; IBR approved for Sec.
80.155(c).
(2) [Reserved]
(e) American Society of Mechanical Engineers (ASME), Two Park
Avenue, New York, NY 10016-5990; (800) 843-2763; www.asme.org.
(1) ASME MFC-5.1-2011 (R2024), Measurement of Liquid Flow in Closed
Conduits Using Transit-Time Ultrasonic Flowmeters, June 17, 2011,
Reaffirmed 2024 (``ASME MFC-5.1''); IBR approved for Sec. 80.155(a).
(2) ASME MFC[hyphen]21.2-2010 (R2018), Measurement of Fluid Flow by
Means of Thermal Dispersion Mass Flowmeters, January 10, 2011,
Reaffirmed 2018 (``ASME MFC-21.2''); IBR approved for Sec. 80.155(a).
(f) 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 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).
(4) ASTM D1945-14 (Reapproved 2019), Standard Test Method for
Analysis of Natural Gas by Gas Chromatography, approved December 1,
2019 (``ASTM D1945''); IBR approved for Sec. 80.155(b).
(5) ASTM D3588-98 (Reapproved 2024)e1, Standard Practice for
Calculating Heat Value, Compressibility Factor, and Relative Density of
Gaseous Fuels, reapproved May 1, 2024 (``ASTM D3588''); IBR approved
for Sec. 80.155(b) and (f).
(6) 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).
(7) 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).
(8) ASTM D4442-20, Standard Test Methods for Direct Moisture
Content Measurement of Wood and Wood-Based Materials, approved March 1,
2020 (``ASTM D4442''); IBR approved for Sec. 80.1426(f).
(9) ASTM D4444-13 (Reapproved 2018), Standard Test Method for
Laboratory Standardization and Calibration of Hand-Held Moisture
Meters, reapproved July 1, 2018 (``ASTM D4444''); IBR approved for
Sec. 80.1426(f).
(10) 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).
(11) 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).
(12) 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).
(13) ASTM D5854-19a, Standard Practice for Mixing and Handling of
Liquid Samples of Petroleum and Petroleum Products, approved May 1,
2019 (``ASTM D5854''); IBR approved for Sec. 80.8(d).
(14) 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.
(15) 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).
(16) 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).
(17) 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).
(18) 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).
(19) ASTM E870-24, Standard Test Methods for Analysis of Wood
Fuels, approved October 1, 2024 (``ASTM E870''); IBR approved for Sec.
80.1426(f).
(g) 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]
(h) 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, Measurement of fluid flow by means of pressure
differential devices inserted in circular cross-section conduits
running full, Part 1: General principles and requirements, 3rd Edition,
June 2022 (``ISO 5167-1''); IBR approved for Sec. 80.155(a).
(2) ISO 5167-2:2022, Measurement of fluid flow by means of pressure
differential devices inserted in circular cross-section conduits
running full, Part 2: Orifice plates, 2nd Edition, June 2022 (``ISO
5167-2''); IBR approved for Sec. 80.155(a).
(3) ISO 5167-4:2022, Measurement of fluid flow by means of pressure
differential devices inserted in circular cross-section conduits
running full, Part 4: Venturi tubes, 2nd Edition, June 2022 (``ISO
5167-4''); IBR approved for Sec. 80.155(a).
(4) ISO 5167-5:2022, Measurement of fluid flow by means of pressure
differential devices inserted in circular cross-section conduits
running full, Part 5: Cone meters, 2nd Edition, October 2022 (``ISO
5167-5''); IBR approved for Sec. 80.155(a).
(5) ISO 17089-2:2012, Measurement of fluid flow in closed
conduits--Ultrasonic meters for gas, Part 2: Meters for industrial
applications, 1st Edition, October 2012 (``ISO 17089-2''); IBR approved
for Sec. 80.155(a).
(i) International Organization of Legal Metrology (OIML), 11 Rue
Turgot, F-75009, Paris, France; +33 1 4878 1282; www.oiml.org.
