Document ID: EPA-HQ-OAR-2021-0427-0966
Agency: epa
Document Type: Rule
Title: Renewable Fuel Standard Program: Standards for 2023–2025 and Other Changes
Posted Date: 2023-07-12T04:00Z

[Federal Register Volume 88, Number 132 (Wednesday, July 12, 2023)]
[Rules and Regulations]
[Pages 44468-44593]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2023-13462]

[[Page 44467]]

Vol. 88

Wednesday,

No. 132

July 12, 2023

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; Final Rule

  Federal Register / Vol. 88, No. 132 / Wednesday, July 12, 2023 / 
Rules and Regulations  

[[Page 44468]]

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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Parts 80 and 1090

[EPA-HQ-OAR-2021-0427; FRL-8514-02-OAR]
RIN 2060-AV14

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

AGENCY: Environmental Protection Agency (EPA).

ACTION: Final 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 establishes 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 establishes the second supplemental standard addressing the 
judicial remand of the 2016 standard-setting rulemaking. Finally, this 
action makes several regulatory changes to the RFS program, including 
changes related to the treatment of biogas and other modifications to 
improve the program's implementation. At this time EPA is not 
finalizing proposed provisions related to the generation of RINs from 
qualifying renewable electricity.

DATES: This rule is effective on September 11, 2023, except for 
amendatory instruction 30, which is effective on February 1, 2024, and 
amendatory instructions 41 and 42, which are effective on April 1, 
2024. The incorporation by reference of certain publications listed in 
this regulation is approved by the Director of the Federal Register as 
of July 12, 2023. The incorporation by reference of ASTM D1250, ASTM 
D4442, ASTM D4444, ASTM D6866, and ASTM E870 was approved by the 
Director of the Federal Register as of July 1, 2022. The incorporation 
by reference of ASTM D4057, ASTM D4177, ASTM D5842, and ASTM D5854 was 
approved by the Director of the Federal Register as of April 28, 2014. 
The incorporation by reference of ASTM E711 was approved by the 
Director of the Federal Register as of July 1, 2010.

ADDRESSES: EPA has established a docket for this action under Docket ID 
No. EPA-HQ-OAR-2021-0427. All documents in the docket are listed on the 
https://www.regulations.gov website. Although listed in the index, some 
information is not publicly available, e.g., confidential business 
information (CBI) or other information whose disclosure is restricted 
by statute. Certain other material is not available on the internet and 
will be publicly available only in hard copy form. Publicly available 
docket materials are available electronically through https://www.regulations.gov.

FOR FURTHER INFORMATION CONTACT: Dallas Burkholder, Office of 
Transportation and Air Quality, Assessment and Standards Division, 
Environmental Protection Agency, 2000 Traverwood Drive, Ann Arbor, MI 
48105; telephone number: 734-214-4766; email address: [email protected].

SUPPLEMENTARY INFORMATION: Entities potentially affected by this final 
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, and biogas). 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......................................          221210  Manufactured gas production and distribution,
                                                                 and distribution of renewable natural gas
                                                                 (RNG).
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......................................          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 potentially affected by this final 
action. This table lists the types of entities that EPA is now aware 
could potentially be affected by this final action. Other types of 
entities not listed in the table could also be affected. To determine 
whether your entity would be affected by this final action, you should 
carefully examine the applicability criteria in 40 CFR part 80. If you 
have any questions regarding the applicability of this final action to 
a particular entity, consult the person listed in the FOR FURTHER 
INFORMATION CONTACT section.

Table of Contents

I. Executive Summary
    A. Summary of the Key Provisions of This Regulatory Action
    B. Environmental Justice
    C. Impacts of This Rule
    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 Volumes and Percentage Standards for 
Multiple Future Years
    E. Considerations for Late Rulemaking
    F. Impact on Other Waiver Authorities
    G. Severability
III. Candidate Volumes and Baselines
    A. Scope of Analysis
    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 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. Volume Requirements for 2023-2025
    A. Cellulosic Biofuel
    B. Non-Cellulosic Advanced Biofuel
    C. Biomass-Based Diesel
    D. Conventional Renewable Fuel
    E. Summary of Final Volume Requirements

[[Page 44469]]

VII. Percentage Standards for 2023-2025
    A. Calculation of Percentage Standards
    B. Treatment of Small Refinery Volumes
    C. Percentage Standards
VIII. Administrative Actions
    A. Assessment of the Domestic Aggregate Compliance Approach
    B. Assessment of the Canadian Aggregate Compliance Approach
IX. Biogas Regulatory Reform
    A. Background
    B. Biogas Under a Closed Distribution System
    C. RNG Producer as the RIN Generator
    D. Assignment, Separation, Retirement, and Expiration of RNG 
RINs
    E. Structure of the Regulations
    F. Implementation Date
    G. Definitions
    H. Registration, Reporting, Product Transfer Documents, and 
Recordkeeping
    I. Testing and Measurement Requirements
    J. RFS QAP Under Biogas Regulatory Reform
    K. Compliance and Enforcement Provisions and Attest Engagements
    L. RNG Used as a Feedstock
    M. RNG Imports and Exports
    N. Biogas/RNG Storage Prior to Registration
    O. Single Use for Biogas Production Facilities
    P. Requirements for Parties That Own and Transact RNG RINs
X. 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. Separated Food Waste Recordkeeping Requirements
    I. Definition of Ocean-Going Vessels
    J. Bond Requirement for Foreign RIN-Generating Renewable Fuel 
Producers and Foreign RIN Owners
    K. Definition of Produced from Renewable Biomass
    L. Technical Amendments
XI. 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) and 
1 CFR Part 51
    J. Executive Orders 12898 (Federal Actions To Address 
Environmental Justice in Minority Populations, and Low-Income 
Populations) and 14096 (Revitalizing Our Nation's Commitment to 
Environmental Justice for All)
    K. Congressional Review Act (CRA)
XII. 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
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                          Category                               Years
------------------------------------------------------------------------
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:
     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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     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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     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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     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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     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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     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 establishes the volume targets and applicable percentage 
standards for cellulosic biofuel, BBD, advanced biofuel, and total 
renewable fuel for 2023-2025. We are also promulgating a number of 
regulatory changes intended to improve the operation of the RFS 
program. This action describes our rationale for the final volume 
targets and regulatory changes. Responses to comments received from 
stakeholders on the proposed rule can be found in the associated 
Response to Comments (RTC) document.
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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, production, and use 
of low-carbon, domestically produced renewable fuels. This ``Set rule'' 
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 input on what policy 
direction this action should take, and the Agency greatly appreciates 
the sustained and constructive input we have received from 
stakeholders. We appreciate the many comments we received, not only on 
the volumes that we proposed on December 30, 2022, but also on the

[[Page 44470]]

analyses we conducted and the proposed regulatory changes. EPA looks 
forward to continued engagement with stakeholders on the RFS program.

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 are 
establishing the volume targets for three years, 2023 to 2025, as shown 
below. We proposed setting standards for three years to strike 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. After reviewing 
stakeholder comments and considering the statutory deadlines for 
establishing RFS volume obligations we have determined that this three-
year timeframe remains appropriate. In addition to the volume targets 
for 2023-2025, we are also completing our response to the D.C. Circuit 
Court of Appeals' remand of the 2016 RFS annual rule in Americans for 
Clean Energy v. EPA, 864 F.3d 691 (2017) (``ACE'') by establishing 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\ See 87 FR 39600, 39628-29 (July 1, 2022) (discussing 
approaches for responding to the ACE remand).

                                       Table I.A.1-1--Final Volume Targets
                                               [Billion RINs] \a\
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                                                                       2023            2024            2025
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Cellulosic biofuel..............................................            0.84            1.09            1.38
Biomass-based diesel \b\........................................            2.82            3.04            3.35
Advanced biofuel................................................            5.94            6.54            7.33
Renewable fuel..................................................           20.94           21.54           22.33
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 (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. Many of those factors, particularly those related 
to economic and environmental impacts, are 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 establish under the statute. 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, and other 
relevant factors, to identify ``candidate volumes.'' We then analyzed 
the impacts of the candidate volumes on the other economic and 
environmental factors that the statute lists. 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 establish in light of 
all of the analyses that we conducted and all of the comments we 
received from stakeholders at the public hearing on January 10 and 11, 
2023, written comments, letters, and other meetings and input provided 
to us.
    The cellulosic biofuel volumes we are finalizing in this rule for 
2024 and 2025 are lower than the proposed volumes as they do not 
include cellulosic biofuel from eRINs (all eRIN volumes projected in 
the proposal have been zeroed out in this final rule). The decreases in 
the cellulosic biofuel volumes for 2024 and 2025 are partially offset 
by increases in the projected volumes of non-eRIN cellulosic biofuel 
(i.e., CNG/LNG derived from biogas and ethanol from corn kernel fiber) 
for all three years. The advanced and total biofuel volumes reflect 
both these changes in cellulosic biofuel, and our new, higher 
projections of the availability of BBD relative to the proposed rule. 
The final volumes also reflect our decision to maintain a 15.0 billion 
gallon implied conventional biofuel requirement for all three years 
(plus an additional 250 million gallon supplemental volume requirement 
for 2023 to complete EPA's response to the ACE remand), consistent with 
the statutory level from 2015 through 2022, rather than increasing this 
volume to 15.25 billion gallons in 2024 and 2025 as we originally 
proposed.
    The volume targets that we are establishing in this action have 
similar status as those in the statute for the years shown in Table I-
1. Specifically, they are the basis for the calculation of percentage 
standards applicable to producers and importers of gasoline and diesel 
unless they are waived in a future action using one or more of the 
available waiver authorities in CAA section 211(o)(7).
2. Applicable Percentage Standards for 2023-2025
    For years after 2022,\9\ the CAA gives EPA authority to establish 
percentage standards for several years simultaneously and at the same 
time that it establishes the volume targets for those years. Consistent 
with the proposed rule, we are finalizing the percentage standards for 
2023, 2024, and 2025. The percentage standards corresponding to the 
volume requirements from Table I.A.1-1 are shown below.
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    \9\ 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. CAA section 211(o)(3).

[[Page 44471]]

                                       Table I.A.2-1--Percentage Standards
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                                                                     2023  (%)       2024  (%)       2025  (%)
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Cellulosic biofuel..............................................            0.48            0.63            0.81
Biomass-based diesel............................................            2.58            2.82            3.15
Advanced biofuel................................................            3.39            3.79            4.31
Renewable fuel..................................................           11.96           12.50           13.13
Supplemental standard...........................................            0.14             n/a             n/a
----------------------------------------------------------------------------------------------------------------

    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 under CAA section 
211(o)(9). For this rulemaking, we have projected that there are not 
likely to be small refinery exemptions (SREs) for 2023-2025 based on 
the information available at the present time. 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 are added to the regulations at 40 
CFR 80.1405(a).
3. Carryover RINs and Gasoline and Diesel Projections
    EPA assesses the availability of carryover RINs in determining the 
volumes under our set authority. Carryover RINs provide important 
benefits to the RFS program, including compliance flexibility to 
individual obligated parties, liquidity to the RIN market, and 
mitigation against market impacts that could occur if RIN generation in 
any year exceeds or falls short of the required volume of renewable 
fuel.
    In establishing RFS volume requirements for 2020 and 2021 that were 
equal to the number of RINs generated in those years, EPA intended that 
compliance with the renewable volume obligations would not impact the 
total number of available carryover RINs. Since that time, obligated 
parties have submitted compliance reports for the 2020 and 2021 
compliance years. These reports revealed that there exist significant 
differences between the volume of obligated fuel reported by obligated 
parties, on the one hand, and the volumes of gasoline and diesel from 
EIA that EPA used to calculate the percentage standards for 2020 and 
2021 on the other. Higher-than-expected volumes of obligated fuel in 
2020 and 2021 meant that the number of RINs that must be retired for 
these compliance years was higher than EPA anticipated. As discussed in 
greater detail in Section III.C.4 and RIA Chapter 1.10, compliance with 
these obligations has required the use of significant quantities of 
carryover RINs, resulting in effectively no available carryover RINs 
for several renewable fuel categories going into the 2022 compliance 
year. In an effort to better project the volume of obligated fuel in 
future years, we are adjusting how we project the obligated volume of 
gasoline and diesel in 2023-2025. These changes are discussed further 
in Section VII.A and RIA Chapter 1.11.
4. Regulatory Provisions for eRINs
    The 2023-2025 proposed rule included a comprehensive program 
governing the generation of RINs from renewable electricity produced 
from biogas that is used in electric vehicles. The proposed ``eRIN'' 
regulations laid out a comprehensive approach to eRIN generation and 
program implementation, and included details on multiple design 
elements, including the entities that would be eligible to generate 
eRINs, approaches to ensure the prevention of double-counting of such 
RINs, and data requirements for valid eRIN generation. In addition to 
the proposed eRIN program, the December 2022 proposal also described 
several alternative approaches to how such a program could be 
established and implemented.
    In response to the proposal, we received a wide variety of comments 
on all aspects of the proposed eRIN program. Stakeholder positions on 
the proposed eRIN provisions varied greatly, with some stakeholders 
strongly supportive of EPA finalizing the proposed provisions, some who 
sought significant modifications to the program while remaining broadly 
supportive of eRINs conceptually, and others who opposed, for a variety 
of reasons, EPA moving forward to finalize a new eRIN framework. In 
light of the significant number of comments provided by stakeholders on 
EPA's proposed eRIN approach, and the complexity of many of the topics 
raised in those comments, and the consent decree deadline on other 
portions of the rule, we are not finalizing the proposed revisions to 
the eRIN program at this time. We have adjusted the final volume 
requirements for this rulemaking to reflect this decision.
    The large number of comments EPA received on our proposed eRIN 
language, representing a range of perspectives, is a clear signal that 
stakeholders care a great deal about a potential eRIN program. As 
discussed in the proposed rule, EPA's policy goal in developing an eRIN 
program would be to support one of the objectives of the RFS program, 
which is to increase the use of renewable transportation fuels, in 
particular cellulosic biofuels, over time, consistent with the 
statute's focus on growth in this category. Moreover, an eRIN program 
would support Congress' goals of reducing GHGs and increasing energy 
security,\10\ both of which can be affected by the design of that 
program. We anticipate that an eRIN program may also have the ancillary 
effect of incentivizing increased electrification of the vehicle fleet.
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    \10\ Congress stated that the purposes of EISA, in which the 
RFS2 program was enacted, included ``[t]o move the United States 
toward greater energy independence and security, to increase the 
production of clean renewable fuels, to protect consumers, to 
increase the efficiency of products, building, and vehicles, to 
promote research on and deploy greenhouse gas capture and storage 
options, and to improve the energy performance of the Federal 
Government, and for other purposes.'' Public Law 110-140 (2007). See 
also, CAA 211(o)(1) (definitions of qualifying biofuel include 
requirement that they reduce greenhouse gas emissions by specified 
amounts relative to a petroleum baseline).
---------------------------------------------------------------------------

    Given strong stakeholder interest in the proposed eRIN program and 
the range of potential benefits that the program could provide, EPA 
will continue to work on potential paths forward for the eRIN program. 
To that end, EPA will continue to assess the comments received on the 
proposal. EPA will also seek additional input from stakeholders to 
inform potential next steps.

[[Page 44472]]

5. Other Regulatory Changes
    We also proposed regulatory changes in several areas to strengthen 
EPA's implementation of the RFS program. Stakeholders provided valuable 
comment on these proposed modifications, and EPA is finalizing many of 
the proposed changes with modifications based on that stakeholder 
input. The regulatory changes we are finalizing in this rulemaking 
include:
     Modification of the regulatory provisions for biogas-
derived renewable fuels to ensure that biogas is produced from 
renewable biomass and used as a transportation fuel and to allow for 
the use of biogas as a biointermediate.
     Enhancements to the third-party oversight provisions 
including engineering reviews, the RFS quality assurance program, and 
annual attest engagements.
     Establishing a deadline for third-party engineering 
reviews for three-year registration updates.
     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.
     Revising the conversion factor in the formula for 
calculating the percentage standard for BBD to reflect increasing 
production volumes of renewable diesel.
     Flexibility for RIN generation.
     Reiterating the prohibition on generating RINs for fuels 
not used in the covered location.
     Flexibilities for the generation and maintenance of 
records for waste feedstocks.
     Clarifying the definition of fuel used in ocean-going 
vessels.
     Modifications to the bonding requirements for foreign 
parties that participate in the RFS program.
     Other minor changes and technical corrections.
    Each of these regulatory changes is discussed in greater detail in 
Section X.
    We proposed but are not finalizing at this time the following 
regulatory changes:
     A definition of produced from renewable biomass (discussed 
more in Section X.K).
     The proposed changes to the requirements for the 
separation of RINs.\11\
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    \11\ See 87 FR 80707 (December 30, 2022).
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    We need more time to consider the public comments received on these 
proposed changes.

B. Environmental Justice

    In considering environmental justice in this action, we have sought 
to identify and address, 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 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.12 13 The manner in which the market 
responds to the provisions in this rule could also have non-GHG 
impacts. For instance, replacing petroleum fuels with renewable fuels 
will also have potential impacts on water and air exposure for 
communities living near biofuel and petroleum facilities given the 
potential for biofuel facilities to have increased emissions of certain 
criteria pollutants in local communities, resulting in a potential 
corresponding decrease in exposure for local communities surrounding 
petroleum facilities with less petroleum production. 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. We received extensive comment, 
primarily on the proposed eRIN provisions, from community-based and 
environmental justice stakeholders expressing concern over the use of 
biogas, particularly from landfills and concentrated animal feeding 
operations, in the RFS. While EPA is not finalizing eRIN provisions as 
part of this rule, we will continue to engage with stakeholders on 
impacts of the RFS program related to biogas use and expansion. Our 
assessment of potential economic impacts on communities with 
environmental justice concerns is provided in Section IV.E.3.
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    \12\ 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.
    \13\ 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. http://dx.doi.org/10.7930/J0R49NQX.
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C. Impacts of This Rule

    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 
Regulatory Impact Analysis (RIA) accompanying this rule. Congress 
provided EPA flexibility by enumerating factors to consider without 
rigidly mandating the specific steps of analysis that EPA should take 
or how EPA should weigh the various factors. For two of these statutory 
factors--costs and energy security--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 nevertheless cannot be easily 
monetized. Thus, we are unable to quantitatively compare all of the 
evaluated impacts of this rulemaking. Regardless of whether we 
monetized a factor or not, however, EPA did consider all statutory 
factors in this rulemaking, and we find that the final volumes are 
appropriate under the set authority when we balance all the relevant 
factors. Table ES-1 in the RIA provides a list of all of the impacts 
that we assessed, both quantitative and qualitative. Our assessments of 
each factor, including the impacts on costs, energy security, climate, 
and other environmental and economic factors, are summarized in Section 
IV of this document. Additional detail for each of the assessed factors 
is provided in RIA Chapters 4 through 10.
    Monetized impacts on cost and energy security are summarized in 
Table I.C-1 below using two discount rates (3 percent and 7 percent) 
following federal guidance on regulatory impact analyses.\14\ 
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.
---------------------------------------------------------------------------

    \14\ Office of Management and Budget (OMB) Circular A-4. Sept. 
17, 2003.

[[Page 44473]]

    Table I.C-1--Cumulative Monetized Fuel Costs and Energy Security
   Benefits of 2023-2025 Standards With Respect to the No RFS Baseline
                            [2022$, millions]
------------------------------------------------------------------------
                                                   Discount rate
                                         -------------------------------
                                                3%              7%
------------------------------------------------------------------------
Excluding Supplemental Standard:
    Fuel Costs..........................         $23,218         $22,366
    Energy Security Benefits............             524             505
Including 2023 Supplemental Standard:
    Fuel Costs..........................          23,846          22,994
    Energy Security Benefits............             536             517
------------------------------------------------------------------------

D. Policy Considerations

    This rule comes at a time when substantial policy developments and 
global events are affecting the transportation energy and environmental 
landscape in unprecedented ways. The 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 an important policy consideration. 
The war in Ukraine has significantly destabilized multiple global 
commodity markets, including petroleum markets, and continues to have 
impacts in these areas. 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 establishing RFS volume 
requirements for the next three years in this action. The volumes that 
EPA is finalizing continue to support ongoing growth in renewable 
fuels, recognizing their benefits, and based on EPA's consideration of 
the multiple factors identified in the statute. Beyond providing 
continued support for fuels like ethanol and biodiesel, this action 
provides a strong market signal for the continued growth of low carbon 
advanced biofuels, including ``drop-in'' renewable diesel, and 
cellulosic biofuels. Renewable fuels are a key policy tool identified 
by Congress for decarbonizing the transportation sector, and this 
rulemaking sets the stage for further growth and development of low-
carbon biofuels in the coming years.
    In the proposed rule EPA requested comment on multiple volume 
scenarios, including limiting the implied volume of conventional 
renewable fuel to 15.0 billion gallons in 2024 and 2025, and 
establishing RFS volumes with an implied volume of conventional 
renewable fuel at or below the E10 blendwall. The volumes we are 
finalizing in this rule reflect the scenario on which we requested 
comment wherein we are limiting the implied volume of conventional 
renewable fuel to 15.0 billion gallons in 2024 and 2025. We have also 
included an analysis of the projected impact of the other alternative 
scenarios in RIA Chapter 10.6.
    In the proposal EPA also sought public comment on not only the 
elements of the proposed rule, but also asked for responses to 
questions on various topics that intersect with the larger energy 
transition and energy security issues discussed above. For example, 
several commenters provided responses on the topic of whether and how 
EPA should consider incorporating some measure of carbon intensity into 
the RFS program. Many of the commenters who weighed in on this topic 
pointed to various non-federal ``clean fuel programs'' that are being 
implemented in different states and jurisdictions and urged EPA to 
consider changes that would make the RFS program more closely resemble 
those programs. Other commenters suggested that the RFS program does 
not lend itself well to such changes and that an entirely new framework 
would be preferable if EPA were to pursue such carbon intensity-related 
changes. Many different stakeholders provided suggestions and 
perspectives on lifecycle analysis tools and approaches, and these 
comments helped inform the discussion and analysis in this rulemaking 
package related to the assessment of environmental impacts of renewable 
fuels.
    Multiple commenters also provided input on what RFS-related 
policies EPA could pursue to incorporate new pathways and technologies 
into the program. For example, some commenters urged EPA to take steps 
to integrate carbon capture and storage (CCS) opportunities related to 
the production of biofuels into the RFS program, while other commenters 
cited various reasons why EPA should refrain from taking such steps. 
Similarly, EPA received comment from different stakeholders that took 
various positions on whether and how hydrogen should be integrated into 
the RFS program. Many stakeholders also shared their perspectives on 
how the RFS program can and should be used to further support the 
development of sustainable aviation fuels (SAF).
    EPA appreciates commenters' input on these other policy topics 
raised in the proposal. We will continue to engage stakeholders on the 
topics we raised in the December 2022 proposal and welcome continued 
input on RFS policy options and opportunities. These

[[Page 44474]]

comments will be used to inform future rulemaking decisions.
    EPA also recognizes the concerns that diverse stakeholders have 
shared about the potential impacts from implementation of the RFS 
program. Stakeholders have also shared concerns about RIN market 
dynamics, including RIN price volatility. EPA understands that 
maintaining and strengthening energy security in the near term remains 
a policy imperative. The war in Ukraine continues to affect multiple 
global commodity markets and reductions in global 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 the RFS has 
played an important role in incentivizing the production of low-carbon 
alternatives. At the same time, EPA recognizes that maintaining stable 
fuel supplies and refining assets continues to be important to 
achieving our nation's energy and economic goals and retaining a 
skilled and necessary workforce.
    Given these factors, and because we are starting a new phase of the 
RFS program where Congress has not prescribed volumes and with 
prospective standards covering three years, careful administration of 
the RFS program and monitoring of its impacts is critical. EPA intends 
to use all available data and tools to monitor the implementation of 
the RFS program and its impacts. EPA is committed to successful 
implementation of the program, and the Clean Air Act provides EPA the 
tools to adjust course if appropriate. EPA will monitor a set of 
indicators that will help us assess the impact from implementation of 
the final Set rule volumes to determine whether EPA should consider 
adjusting those volumes or taking other action. These indicators could 
include, but are not limited to, the following:
     The prices of biofuels relative to the petroleum-based 
fuels they displace;
     The cost to consumers of transportation fuel;
     The prices of biofuel feedstocks and their impacts on food 
prices to consumers;
     Changes in domestic energy supply that affect domestic 
energy security;
     Changes in domestic energy demand that negatively impact 
the energy security of a State, region, or the U.S.;
     The stability of fuel supplies and domestic refining 
assets;
     The potential for RIN deficits and noncompliance by 
obligated parties;
     Signs of market manipulation in RIN markets;
     RIN prices, generally, as an indicator of how the RFS 
program is functioning, including significant increases in RIN prices;
     Various other impacts of the RFS standards, as 
appropriate.
    In addition to these indicators, EPA will also monitor the 
volatility in D6 (``conventional'') RIN prices. Specifically, as part 
of our oversight of program implementation, EPA intends to consider 
whether the following volatility measure is met:
     A 50% deviation in the monthly average D6 RIN price, 
relative to the 6-month rolling average D6 RIN price, evaluated at the 
end of the calendar month and based on EPA data or third-party data, as 
EPA determines appropriate. EPA would also consider whether changes in 
RFS standards, other related EPA actions, or court decisions have 
occurred which affect the relevance of this measure at a particular 
time.
    Based on EPA's assessment of these indicators, the Administrator 
may then consider using the statutory authorities available under the 
Clean Air Act to adjust the volume standards or make other programmatic 
changes. For example, EPA has authority to reconsider its volumes and 
standards, and has shown its willingness to do so when extreme and 
unforeseen events require it, such as revising the 2020 and 2021 
volumes to account for changes due to the COVID-19 pandemic. For years 
after 2022, CAA section 211(o)(2)(B)(ii) establishes the processes, 
criteria, and standards for setting the applicable annual renewable 
fuel volumes. That provision provides that the Administrator shall, in 
coordination with the Secretary of Energy and the Secretary of 
Agriculture and after public notice and opportunity for comment, 
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 multiple factors, as described in Section II.B of this 
action.\15\ Those factors include, for example, the impact of the use 
of renewable fuels on the cost to consumers of transportation, and 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. As EPA has stated in previous 
actions, we generally do not think it is appropriate to reconsider and 
revise previously finalized RFS standards. Revising standards has the 
potential to decrease market certainty and create unnecessary market 
disruption (which could in turn exacerbate some of the indicators 
listed above). At the same time, given the new phase of the program, we 
want to reiterate our commitment to monitoring various measures to 
ensure successful program implementation and consider adjusting course 
if appropriate.
---------------------------------------------------------------------------

    \15\ EPA may consider using an expedited process if EPA 
determines such process is appropriate and consistent with statutory 
authority.
---------------------------------------------------------------------------

    Apart from EPA's authority to reconsider our RFS standards, CAA 
section 211(o)(7)(A) provides the Administrator the discretion to waive 
the national quantity of renewable fuel required under the RFS program, 
upon petition by one or more States, or by any party subject to the 
requirements of the RFS program. The Administrator may also waive the 
volume requirements on his own motion. The Administrator may do so only 
after consultation with the Secretary of Agriculture and the Secretary 
of Energy and after public notice and opportunity for comment.\16\ A 
waiver may be issued if the Administrator determines that 
implementation of the RFS volume requirements would severely harm the 
economy or environment of a State, region, or the United States, or 
that there is an inadequate domestic supply. EPA has previously 
interpreted this waiver authority in prior responses to requests for a 
waiver of the RFS volume requirements \17\ and in annual 
rulemakings.\18\ EPA will monitor as appropriate the criteria we have 
laid out previously in order to determine whether we should adjust 
volume requirements using existing waiver authority under the statute. 
These criteria, for example, include whether, under the severe economic 
harm waiver authority, the harm is occurring with a high degree of 
certainty, the harm is severe, and whether the harm is to an entire 
state, region, or the United States.
---------------------------------------------------------------------------

    \16\ EPA may consider using an expedited process if EPA 
determines such process is appropriate and consistent with the 
statutory waiver authority.
    \17\ See 73 FR 47168 (August 13, 2008) and 77 FR 70752 (November 
27, 2012).
    \18\ See, e.g., Renewable Fuel Standard Program--Standards for 
2020 and Biomass-Based Diesel Volume for 2021 and Other Changes: 
Response to Comments, EPA-420-R-19-018; see also American Fuel & 
Petrochemical Manufacturers v. EPA, 937 F.3d 559, 580 (D.C. Cir. 
2019) (upholding EPA's interpretation of the severe economic harm 
waiver authority in the 2018 RFS rulemaking).
---------------------------------------------------------------------------

    In addition to monitoring the program's implementation for the

[[Page 44475]]

potential need to adjust the standards, EPA will also strengthen 
existing efforts, and work to develop new tools, to help us monitor and 
oversee the RIN market. EPA welcomes ideas from stakeholders impacted 
by the RFS program on how to improve market oversight capabilities, 
including ideas on how EPA's compliance regulations could be enhanced.
    EPA closely monitors the RIN market, and we take seriously claims 
of RIN market manipulation. In March 2016, EPA entered into a 
Memorandum of Understanding (MOU) with the Commodity Futures Trading 
Commission (CFTC).\19\ This MOU allows EPA to share RIN transaction 
data with CFTC to advise EPA on the techniques used to minimize market 
manipulation, to increase CFTC's understanding of the RIN market, and 
to conduct oversight for this market. Under the MOU, EPA has met with 
CFTC to discuss RIN market data and to evaluate strategies to identify 
and reduce the potential for manipulation in the RFS program.
---------------------------------------------------------------------------

    \19\ See ``Memorandum of Understanding Between the Environmental 
Protection Agency and the Commodity Futures Trading Commission on 
the Sharing of Information Available to EPA Related to the 
Functioning of Renewable Fuel and Related Markets'' (2016), 
available at https://www.epa.gov/sites/production/files/2016-03/documents/epa-cftc-mou-2016-03-16.pdf.
---------------------------------------------------------------------------

    In June 2019, EPA modified certain elements of the RFS compliance 
system, in order to improve functioning of the RIN market and prevent 
any potential manipulation in the RFS compliance market.\20\ The 2019 
rulemaking requires reporting of RIN holdings above a threshold to help 
ensure no single party can manipulate the price of RINs through the 
sheer size of their holdings.\21\ Underpinning that reform was the 
observation that increased transparency would help deter market 
participants from amassing an excess of separated RINs, which due to 
the concentration in ownership could result in undue influence or 
market power. Since EPA implemented these provisions, no company has 
had RIN holdings which have exceeded the thresholds set in the rule.
---------------------------------------------------------------------------

    \20\ See 84 FR 27013-27019.
    \21\ See 40 CFR 80.1435.
---------------------------------------------------------------------------

    The 2019 rulemaking also required reporting of RIN transaction 
prices to EPA.\22\ EPA has utilized the new reported price data to 
supplement third-party RIN price assessment data. EPA has also 
increased transparency by aggregating the reporting price data and 
making it publicly available on our website.\23\ We believe that 
publishing as much data and information on the RIN market as possible, 
while still protecting confidential business information, improves 
market transparency and helps obligated parties and other market 
participants make informed decisions. Since the June 2019 rule, we have 
not seen data-based evidence of RIN market manipulation. The potential 
for such behavior, however, remains a concern.
---------------------------------------------------------------------------

    \22\ See 40 CFR 80.1451(c)(2).
    \23\ See ``RIN Trades and Price Information,'' available at 
https://www.epa.gov/fuels-registration-reporting-and-compliance-help/rin-trades-and-price-information.
---------------------------------------------------------------------------

    We have recently further expanded our oversight and enforcement 
capabilities by entering into an MOU with California Air Resources 
Board (CARB).\24\ This MOU expands our oversight capabilities and 
supports our enforcement activities by leveraging information collected 
under California's Low Carbon Fuel Standard to help identify non-
compliance and potential market manipulation in the renewable fuels and 
RIN markets. EPA and CARB compliance staff meet regularly to analyze 
market forces and participant behavior to ensure that our program meets 
the CAA requirements.
---------------------------------------------------------------------------

    \24\ See ``Confidentiality Agreement Between the United States 
Environmental Protection Agency Offices of Transportation and Air 
Quality and Civil Enforcement and the California Air Resources Board 
for the Sharing of Information.'' August 17, 2021 (on file with 
EPA).
---------------------------------------------------------------------------

    As we begin to implement the Set Rule volumes, EPA will work with 
partners in federal and state governments to assess what new 
improvements and modifications could reasonably be made that would 
further strengthen market oversight and program implementation. 
Furthermore, within 45 days of publication of the final 2023-2025 rule, 
EPA will meet with CFTC to review our MOU with CFTC and the sufficiency 
of the existing RIN data collection to address potential market 
manipulation. EPA will also discuss with CFTC whether the existing MOU 
should be revised to allow for the monitoring of daily trades and 
whether the existing MOU should be revised to include additional market 
oversight experts, such as the Federal Trade Commission.

