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Proposed Rule2022-26499

Renewable Fuel Standard (RFS) Program: Standards for 2023-2025 and Other Changes

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Published

December 30, 2022

Issuing agencies

Environmental Protection Agency

Abstract

Under the Clean Air Act, 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. This action proposes the applicable volumes and percentage standards for 2023 through 2025 for cellulosic biofuel, biomass-based diesel, advanced biofuel, and total renewable fuel. This action also proposes the second supplemental standard addressing the remand of the 2016 standard-setting rulemaking. Finally, this action proposes several regulatory changes to the RFS program including regulations governing the generation of qualifying renewable electricity and other modifications intended to improve the program's implementation.

Full Text

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[Federal Register Volume 87, Number 250 (Friday, December 30, 2022)]
[Proposed Rules]
[Pages 80582-80756]
From the Federal Register Online via the Government Publishing Office [<a href="http://www.gpo.gov">www.gpo.gov</a>]
[FR Doc No: 2022-26499]

[[Page 80581]]

Vol. 87

Friday,

No. 250

December 30, 2022

Part II

Environmental Protection Agency

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40 CFR Parts 80 and 1090

Renewable Fuel Standard (RFS) Program: Standards for 2023-2025 and
Other Changes; Proposed Rule

Federal Register / Vol. 87 , No. 250 / Friday, December 30, 2022 /
Proposed Rules

[[Page 80582]]

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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Parts 80 and 1090

[EPA-HQ-OAR-2021-0427; FRL-8514-01-OAR]
RIN 2060-AV14

Renewable Fuel Standard (RFS) Program: Standards for 2023-2025
and Other Changes

AGENCY: Environmental Protection Agency (EPA).

ACTION: Proposed rule.

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SUMMARY: Under the Clean Air Act, 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. This action proposes the applicable volumes and percentage
standards for 2023 through 2025 for cellulosic biofuel, biomass-based
diesel, advanced biofuel, and total renewable fuel. This action also
proposes the second supplemental standard addressing the remand of the
2016 standard-setting rulemaking. Finally, this action proposes several
regulatory changes to the RFS program including regulations governing
the generation of qualifying renewable electricity and other
modifications intended to improve the program's implementation.

DATES:
Comments. Comments must be received on or before February 10, 2023.
Public Hearing. EPA will announce information regarding the public
hearing for this proposal in a supplemental Federal Register document.

ADDRESSES:
Comments. You may send your comments, identified by Docket ID No.
EPA-HQ-OAR-2021-0427, by any of the following methods:
<bullet> Federal eRulemaking Portal: <a href="http://www.regulations.gov">http://www.regulations.gov</a>
(our preferred method). Follow the online instructions for submitting
comments.
<bullet> Email: <a href="/cdn-cgi/l/email-protection#18793579767c356a355c777b737d6c587d6879367f776e">[email&#160;protected]</a>. Include Docket ID No. EPA-
HQ-OAR-2021-0427 in the subject line of the message.
<bullet> Mail: U.S. Environmental Protection Agency, EPA Docket
Center, Air Docket, Mail Code 28221T, 1200 Pennsylvania Avenue NW,
Washington, DC 20460.
<bullet> Hand Delivery or Courier: EPA Docket Center, WJC West
Building, Room 3334, 1301 Constitution Avenue NW, Washington, DC 20004.
The Docket Center's hours of operation are 8:30 a.m.-4:30 p.m., Monday-
Friday (except Federal Holidays).
Instructions: All submissions received must include the Docket ID
No. for this rulemaking. Comments received may be posted without change
to <a href="https://www.regulations.gov">https://www.regulations.gov</a>, including any personal information
provided. For the full EPA public comment policy, information about CBI
or multimedia submissions, and general guidance on making effective
comments, please visit <a href="http://www.epa.gov/dockets/commenting-epa-dockets">http://www.epa.gov/dockets/commenting-epa-dockets</a>.

FOR FURTHER INFORMATION CONTACT: David Korotney, Office of
Transportation and Air Quality, Assessment and Standards Division,
Environmental Protection Agency, 2000 Traverwood Drive, Ann Arbor, MI
48105; telephone number: 734-214-4507; email address: <a href="/cdn-cgi/l/email-protection#782a3e2b552a0d141d15191311161f0b381d0819561f170e">[email&#160;protected]</a>. Comments on this proposal should not be submitted
to this email address, but rather through <a href="http://www.regulations.gov">http://www.regulations.gov</a> as
discussed in the ADDRESSES section.

SUPPLEMENTARY INFORMATION: Entities potentially affected by this
proposed rule are those involved with the production, distribution, and
sale of transportation fuels (e.g., gasoline and diesel fuel),
renewable fuels (e.g., ethanol, biodiesel, renewable diesel, biogas,
and renewable electricity), and electric vehicles. Potentially affected
categories include:

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NAICS \a\
Category Codes Examples of potentially affected entities
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Industry...................................... 112111 Cattle farming or ranching.
Industry...................................... 112210 Swine, hog, and pig farming.
Industry...................................... 221117 Biomass electric power generation.
Industry...................................... 221210 Manufactured gas production and distribution,
and distribution of renewable natural gas
(RNG).
Industry...................................... 221320 Sewage treatment plants or facilities.
Industry...................................... 324110 Petroleum refineries.
Industry...................................... 325120 Biogases, industrial (i.e., compressed,
liquefied, solid), manufacturing.
Industry...................................... 325193 Ethyl alcohol manufacturing.
Industry...................................... 325199 Other basic organic chemical manufacturing.
Industry...................................... 336110 Electric automobiles for highway use
manufacturing.
Industry...................................... 424690 Chemical and allied products merchant
wholesalers.
Industry...................................... 424710 Petroleum bulk stations and terminals.
Industry...................................... 424720 Petroleum and petroleum products merchant
wholesalers.
Industry...................................... 454319 Other 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 likely to be affected by this
proposed action. This table lists the types of entities that EPA is now
aware could potentially be affected by this proposed action. Other
types of entities not listed in the table could also be affected. To
determine whether your entity would be affected by this proposed
action, you should carefully examine the applicability criteria in 40
CFR part 80. If you have any questions regarding the applicability of
this proposed action to a particular entity, consult the person listed
in the FOR FURTHER INFORMATION CONTACT section.

Outline of This Preamble

I. Executive Summary
A. Summary of the Key Provisions of This Regulatory Action
B. Environmental Justice
C. Comparison of Costs to Impacts
D. Policy Considerations
E. Endangered Species Act
II. Statutory Requirements and Conditions
A. Requirement To Set Volumes for Years After 2022
B. Factors That Must Be Analyzed
C. Statutory Conditions on Volume Requirements
D. Authority To Establish Percentage Standards for Multiple
Future Years
E. Considerations for Late Rulemaking
F. Impact on Other Waiver Authorities
G. Severability
III. Candidate Volumes and Baselines

[[Page 80583]]

A. Number of Years Analyzed
B. Production and Import of Renewable Fuel
C. Candidate Volumes for 2023-2025
D. Baselines
E. Volume Changes Analyzed
IV. Analysis of Candidate Volumes
A. Climate Change
B. Energy Security
C. Costs
D. Comparison of Costs and Impacts
E. Assessment of Environmental Justice
V. Response to Remand of 2016 Rulemaking
A. Supplemental 2023 Standard
B. Authority and Consideration of the Benefits and Burdens
VI. Proposed Volume Requirements for 2023-2025
A. Cellulosic Biofuel
B. Non-Cellulosic Advanced Biofuel
C. Biomass-Based Diesel
D. Conventional Renewable Fuel
E. Summary of Proposed Volume Requirements
F. Request for Comment on Volume Requirements for 2026
G. Request for Comment on Alternative Volume Requirements
VII. Proposed Percentage Standards for 2023-2025
A. Calculation of Percentage Standards
B. Treatment of Small Refinery Volumes
C. Proposed Percentage Standards
VIII. Regulatory Program for Renewable Electricity
A. Historical Treatment of Electricity in the RFS Program
B. The eRIN Generation and Disposition Chain
C. Policy Goals in Developing the eRIN Program
D. Regulatory Goals in Developing the eRIN Program
E. Proposed Applicability of the eRIN Program
F. Proposed Program Structure for Light-Duty Vehicles
G. How the Proposed Program Structure Meets the Goals
H. Alternative eRIN Program Structures
I. Equivalence Value for Electricity
J. Regulatory Structure and Implementation Dates
K. Definitions
L. Registration, Reporting, Product Transfer Documents, and
Recordkeeping
M. Testing and Measurement Requirements
N. RFS Quality Assurance Program (QAP)
O. Compliance and Enforcement Provisions and Attest Engagements
P. Foreign Producers
IX. Other Changes to Regulations
A. RFS Third-Party Oversight Enhancement
B. Deadline for Third-Party Engineering Reviews for Three-Year
Updates
C. RIN Apportionment in Anaerobic Digesters
D. BBD Conversion Factor for Percentage Standard
E. Flexibility for RIN Generation
F. Changes to Tables in 40 CFR 80.1426
G. Prohibition on RIN Generation for Fuels Not Used in the
Covered Location
H. Seeking Public Comment on Hydrogen Fuel Lifecycle Analysis
I. Biogas Regulatory Reform
J. Separated Food Waste Recordkeeping Requirements
K. Definition of Ocean-Going Vessels
L. Bond Requirement for Foreign RIN-Generating Renewable Fuel
Producers
M. Definition of Produced From Renewable Biomass
N. Limiting RIN Separation Amounts
O. Technical Amendments
X. Statutory and Executive Order Reviews
A. Executive Order 12866: Regulatory Planning and Review and
Executive Order 13563: Improving Regulation and Regulatory Review
B. Paperwork Reduction Act (PRA)
C. Regulatory Flexibility Act (RFA)
D. Unfunded Mandates Reform Act (UMRA)
E. Executive Order 13132: Federalism
F. Executive Order 13175: Consultation and Coordination With
Indian Tribal Governments
G. Executive Order 13045: Protection of Children From
Environmental Health Risks and Safety Risks
H. Executive Order 13211: Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution, or Use
I. National Technology Transfer and Advancement Act (NTTAA) &
Incorporation by Reference
J. Executive Order 12898: Federal Actions To Address
Environmental Justice in Minority Populations, and Low-Income
Populations
XI. Statutory Authority

A red-line version of the regulatory language that incorporates the
changes in this action is available in the docket for this action.

I. Executive Summary

The Renewable Fuel Standard (RFS) program began in 2006 pursuant to
the requirements of the Energy Policy Act of 2005 (EPAct), which were
codified in Clean Air Act (CAA) section 211(o). The statutory
requirements were subsequently amended by the Energy Independence and
Security Act of 2007 (EISA). The statute sets forth annual, nationally
applicable volume targets for each of the four categories of renewable
fuel for the years shown below.

Table I-1--Years for Which the Statute Provides Volume Targets
------------------------------------------------------------------------
Category Years
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Cellulosic biofuel.......................................... 2010-2022
Biomass-based diesel........................................ 2009-2012
Advanced biofuel............................................ 2009-2022
Renewable fuel.............................................. 2006-2022
------------------------------------------------------------------------

For calendar years after those for which the statute provides
volume targets, the statute directs EPA to determine the applicable
volume targets in coordination with the Secretary of Energy and the
Secretary of Agriculture, based on a review of the implementation of
the program for prior years and an analysis of specified factors:
<bullet> 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; \1\
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\1\ CAA section 211(o)(2)(B)(ii)(I).
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<bullet> The impact of renewable fuels on the energy security of
the U.S.; \2\
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\2\ CAA section 211(o)(2)(B)(ii)(II).
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<bullet> The expected annual rate of future commercial production
of renewable fuels, including advanced biofuels in each category
(cellulosic biofuel and biomass-based diesel); \3\
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\3\ CAA section 211(o)(2)(B)(ii)(III).
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<bullet> The impact of renewable fuels on the infrastructure of the
U.S., including deliverability of materials, goods, and products other
than renewable fuel, and the sufficiency of infrastructure to deliver
and use renewable fuel; \4\
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\4\ CAA section 211(o)(2)(B)(ii)(IV).
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<bullet> The impact of the use of renewable fuels on the cost to
consumers of transportation fuel and on the cost to transport goods;
\5\ and
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\5\ CAA section 211(o)(2)(B)(ii)(V).
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<bullet> 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.\6\
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\6\ CAA section 211(o)(2)(B)(ii)(VI).
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While this statutory requirement does not apply to cellulosic
biofuel, advanced biofuel, and total renewable fuel until compliance
year 2023, it applied to biomass-based diesel (BBD) beginning in
compliance year 2013. Thus, EPA established applicable volume
requirements for BBD volumes for 2013-2022 in prior rulemakings.\7\
This action proposes the volume targets and applicable percentage
standards for cellulosic biofuel, BBD, advanced biofuel, and total
renewable fuel for 2023-2025. In association with these volume targets,
we are also proposing new regulations governing the generation of
Renewable Identification Numbers (RINs) for electricity made from
renewable biomass that is used for transportation fuel, as well as a
number of other regulatory changes intended to improve the operation of
the RFS program.
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\7\ See, e.g., 87 FR 39600 (July 1, 2022), establishing the 2022
BBD volume requirement.
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Low-carbon fuels are an important part of reducing greenhouse gas
(GHG) emissions in the transportation sector, and the RFS program is a
key federal policy that supports the development,

[[Page 80584]]

production, and use of low-carbon, domestically produced renewable
fuels. This ``Set rule'' proposal marks a new phase for the program,
one which takes place following the period for which the Clean Air Act
enumerates specific volume targets. We recognize the important role
that the RFS program can play in providing ongoing support for
increasing production and use of renewable fuels, particularly advanced
and cellulosic biofuels. For a number of years, RFS stakeholders have
provided their input on what policy direction this action should take,
and the Agency greatly appreciates the sustained and constructive input
we have received from stakeholders. The RFS program is entering a new
phase, and we are introducing a new regulatory program governing
renewable electricity. We welcome comments not only on the volumes we
are proposing in this rule but also on the analyses we conducted and
the proposed regulatory changes. EPA looks forward to continued
engagement with stakeholders on this rule, through the formal public
comment process, the public hearing we will hold, and through meetings
with program participants and others.

A. Summary of the Key Provisions of This Regulatory Action

1. Volume Requirements for 2023-2025
Based on our analysis of the factors required in the statute, and
in coordination with the Departments of Agriculture and Energy, we
propose to establish the volume targets for three years, 2023 to 2025,
as shown below. In addition to the volume targets, we are also
proposing to complete our response to the D.C. Circuit Court of
Appeals' remand of the 2016 annual rule in Americans for Clean Energy
v. EPA, 864 F.3d 691 (2017) (hereafter ``ACE'') by proposing a
supplemental volume requirement of 250 million gallons of renewable
fuel for 2023. This ``supplemental standard'' follows the
implementation of a 250-million-gallon supplement for 2022 in a
previous action.\8\
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\8\ 87 FR 39600 (July 1, 2022).

Table I.A.1-1--Proposed Volume Targets
[Billion RINs] \a\
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2023 2024 2025
----------------------------------------------------------------------------------------------------------------
Cellulosic biofuel.............................................. 0.72 1.42 2.13
Biomass-based diesel \b\........................................ 2.82 2.89 2.95
Advanced biofuel................................................ 5.82 6.62 7.43
Renewable fuel.................................................. 20.82 21.87 22.68
Supplemental standard........................................... 0.25 n/a n/a
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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 categories shown above, while gallons are
generally used to describe volumes for individual types of biofuel such as ethanol, biodiesel, renewable
diesel, etc. Exceptions include BBD (which is always given in physical volumes) and biogas and electricity
(which are always given in RINs).
\b\ The BBD volumes are in physical gallons (rather than RINs).