(1) OIML R 137-1 and 2, Gas meters, Part 1: Metrological and
technical requirements and Part 2: Metrological controls and
performance tests, Edition 2012, Including Amendment 2014 (``OIML R
137-1 and 2''); IBR approved for Sec. 80.155(a).
(2) [Reserved]
(i) U.S. Environmental Protection Agency (EPA), 1200 Pennsylvania
Avenue NW, Washington, DC 20460; (202) 272-0167; www.epa.gov.
(1) EPA/625/R-96/010b, Compendium Method TO-15, Determination Of
Volatile Organic Compounds (VOCs) In Air Collected In Specially-
Prepared Canisters And
[[Page 25861]]
Analyzed By Gas Chromatography/Mass Spectrometry (GC/MS), Second
Edition, January 1999 (``EPA Method TO-15''); IBR approved for Sec.
80.155(b).
(2) [Reserved]
Subpart E--Biogas-Derived Renewable Fuel
0
5. 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
6. Amend Sec. 80.110 by revising paragraph (j)(3) to read as follows:
Sec. 80.110 RNG producers, RNG importers, and biogas closed
distribution system RIN generators.
* * * * *
(j) * * *
(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
7. Amend Sec. 80.125 by revising paragraphs (d)(4) and (e)(2) to read
as follows:
Sec. 80.125 RINs for RNG.
* * * * *
(d) * * *
(4) A party must only separate a number of RINs equal to or less
than the total volume of RNG (where the Btu LHV are converted to
gallon-RINs using the conversion specified in Sec. 80.1415(b)(1)) that
the party demonstrates is used as renewable CNG/LNG under paragraph
(d)(2) of this section.
* * * * *
(e) * * *
(2) A party must retire all assigned RINs for a volume of RNG if
the RINs are not separated under paragraph (d) of this section by March
31 of the subsequent calendar year after the RNG RIN was generated.
* * * * *
0
8. Amend Sec. 80.135 by revising paragraphs (c)(3)(i),
(c)(10)(vi)(A)(5), and (d)(3)(i) to read as follows:
Sec. 80.135 Registration.
* * * * *
(c) * * *
(3) * * *
(i) A description of how biogas will be measured, including the
specific standards under which the meters are operated, the fluid with
which the meters were calibrated, and the equivalency to biogas flow
for meters calibrated with a fluid other than biogas, as applicable.
* * * * *
(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) * * *
(i) A description of how RNG will be measured, including the
specific standards under which the meters are operated, the fluid with
which the meters were calibrated, and the equivalency to RNG flow for
meters calibrated with a fluid other than natural gas, as applicable.
* * * * *
0
9. Amend Sec. 80.140 by revising paragraph (b)(2) to read as follows:
Sec. 80.140 Reporting.
* * * * *
(b) * * *
(2) Production date.
* * * * *
0
10. Amend Sec. 80.155 by:
0
a. Revising and republishing paragraph (a)(2); and
0
b. Revising paragraph (b)(2)(v).
The revisions read as follows:
Sec. 80.155 Sampling, testing, and measurement.
(a) * * *
(2) Flow meters tested and calibrated under OIML R 137-1 and 2
(incorporated by reference, see Sec. 80.12) and compliant with one of
the following:
(i) AGA Report No. 3 Parts 1, 2, 3, and 4 or API MPMS 14.3.1, API
MPMS 14.3.2, API MPMS 14.3.3, and API MPMS 14.3.4 (incorporated by
reference, see Sec. 80.12).
(ii) API MPMS 14.12 (incorporated by reference, see Sec. 80.12).
(iii) EN 17526 (incorporated by reference, see Sec. 80.12)
compatible with gas type H.
(iv) AGA Report No. 9 (incorporated by reference, see Sec. 80.12).
(v) AGA Report No. 11 or API MPMS 14.9 (incorporated by reference,
see Sec. 80.12).