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, in consultation 
with the U.S. Fish and Wildlife Service (USFWS) and/or the National 
Marine Fisheries Service (NMFS) (collectively ``the Services''), ensure 
that any action authorized, funded, or carried out by the action agency 
is not likely to jeopardize the continued existence of any endangered 
or threatened species or result in the destruction or adverse 
modification of designated critical habitat for such species. Under ESA 
implementing regulations, the action agency is required to formally 
consult with the Services for actions that ``may affect'' listed 
species or designated critical habitat, unless the Services concur in 
writing that the action is not likely to adversely affect ESA-listed 
species or 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 ESA 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 
engaged in technical assistance and informal consultation discussions 
with the Services regarding this rule. On January 30, 2023, EPA 
submitted its initial biological evaluation to the Services, and 
following continued informal consultation--including regular meetings 
and telephone and email communications between EPA and the Services--on 
May 20, 2023, EPA submitted to the Services its May 19, 2023 biological 
evaluation. On May 31, 2023, EPA provided an addendum to the May 19, 
2023 biological evaluation in response to a request from NMFS.\25\ EPA 
has determined that this action is not likely to adversely affect 
listed species and critical habitat. The Services have confirmed that 
EPA's biological evaluation with the May 31, 2023 addendum is 
sufficient and USFWS and NMFS intend to proceed with informal 
consultation. EPA has prepared an ESA section 7(d) determination 
memorandum that discusses our decision to finalize this action before 
the informal consultation process is complete, which is also available 
in the docket for this action.
---------------------------------------------------------------------------

    \25\ ``Biological Evaluation of the Renewable Fuel Standard 
(RFS) Set Rule,'' May 19, 2023, and email from T. Phillips, EPA, to 
D. Baldwin, NOAA (May 31, 2023) are both available in the docket for 
this action.
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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

[[Page 44476]]

the Act in Section 211(o)(2).\26\ For total 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 BBD, the CAA only provides volume targets 
through 2012; EPA has been setting the biomass-based diesel volume 
requirements in annual rulemakings since 2013.
---------------------------------------------------------------------------

    \26\ We refer to CAA section 211(o)(2)(B)(ii) as the ``set 
authority.''
---------------------------------------------------------------------------

    This section discusses EPA's statutory authority and additional 
factors we have considered due to the lateness of this rulemaking, as 
well as the severability of the various portions of this rule.

B. Factors That Must Be Analyzed

    CAA section 211(o)(2)(B)(ii) establishes the processes, criteria, 
and standards for setting the applicable annual renewable fuel volumes. 
That provision provides that the Administrator shall, in coordination 
with the Secretary of Energy and the Secretary of Agriculture,\27\ 
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:
---------------------------------------------------------------------------

    \27\ In furtherance of this requirement, we have had periodic 
discussions with DOE and USDA on this action. These have occurred 
with agency staff throughout the proposal and final rule process, as 
well as through the OMB interagency process. An additional 
memorandum documenting discussions with the Administrator and 
Secretaries is also available in the docket for this action.
---------------------------------------------------------------------------

     The impact of the production and use of renewable fuels on 
the environment; \28\
---------------------------------------------------------------------------

    \28\ CAA section 211(o)(2)(B)(ii)(I).
---------------------------------------------------------------------------

     The impact of renewable fuels on the energy security of 
the U.S.; \29\
---------------------------------------------------------------------------

    \29\ CAA section 211(o)(2)(B)(ii)(II).
---------------------------------------------------------------------------

     The expected annual rate of future commercial production 
of renewable fuels; \30\
---------------------------------------------------------------------------

    \30\ CAA section 211(o)(2)(B)(ii)(III).
---------------------------------------------------------------------------

     The impact of renewable fuels on the infrastructure of the 
U.S.; \31\
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    \31\ CAA section 211(o)(2)(B)(ii)(IV).
---------------------------------------------------------------------------

     The impact of the use of renewable fuels on the cost to 
consumers of transportation fuel and on the cost to transport goods; 
\32\ and
---------------------------------------------------------------------------

    \32\ CAA section 211(o)(2)(B)(ii)(V).
---------------------------------------------------------------------------

     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.\33\
---------------------------------------------------------------------------

    \33\ CAA section 211(o)(2)(B)(ii)(VI).
---------------------------------------------------------------------------

    Congress provided EPA flexibility by enumerating factors to 
consider without rigidly mandating the specific steps of analysis that 
EPA should take or 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.'' \34\ These factors 
were analyzed in the context of the 2020-2022 standard-setting rule 
that modified volumes under CAA section 211(o)(7)(F),\35\ which 
requires EPA to comply with the processes, criteria, and standards in 
CAA section 211(o)(2)(B)(ii). Consistent with our past practice in 
evaluating the factors,\36\ we have again determined that a holistic 
balancing of the factors is appropriate.\37\
---------------------------------------------------------------------------

    \34\ 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 (2d Cir. 2004) 
(same); BP Exploration & Oil, Inc. v. EPA, 66 F.3d 784, 802 (6th 
Cir. 1995) (same); see also Brown v. Watt, 668 F.3d 1290, 1317 (D.C. 
Cir. 1981) (``A balancing of factors is not the same as treating all 
factors equally. The obligation instead is to look at all factors 
and then balance the results. The Act does not mandate any 
particular balance, but vests the Secretary with discretion to weigh 
the elements . . . .'') (addressing factors articulated in the Out 
Continental Shelf Lands Act).
    \35\ See 87 FR 39600 (July 1, 2022).
    \36\ See 87 FR 39600, 39607-08 (July 1, 2022).
    \37\ RFS Annual Rules Response to Comments Document at 10.
---------------------------------------------------------------------------

    In addition to those factors listed in the statute, the statute 
also directs EPA to consider ``the impact of the use of renewable fuels 
on other factors.'' \38\ Moreover, many other factors affect the 
statutory factors themselves. Accordingly, consistent with the statute, 
we have considered several other factors, including:
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    \38\ CAA section 211(o)(2)(B)(ii)(VI).
---------------------------------------------------------------------------

     The interaction between volume requirements for years 
2023-2025, including the nested nature of those volume requirements and 
the availability of carryover RINs.\39\
---------------------------------------------------------------------------

    \39\ This also informs our analysis of the statutory factor 
``review of the implementation of the program.'' CAA section 
211(o)(2)(B)(ii).
---------------------------------------------------------------------------

     The ability of the market to respond given the timing of 
this rulemaking.\40\
---------------------------------------------------------------------------

    \40\ This also informs our analysis of the statutory factor 
``the expected annual rate of future commercial production of 
renewable fuels.'' CAA section 211(o)(2)(B)(ii)(III).
---------------------------------------------------------------------------

     Our obligation to respond to the ACE remand (Section V).
     The supply of qualifying renewable fuels to U.S. consumers 
(Section III.A.5).\41\
---------------------------------------------------------------------------

    \41\ This is based on our analysis of the statutory factor the 
expected annual rate of future commercial production of renewable 
fuel as well as of downstream constraints on biofuel use, including 
the statutory factors relating to infrastructure and costs.
---------------------------------------------------------------------------

     Soil quality (RIA Chapter 3.4).\42\
---------------------------------------------------------------------------

    \42\ Soil quality is closely tied to water quality and is also 
relevant to the impact of renewable fuels on the environment more 
generally, such that this analysis also informs our analysis of the 
statutory factor ``the impact of the production and use of renewable 
fuels on the environment.'' CAA section 211(o)(2)(B)(ii)(I).
---------------------------------------------------------------------------

     Environmental justice (Section IV.E and RIA Chapter 
8).\43\
---------------------------------------------------------------------------

    \43\ 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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     A comparison of costs and benefits (Section IV.D).\44\
---------------------------------------------------------------------------

    \44\ The comparison of costs and benefits compares our 
quantitative analysis of various statutory factors, including costs 
and energy security.
---------------------------------------------------------------------------

C. Statutory Conditions on Volume Requirements

    As indicated above, the CAA affords EPA flexibility to consider 
each of the enumerated factors and the weight to give those factors. 
However, the CAA does contain three conditions that affect our 
determination of the applicable volume requirements:
     A constraint in setting the applicable volume of total 
renewable fuel as compared to advanced biofuel, with implications for 
the implied volume requirement for conventional renewable fuel.
     Direction in setting the cellulosic biofuel applicable 
volume regarding potential future waivers.
     A floor on the applicable volume of BBD.
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 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,'' \45\ 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 implied volume of 
conventional renewable fuel within the

[[Page 44477]]

total renewable fuel volume for years after 2022.
---------------------------------------------------------------------------

    \45\ CAA section 211(o)(2)(B)(iii).
---------------------------------------------------------------------------

    The applicable advanced biofuel volume requirement is 5.63 billion 
gallons for 2022.\46\ 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 finalizing 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 finalizing satisfy this 
statutory criterion.
---------------------------------------------------------------------------

    \46\ 87 FR 39601.
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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.\47\ 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).\48\ CAA section 211(o)(7)(D) provides that if 
``the projected volume of cellulosic biofuel production is less than 
the minimum applicable volume established under paragraph (2)(B),'' EPA 
``shall reduce the applicable volume of cellulosic biofuel required 
under paragraph (2)(B) to the projected volume available during that 
calendar year.'' Therefore, we are setting the volume requirements such 
that the mandatory waiver of the cellulosic volume is not anticipated 
to be triggered in those future years. Operating within this 
limitation, and in light of our consideration of the statutory factors 
explained in Section VI, we are setting 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.\49\ These projections, discussed further in 
Sections III.B.1 and VI.A, represent our best efforts to project the 
growth in the volume of these fuels that can be achieved in 2023-2025.
---------------------------------------------------------------------------

    \47\ CAA section 211(o)(2)(B)(iv).
    \48\ 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).
    \49\ See, e.g., 2020-2022 Rule, 87 FR 39600 (July 1, 2022).
---------------------------------------------------------------------------

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.\50\ EPA is setting 
the BBD volume requirement for 2023, 2024, and 2025 at 2.82, 3.04, and 
3.35 billion gallons respectively. These volumes are significantly 
greater than 1.0 billion gallon minimum requirement for these years.
---------------------------------------------------------------------------

    \50\ CAA Section 211(o)(2)(B)(iv).
---------------------------------------------------------------------------

D. Authority To Establish Volumes and Percentage Standards for Multiple 
Future Years

    EPA is finalizing volume and percentage standards for 2023, 2024, 
and 2025 in this single action. In the proposed rule, we sought comment 
on volume requirements for 2026, and proposed volumes for 2023, 2024, 
and 2025. We also proposed corresponding percentage standards for 2023, 
2024, and 2025.
    In the proposal, we discussed how the number of years for which we 
might establish standards, and thus the numbers of years for which we 
must analyze the impacts of those standards, represented a tension 
between providing certainty for stakeholders of future demand and being 
able to project renewable fuel supply with reasonable certainty. We 
discussed how 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) as an attempt to find a balance between these 
opposing concerns. Additionally, we have considered the statutory 
deadlines from promulgating applicable volumes, two of which have 
already passed (October 31, 2021, for 2023 applicable volumes, and 
October 31, 2022, for 2024 applicable volumes). The statutory deadline 
for promulgating the 2025 applicable volumes is later this year on 
October 31, 2023. Establishing volume requirements for three years 
strikes an appropriate balance between these opposing concerns.
    We acknowledge that establishing volume targets and the associated 
percentage standards for a greater number of years would increase 
market certainty for obligated parties, biofuel producers, and other 
RIN market participants. 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 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.
    Promulgating standards for three years in a single action also 
increases the likelihood that we can meet the statutory deadline to 
promulgate applicable volumes by 14 months prior to the beginning of 
the calendar year. In this action, we are promulgating the 2025 volumes 
ahead of the statutory deadline of October 2023. Given the extensive 
analysis required to support the volumes, and the associated length of 
time necessary for CAA rulemaking actions, promulgating standards for 
multiple years facilitates compliance with the statutory requirements.
    Many of the comments we received from stakeholders supported our 
proposal to establish standards for three years. While some 
stakeholders requested that standards be set for fewer than three 
years, others requested that we set standards for more than three 
years. 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, increasing the potential that applicable 
standards might need to be waived at a later date, we continue to 
believe that three years represents an appropriate balance at this 
time. We are not making a determination in this action that three years 
is the appropriate number of years to establish standards under all 
circumstances and in all future actions. Indeed, it may be appropriate 
in future standard-setting

[[Page 44478]]

actions to establish standards for more or less than three years at a 
time.
    The CAA requires EPA to promulgate regulations that, regardless of 
the date of promulgation, contain compliance provisions applicable to 
refineries, blenders, distributors and importers that ensure that the 
volumes in CAA section 211(o)(2)(B), which includes set volumes, are 
met.\51\ As to setting percentage standards, 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.\52\ Thus, 
Congress provided EPA discretion as to how to implement the volume 
requirements of the RFS program in years 2023 and beyond.
---------------------------------------------------------------------------

    \51\ CAA section 211(o)(A)(i), (iii).
    \52\ 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.'' \53\ The next clause (ii) provides further 
requirements for the obligation described in clause (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.
---------------------------------------------------------------------------

    \53\ 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. In that case, EPA would establish 
standards for 2023 in this rulemaking, and separately set standards for 
2024 and 2025 in later actions. However, EPA has chosen to set 
percentage standards at one time for several future years (i.e., for 
2023, 2024, and 2025). Doing so increases certainty for obligated 
parties, renewable fuel producers, and RIN market participants, as both 
the applicable volume requirements and the associated percentage 
standards can be established in advance of the year in which they 
apply. This also provides 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 provides certainty as to the 
date of the compliance deadlines for 2022-2024. This action properly 
balances creating certainty for obligated parties, renewable fuel 
producers, and RIN market participants in establishing percentage 
standards and limiting the scope of uncertainty in projections of 
future gasoline and diesel consumption by setting percentage standards 
only for the next three compliance years.\54\
---------------------------------------------------------------------------

    \54\ See Growth Energy v. Env't Prot. Agency, 5 F.4th 1, 15 
(D.C. Cir. 2021) (acknowledging deference to agency's predictive 
judgments).
---------------------------------------------------------------------------

    Several commenters supported EPA's proposal to establish volumes 
and associated percentage standards for 2023-2025. Other commenters 
suggested that EPA should only promulgate percentage standards for 2023 
and 2024 because EPA could instead finalize the percentage standards 
for 2025 along with the 2026 volumes and percentage standards given the 
statutory deadline of October 31, 2024. We discuss responses to these 
comments in the RTC document.
    In this action, we are finalizing 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.

E. Considerations for Late Rulemaking

    In this rulemaking, we are finalizing applicable volume targets for 
the 2023 and 2024 compliance years that miss the statutory 
deadlines.\55\ 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 same 
provision under which we are establishing the 2023 and 2024 standards. 
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.\56\ In doing so, EPA must 
balance the burden on obligated parties of a delayed rulemaking with 
the broader goal of the RFS program to increase renewable fuel use.\57\ 
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.\58\ Most 
relevant here is EPA's action in 2015 that established the BBD volume 
requirements for 2014-2017.\59\ There, EPA missed the statutory 
deadline, 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, for all four years.\60\ The court found that 
EPA properly balanced the relevant considerations and had provided 
sufficient notice to parties in establishing the applicable volume 
requirements for 2014-2017.\61\ A commenter suggested that EPA is 
further limited on our promulgation of the 2023 and 2024 standards at 
no greater than the 2022 standards. We disagree for the reasons 
articulated in the RTC document.
---------------------------------------------------------------------------

    \55\ 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.
    \56\ 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).
    \57\ NPRA v. EPA, 630 F.3d 145, 164-65.
    \58\ ACE, 864 F.3d at 721-22.
    \59\ 80 FR 77420, 77427-28, 77430-31 (Dec. 14, 2015).
    \60\ CAA section 211(o)(2)(B)(ii).
    \61\ ACE, 864 F.3d at 721-23.
---------------------------------------------------------------------------

    In this rulemaking, we are exercising 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.\62\ 
This final rule will also be partly retroactive, as the 2023 standards 
are being finalized in the middle of the 2023 calendar year. 
Nevertheless, we believe that the 2023 standards being finalized in 
this action can be met and that the available RIN generation data from 
the first quarter of 2023 suggests the market is on track to supply the 
volumes we are finalizing for 2023 (see Section VI and RIA Chapter 6). 
We are finalizing the 2024 standards prior to

[[Page 44479]]

the beginning of the 2024 calendar year and do not expect those 
standards to apply retroactively. Additionally, we have provided 
obligated parties notice as of December 1, 2022 of the proposed 2023 
and 2024 standards, a month ahead of when the 2023 standards would 
apply, and over a year in advance of when the 2024 standards would 
apply. Additionally, obligated parties will have at least nine months 
from the time of promulgation of this final rule before they are 
required to submit associated compliance reports for 2023.\63\ There 
will additionally be approximately 22 months between the promulgation 
of this rule and the compliance deadline for the 2024 standards.\64\ 
Additionally, all obligated parties will continue to have available 
compliance flexibilities such as carry forward deficits, and carryover 
RINs to comply with the 2023 and 2024 standards.
---------------------------------------------------------------------------

    \62\ CAA section 211(o)(2)(B)(ii).
    \63\ EPA expects the 2023 compliance deadline to be March 31, 
2024. See 40 CFR 80.1451(f)(1)(A).
    \64\ The 2024 compliance deadline is March 31, 2025. 40 CFR 
80.1451(f)(1)(A).
---------------------------------------------------------------------------

    In addition, in completing its response to the ACE remand of the 
2016 annual rule, we are establishing a supplemental standard for 
2023.\65\ This supplemental standard is being promulgated after the 
statutory deadline for the 2016 standards (November 30, 2015). However, 
the supplemental standard would prospectively apply to gasoline and 
diesel produced or imported in 2023, therefore is only partly 
retroactive. We further discuss our response to the ACE remand in 
Section V.
---------------------------------------------------------------------------

    \65\ We also established a supplemental standard for 2022 in a 
prior action. See, e.g., 87 FR 39600 (July 1, 2022).
---------------------------------------------------------------------------

F. Impact on Other Waiver Authorities

    While we are establishing applicable volume requirements in this 
action for future years that are achievable and appropriate based on 
our consideration of the statutory factors, we retain our legal 
authority to waive volumes in the future under the waiver authorities 
should circumstances so warrant.\66\ For example, the general waiver 
authority under CAA section 211(o)(7)(A) provides that EPA may waive 
the volume targets in ``paragraph (2),'' which 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, similar to our exercise of the waiver authorities to 
modify the statutory volumes in past annual standard-setting 
rulemakings, EPA has the authority to modify the applicable volumes for 
2023 and beyond in future actions through the use of our waiver 
authorities to modify the applicable volumes we are setting in this 
action.
---------------------------------------------------------------------------

    \66\ 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).
---------------------------------------------------------------------------

    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, establishing 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 has 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, establishing 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, where we stated 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. \67\ Some commenters 
suggested that we should make CWCs available even in the absence of 
exercising our cellulosic waiver authority to provide a price cap on 
cellulosic volume, or to provide additional flexibility for obligated 
parties. As we do not find authority to issue cellulosic waiver credits 
without use of the cellulosic waiver authority, we will not be issuing 
CWCs absent a future waiver of the cellulosic standard. 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.
---------------------------------------------------------------------------

    \67\ 87 FR 39616 (July 1, 2022).
---------------------------------------------------------------------------

G. Severability

    As stated in the proposal, we intend for the volume requirements 
and percentage standards for each single year covered by this rule 
(i.e., 2023, 2024, and 2025) to be severable from the volume 
requirements and percentage standards for the 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 are 
not part of EPA's analysis for the volume requirements and percentage 
standards for any specific year. Further, each of the regulatory 
amendments in Sections IX and X is severable from the other regulatory 
amendments because they all function independently of one another.
    If any of the portions of the rule identified in the preceding 
paragraph (i.e., volume requirements and percentage standards for a 
single year, the 2023 supplemental standard, the individual regulatory 
amendments) is invalidated 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 invalidate the volume requirements and percentage standards and 
supplemental standard, we intend the other regulatory amendments to 
remain effective. Or, as another example, if a reviewing court 
invalidates 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.

[[Page 44480]]

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, and further requires that we review 
implementation of the program in prior years. The statutory factors are 
listed in Section II.B. Because many of those factors, particularly 
those related to economic and environmental impacts, are difficult to 
analyze in the abstract, we have therefore opted to analyze those 
factors based on specific ``candidate volumes'' for each category of 
renewable fuel. To accomplish this, we first derived a set of renewable 
fuel volumes from the statutory factors most closely related to 
renewable fuel supply and other relevant factors. The development of 
these candidate volumes helps further our consideration of the 
statutory factor to analyze the expected annual rate of future 
commercial production of renewable fuels and provide us with renewable 
fuel volumes with which to perform the remaining analyses required by 
the statute. We used these candidate volumes to conduct analyses of the 
other environmental and economic factors. Finally, we determined, based 
on the results of all of the analyses (those that went into developing 
the candidate volumes, described in this section, and the subsequent 
analyses performed using these candidate volumes, described in Sections 
IV and VI), the volume requirements that would be appropriate to 
establish. Our approach can be summarized as a three-step process:
    1. Development of candidate volumes (described in this section).
    2. Multifactor analysis based on those candidate volumes (described 
in Section IV).
    3. Determination of applicable volume requirements based on a 
consideration of all factors analyzed (described in Section VI).
    We acknowledge that we are taking a different approach to 
developing candidate volumes in this rule than we did under the reset 
authority in the 2020-2022 rule. The primary difference is that in the 
2020-2022 rule the candidate volumes for non-cellulosic advanced 
biofuel and conventional renewable fuel were generally in the implied 
statutory volumes for these fuel types in comparison to the statutory 
volumes. In this rule we are establishing volumes for 2023-2025, a time 
period for which there are no statutory targets. We therefore developed 
the candidate volumes for non-cellulosic biofuel and conventional 
biofuel based primarily on a consideration of supply-related factors, 
with a consideration of other relevant factors as noted in the 
following sections. This approach is generally consistent with the 
approach we took for developing the candidate cellulosic biofuel 
volumes in the 2020-2022 rule, as the statutory cellulosic biofuel 
volumes were far beyond the quantity of these fuels that could be 
supplied.
    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'') \68\ 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), (II), (V), and 
(VI))), 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, the 
availability of qualifying feedstocks, and other relevant factors as 
discussed in the following sections. 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. 
While we focused on supply-related factors, as discussed further in the 
following sections we also considered other information such as trends 
in statutory volumes, GHG reduction implications, and market 
expectations resulting from our proposed rule.
---------------------------------------------------------------------------

    \68\ 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, 864 
F.3d at 710. (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 primarily on 
supply-related considerations is a reasonable first step because doing 
so narrows the scope for the multifactor analysis in a commonsense way. 
This step better enables our analysis of the remaining statutory 
factors. The candidate volumes we have identified in this final rule 
are similar to, but slightly higher than the candidate volumes in the 
proposed rule. Specifically, the candidate cellulosic biofuel volumes 
are higher for all three years (after accounting for the fact that we 
are not finalizing the proposed eRIN provisions in this rule). The 
candidate volumes for non-cellulosic advanced biofuels in this final 
rule are higher than the candidate volumes from the proposed rule for 
2023-2025. Finally, the candidate volumes for conventional biofuel in 
this final rule are lower than the candidate volumes in the proposed 
rule for all three years, due to lower projected gasoline consumption. 
Section VI provides our rationale for the final volume requirements in 
light of all the analyses that we conducted.
    In this final rule we updated the candidate volumes after 
considering the comments we received on our proposed rule as well as 
additional data not available at the time the analyses for the proposed 
rule were completed. We received many comments on the supply-related 
factors that informed the candidate volumes, including comments related 
to renewable fuel production capacity, the availability of feedstocks 
to produce renewable fuel, the quantity of renewable fuel that can be 
consumed in the transportation sector, and the ability for the 
incentives provided by the RFS program to incentivize increased 
renewable fuel production and use. These comments, along with more 
recent data, led us to increase the candidate volumes for CNG/LNG 
derived from biogas, ethanol produced from corn kernel fiber, biomass-
based diesel, and other advanced biofuels projected to be produced or 
imported in 2023-2025, and corresponding increases to the candidate 
volumes for these fuel types relative to the proposal. Our 
consideration of comments on the proposed rule and additional data also 
resulted in slight decreases to the candidate volumes of conventional 
renewable fuel for 2023-2025.
    Our updated projections of projected renewable fuel production and 
imports, including a brief discussion of the

[[Page 44481]]

relevant comments and new data that informed these projections, can be 
found in Section III.B. Section III.C summarizes the candidate volumes 
we analyzed. 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. Scope of Analysis

    In Section II.D we discuss our statutory authority to establish RFS 
volumes and percentage standards for multiple years in a single rule. 
As discussed in that section, in this final rule we are establishing 
volumes and percentage standards for three years, 2023-2025. Consistent 
with this decision, Sections III.B and III.C discuss our determination 
of the candidate volumes for each year covered by this rule.

B. Production and Import of Renewable Fuel

1. Cellulosic Biofuel
    Cellulosic biofuel is defined as renewable fuel derived from any 
cellulose, hemi-cellulose, or lignin that has lifecycle greenhouse gas 
emissions that are at least 60 percent less than the baseline lifecycle 
greenhouse gas emissions.\69\ In the past several years, production of 
cellulosic biofuel has continued to increase. Cellulosic biofuel 
production reached record levels in 2022, driven by compressed natural 
gas (CNG) and liquified natural gas (LNG) derived from biogas. 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 RIA Chapter 6.1.
---------------------------------------------------------------------------

    \69\ 40 CFR 80.1401.
    [GRAPHIC] [TIFF OMITTED] TR12JY23.000
    
a. CNG/LNG Derived From Biogas
    To be eligible to generate RINs for CNG/LNG derived from biogas, 
biogas from qualifying sources first must be collected and upgraded to 
enable its use in CNG/LNG vehicles. This upgrading process involves 
removing undesirable components and contaminants from biogas. Biogas 
that has been upgraded and distributed via a closed, private 
distribution system is called ``treated biogas'' while biogas that has 
been upgraded and distributed via the natural gas commercial pipeline 
system is referred to as renewable natural gas (RNG). RNG is 
essentially indistinguishable from fossil-based natural gas and can be 
used interchangeably and transported through the same pipelines. While 
treated biogas is typically used to fuel CNG/LNG vehicles at the site 
where it is produced, RNG is injected into the natural gas commercial 
pipeline system. Once injected into the natural gas commercial pipeline 
system, RNG can be used in a variety of applications, including to fuel 
CNG/LNG vehicles, for generating electricity, for residential heating, 
and for other industrial or commercial purposes.
    In the proposed rule we projected the use of CNG/LNG produced from 
RNG \70\ in 2023-2025 using an industry-wide projection of the rate of 
growth calculated from RIN generation over the previous 24 months. 
While some commenters argued that EPA should project future production 
of CNG/LNG from RNG based on a facility-by-facility assessment, many 
supported the proposed methodology of using an industry-wide rate of 
growth to project production in future years. Many of the commenters 
who generally supported the rate of growth approach, however, requested 
that EPA use a higher rate of growth that considered data beyond just 
the most recent 24 months. These comments are discussed briefly at the 
end of this section, and in greater detail in the RTC document. In this 
final rule we are using an industry-wide rate of growth based on RIN 
generation data

[[Page 44482]]

from 2015-2022 to project the production and use of RNG as CNG/LNG. As 
discussed later in this section, we believe the growth rate calculated 
using data from 2015-2022 better reflects the potential production and 
use of RNG as CNG/LNG through 2025. This results in a significantly 
higher rate of grow in the final rule (25.0%) relative to the proposed 
rule (13.1%), and higher projected volumes of RNG use as CNG/LNG for 
each year from 2023-2025.
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    \70\ We note that as described in the biogas regulatory reform 
provisions in Section IX, we define RNG to mean biogas that has been 
upgraded to commercial pipeline quality and placed onto the natural 
gas commercial pipeline system. We also define the term ``treated 
biogas'' to refer to biogas that has undergone treatment for use as 
transportation fuel but that is not placed onto the natural gas 
commercial pipeline system (i.e., it is distributed via a closed, 
private distribution system). For purposes of this section of the 
preamble, we use the term RNG to refer collectively to treated 
biogas and RNG.
---------------------------------------------------------------------------

    In projecting the production and use of RNG used as CNG/LNG in 
2023-2025 we primarily considered two potential limiting factors. The 
first factor considered was the quantity of RNG we project will be 
produced from qualifying biogas in 2023-2025. Because biogas must be 
upgraded to enable its use in CNG/LNG vehicles, the quantity of RNG 
that we project will be produced sets a maximum for the quantity of 
biogas that can be used in vehicles as CNG/LNG. The second major factor 
we consider is the quantity of RNG that is capable of being used as 
transportation fuel in CNG/LNG vehicles. As discussed above, RNG can be 
used in many different applications and a variety of factors, including 
limitations related to the demand for CNG/LNG from vehicles, fueling 
infrastructure, and demand for RNG from other sectors can all impact 
the quantity of CNG/LNG used in vehicles. Our projection of the 
quantity of RNG used as CNG/LNG that will be produced and used in 2023-
2025 is described briefly in this section, and in greater detail in RIA 
Chapter 6.1.3.
    To project qualifying RNG production for this final rule we used an 
industry wide projection approach that is similar, though not 
identical, to the approach used to project the production of RNG used 
as CNG/LNG in previous RFS rules as well as in the proposed rule. While 
the approach we are using to project the production of CNG/LNG is 
similar to the approach used in previous years and the proposal, we are 
now using a broader range of data to calculate the growth rate used to 
project future projection. This reflects our consideration of an 
appropriate growth rate following engagement with stakeholders and 
review of both new data and commenter submissions on the proposal. More 
detail on our consideration of the appropriate rate of growth is 
provided later in this section. We have successfully used an industry 
wide projection methodology in previous years and continue to believe 
it better reflects the projected growth of the industry in light of 
potential limiting factors (which are more likely to be market based 
than technology based) than a projection based on an assessment of each 
potential RNG producer.
    To project the production of qualifying RNG we calculated a year-
over-year growth rate and applied this growth rate to the total 
production of RNG used as CNG/LNG in 2022 (the most recent year for 
which complete data are available). To calculate the year-over-year 
growth rate we considered RIN generation data for RNG used as CNG/LNG 
from 2015-2022 instead of just the most recent 24 months for the 
proposal. We believe a rate of growth based on this larger set of data 
better reflects the potential for RNG production in 2023-2025. We also 
note that this rate of growth is within the range of the growth rates 
suggested by RNG producers in the public comment period (generally 20-
30%) and closer to, though still less than, estimated RNG production 
from the Coalition for Renewable Natural Gas based on their analysis of 
new RNG facilities under construction and in development.\71\ The data 
used to calculate the projected rate of growth for RNG and the 
resulting projections of RNG production in 2023-2025 are shown in Table 
III.B.1.a-1 and Table III.B.1.a-2.
---------------------------------------------------------------------------

    \71\ Further discussion of the growth rate used to project the 
production of CNG/LNG derived from biogas, and our reasons for 
considering data beyond the most recent 24 months, can be found in 
RTC Section 3.2.2.