As discussed above, the statute requires that we analyze a
specified set of factors in making our determination of the appropriate
volume requirements to establish. However, many of those factors,
particularly those related to economic and environmental impacts, would
be difficult to analyze in the abstract. As a result, we needed to
identify a set of renewable fuel volumes to analyze prior to
determining the volume requirements that would be appropriate to
propose. To this end, we began by using a subset of the statutory
factors that are most closely related to production and consumption of
renewable fuel to identify ``candidate volumes'' that we then subjected
to the other economic and environmental factors that we are required to
analyze. The derivation of these candidate volumes is discussed in
Section III. Section IV discusses the analysis of those candidate
volumes for the other economic and environmental factors. Finally,
Section VI discusses our conclusions regarding the appropriate volume
requirements to propose in light of all of the analyses that we
conducted.
We believe that proposing volume targets for more than one year is
appropriate as it will provide the market with the certainty of demand
needed for longer term business and investment plans. At the same time,
setting volume targets too far out into the future can be difficult
given the higher uncertainty associated with projecting supply for
longer time periods and the increasing likelihood for unforeseen
circumstances to upset supply. By proposing volume requirements for
three years in this action but leaving the development of volume
requirements for 2026 and beyond to a subsequent action, we believe we
are striking a reasonable balance between certainty in our projections
and providing certainty for investment. Nevertheless, recognizing that
many regulated parties would appreciate knowing the applicable
standards for as many years as is reasonably possible, we are
requesting comment on establishing standards for 2026 in addition to
2023-2025 through this rulemaking.
The volume targets that we are proposing in this action would have
the same status as those in the statute for the years shown in Table I-
1. That is, they would be 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).
2. Applicable Percentage Standards for 2023-2025
Although the statute requires EPA to establish applicable
percentage standards annually by November 30 of the previous year, as
discussed in Section II, this requirement does not apply to years after
2022.\9\ For years after 2022, EPA can establish percentage standards
for any number of years at the same time that it establishes the volume
targets for those years. As this proposed rule is being released in
2022, we are proposing the applicable percentage standards for 2023 in
this action. In addition, we are proposing the percentage standards for
the two other years (2024 and 2025) for which we are proposing volume
requirements, the merits of which we discuss in Section II.D. The
proposed percentage standards corresponding to the proposed volume
requirements from Table I.A.1-1 are shown below.
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\9\ CAA section 211(o)(3).

[[Page 80585]]

Table I.A.2-1--Proposed Percentage Standards
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2023 2024 2025
----------------------------------------------------------------------------------------------------------------
Cellulosic biofuel.............................................. 0.41 0.82 1.23
Biomass-based diesel............................................ 2.54 2.60 2.67
Advanced biofuel................................................ 3.33 3.80 4.28
Renewable fuel.................................................. 11.92 12.55 13.05
Supplemental standard........................................... 0.14 n/a n/a
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The formulas used to calculate the percentage standards in 40 CFR
80.1405(c) require that EPA specify the projected volume of exempt
gasoline and diesel associated with exemptions for small refineries
granted because of disproportionate economic hardship resulting from
compliance with their obligations under the program. For this proposed
rulemaking we have projected that based on the information available at
the present time there are not likely to be small refinery exemptions
(SREs) for 2023-2025. This issue is discussed further in Section VII
along with the total nationwide projected gasoline and diesel
consumption volumes used in the calculation of the percentage
standards.
As in previous annual standard-setting rulemakings, the applicable
percentage standards for 2023-2025 would be added to the regulations at
40 CFR 80.1405(a).
3. Regulatory Provisions for eRINs
We are proposing regulatory changes to prescribe how RINs from
renewable electricity (eRINs) would be implemented and managed under
the RFS program. These changes are intended to address many of the
outstanding issues which to date have prevented EPA from registering
parties to allow them to generate eRINs produced from qualifying
renewable biomass and used as transportation fuel. The regulations we
propose as part of this action address a number of important areas,
including which parties can generate eRINs, prevention of double-
counting, and data requirements for valid eRIN generation. The proposed
changes are intended to provide clarity on how electricity would be
incorporated into the RFS so that the existing RIN-generating pathway
can be effectively utilized in a manner that ensures RINs are generated
only for qualifying electricity. We recognize that multiple
stakeholders have expressed interest in the design of the regulations
governing the generation of eRINs, and while this action proposes
regulations to implement one chosen approach, this package also
describes alternative approaches. We welcome comments on both the
proposed and alternative approaches.
In addition to the general program requirements for eRINs we are
also proposing to revise the equivalence value for renewable
electricity in the RFS program under 40 CFR 80.1415. The current value
of 22.6 kWh/RIN would be replaced by a value of 6.5 kWh/RIN. We believe
that this change would more accurately represent the use of electricity
as a transportation fuel relative to the production of biogas.
Given the timing of this rulemaking and the need for sufficient
time for regulated parties to become familiar with the new eRIN
regulatory requirements and to register for eRIN generation, we propose
that those requirements would become effective beginning on January 1,
2024. To this end, the proposed cellulosic volume requirements shown in
Table I.A.1-1 include our projected volumes for eRINs for years 2024
and 2025, but does not include any projection for eRINs for 2023.
4. Other Regulatory Changes
We have identified several areas where regulatory changes would
assist EPA in implementing the RFS program. These proposed regulatory
changes include:
<bullet> Enhancements to the third-party oversight provisions
including engineering reviews, the RFS quality assurance program, and
annual attest engagements;
<bullet> Establishing a deadline for third-party engineering
reviews for three-year registration updates;
<bullet> Updating procedures for the apportionment of RINs when
feedstocks qualifying for multiple D-codes (e.g., D3 and D5) are
converted to biogas simultaneously in an anaerobic digester;
<bullet> Revising the conversion factor in the formula for
calculating the percentage standard for BBD to reflect increasing
production volumes of renewable diesel;
<bullet> Amending the provisions for the generation of RINs for
straight vegetable oil to ensure that RINs are valid;
<bullet> Clarifying the definition of fuel used in ocean-going
vessels; and
<bullet> Other minor changes and technical corrections
Each of these regulatory changes is discussed in greater detail in
Section IX.
5. Request for Comment on Alternative Volume Requirements
We are requesting comment on various alternative approaches that we
could take with respect to volumes as well as certain other policy
parameters. Specifically, we request comment on whether we should
establish volume requirements for one or two years instead of three
years, whether the implied conventional renewable fuel volume
requirement should be 15.00 billion gallons rather than 15.25 billion
gallons in 2024 and 2025, or whether the implied conventional renewable
fuel volume requirement should be reduced by some other amount, such as
below the E10 blendwall, while keeping the total renewable fuel volume
requirement unchanged. Section VI.G provides additional discussion of
these alternatives.

B. Environmental Justice

Executive Order 12898 (59 FR 7629, February 16, 1994) establishes
federal executive policy on environmental justice. It directs federal
agencies, to the greatest extent practicable and permitted by law, to
make achieving environmental justice part of their mission by
identifying and addressing, as appropriate, disproportionately high and
adverse human health or environmental effects of their programs,
policies, and activities on communities with environmental justice
concerns in the United States.
This proposed rule is projected to reduce GHG emissions, which
would benefit communities with environmental justice concerns who are
disproportionately impacted by climate change due to a greater reliance
on climate sensitive resources such as localized food and water
supplies which may be adversely impacted by climate change, as well as
having less access to information resources that would enable them to
adjust to such impacts.\10\ \11\ The

[[Page 80586]]

manner in which the market responds to the provisions in this proposed
rule could also have non-GHG impacts. For instance, replacing petroleum
fuels with renewable fuels will also have impacts on water and air
exposure for communities living near biofuel and petroleum facilities
given the potential for biofuel facilities to have relatively high
emission rates in local communities. Replacing petroleum fuels with
renewable fuels is also projected to increase food and fuel prices, the
effects of which will be disproportionately borne by the lowest income
individuals. Our assessment of potential economic impacts on people of
color and low-income populations is provided in Section IV.E.3.
---------------------------------------------------------------------------

\10\ USGCRP, 2018: Impacts, Risks, and Adaptation in the United
States: Fourth National Climate Assessment, Volume II [Reidmiller,
D.R., C.W. Avery, D.R. Easterling, K.E. Kunkel, K.L.M. Lewis, T.K.
Maycock, and B.C. Stewart (eds.)]. U.S. Global Change Research
Program, Washington, DC, USA, 1515 pp. doi: 10.7930/NCA4.2018.
\11\ USGCRP, 2016: The Impacts of Climate Change on Human Health
in the United States: A Scientific Assessment. Crimmins, A., J.
Balbus, J.L. Gamble, C.B. Beard, J.E. Bell, D. Dodgen, R.J. Eisen,
N. Fann, M.D. Hawkins, S.C. Herring, L. Jantarasami, D.M. Mills, S.
Saha, M.C. Sarofim, J. Trtanj, and L. Ziska, Eds. U.S. Global Change
Research Program, Washington, DC, 312 pp. <a href="http://dx.doi.org/10.7930/J0R49NQX">http://dx.doi.org/10.7930/J0R49NQX</a>.
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C. Comparison of Costs to Impacts

CAA section 211(o)(2)(B)(ii) requires EPA to assess a number of
factors when determining volume targets for calendar years after those
shown in Table I-1. 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 proposed
rule. However, the statute does not specify how EPA must assess each
factor. For two of these statutory factors, costs and energy security
impacts, we provide monetized impacts for the purpose of comparing
costs and benefits. For the other statutory factors, we are either
unable to quantify impacts, or we provide quantitative estimated
impacts that cannot be easily monetized for comparison. Thus, we are
unable to quantitatively compare all of the evaluated impacts when
assessing the overall costs and impacts of this proposed rulemaking. We
request comment generally on how costs and benefits quantified in this
proposed rule are calculated and accounted for, methods to quantify and
monetize additional statutory factors, and appropriate means of
comparing the costs and benefits. Table ES-1 in the DRIA provides a
list of all of the impacts that we assessed, both quantitative and
qualitative. Our assessments of each factor, including the different
components of the estimated costs, energy security methodology, climate
impacts, and other environmental and economic impacts, are summarized
in Section IV of this document. Additional detail for each of the
assessed factors is provided in DRIA Chapters 4 through 10.
Monetized cost and energy security impacts are summarized in Table
I.C-1 below using two discount rates (3 percent and 7 percent)
following federal guidance on regulatory impact analyses.\12\
Summarized impacts are calculated in comparison to a No RFS baseline as
discussed in Section III.D and are summed across all three years of
standards.
---------------------------------------------------------------------------

\12\ Office of Management and Budget (OMB). Circular A-4.
September 17, 2003.

Table I.C-1--Cumulative Monetized Cost Impacts and Energy Security
Benefits of 2023-2025 Standards With Respect to the No RFS Baseline
[2021$, millions]
------------------------------------------------------------------------
Discount rate
-------------------------------
3% 7%
------------------------------------------------------------------------
Excluding Supplemental Standard:
Cost Impacts........................ 28,801 27,835
Energy Security Benefits............ 623 600
Including Supplemental Standard:
Cost Impacts........................ 29,458 28,492
Energy Security Benefits............ 634 611
------------------------------------------------------------------------

D. Policy Considerations

This proposed rule comes at a time when major policy developments
and global events are affecting the transportation energy and
environmental landscape in unprecedented ways. The recently passed
Inflation Reduction Act (IRA) makes historic investments in a range of
areas, including in clean vehicle and alternative fuel technologies,
that will help decarbonize the transportation sector and bolster a
variety of clean technologies. Provisions in the IRA will accelerate
many of the pollution-reducing shifts that are already occurring as
part of a broad energy transition in the transportation, power
generation, and industrial sectors. Major new incentives in legislation
for cleaner vehicles, carbon capture and sequestration, biofuels
infrastructure, clean hydrogen production and other areas have
effectively shifted the policy ground--and it is on this new ground
that EPA must develop forward-looking policies and implement existing
regulatory programs, including the RFS program.
Even as the IRA bolsters future investments in clean transportation
technologies, EPA recognizes that maintaining and strengthening energy
security in the near term remains a policy imperative. The war in
Ukraine has significantly destabilized multiple global commodity
markets, including petroleum markets. In addition, global reductions in
refining capacity, which accelerated during the pandemic, have further
tightened the market for transportation fuels like gasoline and diesel.
Programs like the RFS program help boost energy security by supporting
domestic production of fuels and diversifying the fuel supply, and it
has played an important role in incentivizing the production of low-
carbon alternatives. At the same time, EPA recognizes that the
transition to such alternatives will take time, and that during this
transition maintaining stable fuel supplies and refining assets will
continue to be important to achieving our nation's energy and economic
goals as well as providing consistent investments in a skilled and
growing workforce.
It is against this backdrop that EPA is proposing to establish
volume requirements under the RFS program, through the ``Set'' rule
process, for the next three years. The volumes that EPA is proposing
sustain a path of renewable fuel growth for the program and build on
the foundation set by the 2022

[[Page 80587]]

required volumes. Beyond providing continued support for fuels like
ethanol and biodiesel, the set proposal provides a strong market signal
for the continued growth of low carbon advanced biofuels, including
``drop-in'' renewable diesel, cellulosic biofuels, and through a newly
proposed program for electricity produced from qualifying renewable
feedstocks and used as transportation fuel. Renewable fuels are a key
policy tool identified by Congress for decarbonizing the transportation
sector, and this rulemaking will set the stage for further growth and
development of low-carbon biofuels in the coming years.
With this proposal, EPA is asking for public comment on multiple
elements of the rule, including our analysis, volume requirements, and
proposed regulatory amendments. Simultaneously, EPA, having heard from
a range of stakeholders who have raised concerns and questions
reflecting a number of policy considerations that potentially bear on
this proposal, is interested in the public's input about how this
proposal intersects with the larger energy transition and energy
security issues discussed above. EPA is interested, for example, in
understanding how the proposed required RFS volume requirements
interact with domestic refining capacity and associated energy security
considerations. We are also interested in public input regarding ways
in which EPA might enhance program administration to make the RFS
program as efficient as possible, to increase program transparency, to
address climate change, or otherwise improve program implementation.
More specifically, EPA is interested in public and stakeholder
input on the questions listed below, which will be considered and may
inform the contents of the final rule. We note that for some of these
topics, stakeholders may have previously provided information to EPA.
We therefore ask that information provided in response to this request
focus on new data, new information, or new policy suggestions.
<bullet> How can the proposed set rule further Congress' policy
goal of enhancing energy security, specifically with respect to the
transportation sector?
<bullet> How do the requirements of this proposed rule intersect
with continued viability of domestic oil refining assets? How does the
structure or positioning of refining assets in the marketplace, such as
refineries that operate on a merchant basis, relate to a given
obligated party's ability to participate, and associated costs with
participation, in the RFS program?
<bullet> Are there policy changes or additional programmatic
incentives that EPA should consider implementing under the RFS program
to strengthen or accelerate the transition to a decarbonized
transportation sector?
<bullet> If EPA were to incorporate some measure of the carbon
intensity of each biofuel into the RFS program (e.g., providing a
higher RIN value for fuels with a better carbon intensity score), what
approach would best advance the program's environmental objectives, and
at the same time be consistent with the statutory provisions of CAA
section 211(o)?
<bullet> How can EPA best build upon the policy investments that
the IRA established to further develop low carbon renewable fuels,
including through incentives established through the RFS program?
<bullet> What role can the RFS program play, beyond what exists
today, to further support the development of sustainable aviation fuel?
<bullet> Are there steps EPA should consider taking under the RFS
program to integrate carbon capture and storage (CCS) opportunities
related to the production of renewable fuels?
<bullet> Are there steps EPA should consider taking under the RFS
program to capture opportunities related to hydrogen derived from
renewable biomass?
<bullet> What actions should EPA consider to improve the
transparency of how the Agency administers the RFS program? Are there
steps EPA should consider taking to enhance RIN market liquidity,
transparency, and efficiency, or otherwise improve market
administration? For example, should EPA revisit some of the policy
design conclusions of the 2019 RIN market reform rule such as the RIN
holding thresholds that require parties to publicly disclose their
positions? \13\ Are there other policy designs not considered in that
rule that EPA should be considering in this rule?
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\13\ 84 FR 26980 (June 10, 2019).
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<bullet> As noted earlier, should the conventional renewable fuel
volume requirement be set below the E10 blendwall, while keeping the
total proposed renewable fuel volume requirement unchanged?
In addition, the inclusion of a new regulatory program for eRINs
significantly increases the uncertainty of our cellulosic biofuel
projections for 2024 and 2025, and that uncertainty may warrant special
consideration. Unlike other types of cellulosic biofuel, EPA has no
history projecting the generation of eRINs under the RFS program. The
number of eRINs generated could also be impacted by a number of
interrelated and complex factors, such as the size and future growth
rate of the EV fleet, the supply of qualifying biogas for electricity
generation, competition for the biogas and electricity from other
markets, and the rate at which electricity generators can register to
participate in the RFS program. Our consideration of these factors in
projecting eRIN volumes can be found in DRIA Chapter 6.1.4. We request
comment on how to account for the uncertainty in projecting the
quantity of eRINs in the RFS program, and specifically, whether we
should be considering lower (or different) cellulosic volume
requirements for 2024 and 2025 in this rule.

E. 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, along 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 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 only for actions that ``may affect'' listed species or
designated critical habitat. 50 CFR 402.14. Consultation is not
required where the action has no effect on such species or habitat. For
several prior RFS annual standard-setting rules, EPA did not consult
with the Services under section 7(a)(2).
Consistent with ESA section 7(a)(2) and relevant ESA implementing
regulations at 50 CFR part 402, for approximately two years, EPA has
been engaged in informal consultation including technical assistance
discussions with the Services regarding this rule.