(vi) ASME MFC-5.1 (incorporated by reference, see Sec. 80.12).
(vii) ASME MFC[hyphen]21.2 (incorporated by reference, see Sec.
80.12).
(viii) ANSI B109.3 (incorporated by reference, see Sec. 80.12).
(ix) ISO 5167-1 and ISO 5167-2, ISO 5167-4, or ISO 5167-5
(incorporated by reference, see Sec. 80.12).
(x) ISO 17089-2 (incorporated by reference, see Sec. 80.12).
* * * * *
(b) * * *
(2) * * *
(v) Hydrocarbon analysis using EPA Method 18 (see Appendix A-6 to
40 CFR part 60), EPA Method TO-15, or ASTM D1945 (incorporated by
reference, see Sec. 80.12).
* * * * *
Subpart M--Renewable Fuel Standard
0
11. Amend Sec. 80.1405 by:
0
a. Revising entry 2025 and adding entries 2026 and 2027 in table 1 to
paragraph (a); and
0
b. Revising paragraphs (c) and (d).
The revisions and addition read as follows:
Sec. 80.1405 What are the Renewable Fuel Standards?
(a) * * *
[[Page 25862]]
Table 1 to Paragraph (a)--Annual Renewable Fuel Standards
----------------------------------------------------------------------------------------------------------------
Cellulosic Advanced Renewable
biofuel Biomass-based biofuel fuel Supplemental total
Year standard diesel standard standard standard renewable fuel
(%) (%) (%) (%) standard (%)
----------------------------------------------------------------------------------------------------------------
* * * * * * *
2025............................... 0.70 3.15 4.31 13.13 n/a
2026............................... 0.87 4.75 6.02 16.02 n/a
2027............................... 0.92 5.07 6.40 16.54 n/a
----------------------------------------------------------------------------------------------------------------
* * * * *
(c) EPA will calculate the annual renewable fuel percentage
standards using the following equations:
[GRAPHIC] [TIFF OMITTED] TP17JN25.007
Where:
StdCB,i = The cellulosic biofuel standard for year i, in
percent.
StdBBD,i = The biomass-based diesel standard for year i,
in percent.
StdAB,i = The advanced biofuel standard for year i, in
percent.
StdRF,i = The 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 blended renewable fuel projected to be
contained in the projection of Gi for year i, in gallons.
RDi = Amount of blended renewable fuel projected to be
contained in the projection of Di for year i, in gallons.
GEi = The total amount of gasoline projected to be exempt
for year i, in gallons, per Sec. Sec. 80.1441 and 80.1442.
DEi = The total 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
12. 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
13. 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)(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)(1) Equivalence values for certain renewable fuels are assigned
as follows:
Table 1 to Paragraph (b)(1)--Equivalence Values for Certain Renewable
Fuels
------------------------------------------------------------------------
Equivalence
Renewable fuel Amount value
------------------------------------------------------------------------
Denatured ethanol................. 1 gallon............ 1.0
Biodiesel......................... 1 gallon............ 1.5
Butanol........................... 1 gallon............ 1.3
Renewable diesel.................. 1 gallon............ 1.6
[[Page 25863]]
Renewable naphtha................. 1 gallon............ 1.4
Renewable jet fuel................ 1 gallon............ 1.6
Fuels that are gaseous at STP 77,000 Btu LHV...... 1.0
(e.g., RNG, renewable CNG/LNG).
------------------------------------------------------------------------
(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
14. 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
15. Amend Sec. 80.1426 by:
0
a. Adding paragraph (a)(5);
0
b. Revising paragraph (b)(2), (c)(7), and (e);
0
c. In paragraphs (f)(1)(v)(A) and (B), removing the text ``D-code'' and
adding in its place the text ``D code'';
0
d. Adding paragraph (f)(1)(vii);
0
e. Revising paragraph (f)(8) introductory text, (f)(8)(iii), (f)(10),
(11) and (17);
0
f. Adding paragraph (f)(18); and
0
g. Revising table 1 to Sec. 80.1426.