Table III.B.1.a-1--Generation of Cellulosic Biofuel RINs for RNG Used as
                                 CNG/LNG
                      [Ethanol-equivalent gallons]
------------------------------------------------------------------------
                                       2022 RIN
  2015 RIN generation  (million       generation        Year-over-year
              RINs)                 (million RINs)       increase  (%)
------------------------------------------------------------------------
139.9...........................              666.1                25.0
------------------------------------------------------------------------

                            Table III.B.1.a-2--Projected Generation of Qualifying RNG
                                          [Ethanol-equivalent gallons]
----------------------------------------------------------------------------------------------------------------
                                                                                 Growth rate    Volume  (million
                    Year                                 Date type                   (%)             RINs)
----------------------------------------------------------------------------------------------------------------
2022........................................  Actual.........................             N/A                665
2023........................................  Projection.....................            25.0                831
2024........................................  Projection.....................            25.0              1,039
2025........................................  Projection.....................            25.0              1,299
----------------------------------------------------------------------------------------------------------------

    We next considered how much of the qualifying RNG produced in 2023-
2025 could be used as transportation fuel in the form of CNG/LNG. While 
the volumes of RNG use as CNG/LNG in Table III.B.1.a-2. appear to be 
approaching the upper limit (estimated to be 1.4-1.75 billion ethanol-
equivalent gallons) of all CNG/LNG capable of being used as 
transportation fuel in 2023-2025 in CNG/LNG vehicles in the fleet, 
these 2023-2025 volumes are still below the total quantity of CNG/LNG 
projected to be used as transportation fuel in 2023-2025.\72\ Thus, the 
entire quantity of qualifying RNG produced in 2023-2025 could still be 
used as transportation fuel and be able to generate RINs under the RFS 
program. We therefore used the volumes in Table III.B.1.a-2 as the 
candidate volumes for RNG use as CNG/LNG in 2023-2025.
---------------------------------------------------------------------------

    \72\ See RIA Chapter 6.1.3 for a further discussion of our 
estimate of CNG/LNG used as transportation fuel in 2023-2025.
---------------------------------------------------------------------------

    We received many comments on our projected volume for RNG used as 
CNG/LNG in our proposed rule. While some commenters supported the 
proposed volumes, many stakeholders involved in

[[Page 44483]]

the production, distribution, and use of RNG as CNG/LNG stated that the 
projected volumes were too low. In particular, they stated that the 
growth in RNG use as CNG/LNG in recent years was significantly impacted 
by the COVID pandemic and did not reflect projected growth in this 
industry through 2025. Some commenters also noted significant 
investment in expanding RNG production which they claimed supported a 
much higher growth rate in the projected volume of biogas used in CNG/
LNG vehicles.\73\
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    \73\ See RTC Section 3.2.2 for a summary of these comments and a 
more detailed response.
---------------------------------------------------------------------------

    In this final rule we used a growth rate based on a longer time-
period (2015-2022) than in both our proposed rule and previous RFS 
rules. We believe the higher growth rate that results from using 
additional data better reflects the likely production of RNG use as 
CNG/LNG in 2023-2025 than using a growth rate based on the last 24 
months of data. Using data from 2015-2022 strikes a balance between 
using the most recent data available and not focusing exclusively on 
data from the last 24 months, during which the industry may still have 
been recovering from the impacts of the COVID pandemic. As noted 
earlier, the growth rate that results from using this additional data 
is supported by the public comments (which generally requested that EPA 
use growth rates that ranged from 20 to 30 percent), as well as the 
data received during the public comment period on the large number of 
RNG production facilities that are currently under construction or in 
the project development phase. Finally, we note that the limited data 
available from early 2023 suggest that 25% growth is achievable in 
2023.\74\
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    \74\ Further discussion of the growth rate used to project the 
production of CNG/LNG derived from biogas, and our reasons for 
considering data beyond the most recent 24 months, can be found in 
RTC Section 3.2.2.
---------------------------------------------------------------------------

b. 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 exception is the 
production of ethanol from corn kernel fiber (CKF), 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 making it difficult to quantify what portion of the 
ethanol they produce is from cellulosic biomass.
    In the proposed rule we noted the potential for the production of 
cellulosic ethanol from CKF in 2023-2025. We did not, however, project 
any production of ethanol from CKF in 2023-2025 beyond the few 
facilities that were currently registered as cellulosic biofuel 
producers. At the time of the proposal no facilities had yet requested 
to register as cellulosic biofuel producers using analytical methods 
consistent with recently published guidance.\75\ Since the proposal, 
however, a number of facilities have approached EPA with registration 
requests. In this final rule we are now projecting that the production 
of ethanol from CKF will increase from 7 million gallons in 2023 to 77 
million gallons in 2025. These projections, which are described further 
in the remainder of this section and in greater detail in RIA Chapter 
6.1 are based on projections of the number of facilities we expect will 
register as cellulosic biofuel producers and the expected rate of 
cellulosic biofuel production at each facility.
---------------------------------------------------------------------------

    \75\ 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).
---------------------------------------------------------------------------

    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. \76\ This guidance 
highlighted several outstanding critical technical issues that need to 
be addressed.
---------------------------------------------------------------------------

    \76\ 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).
---------------------------------------------------------------------------

    Since issuing the proposed rule EPA has continued to have 
substantive discussions with technology providers intending to use 
analytical methods consistent with the guidance document and owners of 
facilities intending to register as cellulosic biofuel producers using 
these analytical methods. The technology providers have indicated that 
using analytical methods consistent with those in the guidance document 
they can demonstrate that approximately 1.5% of the ethanol produced 
from existing corn ethanol facilities is produced from cellulosic 
biomass.
    Based on the information from the technology providers, we believe 
that 1.5% of cellulosic ethanol can generally be produced from corn 
kernel fiber at existing ethanol facilities with few, if any, 
additional processing units or process changes. We are aware that many 
ethanol facilities are working with the technology providers in order 
to register their facilities to produce cellulosic ethanol. We are 
therefore projecting volumes of ethanol from corn kernel fiber through 
2025 that include production from facilities that have not yet 
registered as cellulosic biofuel producers, but are expected to do so 
during this time period. The projected production of cellulosic ethanol 
from CKF, shown in Table III.B.1.b-1, are based on projections of when 
facilities will register as cellulosic biofuel producers under the RFS 
program and begin producing fuel. The projection methodology for 
cellulosic ethanol production from CKF used in this final rule is 
discussed further in RIA Chapter 6.1.2.

       Table III.B.1.b-1--Projected Production of Ethanol From CKF
                      [Ethanol-equivalent gallons]
------------------------------------------------------------------------
                                                        Volume  (million
                         Year                                RINs)
------------------------------------------------------------------------
2023.................................................                  7
2024.................................................                 51
2025.................................................                 77
------------------------------------------------------------------------

c. Other
    For the 2023-2025 timeframe, we expect that commercial scale 
production of cellulosic biofuel in the U.S. beyond CNG/LNG derived 
from biogas and ethanol produced from CKF will be very limited. 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 achieved consistent production of liquid cellulosic 
biofuel

[[Page 44484]]

in the U.S. or consistently exported liquid cellulosic biofuel to the 
U.S., production and import of liquid cellulosic biofuel in 2023-2025 
is highly uncertain and likely to be relatively small (see RIA Chapter 
6.1.4 for more detail on the potential production of liquid cellulosic 
biofuel through 2025). For the candidate volumes we have projected no 
production of these fuels in 2023-2025.
d. eRINs
    As noted in the Executive Summary, we are not finalizing the 
proposed revisions to the eRIN program in this rulemaking. We are 
therefore not including any volume from renewable electricty in our 
projections of the production and import of cellulosic biofuel. eRINs 
were projected to be a significant source of cellulosic biofuel in the 
proposed rule in 2024 and 2025 (representing 600 million and 1.2 
billion RINs in 2024 and 2025 respectively). Because we no longer 
included projected volumes of eRINs, our projections of the production 
and imports of total cellulosic biofuel for 2024 and 2025 in this final 
rule are lower than the proposed rule, despite the higher projections 
for RNG used in vehicles as a renewable form of CNG/LNG and ethanol 
produced from CKF in this final rule.
2. Biomass-Based Diesel
    Since 2010, when the BBD volume requirement was added to the RFS 
program, production of BBD has generally increased year-on-year. 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.
    The vast majority of fuel that qualifies as BBD is biodiesel and 
renewable diesel. Both these fuels are produced from animal fat and 
vegetable oils and are replacements for diesel fuel, however they 
differ in their production processes and chemical composition. 
Biodiesel is an oxygenated fuel that is generally produced using a 
transesterification process. Renewable diesel is a hydrocarbon fuel 
that closely resembles petroleum diesel that is generally produced by 
hydrotreating renewable feedstocks. 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., the supply of 
renewable diesel in 2022 was nearly as large as the supply of 
biodiesel, and the supply of renewable diesel is projected to exceed 
the supply of biodiesel in future years as renewable diesel production 
and imports continue to grow.
[GRAPHIC] [TIFF OMITTED] TR12JY23.001

    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).\77\ 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 
process that produces renewable diesel from waste fats, oils, and 
greases or plant oils generally

[[Page 44485]]

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 15 
million gallons per year--opportunities for increasing this category of 
advanced biofuel exist. A new tax credit for SAF, which was included in 
the Inflation Reduction Act, may result in increasing volumes of SAF 
produced from existing renewable diesel production facilities. SAF 
production from existing renewable diesel facilities would increase the 
amount of renewable fuel available for a transportation sector that may 
be otherwise particularly difficult to reduce carbon intensity; 
however, it would likely result in a decrease in renewable diesel 
production, with little or no net change in their overall production of 
RIN-generating fuels.\78\ In this rule we have not separately projected 
growth in SAF production, but we recognize that some of the projected 
growth in renewable diesel production may instead be SAF from the same 
production facilities. Other SAF production technologies and production 
facilities also being developed could enable the future production of 
SAF from new facilities and feedstocks that are not expected to impact 
renewable diesel production.
---------------------------------------------------------------------------

    \77\ According to EMTS data renewable jet fuel supply has ranged 
from 0-15 million gallons per year from 2014-2022. Jet fuel is 
eligible to generate RINs per 40 CFR 80.1426(a)(1)(iv), provided all 
other regulatory requirements are met.
    \78\ The equivalence values for renewable diesel and jet fuel 
are similar, with renewable diesel generating 1.6-1.7 RINs per 
gallon depending on the energy content of the fuel and Jet fuel 
generally generating 1.6 RINs per gallon.
---------------------------------------------------------------------------

    In addition, in April 2022 the Biden 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.
    The remainder of this section provides historical data on biodiesel 
and renewable diesel production and production capacity, briefly 
discusses potential feedstock limitations for biodiesel and renewable 
diesel production in future years, and 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. Our 
assessments of production capacity, available feedstocks, and likely 
future production of biodiesel and renewable diesel in this final rule 
reflect our consideration of the comments we received on this rule as 
well as updated data not available at the time of the proposed rule. 
Our projections of the likely future production of biodiesel and 
renewable diesel in this final rule are higher than in the proposed 
rule, particularly in 2025 due to higher projections of feedstock 
availability. Further details on these volume projections can be found 
in RIA 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 decreased slightly, to approximately 
1.6 billion gallons in 2022. 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.\79\ In August 2017, the U.S. announced tariffs on biodiesel 
imported from Argentina and Indonesia.\80\ These tariffs were 
subsequently confirmed in April 2018.\81\ Since that time no biodiesel 
has been imported from Argentina or Indonesia, and net biodiesel 
imports have been relatively small.
---------------------------------------------------------------------------

    \79\ EIA U.S. Imports by Country of Origin,https://www.eia.gov/dnav/pet/pet_move_impcus_a2_nus_EPOORDB_im0_mbbl_a.htm. According to 
EIA data, 67 percent of all biodiesel imports in 2016 and 2017 were 
from Argentina.
    \80\ 82 FR 40748 (Aug. 28, 2017).
    \81\ 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. Consistent with comments we received on the rule, we have 
updated our assessment of domestic biodiesel production capacity using 
the latest information available from EIA. Data reported by EIA shows 
that biodiesel production capacity in January 2023 was approximately 
2.05 billion gallons per year.\82\ According to EIA data biodiesel 
production capacity grew slowly from about 2.1 billion gallons in 2012 
\83\ to a peak of approximately 2.5 billion gallons in 2018.\84\ EIA 
reports that domestic biodiesel production capacity was approximately 
2.5 billion gallons as recently as October 2021.\85\ 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 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.
---------------------------------------------------------------------------

    \82\ EIA Monthly Biofuels Feedstock and Capacity Update, https://www.eia.gov/biofuels/update. Mar. 31, 2023 ().
    \83\ EIA Monthly Biodiesel Production Report. February 2013.
    \84\ EIA Monthly Biodiesel Production Report. February 2019.
    \85\ EIA Monthly Biofuels Feedstock and Capacity Update. January 
31, 2023 (https://www.eia.gov/biofuels/update).
---------------------------------------------------------------------------

b. Renewable Diesel and SAF
    Renewable diesel and SAF are currently produced using the same 
feedstocks and very similar production technologies, and in most cases 
are produced at the same production facilities. Historically, greater 
incentives have been available for renewable diesel production, which 
has caused many of these production facilities to maximize renewable 
diesel production. In the near term, we expect that any increase in SAF 
production will result in a corresponding decrease in renewable diesel 
production.\86\ In this section we have focused on renewable diesel 
production, but we acknowledge that an increasing portion of this fuel 
may be used as SAF in future years.
---------------------------------------------------------------------------

    \86\ We recognize that new technologies are being developed to 
produce SAF from a wider variety of feedstocks. Production of SAF 
using these technologies would not negatively impact renewable 
diesel production. Through 2025, however, we expect that only 
relatively modest volumes of these fuels might be produced.
---------------------------------------------------------------------------

    Renewable diesel has historically been produced and imported in 
smaller quantities than biodiesel as shown in Figure III.B.2-1. In 
recent years, however, domestic production of renewable diesel has 
increased significantly. Renewable diesel production facilities 
generally have higher capital costs and production costs relative to 
biodiesel, which likely accounts for the much higher volumes

[[Page 44486]]

of biodiesel production relative to renewable diesel production to 
date. The higher cost of renewable diesel production can largely be 
offset through the benefits of economies of scale, since renewable 
diesel facilities tend to be much larger than biodiesel production 
facilities. 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. The greater 
ability for renewable diesel to generate credits under California's 
LCFS program provides a significant advantage over biodiesel. Biodiesel 
blends in California containing 6 to 20 percent biodiesel require the 
use of an additive to comply with California's Alternative Diesel Fuels 
Regulations, making the use of higher level biodiesel blends more 
challenging in California.\87\ 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 RIA Chapter 6.2 for further 
discussion.
---------------------------------------------------------------------------

    \87\ CARB Alternative Diesel Fuels Regulations Frequently Asked 
Questions. 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.
---------------------------------------------------------------------------

    Total domestic renewable diesel production capacity has increased 
significantly in recent years from approximately 280 million gallons in 
2017 to approximately 2.9 billion gallons in January 2023.\88\ 
Additionally, a number of parties have announced plans to build new 
renewable diesel production capacity with the potential to begin 
production by the end of 2025. This new capacity includes new renewable 
diesel production facilities, expansions of existing renewable diesel 
production facilities, and the conversion of units at petroleum 
refineries to produce renewable diesel.
---------------------------------------------------------------------------

    \88\ 2017 renewable diesel capacity based on facilities 
registered in EMTS; January 2023 renewable capacity based on EIA 
March 2023 Monthly Biofuels Feedstock and Capacity Update.
---------------------------------------------------------------------------

    We received numerous comments on the proposed rule related to 
renewable diesel production capacity. These comments generally cited 
projections that renewable diesel production capacity will grow 
significantly through 2025, and many of these comments cited data and 
projections from EIA. In this final rule we have updated our projection 
of renewable diesel production capacity through 2025 based on updated 
information from EIA, consistent with these comments. As in the 
proposed rule, however, we expect that renewable diesel production 
through 2025 will be limited to a level below production capacity 
primarily due to limited feedstock availability, which is further 
discussed later in Section III.B.2.c.
    EIA currently projects that renewable diesel production capacity 
could reach nearly 6 billion gallons by 2025,\89\ though it is possible 
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.\90\ In previous years, 
domestic renewable diesel production has increased in concert with 
increases in domestic production capacity, with renewable diesel 
facilities generally operating at high utilization rates. In future 
years we expect that feedstock limitations will result in renewable 
diesel and biodiesel facilities operating below their production 
capacity. Competition for qualifying feedstocks could also result in 
reductions in biodiesel production if larger renewable diesel 
facilities are able to out-compete smaller biodiesel producers for 
feedstock.
---------------------------------------------------------------------------

    \89\ Domestic renewable diesel capacity could more than double 
through 2025. EIA Today in Energy. Feb. 2, 2023.
    \90\ Reuters. CVR Pauses Renewable Diesel Plans as Feedstock 
Prices Surge. August 3, 2021. Available at: https://www.reuters.com/business/energy/cvr-pauses-renewable-diesel-plans-feedstock-prices-surge-2021-08-03.
---------------------------------------------------------------------------

    In addition to domestic production of renewable diesel, the U.S. 
has also imported renewable diesel, with nearly all of it produced from 
FOG and imported from Singapore.\91\ 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 and 130 
million gallons in 2022. 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, as domestic producers export volumes to take 
advantage of both the U.S. tax incentives and other incentives abroad. 
However, we also recognize that increasing net imports of renewable 
diesel could be a significant source of additional renewable fuel 
supply in future years.
---------------------------------------------------------------------------

    \91\ EIA Monthly Renewable Diesel Imports by Country, available 
at https://www.eia.gov/dnav/pet/pet_move_impcus_a2_nus_EPOORDO_im0_mbbl_m.htm.
---------------------------------------------------------------------------

c. BBD Feedstocks
    As was highlighted in the proposal, when considering the likely 
production and import of biodiesel and renewable diesel in future 
years, the availability of feedstock is a key consideration. We 
received many comments on our assessment of the availability of BBD 
feedstocks in the proposed rule. Many of these commenters stated that 
the data from USDA \92\ that EPA used to project domestic soybean oil 
production through 2025 was not appropriate for this use. For this 
final rule we have updated our projections of soybean oil production in 
the U.S. and canola oil production in Canada through 2025. Our current 
projections of the production of these feedstocks are significantly 
higher than our projections in the proposed rule (which did not 
consider increased availability of canola oil from Canada \93\) and are 
generally in alignment with the projections provided by the commenters 
and discussions with market experts. As in our proposed rule, however, 
we continue to believe that the availability of qualifying feedstocks 
will serve to limit the production of biodiesel and renewable diesel 
through 2025. We also continue to believe that when evaluating the 
various statutory factors, the greatest benefits and fewest negative 
impacts of these fuels occur when increased production of these fuels 
is consistent with increased production of qualifying feedstocks 
produced in North America. Our assessment of available feedstocks 
(including our consideration of

[[Page 44487]]

comments on the proposed rule and data not available at the time of the 
proposed rule) is discussed briefly in this section, and in greater 
detail in RIA Chapter 6.2 and the RTC document.
---------------------------------------------------------------------------

    \92\ USDA Agricultural Projections to 2031.
    \93\ Since the analyses for the proposed rule were conducted, 
EPA approved a pathway for renewable diesel produced from canola 
oil. In addition, Canadian feedstocks are covered by an aggregate 
compliance approach and are likely to be sourced from increased 
production of canola oil rather than diverted from existing uses. 
For a further discussion of the inclusion of canola oil from Canada 
in our projection of available feedstocks for biodiesel and 
renewable diesel production, see RTC Section 4.2.
---------------------------------------------------------------------------

    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.
[GRAPHIC] [TIFF OMITTED] TR12JY23.002

    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 42 percent in the 2021/2022 
agricultural marketing year.\94\ 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 it appears 
that demand for soybean oil is growing faster than demand for soybean 
meal. Notably, the percentage of the soybean value that came from the 
soybean oil (rather than the meal and hulls) had been relatively stable 
and averaged approximately 33 percent from 2016-2020. The percentage of 
the soybean value that came from the soybean oil increased 
significantly starting in 2021, reaching a high of 53 percent in 
October 2021, before declining slightly to 43 percent in August 2022 
(the most recent date for which data are available).
---------------------------------------------------------------------------

    \94\ USDA Oil Crops Yearbook. March 2023.
---------------------------------------------------------------------------

    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 FOG and distillers corn oil, 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 due to the 
combined value of RFS and LCFS incentives (together with the blenders' 
tax credit). Under California's LCFS program renewable diesel produced 
from FOG and distillers corn oil receive more credits than renewable 
diesel produced from soybean oil.
    Available volumes of FOG and distillers corn oil from domestic 
sources are expected to continue to increase in future years, but these 
increases are expected to be limited. FOG are the byproducts of other 
activities (rendering operations, for example), and production of FOG 
is not responsive to increasing demand for biofuel production. We 
therefore expect the availability of FOG to increase slowly, consistent 
with the observed trend in recent years. Similarly, distillers corn oil 
is a byproduct of ethanol production. Since we do not anticipate 
significant growth in ethanol production in future years, we do not 
project significant increases in the production of distillers corn oil 
for biofuel production, as most ethanol production facilities currently 
produce distillers corn oil. Therefore, if renewable diesel production 
in future years increases rapidly as suggested by the large production 
capacity announcements, it will likely require increased use of 
vegetable oils such as soybean oil and canola oil, increased use of 
imported feedstocks, or the use of feedstocks diverted from other 
markets.
    Greater volumes of soybean oil are projected to be produced 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.\95\ This new crushing

[[Page 44488]]

capacity is expected to come online in the 2023-2025 timeframe. 
Increased crushing of soybeans in the U.S. will increase domestic 
soybean oil production. In this final rule we have updated our 
projections of domestic soybean oil production through 2025 to better 
reflect recent investments in domestic soybean crushing facilities that 
are expected to begin operating by 2025.
---------------------------------------------------------------------------

    \95\ For example, see Demaree-Saddler, Holly, Cargill plans US 
soy processing operations expansion, World Grain, March 4, 2021; 
Sanicola, Laura, Chevron to invest in Bunge soybean crushers to 
secure renewable feedstock, Reuters, Sept. 2, 2021.
---------------------------------------------------------------------------

    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.
    We also expect that production of canola oil will increase in 
future years due to expanding canola crushing capacity in Canada. 
Similar to the investments in soybean crushing in the U.S., a number of 
companies have announced investment in additional canola crushing 
capacity, and some of these projects are already under construction. 
Increasing canola oil production in Canada could provide an opportunity 
for domestic renewable diesel producers to import canola oil for 
biofuel production, however we expect that these parties will face 
competition for this feedstock from Canadian biofuel producers as well 
as food and other non-biofuel markets. The assessment of feedstock 
availability for this final rule (discussed in greater detail in RIA 
Chapter 6.2.3) includes volumes of imported canola oil we project could 
be available to domestic BBD producers.
d. Projected BBD Production and Imports
    We project that the supply of BBD to the U.S. will increase through 
2025. Consistent with our updated projections of feedstock availability 
discussed in the preceding section, our projections of BBD production 
and imports are higher in this final rule than in the proposed rule, 
particularly in 2025. We project that the largest increases will come 
from domestic renewable diesel as new production facilities come 
online. 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 
relative to renewable diesel production is that opportunities for 
renewable diesel expansion in California are not constrained by 
blending limits. Renewable diesel can therefore continue to benefit 
from both LCFS credits and the RFS RIN incentives. In contrast, 
continued biodiesel expansion in California is expected to be more 
limited due to requirements for the use of additives in higher level 
biodiesel blends. Consequently, for biodiesel to continue to expand, it 
must do so primarily outside of California and without the added 
financial incentive of the LCFS credits. This provides a significant 
advantage to renewable diesel in the competition for access to new 
feedstocks, particularly feedstocks with low carbon intensity (CI) 
scores in California's LCFS program and Oregon and Washington's Clean 
Fuels programs. While we project most of the biodiesel and renewable 
diesel supplied to the U.S. will be produced domestically, we project 
that imports of both biodiesel and renewable diesel will continue to 
contribute to the supply of these fuels through 2025. We note that in 
the first quarter of 2023 imports of biodiesel and renewable diesel, 
and the feedstocks used to produce these fuels in the U.S., increased 
substantially on a year-over-year basis, seemingly in response to the 
proposed volume requirements for 2023-2025. See RIA Chapter 6.2 for 
more information on the projected supply of biodiesel and renewable 
diesel to the U.S. in 2023-2025. We take this data into consideration 
both in our assessment of the candidate volumes of non-cellulosic 
advanced biofuel (discussed in Section III.C.2) and the final volumes 
of advanced and total renewable fuel (discussed in Section VI).
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.\96\ However, these biofuels have been consumed in much 
smaller quantities than biodiesel and renewable diesel in the past, 
and/or have been highly variable.
---------------------------------------------------------------------------

    \96\ Renewable diesel produced through coprocessing vegetable 
oils or animal fats with petroleum cannot be categorized as BBD but 
remains advanced biofuel. See 40 CFR 80.1426(f)(1).
---------------------------------------------------------------------------

    We did not receive a significant number of comments suggesting 
alternative projections of other advanced biofuel volumes. The comments 
we did receive generally suggested higher volumes might be appropriate 
due to expectations of increased production of SAF \97\ (which is 
covered in Section III.B.2) and CNG/LNG produced from food waste or 
other non-cellulosic feedstocks. For this final rule we used the same 
general projection methodology as in the proposed rule, but we included 
data from 2022 that was not available at the time of the proposed rule. 
The inclusion of this additional data resulted in slightly higher 
volumes of other advanced biofuels relative to the proposed rule.
---------------------------------------------------------------------------

    \97\ While the existing pathways for SAF qualify as BBD, rather 
than advanced biofuel, some commenters stated that increasing 
production of SAF would result in additional volumes of other 
advanced biofuel.
---------------------------------------------------------------------------

    In order to estimate the volumes of these other advanced biofuels 
that may be available in 2023-2025, we used the same general 
methodology as in the proposed rule. This methodology was originally 
presented in the annual rulemaking establishing the applicable 
standards for 2020-2022.\98\ 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 RIA 
Chapter 5.4.
---------------------------------------------------------------------------

    \98\ 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..............................              95
Domestic ethanol........................................              27
CNG/LNG.................................................               6
Heating oil.............................................               3

[[Page 44489]]

 
Naphtha.................................................              55
Renewable diesel........................................             104
                                                         ---------------
    Total...............................................             290
------------------------------------------------------------------------

    As the available data does not permit us to identify an upward or 
downward trend in the historical consumption of these other advanced 
biofuels, we have used the volumes in Table III.B.3-1 for all years 
covered in this final rule (i.e., 2023-2025).
4. Conventional Renewable Fuel
    Conventional renewable fuel includes any renewable fuel that is 
made from renewable biomass as defined in 40 CFR 80.1401, does not 
qualify as advanced biofuel, and meets one of the following criteria:
     Is demonstrated to achieve a minimum 20 percent reduction 
in GHGs in comparison to the gasoline or diesel which it displaces; or
     Is exempt (``grandfathered'') from the 20 percent minimum 
GHG reduction requirement due to having been produced in a facility or 
facility expansion that commenced construction on or before December 
19, 2007, as described in 40 CFR 80.1403.\99\
---------------------------------------------------------------------------

    \99\ 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.
    To estimate candidate volumes of conventional renewable fuel for 
2023-2025, we focused primarily on projecting volumes of corn ethanol 
consumption, which in turn is driven by total ethanol consumption. For 
this final rule we have updated our projections of total ethanol 
consumption and corn ethanol consumption based on the comments we 
received and additional data that was not available for the proposed 
rule. We also investigated potential volumes of non-advanced biodiesel 
and renewable diesel.
a. Corn Ethanol
    Ethanol made from corn starch has dominated the renewable fuels 
market on a volume basis in the past and is expected to continue to do 
so for the time period addressed by this rulemaking.\100\ Corn starch 
ethanol is prohibited by statute from being an advanced biofuel 
regardless of its GHG performance in comparison to gasoline.\101\
---------------------------------------------------------------------------

    \100\ 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 in that year; grain 
sorghum ethanol in 2022 was only 77 million gallons. Waste 
industrial ethanol and ethanol made from non-cellulosic portions of 
separated food waste have been produced more sporadically and at 
even lower volumes. These other sources do not materially affect our 
assessment of volumes of conventional ethanol that can be produced.
    \101\ CAA section 211(o)(1)(B)(i).
---------------------------------------------------------------------------

    Total domestic corn ethanol production capacity increased 
dramatically between 2005 and 2010 and increased at a slower rate 
thereafter. In 2022, production capacity had reached 17.7 billion 
gallons.102 103 Available production capacity was 
significantly underused in 2020 and to some degree in 2021 because the 
COVID-19 pandemic depressed gasoline demand in comparison to previous 
years and thus ethanol demand in the form of E10 (gasoline containing 
10% denatured ethanol). Actual production of ethanol in the U.S. 
reached 15.4 billion gallons in 2022, compared to 16.1 billion gallons 
in 2018.\104\
---------------------------------------------------------------------------

    \102\ ``2022 Ethanol Industry Outlook--RFA,'' available in the 
docket.
    \103\ ``Ethanol production capacity--EIA August 2022,'' 
available in the docket.
    \104\ ``EIA Monthly Energy Review, April 2023,'' 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 the demand for E0, E15, and E85. We 
have incorporated projected growth in opportunities for sales of E15 
and E85 into our assessment. There is an excess of production capacity 
of ethanol and corn feedstock 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. Thus, consistent with the 
proposed rule, 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 at significant 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. 
While conventional biodiesel and renewable diesel could be used in 
2023-2025, as in the proposed rule we are not projecting any volumes of 
these fuels will be used in these years.\105\
---------------------------------------------------------------------------

    \105\ Data from EMTS shows some generation of D6 RINs for 
biodiesel and renewable diesel in recent years, however these RINs 
were retired using the retirement code ``renewable fuel used or 
designated to be used in any application that is not transportation 
fuel, heating oil, or jet fuel.'' These RINs therefore do not 
represent qualifying fuel under the RFS program.
---------------------------------------------------------------------------

    Actual global production of palm oil biodiesel and renewable diesel 
was about 4.5 billion gallons in 2021.\106\ The 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 approximately 1 billion gallons, suggesting that 
significant volumes of grandfathered biodiesel and renewable diesel 
could be imported under favorable market conditions.
---------------------------------------------------------------------------

    \106\ Total worldwide production of biodiesel and renewable 
diesel was 55 billion liters in 2021, of which 31 percent was from 
palm oil. See OECD-FAO Agricultural Outlook 2022-2031, p.236, 
available at https://www.oecd.org/development/oecd-fao-agricultural-outlook-19991142.htm.
---------------------------------------------------------------------------

    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.\107\ After 2016,

[[Page 44490]]

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 with no conventional renewable diesel imported since 
2017.\108\ The highest imported volume of total conventional biodiesel 
and renewable diesel occurred in 2016 with 160 million gallons (258 
million RINs).
---------------------------------------------------------------------------

    \107\ ``RIN supply as of 3-7-23,'' available in the docket.
    \108\ ``RIN supply as of 3-7-23,'' 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.\109\
---------------------------------------------------------------------------

    \109\ As discussed in Section VII.B, the gasoline+diesel 
estimates used to calculate the percentage standards have 
historically been lower than the gasoline+diesel volumes used by 
obligated parties to determine their Renewable Volume Obligations 
(RVO). Relatedly, the historical ethanol concentration values shown 
in Figure III are likely to be higher than actual values due to some 
underestimates of total gasoline demand.
[GRAPHIC] [TIFF OMITTED] TR12JY23.003

    As the average ethanol concentration approached and then exceeded 
10 percent, the gasoline pool became saturated with E10, with a small, 
likely stable volume of E0 and small but increasing volumes of E15 and 
E85. The average ethanol concentration can exceed 10 percent only 
insofar as the ethanol in E15 and E85 exceeds the ethanol content of 
E10 and more than offsets the volume of E0.
    We used the same general methodology to project total ethanol 
consumption in this final rule as in the proposed rule, but we updated 
the projections of poolwide ethanol concentration and total gasoline 
consumption using more recent data. This methodology is different than 
the methodology used in previous RFS rules, which generally looked to 
EIA projections of ethanol concentration in the gasoline pool. We have 
used this new methodology to better account for the projected increase 
in retail stations selling higher level blends such as E15 and 
E85.\110\
---------------------------------------------------------------------------

    \110\ See RIA Chapter 6.5.1 for more information on our 
projections of ethanol concentration in the gasoline pool.
---------------------------------------------------------------------------

    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. In 
this final rule we updated both the correlations between E15 and E85 
stations and poolwide ethanol consumption and our projections of the 
number of E15 and E85 stations for 2023-2025. The results are shown in 
Table III.B.5-1. While the projected ethanol concentration in 2023-2025 
are similar to the projected concentrations from the proposed rule, 
projected ethanol consumption for 2023-2025 is significantly lower due 
to lower projected gasoline demand in these years in EIA's most recent 
AEO. Details of these calculations can be found in the RIA.