II. Statutory Requirements and Conditions

A. Requirement To Set Volumes for Years After 2022

The CAA provides EPA with the authority to establish the applicable
renewable fuel volume targets for calendar years after those specified
in the Act in Section 211(o)(2).\14\ For total

[[Page 80588]]

renewable fuel, cellulosic biofuel, and total advanced biofuel, the CAA
provides volume targets through 2022, after which EPA must establish or
``set'' the volume targets via rulemaking. For biomass-based diesel
(BBD), the CAA only provides volume targets through 2012; EPA has been
setting the biomass-based diesel volume requirements in annual
rulemakings since 2013.
---------------------------------------------------------------------------

\14\ We refer to CAA section 211(o)(2)(B)(ii) as the ``set
authority.''
---------------------------------------------------------------------------

This section discusses the statutory authority and additional
factors we are considering due to the lateness of this rulemaking, as
well as the severability of the various portions of this proposed rule.

B. Factors That Must Be Analyzed

In setting the applicable annual renewable fuel volumes, EPA must
comply with the processes, criteria, and standards set forth in CAA
section 211(o)(2)(B)(ii). That provision provides that the
Administrator shall, in coordination with the Secretary of Energy and
the Secretary of Agriculture,\15\ determine the applicable volumes of
each biofuel category specified based on a review of 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:
---------------------------------------------------------------------------

\15\ In furtherance of this requirement, we have had periodic
discussions with DOE and USDA on this proposed action.
---------------------------------------------------------------------------

<bullet> The impact of the production and use of renewable fuels on
the environment; \16\
---------------------------------------------------------------------------

\16\ CAA section 211(o)(2)(B)(ii)(I).
---------------------------------------------------------------------------

<bullet> The impact of renewable fuels on the energy security of
the U.S.; \17\
---------------------------------------------------------------------------

\17\ CAA section 211(o)(2)(B)(ii)(II).
---------------------------------------------------------------------------

<bullet> The expected annual rate of future commercial production
of renewable fuels; \18\
---------------------------------------------------------------------------

\18\ CAA section 211(o)(2)(B)(ii)(III).
---------------------------------------------------------------------------

<bullet> The impact of renewable fuels on the infrastructure of the
U.S.; \19\
---------------------------------------------------------------------------

\19\ CAA section 211(o)(2)(B)(ii)(IV).
---------------------------------------------------------------------------

<bullet> The impact of the use of renewable fuels on the cost to
consumers of transportation fuel and on the cost to transport goods;
\20\ and
---------------------------------------------------------------------------

\20\ CAA section 211(o)(2)(B)(ii)(V).
---------------------------------------------------------------------------

<bullet> The impact of the use of renewable fuel on other factors,
including job creation, the price and supply of agricultural
commodities, rural economic development, and food prices.\21\
---------------------------------------------------------------------------

\21\ CAA section 211(o)(2)(B)(ii)(VI).
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While the statute requires that EPA base its determination on an
analysis of these factors, it does not establish any numeric criteria,
require a specific type of analysis (such as quantitative analysis), or
provide guidance on how EPA should weigh the various factors.
Additionally, we are not aware of anything in the legislative history
of EISA that is authoritative on these issues. Thus, as the Clean Air
Act ``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.'' \22\ These factors
were analyzed in the context of the 2020-2022 standard-setting rule
that modified volumes under CAA section 211(o)(7)(F),\23\ which
requires EPA to comply with the processes, criteria, and standards in
CAA section 211(o)(2)(B)(ii). Many commenters provided comments about
how EPA should weigh these factors. We considered those comments and
determined that a holistic balancing of the factors was
appropriate.\24\ We are taking the same approach in this proposal to
holistically balance competing factors. Further evaluation following
the proposed rule, and consideration of comments received, will inform
how we analyze and weigh these factors in establishing final volumes
and standards for 2023 and beyond.
---------------------------------------------------------------------------

\22\ See 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 (2nd 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).
\23\ See 87 FR 39600 (July 1, 2022).
\24\ RFS Annual Rules Response to Comments Document at 10.
---------------------------------------------------------------------------

In addition to those factors listed in the statute, we also have
authority to consider other factors, including both implied authority
to consider factors that inform our analysis of the statutory factors
and explicit authority to consider ``the impact of the use of renewable
fuels on other factors . . . .'' \25\ Accordingly, we have considered
several other factors, including:
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\25\ CAA section 211(o)(2)(B)(ii)(VI).
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<bullet> The interaction between volume requirements for years
2023-2025, including the nested nature of those volume requirements and
the availability of carryover RINs;
<bullet> The ability of the market to respond given the timing of
this rulemaking;
<bullet> Our obligation to respond to the ACE remand (Section V);
<bullet> The supply of qualifying renewable fuels to U.S. consumers
(Section III.A.5) \26\;
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\26\ This is based on our analysis of this same statutory factor
as well as of downstream constraints on biofuel use, including the
statutory factors relating to infrastructure and costs.
---------------------------------------------------------------------------

<bullet> Soil quality (Chapter 3.4 of the RIA) \27\;
---------------------------------------------------------------------------

\27\ Soil quality is closely tied to water quality and is also
relevant to the impact of renewable fuels on the environment more
generally.
---------------------------------------------------------------------------

<bullet> Environmental justice (Section IV.E and Chapter 8 of the
RIA) \28\;
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\28\ Addressing environmental justice involves assessing the
potential for the use of renewable fuels to have a disproportionate
and adverse health or environmental effect on minority populations,
low-income populations, tribes, and/or indigenous peoples.
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<bullet> A comparison of costs and benefits (Section IV.D).\29\;
---------------------------------------------------------------------------

\29\ The comparison of costs and benefits compares our
quantitative analysis of various statutory factors, including costs,
energy security, and climate impacts.
---------------------------------------------------------------------------

C. Statutory Conditions on Volume Requirements

As indicated above, the CAA does not provide instruction on how EPA
should consider the factors or the weight each factor should be given
when setting the applicable volumes, and thus leaves this to EPA's
discretion. However, the Act does contain three conditions that affect
our determination of the applicable volume requirements:
<bullet> 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;
<bullet> Direction in setting the cellulosic biofuel applicable
volume regarding potential future waivers; and
<bullet> A floor on the applicable volume of BBD.
Other than these limits, Congress has not provided instruction on
how EPA must evaluate the statutorily enumerated factors, and courts
have interpreted such congressional silence as conveying substantial
discretion to the Agency.\30\
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\30\ Monroe Energy, LLC v. EPA, 750 F.3d 909, 915 (D.C. Cir.
2014) (quoting Catawba Cty., N.C. v. EPA, 571 F.3d 20, 37 (D.C. Cir.
2009) (``[W]hen a statute is silent with respect to all potentially
relevant factors, it is eminently reasonable to conclude that the
silence is meant to convey nothing more than a refusal to tie the
agency's hands.'').
---------------------------------------------------------------------------

1. Advanced Biofuel as a Percentage of Total Renewable Fuel
While the statute 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

[[Page 80589]]

requirements, and this constraint has implications for the implied
volume requirement for conventional renewable fuel. The CAA 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.'' \31\ Meaning that EPA must, at a minimum,
maintain the ratio of advanced biofuel to total renewable fuel that was
established for 2022 for the years in which EPA sets the applicable
volume requirements. In effect, this limits the applicable volume of
conventional renewable fuel within the total renewable fuel volume for
years after 2022.
---------------------------------------------------------------------------

\31\ CAA section 211(o)(2)(B)(iii).
---------------------------------------------------------------------------

The applicable advanced biofuel volume requirement is 5.63 billion
gallons for 2022.\32\ The total renewable fuel volume requirement for
2022 is 20.63 billion gallons, resulting in an implied conventional
volume requirement of 15 billion gallons. For 2022, then, advanced
biofuel would represent 27.3 percent of total renewable fuel. The
volume requirements we are proposing in this action for 2023-2025,
shown in Table I.A.1-1, all exceed this 27.3 percent minimum, and thus
the applicable volume requirements that we are proposing are consistent
with this statutory criterion.
---------------------------------------------------------------------------

\32\ 87 FR 39600 (July 1, 2022).
---------------------------------------------------------------------------

2. Cellulosic Biofuel
The statute 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.\33\ We
interpret this requirement to mean that we must establish the
cellulosic volume requirement at a level that is achievable and not
expected to require us in the future to lower the applicable cellulosic
volume requirement using the cellulosic waiver authority under CAA
section 211(o)(7)(D).\34\ That is, we are setting the volume
requirements such that the mandatory waiver of the cellulosic volume is
not likely to be triggered in those future years. Operating within this
limitation, we are proposing to set the cellulosic volumes for 2023,
2024, and 2025 at the projected volume available in each year,
respectively, consistent with our past actions in determining the
cellulosic biofuel volume.\35\
---------------------------------------------------------------------------

\33\ CAA section 211(o)(2)(B)(iv).
\34\ The cellulosic biofuel waiver applies when the projected
volume of cellulosic biofuel production is less than the minimum
applicable volume. CAA section 211(o)(7)(D).
\35\ See, e.g., 2020-2022 Rule, 87 FR 39600 (July 1, 2022).
---------------------------------------------------------------------------

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.'' Thus, in
order to avoid triggering the mandatory cellulosic waiver, EPA is
proposing to set cellulosic volumes at the levels we believe to be
achievable. Our discussion of the projected supply of cellulosic
biofuel is addressed in Section III.A.1.
3. Biomass-Based Diesel
EPA has established the BBD requirement under CAA section
211(o)(2)(B)(ii) since 2013 because the statute only provided BBD
volume targets through 2012. The statute also requires that the BBD
volume requirement be set at or greater than the 1.0 billion gallon
volume requirement for 2012 in the statute, but does not provide any
other numerical criteria that EPA is to consider.\36\ We are proposing
an applicable volume requirement for BBD for 2023, 2024, and 2025 under
these authorities.
---------------------------------------------------------------------------

\36\ CAA Section 211(o)(2)(B)(iv).
---------------------------------------------------------------------------

D. Authority To Establish Percentage Standards for Multiple Future
Years

EPA is proposing to establish percentage standards for multiple
future years in a single action. For years after 2022, the CAA does not
expressly direct EPA to continue to implement volume requirements
through percentage standards established through annual rulemakings.
Furthermore, in establishing volumes for years after 2022, EPA is
directed to review ``the implementation of the program'' in years
during which Congress provided statutory volumes.\37\ Thus, Congress
provided EPA discretion as to how to implement the volume requirements
of RFS program in years 2023 and beyond.
---------------------------------------------------------------------------

\37\ CAA Section 211(o)(2)(B)(ii).
---------------------------------------------------------------------------

CAA section 211(o)(3)(B)(i) provides that by ``November 30 of each
of calendar years 2005 through 2021, based on the estimate provided [by
EIA], the Administrator . . . shall determine and publish in the
Federal Register, with respect to the following calendar year, the
renewable fuel obligation that ensures that the requirements of
paragraph (2) are met.'' \38\ The next subparagraph (ii) provides
further requirements for the obligation described in paragraph (i). On
its face, this language does not apply to rulemakings establishing
obligations for years subsequent to 2022. Therefore, EPA is not bound
by this language for those years.
---------------------------------------------------------------------------

\38\ CAA Section 211(o)(3)(b)(i).
---------------------------------------------------------------------------

EPA could choose to continue to utilize the same procedures
articulated in CAA section 211(o)(3)(B)(i) for establishing percentage
standards for years beyond 2022. However, EPA could also choose to set
percentage standards at one time for several future years (e.g., for
2023-2025 through this rulemaking). Doing so could increase certainty
for obligated parties and renewable fuel producers, as both the
applicable volume requirements and the associated percentage standards
would be established several years in advance of the year in which they
would apply. This would also provide certainty for obligated parties in
determining compliance deadlines. The regulations at 40 CFR
80.1451(f)(1)(i)(A) provide that compliance will not be required for a
given compliance year until after the percentage standards for the
following year are established. Thus, establishing the percentage
standards through this rulemaking process would provide certainty as to
the date of the compliance deadlines for the years prior to those for
which we are proposing to establish percentage standards through this
action (i.e., 2022-2024).
Setting percentage standards several years in advance, however,
could result in less accurate gasoline and diesel projections being
used in calculating the percentage standards. When gasoline and diesel
demand projections are made only a few months prior to the subsequent
year, those projections tend to be more accurate. Projections further
into the future are inherently more uncertain.
In this action, we are proposing applicable volume requirements and
the associated percentage standards for 2023-2025, as described further
in Sections VI and VII. We believe that establishing both the volume
requirements and percentage standards for the next three years strikes
an appropriate balance between improving the program by providing
increased certainty over a multiple number of years and recognizing the
inherent uncertainty in longer-term projections. We seek comment on
this approach.

E. Considerations for Late Rulemaking

In this rulemaking, we are proposing applicable volume targets for
the 2023 and 2024 compliance years that miss the

[[Page 80590]]

statutory deadlines.\39\ EPA has in the past also missed statutory
deadlines for promulgating RFS standards, including the BBD Standards
in 2014-2016, which were established under CAA section
211(o)(2)(B)(ii). The U.S. Court of Appeals for the D.C. Circuit found
that EPA retains authority to promulgate volumes and annual standards
beyond the statutory deadlines, even those that apply retroactively, so
long as EPA exercises this authority reasonably.\40\ In doing so, EPA
must balance the burden on obligated parties of a delayed rulemaking
with the broader goal of the RFS program to reduce GHG emissions and
enhance energy security through increases in renewable fuel use.\41\ In
upholding EPA's late and retroactive standards in ACE, the court
considered several specific factors, including the availability of RINs
for compliance, the amount of lead time and adequate notice for
obligated parties, and the availability of compliance flexibilities. In
addressing rulemakings that were late (i.e., those issued after the
statutory deadline), but not retroactive, the court emphasized the
amount of lead time and adequate notice for obligated parties.\42\ Most
relevant here is EPA's action in 2015 that established the BBD volume
requirements for 2014 and 2015.\43\ There, EPA missed the statutory
criterion that EPA establish an applicable volume target for BBD no
later than 14 months before the first year to which that volume
requirement will apply.\44\ However, 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
and 2015.\45\
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\39\ 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.
\40\ 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).
\41\ NPRA v. EPA, 630 F.3d 145, 164-165.
\42\ ACE, 864 F.3d at 721-22.
\43\ 80 FR 77420, 77427-77428, 77430-77431 (December 14, 2015).
\44\ CAA section 211(o)(2)(B)(ii).
\45\ ACE, 864 F.3d at 721-23.
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In this rulemaking, we are proposing to exercise our authority to
set the applicable renewable fuel volume requirements for 2023 and 2024
after the statutory deadline to promulgate volumes no later than 14
months before the first year to which those volume requirements
apply.\46\ We also expect the final rule to be partly retroactive, as
the 2023 standards are unlikely to be finalized prior to the beginning
of the 2023 calendar year. Nevertheless, as discussed in Section VI.E,
we believe that the 2023 standards being proposed in this action could
be met. Additionally, we plan to finalize the 2024 standards prior to
the beginning of the 2024 calendar year and do not expect those
standards to apply retroactively.
---------------------------------------------------------------------------

\46\ CAA section 211(o)(2)(B)(ii).
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In addition, in completing its response to the ACE remand of the
2016 annual rule, we are proposing a supplemental standard for
2023.\47\ We are proposing this supplemental standard after the
statutory deadline for the 2016 standards (November 30, 2015). However,
the proposed supplemental standard would prospectively apply to
gasoline and diesel produced or imported in 2023. We further discuss
our response to the ACE remand in Section V.
---------------------------------------------------------------------------

\47\ We also established a supplemental standard for 2022 in a
prior action. 87 FR 39600 (July 1, 2022).
---------------------------------------------------------------------------

F. Impact on Other Waiver Authorities

While we are proposing to establish 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.\48\ For example, the
general waiver authority under CAA section 211(o)(7)(A) provides that
EPA may waive the volume targets in ``paragraph (2).'' CAA section
211(o)(2) provides both the statutory applicable volume tables and
EPA's set authority (the authority to set applicable volumes for years
not specified in the table). Therefore, in the future, EPA could modify
the volume targets for 2023 and beyond through the use of our waiver
authorities as we have in past annual standard-setting rulemakings.
---------------------------------------------------------------------------

\48\ 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).
---------------------------------------------------------------------------