The additions and revisions read as follows:
Sec. 80.1426 How are RINs generated and assigned to batches of
renewable fuel?
(a) * * *
(5) Starting January 1, 2026, the following parties must reduce the
number of RINs generated, as calculated under paragraphs (f) of this
section, for the specified renewable fuel by 50 percent:
(i) RIN-generating foreign producers, for all renewable fuel
produced.
(ii) RIN-generating importers of renewable fuel, for all imported
renewable fuel.
(iii) Domestic renewable fuel producers, for all renewable fuel
produced from foreign feedstocks or foreign biointermediates.
(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 the point of 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 RNG and renewable fuels that are gaseous at STP, RINs must
be assigned to a volume of RNG or renewable fuel, as applicable, at the
same time the RIN is generated.
(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 GHG reduction requirement
* * * * *
(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) 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.
[[Page 25864]]
(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) 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 of 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.
(ii) 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), 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), 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), 80.130(b), and this paragraph (f), as applicable.
(B) For foreign produced RIN-less RNG, RINs must be generated when
title is transferred from the foreign producer to the RIN-generating
importer.
* * * * *
Table 1 to Sec. 80.1426--Applicable D Codes for Each Fuel Pathway for
Use in Generating RINs
------------------------------------------------------------------------
Production
Row Fuel type Feedstock process D Code
requirements
------------------------------------------------------------------------
A........ Ethanol......... Corn starch..... All the 6
following: Dry
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 6
following: Dry
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 6
following: Dry
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 6
process using
biomass or
biogas for
process energy.
E........ Ethanol......... Starches from Fermentation 6
crop residue using natural
and annual gas, biomass,
cover crops. or biogas for
process energy.
[[Page 25865]]
F........ Biodiesel; Soybean oil; Oil The following 4
Renewable from annual processes that
diesel; cover crops; do not co-
Renewable jet Oil from algae process
fuel; Renewable grown renewable
fuel oil. photosynthetica biomass and
lly; Biogenic petroleum:
waste oils/fats/ Transesterific
greases; ation with or
Camelina sativa without
oil; Distillers esterification
corn oil; pre-treatment;
Distillers Esterification
sorghum oil; ;
Commingled Hydrotreating.
distillers corn
oil and sorghum
oil.
G........ Biodiesel; Canola/Rapeseed The following 4
Renewable oil. processes that
diesel; do not co-
Renewable jet process
fuel; Renewable renewable
fuel oil. biomass and
petroleum:
Transesterific
ation using
natural gas or
biomass for
process
energy;
Hydrotreating.
H........ Biodiesel; Soybean oil; Oil The following 5
Renewable from annual processes that
diesel; cover crops; co-process
Renewable jet Oil from algae renewable
fuel; Renewable grown biomass and
fuel oil. photosynthetica petroleum:
lly; Biogenic Transesterific
waste oils/fats/ ation with or
greases; without
Camelina sativa esterification
oil; Distillers pre-treatment;
corn oil; Esterification
Distillers ;
sorghum oil; Hydrotreating.
Commingled
distillers corn
oil and sorghum
oil; Canola/
Rapeseed oil.
I........ Renewable Camelina sativa Hydrotreating.. 5
naphtha; LPG. oil; 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; Biochemical 3
Slash, pre- fermentation
commercial process that
thinnings, and converts
tree residue; cellulosic
Switchgrass; biomass to
Miscanthus; ethanol and
Energy cane; uses the
Arundo donax; lignin and
Pennisetum other biogenic
purpureum; feedstock
Separated yard residues from
waste; Biogenic the
components of fermentation
separated MSW; and ethanol
Cellulosic production
components of processes for
separated food all thermal
waste; and electrical
Cellulosic process energy
components of and are net
annual cover exporters of
crops. electricity to
the grid;
Thermochemical
gasification
process that
converts
cellulosic
biomass to
ethanol and
uses a portion
of the
feedstock for
over 99% of
thermal and
electrical
process
energy; Dry
mill process
that converts
corn or grain
sorghum kernel
fiber to
ethanol and
uses natural
gas, biogas,
or crop
residue for
all thermal
process energy.