[[Page 44491]]

             Table III.B.5-1--Projected Ethanol Consumption
------------------------------------------------------------------------
                                                             Projected
                                             Projected        ethanol
                  Year                        ethanol       consumption
                                           concentration     (million
                                                (%)          gallons)
------------------------------------------------------------------------
2023....................................           10.41          13,974
2024....................................           10.46          14,128
2025....................................           10.51          13,978
------------------------------------------------------------------------

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 analyzed under the other economic and environmental factors 
required by the statute. This section describes the candidate volumes, 
while Section IV summarizes the results of the additional analyses we 
performed. Relative to the candidate volumes in the proposed rule, the 
candidate volumes for cellulosic biofuel, BBD, and other advanced 
biofuels in this final rule are all higher for all three years (after 
accounting for the fact that we are not finalizing the proposed eRIN 
provisions in this rule). The candidate volumes for conventional 
biofuel in this final rule are lower than the volumes from the proposed 
rule.
    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 equivalent to analyzing the statutory categories, since 
doing so would effectively require us to evaluate the difference 
between various statutory categories (e.g., assessing ``the difference 
between volumes of advanced biofuel and total renewable fuel'' instead 
of assessing ``the volume of conventional renewable fuel''), adding 
unnecessary complexity 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
    In determining the candidate volumes for cellulosic biofuel, we 
started by considering the statutory volume targets for 2010-2022. The 
statutory volumes for cellulosic biofuel increased rapidly, from 100 
million gallons in 2010 to 16 billion gallons in 2022 with the largest 
increases in the later years. While notable on its own, it is even more 
notable in comparison to the implied statutory volumes for the other 
renewable fuel volumes. Statutory BBD volumes did not increase after 
2012, implied conventional renewable fuel volumes did not increase 
after 2015, and non-cellulosic advanced biofuel volume increases 
tapered off in recent years with a final increment in 2022. Thus, the 
clear focus of the statute by 2022 was on growth in cellulosic biofuel 
volumes, which have the greatest greenhouse gas reduction threshold 
requirement in the statute.\111\ The statutory cellulosic waiver 
provision,\112\ while acknowledging that the statutory cellulosic 
biofuel volumes may not be met, nevertheless effectively expresses 
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 
in the statute on cellulosic biofuel over time is likely due to 
expectations that cellulosic biofuel 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), that cellulosic biofuel feedstocks could be produced or 
collected with relatively few negative environmental impacts, that the 
feedstocks would be comparable or cheaper in cost relative to other 
fuel feedstocks, allowing for lower cost biofuels to be produced than 
those produced from feedstocks without other primary uses such as food, 
and that the technological breakthroughs needed to convert cellulosic 
feedstocks into biofuel were likely imminent.
---------------------------------------------------------------------------

    \111\ CAA section 211(o)(1)(E). Cf. CAA section 211(o)(1)(B)(i), 
(D), (2)(A)(i). See also definition of ``cellulosic biofuel'' at 40 
CFR part 80, section 1401.
    \112\ CAA section 211(o)(7)(D).
---------------------------------------------------------------------------

    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 2023-2025, after taking into consideration 
the incentives provided by the RFS program and other available state 
and federal incentives. The candidate volumes for 2023-2025 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 and CNG/LNG derived 
from biogas separately. Relative to the proposed rule the candidate 
volumes of CNG/LNG derived from biogas are higher in all three years 
due to the use of a higher growth rate to project these volumes. 
Similarly, volumes of ethanol from CKF are higher in all three years as 
we are now projecting additional facilities will register as cellulosic 
biofuel producers using this pathway. Despite the increase in RNG use 
as CNG/LNG and the addition of ethanol from CKF, total cellulosic 
biofuel volumes for 2024 and 2025 are significantly lower in this final 
rule relative to the proposal because we are not finalizing the eRIN 
provisions in this rule.

[[Page 44492]]

                              Table III.C.1-1--Cellulosic Biofuel Candidate Volumes
                                                 [Million RINs]
----------------------------------------------------------------------------------------------------------------
                                                                       2023            2024            2025
----------------------------------------------------------------------------------------------------------------
RNG use as CNG/LNG..............................................             831           1,039           1,299
Ethanol from CKF................................................               7              51              77
                                                                 -----------------------------------------------
    Total Cellulosic Biofuel....................................             838           1,090           1,376
----------------------------------------------------------------------------------------------------------------

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.\113\ It remained at 4.5 billion gallons for three years before 
finally rising to 5.0 billion gallons in 2022. The candidate volumes 
for non-cellulosic advanced biofuel in the final rule are higher than 
the candidate volumes from the proposed rule for 2023-2025. The 
increases are primarily the result of higher projections of feedstock 
availability allowing for greater renewable diesel production relative 
to the proposed rule.
---------------------------------------------------------------------------

    \113\ See CAA section 211(o)(2)(B).
---------------------------------------------------------------------------

    For years after 2022, we anticipate that a key factor in the growth 
in the production of advanced biodiesel and renewable diesel (the two 
non-cellulosic advanced biofuels projected to be available in the 
greatest quantities through 2025) will be the availability of 
feedstocks as discussed in III.B.2.c. above. We expect small increases 
in the supply of FOG and distillers corn oil, but we project that the 
largest increases in feedstock availability in the U.S. will come from 
increased production of soybean oil. This expectation is largely in 
line with data and input provided by commenters on the December 2022 
proposed rule. Significant investments have been made in recent years 
that would result in higher domestic soybean crushing capacity and thus 
soybean oil production, particularly in 2024 and 2025 (see additional 
discussion of the availability of biodiesel and renewable feedstocks in 
RIA Chapter 6.2.3). Similar investments have also been made to increase 
the production of canola oil in Canada, much of which could be supplied 
to U.S. markets for biofuel production. 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 higher-GHG feedstocks in non-biofuel markets as low-
GHG feedstocks are increasingly used for biofuel production, then it 
would prove counterproductive.
    Based on these considerations, we believe that increases in the 
volume of non-cellulosic advanced biofuel in the 2023-2025 timeframe 
should primarily be based on projected increases in the availability of 
feedstocks from the U.S. and Canada. One potential methodology for 
projecting the available supply of BBD in 2023-2025 is to base the 
projected supply for these years solely on the quantity of these fuels 
supplied in 2022 and the projected increases in feedstock availability 
in the U.S. and Canada (see RIA Chapter 6.2 for additional detail on 
our projections of biodiesel and renewable diesel supply for 2023-
2025). However, RIN generation data from the first three months of 2023 
indicates that the market is supplying greater volumes of non-
cellulosic advanced biofuel than we would project based only on the 
quantity of these fuels used in 2022 plus the projected growth in 
feedstock production in the U.S. and Canada. The market appears to be 
responding to the proposed RFS volume requirements for 2023 by drawing 
upon imports and other sources of feedstock.
    The candidate volumes for non-cellulosic advanced biofuel for 2023-
2025 attempt to balance the longer-term desire to maximize the benefits 
(and minimize the potential negative impacts) of non-cellulosic 
advanced biofuel production by aligning growth in these fuels with the 
projected growth in feedstock production in North America and the 
observed data on the quantities of these fuels that have been supplied 
to the U.S. in the first quarter of 2023 (see Section VI for further 
discussion of this topic). The candidate volume for 2023 is equal to 
the quantity of non-cellulosic advanced biofuels to meet the proposed 
RFS volumes for 2023 (including the projected shortfall in conventional 
renewable fuel), consistent with the recent market data that indicates 
that the market is on track to supply this quantity of non-cellulosic 
advanced biofuel. The candidate volume for 2024 was determined in the 
same way, but we note that we project that a greater proportion of the 
increase over the quantity of these fuels supplied in 2022 is project 
to be supplied with feedstocks from North America (rather than other 
foreign countries) as soybean and canola crush capacity increases. 
Finally, the candidate volume for 2025 is primarily based on the 
projected increase in feedstocks from North America projected to be 
available to biofuel producers. These candidate volumes are shown in 
Table III.C.2-1, and the basis for these volumes are discussed in more 
detail in RIA Chapter 6.

                    Table III.C.2-1--Total Non-Cellulosic Advanced Biofuel Candidate Volumes
                                                 [Million RINs]
----------------------------------------------------------------------------------------------------------------
                                                                       2023            2024            2025
----------------------------------------------------------------------------------------------------------------
Advanced biodiesel..............................................           2,565           2,500           2,436
Advanced renewable diesel \a\...................................           3,650           3,705           4,445
Other advanced biofuel..........................................             290             290             290
                                                                 -----------------------------------------------

[[Page 44493]]

 
    Total.......................................................           6,505           6,495           7,171
----------------------------------------------------------------------------------------------------------------
\a\ Represents only renewable diesel and jet fuel 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.

3. Conventional Renewable Fuel
    Consistent with the statute, EPA increased the implied conventional 
renewable fuel volumes every year between 2009 and 2015, after which it 
remained at 15 billion gallons through 2022.114 115 However, 
since 2017 these standards were set with the expectation that corn 
ethanol and other conventional biofuel volumes would not be sufficient 
to meet the standards, and instead advanced biofuel volumes would be 
required to make up for the shortfall. This is consistent with our 
observations of the market, in which the total supply of conventional 
renewable reached a maximum of approximately 14.5 billion gallons in 
2016-2018. The candidate volume for conventional renewable in this 
final rule are based primarily on supply related factors rather than 
the implied volume requirements for conventional renewable fuel in 
previous RFS rules.
---------------------------------------------------------------------------

    \114\ See CAA section 211(o)(2)(B).
    \115\ While the 2020 implied volume requirement was originally 
set at 15 billion gallons (85 FR 7016, February 6, 2020), we 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 set the 
implied volume requirement for conventional renewable fuel at the 
level actually consumed. In 2016 EPA reduced the implied 
conventional renewable fuel volume to 14.5 billion gallons under our 
general waiver authority; this action was subsequently invalidated 
by the D.C. Circuit Court of Appeals in ACE. In this rule we are 
completing our response to the ACE remand by establishing 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. These two supplemental actions effectuates the 
Congressionally determined renewable fuel volume for 2016, modified 
only by the proper exercise of EPA's waiver authorities, as upheld 
by the court in ACE, as discussed in Section V.
---------------------------------------------------------------------------

    The amount of conventional 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. Relative to the proposed 
rule both total ethanol consumption and corn ethanol consumption are 
significantly lower in all years, primarily due to lower projections of 
gasoline consumption in EIA's most recent AEO. We do not currently 
project that non-ethanol conventional renewable fuels will be supplied 
to the U.S. in 2023-2025. Therefore, our candidate volumes for 
conventional renewable fuel are equal to our projections of 
conventional ethanol consumption for 2023-2025.

                               Table III.C.3-1--Projections of Ethanol Consumption
                                                [Million gallons]
----------------------------------------------------------------------------------------------------------------
                                                                       2023            2024            2025
----------------------------------------------------------------------------------------------------------------
Ethanol in all blends...........................................          13,974          14,128          13,978
Cellulosic ethanol..............................................               7              51              77
Imported sugarcane ethanol......................................              95              95              95
Domestic advanced ethanol.......................................              27              27              27
Conventional ethanol............................................          13,845          13,955          13,779
----------------------------------------------------------------------------------------------------------------

    Since conventional ethanol consumption would be about 13.8-14.0 
billion gallons, there would need to be about 1.0-1.2 billion ethanol-
equivalent gallons of non-ethanol renewable fuel in order for the 
implied conventional renewable fuel volumes of 15.0 billion gallons to 
be met.
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. 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 final 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 the RFS 
regulations limit the use of these carryover RINs to 20 percent of the 
obligated party's renewable volume obligation (RVO).\116\ For the 
collective supply of carryover RINs to be preserved from one year to 
the next, individual carryover RINs are used for compliance before they 
expire and are essentially replaced with newer vintage RINs that are 
then held for use in the next year. For example, vintage 2022 carryover 
RINs must be used for compliance with 2023 compliance year obligations, 
or they will expire.

[[Page 44494]]

However, vintage 2023 RINs can then be saved for use toward 2024 
compliance.
---------------------------------------------------------------------------

    \116\ 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.\117\ Carryover RINs are 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.\118\ 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.
---------------------------------------------------------------------------

    \117\ See, e.g., 72 FR 23904 (May 1, 2007).
    \118\ 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 number of available 
carryover RINs may negatively impact the RIN market, even when the 
market overall could satisfy the standards. In such a case, market 
disruptions could force the need for a retroactive waiver of the 
standards, undermining the market certainty so critical to the RFS 
program. For all of these reasons, carryover RINs provide a necessary 
programmatic buffer that helps facilitate compliance by individual 
obligated parties, provides for smooth overall functioning of the 
program to the benefit of all market participants, and is consistent 
with the statutory provision requiring the generation and use of 
credits.
    Carryover RINs have also provided flexibility when EPA considered 
the need to use its waiver authorities to lower previously established 
volumes. For example, in the context of the 2013 RFS rulemaking we 
noted that an abundance of carryover RINs available in that year, 
together with possible increases in renewable fuel production and 
import, justified maintaining the advanced and total renewable fuel 
volume requirements for that year at the levels specified in the 
statute.\119\
---------------------------------------------------------------------------

    \119\ 79 FR 49793-95 (August 15, 2013).
---------------------------------------------------------------------------

a. Projected Number of Available Carryover RINs
    The projected number of available carryover RINs after compliance 
with the 2021 standards (i.e., the number of carryover RINs available 
for compliance with the 2022 standards) are summarized in Table 
III.C.4.a-1.\120\
---------------------------------------------------------------------------

    \120\ The calculations performed to project the number of 
available carryover RINs can be found in RIA Chapter 1.10.

                                Table III.C.4.a-1--Projected 2021 Carryover RINs
                                                 [Million RINs]
----------------------------------------------------------------------------------------------------------------
                                                                                   Absolute 2021  Effective 2021
                 RFS standard                               RIN type              carryover RINs  carryover RINs
                                                                                        \a\             \b\
----------------------------------------------------------------------------------------------------------------
Cellulosic Biofuel............................  D3+D7...........................              25               0
Non-Cellulosic Advanced Biofuel \c\...........  D4+D5...........................              61               0
Conventional Renewable Fuel \d\...............  D6..............................           1,047             494
----------------------------------------------------------------------------------------------------------------
\a\ Represents the absolute number of 2021 carryover RINs that are available for compliance with the 2022
  standards and does not account for deficits carried forward from 2021 into 2022.
\b\ Represents the effective number of 2021 carryover RINs that are available for compliance with the 2022
  standards after accounting for deficits carried forward from 2021 into 2022. Standards for which deficits
  exceed the number of available carryover RINs are represented as zero.
\c\ Non-cellulosic advanced biofuel is not an RFS standard category but is calculated by subtracting the number
  of cellulosic RINs from the number of advanced RINs.
\d\ Conventional renewable fuel is not an RFS standard category but is calculated by subtracting the number of
  advanced RINs from the number of total renewable fuel RINs.

    Assuming that the market exactly meets the 2022, 2023, and 2024 
standards with new RIN generation, these are also the number of 
carryover RINs that would be available for 2023, 2024, and 2025 
(including the 2023 supplemental standard). 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 2023-
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.\121\ 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). In 
particular, as discussed in RIA Chapter 1.11, the percentage standards 
established for 2020 and 2021 were more stringent than EPA anticipated 
(i.e., the volume of gasoline and diesel reported by obligated parties 
for these compliance years was higher than volume used by EPA to set 
the standards), resulting in an unexpected drawdown of the number of 
available

[[Page 44495]]

carryover RINs as a result of compliance with the 2020 and 2021 
standards. In addition, a number of small refineries have elected to 
defer compliance with their 2020 obligations by opting-in to the 
alternative RIN retirement schedule for small refineries.\122\ This 
flexibility allows small refineries to use any valid RIN (including 
2023 and 2024) to comply with their 2020 RVOs as part of a quarterly 
RIN retirement schedule and effectively reduces the number of 2021-2024 
carryover RINs available to comply with the 2022-2025 standards. 
Furthermore, we note that there have been enforcement actions in past 
years that have resulted in the retirement of carryover RINs to make up 
for the generation and use of invalid RINs and/or the failure to retire 
RINs for exported renewable fuel. To the extent that there are 
enforcement actions in the future, they could have similar results and 
require that obligated parties or renewable fuel exporters settle past 
enforcement-related obligations in addition to complying with the 
annual standards. In light of these uncertainties, the number of 
available carryover RINs could be larger or smaller than the number 
projected in Table III.C.4.a-1.
---------------------------------------------------------------------------

    \121\ Per 40 CFR 80.1451(f)(1)(i)(B)(4), the compliance deadline 
for the 2022 standards will be the first quarterly reporting 
deadline after the effective date of this action. We expect this 
deadline is likely to be December 1, 2023.
    \122\ 40 CFR 80.1444.
---------------------------------------------------------------------------

    We acknowledge that the effective number of cellulosic and non-
cellulosic advanced biofuel carryover RINs is zero, and that the 
effective number of conventional renewable fuel carryover RINs is 
significantly lower than it has been in recent years. We have recently 
taken actions to preserve the number of carryover RINs, and to ensure 
the continued functioning of the RIN market, and continue to believe 
that carryover RINs serve a vital programmatic function.\123\ We have 
monitored RIN prices as a proxy for RIN market functioning, and given 
current RIN prices, we continue to believe the RIN market is liquid and 
fungible. Moreover, we note that the demand for RINs has been somewhat 
reduced and dispersed across a broad range of RIN vintages as a result 
of several actions related to small refineries: (1) The use of the 
alternative RIN retirement schedule in 40 CFR 80.1444, which gives 
small refineries additional time and opens a broader range of RIN 
vintages to acquire and retire the RINs needed to demonstrate 
compliance for the 2020 compliance year; and (2) The requests by 
several small refineries, granted by three different U.S. Circuit 
Courts of Appeals, to stay their RFS compliance obligations as part of 
the pending litigation challenging the EPA's April 2022 \124\ and June 
2022 \125\ SRE Denial Actions.\126\ We will continue to monitor RIN 
prices and the market, and retain our ability to modify future volumes 
through the use of our waiver authorities as discussed in Section II.F.
---------------------------------------------------------------------------

    \123\ See 87 FR 39600 (July 1, 2022), See also, ``April 2022 
Alternative RFS Compliance Demonstration Approach for Certain Small 
Refineries,'' EPA-420-R-22-006, April 2022; and ``June 2022 
Alternative RFS Compliance Demonstration Approach for Certain Small 
Refineries,'' EPA-420-R-22-012, June 2022.
    \124\ ``April 2022 Denial of Petitions for RFS Small Refinery 
Exemption,'' EPA-420-R-22-005, April 2022 (``April 2022 SRE Denial 
Action'').
    \125\ ``June 2022 Denial of Petitions for RFS Small Refinery 
Exemption,'' EPA-420-R-22-011, June 2022 (``June 2022 SRE Denial 
Action'').
    \126\ See, e.g., Hunt Refining Co. v. EPA, No. 22-12535-A, 
Document 33 (11th Cir.), Calumet Shreveport Refining, et al. v. EPA, 
No. 22-60266, Documents 209-1, 304-1 (5th Cir.), Sinclair Wyoming, 
et. al. v. EPA, No. 22-1073, Document 1992426 (D.C. Cir.).
---------------------------------------------------------------------------

    Even though carryover RIN levels are low, we believe that the 
standards we are finalizing in this action, including the supplemental 
standard, can be met through additional production of renewable fuel in 
the market. Additionally, should the market fall short of the volumes 
we are finalizing, obligated parties will continue to be able to carry 
forward a RIN deficit from one year into the next, although they may 
not carry forward a deficit for consecutive years. Conversely, should 
the market over-comply with the standards we are finalizing, the number 
of available carryover RINs could again grow.
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 finalized for 2023-2025 (including the 2023 
supplemental volume). Doing so would be equivalent to intentionally 
drawing down the number of available carryover RINs in setting those 
volume requirements. We do not believe that this would be appropriate. 
In reaching this determination, we considered the functions of 
carryover RINs, the projected number available, the uncertainties 
associated with this projection, the potential impact of carryover RINs 
on the production and use of renewable fuel, the ability and need for 
obligated parties to draw on carryover RINs to comply with their 
obligations (both on an individual basis and on a market-wide basis), 
and the impacts of drawing down the number of available carryover RINs 
on obligated parties and the fuels market more broadly. As previously 
described, carryover RINs provide important and necessary programmatic 
functions--including as a cost spike buffer--that will both facilitate 
individual compliance and provide for smooth overall functioning of the 
program. We believe that a balanced consideration of the possible role 
of carryover RINs in achieving the volume requirements, versus 
maintaining an adequate number of carryover RINs for important 
programmatic functions, is appropriate when EPA exercises its 
discretion under its statutory authorities.
    Furthermore, as discussed in the previous section and in RIA 
Chapter 1.10, the number of available carryover RINs has been 
significantly and unexpectedly drawn down as a result of 2020 and 2021 
compliance, including effectively depleting the number of available 
cellulosic and non-cellulosic advanced carryover RINs. Moreover, 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 believed that the market could make sufficient 
renewable fuel available to meet the 2022 standards, there may be some 
challenges.\127\ In addition, in this action we are for the first time 
prospectively establishing volume requirements for multiple years. This 
inherently adds uncertainty and makes it more challenging to project 
with accuracy the number of carryover RINs that will 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 number of available carryover RINs could lead to 
significant deficit carryforwards and noncompliance 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 including 
carryover RINs in the candidate volumes, nor setting the 2023, 2024, 
and 2025 volume requirements (including the 2023 supplemental standard) 
at levels that would intentionally draw down the number of available 
carryover RINs.
---------------------------------------------------------------------------

    \127\ 87 FR 39600 (July 1, 2022).
---------------------------------------------------------------------------

    We are not determining that the number of carryover RINs projected 
in Table III.C.4.a-1 is a bright-line threshold for the number of 
carryover

[[Page 44496]]

RINs that provides sufficient market liquidity and allows carryover 
RINs to play their important programmatic functions. As in past years, 
we are instead evaluating, on a case-by-case basis, the number of 
available carryover RINs in the context of the RFS standards and the 
broader transportation fuel market 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 a larger number of 
available carryover RINs may provide greater assurance of market 
liquidity, we do not believe it would be appropriate to set the 
standards at levels specifically designed 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 that we 
believe represent achievable levels of supply related factors and other 
relevant considerations. These volumes are summarized in Table III.C.5-
1.

                Table III.C.5-1--Candidate Volume Components Derived From Supply-Related Factors
                                               [Million RINs] \a\
----------------------------------------------------------------------------------------------------------------
                                                                       2023            2024            2025
----------------------------------------------------------------------------------------------------------------
Cellulosic biofuel (D3 & D7)....................................             838           1,090           1,376
Biomass-based diesel (D4).......................................           6,215           6,205           6,881
Other advanced biofuel (D5).....................................             290             290             290
Conventional renewable fuel (D6)................................          13,845          13,955          13,779
----------------------------------------------------------------------------------------------------------------
\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 RIA 
Chapter 3. These candidate volumes represent our assessment of the 
volume of renewable fuels we project could be used in the U.S. based on 
the expected annual rate of future commercial production of renewable 
fuels (one of the statutory factors), potential constraints on the 
domestic consumption of renewable fuels, and other relevant factors. We 
considered these candidate volumes when conducting the analyses of the 
additional statutory factors, which are summarized in Section IV and 
discussed in greater detail in the RIA. In Section VI, we discuss the 
final applicable volume targets based on a consideration of all of the 
factors that we analyzed--both the supply-related factors that were 
considered in developing the candidate volumes (discussed in this 
section) and the additional statutory factors discussed in Section IV.
    Note that the volumes shown in Table III.C.5-1 represent the total 
candidate volumes 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 that could 
be used to satisfy 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.

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 used 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 in 
the proposal, we did not use to assess 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.''
    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 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.

[[Page 44497]]

    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 the economics for 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 (e.g., did they lose 
money in a previous year), current, and perceived future economics of 
the biofuel market when deciding whether to continue to operate their 
biofuel plants, and our analysis attempted to account for these 
factors.
    The No RFS Baseline analysis for 2023-2025 compares the biofuel 
cost 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 to blenders. 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 (within the constraints described below). 
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 society at large (see Section IV.C and RIA 
Chapter 10 for descriptions of the social cost analysis). 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 generally borne by consumers, not the 
fuels industry. Other ways that the No RFS economic analysis is 
different from the social cost analysis include:
     In the context of assessing production costs, we amortized 
the capital costs at a higher rate of return more typical for industry 
investment instead of the rate of return used for social costs.
     We assessed 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.
     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 must price E85 lower 
than the primary alternative E10 to account for this bias and they must 
consider this in their decisions to blend and sell E85. 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 Baseline 
discussion in RIA Chapter 2.
    We added these various cost components (i.e., production cost, 
distribution cost, any blending cost, retail cost, applicable tax 
subsidies) 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. An important subsidy is the $1 federal 
tax incentives for blending biodiesel and other biofuels into diesel 
fuel which was extended in the IRA.\128\ 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 Higher Blends 
Infrastructure Incentive Program (HBIIP) program administered by the 
United States Department of Agriculture.
---------------------------------------------------------------------------

    \128\ H.R. 5376--The Inflation Reduction Act of 2022
---------------------------------------------------------------------------

    In addition, there are a number of state programs that create 
subsidies for biodiesel and renewable diesel fuel, the largest being 
offered by California and Oregon through their LCFS programs. 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.\129\ To account 
for the various state assumptions, it was necessary to model the cost 
of using these biofuels on a state-by-state basis.
---------------------------------------------------------------------------

    \129\ In light of the fluid situation with respect to a 1-psi 
RVP waiver for E15 or actions to remove the 1 psi wavier for E10 in 
eight midwestern states, our analysis did not specifically assume 
either of these potential changes. These assumptions can affect the 
relative cost of E15, however, adopting these assumptions would not 
have impacted the overall conclusions with respect to blending E15 
in the absence of the RFS program.
---------------------------------------------------------------------------

    For most 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 to determine whether to continue to operate their 
plants, or shutdown. Thus, to smooth out the swings in the economics 
for using biodiesel and renewable diesel and look at it the way plant 
operators and their 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 distinct four-year periods. As a 
result, the first 4-year modeled period 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 in Table III.D.1-1. 
A more complete description of the No RFS baseline and its derivation 
is provided in RIA Chapter 2. The projected consumption of cellulosic 
biofuel and

[[Page 44498]]

other advanced biofuel in this final rule is similar to the volumes for 
these fuel types projected in the proposed rule, with slight variations 
based on updated data. The projected BBD volumes for the No RFS 
baseline are significantly higher in all years, primarily because the 
significantly higher crude oil prices from the most recent AEO make BBD 
more cost competitive with petroleum diesel, after accounting for the 
available non-RFS incentives such as the federal tax credit for BBD and 
the incentives offered by California's LCFS program. Finally, the 
conventional renewable fuel volumes for the No RFS baseline are 
significantly lower in all years, relative to the volumes in the 
proposed rule, primarily due to lower projected gasoline consumption in 
2023-2025 from EIA.