However, 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 the
Administrator will not need to waive those volume requirements under
the cellulosic waiver authority. Because we are, in this action,
proposing to establish the applicable volume targets for 2023-2025
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.
Establishing the volume requirements for 2023-2025 using our set
authority apart from the cellulosic waiver authority would have
important implications for the availability of cellulosic waiver
credits (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,
for the first time, proposing to establish a cellulosic biofuel
standard 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, cellulosic
waiver credits would not be available as a compliance mechanism for
obligated parties in these years absent a future action to exercise the
cellulosic waiver authority. We recognized this likelihood in the
recent rule establishing volume requirements for 2020-2022.\49\ There,
we cited to the fact that CWCs were unlikely to be available in 2023 as
part of our rationale for not requiring the use of cellulosic carryover
RINs in setting the cellulosic volume requirements for 2020-2022.
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
be produced and imported in the U.S. each year. Nevertheless, we
recognize that the absence of CWCs is potentially a significant change
to the operation of the RFS program, and we request comment on EPA's
authority to offer CWCs in years in which we do not establish volume
requirements using our cellulosic waiver authority.
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\49\ 87 FR 39600 (July 1, 2022).
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G. Severability

We intend for the volume requirements and percentage standards for
a single year (i.e., 2023, 2024, and 2025) to be severable from the
volume

[[Page 80591]]

requirements and percentage standards for other years. Each year's
volume requirements and percentage standards are supported by analyses
for that year. Similarly, we intend for the 2023 supplemental standard
and percentage standard to be severable from the annual volume
requirements and percentage standards. We also intend for the other
regulatory amendments to be severable from the volume requirements and
percentage standard. The regulatory amendments are intended to improve
the RFS program in general, and, with the exception noted below, are
not part of EPA's analysis for the volume requirements and percentage
standards for any specific year in 2023 or beyond. Each of the
regulatory amendments in Section IX is also severable from the other
regulatory amendments because they all function independently of one
another. However, we do not intend for the eRIN regulatory provisions
(Section VIII) to be severable from the volumes for 2024 and 2025, such
that if a reviewing court were to set aside the eRIN program, the
volumes for 2024 and 2025 would also be set aside, as those volumes
will take into account considerable volumes of cellulosic biofuel
expected to be generated utilizing those regulatory provisions. While
the projected volumes for years 2024 and 2025 are dependent in part on
the eRIN program being in place, the eRIN program, which is designed to
last for years beyond 2024 and 2025, is not dependent on the volumes
for 2024 and 2025.
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 2023 supplemental standard, the eRIN program, the
individual regulatory amendments) is vacated by a reviewing court, we
intend the remainder of this action to remain effective as described in
the preceding paragraph. To further illustrate, if a reviewing court
were to vacate the volume requirements and percentage standards and
supplemental standard, we intend the eRIN provisions and the other
regulatory amendments to remain effective. Or, for example, if a
reviewing court vacates the BBD conversion factor provisions, we intend
the volume requirements and percentage standards as well as the
supplemental standard and other regulatory amendments to remain
effective.

III. Candidate Volumes and Baselines

The statute requires that we analyze a specified set of factors in
making our determination of the appropriate volume requirements to
establish for years after 2022. These factors are listed in Section
II.B. Many of those factors, particularly those related to economic and
environmental impacts, are difficult to analyze in the abstract, and so
we have opted to analyze those factors based on specific ``candidate
volumes'' for each category of renewable fuel. To accomplish this, we
derived a set of renewable fuel volumes that we then used to conduct
the required multi-factor analyses. We then determined, based on the
results of those analyses, the volume requirements that would be
appropriate to propose. Our approach can be summarized as a three-step
process:
1. Development of candidate volumes;
2. Multifactor analysis based on candidate volumes; and
3. Determination of proposed volumes based on a consideration of
all factors analyzed.
For the first step in this process, we analyzed a subset of the
statutory factors that are most closely related to supply of and demand
for renewable fuel. These supply-and-demand-related factors
(hereinafter ``supply-related factors'') \50\ include the production
and use of renewable fuels (as a necessary prerequisite to analyzing
their impacts under CAA section 211(o)(2)(B)(ii)(I)), the expected
annual rate of future commercial production of renewable fuels (CAA
section 211(o)(2)(B)(ii)(III)), and the sufficiency of infrastructure
to deliver and use renewable fuel (CAA section 211(o)(2)(B)(ii)(IV)).
Consideration of these supply-related statutory factors necessarily
included a consideration of imports and exports of renewable fuel,
consumer demand for renewable fuel, and the availability of qualifying
feedstocks. Since the statute also requires us to review the
implementation of the program in prior years, an analysis of renewable
fuel supply includes not just projections for the future but also an
assessment of the historical supply of renewable fuel.
---------------------------------------------------------------------------

\50\ We use this shorthand (``supply-related factors'') only for
ease of explanation in the context of identifying candidate volumes
for analysis under CAA section 211(o)(2)(B)(ii). We recognize that
this shorthand (``supply-related factors'') utilizes the term
``supply'' in a manner that is incongruent with the D.C. Circuit's
interpretation of the scope of the term ``supply'' in the general
waiver authority provision in CAA section 211(o)(7)(A). ACE v. EPA
(holding that the term ``inadequate domestic supply'' under the
general waiver authority excludes ``demand-side factors'').
References to ``supply-related factors'' in the context of our
discussion of the candidate volumes for analysis under CAA section
211(o)(2)(B)(ii) have no bearing on our interpretation of the term
``inadequate domestic supply'' under the general waiver authority
under CAA section 211(o)(7)(A).
---------------------------------------------------------------------------

This section describes the derivation of ``candidate volumes''
based on a consideration of supply-related factors as the first step in
our consideration of all factors that we are required to analyze under
the statute. The candidate volumes represent those volumes that might
be reasonable to require based on the supply-related factors, but which
have not yet been evaluated in terms of the other economic and
environmental factors. Basing the candidate volumes on supply-related
considerations is a reasonable first step because doing so narrows the
scope for the multifactor analysis in a commonsense way. Without this
step, it would be difficult to meaningfully analyze the remaining
statutory factors. Our determination of the volume requirements to
propose was based not only on our consideration of supply-related
factors, but also on the results of our analysis of the other economic
and environmental factors discussed in Section IV. Section VI provides
our rationale for the proposed volume requirements in light of all the
analyses that we conducted.
This section begins with a discussion of the years that we
determined would be reasonable to analyze. Section III.B describes our
analysis of the supply-related factors for those years, and Section
III.C summarizes the resulting candidate volumes. Finally, Sections
III.D and III.E describe, respectively, the No RFS baseline that we
believe would be the most appropriate point of reference for the
analysis of the other statutory factors, and the volume changes
calculated in comparison to that baseline.

A. Number of Years Analyzed

Before assessing future supply of renewable fuel, we first
considered the number of years to which this assessment would apply,
since the nature of this assessment can be different for the nearer
term than for the longer term. We focused our assessment of renewable
fuel supply on the three years immediately following the end of the
statutory volume targets (i.e., 2023-2025). To some degree,
establishing volume targets and the associated percentage standards for
a greater number of years would increase market certainty for all
parties, and would suggest that EPA should do so for as many years as
possible. However, the uncertainty inherent in making future
projections increases for longer timeframes. Moreover, our experience
with the RFS program since its inception is that unforeseen market
circumstances involving not only renewable fuel supply but also
relevant economics mean that fuels markets are continually evolving and
changing in ways that cannot be predicted. These

[[Page 80592]]

facts affect all supply-related elements of biofuel: projections of
production capacity, availability of imports, rates of consumption,
availability of qualifying feedstocks, and the gasoline and diesel
demand projections that provide the basis for the calculation of
percentage standards. Greater uncertainty in future projections means a
higher likelihood that those future projections could turn out to be
inaccurate, leading to the potential need to revise them after they are
established through, for instance, one of the statutory waiver
provisions. Such actions to revise applicable standards after they have
been set could be expected to increase market uncertainty. Based on our
desire to strengthen market certainty by establishing applicable
standards for as many years as is practical, tempered by the knowledge
that longer time periods increase uncertainty in projected volumes and
increase the likelihood that applicable standards turn out to be not
reasonably achievable and might need to be waived at a later date, we
believe that three years represents an appropriate balance at this
time.
Nevertheless, in our assessment of renewable fuel supply, we have
also made projections for one additional year, 2026. As discussed more
fully in Section VI.F, we believe that 2026 represents a transitional
year in the market's response to the availability of eRINs. Prior to
2026, we expect eRIN generators to use primarily existing generating
capacity. By 2026, however, we expect additional electricity generating
capacity to come online to take advantage of the new eRIN market. Both
this projection and the projection of the amount of electricity that
will be used as transportation fuel have uncertainty associated with
them, especially at the inception of the eRIN program. Thus, projecting
the availability of eRINs for 2026 carries with it greater uncertainty
than doing so for 2025 does. This is one important reason that we are
not proposing volume requirements for 2026. However, based on the
interest on the part of some stakeholders to see volume requirements
established for as many years as possible, we believe it is in the
public interest for us to estimate potential eRIN generation in 2026
despite the additional uncertainty involved. This estimate is discussed
in Section III.C.5 below.

B. Production and Import of Renewable Fuel

1. Cellulosic Biofuel
In the past several years, production of cellulosic biofuel has
continued to increase. Cellulosic biofuel production reached record
levels in 2021, driven by compressed natural gas (CNG) and liquified
natural gas (LNG) derived from biogas. The projected volumes of
cellulosic biofuel production in 2022 are even higher than the volume
produced in 2021. While the production of liquid cellulosic biofuel has
remained limited in recent years (see Figure III.B.1-1), the inclusion
of eRINs into the program affords another opportunity for dramatic
growth of cellulosic biofuel (see DRIA Chapter 6 for a projection of
RIN generation from eRINs in 2023-2025). Despite the significant
increase in cellulosic biofuel production since 2014 and the dramatic
growth that would result from this proposal, several cellulosic biofuel
producers have stated that uncertainty in the demand for cellulosic
biofuels and volatility in the cellulosic RIN price has hindered the
production of cellulosic biofuel. We recognize the importance of
consistent and dependable market signals to the cellulosic biofuel
industry. Further discussion of how the RFS program might be able to
provide greater certainty to the cellulosic biofuel industry can be
found in Section VI.A. This section describes our assessment of the
rate of production of qualifying cellulosic biofuel from 2023 to 2025,
and some of the uncertainties associated with these volumes. Further
detail on our projections of the rate of cellulosic biofuel production
and import can be found in DRIA Chapter 5.1.
[GRAPHIC] [TIFF OMITTED] TP30DE22.000

a. CNG/LNG Derived From Biogas
To project the production of CNG/LNG derived from biogas, we used
the same industry wide projection approach that we have used to project
the production of this fuel in the RFS standard-setting annual rules
since 2018 and that has been reasonably successful in projecting
volumes. This methodology projects the production of CNG/LNG derived
from biogas based on a year-over-year growth rate applied to the
current rate of production of cellulosic biogas. We calculated the
year-over-year growth rate in CNG/LNG

[[Page 80593]]

derived from biogas by comparing RIN generation from January 2021 to
December 2021 (the most recent 12 months for which data are available)
to RIN generation in the 12 months that immediately precede this time
period (January 2020 to December 2020). The growth rate calculated
using this data is 13.1 percent. These RIN generation volumes are shown
in Table III.B.1.a-1.

Table III.B.1.a-1--Generation of Cellulosic Biofuel RINs for CNG/LNG Derived From Biogas
[Ethanol-equivalent gallons]
----------------------------------------------------------------------------------------------------------------
RIN generation (June
RIN generation (June 2020-May 2021) (million) 2021-May 2022) Year-over-year increase
(million) (%)
----------------------------------------------------------------------------------------------------------------
526.1......................................................... 595.1 13.1
----------------------------------------------------------------------------------------------------------------

In previous annual rules we applied the year-over-year growth rate
to actual supply in the most recent calendar year for which a full year
of data is available. For instance, when determining the original 2020
standards for cellulosic biofuel, we used actual supply of cellulosic
RINs generated and made available for compliance in 2018. For this
proposal, the most recent full calendar year for which we have data on
RIN supply is 2021. Applying the 13.1 percent annual growth rate twice
to the 2021 RIN supply provides a two-year projection, i.e., for 2023.
Applying this same growth rate can then be used to project volumes of
CNG/LNG derived from biogas in subsequent years. This methodology
results in the projections of CNG/LNG derived from biogas in 2023 to
2025 shown in Table III.B.1.a-2.

Table III.B.1.a-2--Projected Generation of Cellulosic Biofuel RINs for CNG/LNG Derived From Biogas
[Ethanol-equivalent gallons]
----------------------------------------------------------------------------------------------------------------
Growth rate Volume (RINs)
Year Date type (%) (million)
----------------------------------------------------------------------------------------------------------------
2021.......................................... Actual.......................... N/A 561.8
2023.......................................... Projection...................... 13.1 719.3
2024.......................................... Projection...................... 13.1 813.9
2025.......................................... Projection...................... 13.1 920.9
----------------------------------------------------------------------------------------------------------------

While we have successfully used this methodology in previous years
to project the production of CNG/LNG derived from biogas with
reasonable accuracy there are several factors that may impact the
accuracy of this methodology out to 2025. In previous annual rules this
methodology was used to project the production of CNG/LNG derived from
biogas out 1-2 years in the future. As the methodology relies on
historical data to project future production, the uncertainty
associated with the projections is expected to increase the further out
into the future the projections are extended. In particular, we are
aware of several market factors that may impact the rate of growth of
CNG/LNG derived from biogas in future years. One important factor is
the quantity of CNG/LNG able to be used for transportation fuel. Under
the RFS program RINs may only be generated for CNG/LNG that is used as
transportation fuel, and the quantity of CNG/LNG used as transportation
fuel is relatively limited in the U.S. We currently project that use of
CNG/LNG as transportation fuel will be approximately 1.4-1.75 billion
ethanol-equivalent gallons in 2023-2025.\51\ While these projections of
CNG/LNG use as transportation fuel might appear unlikely to limit RIN
generation for the candidate volumes through 2025, it is highly
unlikely that registered parties will be able to document and verify
the use of all CNG/LNG use in the transportation sector. Since this
documentation is a requirement under the regulations, generation of
RINs for CNG/LNG derived from biogas will likely be limited to a
quantity somewhat less than the total amount of CNG/LNG used in the
transportation sector.
---------------------------------------------------------------------------

\51\ See Chapter 6.1.3 for a further discussion of our estimate
of CNG/LNG used as transportation fuel in 2023-2025.
---------------------------------------------------------------------------

There are also potential limitations related to the available
supply of CNG/LNG derived from biogas. Currently, a significant volume
of biogas is produced at landfills and wastewater treatment plants
across the U.S.\52\ Some of this biogas is currently being flared or
used to produce electricity onsite. There are also significant
opportunities for increasing the production of biogas from manure and
other agricultural residues. However, biogas must be used as
transportation fuel to be eligible to generate RINs.\53\ Raw biogas
from landfills, wastewater treatment facilities, or agricultural
digesters must be treated before it can be used as transportation fuel,
either at on site fueling stations or transported to fueling stations
via the natural gas pipeline network. Collecting and treating the raw
biogas to enable it to be used as CNG/LNG requires a significant
capital investment. While the quantity of biogas that could be used as
transportation fuel exceeds the quantity of CNG/LNG actually used as
transportation fuel, much of this biogas is not currently being treated
to the level necessary to enable its use as CNG/LNG and thus to
generate RINs.\54\
---------------------------------------------------------------------------

\52\ EPA Landfill Methane Outreach Program Landfill and Project
Database; Accessed March 2022.
\53\ See definition of ``renewable fuel'' in 40 CFR part 80
Section 1401.
\54\ According to the American Biogas Council there are
currently over 2,200 sites producing biogas in the U.S. (see Biogas
Industry Market Snapshot--American Biogas Council, available in the
docket). Approximately 860 of these sites use the biogas they
produce, and of this total 138 facilities generated RINs for CNG/LNG
derived from biogas used as transportation fuel in 2021.
---------------------------------------------------------------------------

Another factor that may limit the future rate of growth in the
installation of equipment necessary to upgrade raw