L........ Cellulosic Crop residue; Fischer-Tropsch 7
diesel; Slash, pre- process that
Renewable jet commercial converts
fuel; Renewable thinnings, and cellulosic
fuel oil. tree residue; biomass to
Switchgrass; fuel and uses
Miscanthus; a portion of
Energy cane; the feedstock
Arundo donax; for over 99%
Pennisetum of thermal and
purpureum; electrical
Separated yard process energy.
waste; Biogenic
components of
separated MSW;
Cellulosic
components of
separated food
waste;
Cellulosic
components of
annual cover
crops.
M........ Renewable Crop residue; The following 3
gasoline; Slash, pre- processes that
Renewable commercial convert
gasoline thinnings, and cellulosic
blendstock; Co- tree residue; biomass to
processed Separated yard fuel using
cellulosic waste; Biogenic natural gas,
diesel; components of biogas, or
Renewable jet separated MSW; biomass as the
fuel; Renewable Cellulosic only process
fuel oil. components of energy
separated food sources:
waste; Catalytic
Cellulosic pyrolysis and
components of upgrading;
annual cover Gasification
crops. and upgrading;
Thermo-
catalytic
hydrodeoxygena
tion and
upgrading;
Direct
biological
conversion;
Biological
conversion and
upgrading.
N........ Renewable Switchgrass; Gasification 3
naphtha. Miscanthus; and upgrading
Energy cane; processes that
Arundo donax; convert
Pennisetum cellulosic
purpureum. biomass to
fuel.
O........ Butanol......... Corn starch..... Fermentation; 6
Dry mill
process using
natural gas,
biomass, or
biogas for
process energy.
P........ Ethanol; Non-cellulosic Fermentation 5
Renewable portions of using natural
diesel; separated food gas, biogas,
Renewable jet waste; Non- or crop
fuel; Renewable cellulosic residue for
fuel oil; components of thermal
Renewable annual cover energy;
naphtha. crops. Hydrotreating;
Transesterific
ation.
Q........ Renewable CNG; Biogas from The following 3
Renewable LNG. landfills, processes that
municipal occur in North
wastewater America: CNG
treatment production
facility from treated
digesters, biogas via
agricultural compression;
digesters, and LNG production
separated MSW from treated
digesters; biogas via
Biogas from the liquefaction.
cellulosic
components of
biomass
processed in
other waste
digesters.
R........ Ethanol......... Grain sorghum... Dry mill 6
process using
natural gas or
biogas from
landfills,
waste
treatment
plants, or
waste
digesters for
process energy.
S........ Ethanol......... Grain sorghum... Dry mill 5
process using
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 The following 5
Renewable LNG. waste digesters. processes that
occur in North
America: CNG
production
from treated
biogas via
compression;
LNG production
from treated
biogas via
liquefaction.
------------------------------------------------------------------------
* * * * *
0
16. Amend Sec. 80.1428 by:
0
a. Revising paragraph (a)(3);
0
b. Removing paragraph (a)(4); and
0
c. Redesignating paragraph (a)(5) as paragraph (a)(4).
The revision reads as follows:
Sec. 80.1428 General requirements for RIN distribution.
(a) * * *
(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.
[[Page 25866]]
(ii) For RNG, the transferor of assigned RINs with a K code of 3
must transfer RINs under Sec. 80.125(c).
* * * * *
0
17. Amend Sec. 80.1429 by:
0
a. Revising paragraph (b)(5)(i);
0
b. Removing the text ``only'' in paragraph (b)(5)(ii)(B); and
0
c. Revising paragraph (c)
The revisions 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.