                    Table III.D.1-1--Biofuel Consumption in 2023-2025 Under a No RFS Baseline
                                                 [Million RINs]
----------------------------------------------------------------------------------------------------------------
                                                                       2023            2024            2025
----------------------------------------------------------------------------------------------------------------
Cellulosic biofuel (D3 & D7)....................................             343             402             444
Biomass-based diesel (D4).......................................           2,796           3,139           3,496
Other advanced biofuel (D5).....................................             226             226             226
Conventional renewable fuel (D6)................................          13,185          13,224          12,992
----------------------------------------------------------------------------------------------------------------

    Our analysis shows that corn ethanol is economical to use in 10 
percent blends (E10) 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. Higher-
level ethanol blends are not as economical as ethanol blended as E10 
because the octane value of ethanol is generally not realized in these 
blends, and the infrastructure cost for dispensing these fuels are high 
(see RIA Chapter 10). 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.
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 neglect 
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.\130\ 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.
---------------------------------------------------------------------------

    \130\ 75 FR 14670 (March 26, 2010).
---------------------------------------------------------------------------

3. Previous Year Volumes
    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.\131\
---------------------------------------------------------------------------

    \131\ 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 2022 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. 
Therefore, we used actual data on 2020

[[Page 44499]]

biofuels consumption as the primary baseline in that rule.
    In the Set rule proposal, we used the 2022 volume requirements as 
an informational case in addition to the No RFS baseline, but we did so 
only for costs to allow for a comparison to the analysis and results 
presented in recent annual rules. We continue to believe that this is 
appropriate in this final rule. However, we now have data on how the 
market responded to the applicable 2022 standards, and we believe that 
this data on actual market performance is a better point of reference 
than the 2022 volume requirements established in the July 1, 2022 final 
rule. Therefore, we have used actual 2022 biofuel consumption as a 
baseline in the estimation of costs for this final rule, in addition to 
the No RFS baseline. This approach is consistent with the approach we 
took in the rulemaking which established the volume requirements for 
2020, 2021, and 2022,\132\ as well as the rulemaking which established 
the volume requirements for 2014, 2015, and 2016.\133\ 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.\134\
---------------------------------------------------------------------------

    \132\ 87 FR 39600 (July 1, 2022).
    \133\ 80 FR 77420 (Dec. 14, 2015).
    \134\ The 2015 volumes were based on actual consumption data for 
January-September and a projection for October-December.
---------------------------------------------------------------------------

    The volumes of biofuel consumption for 2022 are shown below. More 
details on 2022 biofuel consumption can be found in RIA Chapter 2.

                Table III.D.3-2--2022 Biofuel Consumption
------------------------------------------------------------------------
                                                              Volume
                                                          (million RINs)
------------------------------------------------------------------------
Cellulosic biofuel (D3 & D7)............................             667
Biomass-based diesel (D4)...............................           4,956
Other advanced biofuel (D5).............................             318
Conventional renewable fuel (D6)........................          14,034
------------------------------------------------------------------------

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.5-1) 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 RIA 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. As noted above, we also consider the impacts of this rule 
relative to a 2022 baseline for some of our analyses, such as the cost 
of the rule. The changes in biofuel consumption in the transportation 
sector relative to the 2022 baseline are shown in in Table III.E-2.

 Table III.E-1--Changes in Biofuel Consumption in the Transportation Sector in Comparison to the No RFS Baseline
                                                 [Million RINs]
----------------------------------------------------------------------------------------------------------------
                                                                       2023            2024            2025
----------------------------------------------------------------------------------------------------------------
Cellulosic biofuel (D3 & D7)....................................             495             688             932
Biomass-Based Diesel (D4).......................................           3,169           3,066           3,385
Other Advanced Biofuel (D5).....................................              64              64              64
Conventional Renewable Fuel (D6)................................             660             731             787
----------------------------------------------------------------------------------------------------------------

  Table III.E-2--Changes in Biofuel Consumption in the Transportation Sector in Comparison to the 2022 Baseline
                                                 [Million RINs]
----------------------------------------------------------------------------------------------------------------
                                                                       2023            2024            2025
----------------------------------------------------------------------------------------------------------------
Cellulosic biofuel (D3 & D7)....................................             172             424             710
Biomass-Based Diesel (D4).......................................           1,271           1,511           2,187
Other Advanced Biofuel (D5).....................................             -28             -28             -28
Conventional Renewable Fuel (D6)................................            -189             -79            -255
----------------------------------------------------------------------------------------------------------------

    The volumes shown in Table III.D.1-1 and the volume changes shown 
in Tables III.E-1 and 2 include the volume of renewable fuel projected 
to be supplied to meet the supplemental volume requirements in 2023. 
For purposes of analyzing the environmental and economic impacts 
(discussed in Section IV), we treat the 2023 supplemental volume 
requirement separately as discussed in RIA Chapter 3.3. We project that 
the supplemental volume will be met with 147 million gallons (250 
million RINs) of renewable diesel produced from soybean oil. Our 
analyses of the statutory factors described in Section IV generally do 
not include the impacts of the supplemental volume requirement, except 
where noted.

IV. Analysis of Candidate Volumes

    As described in Section II.B, the statute specifies a number of 
factors that EPA must analyze in making a determination of the 
appropriate volume requirements to establish for years after 2022 (and 
for BBD, years after 2012). A full description of the analysis for all 
factors is provided in the RIA. In this section, we provide a summary 
of the analysis of a selection of factors for the candidate volumes 
derived from supply-related factors as described in the previous 
section (see Table III.C.5-1 for the candidate volume, and Table III.E-
1 for the corresponding volume changes in comparison to the No RFS 
baseline),

[[Page 44500]]

along with some implications of those analyses. In Section VI we 
provide a summary of our consideration of all factors in determining 
the volume requirements that we have determined are appropriate for 
2023-2025.

A. Climate Change

    This section begins with a description of our analysis of the 
climate change impacts of the candidate volumes. Following this, in 
Section IV.A.2, is a description of a model comparison exercise that 
was not conducted for the purpose of evaluating the candidate volumes, 
nor does it inform the volumes in this final rule.
1. Climate Change Analysis Supporting Rule
    CAA section 211(o)(2)(B)(ii) states that the basis for setting 
applicable renewable fuel volumes after 2022 must include, among other 
things, ``an analysis of . . . the impact of the production and use of 
renewable fuels on the environment, including on . . . climate 
change.'' While the statute requires that EPA base its determinations, 
in part, on an analysis of the climate change impact of renewable 
fuels, it does not require a specific type of analysis. The CAA 
requires evaluation of lifecycle greenhouse gas (GHG) emissions as part 
of the RFS program,\135\ and GHG emissions contribute to climate 
change.\136\ Thus, in the proposed rule we used lifecycle GHG emissions 
estimates as a proxy for climate change impacts.\137\ We continue to 
believe this approach is reasonable and appropriate for the final rule.
---------------------------------------------------------------------------

    \135\ See CAA section 211(o)(1)(H) (empowering the Administrator 
to determine lifecycle greenhouse gas emissions) and CAA section 
211(o)(2)(A)(i) (requiring the Administrator to ``ensure that 
transportation fuel sold or introduced into commerce in the United 
States . . . contains . . . renewable fuel . . . [that] achieves at 
least a 20 percent reduction in lifecycle greenhouse gas emissions 
compared to baseline lifecycle greenhouse gas emissions.,'' where 
the 20 percent reduction threshold applies to renewable fuel 
``produced from new facilities that commence construction after 
December 19, 2007.'')
    \136\ Extensive additional information on climate change is 
available in other EPA documents, as well as in the technical and 
scientific information supporting them. See 74 FR 66496 (December 
15, 2009) (finding under CAA section 202(a) that elevated 
concentrations of six key well-mixed GHGs may reasonably be 
anticipated to endanger the public health and welfare of current and 
future generations); 81 FR 54421 (August 15, 2016) (making a similar 
finding under CAA section 231(a)(2)(A)).
    \137\ This is consistent with EPA's analysis of the same 
statutory factor in the 2020-2022 Rule. See ``Renewable Fuel 
Standard (RFS) Program: RFS Annual Rules--Regulatory Impact 
Analysis,'' EPA-420-R-22-008, June 2022, pp 65-96.
---------------------------------------------------------------------------

    To support the GHG emission reduction goals of EISA, Congress 
required that biofuels used to meet the RFS obligations achieve certain 
GHG reductions based on a lifecycle analysis (LCA). To qualify as a 
renewable fuel under the RFS program, a fuel must be produced from 
approved feedstocks and have lifecycle GHG emissions that are at least 
20 percent less than the baseline petroleum-based gasoline and diesel 
fuels. The CAA defines lifecycle emissions in section 211(o)(1)(H) to 
include the aggregate quantity of significant direct and indirect 
emissions associated with all stages of fuel production and use. 
Advanced biofuels and biomass-based diesel are required to have 
lifecycle GHG emissions that are at least 50 percent less than the 
baseline fuels,\138\ while cellulosic biofuel is required to have 
lifecycle emissions at least 60 percent less than the baseline 
fuels.\139\ Congress also allowed for facilities that existed or were 
under construction when the EISA was enacted to be grandfathered into 
the RFS program and exempt from the lifecycle GHG emission reduction 
requirements.\140\
---------------------------------------------------------------------------

    \138\ CAA Sections 211(o)(1)(B)(i) and 211(o)(1)(D).
    \139\ CAA Section 211(o)(1)(E).
    \140\ CAA Section 211(o)(2)(A)(i).
---------------------------------------------------------------------------

    In the proposed rule, we presented biofuel LCA estimates from a 
range of published values from the scientific/technical literature. We 
are using the same approach as the proposed rule, whereby we multiply 
the lifecycle emissions value for each individual fuel by the change in 
the volume of that fuel to quantify the GHG impacts. We repeat this 
process for each fuel (e.g., corn ethanol, soybean biodiesel, landfill 
biogas CNG) to estimate the overall GHG impacts of the candidate 
volumes. We provide a high and low estimate of the potential GHG 
impacts of each pathway (combination of biofuel type, feedstock, and 
production process) based on the range of published LCA estimates from 
the scientific literature. We then use this range of values for 
considering the GHG impacts of the renewable fuel volumes that change 
relative to the No RFS baseline described in Section III. Specifically, 
we use the LCA ranges to develop an illustrative scenario of the GHG 
impacts, which is described and presented in RIA Chapter 4.2.3.\141\
---------------------------------------------------------------------------

    \141\ To be more precise, for the crop-based biofuel pathways we 
use the range of LCA estimates that include an annual stream of 
emissions, which are based on the modeling for the March 2010 RFS2 
rule.
---------------------------------------------------------------------------

    To develop the range of LCA values, we conducted a high-level 
review of relevant literature for the biofuel pathways that would be 
most likely to satisfy the candidate renewable fuel volumes, as well as 
the petroleum-based fuels they are used to replace or reduce. Based on 
our review, we compiled the LCA estimates in the literature for each 
pathway. We include estimates from peer-reviewed journal articles, 
authoritative governmental reports, and other credible publications, 
such as studies by non-governmental organizations. Given that all LCA 
studies and models have particular strengths and weaknesses, as well as 
uncertainties and limitations, our goal for this compilation of 
literatures estimates is to consider the ranges of published estimates, 
not to adjudicate which particular studies, estimates or assumptions 
are most appropriate. Reflecting the many approaches to LCA and 
associated assumptions and uncertainties, our review is intentionally 
broad and inclusive of a wide range of estimates based on a variety of 
study types and assumptions. We focused on LCA estimates for the 
average type of each fuel produced in the United States.\142\ For 
example, for corn ethanol, we focused on estimates for average corn 
ethanol production from natural gas-fired dry mill facilities, as that 
is the predominant mode of corn ethanol production in the United 
States.\143\
---------------------------------------------------------------------------

    \142\ We note that lifecycle GHG emissions are also influenced 
by the use of advanced technologies and improved production 
practices. For example, corn ethanol produced with the adoption of 
advanced technologies or climate smart agricultural practices can 
lower LCA emissions. Corn ethanol facilities produce a highly 
concentrated stream of CO2 that lends itself to carbon 
capture and sequestration (CCS). CCS is being deployed at ethanol 
plants and has the potential to reduce emissions for corn-starch 
ethanol, especially if mills with CCS use renewable sources of 
electricity and other advanced technologies to lower their need for 
thermal energy. Climate smart farming practices are being gradually 
adopted at the feedstock production stage and can lower the GHG 
intensity of biofuels. For example, reducing tillage, planting cover 
crops between rotations, and improving nutrient use efficiency can 
build soil organic carbon stocks and reduce nitrous oxide emissions.
    \143\ Lee, U., et al. (2021). ``Retrospective analysis of the US 
corn ethanol industry for 2005-2019: implications for greenhouse gas 
emission reductions.'' Biofuels, Bioproducts and Biorefining.
---------------------------------------------------------------------------

    We made minor changes to the LCA ranges used in the proposed rule. 
We reviewed the public comments and searched the literature to identify 
new or additional studies to add to our review. However, public 
commenters did not identify any additional LCA estimates that we had 
not already considered. Likewise, our updated search of the literature 
did not identify any additional estimates. The one update we made was 
replacing estimates from the 2021 version of the Greenhouse gases, 
Regulated Emissions, and Energy use in Technologies (GREET) Model with 
estimates from the

[[Page 44501]]

2022 version. Some of the public comments recommended removing some of 
the studies considered in the proposed rule. We considered these 
comments carefully but decided not to remove any of the studies 
considered in the proposed rule as they meet the broad criteria for our 
compilation of published estimates. We discuss these comments and our 
reasoning in the summary and analysis of comments document that is part 
of this rulemaking package.
    The ranges of values in our compilation vary considerably for 
different types of renewable fuels, particularly for crop-based 
biofuels. The ranges of estimates for non-crop based biofuel pathways 
tend to be narrower relative to the crop-based pathways (See Table 
IV.A-1).

 Table IV.A-1--Lifecycle GHG Emissions Ranges Based on Literature Review
                               [gCO2e/MJ]
------------------------------------------------------------------------
                 Pathway                             LCA range
------------------------------------------------------------------------
Petroleum Gasoline.......................  84 to 98
Petroleum Diesel.........................  84 to 94
Natural Gas CNG..........................  73 to 81
Corn Starch Ethanol......................  38 to 116
Soybean Oil Biodiesel....................  14 to 73
Soybean Oil Renewable Diesel.............  26 to 87
Used Cooking Oil Biodiesel...............  12 to 32
Used Cooking Oil Renewable Diesel........  12 to 37
Tallow Biodiesel.........................  16 to 58
Tallow Renewable Diesel..................  14 to 81
Distillers Corn Oil Biodiesel............  14 to 37
Distillers Corn Oil Renewable Diesel.....  12 to 46
Landfill Gas CNG.........................  6 to 70
Manure Biogas CNG........................  -533 to 52
------------------------------------------------------------------------

2. Description of Separate Model Comparison Exercise
    This section describes a model comparison exercise that we 
conducted for the purpose of advancing our understanding of available 
models and science related to the GHG impacts of biofuel consumption. 
We requested comment on a number of issues related to the model 
comparison exercise, including the approach for conducting the model 
comparison. At the time of proposal, we were contemplating using the 
model comparison exercise to inform the final rule.\144\ However, we 
did not ultimately rely on the model comparison exercise to evaluate 
the candidate volumes or to inform the volumes in this final rule. The 
model comparison exercise highlighted areas of uncertainty across the 
models used, a wide range of estimated GHG impacts, and areas for 
further research. Work to refine models to inform future rulemakings is 
ongoing. We want to engage with stakeholders and receive feedback on 
the MCE before deciding how to use any results in a rulemaking context. 
While we did not ultimately rely on the model comparison exercise to 
evaluate the candidate volumes or to inform the volumes in this final 
rule, we describe it here solely for informational purposes, as readers 
of Section IV.A may be interested in the technical information provided 
through this separate exercise.
---------------------------------------------------------------------------

    \144\ See 87 FR 80582, 80611 (December 30, 2022).
---------------------------------------------------------------------------

    In the March 2010 RFS2 rule (75 FR 14670) and in subsequent agency 
actions, EPA estimated the lifecycle GHG emissions from different 
biofuel production pathways; that is, the emissions associated with the 
production and use of a biofuel, including indirect emissions, on a 
per-unit energy basis. Since the existing LCA methodology was developed 
for the March 2010 RFS2 rule, there has been more research on the 
lifecycle GHG emissions associated with transportation fuels. While our 
existing LCA estimates for the RFS program remain within the range of 
more recent estimates, we acknowledge that the biofuel GHG modeling 
framework EPA has previously relied upon is old, and that a better 
understanding of these newer models and data is needed. In the proposed 
rule, we did not propose to reopen the related aspects of the 2010 RFS2 
rule or any prior EPA lifecycle greenhouse gas analyses, methodologies, 
or actions, as that is beyond the scope of this rulemaking. While 
updating our LCA methodology is beyond the scope of this rulemaking, to 
make this information available to the public we are including the 
outcome of a model comparison exercise by placing it in the docket for 
this rulemaking in the document titled, ``Model Comparison Exercise 
Technical Document.''
    The model comparison exercise has three main goals: (1) Advance the 
science in the area of analyzing the lifecycle greenhouse gas emissions 
impacts from increasing use of biofuel; (2) Identify and understand 
differences in scope, coverage, and key assumptions in each model, and 
to the extent possible the impact that those differences have on the 
appropriateness of using a given model to evaluate the GHG impacts of 
biofuels; and (3) Understand how differences between models and data 
sources lead to varying results. As we designed and conducted the model 
comparison exercise, we consulted with our colleagues within the USDA 
and DOE.
    Following the proposed rule, the National Academies of Sciences, 
Engineering, and Medicine (NASEM) published a report titled ``Current 
Methods for Life Cycle Analyses of Low-Carbon Transportation Fuels in 
the United States.'' The conclusions and recommendations from the NASEM 
report support our motivations for conducting the model comparison. In 
particular, recommendation 4-2 from the report states, ``Current and 
future LCFS [low carbon fuel standard] policies should strive to reduce 
model uncertainties and compare results across multiple economic 
modeling approaches and transparently communicate uncertainties.'' 
Consistent with this and other recommendations in the NASEM report, our 
model comparison exercise compares results from multiple models, and we 
strive to transparently consider parameter, scenario and model 
uncertainties.
    LCA plays several diverse roles in the context of the RFS program. 
Under Section 211(o)(2)(B)(ii)(I) of the CAA, EPA is required to 
analyze the climate change impacts of this rule and other RFS rules 
that establish the renewable fuel standards subject to the requirements 
of CAA section 211(o)(2)(B)(ii). This work is related to, but distinct 
from, EPA's responsibility to determine which biofuel pathways satisfy 
the lifecycle GHG reduction thresholds corresponding with the four 
categories of renewable fuel. The model comparison exercise does not 
support these analytical needs at this time, but the insights on 
modeling and science from this exercise may inform future analytical 
efforts on both of these topics. Our work related to biofuel GHG 
modeling and lifecycle analysis will continue after this rulemaking.
    For the model comparison exercise we selected five models, listed 
below in alphabetical order, that provide different insights into the 
climate change impacts of crop-based biofuel production. First, the 
Applied Dynamic Analysis of the Global Economy (ADAGE) model, is an 
economic model that includes all sectors of the economy, including 
agriculture, bioenergy, and transportation. Second, the Global Change 
Analysis Model (GCAM), simulates the world's energy, water, 
agriculture, land, climate and economic systems. Third, the Global 
Biosphere Management Model (GLOBIOM) is an economic model of the 
agricultural, forest and bioenergy sectors. Fourth, the Greenhouse 
gases, Regulated Emissions, and Energy use in Technologies (GREET) 
Model is a lifecycle analysis model that estimates the well-to-wheels 
impacts of transportation technologies.

[[Page 44502]]

Finally, the Global Trade Analysis Project (GTAP) model is a general 
equilibrium model of all sectors of the economy. We selected these 
models based on our many years of experience with biofuel GHG modeling 
and based on stakeholder input, including the proceedings and public 
comments associated with the biofuel GHG modeling workshop that we 
hosted on February 28-March 1, 2022 (86 FR 73756).\145\
---------------------------------------------------------------------------

    \145\ Because the biofuel GHG modeling workshop was not used in 
any way to inform this rulemaking, we have not included any of the 
documents from that event as part of the record for this rulemaking.
---------------------------------------------------------------------------

    In order to facilitate a comparison of the five models, we ran 
common scenarios through each of them. We defined a purely hypothetical 
reference case, for modeling purposes only, with U.S. biofuel 
consumption volumes from 2020-2050 set at their average level from 
2016-2019 (e.g., approximately 14.8 billion gallons of corn ethanol and 
1.2 billion gallons of soybean oil biodiesel). We then simulated a corn 
ethanol shock scenario in which the U.S. consumes an additional one 
billion gallons of corn ethanol in 2030 and in each year after that 
through 2050, with all other U.S. biofuel volumes set at the reference 
scenarios levels. We also simulated a similar soy biodiesel shock 
scenario where the U.S. consumes an additional one billion gallons of 
soybean oil biodiesel in the same time frame. For the dynamic models 
(i.e., ADAGE, GCAM, GLOBIOM), we simulated the shocks as increasing 
linearly from 2020 to 2030, and then held the shocks constant at their 
2030 levels through 2050.
    While the details of the model comparison results are discussed in 
the Model Comparison Exercise Technical Document, we conclude this 
section by summarizing some of our broad conclusions from this 
exercise. Supply chain LCA models, such as GREET, produce a 
fundamentally different analysis than economic models. Supply chain LCA 
models evaluate the GHG emissions emanating from a particular supply 
chain, whereas economic models evaluate the GHG impacts of a change in 
biofuel consumption. Estimates of land use change vary significantly 
among the models used in this study. Drivers of variation in these 
estimates include differences in assumptions related to trade, the 
substitutability of food and feed products, and land conversion, as 
well as structural differences in how models represent land categories. 
Economic modeling of the energy sector may be required to avoid 
overestimating the emissions reduction from fossil fuel consumption. 
Model trade structure and assumed flexibility influence the modeled 
emissions results. The degree to which other vegetable oils replace 
soybean oil diverted to fuel production from other markets can impact 
GHG emissions associated with soybean oil biodiesel. The ability to 
endogenously consider tradeoffs between intensification and 
extensification is an important capability for estimating the emissions 
associated with an increase in biofuel consumption. Models included in 
the model comparison exercise produced a wider range of LCA GHG 
estimates for soybean oil biodiesel than corn ethanol. The models show 
much greater diversity in feedstock sourcing strategies for soybean oil 
biodiesel than they do for corn ethanol, and this wider range of 
options contributes to greater variability in the GHG results. 
Sensitivity analysis, which considers uncertainty within a given model, 
can help identify which parameters influence model results. However, 
pinpointing the direct causes of why one estimate differs from another 
would require additional research.

B. Energy Security

    Another factor that we are required under the statute to analyze is 
energy security. Changes in the required volumes of renewable fuel can 
affect the financial and strategic risks associated with U.S. imports 
of petroleum, which in turn would have a direct impact on the U.S.' 
national energy security.
    The candidate volumes for the years 2023-2025 would represent 
increases in comparison to previous years and, also, increases in 
comparison to a No RFS baseline. Increasing the use of renewable fuels 
in the U.S. displaces domestic consumption of petroleum-based fuels, 
which results in a reduction in U.S. imports of petroleum and 
petroleum-based fuels. A reduction of U.S. petroleum imports reduces 
both financial and strategic risks caused by potential sudden 
disruptions in the supply of imported petroleum to the U.S., thus 
increasing U.S. energy security.
    Energy security and energy independence are distinct but related 
concepts. U.S. energy security is commonly defined as the continued 
availability of energy sources at an acceptable price.\146\ The goal of 
U.S. energy independence is the elimination of all U.S. imports of 
petroleum and other foreign sources of energy, or more broadly, 
reducing the sensitivity of the U.S. economy to energy imports and 
foreign energy markets.\147\ Most discussions of U.S. energy security 
revolve around the topic of the economic costs of U.S. dependence on 
oil imports.
---------------------------------------------------------------------------

    \146\ IEA. Energy Security: Reliable, affordable access to all 
fuels and energy sources. 2019. December.
    \147\ Greene, D. 2010. Measuring energy security: Can the United 
States achieve oil independence? Energy Policy 38. pp. 164-1621.
---------------------------------------------------------------------------

    The U.S.' oil consumption had been gradually increasing in recent 
years (2015-2019) before dropping dramatically as a result of the 
COVID-19 pandemic in 2020.\148\ Domestic oil consumption in 2022 
rebounded to pre-COVID-19 levels and is expected to modestly decline 
during the timeframe of this final rule, 2023-2025.\149\ The U.S. has 
increased its production of oil, particularly ``tight'' (i.e., shale) 
oil, over the last decade.\150\ Mainly as a result of this increase, 
the U.S. became a net exporter of crude oil and petroleum-based 
products in 2020 and is now projected to be a net exporter of crude oil 
and petroleum-based products during the time frame of this final rule, 
2023-2025.151 152 This is a significant reversal of the 
U.S.' net export position since the U.S. had been a substantial net 
importer of crude oil and petroleum-based products starting in the 
early 1950s.\153\
---------------------------------------------------------------------------

    \148\ U.S. Energy Information Administration. 2023. Total 
Energy. Monthly Energy Review. Table 3.1. Petroleum Overview. March.
    \149\ U.S. Energy Information Administration. 2023. Annual 
Energy Outlook 2023. Reference Case. Table A11. Petroleum and Other 
Liquids Supply and Disposition.
    \150\ https://www.eia.gov/energyexplained/oil-and-petroleum-products/images/u.s.tight_oil_production.jpg.
    \151\ https://www.eia.gov/energyexplained/oil-and-petroleum-products/imports-and-exports.php.
    \152\ U.S. Energy Information Administration. 2023. Annual 
Energy Outlook 2023. Reference Case. Table A11. Petroleum and Other 
Liquids Supply and Disposition.
    \153\ EIA https://www.eia.gov/energyexplained/oil-and-petroleum-products/imports-and-exports.php.
---------------------------------------------------------------------------

    In the beginning of 2022, world oil prices rose fairly rapidly. For 
example, as of January 3rd, 2022, the West Texas Intermediate (WTI) 
crude oil price was roughly $76 per barrel.\154\ The WTI oil price 
increased to roughly $124 per barrel on March 8th, 2022, a 63 percent 
increase.\155\ High and volatile oil prices in the first half of 2022 
were a result of oil supply concerns with Russia's invasion of Ukraine 
on February 24th, 2022 contributing to crude oil price increases.\156\ 
Russia's invasion of Ukraine came during eight consecutive

[[Page 44503]]

quarters (from the third quarter of 2020 to the second quarter of 2022) 
of global crude oil inventory decreases.\157\ The lower inventory of 
crude oil stocks were the result of rising economic activity after 
COVID-19 pandemic restrictions were eased. Oil prices drifted downwards 
throughout the second half of 2022 and early 2023. As of March 13th, 
2023, the WTI crude oil price was roughly $75/barrel.\158\
---------------------------------------------------------------------------

    \154\ U.S. Energy Information Administration. 2022. Petroleum 
and Other Liquids: Spot Prices. https://www.eia.gov/dnav/pet/pet_pri_spt_s1_d.htm.
    \155\ Id.
    \156\ U.S. Energy Information Administration. Today in Energy. 
Crude oil prices increased in the first half of 2022 and declined in 
the second half of 2022. January.
    \157\ Id.
    \158\ EIA. Petroleum and Other Liquids Spot Prices. https://www.eia.gov/dnav/pet/pet_pri_spt_s1_d.htm.
---------------------------------------------------------------------------

    Geopolitical disruptions that occurred in 2022 are likely to 
continue to affect global trade of crude oil and petroleum products in 
2023 and beyond. In response to Russia's invasion of Ukraine in late 
February 2022, the U.S. and many of its allies, particularly in Europe, 
announced various sanctions against Russia's petroleum industry.\159\ 
For the European Union (EU), petroleum from Russia had accounted for a 
large share of all energy imports, but the EU banned imports of crude 
oil from Russia starting in December 2022 and imports of petroleum 
products starting in February 2023.\160\ Given recent oil market 
trends, the U.S. set a new record for petroleum product exports in 
2022, up 7% from 2021.\161\ It is not clear to what extent the current 
oil price volatility will continue, increase, or be transitory in the 
2023-2025 time period addressed by this rule.
---------------------------------------------------------------------------

    \159\ U.S. Energy Information Administration. 2023. Today in 
Energy. U.S. Petroleum product exports set a record high in 2022. 
March.
    \160\ Id.
    \161\ Id.
---------------------------------------------------------------------------

    Although the U.S. is projected to be a net exporter of crude oil 
and petroleum-based products over the 2023-2025 timeframe, energy 
security remains a concern. U.S. refineries still rely on significant 
imports of heavy crude oil which could be subject to supply 
disruptions. Also, oil exporters with a large share of global 
production have the ability to raise or lower the price of oil by 
exerting their market power through the Organization of Petroleum 
Exporting Countries (OPEC) to alter oil supply relative to demand. 
These factors contribute to the vulnerability of the U.S. economy to 
episodic oil supply shocks and price spikes, even when the U.S. is 
projected to be an overall net exporter of crude oil and petroleum-
based products.
    In order to understand the energy security implications of reducing 
U.S. oil imports, EPA has worked with Oak Ridge National Laboratory 
(ORNL), which has developed approaches for evaluating the social costs/
impacts and energy security implications of oil use, labeled the oil 
import or oil security premium. ORNL's methodology estimates two 
distinct costs/impacts of importing petroleum into the U.S., in 
addition to the purchase price of petroleum itself: first, the risk of 
reductions in U.S. economic output and disruption to the U.S. economy 
caused by sudden disruptions in the supply of imported oil to the U.S. 
(i.e., the macroeconomic disruption/adjustment costs); and secondly, 
the impacts that changes in U.S. oil imports have on overall U.S. oil 
demand and subsequent changes in the world oil price (i.e., the 
``demand'' or ``monopsony'' impacts).\162\
---------------------------------------------------------------------------

    \162\ Monopsony impacts stem from changes in the demand for 
imported oil, which changes the price of all imported oil.
---------------------------------------------------------------------------

    For this final rule, as has been the case for past EPA rulemakings 
under the RFS program, we consider the monopsony component estimated by 
the ORNL methodology to be a transfer payment, and thus exclude it from 
the estimated quantified benefits of the candidate volumes.\163\ Thus, 
we only consider the macroeconomic disruption/adjustment cost component 
of oil import premiums (i.e., labeled macroeconomic oil security 
premiums below), estimated using ORNL's methodology.
---------------------------------------------------------------------------

    \163\ See the RIA for more discussion of EPA's assessment of 
monopsony impacts of this final rule. Also, see the previous EPA GHG 
vehicle rule for a discussion of monopsony oil security premiums, 
e.g., Section 3.2.5, Oil Security Premiums Used for this Rule, RIA, 
Revised 2023 and Later Model Year Light-Duty Vehicle GHG Emissions 
Standards, December 2021, EPA-420-F-21-077.
---------------------------------------------------------------------------

    For this final rule, EPA and ORNL have worked together to revise 
the oil import premiums based upon recent energy security literature 
and the most recently available oil price projections and energy market 
and economic trends from EIA's 2023 Annual Energy Outlook.\164\ We do 
not consider military cost impacts from reduced oil use from the 
candidate volumes due to methodological issues in quantifying these 
impacts. A discussion of the difficulties in quantifying military cost 
impacts is in RIA Chapter 5.
---------------------------------------------------------------------------

    \164\ See RIA Chapter 5.4.2 for how the macroeconomic oil 
security premiums have been updated based upon a review of recent 
energy security literature on this topic.
---------------------------------------------------------------------------

    To calculate the energy security benefits of the candidate volumes, 
we are using the ORNL macroeconomic oil security premiums combined with 
estimates of annual reductions in aggregate net U.S. crude oil imports/
petroleum product imports as a result of the candidate volumes. A 
discussion of the methodology used to estimate changes in U.S. annual 
net crude oil imports/petroleum product imports from the candidate 
volumes is provided in RIA Chapter 5. Table IV.B-1 below presents the 
macroeconomic oil security premiums and the total energy security 
benefits for the candidate volumes for 2023-2025.