[[Page 80594]]

biogas to transportation fuel quality is the availability of financial
incentives provided by state Low Carbon Fuel Standard (LCFS) programs.
Since its inception in 2011 California's LCFS program has provided
credits for CNG/LNG derived from biogas that is used as transportation
fuel in California. Since 2014 when CNG/LNG derived from biogas was
determined to qualify as cellulosic biofuel in the RFS program, the
quantity of this fuel used with the incentives of both programs (RFS
and California's LCFS) has increased dramatically. It is likely that
this rapid expansion was driven by the ability for this fuel to
generate lucrative credits under both programs. As of 2021, however,
the LCFS data indicates that the quantity of fossil CNG/LNG generating
credits under the LCFS program had decreased to approximately 4 million
diesel gallon equivalents.\55\ This significant reduction suggests that
the ability for new sources of CNG/LNG derived from biogas to displace
CNG/LNG derived from fossil-based natural gas in California and
generate LCFS credits may be limited, which may in turn have an impact
on the economics and rate of developing new projects to produce this
fuel going forward. Currently Oregon is the only other state that has
adopted a clean fuels program, and the opportunity for CNG/LNG derived
from biogas to realize financial incentives in this program is limited
by the size of the Oregon CNG/LNG fleet. If other states adopt programs
similar to California's LCFS or Oregon's Clean Fuels program, these
other state programs could provide additional incentives for the
increased production and use of CNG/LNG derived from biogas.\56\
---------------------------------------------------------------------------

\55\ Data from the LCFS Data Dashboard (<a href="https://www.arb.ca.gov/fuels/lcfs/dashboard/dashboard.htm">https://www.arb.ca.gov/fuels/lcfs/dashboard/dashboard.htm</a>). For context, in 2021
approximately 174 million diesel gallon equivalents of bio-CNG/LNG
generated credits in the LCFS program.
\56\ For instance, Washington is in the process of developing
its own Clean Fuels Program and is targeting January of 2023 for it
to begin. See ``Clean Fuel Standard--Washington State Department of
Ecology,'' available in the docket.
---------------------------------------------------------------------------

Another significant limitation on the growth of CNG/LNG derived
from biogas is the cost associated with establishing a pipeline
interconnect. Not all CNG/LNG vehicles will be situated such that they
can refuel at the location where the biogas is produced and upgraded.
Therefore, getting the upgraded biogas to CNG/LNG vehicles requires
that it be put into common carrier pipelines. If there are no pipelines
near the source of the biogas, then it can quickly become cost
prohibitive and/or require considerable time to put in place a stub
pipeline to connect to the common carrier pipeline.
An important new variable in this limitation on biogas-based CNG/
LNG production is the eRIN provisions being proposed in this action.
With the opportunity to generate eRINs from biogas beginning January 1,
2024, instead of requiring a natural gas pipeline interconnect, a
facility would only need an electrical connection--something far less
expensive and more readily available. While these proposed regulations
are expected to quickly incentivize the expansion of the use of biogas
for electricity, their expansion may outcompete further development of
projects to produce CNG/LNG derived from biogas; the economics may make
it more cost effective to convert biogas to electricity to generate
eRINs than to upgrade the biogas for use in CNG/LNG vehicles. For
further discussion of the relative costs of using of biogas as CNG/LNG
versus using that biogas to produce electricity, see DRIA Chapter 9.
With these potential limitations in mind, it may be appropriate to
view the projected production volumes of CNG/LNG derived from biogas in
this section based on the historical methodology using historical
trends as the highest volumes that could be achieved through 2025.
b. Renewable Electricity
Because we are proposing a new, comprehensive regulatory program
for eRINs, it was necessary to derive a projection methodology for the
quantity of renewable electricity that can be made available. This
methodology is described in DRIA Chapter 6.1.4. In overview, the
methodology relies on an evaluation of just two pieces of information:
projected electricity demand from the fleet of electric vehicles (EVs)
in 2024 and 2025 and the projected production of renewable electricity
from combustion of qualifying biogas in those same years. We assessed
potential electricity demand using EV sales projections from the
Revised 2023 and Later Model Year Light-Duty Vehicle Greenhouse Gas
Emissions Standards,\57\ along with information on the size of the
existing EV fleet. We assessed potential renewable electricity
production using data from a number of sources and adjusted that
production level to account for line losses. The lesser of renewable
electricity production and demand then determined the maximum quantity
of eRINs that could be generated in each year of the program. We are
proposing to use these resulting maximum values in setting the
cellulosic biofuel standards for 2024 and 2025. For 2024 and 2025 the
electricity demanded by the EV fleet would be the limiting factor,
however, this is likely to flip in future years. These RIN generation
volumes are shown in Table III.B.1.b-1. We seek comment on the
appropriateness of the methodology used as described more fully below
and in DRIA Chapter 6.1.4, as well as on the resulting eRIN volume
projections.
---------------------------------------------------------------------------

\57\ 86 FR 74434 (December 30, 2021).

Table III.B.1.b-1--Projected Generation of Cellulosic Biofuel RINs for
Electricity Derived From Biogas
[Ethanol-equivalent gallons]
------------------------------------------------------------------------
Volume (million
Year RINs)
------------------------------------------------------------------------
2023.................................................. n/a
2024.................................................. 600
2025.................................................. 1,200
------------------------------------------------------------------------

We are aware that there is inherent uncertainty for both supply and
demand when it comes to projecting eRIN volumes. Regarding demand,
qualifying renewable electricity will be a direct function of the
number of EVs sold and registered over the timeframe of this action.
The size of the existing fleet of EVs is known, but due to the rapid
rate of growth of EV sales, we anticipate that the current size of the
EV fleet will comprise a relatively small proportion of the total
quantity of EVs eligible to generate RINs by 2025. Consequently, the
cellulosic biofuel volumes that we are proposing in this action are
highly dependent upon the EV sales projections we are using.
Regarding the supply of renewable electricity generated from
qualifying biogas (i.e., biogas that is produced from renewable biomass
consistent with an EPA-approved pathway), there is less uncertainty
because data is collected and reported by EIA on this activity.
However, two predominant sources of uncertainty remain despite EIA data
collection. First, the EIA data does not delineate between which
sources of biogas may or may not qualify for the existing EPA-approved
pathways. Second, although we anticipate there being ample financial
benefit from the eRIN program to justify participation, the rate at
which small and independent generators may be able to begin
participation in the program is unknown. As described in DRIA Chapter
6.1.4.2, our assessment is that a majority of the generating capacity
will be able to participate at the onset of the

[[Page 80595]]

program and that the remaining capacity will register within a few
years.
The addition of cellulosic volumes for electricity from renewable
biomass to the RFS program will comprise a large, and growing, fraction
of the cellulosic standard over the timeframe of this action. We
anticipate that as the eRIN program matures the associated uncertainty
in projecting future volumes will decrease. As mentioned in the prior
section on biogas to CNG/LNG, we anticipate that the addition of
regulations governing the generation of RINs for renewable electricity
may influence the decision making of biogas project developers.
Nevertheless, the cellulosic volumes we are proposing for eRINs are not
dependent upon any potential shift in developer preference for
electricity projects. We will continue to monitor the market closely
and intend to use updated data and information to project the potential
production of eRINs through 2025 in the final rule.
c. Ethanol From Corn Kernel Fiber
While there are several different technologies currently being
developed to produce liquid fuels from cellulosic biomass, these
technologies are by and large highly unlikely to produce significant
quantities of cellulosic biofuel by 2025. One possible exception is the
production of ethanol from corn kernel fiber, for which several
different companies have developed processes. Many of these processes
involve co-processing of both the starch and cellulosic components of
the corn kernel. To be eligible to generate cellulosic RINs, facilities
that are co-processing starch and cellulosic components of the corn
kernel must be able to determine the amount of ethanol that is produced
from the cellulosic portion of the corn kernel. This requires the
ability to accurately and reliably calculate the amount of ethanol
produced from the cellulosic portion as opposed to the starch portion
of the corn kernel; EPA has to date had significant concerns with
facilities' abilities to accurately perform this calculation. In
September 2022 EPA published a document providing updated guidance on
analytical methods that could be used to quantify the amount of ethanol
produced when co-processing corn kernel fiber and corn starch.\58\ This
guidance highlighted several outstanding critical technical issues that
need to be addressed. At this time there is still considerable
uncertainty about whether resolution of existing questions will allow
for significant additional volume of cellulosic biofuel to be available
through 2025 as well as the volume of cellulosic ethanol that could be
produced from corn kernel fiber. We therefore have not included volumes
from additional facilities that intend to produce cellulosic ethanol
from corn kernel fiber co-processed with corn starch in our projections
of cellulosic biofuel production in 2025. We request comment on whether
EPA should include additional volumes of cellulosic ethanol produced
from corn kernel fiber in our projection of cellulosic biofuel for
2023-2025, and if so, how we should project it and what those volumes
should be.
---------------------------------------------------------------------------

\58\ Guidance on Qualifying an Analytical Method for Determining
the Cellulosic Converted Fraction of Corn Kernel Fiber Co-Processed
with Starch. Compliance Division, Office of Transportation and Air
Quality, U.S. EPA. September 2022 (EPA-420-B-22-041).
---------------------------------------------------------------------------

d. Other
For the 2023-2025 timeframe, we expect that commercial scale
production of cellulosic biofuel in the U.S. will be limited to
electricity and CNG/LNG derived from biogas. In previous years several
foreign cellulosic biofuel facilities have also supplied ethanol
produced from sugarcane bagasse and heating oil produced from slash,
precommercial thinnings, and tree residue. Further, 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 2025. These
facilities generally are focusing on producing cellulosic hydrocarbons
that could be blended into gasoline, diesel, and jet fuel from
feedstocks such as separated municipal solid waste (MSW) and slash,
precommercial thinnings, and tree residue. In light of the fact that no
parties have been able to achieve consistent production of liquid
cellulosic biofuel in the U.S., production from these facilities in
2023-2025 is highly uncertain and likely to be relatively small (see
Chapter 5.1 of the RIA for more detail on the potential production of
liquid cellulosic biofuel through 2025). For the candidate volumes we
projected that there would be no production of liquid cellulosic
biofuel in 2023, and that liquid cellulosic biofuel would grow to 5
million and 10 million ethanol-equivalent gallons in 2024 and 2025
respectively.
2. Biomass-Based Diesel
Since 2010 when the biomass-based diesel (BBD) volume requirement
was added to the RFS program, production of BBD has generally
increased. 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 in foreign
markets, and several other economic factors. From 2010 through 2015 the
vast majority of BBD supplied to the U.S. was biodiesel. While
biodiesel is still the largest source of BBD supplied to the U.S.,
increasing volumes of renewable diesel have also been supplied.
Production and import of renewable diesel are expected to continue to
increase in future years.

[[Page 80596]]

[GRAPHIC] [TIFF OMITTED] TP30DE22.001

There are also very small volumes of renewable jet fuel and heating
oil that qualify as BBD, and there are currently significant efforts
underway to incentivize growth in renewable jet fuel in particular
(often referred to as sustainable aviation fuel or SAF).\59\ Jet fuel
has qualified as a RIN-generating 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 be used to produce SAF today are often the same as
those currently used to produce renewable diesel. For example, the same
refinery process that produces renewable diesel from waste fats, oils,
and greases or plant oils also produces hydrocarbons in the
distillation range of jet fuel that can be separated and sold as SAF
instead of being sold as renewable diesel. While relatively little SAF
has been produced since 2010--less than 5 million gallons per year--
opportunities for increasing this category of advanced biofuel exist.
In particular, other technologies and feedstocks are being developed
that might enable new sources of SAF. In addition, in April 2022 the
Administration announced a new Sustainable Aviation Fuel Grand
Challenge to inspire the dramatic increase in the production of
sustainable aviation fuels to at least 3 billion gallons per year by
2030. This effort is accompanied by new and ongoing funding
opportunities to support sustainable aviation fuel projects and fuel
producers totaling up to $4.3 billion.
---------------------------------------------------------------------------

\59\ According to EMTS data renewable jet fuel production has
ranged from 2-4 million gallons per year from 2016-2021.
---------------------------------------------------------------------------

Since the vast majority of BBD is biodiesel and renewable diesel,
and since feedstock limitations are likely to cause any growth in
renewable jet fuel to come at the expense of biodiesel and renewable
diesel, we have focused on just biodiesel and renewable diesel in this
section. The remainder of this section summarizes our assessment of the
rate of production and use of qualifying BBD from 2023 to 2025, and
some of the uncertainties associated with those volumes. Further
details on these volume projections can be found in DRIA Chapter 6.2.
a. Biodiesel
Historically the largest volumes of biomass-based diesel and
advanced biofuel supplied in the RFS program have been 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 has remained at approximately 1.8
billion gallons per year. 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 and
2017, with the majority of the imported biodiesel coming from
Argentina.\60\ In August 2017, the U.S. announced tariffs on biodiesel
imported from Argentina and Indonesia.\61\ These tariffs were
subsequently confirmed in April 2018.\62\ Since that time no biodiesel
has been imported from Argentina or Indonesia, and net biodiesel
imports have been relatively small.
---------------------------------------------------------------------------

\60\ EIA U.S. Imports by Country of Origin (<a href="https://www.eia.gov/dnav/pet/pet_move_impcus_a2_nus_EPOORDB_im0_mbbl_a.htm">https://www.eia.gov/dnav/pet/pet_move_impcus_a2_nus_EPOORDB_im0_mbbl_a.htm</a>). According
to EIA data 67 percent of all biodiesel imports in 2016 and 2017
were from Argentina.
\61\ 82 FR 40748 (August 28, 2017).
\62\ 83 FR 18278 (April 26, 2018).
---------------------------------------------------------------------------

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 biodiesel production capacity
in February 2022 was approximately 2.2 billion gallons per year.\63\
According to EIA data biodiesel production capacity grew slowly from
about 2.15 billion gallons in 2012 to a peak of approximately 2.5
billion gallons in 2018. 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 inactive facilities that are
far less likely to complete a monthly survey. EPA separately collects
facility capacity information through the facility

[[Page 80597]]

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 3.1 billion
gallons per year in April 2022, of which 2.8 billion gallons per year
was at biodiesel facilities that generated RINs in 2021. These
estimates of domestic production capacity strongly suggest that
domestic biodiesel production capacity is unlikely to limit domestic
biodiesel production through 2025.
---------------------------------------------------------------------------

\63\ EIA Monthly Biofuels Feedstock and Capacity Update (<a href="https://www.eia.gov/biofuels/update">https://www.eia.gov/biofuels/update</a>).
---------------------------------------------------------------------------

b. Renewable Diesel
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, both domestic production and imports of
renewable diesel have increased. Renewable diesel production facilities
generally have higher capital costs and production costs relative to
biodiesel, which likely accounts for the much higher volumes of
biodiesel production relative to renewable diesel production to date.
The higher cost of renewable diesel production can largely be off-set
through the benefits of economies of scale as renewable diesel
facilities tend to be much larger than biodiesel production facilities.
More importantly, because renewable diesel more closely resembles
petroleum-based diesel than biodiesel fuel (both renewable diesel and
petroleum-based diesel are hydrocarbons while biodiesel is a methyl-
ester) renewable diesel can be blended at much higher levels than
biodiesel. This allows renewable diesel producers to benefit to a
greater extent from the LCFS credits in California and other states in
addition to the RFS incentives and the federal tax credit and provides
a significant advantage over biodiesel, which has largely saturated the
California market.\64\ We expect that an increasing number of states
will adopt clean fuels programs, and that these programs could provide
an advantage to renewable diesel production relative to biodiesel
production in the U.S. See DRIA Chapter 6.2 for further discussion.
---------------------------------------------------------------------------

\64\ In 2021 nearly all renewable diesel consumed in the U.S.
was consumed in California. Together renewable diesel and biodiesel
represented approximately 26 percent of all diesel fuel consumed in
California in 2021.
---------------------------------------------------------------------------

Domestic renewable diesel production capacity has increased
significantly in recent years from approximately 280 million gallons in
2017 to nearly 1.5 billion gallons in February 2022.\65\ Additionally,
a number of parties have announced their intentions to build new
renewable diesel production capacity with the potential to begin
production by the end of 2025. These new facilities include new
renewable diesel production facilities, expansions of existing
renewable diesel production facilities, and the conversion of units at
petroleum refineries to produce renewable diesel. In total over 5
billion gallons of new renewable diesel capacity has been
announced,\66\ though it is likely that not all these announced
projects will be completed, and not all of those that are completed
will necessarily produce renewable diesel in the 2023-2025 timeframe
addressed by this rule.\67\ 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 it is possible
that feedstock limitations may result in renewable diesel facilities
operating below their production capacity. In light of the high capital
cost for these facilities, however, it appears more likely that the
announced renewable diesel facilities will not be built if sufficient
feedstock to operate these facilities at or near their production
capacity cannot be secured. We therefore expect that domestic renewable
diesel production is likely to increase along with production capacity
through 2025.
---------------------------------------------------------------------------

\65\ 2017 renewable diesel capacity based on facilities
registered in EMTS. February 2022 renewable capacity based on EIA
Monthly Biofuels Feedstock and Capacity Update.
\66\ U.S. Renewable Diesel Capacity Could Increase Due to
Announced and Developing Projects. EIA Today in Energy. July 29,
2021.
\67\ Reuters. CVR Pauses Renewable Diesel Plans as Feedstock
Prices Surge. August 3, 2021. Available at: <a href="https://www.reuters.com/business/energy/cvr-pauses-renewable-diesel-plans-feedstock-prices-surge-2021-08-03">https://www.reuters.com/business/energy/cvr-pauses-renewable-diesel-plans-feedstock-prices-surge-2021-08-03</a>.
---------------------------------------------------------------------------

In addition to domestic production the U.S. has also imported
significant volumes of renewable diesel, with nearly all of the
imported renewable diesel coming from Singapore. In more recent years,
the U.S. has also exported increasing volumes of renewable diesel. Net
imports of renewable diesel were approximately 120 million gallons in
2021. 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). We are projecting that net renewable
diesel imports will continue through 2025 at approximately the levels
observed in recent years, though we also recognize that increasing net
imports of renewable diesel could be a significant source of additional
renewable fuel supply in future years.
c. BBD Feedstocks
When considering the likely production and import of biodiesel and
renewable diesel in future years the availability of feedstock is an
important consideration. Currently, biodiesel and renewable diesel in
the U.S. are produced from a number of different feedstocks including
fats, oils and greases (FOG), distillers corn oil, and virgin vegetable
oils such as soybean oil and canola oil. As domestic production of
biodiesel has increased since 2014, an increasing percentage of total
biodiesel production has been produced from soybean oil, with smaller
increases in the use of FOG, distillers corn oil, and canola oil.