* * * * *
(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.
* * * * *
Sec. 80.1435 [Amended]
0
18. 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
19. 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 year.
* * * * *
0
20. 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 year.
* * * * *
Sec. 80.1444 [Amended]
0
21. Amend Sec. 80.1444 by, in paragraph (b), removing the text ``in
Sec. 80.1401''.
0
22. Amend Sec. 80.1449 by:
0
a. Revising paragraphs (a) introductory text, (a)(1), (a)(4)(i),
(a)(4)(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
23. Amend Sec. 80.1450 by:
0
a. Revising the last sentence in paragraphs (a);
0
b. Revising paragraphs (b)(1)(v)(D) introductory text, (b)(1)(v)(D)(1),
(b)(1)(xi), (b)(1)(xii) introductory text, (b)(1)(xii)(A), (b)(2),
(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) * * *
(v) * * *
(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.
* * * * *
(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 of 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.
[[Page 25867]]
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 Sec. 80.1450(g)(1) through (g)(7)
no later than October 31 before the calendar year that their
registration expires.
* * * * *
0
24. 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)(T);
0
d. Removing paragraph (c)(2)(ii)(D)(14); and
0
e. In paragraph (g)(1)(viii), removing the text ``D-code'' and adding
in its place the text ``D code''.
The revisions read as follows:
Sec. 80.1451 What are the reporting requirements under the RFS
program?
* * * * *
(b) * * *
(1) * * *
(ii) * * *
(L) Each process, feedstock, feedstock point of origin, and
biointermediate, as applicable, used and proportion of renewable volume
attributable to each process, feedstock, feedstock point of origin, and
biointermediate, as applicable.
* * * * *
(T) Producers or importers of any renewable fuel other than
ethanol, biodiesel, renewable gasoline, renewable jet fuel, renewable
diesel that meets the paragraph (1) of the definition of renewable
diesel, biogas-derived renewable fuel, or RNG, must report, on a
quarterly basis, all the following for each volume of fuel:
* * * * *
0
25. Amend Sec. 80.1452 by
0
a. Revising paragraphs (a), (b) introductory text, (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) The type of RIN generation protocol (e.g., domestic, import,
co-processing, etc) 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
26. Amend Sec. 80.1453 by revising paragraphs (a)(12)(v), (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
27. Amend Sec. 80.1454 by:
0
a. Revising paragraph (a) introductory text, (b) introductory text,
(b)(3)(ix), (b)(8), (c)(1) introductory text, and (d)(1);
0
b. 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
c. Revising and republishing paragraph (k)(1);
0
d. Revising paragraphs (k)(2) introductory text, (l) introductory text,
(l)(2), and (l)(3)(iv);
0
e. Removing paragraph (m)(8); and
[[Page 25868]]
0
f. 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.
* * * * *
(d) * * *
(1)(i) Starting January 1, 2026, any domestic producer of renewable
fuel that generates RINs for such fuel must keep records of feedstock
purchases and transfers (e.g., bills of sale, delivery receipts) that
identify the feedstock point of origin for each feedstock (i.e.,
domestic or foreign).
(ii) Except as provided in paragraphs (g) and (h) of this section,
any domestic producer of renewable fuel that generates RINs for such
fuel must keep documents associated with feedstock purchases and
transfers that identify where the feedstocks were produced and are
sufficient to verify that feedstocks used are renewable biomass if RINs
are generated.
* * * * *
(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), Sec.
80.1426(f)(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 which 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 which 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 of 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
28. Amend Sec. 80.1460 by revising paragraphs (b)(4) and (g) to read
as follows:
Sec. 80.1460 What acts are prohibited under the RFS program?
* * * * *
(b) * * *
(4) Transfer to any person a RIN with a K code of 1 or 3 without
transferring an appropriate volume of renewable fuel to the same person
on the same day.