   Table IV.B-1--Macroeconomic Oil Security Premiums and Total Energy
                   Security Benefits for 2023-2025 \a\
------------------------------------------------------------------------
                                 Macroeconomic oil
                                 security premiums       Total energy
             Year                 (2022$/barrel of    security benefits
                                  reduced imports)     (millions 2022$)
------------------------------------------------------------------------
2023 (Including the                           $3.75                 $192
 supplemental standard).......        ($0.86-$6.81)           ($44-$349)
2023 (Excluding the                           $3.75                 $180
 supplemental standard).......        ($0.86-$6.81)           ($41-$326)
2024..........................                $3.70                 $173
                                      ($0.69-$6.87)           ($32-$321)
2025..........................                $3.67                 $187
                                      ($0.65-$6.87)           ($33-$350)
------------------------------------------------------------------------
\a\ Top values in each cell are the mean values, while the values in
  parentheses define 90 percent confidence intervals.

[[Page 44504]]

C. Costs

    We assessed the cost impacts for the renewable fuels expected to be 
used for the candidate volumes relative to a No RFS baseline, described 
in Section III.D.1. Table III.E-1 provides a summary of the volume 
changes that we project would occur if the candidate volumes were to be 
established as applicable volume requirements for 2023-2025, and it is 
these volume changes relative to the No RFS baseline which we analyzed 
for costs.
1. Methodology
    This section provides a brief discussion of the methodology used to 
estimate the costs of the candidate volume changes over the years of 
2023-2025. A more detailed discussion of how we estimated the renewable 
fuel costs, as well as the fossil fuel costs being displaced, is 
contained in RIA Chapter 10.
    The cost analysis compares the cost of an increase in biofuel to 
the cost of the fossil fuel it displaces. There are various components 
to the cost of each biofuel:
     Production cost: biofuel feedstock cost is usually the 
prominent factor.
     Distribution cost: Because the biofuel often has a 
different energy density, the distribution costs are estimated all the 
way to the point of use to capture the full fuel economy effect of 
using these fuels.
     Blending value: In the case of ethanol blended as E10, 
there is a blending value that mostly incorporates ethanol's octane 
value realized by lower gasoline production costs, but also a 
volatility cost that accounts for ethanol's blending volatility in RVP 
controlled gasoline.
     Retail infrastructure cost: In the case of higher ethanol 
blends, there is a retail cost since retail stations usually need to 
add equipment or use compatible materials to enable the sale of these 
newer fuels.
     Fuel economy cost: different fuels have different energy 
content leading to different fuel economy which impacts the relative 
fossil fuel volume being displaced and the cost to the consumer.
    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 the biofuels is used to estimate 
the net cost of the increased use of biofuels. Unlike for biofuels, 
however, we did not calculate production costs for the fossil fuels 
since their production costs are inherent in the wholesale price 
projections provided by the Energy Information Administration in its 
Annual Energy Outlook 2023.
2. Estimated Cost Impacts
    In this section, we summarize the overall results of our cost 
analysis based on changes in the use of renewable fuels which displace 
fossil fuel use. The renewable fuel costs presented here do not reflect 
any tax subsidies for renewable fuels which might be in effect, since 
such subsidies are transfer payments which are not relevant under a 
societal cost analysis.\165\ A detailed discussion of the renewable 
fuel costs relative to the fossil fuel costs is contained in RIA 
Chapter 10.
---------------------------------------------------------------------------

    \165\ Note that in developing the No RFS baseline we did 
consider available subsidies other than those provided by the RFS 
program in determining the volume of renewable fuels that would be 
used in the absence of the RFS program.
---------------------------------------------------------------------------

    For each year for which we are finalizing volumes, Table IV.C.2-1 
provides the total annual cost of the candidate volumes while Table 
IV.C.2-2 provides the per-unit cost (per gallon or per thousand cubic 
feet) of the biofuel. For the year 2023 costs, the estimated costs are 
shown both without and with the costs associated with the Supplemental 
Standard renewable fuel volume. For both the total and per-unit cost, 
the cost of the total change in renewable fuel volume is expressed over 
the gallons of the respective fossil fuel in which it is blended. For 
example, the costs associated with corn ethanol relative to that of 
gasoline are reflected as a cost over the entire gasoline pool, and 
biodiesel and renewable diesel costs are reflected as a cost over the 
diesel fuel pool. Biogas displaces natural gas use as CNG in trucks, so 
it is reported relative to natural gas supply.

                                       Table IV.C.2-1--Total Social Costs
                                           [Million 2022 dollars] \a\
----------------------------------------------------------------------------------------------------------------
                                                                     2023 with
                                                       2023        supplemental        2024            2025
                                                                     standard
----------------------------------------------------------------------------------------------------------------
Gasoline........................................             445             445             423             458
Diesel..........................................           7,610           8,238           6,775           7,769
Natural Gas.....................................              55              55             137             228
                                                 ---------------------------------------------------------------
    Total.......................................           8,110           8,738           7,352           8,455
----------------------------------------------------------------------------------------------------------------
\a\ Total cost of the renewable fuel expressed over the fossil fuel it is blended into.

                           Table IV.C.2-2--Per-Gallon or Per-Thousand Cubic Feet Costs
                                                 [2022 dollars]
----------------------------------------------------------------------------------------------------------------
                                                                     2023 with
                                      Units            2023        supplemental        2024            2025
                                                                     standard
----------------------------------------------------------------------------------------------------------------
Gasoline......................  [cent]/gal......            0.33            0.33            0.31            0.34
Diesel........................  [cent]/gal......           13.56           14.68           12.70           14.69
Natural Gas...................  [cent]/thousand            0.175           0.175           0.455           0.765
                                 ft \3\.
Gasoline and Diesel...........  [cent]/gal......            4.26            4.59            3.90            4.55
----------------------------------------------------------------------------------------------------------------
\a\ Per-gallon or per thousand cubic feet cost of the renewable fuel expressed over the fossil fuel it is
  blended into; the last row expresses the cost over the obligated pool of gasoline and diesel fuel.

[[Page 44505]]

    The biofuel costs are higher than the costs of the gasoline, 
diesel, and natural gas that they displace as evidenced by the 
increases in fuel costs shown in the above table associated with the 
candidate volumes. The estimated costs estimated for this final 
rulemaking are much lower than that estimated for the proposed 
rulemaking due to two primary factors. The first is that crude oil 
prices from Annual Energy Outlook 2023, which we used to estimate costs 
for the FRM, are much higher than that of the proposal which was based 
on the previous version of the AEO. Higher crude oil prices reduce the 
relative cost of renewable fuels. The second reason is because of the 
higher crude oil prices, greater volume of biodiesel and renewable 
diesel is found to be economic for the No RFS baseline, and so the 
candidate volumes present a smaller increase in renewable fuels volume 
relative to the No RFS baseline. As described more fully in RIA Chapter 
10, our assessment of costs did not yield a specific threshold value 
below which the incremental costs of biofuels are reasonable and above 
which they are not. In Section VI we consider these directional 
inferences along with those for the other factors that we analyzed in 
the context of our discussion of the volumes for 2023-2025.
3. Cost To Transport Goods
    We also estimated the impact of the candidate volumes on the cost 
to transport goods. However, it is not appropriate to use the social 
cost for this analysis because the social costs are effectively reduced 
by the cellulosic and biodiesel subsidies and other market factors. The 
per-unit costs from Table IV.C.2-2 are adjusted with estimated RIN 
prices that account for the biofuel subsidies and other market factors, 
and the resulting values can be thought of as retail costs. Consistent 
with our assessment of the fuels markets, we have assumed that 
obligated parties pass through their RIN costs to consumers and that 
fuel blenders reflect the RIN value of the renewable fuels in the price 
of the blended fuels they sell. More detailed information on our 
estimates of the fuel price impacts of this rule can be found in RIA 
Chapter 10.5. Table IV.C.3-1 summarizes the estimated impacts of the 
candidate volumes on gasoline and diesel fuel prices at retail when the 
costs of each biofuel is amortized over the fossil fuel it displaces.

                       Table IV.C.3-1--Estimated Effect of Biofuels on Retail Fuel Prices
                                                  [[cent]/gal]
----------------------------------------------------------------------------------------------------------------
                                                                       2023            2024            2025
----------------------------------------------------------------------------------------------------------------
Relative to No RFS Baseline:
    Gasoline....................................................             2.4             3.2             4.3
    Diesel......................................................            10.1            10.1            11.1
Relative to 2022 Baseline:
    Gasoline....................................................             0.0             0.0             0.0
    Diesel......................................................             0.0            -0.4            -0.1
----------------------------------------------------------------------------------------------------------------

    For estimating the cost to transport goods, we focus on the impact 
on diesel fuel prices since trucks which transport goods are normally 
fueled by diesel fuel. Reviewing the data in Table IV.C.3-1, the 
largest projected price increase is 11.1[cent] per gallon for diesel 
fuel in 2025 for the No RFS baseline.
    The impact of fuel price increases on the price of goods can be 
estimated based upon a study conducted by the United States Department 
of Agriculture (USDA) which analyzed the impact of fuel prices on the 
wholesale price of produce.\166\ Applying the price correlation from 
the USDA study would indicate that the 11.1[cent] per gallon diesel 
fuel cost increment associated with the 2025 RFS volumes which 
increases retail prices by about 2.8 percent, would then increase the 
wholesale price of produce by about 0.7 percent. If produce being 
transported by a diesel truck costs $3 per pound, the increase in that 
product's price would be $0.02 per pound.\167\ If the estimated program 
price impacts are averaged over the combined gasoline and diesel fuel 
pool, the impact on produce prices would be proportionally lower based 
on the lower per-gallon cost.
---------------------------------------------------------------------------

    \166\ Volpe, Richard; How Transportation Costs Affect Fresh 
Fruit and Vegetable Prices; United States Department of Agriculture; 
November 2013.
    \167\ Comparing Prices on Groceries; May 4, 2021: http://www.coupons.com/thegoodstuff/comparing-prices-on-groceries.
---------------------------------------------------------------------------

D. Comparison of Impacts

    As explained in Section III of this rule, for those factors for 
which we quantified the impacts of the candidate volumes for 2023-2025, 
the impacts were based on the difference in the volumes of specific 
renewable fuel types between the candidate volumes and the No RFS 
baseline. The No RFS baseline assumes the RFS program remains intact 
through 2022 but ceases to exist thereafter. As explained in Section 
VI, we then go on to finalize these candidate volumes after evaluating 
them against the statutory factors. Congress provided EPA flexibility 
by enumerating factors to consider without rigidly mandating the 
specific steps or manner of analysis that EPA should undertake, 
including whether the assessment must be quantitative or qualitative. 
For two of the statutory factors (fuel costs and energy security 
benefits) we were able to quantify and monetize the expected impacts of 
the candidate volumes.\168\ Information and specifics on how fuel costs 
are calculated are presented in RIA Chapter 10, while energy security 
benefits are discussed in RIA Chapter 5. Summaries of the fuel costs 
and energy security benefits are shown in Tables IV.D-1 and 2. Impacts 
on other factors, such as job creation and the price and supply of 
agricultural commodities, are quantified but have not been monetized. 
Further information and the quantified impacts of the candidate volumes 
on these factors can be found in the RIA. We were not able to quantify 
many of the impacts of the candidate volumes, including impacts on many 
of the statutory factors such as the environmental impacts (water 
quality and quantity, soil quality, etc.) and rural economic 
development.
---------------------------------------------------------------------------

    \168\ Due to the uncertainty related to the GHG emission impacts 
of the volumes (discussed in further detail in RIA Chapter 4.2) we 
have not included a quantified projection of the GHG emission 
impacts of this rule.

[[Page 44506]]

                                Table IV.D-1--Fuel Costs of the 2023-2025 Volumes
                                          [2022 dollars, millions] \a\
----------------------------------------------------------------------------------------------------------------
                                                                                   Discount rate
                              Year                               -----------------------------------------------
                                                                        0%              3%              7%
----------------------------------------------------------------------------------------------------------------
2023:
    Excluding Supplemental Standard.............................          $8,110          $8,110          $8,110
    Including Supplemental Standard.............................           8,738           8,738           8,738
2024............................................................           7,352           7,138           6,871
2025............................................................           8,455           7,970           7,385
Cumulative Discounted Costs:
    Excluding Supplemental Standard.............................          23,917          23,218          22,366
    Including Supplemental Standard.............................          24,545          23,846          22,994
----------------------------------------------------------------------------------------------------------------
\a\ These costs represent the costs of producing and using biofuels relative to the petroleum fuels they
  displace. They do not include other factors, such as the potential impacts on soil and water quality or
  potential GHG reduction benefits.

                         Table IV.D-2--Energy Security Benefits of the 2023-2025 Volumes
                                            [2022 dollars, millions]
----------------------------------------------------------------------------------------------------------------
                                                                                   Discount rate
                              Year                               -----------------------------------------------
                                                                        0%              3%              7%
----------------------------------------------------------------------------------------------------------------
2023:
    Excluding Supplemental Standard.............................            $180            $180            $180
    Including Supplemental Standard.............................             192             192             192
2024............................................................             173             168             162
2025............................................................             187             177             164
Cumulative Discounted Benefits:
    Excluding Supplemental Standard.............................             540             524             505
    Including Supplemental Standard.............................             552             536             517
----------------------------------------------------------------------------------------------------------------

    All of the statutory factors were taken under consideration, as is 
required by the statute, regardless of whether or not we were able to 
quantify or monetize the impact of the candidate volumes on each of the 
statutory factors.

E. Assessment of Environmental Justice

    Although the statute identifies a number of environmental factors 
that we must analyze as described in Section I, environmental justice 
is not explicitly included in those factors. Nonetheless as explained 
in Section II.B, EPA has discretion under the statute to consider 
environmental justice, and has chosen to do so. Specifically, EPA views 
consideration of environmental justice as an aspect of our 
consideration of the statutory factors ``the impact of the production 
and use of renewable fuels on the environment,'' ``the impact of the 
use of renewable fuels on the cost to consumers of transportation fuel 
and on the cost to transport goods,'' and ``the impact of the use of 
renewable fuels on other factors, including . . . food prices.'' (CAA 
section 211(o)(2)(B)(ii)(I), (V), (VI)). Our consideration of 
environmental justice is authorized by and supports our analysis of 
these statutory factors. However, Executive Orders 12898 (Federal 
Actions to Address Environmental Justice in Minority Populations, and 
Low-Income Populations) and 14096 (Revitalizing Our Nation's Commitment 
to Environmental Justice for All) establish federal executive policy on 
environmental justice. Its main provision directs federal agencies, to 
the greatest extent practicable and permitted by law, to make 
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. EPA defines environmental justice as the fair treatment 
and meaningful involvement of all people regardless of race, color, 
national origin, or income with respect to the development, 
implementation, and enforcement of environmental laws, regulations, and 
policies.\169\ To the extent that environmental justice (EJ) 
considerations played a role in our analysis of the candidate volumes 
and volume requirements, we considered EJ only as it affected the 
statutory factors in CAA section 211(o)(2)(B)(ii). Executive Order 
14008 (86 FR 7619; February 1, 2021) also calls on federal agencies to 
make achieving environmental justice part of their missions ``by 
developing programs, policies, and activities to address the 
disproportionately high and adverse human health, environmental, 
climate-related and other cumulative impacts on disadvantaged 
communities, as well as the accompanying economic challenges of such 
impacts.'' It also declares a policy ``to secure environmental justice 
and spur economic opportunity for disadvantaged communities that have 
been historically marginalized and overburdened by pollution and under-
investment in housing, transportation, water and wastewater 
infrastructure and health care.'' EPA also released its ``Technical 
Guidance for Assessing Environmental Justice in Regulatory Analysis'' 
(U.S. EPA, 2016) to provide recommendations that encourage analysts to 
conduct the highest quality analysis feasible, recognizing that data 
limitations, time and resource constraints, and analytic challenges 
will vary by media and circumstance.
---------------------------------------------------------------------------

    \169\ E.O. 12898, E.O. 14008, and EPA's guidances do not serve 
as the legal basis for EPA's consideration of environmental justice 
in this action. As explained above, the legal basis for EPA's 
consideration of environmental justice is found in the CAA.
---------------------------------------------------------------------------

    When assessing the potential for disproportionately high and 
adverse health or environmental impacts of regulatory actions on 
communities with environmental justice concerns, EPA strives to answer 
three broad questions:

[[Page 44507]]

     Is there evidence of potential environmental justice (EJ) 
concerns in the baseline (the state of the world absent the regulatory 
action)? Assessing the baseline allows EPA to determine whether pre-
existing disparities are associated with the pollutant(s) under 
consideration (e.g., if the effects of the pollutant(s) are more 
concentrated in some population groups).
     Is there evidence of potential EJ concerns for the 
regulatory option(s) under consideration? Specifically, how are the 
pollutant(s) and its effects distributed for the regulatory options 
under consideration?
     Do the regulatory option(s) under consideration exacerbate 
or mitigate EJ concerns relative to the baseline?
    It is not always possible to quantitatively assess these questions, 
though it may still be possible to describe them qualitatively.
    EPA's 2016 Technical Guidance does not prescribe or recommend a 
specific approach or methodology for conducting an environmental 
justice analysis, though a key consideration is consistency with the 
assumptions underlying other parts of the regulatory analysis when 
evaluating the baseline and regulatory options. Where applicable and 
practicable, EPA endeavors to conduct such an analysis. Going forward, 
EPA is committed to conducting environmental justice analysis for 
rulemakings based on a framework similar to what is outlined in EPA's 
Technical Guidance, in addition to investigating ways to further weave 
environmental justice into the fabric of the rulemaking process.
    In accordance with Executive Orders 12898 and 14008, as well as 
EPA's 2016 Technical Guidance, we have assessed demographics near 
biofuel and petroleum-based fuel facilities to identify populations 
that may be affected by changes to fuel production volumes that result 
in changes to air quality. The displacement of fuels such as gasoline 
and diesel by biofuels has positive GHG benefits which 
disproportionately benefit EJ communities. We have also considered the 
effects of the RFS program on fuel and food prices, as low-income 
populations often spend a larger percentage of their earnings on these 
commodities compared to the rest of the U.S.
1. Air Quality
    There is evidence that communities with EJ concerns are impacted by 
non-GHG emissions. Numerous studies have found that environmental 
hazards such as air pollution are more prevalent in areas where racial/
ethnic minorities and people with low socioeconomic status (SES) 
represent a higher fraction of the population compared with the general 
population.170 171 172 173 Consistent with this evidence, a 
recent study found that most anthropogenic sources of PM2.5, 
including industrial sources, and light- and heavy-duty vehicle 
sources, disproportionately affect people of color.\174\ There is also 
substantial evidence that people who live or attend school near major 
roadways are more likely to be of a minority race, Hispanic ethnicity, 
and/or low socioeconomic status.175 176 177 As this 
rulemaking would displace petroleum-based fuels with biofuels, we have 
examined near-facility demographics of biodiesel, renewable diesel, 
RNG, ethanol, and petroleum facilities.
---------------------------------------------------------------------------

    \170\ Mohai, P.; Pellow, D.; Roberts Timmons, J. (2009) 
Environmental justice. Annual Reviews 34: 405-430. https://doi.org/10.1146/annurev-environ-082508-094348.
    \171\ Rowangould, G.M. (2013) A census of the near-roadway 
population: public health and environmental justice considerations. 
Trans Res D 25: 59-67. http://dx.doi.org/10.1016/j.trd.2013.08.003.
    \172\ Marshall, J.D., Swor, K.R.; Nguyen, N.P (2014) 
Prioritizing environmental justice and equality: diesel emissions in 
Southern California. Environ Sci Technol 48: 4063-4068. https://doi.org/10.1021/es405167f.
    \173\ Marshall, J.D. (2000) Environmental inequality: air 
pollution exposures in California's South Coast Air Basin. Atmos 
Environ 21: 5499-5503. https://doi.org/10.1016/j.atmosenv.2008.02.005.
    \174\ C. W. Tessum, D. A. Paolella, S. E. Chambliss, J. S. Apte, 
J. D. Hill, J. D. Marshall (2021). PM2.5 polluters 
disproportionately and systemically affect people of color in the 
United States. Sci. Adv. 7, eabf4491.
    \175\ Rowangould, G.M. (2013) A census of the U.S. near-roadway 
population: public health and environmental justice considerations. 
Transportation Research Part D; 59-67.
    \176\ Tian, N.; Xue, J.; Barzyk. T.M. (2013) Evaluating 
socioeconomic and racial differences in traffic-related metrics in 
the United States using a GIS approach. J Exposure Sci Environ 
Epidemiol 23: 215-222.
    \177\ Boehmer, T.K.; Foster, S.L.; Henry, J.R.; Woghiren-
Akinnifesi, E.L.; Yip, F.Y. (2013) Residential proximity to major 
highways--United States, 2010. Morbidity and Mortality Weekly Report 
62(3): 46-50.
---------------------------------------------------------------------------

    Emissions of non-GHG pollutants associated with the candidate 
volumes, including, for example, PM, NOx, CO, SO2, and air 
toxics, occur during the production, storage, transport, distribution, 
and combustion of petroleum-based fuels and biofuels.\178\ EJ 
communities may be located near petroleum and biofuel production 
facilities as well as their distribution systems. Given their long 
history and prominence, petroleum refineries have been the focus of 
past research which has found that vulnerable populations near them may 
experience potential disparities in pollution-related health risk from 
that source.\179\
---------------------------------------------------------------------------

    \178\ U. S. EPA (2023) Health and environmental effects of 
pollutants discussed in chapter 4 of regulatory impact analysis 
(RIA) supporting RFS standards for 2023-2025. Memorandum from 
Margaret Zawacki to Docket No. EPA-HQ-OAR-2021-0427.
    \179\ Final Petroleum Refinery Sector Risk and Technology Review 
and New Source Performance Standards, https://www.epa.gov/sites/default/files/2016-06/documents/2010-0682_factsheet_overview.pdf.
---------------------------------------------------------------------------

    RIA Chapter 4.1 summarizes what is known about potential air 
quality impacts of the candidate volumes assessed for this rule. We 
expect that small increases in non-GHG emissions from biofuel 
production and small reductions in petroleum-based emissions would lead 
to small changes in exposure to these non-GHG pollutants for people 
living in the communities near these facilities. We do not have the 
information needed to understand the exact magnitude and direction of 
travel (i.e., how these potential pollutants drift into nearby areas) 
of facility-specific emissions associated with the candidate volumes, 
and therefore we are unable to evaluate impacts on air quality in the 
specific communities with environmental concerns near biofuel and 
petroleum facilities. However, modeled averaged facility emissions for 
biodiesel, ethanol, gasoline, and diesel production do offer some 
insight into the differences these near-facility populations may 
experience, as seen in RIA Table 4.1.1-1.
    Both biofuel facilities and petroleum refineries could see changes 
to their production output as a result of candidate volumes analyzed in 
this proposed rule, and as a result the air quality near these 
facilities may change. We examined demographics based on 2020 American 
Community Survey data near both registered biofuel facilities and 
petroleum refineries to identify any disproportionate impacts these 
volume changes may have on nearby communities with EJ concerns.\180\ 
Information on these populations and potential impacts upon them are 
further discussed in RIA Chapter 9. Several regional disparities have 
been identified in near-refinery populations. For example, people of 
color and other minority groups near petroleum and renewable diesel 
facilities are more likely to be disproportionately affected by 
production emissions from these facilities, especially in EPA Regions 
3-7 and Region 9, where a greater proportion of minorities live within 
a 5

[[Page 44508]]

kilometer radius of these facilities, compared to the regional 
averages. Some regions are also characterized by a higher proportion of 
minority populations near facilities, though none more consistently 
than Regions 4, 6, 7, and 9, which are regions that contain the 
majority of petroleum facilities and the majority of facilities that 
are near large population centers. Ethanol and RNG facilities are seen 
as lower risk compared to soy biodiesel from a demographic perspective, 
as many ethanol and RNG facilities are in sparsely populated areas or 
have lower impacts on air quality. RNG facilities introduced to the RFS 
program may also reduce production emissions by processing otherwise 
flared biogas in some cases, making the effect of facility production 
emissions on nearby populations unclear. The candidate volumes by and 
large would not result in significantly greater production of corn 
ethanol or biogas than exists already, and therefore we would not 
expect appreciable adverse impacts on communities with EJ concerns near 
facilities that are currently producing ethanol or upgrading biogas to 
RNG during the timeframe of this rule.
---------------------------------------------------------------------------

    \180\ U.S. EPA (2014). Risk and Technology Review--Analysis of 
Socio-Economic Factors for Populations Living Near Petroleum 
Refineries. Office of Air Quality Planning and Standards, Research 
Triangle Park, North Carolina. Jan. 6, 2014.
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2. Other Environmental Impacts
    As discussed in RIA Chapter 4.5, the increases in renewable fuel 
volumes--particularly corn ethanol and soy renewable diesel--that may 
result from the candidate volumes can impact water and soil quality, 
which could in turn have disproportionate impacts on communities of 
concern. In addition, biogas used that is upgraded to RNG may have 
localized soil or water impacts. The associated manure collection and 
agricultural anaerobic digesters may decrease pathogen risk in water, 
but without proper treatment, excess nutrient pollution can also be a 
concern.
3. Economic Impacts
    The candidate volumes could have an impact on food and fuel prices 
nationwide, as discussed in RIA Chapters 8.5 and 10.5. We estimate that 
the candidate volumes would result in food prices that are 0.72 percent 
higher in 2023, 0.63 percent higher in 2024, and 0.55 percent higher in 
2025, than the food prices we project with the No RFS baseline. The 
impacts on food prices decline with the projected decline in commodity 
prices in future years. These food price impacts are in addition to the 
higher costs to transport all goods, including food, discussed in 
Section IV.C.3. These impacts, while generally small, are borne more 
heavily by low-income populations, as they spend a disproportionate 
amount of their income on goods in these categories. For instance, 
those in the bottom two quintiles of consumer income in the U.S. are 
more likely to be black, women, and people with a high school education 
or less, while also spending a proportionally larger fraction of their 
income on food and fuel. The lowest quintile of consumer units by 
income will spend 16 percent of their income on food as a result of the 
RFS program, up from 15.8 percent currently, while the second lowest 
quintile of consumer units by income will spend 13.4 percent of their 
income on food as a result of the RFS program, up from 13.2 percent 
currently. These absolute values can be seen in Table IV.E.3-1.