[[Page 80598]]

[GRAPHIC] [TIFF OMITTED] TP30DE22.002

Use of soybean oil to produce biodiesel increased from
approximately 10 percent of all domestic soybean oil production in the
2009/2010 agricultural marketing year to 38 percent in the 2020/2021
agricultural marketing year. 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 very 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 there has
been a corresponding increase in competition for these feedstocks
between biodiesel and renewable diesel. 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. By August 2021, the percentage of the soybean value
that came from the soybean oil had increased to approximately 50
percent. This competition is expected to continue to increase through
2025.
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. While many biodiesel production facilities are unable
to use these feedstocks, renewable diesel production facilities are
generally able to use them. Additionally, nearly all the renewable
diesel consumed in the U.S. is used in California, and under
California's LCFS program renewable diesel produced from FOG and
distillers corn oil receive more credits than renewable diesel produced
from soybean oil. Available volumes of FOG and distillers corn oil are
limited, however, and 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. Data from 2021 appears to support
this expectation, with increased soybean oil representing approximately
half of the increase in feedstocks used to produce renewable diesel in
the U.S. from 2020 to 2021.
One likely source of feedstock for expanding renewable diesel
production in 2023-2025 is soybean oil from new or expanded soybean
crushing facilities. Several parties have announced plans to expand
existing soybean crushing capacity and/or build new soybean crushing
facilities.\68\ This new crushing capacity is expected to come online
in the 2023-2025 timeframe. Increase crushing of soybeans in the U.S.
will increase domestic soybean oil production. If domestic crushing of
soybeans increases at the expense of soybean exports, domestic
vegetable oil production could be increased without the need for
additional soybean production. Alternatively, increased demand for
soybeans from new or expanded crushing facilities could result in
increased soybean production in the U.S. or increasing volumes of
qualifying feedstocks such as soybean oil and canola oil may be
diverted from existing markets to produce renewable diesel, with non-
qualifying feedstocks such as palm oil used in place of soybean and
canola oil in food and oleochemical markets.
---------------------------------------------------------------------------

\68\ For example, see Demaree-Saddler, Holly. Cargill plans US
soy processing operations expansion. World Grain. March 4, 2021, and
Sanicola, Laura. Chevron to invest in Bunge soybean crushers to
secure renewable feedstock. Reuters. September 2, 2021.
---------------------------------------------------------------------------

d. Projected BBD Production and Imports
We project that the supply of BBD to the U.S. will increase through
2025. We project that the largest increases will come from domestic
renewable diesel as new production facilities come online and ramp up
to full production. We project slight decreases in the volume of
biodiesel used in the U.S. as new renewable diesel producers are able
to out-compete some existing biodiesel producers for limited
feedstocks. One significant factor that is likely to negatively impact
biodiesel production is that opportunities for biodiesel expansion in
California, where producers can benefit from LCFS credits in addition
to RFS incentives, are very limited while there is significant
opportunity for the expansion of renewable diesel consumption in
California. The availability of LCFS credits will likely be a
significant factor in the competition between biodiesel producers and
renewable producers for access to new feedstocks, particularly
feedstocks with low carbon intensity (CI) scores in California's LCFS
program. While we project most of the biodiesel and renewable supplied
to the U.S. will be produced domestically, we project that imports of
both biodiesel and renewable diesel will continue to

[[Page 80599]]

contribute to the supply of these fuels through 2025.
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 would be
expected to contribute to compliance with applicable volume
requirements in the years after 2022. These other advanced biofuels
include imported sugarcane ethanol, domestically produced advanced
ethanol, biogas that is purified and compressed to be used in CNG or
LNG vehicles, heating oil, naphtha, and renewable diesel that does not
qualify as BBD.\69\ However, these biofuels have been consumed in much
smaller quantities than biodiesel and renewable diesel in the past,
and/or have been highly variable. In order to estimate the volumes of
these other advanced biofuels that may be available in 2023-2025, we
employed a methodology originally presented in the annual rulemaking
establishing the applicable standards for 2020-2022.\70\ 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 the table below. Details of the derivation of these
estimates can be found in DRIA Chapter 5.4.
---------------------------------------------------------------------------

\69\ Renewable diesel produced through coprocessing vegetable
oils or animals fats with petroleum cannot be categorized as BBD but
remains advanced biofuel. See 40 CFR 80.1426(f)(1).
\70\ 87 FR 39600 (July 1, 2022).

Table III.B.3-1--Estimate of Future Consumption of Other Advanced
Biofuel
------------------------------------------------------------------------
Volume
Fuel (million
RINs)
------------------------------------------------------------------------
Imported sugarcane ethanol................................... 110
Domestic ethanol............................................. 25
CNG/LNG...................................................... 5
Heating oil.................................................. 2
Naphtha...................................................... 33
Renewable diesel............................................. 81
----------
Total.................................................... 256
------------------------------------------------------------------------

As the available data does not permit us to identify an unambiguous
upward or downward trend in the historical consumption of these other
advanced biofuels, we propose to use the volumes in the table above for
all years covered in this proposed rule (i.e., 2023-2025).
4. Conventional Renewable Fuel
Conventional renewable fuel includes any renewable fuel made from
renewable biomass as defined in 40 CFR 80.1401, does not qualify as
advanced biofuel, and which meets one of the following criteria:
<bullet> Is demonstrated to achieve a minimum 20 percent reduction
in GHGs in comparison to the gasoline or diesel which it displaces; or
<bullet> 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.\71\
---------------------------------------------------------------------------

\71\ CAA section 211(o)(2)(A)(i).
---------------------------------------------------------------------------

Under the statute, there is no volume requirement for conventional
renewable fuel. Instead, conventional renewable fuel is that portion of
the total renewable fuel volume requirement that is not required to be
advanced biofuel. In some cases, it 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 in excess of that needed to meet the advanced biofuel
volume requirement.
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 time period addressed by this rulemaking. Corn starch
ethanol is prohibited by statute from being an advanced biofuel
regardless of its GHG performance in comparison to gasoline.\72\
---------------------------------------------------------------------------

\72\ CAA section 211(o)(1)(B)(i).
---------------------------------------------------------------------------

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 an historical high of
125 million gallons in 2019, representing just less than 1 percent of
all conventional ethanol. Waste industrial ethanol and ethanol made
from non-cellulosic portions of separated food waste have been produced
more sporadically and at even lower volumes. We have ignored these
other sources for our purposes here as they 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. In 2020, production capacity had reached 17.4 billion
gallons.73 74 This production capacity was significantly
underused in 2020 because the COVID-19 pandemic depressed gasoline
demand in comparison to previous years and thus ethanol demand in the
form of E10. Actual production of denatured ethanol in the U.S. reached
just 12.82 billion gallons in 2020, compared to 14.72 billion gallons
in 2019. Denatured ethanol production partially recovered in 2021,
reaching 14.09 billion gallons.\75\
---------------------------------------------------------------------------

\73\ ``2021 Ethanol Industry Outlook--RFA,'' available in the
docket.
\74\ ``Ethanol production capacity--EIA April 2021,'' available
in the docket.
\75\ ``RIN supply as of 1-31-22,'' available in the docket.
---------------------------------------------------------------------------

The expected annual rate of future commercial production of corn
ethanol will continue to be driven primarily by gasoline demand in the
2023-2025 timeframe as most gasoline is expected to continue to contain
10 percent ethanol. Commercial production of corn ethanol is also a
function of exports of ethanol and to a smaller degree the demand for
E0, E15, and E85, and we have incorporated projected growth in
opportunities for sales of E15 and E85 into our assessment. While
production of corn ethanol could in theory be limited by production
capacity, in reality there is an excess of production capacity in
comparison to the ethanol volumes that we estimate will be consumed in
the near future given constraints on consumption as described in
Section III.B.5 below. Thus, it does not appear that production
capacity will be a limiting factor in 2023-2025 for meeting the
candidate volumes.
b. Biodiesel and Renewable Diesel
Other than corn ethanol, the only other conventional renewable
fuels that have been used above de minimis levels in the U.S. have been
biodiesel and renewable diesel. The vast majority of those volumes were
imported, and all of it was grandfathered under 40 CFR 80.1403 and thus
was not required to meet the 20 percent GHG reduction requirement.
Actual global production of palm oil biodiesel and renewable diesel
was about 3.7 billion gallons in 2019.\76\ The

[[Page 80600]]

U.S. could be an attractive market for this foreign-produced
conventional biodiesel and renewable diesel if domestic demand for
conventional renewable fuel exceeded domestic supply, i.e., the amount
of ethanol that could be consumed combined with domestic production of
conventional biodiesel and renewable diesel. While there is no RIN-
generating pathway for biodiesel or renewable diesel produced from palm
oil in the RFS program, fuels produced at grandfathered facilities from
any feedstock meeting the definition of ``renewable biomass'' may be
eligible to generate conventional renewable fuel RINs. Total foreign
production capacity at grandfathered biodiesel and renewable diesel
production facilities is over 3.6 billion gallons, suggesting that
significant volumes of grandfathered biodiesel and renewable diesel
could be imported under favorable market conditions.
---------------------------------------------------------------------------

\76\ Total worldwide production of biodiesel and renewable
diesel was 46.8 billion liters in 2019 (see ``OECD-FAO Agricultural
Outlook 2020-2029 data for biodiesel & renewable diesel''), of which
30 percent was from palm oil (see page 206 of ``OECD-FAO
Agricultural Outlook 2021-2030'').
---------------------------------------------------------------------------

Historical U.S. imports of conventional biodiesel and renewable
diesel have been only a small fraction of global production in the
past. Conventional biodiesel imports rose between 2012 and 2016,
reaching a high of 113 million gallons.\77\ After 2016, however, there
have been no imports of conventional biodiesel. Small refinery
exemptions granted from 2016-2018 decreased demand for renewable fuel
in the U.S. and likely had an impact on conventional biodiesel and
renewable diesel imports. Imports of conventional renewable diesel have
been similarly low, reaching a high of 87 million gallons in 2015 and
being zero since 2017.\78\ The highest imported volume of total
conventional biodiesel and renewable diesel occurred in 2016 with 160
million gallons (258 million RINs).
---------------------------------------------------------------------------

\77\ ``RIN supply as of 3-22-21,'' available in the docket.
\78\ ``RIN supply as of 3-22-21,'' available in the docket.
---------------------------------------------------------------------------

5. Ethanol Consumption
Ethanol consumption in the U.S. is dominated by E10, with higher
ethanol blends such as E15 and E85 being used in much smaller
quantities. The total volume of ethanol that can be consumed, including
that produced from corn, cellulosic biomass, the non-cellulosic
portions of separated food waste, and sugarcane, is a function of these
three ethanol blends and demand for E0. The use of these different
gasoline blends is reflected in the poolwide ethanol concentration
which increased dramatically from 2003 through 2010 and thereafter
increased at a considerably slower rate.
[GRAPHIC] [TIFF OMITTED] TP30DE22.003

As the average ethanol concentration approached and then exceeded
10.00 percent, the gasoline pool became saturated with E10, with a
small, likely stable volume of E0 and small but increasing volumes of
E15 and E85. The average ethanol concentration can exceed 10.00 percent
only insofar as the ethanol in E15 and E85 exceeds the ethanol content
of E10 and more than offsets the volume of E0. In order to project
total ethanol consumption for 2023-2025, we correlated the poolwide
average ethanol concentration shown in the figure above with the number
of retail service stations offering E15 and E85. Projections of the
number of stations offering these blends in the future then provided a
basis for a projection of the average ethanol concentration, and thus
of total ethanol volumes consumed. The results are shown below. Details
of these calculations can be found in the DRIA.

Table III.B.5-1--Projected Ethanol Consumption
------------------------------------------------------------------------
Projected ethanol
Year Projected ethanol consumption
concentration (%) (million gallons)
------------------------------------------------------------------------
2023........................ 10.44 14,590
2024........................ 10.49 14,640
2025........................ 10.53 14,669
------------------------------------------------------------------------

[[Page 80601]]

C. Candidate Volumes for 2023-2025

Based on our analysis of supply-related factors as described in
Section III.B above, we developed candidate volumes for 2023-2025 which
we then subjected to the other economic and environmental analyses
required by the statute. This section describes the candidate volumes,
while Section IV summarizes the results of the additional analyses we
performed.
We have largely framed our assessment of volumes in terms of the
component categories (cellulosic biofuel, non-cellulosic advanced
biofuel, and conventional renewable fuel) 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 which 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 parsimonious as analyzing the statutory categories 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 and length 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
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. BBD volumes did not increase after
2012, 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 by 2022 was intended to be on growth in cellulosic biofuel
volumes, which have the greatest greenhouse gas reduction threshold.
The statutory cellulosic waiver provision, while acknowledging that the
statutory cellulosic biofuel volumes may not be met, nevertheless
expressed support for the cellulosic biofuel industry in directing EPA
to establish the cellulosic biofuel volume at the projected volume
available in years when the projected volume of cellulosic biofuel
production was less than the statutory volume. This increasing emphasis
on cellulosic biofuel in the RFS program is likely due to the
expectations among proponents of cellulosic biofuel that it has
significant potential to reduce GHG emissions (cellulosic biofuels are
required to reduce GHG emissions by 60 percent relative to the gasoline
or diesel fuel they displace),\79\ that cellulosic biofuel feedstocks
could be produced or collected with relatively few negative
environmental impacts, that the feedstocks would be inexpensive,
allowing for lower cost biofuels to be produced than those produced
from feedstocks with other primary uses such as food, and that the
technological breakthroughs needed to convert cellulosic feedstocks
into biofuel were right around the corner.
---------------------------------------------------------------------------

\79\ See definition of ``cellulosic biofuel'' at 40 CFR part 80
Section 1401.
---------------------------------------------------------------------------

The candidate volumes discussed in this section represent the
volume of qualifying cellulosic biofuel we project will be produced or
imported into the U.S. in 2022-2025, after taking into consideration
the incentives provided by the RFS program and other available state
and federal incentives. The candidate volumes for 2022-2025 are 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
candidate volumes for liquid cellulosic biofuel, CNG/LNG derived from
biogas, and eRINs separately. Note that consistent with the proposed
regulations for eRINs in this proposed rule, the candidate volumes for
2023 do not include any generation of cellulosic RINs from eRINs.