* * * * *
(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
29. 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
30. Amend Sec. 80.1464 by revising paragraph (b)(1)(v)(B) to read as
follows:
Sec. 80.1464 What are the attest engagement requirements under the
RFS program?
* * * * *
(b) * * *
(1) * * *
(v) * * *
(B) Verify that feedstocks were properly identified in the reports,
including the feedstock point of origin for domestic renewable fuel
producers, and met the definition of renewable biomass.
* * * * *
0
31. 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).
[[Page 25869]]
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, including the feedstock point of origin.
* * * * *
(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 [Reserved]
0
32. Remove and reserve Sec. 80.1470.
0
33. Amend Sec. 80.1471 by:
0
a. Revising paragraph (b)(3);
0
b. Revising and republishing paragraph (e); and
0
c. Revising paragraph (f).
The revisions read as follows:
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 the EPA-approved remote monitoring system is
in place at the renewable fuel production facility.
* * * * *
0
34. 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)(2)(i)(B).
0
35. 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:
[[Page 25870]]
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
36. 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
37. 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, 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
38. 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
39. 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
40. 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
41. Amend Sec. 1090.80 by:
0
a. Revising paragraph (2) in the definition ``Diesel fuel'';
0
b. Removing the definition ``Nonpetroleum (NP) diesel fuel'';
0
c. Adding the definition ``Nonpetroleum diesel fuel''; and
0
d. Revising the last sentence in the definition of ``Responsible
corporate officer (RCO)''.
The revision 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
42. Amend Sec. 1090.95 by revising paragraphs (c)(1), (2), (4), (8),
(11), (15) through (18), (21), (25), (28), and (32) through (38) to
read as follows:
Sec. 1090.95 Incorporation by Reference.
* * * * *
(c) * * *
(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).
* * * * *
(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).
* * * * *
(8) ASTM D2622-24a, Standard Test Method for Sulfur in Petroleum
[[Page 25871]]
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).
* * * * *
(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).
* * * * *
(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 D4806-21a, Standard Specification for Denatured Fuel
Ethanol for Blending with Gasolines for Use as Automotive Spark-
Ignition Engine Fuel, approved October 1, 2021 (``ASTM D4806''); IBR
approved for Sec. 1090.1395(a).
(17) ASTM D4814-24b, Standard Specification for Automotive Spark-
Ignition Engine Fuel, approved December 1, 2024 (``ASTM D4814''); IBR
approved for Sec. Sec. 1090.80; 1090.1395(a).
(18) ASTM D5134-21, Standard Test Method for Detailed Analysis of
Petroleum Naphthas through n-Nonane by Capillary Gas Chromatography,
approved December 1, 2021 (``ASTM D5134''); IBR approved for Sec.
1090.1350(b).
* * * * *
(21) ASTM D5453-24, 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 October 15,
2024 (``ASTM D5453''); IBR approved for Sec. 1090.1350(b).
* * * * *
(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).
* * * * *
(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).
* * * * *
(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), and 1090.1375(c).
(33) ASTM D6729-20, Standard Test Method for Determination of
Individual Components in Spark Ignition Engine Fuels by 100 Metre
Capillary High Resolution Gas Chromatography, approved June 1, 2020
(``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) and
1090.1350(b).
(36) ASTM D6792-23c, Standard Practice for Quality Management
Systems in Petroleum Products, Liquid Fuels, and Lubricants Testing
Laboratories, approved November 1, 2023 (``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 D--Diesel Fuel and ECA Marine Fuel Standards
0
43. 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 in
Sec. 1090.95) is not subject to the cetane index or aromatic content
standards in Sec. 1090.305(c). Biodiesel or biodiesel blends that do
not meet ASTM D6751 remain subject to the cetane index or aromatic
content standards in Sec. 1090.305(c).
* * * * *
0
44. Amend Sec. 1090.305 by revising paragraph (a) to read as follows:
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
45. 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
46. 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. 2025-11128 Filed 6-16-25; 8:45 am]
BILLING CODE 6560-50-P