                       Table IV.E.3-1--Impact on Total Expenditures of Food and Fuel \181\
----------------------------------------------------------------------------------------------------------------
                                                                       2023            2024            2025
----------------------------------------------------------------------------------------------------------------
                                               All Consumer Units
----------------------------------------------------------------------------------------------------------------
Food Expenditures...............................................          $8,289          $8,289          $8,289
Percent Impact on Food Expenditures.............................           0.61%           0.50%           0.44%
Projected Food Expenditure Increase.............................          $50.56          $41.45          $36.59
Fuel Expenditures...............................................          $2,148          $2,148          $2,148
Percent Impact on Fuel Expenditures.............................           0.79%           1.23%           1.73%
Projected Fuel Expenditure Increase.............................          $16.97          $26.42          $37.24
----------------------------------------------------------------------------------------------------------------
                                      Lowest Quintile Income Consumer Units
----------------------------------------------------------------------------------------------------------------
Food Expenditures...............................................          $4,875          $4,875          $4,875
Percent Impact on Food Expenditures.............................           0.61%           0.50%           0.44%
Projected Food Expenditure Increase.............................          $29.74          $24.38          $21.52
Fuel Expenditures...............................................          $1,111          $1,111          $1,111
Percent Impact on Fuel Expenditures.............................           0.79%           1.23%           1.73%
Projected Fuel Expenditure Increase.............................           $8.78          $13.67          $19.22
----------------------------------------------------------------------------------------------------------------
                                  Second-Lowest Quintile Income Consumer Units
----------------------------------------------------------------------------------------------------------------
Food Expenditures...............................................          $5,808          $5,808          $5,808
Percent Impact on Food Expenditures.............................           0.61%           0.50%           0.44%
Projected Food Expenditure Increase.............................          $35.43          $29.04          $25.63
Fuel Expenditures...............................................          $1,702          $1,702          $1,702
Percent Impact on Fuel Expenditures.............................           0.79%           1.23%           1.73%
Projected Fuel Expenditure Increase.............................          $13.45          $20.93          $29.44
----------------------------------------------------------------------------------------------------------------

V. Response to Remand of 2016 Rulemaking

    In this action, we are completing the process of addressing the 
remand of the 2014-2016 annual rule by the U.S. Court of Appeals for 
the D.C. Circuit in ACE.182 183 As discussed in the final 
rule

[[Page 44509]]

establishing applicable standards for 2020-2022,\184\ our approach to 
address the ACE remand is to impose a 500-million-gallon supplemental 
volume requirement for renewable fuel over two years. This is 
equivalent to the volume of renewable fuel waived from the 2016 
statutory volume requirement using a waiver which was subsequently 
vacated by the D.C. Circuit.\185\ We required the first 250-million-
gallon supplement in 2022. We are now requiring a second 250-million-
gallon supplement to be complied with in 2023. This 2023 supplemental 
volume requirement, in combination with the 2022 supplement, 
constitutes a meaningful remedy and completes our response to the ACE 
vacatur and remand.
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    \181\ Bureau of Labor and Statistics Consumer Expenditure 
Survey, 2022. https://www.bls.gov/cex/tables/calendar-year/aggregate-group-share/cu-income-quintiles-before-taxes-2020.pdf.
    \182\ 80 FR 77420 (December 14, 2015). In the 2014-2016 rule, 
for year 2016 EPA lowered the cellulosic biofuel requirement by 4.02 
billion gallons and the advanced biofuel and total renewable fuel 
requirements each by 3.64 billion gallons pursuant to the cellulosic 
waiver authority. CAA section 211(o)(7)(D). In the same rule, EPA 
further lowered the 2016 total renewable fuel requirement by 500 
million gallons under the general waiver authority for inadequate 
domestic supply. CAA section 211(o)(7)(A).
    \183\ In 2017, the D.C. Circuit vacated EPA's use of the general 
waiver authority for inadequate domestic supply to reduce the 2016 
total renewable fuels standard by 500 million gallons and remanded 
the 2014-2016 rule. 864 F.3d 691 (2017).
    \184\ 87 FR 39600, 39627-39631 (July 1, 2022).
    \185\ 864 F.3d at 691.
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    In the final rule establishing applicable standards for 2020-2022, 
we discussed the original 2016 renewable fuel standard, the ACE court's 
ruling, and our responsibility on remand in detail.\186\ We also 
discussed our consideration of alternative approaches to respond to the 
remand.\187\ We maintain the same views on the alternatives, including 
the alternatives identified by commenters, discussed in that 
rulemaking, and since that rulemaking have not identified any 
additional alternative approaches to addressing the ACE vacatur and 
remand. In particular, because we have already begun our response by 
imposing a 250-million-gallon supplemental standard in 2022, 
consideration of any other alternatives is evaluated in light of that 
partial response.
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    \186\ 87 FR 39600, 39627-39628 (July 1, 2022).
    \187\ 87 FR 39600, 39628-39629 (July 1, 2022). We also responded 
to alternative ideas provided by commenters. See also Renewable Fuel 
Standard (RFS) Program: RFS Annual Rules Response to Comments, EPA-
420-R-22-009 at 151-154.
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A. Supplemental 2023 Standard

    We are completing the process of addressing the ACE remand by 
applying a supplemental volume requirement of 250 million gallons of 
renewable fuel in 2023, on top of and in addition to the other 2023 
volume requirements.
    Under this approach, the original 2016 standard for total renewable 
fuel will remain unchanged and the compliance demonstrations that 
obligated parties made for it will likewise remain in place. A 
supplemental standard for 2023 avoids the difficulties associated with 
reopening 2016 compliance, as discussed in detail in the 2020-2022 
proposed rulemaking.\188\ This supplemental standard has the same 
practical effect as increasing the 2023 total renewable fuel volume 
requirement by 250 million gallons, as compliance will be demonstrated 
using the same RINs as used for the 2023 standard. The percentage 
standard for the supplemental standard is calculated the same way as 
the 2023 percentage standards (i.e., using the same gasoline and diesel 
fuel projections), such that the supplemental standard is additive to 
the 2023 total renewable fuel percentage standard. This approach 
provides a meaningful remedy in response to the court's vacatur and 
remand in ACE and effectuates the Congressionally determined renewable 
fuel volume for 2016, modified only by the proper exercise of EPA's 
waiver authorities, as upheld by the court in ACE and in a manner that 
can be implemented in the near term. We are treating such a 
supplemental standard as a supplement to the 2023 standards, rather 
than as a supplement to standards for 2016, which has passed. In order 
to comply with the supplemental standard, obligated parties will need 
to retire available RINs; it is thus logical to require the retirement 
of available RINs in the marketplace at the time of compliance with 
this supplemental standard. As discussed below, it is no longer 
possible for obligated parties to comply with a 500-million-gallon 2016 
obligation using 2015 and 2016 RINs as required by our regulations. 
Thus, compliance with a supplemental standard applied to 2016 would be 
impossible barring EPA reopening compliance for all years from 2016 
onward. By applying the supplemental standard to 2023 instead of 2016, 
RINs generated in 2022 and 2023 can be used to comply with the 2023 
supplemental standard. Additionally, as provided by our regulations, 
RINs generated in 2015 and 2016 could only be used for 2015 and 2016 
compliance demonstrations,\189\ and obligated parties had an 
opportunity at that time to utilize those RINs for compliance or sell 
them to other parties, while holding RINs that could be utilized for 
future compliance years.
---------------------------------------------------------------------------

    \188\ 86 FR 72436, 72459-72460 (Dec. 21, 2022).
    \189\ 2016 RINs could also have been used for up to 20 percent 
of an obligated party's 2017 compliance demonstrations.
---------------------------------------------------------------------------

    In applying a supplemental standard to 2023, we are treating it 
like all other 2023 standards in all respects. That is, producers and 
importers of gasoline and diesel that are subject to the 2023 standards 
are subject to the supplemental standard. The applicable deadlines for 
attest engagements and compliance demonstrations that apply to the 2023 
standards also apply to the supplemental standard. The gasoline and 
diesel volumes used by obligated parties to calculate their obligation 
is their 2023 gasoline and diesel production or importation. 
Additionally, obligated parties can use 2022 RINs for up to 20 percent 
of their 2023 supplemental standard.
    Stakeholders provided comments on this approach, with some 
supporting EPA's approach to the remand, and others suggesting that EPA 
should take an alternative response. We respond to those comments in 
the RTC document.
1. Demonstrating Compliance With the 2023 Supplemental Standard
    As we did for the 2022 supplemental standard, we are prescribing 
formats and procedures as specified in 40 CFR 80.1451(j) for how 
obligated parties will demonstrate compliance with the 2023 
supplemental standard that simplifies the process in this unique 
circumstance. Although the proposed 2023 supplemental standard is a 
regulatory requirement separate from and in addition to the 2023 total 
renewable fuel standard, obligated parties will submit a single annual 
compliance report for both the 2023 annual standards and the 
supplemental standard and will only report a single number for their 
total renewable fuel obligation in the 2023 annual compliance report. 
Obligated parties will also only need to submit a single annual attest 
engagement report for the 2023 compliance period that covers both the 
2023 annual standards and the 2023 supplemental standard.
    To assist obligated parties with this special compliance situation, 
we will issue guidance with instructions on how to calculate and report 
the values to be submitted in their 2023 compliance reports, similar to 
how we intend to do so for 2022.
2. Calculating a Supplemental Percentage Standard for 2023
    The formulas in 40 CFR 80.1405(c) for calculating the applicable 
percentage standards were designed explicitly to associate a percentage 
standard for a particular year with the volume requirement for that 
same year. The formulas are not explicitly designed to address the use 
of a 2016 volume requirement to calculate a 2023 percentage standard. 
Nonetheless, in light of EPA's and obligated parties' familiarity with 
this approach and the benefits of consistency within the structure of 
RFS regulations, we find it appropriate to apply the same general 
approach to calculating a supplemental

[[Page 44510]]

percentage standard for 2023. Utilizing the same principles and general 
terms allows for a formula that properly utilizes the 250 million 
gallon supplemental volume, but the same values used to calculate the 
2023 percentage standards, such that the supplemental percentage 
standard is still properly additive.
    The numerator in the formula in 40 CFR 80.1405(c) is the 
supplemental volume of 250 million gallons of total renewable fuel. The 
values in the denominator are the same as those used to calculate the 
2023 percentage standards, which can be found in Table VII.C-1. As 
described in Section VII, the resulting supplemental total renewable 
fuel percentage standard for the 250-million-gallon volume requirement 
in 2023 is 0.14 percent.
    The supplemental standard for 2023 is a requirement for obligated 
parties separate from and in addition to the 2023 standard for total 
renewable fuel. The two percentage standards are listed separately in 
the regulations at 40 CFR 80.1405(a), but in practice obligated parties 
will demonstrate compliance with both at the same time.

B. Authority and Consideration of the Benefits and Burdens

    In establishing the 2016 total renewable fuel standard, EPA waived 
the required volume of total renewable fuel by 500 million gallons 
using the inadequate domestic supply general waiver authority. The use 
of that waiver authority was vacated by the court in ACE and the rule 
was remanded to EPA. In order to remedy our improper use of the 
inadequate domestic supply general waiver authority, we find that it is 
appropriate to treat our authority to establish a supplemental standard 
at this time as the same authority used to establish the 2016 total 
renewable fuel volume requirement--CAA section 211(o)(3)(B)(i)--which 
requires EPA to establish percentage standard requirements by November 
30 of the year prior to which the standards will apply and to 
``ensure'' that the volume requirements ``are met.'' \190\ EPA 
exercised this authority for the 2016 standards once already. However, 
the effect of the ACE vacatur is that there remain 500 million gallons 
of total renewable fuel from the 2016 statutory volumes that were not 
included under the original exercise of EPA's authority under CAA 
section 211(o)(3)(B)(i). We are now utilizing the same authority to 
correct our prior action, and ``ensure'' that the volume requirements 
``are met,'' and we are doing so significantly after November 30, 2015. 
Therefore, we have considered how to balance benefits and burdens and 
mitigate hardship by our late issuance of this standard. We recognize 
that we used the same authority to establish the 2022 supplemental 
standard. As noted in that action, we had only provided a partial 
response to the ACE court's remand and vacatur. This action now 
completes our response. Additionally, as we have in the past, we rely 
on our authority in CAA section 211(o)(2)(A)(i) to promulgate late 
standards.\191\ CAA section 211(o)(2)(A)(i) requires that EPA 
``ensure'' that ``at least'' the applicable volumes ``are met.'' \192\ 
Because the D.C. Circuit vacated our waiver of 500 million gallons of 
total renewable fuel from the original 2016 standards, we are now 
taking action to ensure that at least the applicable volumes from 2016 
are ultimately met. We have determined that the appropriate means to do 
so is through the use of two 250-million-gallon supplemental standards, 
one in 2022, as finalized in a prior action, and one in 2023, as we are 
finalizing in this action.
---------------------------------------------------------------------------

    \190\ EPA acknowledges that CAA section 211(o)(3)(B)(i) does not 
apply to the standards for 2023-2025. EPA cites this authority for 
the supplemental standard which is a 2016 standard with compliance 
aligned with calendar year 2023.
    \191\ In promulgating the 2009 and 2010 combined BBD standard, 
upheld by the D.C. Circuit in NPRA v. EPA, 630 F.3d 145 (2010), we 
utilized express authority under section 211(o)(2). 75 FR 14670, 
14718.
    \192\ See also CAA section 211(o)(2)(A)(iii)(I), requiring that 
``regardless of the date of promulgation,'' EPA shall promulgate 
``compliance provisions applicable to refineries, blenders, 
distributors, and importers, as appropriate, to ensure that the 
requirements of this paragraph are met.''
---------------------------------------------------------------------------

    As noted elsewhere, we are finalizing this action during the 2023 
compliance year. Thus, our action is partly retroactive as to the 
compliance with the supplemental standard by obligated parties. In 
analyzing the benefits and burdens attendant to this approach, we have 
also considered the partially retroactive nature of the rule. The 
issuance of the supplemental standard is thus a late standard, in that 
we are acting beyond the statutory deadline for a standard associated 
with the 2016 volume requirements, and it is partially retroactive as 
it is being finalized partway through the compliance year during which 
it applies.
    In ACE and two prior cases, the court upheld EPA's authority to 
issue late renewable fuel standards, even those applied retroactively, 
so long as EPA's approach is reasonable.\193\ EPA must consider and 
mitigate the burdens on obligated parties associated with a delayed 
rulemaking.\194\ When imposing a late or retroactive standard, we must 
balance the burden on obligated parties of a retroactive standard with 
the broader goal of the RFS program to increase renewable fuel 
use.\195\ The approach in this action implements a late standard, with 
partially retroactive effects, as described in these cases. Obligated 
parties made their RIN acquisition decisions in 2016 based on the 
standards as established in the 2014-2016 standards final rule, and 
they may have made different decisions had we not reduced the 2016 
total renewable fuel standard by 500 million gallons using the general 
waiver authority. Were EPA to create a supplemental standard for 2016 
designed to address the use of the general waiver authority in 2016, we 
would be imposing a wholly retroactive standard on obligated parties, 
but because obligated parties will comply with the supplemental 
standard in 2023, it would instead be a late standard applied in 2023, 
with partially retroactive effects. Pursuant to the court's direction, 
we have carefully considered the benefits and burdens of our approach 
and considered and mitigated the burdens to obligated parties caused by 
the lateness.\196\
---------------------------------------------------------------------------

    \193\ See ACE, 864 F.3d at 718; Monroe Energy, LLC v. EPA, 750 
F.3d at 920; NPRA, 630 F.3d at 154-58.
    \194\ ACE, 864 F.3d at 718.
    \195\ NPRA, 630 F.3d at 154-58.
    \196\ As we also did for the 2022 supplemental standard. 87 FR 
39629-31 (July 1, 2022).
---------------------------------------------------------------------------

    We believe that the approach we are finalizing provides benefits 
that outweigh potential burdens. Consistent with the 2016 renewable 
fuel volume requirement established by Congress, the supplemental 
standards for 2022 and 2023 are together equivalent to the volume of 
total renewable fuel that we inappropriately waived for the 2016 total 
renewable fuel standard. The use of these supplemental standards phased 
across two compliance years provides a meaningful remedy to the D.C. 
Circuit's vacatur of EPA's use of the general waiver authority and 
remand of the 2016 rule in ACE. While this action cannot result in 
additional renewable fuel used in 2016, it can result in additional 
fuel use in 2023. We believe that while the additional volume in 2023 
will put some moderate degree of increased pressure on the market, it 
is nevertheless feasible and achievable.
    We have carefully considered and designed this approach to mitigate 
any burdens on obligated parties. First, we have considered the 
availability of RINs to satisfy this additional requirement. As 
explained earlier, there are insufficient 2015 and 2016 RINs

[[Page 44511]]

available to satisfy the proposed 250-million-gallon volume 
requirement. Instead, we are finalizing a supplemental volume 
requirement to the 2023 standards that applies prospectively, in part. 
Doing so allows 2022 and 2023 RINs to be used for compliance with the 
2023 supplemental standard, in keeping with existing RFS regulations. 
We believe there will be a sufficient number of 2023 RINs to satisfy 
the 2023 supplemental standard through a combination of domestic 
production and importation of renewable fuel, as described more fully 
in Section VI. In Section VI and RIA Chapter 6.2.6, we considered the 
feasibility and achievability of the 2023 supplemental standard 
alongside the other volume standards for 2023. We believe that 
compliance through the use of carryover RINs will not be necessary, but 
nevertheless remains available as an option for obligated parties for 
compliance.\197\
---------------------------------------------------------------------------

    \197\ See Section III.C.4 for further discussion of carryover 
RINs.
---------------------------------------------------------------------------

    Second, we provided significant lead-time for obligated parties by 
proposing this supplemental standard for 2023 no less than 12 months 
prior to the 2023 compliance deadline.\198\ Moreover, we initially 
provided obligated parties notice of the 250-million-gallon 
supplemental standard for 2022 in December of 2021,\199\ no less than 
24 months prior to the 2023 compliance deadline, and indicated our 
intention to similarly apply a 250-million-gallon supplemental standard 
to 2023. Given this December 2021 statement of intent, parties have had 
notice of a 250-million-gallon supplemental standard in 2023 for longer 
than they had notice of the 2023 standards for renewable fuel, advanced 
biofuel, and total renewable fuel. We are also finalizing this action 
approximately 9 months prior to the 2023 compliance deadline.
---------------------------------------------------------------------------

    \198\ See 40 CFR 80.1427. See also Nat'l Petrochemical & 
Refiners Ass'n v. EPA, 630 F.3d 145, 166 (D.C. Cir.), acknowledging 
11 months from issuance of standards to the compliance deadline as 
sufficient time, and ACE at 722-23 acknowledging ``very extensive 
extensions of the normal compliance demonstration deadlines'' of 
approximately 8 months after signature.
    \199\ 86 FR 72436 (December 21, 2021).
---------------------------------------------------------------------------

    Third, we are finalizing multiple mechanisms to mitigate the 
potential compliance burden caused by a late rulemaking. One step is to 
designate that the response to the ACE remand is a supplement to the 
2023 standards. This approach not only allows the use of 2022 and 2023 
RINs for compliance with the 2023 standard, as described earlier, but 
it also avoids the need for obligated parties to revise their 2016 (and 
potentially 2017, 2018, 2019, etc.) compliance demonstrations, which 
would be a burdensome and time-consuming process. In addition, 
obligated parties can satisfy both the 2023 standards and the 
supplemental standard in a single set of compliance and attest 
engagement demonstrations. We are also extending the same compliance 
flexibility options already available for the 2023 standards to the 
2023 supplemental standard, including allowing the use of carryover 
RINs and deficit carry forward subject to the conditions of 40 CFR 
80.1427(b)(1). With this action we are also spreading out the 500-
million-gallon obligation over two compliance years. As explained in 
the 2020-2022 final rule, this is designed to allow obligated parties 
and renewable fuel producers additional lead time to meet the standard, 
thus providing almost a year for the market to prepare for compliance 
with the second 250-million-gallon requirement.\200\
---------------------------------------------------------------------------

    \200\ 87 FR 39600 (July 1, 2022).
---------------------------------------------------------------------------

    Lastly, we carefully considered alternatives, including retaining 
the 2016 total renewable fuel volume as described in the 2020 
proposal,\201\ reopening 2016 compliance and applying a supplemental 
standard to the 2016 compliance year,\202\ and, as suggested by 
commenters on the 2020-2022 rule, using our cellulosic or general 
waiver authority to retroactively lower 2016 volumes such that 2022 and 
2023 supplemental standards would be smaller.\203\
---------------------------------------------------------------------------

    \201\ 84 FR 36762, 36787-36789 (July 29, 2019).
    \202\ 86 FR 72459-60.
    \203\ 87 FR 39600 (July 1, 2022). See also Chapter 8 of the 
Response to Comments document for this action.
---------------------------------------------------------------------------

    On balance, we find that requiring an additional 250 million 
gallons of total renewable fuel to be complied with through a 
supplemental standard in 2023 in addition to that already applied in 
2022 is an appropriate response to the court's vacatur and remand of 
our use of the general waiver authority to waive the 2016 total 
renewable fuel standard by 500 million gallons.

VI. Volume Requirements for 2023-2025

    As required by the statute, we have reviewed the implementation of 
the program in prior years and have analyzed a specified set of 
factors.\204\ As described in Section III, we did this by first 
deriving a set of ``candidate volumes'' based on a consideration of 
supply-related factors and other relevant factors, and then using those 
candidate volumes to analyze the remaining economic and environmental 
factors as discussed in Section IV. Details of all analyses are 
provided in the RIA. We have coordinated with the Secretary of Energy 
and the Secretary of Agriculture, including through the interagency 
review process, and their input is reflected in this final rule. We 
have also considered all information provided through comments from 
stakeholders and any other information that has become available since 
release of the proposal.
---------------------------------------------------------------------------

    \204\ CAA section 211(o)(2)(B)(ii).
---------------------------------------------------------------------------

    In this section, we summarize and discuss the implications of all 
our analyses and any other information that has become available as it 
applies to each of the three different component categories of biofuel: 
cellulosic biofuel, non-cellulosic advanced biofuel, and conventional 
renewable fuel. These three components combine to produce the statutory 
categories: the volume requirement for advanced biofuel is equal to the 
sum of cellulosic biofuel and non-cellulosic advanced biofuel, while 
the volume requirement for total renewable fuel is equal to the sum of 
advanced biofuel and conventional renewable fuel.\205\
---------------------------------------------------------------------------

    \205\ These combinations are set forth in the statute. See CAA 
section 211(o)(2)(B)(i)(I)-(III). In addition, the determination of 
the appropriate volume requirements for BBD is treated separately in 
Section VI.C.
---------------------------------------------------------------------------

    We note that while we do not separately discuss each of the 
statutory factors for each component category in this section, we have 
analyzed all the statutory factors. However, it was not always possible 
to precisely identify the implications of the analysis of a specific 
factor for a specific component category of renewable fuel. For 
instance, while we analyzed ethanol use in the context of the review of 
the implementation of the program in prior years, ethanol can be used 
in all biofuel categories except BBD and our analysis therefore does 
not apply to a single standard. Air quality impacts are driven 
primarily by biofuel type (e.g., ethanol, biodiesel, etc.) rather than 
by biofuel category, and energy security impacts are driven solely by 
the amount of fossil fuel energy displaced. Moreover, with the 
exception of CAA section 211(o)(2)(ii)(III), the statute does not 
require that the requisite analyses be specific to each category of 
renewable fuel. Rather, the statute directs EPA to analyze certain 
factors, without specifying how that analysis must be conducted. In 
addition, the statute directs EPA to analyze the ``program'' and the 
impacts of ``renewable fuels'' generally, further indicating that 
Congress intended to provide to EPA the discretion to decide how and at 
what level of specificity to analyze the statutory factors. This 
section

[[Page 44512]]

supplements the analyses discussed in Sections III and IV by providing 
a narrative summary of the key criteria that apply distinctively to 
each component category insofar as we have deemed appropriate.

A. Cellulosic Biofuel

    In EISA, Congress established escalating targets for cellulosic 
biofuel, reaching 16 billion gallons in 2022. After 2015, all of the 
growth in the statutory volume of total renewable fuel was advanced 
biofuel, and of the advanced biofuel growth, the vast majority was 
cellulosic biofuel. This indicates that Congress intended the RFS 
program to provide a significant incentive for cellulosic biofuels and 
that the focus for years after 2015 was to be on cellulosic. While 
cellulosic biofuel production has not reached the levels envisioned by 
Congress in 2007, EPA remains committed to supporting the development 
and commercialization of cellulosic biofuels. Cellulosic biofuels, 
particularly those produced from waste or residue materials, have the 
potential to significantly reduce GHG emissions from the transportation 
sector. In many cases cellulosic biofuel can be produced without 
impacting current land use and with little to no impact on other 
environmental factors, such as air and water quality. The cellulosic 
biofuel volumes we are finalizing are intended to provide the necessary 
support for the ongoing development and commercial scale deployment of 
cellulosic biofuels, and to continue to build towards the Congressional 
target of 16 billion gallons of cellulosic biofuel established in EISA, 
and are supported by our consideration of the specified statutory 
factors.
    As discussed in Section III.B.1, we developed candidate volumes for 
cellulosic biofuel based on a consideration of statutory supply-related 
factors. This process included a consideration not only of production 
and import of the different possible forms of cellulosic biofuel, but 
also of constraints on consumption (i.e., the number of CNG/LNG 
vehicles) and of the availability of qualifying feedstocks, primarily 
but not exclusively biogas. With an eye towards estimating candidate 
volumes based on the supply-related statutory factors that reflect the 
projected growth in cellulosic biofuel production from 2023-2025, we 
estimated the following candidate volumes:

                              Table VI.A-1--Candidate Volumes of Cellulosic Biofuel
                                                 [Million RINs]
----------------------------------------------------------------------------------------------------------------
                                                                       2023            2024            2025
----------------------------------------------------------------------------------------------------------------
CNG/LNG Derived from Biogas.....................................             831           1,039           1,299
Ethanol from CKF................................................               7              51              77
                                                                 -----------------------------------------------
    Total Cellulosic Biofuel....................................             838           1,090           1,376
----------------------------------------------------------------------------------------------------------------

    We then analyzed these candidate volumes according to the other 
statutory factors. These analyses are discussed briefly here and 
described in greater detail in the RIA. Our assessment of those factors 
suggests that cellulosic biofuels have multiple benefits, including the 
potential for very low lifecycle GHG emissions that meet or exceed the 
statutorily-mandated 60 percent GHG reduction threshold for cellulosic 
biofuel.\206\ Many of these benefits stem from the fact that nearly all 
of the feedstocks projected to be used to produce the candidate 
cellulosic biofuel volumes are either waste materials (as in the case 
of CNG/LNG derived from biogas) or residues (as in the case of 
cellulosic diesel and heating oil from mill residue). The use of many 
of the feedstocks currently being used to produce cellulosic biofuel 
and those expected to be used through 2025 (primarily biogas to produce 
CNG/LNG) are not expected to cause significant land use changes that 
might lead to adverse environmental impacts.
---------------------------------------------------------------------------

    \206\ CAA section 211(o)(1)(E).
---------------------------------------------------------------------------

    None of the cellulosic biofuel feedstocks expected to be used to 
produce liquid cellulosic biofuels through 2025 (including agricultural 
residues such as corn kernel fiber, mill residue, and separated MSW) 
are produced with the intention that they be used as feedstocks for 
cellulosic biofuel production. Moreover, many of these feedstocks have 
limited uses in other markets.\207\ Because of this, using these 
feedstocks to produce liquid cellulosic biofuel is not expected to have 
significant adverse impacts related to several of the statutory 
factors, including the conversion of wetlands, ecosystems and wildlife 
habitat, soil and water quality, the price and supply of agricultural 
commodities, and food prices through 2025.
---------------------------------------------------------------------------

    \207\ One potential exception is corn kernel fiber. Corn kernel 
fiber is a component of distillers grains, which is currently sold 
as animal feed. Depending on the type of animal to which the 
distillers grain is fed, corn kernel fiber removed from the 
distillers grain through conversion to cellulosic biofuel may need 
to be replaced with additional feed.
---------------------------------------------------------------------------

    Despite the fact that both liquid cellulosic biofuels and CNG/LNG 
derived from biogas are projected to be produced from feedstocks that 
are wastes or by-products, there are also significant differences 
between liquid cellulosic biofuels and CNG/LNG derived from biogas. In 
particular, the cost of producing liquid cellulosic biofuel is 
generally high. These high costs are generally the result of low yields 
(e.g., gallons of fuel per ton of feedstocks) and the high capital 
costs of liquid cellulosic biofuel production facilities. In the near 
term (through 2025), the production of these fuels is likely to be 
dependent on relatively high cellulosic RIN prices (in addition to 
state level programs such as California's LCFS) in order for them to be 
economically competitive with petroleum-based fuels.
    In contrast to liquid cellulosic biofuels, cellulosic biofuels 
derived from biogas, most notably CNG/LNG, can be more cost-competitive 
with the fuels they displace. Some biogas from qualifying sources such 
as landfills, wastewater treatment facilities, and agricultural 
digesters are already injected into natural gas pipelines.\208\ In some 
situations, such as at larger landfills, CNG/LNG derived from biogas 
may be able to be produced at a price comparable to fossil natural gas. 
In most cases, however, some financial incentive is needed to enable 
these fuels to compete economically with the fuels they displace. 
Because of the low cost of production relative to liquid cellulosic 
biofuels and the relatively mature state of this technology, CNG/LNG 
from biogas is expected to remain as the dominant type of cellulosic 
biofuel through 2025.
---------------------------------------------------------------------------

    \208\ See Landfill Gas Energy Project Data from EPA's Landfill 
Methane Outreach Program.

---------------------------------------------------------------------------

[[Page 44513]]

    Despite the relatively low cost of production for CNG/LNG derived 
from biogas, the combination of the relatively high cellulosic biofuel 
RIN price and the significant volume potential for CNG/LNG derived from 
biogas used as transportation fuel could have an impact on the price of 
gasoline and diesel. We project that together these fuels could add 
about $0.01 per gallon to the price of gasoline and diesel in 2023, and 
that this price impact could rise to about $0.02 per gallon in 
2025.\209\
---------------------------------------------------------------------------

    \209\ See RIA Chapters 1.9.2 and 10 for a further discussion of 
the expected impact of RINs generated for CNG/LNG derived from 
biogas on the price of gasoline and diesel and the impact of CNG/LNG 
derived from biogas on the cost of this rule.
---------------------------------------------------------------------------

    Based on our analyses of all of the statutory factors, we find that 
the benefits of higher volumes of cellulosic biofuel outweigh the 
potential negative impacts. We therefore believe that to realize the 
benefits associated with increasing cellulosic biofuel production it is 
reasonable to establish cellulosic biofuel volume requirements through 
2025 at the candidate levels that reflect the projected growth in 
cellulosic biofuel production from 2023-2025 based on available data. 
The volumes for 2023-2025 we are finalizing in this rule are based on 
the data available at the time of this rule and reflect our 
consideration of the public comments received on the proposed rule. 
These volumes represent our best efforts to project the potential for 
growth in the volume of these fuels that can be achieved in 2023-2025. 
We believe these volumes will continue to provide substantial support 
for investment in and development of cellulosic biofuels and yet are 
consistent with statutory requirements for the cellulosic biofuel 
volumes (including CAA 211(o)(2)(B)(iv)).