Table III.C.1-1--Cellulosic Biofuel Candidate Volumes
[Million RINs]
----------------------------------------------------------------------------------------------------------------
2023 2024 2025
----------------------------------------------------------------------------------------------------------------
Liquid Cellulosic Biofuel....................................... 0 5 10
CNG/LNG Derived from Biogas..................................... 719 814 921
eRINs........................................................... 0 600 1,200
-----------------------------------------------
Total Cellulosic Biofuel.................................... 719 1,419 2,131
----------------------------------------------------------------------------------------------------------------

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 2023-2025. For non-cellulosic advanced biofuel, the
implied statutory requirement increased in every year between 2009 and
2019. It remained at 4.5 billion gallons for three years before finally
rising to 5.0 billion gallons in 2022.
In calculating the applicable percentage standards in the past, we
have used volumes for non-cellulosic advanced biofuel that are at least
as high as those derived from the statutory targets, and occasionally
higher. For 2022, we have set the implied volume requirement for non-
cellulosic advanced biofuel at 5.0 billion gallons, equivalent to the
implied volume target in the statute.\80\ As described in that rule, we
believe that this level can be reached, though likely not without
market adjustments that could include some diversion of soybean oil
from food and other uses to biofuel production.
---------------------------------------------------------------------------

\80\ 87 FR 39600 (July 1, 2022).
---------------------------------------------------------------------------

For years after 2022, we anticipate that the growth in the
production of feedstocks used to produce advanced

[[Page 80602]]

biodiesel and renewable diesel (the two non-cellulosic advanced
biofuels projected to be available in the greatest quantities through
2025) will be limited, particularly in the U.S. While advanced biofuels
have the potential for significant GHG reductions, if pushing volume
requirements beyond the supply of low-GHG feedstocks results in an
increased use of high-GHG feedstocks in non-biofuel markets as low-GHG
feedstocks are increasingly used for biofuel production, then it would
prove counterproductive. Further, as discussed in greater detail in
Section III.C.3 below, significant volumes of non-ethanol advanced
biofuels beyond what would be needed to meet the implied non-cellulosic
advanced biofuel category are likely to also be needed to meet an
implied conventional renewable fuel volume of 15.25 billion
gallons.\81\
---------------------------------------------------------------------------

\81\ In 2023, the candidate volume for conventional renewable
fuel would be 15.00 billion gallons, but the inclusion of the
supplemental standard of 250 million gallons makes the conventional
renewable fuel volume effectively 15.25 billion gallons. We
sometimes refer to 15.25 billion gallons in 2023 as the effective
volume requirement for conventional renewable fuel.
---------------------------------------------------------------------------

Based on these considerations, we believe that increases in the
implied volume for non-cellulosic advanced biofuel in the 2023-2025
timeframe should be relatively small in comparison to the 500 million
RIN increase that occurred in 2022. As a result, we believe that an
annual increase of 100 million RINs as shown below would be reasonable.
We also note that this increase (100 million RINs per year) is
consistent with the projected increase in domestic soybean oil
production through 2025 if the entire volume were used to produce
biodiesel and/or renewable diesel.\82\
---------------------------------------------------------------------------

\82\ USDA Agricultural Projections to 2031. Soybean oil
production is projected to increase from 25,535 million pounds in
2021/22 to 27,475 million pounds in 2025/2026. This represents an
average annual increase of 485 million pounds per year, which could
be used to produce approximately 65 million gallons of biodiesel or
renewable diesel. This volume of fuel could generate between 95
million and 110 million RINs, depending on the equivalence value of
the fuel produced.

Table III.C.2-1--Non-Cellulosic Advanced Biofuel Candidate Volumes
[Million RINs]
------------------------------------------------------------------------
Year Volume
------------------------------------------------------------------------
2023........................................................... 5,100
2024........................................................... 5,200
2025........................................................... 5,300
------------------------------------------------------------------------

3. Conventional Renewable Fuel
As for non-cellulosic advanced biofuel, the implied statutory
volume targets for conventional renewable fuel in prior years represent
a useful point of reference in the consideration of candidate volumes
that may be appropriate for 2023-2025. Under the statute, conventional
renewable fuel increased every year between 2009 and 2015, after which
it remained at 15 billion gallons through 2022. In calculating the
applicable percentage standards in the past, we have used 15 billion
gallons in most years between 2017 and 2022.\83\ Thus as a starting
point, consistent with our approach to setting standards in recent
years, we considered whether 15 billion gallons of conventional
renewable fuel would be appropriate for 2023-2025.
---------------------------------------------------------------------------

\83\ While the 2020 implied volume requirement was originally
set at 15 billion gallons (85 FR 7016, February 6, 2020), we have
reduced it to the volume actually consumed due to the significant
impacts of the COVID-19 pandemic on demand for renewable fuel and
our change to the treatment of exemptions for small refineries (87
FR 39600, July 1, 2022). For 2021, as EPA did not establish
applicable standards with sufficient time to influence market
behavior, we have set the implied volume requirement for
conventional renewable fuel at the level actually consumed.
---------------------------------------------------------------------------

However, we note that the inclusion of a supplemental volume
requirement of 250 million gallons in 2022 to address the remand of the
2016 standards effectively results in an implied conventional renewable
fuel volume requirement of 15.25 billion gallons. Since we are also
proposing to include a supplemental volume requirement of 250 million
gallons in 2023 as described in Section V, an implied volume
requirement of 15 billion gallons for conventional renewable fuel would
also effectively be 15.25 billion gallons in 2023. As discussed in the
final rule which established the applicable volume requirements for
2022, we believe that a 15.25 billion gallon implied volume requirement
for conventional renewable fuel can be met without the need for
obligated parties to use carryover RINs for compliance. The same is
true for 2023-2025; not only do we project that total ethanol
consumption in these years will be higher than it was in 2022, but we
also project that sufficient excess volumes of advanced biodiesel and
renewable diesel can be supplied in 2023-2025. Thus, we believe that a
volume of 15.25 billion gallons in 2024 and 2025 is an appropriate
candidate volume for consideration. We expect that the market will have
adjusted to providing this volume in 2022 in meeting the combination of
the conventional renewable fuel implied volume requirement and the
supplemental volume requirement, and we project that the market could
do so as well for 2023, so it would be consistent with available supply
to consider 15.25 billion gallons as a candidate volume for 2024 and
2025 as well. However, for purposes of analyzing the other
environmental and economic impacts, we treat the proposed 2023
supplemental volume requirement separately as discussed in DRIA Chapter
3.3; the candidate volumes which we subjected to the other analyses
described in Section IV do not include the impacts of the supplemental
volume requirement.\84\
---------------------------------------------------------------------------

\84\ Although the effective implied volume requirement for
conventional renewable fuel would be 15.25 bill RINs for all years
2023-2025, in 2023 this implied volume requirement would in reality
be represented by 15.00 bill RINs for conventional renewable fuel
and 0.25 bill RINs for the supplemental standard.
---------------------------------------------------------------------------

Additionally, in considering a candidate volume of 15.25 billion
gallons of conventional renewable fuel in 2024 and 2025, we believe
that obligated parties would seek out RINs representing new renewable
fuel consumption to comply with the supplemental volume requirement to
the extent they are able, even though the supplemental volume
requirement in 2023 could be met with carryover RINs. In past years we
have noted a preference on the part of obligated parties for using RINs
associated with new renewable fuel consumption when possible,
preserving their individual carryover RIN banks for use in the event
that future supply falls short of that needed to meet the applicable
standards. As a result, we have assumed for purposes of analyzing the
impacts of this proposed rule that no carryover RINs would be used to
meet a candidate conventional renewable volume of 15.25 billion
gallons, and this provides additional justification for the
consideration of a candidate volume of 15.25 billion gallon for
conventional renewable fuel in 2024 and 2025.
As in past years, we do not expect that the implied conventional
renewable volume would be achievable through the consumption of ethanol
alone. As described in Section III.B.5, we estimate that ethanol
consumption will continue to fall short of 15.25 billion gallons in the
2023-2025 timeframe, even under the market influences of the RFS
program and with ongoing efforts to expand offerings of E15 and E85 at
retail service stations. Instead, there are a variety of means through
which the market could meet a 15.25 billion gallon

[[Page 80603]]

candidate volume for conventional renewable fuel, such as: \85\
---------------------------------------------------------------------------

\85\ Carryover RINs also represent a legitimate compliance
approach. However, since they do not represent new supply of
renewable fuel, they are not appropriate for including in the
candidate volumes for purposes of analyzing impacts.
---------------------------------------------------------------------------

<bullet> Reductions in the consumption of E0;
<bullet> Consumption of non-ethanol advanced biofuel, such as
biodiesel and renewable diesel, in excess of the applicable advanced
biofuel standard; and
<bullet> Domestic production and/or importation of conventional
biodiesel or renewable diesel.
As a result, our assessments from previous years remain applicable
for 2023-2025 in broad strokes: 15.25 billion gallons of conventional
renewable fuel is achievable through some collection of the avenues
listed above. We believe it is appropriate to analyze this volume of
conventional renewable fuel as part of the candidate volumes, even
though corn ethanol alone would not be sufficient to meet that volume.
The amount of corn ethanol that could be consumed between 2023 and
2025 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.

Table III.C.3-1--Projections of Corn Ethanol Consumption
[Million gallons]
----------------------------------------------------------------------------------------------------------------
2023 2024 2025
----------------------------------------------------------------------------------------------------------------
Ethanol in all blends........................................... 14,590 14,640 14,669
Cellulosic ethanol.............................................. 0 0 0
Imported sugarcane ethanol...................................... 110 110 110
Domestic advanced ethanol....................................... 25 25 25
Corn ethanol.................................................... 14,455 14,505 14,534
----------------------------------------------------------------------------------------------------------------

Since corn ethanol consumption would be about 14.5 billion gallons,
there would need to be about 0.75 billion ethanol-equivalent gallons of
non-ethanol renewable fuel in order for an effective conventional
renewable fuel volume of 15.25 billion gallons to be met.
As discussed in Section III.C.2, we project that more non-
cellulosic advanced biofuel can be made available than would be needed
to meet the non-cellulosic advanced biofuel candidate volumes shown in
Table III.C.2-1. The total volume of non-cellulosic advanced biofuel
that we project can be produced and consumed in 2023-2025 is shown
below. Details are provided in the DRIA Chapter 5.

Table III.C.3-2--Total Non-Cellulosic Advanced Biofuel Candidate Volumes
[Million RINs]
----------------------------------------------------------------------------------------------------------------
2023 2024 2025
----------------------------------------------------------------------------------------------------------------
Advanced biodiesel.............................................. 2,580 2,530 2,480
Advanced renewable diesel \a\................................... 3,054 3,154 3,275
Advanced jet fuel............................................... 5 5 5
Other advanced biofuel.......................................... 256 256 256
-----------------------------------------------
Total....................................................... 5,895 5,945 6,016
----------------------------------------------------------------------------------------------------------------
\a\ Represents only biomass-based diesel with a D code of 4. Advanced renewable diesel with a D code of 5 is
included in ``Other advanced biofuel.'' See also Table III.B.3-1.

The total volumes of non-cellulosic advanced biofuel that can be
supplied would be in excess of the candidate volumes we have considered
in this action.

Table III.C.3-3--Excess Non-Cellulosic Advanced Biofuel
[Million RINs]
----------------------------------------------------------------------------------------------------------------
2023 2024 2025
----------------------------------------------------------------------------------------------------------------
Total supply.................................................... 5,895 5,945 6,016
Candidate volume requirement.................................... 5,100 5,200 5,300
Excess.......................................................... 795 745 716
----------------------------------------------------------------------------------------------------------------

This excess non-cellulosic advanced biofuel would make up for the
shortfall in corn ethanol, enabling an implied conventional volume of
15.00 billion gallons in 2023 and 15.25 billion gallons in 2024 and
2025 to be met, and also enable the 250 million gallon supplemental
volume to be met.

[[Page 80604]]

Table III.C.3-4--Meeting the Candidate Volume for Conventional Renewable Fuel
[Million RINs]
----------------------------------------------------------------------------------------------------------------
2023 2024 2025
----------------------------------------------------------------------------------------------------------------
Corn ethanol.................................................... 14,455 14,505 14,534
Excess non-cellulosic advanced biofuel.......................... \a\ 545 745 716
-----------------------------------------------
Total....................................................... 15,000 15,250 15,250
----------------------------------------------------------------------------------------------------------------
\a\ An additional 250 million RINs of excess non-cellulosic advanced biofuel would also be available to fulfill
the supplemental volume requirement addressing the remand of the 2016 standards.

Based on our assessment of available supply, we do not believe that
there would be a need for conventional biodiesel or renewable diesel to
be imported in order to help meet an effective conventional renewable
fuel candidate volume of 15.25 billion gallons in the 2023-2025
timeframe. Nevertheless, such imports remain a potential source in the
event that the market did not respond to the candidate volumes in the
way that we have projected it would. As discussed in Section III.B.4.b,
total foreign production capacity for qualifying palm-based biodiesel
and renewable diesel is over 3.6 billion gallons.
4. 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 determine the 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. A
consideration of carryover RINs is also consistent with the statutory
requirement at 211(o)(2)(B)(ii) that, in the context of determining
appropriate volume requirements for years after 2022, we review the
implementation of the program in prior years. We therefore investigated
whether and to what degree carryover RINs should be considered in the
context of determining appropriate levels for the candidate volumes and
ultimately the proposed volume requirements (discussed in Section VI).
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 themselves, or
by purchasing the RINs that represent the renewable fuels from other
parties that perform the blending. 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 our
regulations limit the use of these carryover RINs to 20 percent of the
obligated party's renewable volume obligation (RVO).\86\ For the bank
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 2020 carryover RINs must be used
for compliance with 2021 compliance year obligations, or they will
expire. However, vintage 2021 RINs can then be ``banked'' for use
toward 2022 compliance.
---------------------------------------------------------------------------

\86\ 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.\87\ A bank of carryover RINs is extremely important 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.\88\ 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.
---------------------------------------------------------------------------

\87\ See, e.g., 72 FR 23904 (May 1, 2007).
\88\ 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).
---------------------------------------------------------------------------

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 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. Were there to be too few RINs in reserve, then
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 carryover RIN bank 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 of these
reasons, the collective carryover RIN bank provides 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 allowing for the generation and use of
credits.
EPA can also rely on the availability of carryover RINs to support
market-forcing volumes that may not be able to be met with renewable
fuel production and use in that year, and 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

[[Page 80605]]

production and import, justified maintaining the advanced and total
renewable fuel volume requirements for that year at the levels
specified in the statute.\89\
---------------------------------------------------------------------------

\89\ 79 FR 49793-95 (August 15, 2013).
---------------------------------------------------------------------------

a. Carryover RIN Bank Size
After compliance with the 2019 standards, we project that there are
approximately 1.83 billion total carryover RINs available.\90\ This is
the same total number of carryover RINs that were estimated to be
available in the 2020-2022 final rule. Since we set both the 2020 and
2021 volume requirements at the actual volume of renewable fuel
consumed in those years, we project that 1.83 billion total carryover
RINs will be available for compliance with the 2022 standards
(including the 2022 supplemental standard) as well. Assuming that the
market exactly meets the 2022, 2023, and 2024 standards, this is also
the number of carryover RINs that would be available for 2023, 2024,
and 2025 (including the 2023 supplemental standard).
---------------------------------------------------------------------------

\90\ The calculations performed to estimate the size of the
carryover RIN bank can be found in the memorandum, ``Carryover RIN
Bank Calculations for 2023-2025 Proposed Rule,'' available in the
docket for this action.
---------------------------------------------------------------------------

However, the standards we established for 2022 (including the 2022
supplemental standard) were significantly higher than the volume of
renewable fuel used in previous years, and the candidate volumes would
represent increases for 2025. While we project that the volume
requirements in 2022 and the candidate volumes for 2023-2025 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 2023, 2024, and 2025 standards
(including the 2023 supplemental standard). 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 net result could be a total carryover
RIN bank larger or smaller than 1.83 billion RINs.
b. Treatment of Carryover RINs for 2023-2025
We evaluated the volume of carryover RINs projected to be available
and considered whether we should include any portion of them in the
determination of the candidate volumes that we analyzed or the volume
requirements that we propose for 2023-2025 (including the 2023
supplemental volume). Doing so would be equivalent to intentionally
drawing down the carryover RIN bank in setting those volume
requirements. We do not believe that this would be appropriate. In
reaching this proposed determination, we considered the functions of
the carryover RIN bank, its projected size, the uncertainties
associated with its projection, its potential impact on the production
and use of renewable fuel, the ability and need for obligated parties
to draw on it to comply with their obligations (both on an individual
basis and on a market-wide basis), and the impacts of drawing it down
on obligated parties and the fuels market more broadly. As previously
described, the bank of carryover RINs provides 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 bank of carryover RINs for
important programmatic functions, is appropriate when EPA exercises its
discretion under its statutory authorities.
Furthermore, as noted earlier, the advanced biofuel and total
renewable fuel standards established for 2022 are significantly higher
than the volume of renewable fuel used in previous years. As we
explained in the 2020-2022 final rule, while we believe that the market
can make sufficient renewable fuel available to meet the 2022
standards, there may be some challenges, and carryover RINs will be
available for those obligated parties who choose to use them for
compliance.\91\ In addition, in this action we are for the first time
proposing to establish volume requirements for three years
prospectively. This inherently adds uncertainty and makes it more
challenging to project with accuracy the number of carryover RINs that
will actually 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
after 2022 with the intent to draw down the carryover RIN bank could
lead to significant deficit carryovers and non-compliance by some
obligated parties that own relatively few or no carryover RINs. We do
not believe this would be an appropriate outcome. Therefore, consistent
with the approach we have taken in recent annual rules, we are not
proposing to include carryover RINs in the candidate volumes, nor to
set the 2023, 2024, and 2025 volume requirements (including the 2023
supplemental standard) at levels that would intentionally draw down the
bank of carryover RINs.
---------------------------------------------------------------------------

\91\ 87 FR 39600 (July 1, 2022).
---------------------------------------------------------------------------

We are not determining that 1.83 billion RINs is a bright-line
threshold for the number of carryover RINs that provides sufficient
market liquidity and allows the carryover RIN bank to play its
important programmatic functions. As in past years, we are instead
evaluating, on a case-by-case basis, the size of the carryover RIN bank
in the context of the RFS standards and the broader transportation fuel
market at this time. 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 is capable of achieving in 2023-2025.
Conversely, while an even larger carryover RIN bank may provide greater
assurance of market liquidity, we do not believe it would be
appropriate to set the standards at levels specifically designed to
increase the number of carryover RINs available to obligated parties.
5. Summary
Based on our analysis of supply-related factors, we identified a
set of candidate volumes for each of the component categories which we
believe represent achievable levels of supply (domestic production and/
or import) and consumption.

[[Page 80606]]

Table III.C.5-1--Candidate Volume Components Derived From Supply-Related Factors
[Million RINs] \a\
----------------------------------------------------------------------------------------------------------------
2023 2024 2025
----------------------------------------------------------------------------------------------------------------
Cellulosic biofuel (D3 & D7).................................... 719 1,419 2,131
Biomass-based diesel (D4)....................................... 5,389 5,689 5,760
Other advanced biofuel (D5)..................................... 256 256 256
Conventional renewable fuel (D6)................................ 14,455 14,505 14,534
----------------------------------------------------------------------------------------------------------------
\a\ 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 which can be fulfilled with each component category according to 40 CFR
80.1427(a)(2).

These are the candidate volumes that we further analyzed according
to the other economic and environmental factors required under the
statute in CAA 211(o)(2)(B)(ii). Those additional analyses are
described in Section IV. Details of the individual biofuel types and
feedstocks that make up these candidate volumes are provided in the
DRIA. In Section VI, we discuss our proposed volumes based on a
consideration of all of the factors that we analyzed.
Note that the volumes shown in Table III.C.5-1 represent the total
candidate volumes consumed for each component category of renewable
fuel, not the volume requirements. The volumes of non-cellulosic
advanced biofuel having a D code of 4 or 5, for instance, represent
volumes consumed in fulfillment of the BBD volume requirement, the
advanced biofuel volume requirement, and the total renewable fuel
volume requirement, including that portion of the implied volume for
conventional renewable fuel that cannot be met with ethanol. The volume
requirements that we are proposing to establish for 2023-2025, in
contrast, are based not only on an analysis of the supply-related
factors as discussed at the beginning of this Section III, but also on
a consideration of the other factors that we analyzed as required by
the statute. Below is a summary of the candidate volumes. Section VI
provides more comprehensive discussion of our consideration of all
factors leading to our determination of the proposed volume targets.

Table III.C.5-2--Candidate Volumes
[Million RINs] \a\
----------------------------------------------------------------------------------------------------------------
2023 2024 2025
----------------------------------------------------------------------------------------------------------------
Cellulosic biofuel.............................................. 719 1,419 2,131
Non-cellulosic advanced biofuel \b\............................. 5,100 5,200 5,300
Advanced biofuel................................................ 5,819 6,619 7,431
Conventional renewable fuel \b\................................. \a\ 15,000 15,250 15,250
-----------------------------------------------
Total renewable fuel........................................ 20,819 21,869 22,681
----------------------------------------------------------------------------------------------------------------
\a\ Does not include the 250 million gallon supplemental volume requirement to address the 2016 remand under
ACE.
\b\ These are implied volume requirements, not regulatory volume requirements.

D. Baselines

In order to estimate the impacts of the candidate volumes, we must
identify an appropriate baseline. The baseline reflects the alternative
collection of biofuel volumes by feedstock, production process (where
appropriate), biofuel type, and use which would be anticipated to occur
in the absence of applicable standards, and acts as the point of
reference for assessing the impacts. To this end, we have developed a
``No RFS'' scenario that we use as the baseline for analytical
purposes. Many of the same supply-related factors that we used to
develop the candidate volumes were also relevant in developing the No
RFS baseline.
We also considered other possible baselines that, as described
below, we are not using to assess all the impacts of the candidate
volumes. We discuss the alternative baselines here in an effort 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. Ultimately, we concluded that
the No RFS scenario is the most appropriate to use.
1. No RFS Program
Broadly speaking, the RFS program is designed to increase the use
of renewable fuels in the transportation sector beyond what would occur
in the absence of the program. It is appropriate, therefore, to use a
scenario representing what would occur if the RFS program did not exist
as the baseline for estimating the costs and impacts of the candidate
volumes. 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.'' In the final rule
establishing the standards for 2020-2022, we indicated that a No RFS
baseline would be preferable to using a previous year's volume
requirements as the baseline, but that we could not develop such a
baseline in the time available for that action.\92\
---------------------------------------------------------------------------

\92\ See 87 FR 39600, 39626 (July 1, 2022). See also,
``Renewable Fuel Standard (RFS) Program: RFS Annual Rules--
Regulatory Impact Analysis'' at 50, EPA-420-R-22-008, June 2022.
---------------------------------------------------------------------------

Importantly, a ``No RFS'' baseline would not be equivalent to a
market scenario wherein no biofuels 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 2023-2025 in the absence of the RFS
program. Federal, state, and local tax credits, incentives, and support
payments will continue to be in place

[[Page 80607]]

for these fuels, as well as state programs such as blending mandates
and Low Carbon Fuel Standard (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 2023-2025 to the applicable standards under the RFS
program.
To inform our assessment of the volume of biofuels that would be
used in the absence of the RFS program for the years 2023 through 2025,
we began by analyzing the trends in biofuel blending in prior years.
Assessing these trends is important because the economics for blending
biofuels changes from year to year based on biofuel feedstock and
petroleum product prices and other factors which affect the relative
economics for blending biofuels into petroleum-based transportation
fuels. A biofuel plant investor and the financiers who fund their
projects will review the historical, current, and perceived future
economics of the biofuel market when deciding whether to fund the
construction of biofuel plants, and our analysis attempted to account
for these factors.
The economic analysis for 2023-2025 compares the biofuel value with
the fossil fuel it displaces, at the point that the biofuel is blended
with the fossil fuel, to assess whether the biofuel provides an
economic advantage. If the biofuel is lower cost than the fossil fuel
it displaces, it is assumed that the biofuel would be used absent the
RFS standards. The economic analysis that we conducted to assess the
volume of biofuel that would likely be produced and consumed in the
absence of the RFS program mirrors the cost analysis described in
Section IV.C, but there is one primary difference and a number of other
differences. The primary difference is that the economic analysis
relative to the No RFS baseline assesses whether the fuels industry
would find it economically advantageous to blend the biofuel into the
petroleum fuel in the absence of the RFS program, whereas the social
cost analysis reflects the overall impacts on consumers (society at
large). The primary example of a social cost not considered for the No
RFS economic analysis is the fuel economy effect due to the lower
energy density of the biofuel, as this cost is borne by consumers, not
the fuels industry. Other ways that the No RFS economic analysis is
different from the social cost analysis include:
<bullet> In the context of assessing production costs, we amortized
the capital costs at a 10 percent after-tax rate of return more typical
for industry investment instead of the 7 percent before-tax rate of
return used for social costs.
<bullet> We assessed biofuel distribution costs to the point where
it is blended into fossil fuel, not all the way to the point of use
that is necessary for estimating the fuel economy cost.
<bullet> While we generally do not account for the fuel economy
disadvantage of most biofuels for the No RFS 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 are forced to 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. A
similar situation exists with E15, although it is not clear what the
factors are for E15 and this is discussed in more detail in the No RFS
discussion in DRIA Chapter 2.
We added these various cost components together to reflect the cost
of each biofuel.
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 using biofuels. Unlike for biofuels, we did not calculate
production costs for the fossil fuels. Instead, we projected their
production costs based solely on wholesale price projections by the
Energy Information Administration in its Annual Energy Outlook (AEO).
We also considered any applicable federal or state programs,
incentives, or subsidies that could reduce the apparent blending cost
of the biofuel at the terminal. For instance, 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. 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 volume percent.
Other states offer tax credits for E85, of which the largest is in New
York. We are not aware of any state tax credits or subsidies for E15.
In the case of higher ethanol blends, the retail cost associated with
the equipment and/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 Federal and/or state grant programs such as USDA's Higher Blends
Infrastructure Incentive Program (HBIIP).
For most biofuels, the economic analysis provided consistent
results, indicating that they are either economical in all years or are
not economical in any year. However, this was not true for biodiesel
and renewable diesel, where the results varied from year to year. Such
swings in the economic attractiveness of biodiesel and renewable diesel
confound efforts on the part of investors to project future returns on
their investments. Thus, to smooth out the swings in the economics for
using biodiesel and renewable diesel and look at it the way investors
would have in the absence of the RFS program, we made two different 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 a four year period. As a result, the first year modeled was
actually 2012. 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 biofuels than if no RFS program were in place.
An economic analysis was also conducted 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 2023-2025 is summarized below in Table
III.D.1-1. A more complete description of the No RFS baseline and its
derivation is provided in DRIA Chapter 2.

[[Page 80608]]

Table III.D.1-1--Biofuel Consumption in 2023-2025 Under a No RFS Baseline
[Million RINs]
----------------------------------------------------------------------------------------------------------------
2023 2024 2025
----------------------------------------------------------------------------------------------------------------
Cellulosic biofuel (D3 & D7).................................... 356 385 417
Biomass-based diesel (D4)....................................... 1,374 1,374 1,374
Other advanced biofuel (D5)..................................... 216 216 216
Conventional renewable fuel (D6)................................ 13,750 13,730 13,693
----------------------------------------------------------------------------------------------------------------

Our analysis shows that corn ethanol is economical to use up to the
E10 blendwall without the presence of the RFS program. Conversely,
higher ethanol blends would generally not be economic without the RFS
program, except for some small volume of E85 in the state of New York
which offers a large E85 blending subsidy. 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,
primarily in California due to the LCFS incentives. The volume of CNG
from biogas and imported ethanol from sugarcane are projected to be
consumed in California due to the economic support provided by their
LCFS. There would be no renewable electricity used as transportation
fuel under a No RFS baseline since we are proposing to establish the
eRIN program through this action. However, we expect that the biogas
used to produce that renewable electricity would still be produced
under a No RFS baseline as discussed in DRIA Chapter 2.1.
2. Alternative Approaches to the No RFS Baseline
We also considered several other ways to identify a No RFS
baseline. However, we do not believe they would be appropriate as they
would be unlikely to represent the world in 2023-2025 as it would
likely be in the absence of the RFS program. For instance, the RFS
program went into effect in 2006 with a default percentage standard
specified in the statute. As 2005 represents the most recent year for
which the RFS requirements did not apply, it could be used as the
baseline in assessing costs and impacts of the candidate volumes.
However, a significant number of changes to other factors that
significantly affect the fuels sector have occurred between 2005 and
the 2023-2025 period to which this action applies, including changes in
state requirements, tax subsidies, tariffs, international supply, total
fuel demand, crude oil prices, feedstock prices, and fuel economy
standards. All of these have influenced the economical use of renewable
fuel during the intervening period, and it is infeasible to model all
these interactions. As a result, using 2005 as the baseline would lead
to a highly speculative assessment of costs and impacts that neglects
important market and regulatory realities. Therefore, we do not believe
that a 2005 baseline would be appropriate for this rulemaking.
In the 2010 RFS2 rulemaking that created the RFS2 regulatory
program that was required by EISA, one of the baselines that we used
was the 2007 version of EIA's AEO which provided projections of
transportation fuel use, including the use of renewable fuel, out to
2030.\93\ This is the most recent version of the AEO that projected
fuel use in the absence of the statutory volume targets specified in
the Energy Independence and Security Act of 2007; all subsequent
versions of the AEO have included the current RFS program in their
projections. While the 2007 version of the AEO includes projections for
the timeframe of interest in this action, 2023-2025, it suffers from
the same drawbacks as using fuel use in 2005 as the baseline. Namely, a
significant number of other changes have occurred between 2007 when the
projections were made and the 2023-2025 period to which this action
applies. For the same reasons, then, we do not believe that the
projections in AEO 2007 would be an appropriate baseline.
---------------------------------------------------------------------------

\93\ 75 FR 14670 (March 26, 2010).
---------------------------------------------------------------------------

3. Previous Year Volume Requirements
The applicable volume requirements established for one year under
the RFS program do not roll over automatically to the next, nor do the
volume requirements that apply in one year become the default volume
requirements for the following year in the event that no volume
requirements are set for that following year. Nevertheless, the volume
requirements established for the previous year represent the most
recent set of volume requirements that the market was required to meet,
and the fuels industry as a whole can be expected to have adjusted its
operations accordingly. 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, and we have
used previous year standards as a baseline in previous annual standard-
setting rulemakings.
The 2022 volume requirements were finalized on July 1, 2022, and
are shown in Table III.D.3-1.\94\
---------------------------------------------------------------------------

\94\ 87 FR 39600 (July 1, 2022).

Table III.D.3-1--Final 2022 Volume Requirements
------------------------------------------------------------------------
Volume
Category (billion
RINs)
------------------------------------------------------------------------
Cellulosic biofuel........................................... 0.63
Biomass based diesel \a\..................................... 2.76
Advanced biofuel............................................. 5.63
Total renewable fuel......................................... 20.63
------------------------------------------------------------------------
\a\ The BBD volumes are in physical gallons (rather than RINs).

In the final rule that established these volume requirements, we
discussed the fact that the preferable baseline would have been a No
RFS baseline, but that it could not be developed in the time available.
For this proposed rule for 2023-2025, we again believe that the No RFS
baseline is preferable and should be used since it is now available. As
a result, we have not used the 2022 volume requirements as a baseline
to estimate all of the impacts of the candidate volumes for 2023-2025.
However, as an additional informational case, we have estimated the
costs alone with respect to the 2022 volume requirements in order to
allow comparison to the analysis and results presented in recent annual
rules. For this purpose, we needed to estimate a mix of biofuels and
associated feedstocks that would represent a reasonable way that the
market will respond to the finalized 2022 volume requirements. This
assessment is provided in the DRIA in Chapter 2.

[[Page 80609]]

4. Previous Year Actual Consumption
In most annual standard-setting rules, we have used the previous
year's volume requirements as the baseline against which the impacts of
the next year's volume requirements would be assessed. In the final
rule establishing the volume requirements and percentage standards for
2021 and 2022, however, we instead used the actual consumption in 2020
as a baseline for the purposes of estimating the impacts of those
standards. We did this because the previous year's (2020) volume
requirements were revised in that same action to represent actual
consumption in that year. That approach was also consistent with the
approach we took in the rulemaking which established the volume
requirements for 2014, 2015, and 2016.\95\ In that rule, the impacts of
the volume requirements for 2015 were compared to the actual volumes
consumed in 2014, and the impacts of the volume requirements for 2016
were compared to the actual volumes consumed in 2015.\96\
---------------------------------------------------------------------------

\95\ 80 FR 77420 (December 14, 2015).
\96\ The 2015 volumes were based on actual consumption data for
January-September and a projection for October-December.
---------------------------------------------------------------------------

We acknowledge that actual consumption in a previous year would
have the advantage that the mix of biofuel types and associated
feedstocks are known and would not need to be estimated as would be
required when using the previous year's volume requirements as a
baseline. However, we have not used the previous year's actual
consumption as a baseline in this action because, as explained earlier,
we believe that the No RFS baseline is superior. Moreover, the use of
actual consumption from a previous year has the drawback that the
resulting comparison would conflate the impacts of the program with
whatever unique market circumstances existed in that previous year.

E. Volume Changes Analyzed

In general, our analysis of the economic and environmental impacts
of the candidate volumes derived and discussed above was based on the
differences between our assessment of how the market would respond to
those candidate volumes (summarized in Table III.C.4-1) and the No RFS
baseline (summarized in Table III.D.1-1). Those differences are shown
below. Details of this assessment, including a more precise breakout of
those differences, can be found in DRIA Chapter 2. Note that this
approach is squarely focused on the differences in volumes between the
No RFS baseline and the candidate volumes; our analysis does not, in
other words, assess impacts from total biofuel use in the United
States.

Table III.E-1--Changes in Biofuel Consumption in the Transportation Sector in Comparison to the No RFS Baseline

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