                                 Table VI.A-2--Final Cellulosic Biofuel Volumes
                                                 [Million RINs]
----------------------------------------------------------------------------------------------------------------
                                                                       2023            2024            2025
----------------------------------------------------------------------------------------------------------------
CNG/LNG Derived from Biogas.....................................             831           1,039           1,299
Ethanol from CKF................................................               7              51              77
                                                                 -----------------------------------------------
    Total Cellulosic Biofuel....................................             838           1,090           1,376
----------------------------------------------------------------------------------------------------------------

    We note that the final cellulosic biofuel volumes are higher than 
the proposed volumes, after accounting for the decision not to finalize 
eRIN provisions in this rule. There are several reasons for these 
higher volumes, which are discussed briefly here and in more detail in 
Section III.B and RIA Chapter 6. The addition of projected volume of 
cellulosic ethanol from CKF relative to the proposed rule is largely 
the result of the significant progress several facilities and 
technology providers have made towards facility registration since the 
release of the updated guidance of producing ethanol from corn kernel 
fiber.\210\ As discussed in RIA Chapter 6.1, since the proposed rule 
EPA has received registration requests from facilities intending to 
register to generate cellulosic biofuel RINs for ethanol from CKF, and 
have had substantive technical discussions with technology providers 
who intend to provide testing results consistent with EPA's current 
guidance. The increases in CNG/LNG derived from biogas are due to our 
belief that growth from 2023-2025 can be more in line with the average 
growth from 2015-2022 rather than just the most recent 24 months.
---------------------------------------------------------------------------

    \210\ 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). See RIA Chapter 6.1 for a further discussion of ethanol 
produced form corn kernel fiber.
---------------------------------------------------------------------------

    We recognize that with this Set rule Congress has instructed us to 
begin a new phase of the RFS program, one in which there are no 
statutory volume targets. This has important implications for the use 
of our cellulosic waiver authority and the availability of cellulosic 
waiver credits in future years (see Section II.F for a further 
discussion of the availability of cellulosic waiver credits). In the 
proposed rule we noted several important changes in EPA's statutory 
authority in years after 2022, and we sought input from commenters on 
how these changes can or should impact the required cellulosic biofuel 
volumes. These comments, and our responses to them, are discussed 
briefly here, and in greater detail in RTC Sections 2.3.2 and 3.1.
    Perhaps most importantly EPA proposed volumes for multiple years in 
one action in an effort to provide the consistent market signals that 
the cellulosic biofuel industry needs to develop. At the same time, we 
recognized that there is increased uncertainty in any cellulosic 
biofuel projections due to the multi-year nature of this rule and the 
potential for the development and deployment of new cellulosic biofuel 
production pathways. The increasing cellulosic biofuel volumes that we 
are establishing in this rule should also provide increased stability 
in the cellulosic RIN market, as they allow greater volumes of 
cellulosic RINs to be used for compliance in the following year if 
excess cellulosic RINs are generated. We believe that despite the 
uncertainty associated with cellulosic biofuel production through 2025 
it is appropriate to finalize cellulosic biofuel volumes for 2023-2025 
in this rule, and that the cellulosic biofuel volumes we are finalizing 
are reasonable based on the available data for making future 
projections.
    In the proposed rule we noted that several stakeholders had stated 
that despite the incentive provided by the RFS program, variability and 
uncertainty in cellulosic RIN prices and future cellulosic biofuel 
requirements are hindering investment in the cellulosic biofuel 
industry. These parties generally expressed concerns related to the 
potential impacts on the cellulosic biofuel and cellulosic RIN markets 
if EPA's projections of cellulosic biofuel are significantly and 
consistently lower than the actual production of cellulosic biofuel. 
While many stakeholders acknowledged that EPA has tools to reduce the 
cellulosic biofuel volumes if necessary, they noted that EPA has a 
limited ability to increase the cellulosic biofuel volume if production 
and imports of cellulosic biofuel exceed the required volumes. In such 
a case the stakeholders expressed concern that the price of cellulosic 
RINs could fall to a level at or approaching the advanced biofuel RIN 
price, which might then negatively impact their investment in 
cellulosic biofuel production.
    We agree with these commenters that it is important to maintain 
proper incentives for investment in and growth

[[Page 44514]]

of cellulosic biofuels. Their potential for greater GHG emission 
reductions and typically limited negative environmental impacts make 
them attractive options for displacing petroleum fuels. Since 2015, the 
incentives provided by the RFS program have supported significant 
growth in cellulosic biofuel production (see Figure III.B.1-1). During 
this time, cellulosic biofuel production has grown at an annual rate of 
25% per year, greater than any other category of cellulosic biofuel. In 
response to comments received on the proposed rule and more recent data 
we have adjusted our approach to projecting the potential production of 
CNG/LNG derived from biogas (by far the largest source of cellulosic 
biofuel) to better reflect the potential for the growth of these fuels 
through 2025. This higher growth rate resulted in significantly higher, 
yet still achievable, projections for CNG/LNG derived from biogas.
    We believe that the most effective and direct way to respond to the 
concerns the commenters raised with respect to the negative impacts 
related to a potential surplus of cellulosic biofuel RINs is to 
establish cellulosic biofuel volume requirements that reflect the 
projected growth of the cellulosic biofuel industry based on available 
data, as we have done in this final rule.
    Nevertheless, in their comments on the proposed rule these 
stakeholders requested that EPA modify our historical standard setting 
process for cellulosic biofuel to also commit to a mechanism for 
increasing the cellulosic biofuel volume requirements if actual 
production and imports exceeded the volumes we are finalizing in this 
rule by a specified amount, either by adopting regulatory provisions 
that would automatically increase the volume requirement or by 
committing to adjusting the cellulosic biofuel volume requirements in a 
subsequent rule. The most common mechanism requested by commenters was 
that EPA would finalize a formula that would be used annually to adjust 
the required volume of cellulosic biofuel for a subsequent year.\211\ 
For example, many parties suggested that EPA should calculate the 
difference between (1) the total number of cellulosic RINs generated in 
each year plus any remaining cellulosic RINs from the previous year not 
used for compliance and (2) the required cellulosic biofuel volume for 
that year. If the quantity of cellulosic RIN generation plus carryover 
RINs exceeded the required volume for that year, these parties stated 
that EPA should automatically increase the required cellulosic volume 
for a subsequent year.\212\ By doing so the commenters believed that 
cellulosic biofuel RIN values would be assured of remaining high, 
reducing their investment risk. If the quantity of cellulosic RIN 
generation plus carryover RINs was less than the required volume for 
that year creating a concern for obligated parties, then the commenters 
suggested EPA should automatically decrease the required cellulosic 
volume for a subsequent year.
---------------------------------------------------------------------------

    \211\ For an example of this requested approach, see comments by 
the Coalition for Renewable Natural Gas (Docket Item No. EPA-HQ-OAR-
2021-0427-0756).
    \212\ Several parties noted that EPA need not increase the 
required cellulosic volume for the subsequent year by the entire 
amount that cellulosic RIN generation and carryover RINs exceeded 
the required volume for that year, but that instead EPA could 
increase the required volume by a lesser amount to preserve some 
level of carryover RINs. Further, some parties explicitly stated 
that any increase to the required volume of cellulosic biofuel 
should occur 2 years after the observed RIN surplus. For example, if 
cellulosic RIN generation plus carryover RINs was greater than the 
required volume for 2023, EPA should increase the required volume 
for 2025 to meet the statutory requirements that the volumes be set 
14 months in advance of the year to which they apply.
---------------------------------------------------------------------------

    Several commenters opposed the adoption of a mechanism that would 
automatically adjust the cellulosic volumes.\213\ These comments 
generally focused on the statutory requirements that the RFS volume 
requirements be based on an evaluation of the statutory criteria 
(rather than a simple calculation) and that the volume requirements be 
set 14 months in advance of the applicable year. One commenter 
additionally noted that EPA should not use any adjustment mechanism to 
reduce the available carryover RINs, which they claimed were allowed by 
Congress. Another commenter stated that any formula that could result 
in adjusting the cellulosic volume requirements downward would strip 
the RFS program of its market forcing power and result in only 
requiring the quantity of cellulosic biofuel actually used in the 
market.
---------------------------------------------------------------------------

    \213\ For example, see comments from AFPM (EPA-HQ-OAR-2021-0427-
0812) and Growth Energy (EPA-HQ-OAR-2021-0427-0796).
---------------------------------------------------------------------------

    We acknowledge that in theory a mechanism could be developed and 
implemented in a way that might be able to reduce, and potentially even 
eliminate, the investment risk associated with a potential surplus of 
cellulosic RINs causing RIN price volatility or lower RIN prices. 
Nevertheless, after reviewing these comments, EPA is not committing to 
such a mechanism at this time for the following reasons and as 
discussed more fully in RTC Section 2.3.
    First, as discussed above, we believe that the most effective and 
direct way to respond to the concerns the commenters raised with 
respect to the negative impacts related to a potential surplus of 
cellulosic biofuel RINs is to establish cellulosic biofuel volume 
requirements that reflect the projected growth of the cellulosic 
biofuel industry based on available data.
    Second, it is not yet clear how such a mechanism could or should be 
implemented. For example, the public data many of the commenters 
suggested could be used in these calculations are not clearly suitable 
for this purpose. With the new biogas regulatory reform provisions 
(discussed in Section IX) that we are finalizing in this rule, not all 
D3 biogas RINs generated will represent cellulosic fuel used as 
transportation fuel. Under the new provisions, these RINs may be 
retired if the RNG is used for a non-transportation use (e.g., heating 
or renewable electricity generation), thus altering the ultimate amount 
of cellulosic RINs available to meet the RFS standards.
    Third, EPA also has an obligation to provide public notice and an 
opportunity for comment prior to establishing the RFS volume 
requirements. While we sought comment on an adjustment mechanism in 
general, and commenters provided input on potential mechanisms at a 
high level, there was little specificity associated with how such a 
mechanism could or would be implemented in practice. Notably we did not 
propose regulations for public comment that would implement an 
adjustment mechanism. While some commenters acknowledged this notice 
and comment obligation, these commenters did not adequately address the 
potential public notice concerns that finalizing this approach may now 
raise. While EPA could in theory promulgate a supplemental notice and 
opportunity for comment on this change, doing so would further and 
significantly delay this rulemaking, which would be inconsistent with 
the lead-time provisions in the statute and would itself undermine the 
market certainty integral to success of the entire RFS program.
    Fourth, as stated in the proposed rule, the carryover RIN 
provisions in the existing RFS regulations already represent a 
mechanism to help stabilize demand for cellulosic biofuel and 
cellulosic RINs in the event of a RIN surplus. In the event of a 
surplus of RINs in a current year, the fact that these RINs will still 
be of value in the

[[Page 44515]]

following year when RINs may be in short supply helps to stabilize the 
value of RINs, including D3 RINs, over time. We further address these 
comments in the RTC document.
    EPA will continue to closely monitor the generation of all 
cellulosic RINs in future years and, if appropriate, will consider 
adjusting the cellulosic biofuel volume requirements.

B. Non-Cellulosic Advanced Biofuel

    The volume targets established by Congress through 2022 anticipated 
volumes of advanced biofuel beyond what would be needed to satisfy the 
cellulosic standard. The statutory target for advanced biofuel in 2022 
(21 billion gallons) allowed for up to five billion gallons of non-
cellulosic advanced biofuel to be used towards the advanced biofuel 
volume target, and the applicable standards for 2022 similarly include 
five billion gallons of non-cellulosic advanced biofuel. As discussed 
in Sections III.B.2 and III.B.3, we developed candidate volumes for 
non-cellulosic advanced biofuel based on a consideration of supply-
related factors and other relevant factors. This process included a 
consideration not only of production and import of non-cellulosic 
advanced biofuels, but also of the availability of qualifying 
feedstocks, a consideration of the supply of these fuels in the first 
quarter of 2023, and a desire to maximize benefits and limit potential 
negative consequences associated with the production of these fuels by 
focusing future growth on increases in feedstock production in North 
America. Based on this analysis of these factors, the candidate volumes 
for non-cellulosic biofuel represent significant growth relative to the 
volumes of these fuels supplied in 2022 (see Table III.C.2-1). We then 
analyzed these candidate volumes according to the other statutory 
factors.
    To date, the vast majority of non-cellulosic advanced biofuel in 
the RFS program has been biodiesel and renewable diesel, with 
relatively small volumes of sugarcane ethanol and other advanced 
biofuels. Our assessment of the impact of non-cellulosic advanced 
biofuels on each of the statutory factors can be found in the RIA, that 
assessment is summarized briefly in this section. While the impacts of 
non-cellulosic advanced biofuels on the statutory factors can vary 
depending on the fuel type, production process, where the fuel is 
produced, and the feedstock used to produce the fuel, all advanced 
biofuels have the potential to provide significant GHG reductions as 
they are required to achieve at least 50 percent GHG reductions 
relative to the petroleum fuels they displace.\214\ These potential GHG 
reductions suggest that non-cellulosic advanced biofuel volumes that 
meet or exceed those established by Congress for 2022 (5.0 billion 
RINs) may be appropriate.
---------------------------------------------------------------------------

    \214\ CAA section 211(o)(1)(B)(i).
---------------------------------------------------------------------------

    Advanced biodiesel and renewable diesel together comprised 95 
percent or more of the total supply of non-cellulosic advanced biofuel 
over the last several years, and together the two fuels are expected to 
continue to do so through 2025 due to the limited production and import 
of other types of non-cellulosic advanced biofuels (see RIA Chapters 
6.2 through 6.4). We have therefore focused our attention on the 
impacts of these fuels in relation to the statutory factors in 
determining appropriate levels of non-cellulosic advanced biofuel for 
2023-2025.\215\
---------------------------------------------------------------------------

    \215\ We have also considered the potential for increasing 
volumes of renewable jet fuel. Given its similarity to renewable 
diesel, for purposes of projecting appropriate volume requirements 
for 2023-2025, in most cases we consider renewable jet fuel to be a 
component of renewable diesel.
---------------------------------------------------------------------------

    As explained in Section III.B.2, we identified candidate volumes 
for non-cellulosic advanced biofuels based on the supply-related 
factors and other relevant factors. We also considered the supply of 
these fuels through March 2023 (the most recent month for which data 
were available at the time the analyses for this rule were completed). 
We concluded that domestic production capacity and availability of 
imports indicate that volumes of non-cellulosic advanced biofuel 
through 2025 could exceed the implied statutory target for 2022 (5 
billion ethanol-equivalent gallons). Similarly, the feedstocks used to 
make advanced biodiesel and renewable diesel (such as soy oil, canola 
oil, and corn oil, as well as waste oils such as white grease, yellow 
grease, trap grease, poultry fat, and tallow) currently exist in 
sufficient quantities globally to supply increasing volumes. While 
there is potential for increasing growth in the production of some of 
these feedstocks, these feedstocks also have many existing uses and may 
require replacement with suitable substitutes if increasing quantities 
are used for biofuel production.
    Beyond the supply-related statutory factors considered in 
determining the candidate volumes, our assessment of the impact of 
biodiesel and renewable diesel on the remaining statutory factors found 
that some of these factors would suggest that volumes higher than the 
candidate volumes are appropriate. For example, we observe also that 
higher implied volume requirements for non-cellulosic advanced biofuel 
may have energy security benefits and result in increases in domestic 
employment in the biofuels industry and increases in income for biofuel 
feedstock producers. Benefits to domestic employment are only likely to 
occur if increasing volumes of biodiesel and renewable diesel are 
produced domestically. Similarly, benefits to domestic feedstock 
producers are significantly more likely if these fuels are produced 
from domestic feedstocks. Our assessment of these factors therefore 
suggests it is appropriate to focus the volume requirements for these 
fuels on volumes that can be produced in the U.S. from North American 
feedstocks.\216\
---------------------------------------------------------------------------

    \216\ While biofuels produced from Canadian feedstocks do not 
increase employment in feedstock production, these feedstocks are 
often converted to biofuels in the U.S., which increases domestic 
employment in biofuel production. For a further discussion of our 
decision in this final rule to include canola oil imported from 
Canada in the feedstocks projected to be available to U.S. biofuel 
producers see RTC Section 4.2.
---------------------------------------------------------------------------

    Some of the statutory factors, however, suggest that lower volumes 
of non-cellulosic advanced biofuel would be appropriate. For instance, 
as described in RIA Chapter 10, the cost of biodiesel and renewable 
diesel is significantly higher than petroleum-based diesel fuel and is 
expected to remain so over the next several years. Even if biodiesel 
and renewable diesel blends are priced similarly to petroleum diesel at 
retail after accounting for the applicable federal and state incentives 
(including the RIN value), the higher relative costs of biodiesel and 
renewable diesel are still borne by society as a whole. Moreover, the 
fact that sufficient feedstocks exist to produce increasing quantities 
of advanced biodiesel and renewable diesel does not mean that those 
feedstocks are readily available or could be diverted to biofuel 
production without adverse consequences.
    Further, we expect only limited quantities of fats, oils, and 
greases and distillers corn oil to be available for increased biodiesel 
and renewable diesel production in future years (see RIA Chapter 6.2). 
We expect that the primary feedstock available to biodiesel and 
renewable diesel producers through 2025 (beyond those currently used to 
produce biodiesel and renewable diesel) will be soybean oil and canola 
oil whose primary markets are for food, with lesser contributions from 
FOG and distillers corn oil. Increased demand for soybean oil and 
canola oil could incentivize increased production of these vegetable 
oils (through increased oilseed crushing), however if the use of 
soybean and canola oil for biofuel production increases faster than the 
projected

[[Page 44516]]

increase in production we project the result to be a diversion of 
feedstocks from food and other current uses and/or increasing imports 
of soybean oil, canola oil, or other products that can be used as a 
substitute. This would have a number of implications warranting caution 
on growing volumes further, including potentially reduced GHG benefits. 
Increased production of soybean oil and canola oil could also result in 
increasing soybean and canola production in the U.S. and abroad, and in 
turn could result in greater conversion of wetlands, adverse impacts on 
ecosystems and wildlife habitat, adverse impacts on water quality and 
supply, and increased prices for agricultural commodities and food 
prices.
    Based on our analyses of all of the statutory factors, we believe 
that the candidate volumes derived in Section III.C.2 and shown in in 
Table III.C.2-1 would be reasonable and appropriate to require. These 
volumes reflect our consideration of the potential for GHG reductions 
that may result from their use, balanced with the projected increases 
in related feedstock production through 2025, the current high prices 
for vegetable oils that indicate high demand for vegetable oils 
relative to previous years, and the potential negative impacts 
associated with diverting some feedstock from existing uses to biofuel 
production. These numbers also reflect our assessment that non-
cellulosic biofuels produced in the U.S. from domestic feedstocks (or 
imported Canadian canola oil) are likely to provide benefits (domestic 
jobs in biofuel and feedstock production, support for rural economic 
growth) and/or are less likely to have adverse impacts (e.g., 
conversion of natural lands to crop production and high GHG emissions 
associated with land conversion) than imported fuels or fuels produced 
from imported feedstocks. The volumes we are finalizing are intended to 
reflect the projected increases in feedstock production in the U.S and 
Canada, particularly in 2025, while also providing continued support 
for biodiesel and renewable diesel producers.
    While we have determined that it is reasonable to require the use 
of the candidate volumes of non-cellulosic advanced biofuel for 2023-
2025, we are not establishing the advanced biofuel volume requirements 
for 2023-2025 at a level equal to the sum of the candidate volumes for 
cellulosic biofuel and non-cellulosic advanced biofuel. As discussed in 
greater detail in Section VI.D, we are establishing RFS volume 
requirements in this rule that reflect an implied conventional 
renewable fuel requirement of 15.0 billion gallons in each year.\217\ 
Since we project that the quantity of conventional renewable fuel 
available in these years will be limited, significant volumes of non-
ethanol biofuels will be needed to meet an implied conventional 
renewable fuel volume of 15.0 billion gallons. We project that the most 
likely source of non-ethanol biofuel will be biodiesel and renewable 
diesel that qualifies as BBD. Biodiesel and renewable diesel cannot be 
used to satisfy the projected shortfall in conventional renewable fuel 
if we already require the use of these fuels to meet the implied non-
cellulosic advanced biofuel volume requirement. Therefore, the RFS 
volume requirements we are establishing in this rule reflect implied 
volumes for non-cellulosic advanced biofuel that are equal to the 
candidate volumes of these fuels less the volume projected to be needed 
to meet the shortfall in the implied conventional renewable fuel 
category (plus the 250 million gallon supplemental volume for 2023). 
The implied non-cellulosic advanced biofuel volumes for 2023-2025 we 
are finalizing in this rule are summarized in Table VI.B-1.
---------------------------------------------------------------------------

    \217\ In 2023, the implied volume for conventional renewable 
fuel would be 15.00 billion gallons, but the inclusion of the 
supplemental standard of 250 million gallons makes the implied 
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.

                                  Table VI.C-1--Non-Cellulosic Advanced Biofuel
                                                 [Million RINs]
----------------------------------------------------------------------------------------------------------------
                                                                       2023            2024            2025
----------------------------------------------------------------------------------------------------------------
Candidate Volume (Total supply).................................           6,505           6,495           7,171
Needed to meet the implied Conventional Volume..................           1,155           1,045           1,221
Needed to meet the Supplemental Volume Requirement..............             250               0               0
Available for the Advanced Standard.............................           5,100           5,450           5,950
----------------------------------------------------------------------------------------------------------------

C. Biomass-Based Diesel

    As described in the preceding section, we are establishing advanced 
biofuel volumes that represent increases of 100 million, 350 million, 
and 500 million ethanol-equivalent gallons per year in the implied non-
cellulosic advanced biofuel volume requirement from 2023 through 2025. 
In concert, we are also finalizing BBD volume requirements by an 
energy-equivalent amount; 65 million physical gallons (100 million 
ethanol-equivalent gallons), 220 million physical gallons (350 million 
ethanol-equivalent gallons), and 310 million gallons (500 million 
ethanol-equivalent gallons) for 2023 through 2025 respectively. This 
approach is consistent with our policy in previous annual rules, where 
we also set the BBD volume requirement in concert with the change, if 
any, in the implied non-cellulosic advanced biofuel volume requirement. 
In reviewing the implementation of the RFS program to date we 
determined that this approach successfully balanced a desire to provide 
support for BBD producers with an increasing guaranteed market, while 
at the same time maintaining an opportunity for other advanced biofuels 
to compete within the advanced biofuel category. Our assessment of the 
impacts of BBD on the statutory factors is discussed further in the 
RIA.
    As in recent years, we believe that excess volumes of BBD beyond 
the BBD volume requirements will be used to satisfy the advanced 
biofuel volume requirement within which the BBD volume requirement is 
nested. Historically, the BBD standard has not independently driven the 
use of BBD in the market. This is due to the nested nature of the 
standards and the competitiveness of BBD relative to other advanced 
biofuels. Instead, the advanced biofuel standard has driven the use of 
BBD in the market. Moreover, BBD can also be driven by the implied 
conventional renewable fuel volume requirement as an alternative to 
using increasing volumes of corn ethanol in higher level ethanol blends 
such as E15 and E85. We believe these trends will continue through 
2025.

[[Page 44517]]

    We also believe it is important to maintain space for other 
advanced biofuels to participate in the RFS program. Although the BBD 
industry has matured over the past decade, the production of advanced 
biofuels other than biodiesel and renewable diesel continues to be 
relatively low and uncertain. Maintaining this space for other advanced 
biofuels can in the long-term facilitate increased commercialization 
and use of other advanced biofuels, which may have superior 
environmental benefits, avoid concerns with food prices and supply, and 
have lower costs relative to BBD. Conversely, we do not think 
increasing the size of this space is necessary through 2025 given that 
only small quantities of these other advanced biofuels have been used 
in recent years relative to the space we have provided for them in 
those years.

D. Conventional Renewable Fuel

    Although Congress had intended cellulosic biofuel to become the 
most widely used renewable fuel by 2022, instead, conventional 
renewable fuel has remained as the majority of renewable fuel supply 
since the RFS program began in 2005. The favorable economics of 
blending corn ethanol at 10 percent into gasoline caused it to quickly 
saturate the gasoline supply shortly after the RFS program began and it 
has remained in nearly every gallon of gasoline used for transportation 
in the United States ever since.
    The implied statutory volume target for conventional renewable fuel 
rose annually between 2009 and 2015 until it reached 15 billion gallons 
where it remained through 2022. EPA has used 15 billion gallons of 
conventional renewable fuel in calculating the applicable percentage 
standards for several recent years, most recently for 
2022.218 219
---------------------------------------------------------------------------

    \218\ EPA did not use 15 billion gallons of conventional 
renewable fuel for 2016, but instead used the general waiver 
authority to reduce that implied volume requirement below 15 billion 
gallons. The U.S. Courts of Appeals for the D.C. Circuit ruled in 
ACE that EPA had improperly used the general waiver authority, and 
remanded that rule back to EPA for reconsideration. As discussed in 
Section V, EPA is responding to this remand through the application 
of a supplemental standard in 2023 that, combined with an identical 
supplemental standard in 2022, rectifies our inappropriate use of 
the general waiver authority for 2016. The effective implied 
conventional biofuel volume for 2023 of 15.25 billion gallons is 
thus a result of the 2023 supplemental standard.
    \219\ 87 FR 39600 (July 1, 2022).
---------------------------------------------------------------------------

    As discussed in Section III.B.5, constraints on ethanol consumption 
have made reaching 15 billion gallons with ethanol alone infeasible, 
even with the incentives provided by the RFS program and after 
accounting for the projected increase in the availability of higher-
level ethanol blends such as E15 and E85. We expect these constraints 
to continue through 2025. The difficulty in reaching 15 billion gallons 
with ethanol is compounded by the fact that gasoline demand for 2023-
2025 is not projected to recover to pre-pandemic levels, and moreover 
is expected to be lower by 2025 than it was in 2022. These constraints 
are reflected in the candidate volumes for conventional renewable fuel, 
which ranged from approximately 13.8 to 14.0 billion gallons from 2023-
2025 (see Table III.C.3-1).
    Nevertheless, we do not believe that constraints on ethanol 
consumption should be the single determining factor in the appropriate 
level of conventional renewable fuel to establish for 2023-2025. The 
implied volume requirement for conventional renewable fuel is not a 
requirement for ethanol, nor even for conventional renewable fuel. 
Instead, conventional renewable fuel is that portion of total renewable 
fuel which is not required to be advanced biofuel. The implied volume 
requirement for conventional renewable fuel can also be satisfied by 
non-ethanol advanced biofuel, such as conventional biodiesel and 
renewable diesel or advanced biodiesel and renewable diesel beyond what 
is required by the advanced biofuel volume requirement.
    Higher-level ethanol blends such as E15 and E85 are one avenue 
through which higher volumes of renewable fuels can be used in the 
transportation sector to reduce GHG emissions and improve energy 
security over time, and the incentives created by the implied 
conventional renewable fuel volume requirement contribute to the 
economic attractiveness of these fuels. Moreover, sustained and 
predictable support of higher-level ethanol blends through the level of 
the implied conventional renewable fuel volume requirement helps 
provide some longer-term incentive for the market to invest in the 
necessary infrastructure. As a result, we do not believe it would be 
appropriate to reduce the implied conventional renewable fuel volume 
requirement below 15 billion gallons at this time.
    Our analysis of several of the statutory factors highlighted, in 
our view, the importance of ongoing support for corn ethanol generally 
and for an implied conventional renewable fuel volume requirement that 
helps to incentivize the domestic consumption of corn ethanol. These 
include the economic advantages to the agricultural sector, most 
notably for corn farmers, as well as employment at ethanol production 
facilities and related ethanol blending and distribution activities. 
The rural economies surrounding these industries also benefit from 
strong demand for ethanol. The consumption of ethanol, most notably 
that produced domestically, reduces our reliance on foreign sources of 
petroleum and increases the energy security status of the U.S. as 
discussed in Section IV.B.
    Although most corn ethanol production occurs in facilities that 
commenced construction prior to December 19, 2007, and is 
``grandfathered'' under the provisions of 40 CFR 80.1403, and thus is 
not required to achieve a 20 percent reduction in GHGs in comparison to 
gasoline,\220\ nevertheless, based on our current assessment of GHG 
impacts, on average corn ethanol provides some GHG reduction in 
comparison to gasoline. Greater volumes of ethanol consumed thus 
correspond to greater GHG reductions than would be the case if gasoline 
was consumed instead of ethanol.
---------------------------------------------------------------------------

    \220\ CAA section 211(o)(2)(A)(i).
---------------------------------------------------------------------------

    The volumes we are finalizing in this rule reflect an implied 
conventional renewable fuel volume of 15.0 billion gallons each year 
from 2023-2025.\221\ These volumes are consistent with the statutory 
intent of the RFS program and provide ongoing incentive for the use of 
higher-level ethanol blends. As discussed in the preceding paragraphs, 
greater use of higher-level ethanol blends is expected to result in 
benefits to rural economic development and energy security and is 
projected to reduce GHG emissions from the transportation sector. While 
we recognize that ethanol consumption is highly unlikely to reach 15.0 
billion gallons in any year through 2025 there are sufficient volumes 
of non-ethanol renewable fuels to enable the total renewable fuel 
volume requirements to be met.
---------------------------------------------------------------------------

    \221\ In 2023, the implied volume for conventional renewable 
fuel is 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.
---------------------------------------------------------------------------

    In our proposed rule, the RFS volumes reflected an implied 
conventional renewable fuel volume of 15.25 billion gallons for 2024 
and 2025. In comments on our proposed rule multiple stakeholders stated 
that any increase in the implied volume requirement for conventional 
renewable fuel above 15 billion gallons was inconsistent with Congress' 
intention that all increases in renewable fuel between 2015 and 2022 be 
in advanced biofuel, with conventional renewable fuel static at 15 
billion gallons. We

[[Page 44518]]

continue to believe that EPA has authority to establish RFS volumes 
that reflect an implied conventional renewable fuel volume that is 
greater than 15.0 billion gallons if these volumes are supported by our 
analysis of the statutory factors. However, after reviewing the public 
comments and available data we have decided to finalize RFS volumes 
that reflect an implied conventional renewable fuel volume of 15.0 
billion gallons each year from 2023-2025. We believe these volumes are 
supported by our analysis of the statutory factors, are consistent with 
the statutory intent of the RFS program, and appropriately balance a 
desire to provide continued incentives for higher level ethanol blends 
and a desire to incentivize increasing production and use of advanced 
biofuels.
    Table VI.B-1. shows the types of biofuel we project will be 
supplied to meet the implied conventional renewable fuel volumes, 
including both conventional ethanol and non-cellulosic advanced 
biofuels beyond those needed to satisfy the advanced biofuel volume 
requirements.

                   Table VI.D-1--Meeting the Candidate Volume for Conventional Renewable Fuel
                                                 [Million RINs]
----------------------------------------------------------------------------------------------------------------
                                                                       2023            2024            2025
----------------------------------------------------------------------------------------------------------------
Conventional ethanol............................................          13,845          13,955          13,779
Non-cellulosic advanced biofuel.................................           1,405           1,045           1,221
    Total.......................................................      \a\ 15,250          15,000          15,000
----------------------------------------------------------------------------------------------------------------
\a\ Includes the additional 250 million RINs needed to satisfy 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 2023 (after 
accounting for the supplemental standard) and 15.0 billion gallons in 
2024 and 2025. A review of the recent RIN generation data suggests that 
conventional biodiesel and renewable diesel are unlikely to be supplied 
to the U.S. market if sufficient volumes of advanced biodiesel and 
renewable diesel are available. 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 production capacity from 
grandfathered biodiesel and renewable diesel facilities is 
approximately 2.5 billion gallons.

E. Summary of Final Volume Requirements

    For the reasons described above, we are establishing RFS volume 
requirements based the four component categories discussed above. The 
volumes for each of the component categories (sometimes referred to as 
implied volume requirements) are summarized in Table VI.E-1. Also shown 
is the supplemental volume requirement addressing the 2016 remand, 
discussed more fully in Section V.

                        Table VI.E-1--Final Volume Requirements for Component Categories
                                                 [Billion RINs]
----------------------------------------------------------------------------------------------------------------
                                                                       2023            2024            2025
----------------------------------------------------------------------------------------------------------------
Cellulosic biofuel..............................................            0.84            1.09            1.38
Biomass-based diesel \a\........................................            2.82            3.04            3.35
Non-cellulosic advanced biofuel.................................            5.10            5.45            5.95
Conventional renewable fuel.....................................           15.00           15.00           15.00
Supplemental volume requirement.................................            0.25               0               0
----------------------------------------------------------------------------------------------------------------
\a\ BBD volumes are given in billion gallons.

    These final volumes are similar to, but higher than the volumes in 
the proposed rule (after accounting for the fact that we are not 
finalizing the proposed eRIN provisions in this rule). Specifically, 
the cellulosic biofuel volumes are higher for all three years. The 
volumes for non-cellulosic advanced biofuels in this final rule are 
equal to the volumes from the proposed rule in 2023, and 250 million 
and 650 million ethanol-equivalent gallons higher in 2024 and 2025 
respectively. Finally, the volumes for conventional biofuel in this 
final rule are equal to the volumes in the proposed rule for 2023, and 
250 million gallons lower for 2024 and 2025. The volumes for each of 
the four component categories shown in the table above can be combined 
to produce volume requirements for the four statutory categories on 
which the applicable percentage standards are based. The results are 
shown below.

                        Table VI.E-2--Final Volume Requirements for Statutory Categories
                                                 [Billion RINs]
----------------------------------------------------------------------------------------------------------------
                                                                       2023            2024            2025
----------------------------------------------------------------------------------------------------------------
Cellulosic biofuel..............................................            0.84            1.09            1.38
Biomass-based diesel \a\........................................            2.82            3.04            3.35
Advanced biofuel................................................            5.94            6.54            7.33
Total renewable fuel............................................           20.94           21.54           22.33

[[Page 44519]]

 
Supplemental volume requirement.................................            0.25               0               0
----------------------------------------------------------------------------------------------------------------
\a\ BBD volumes are given in billion gallons.

    We believe that these volume requirements will preserve and 
continue the gains made through biofuels in previous years when the 
statute specified applicable volume targets. In particular, these 
volume requirements will help ensure that the transportation sector 
will realize additional reductions in GHGs and that the U.S. will 
experience greater energy independence and energy security. The volume 
requirements will also promote ongoing development within the biofuels 
and agriculture industries as well as the economies of the rural areas 
in which biofuels production facilities and feedstock production 
reside.
    As discussed in Section II, our volume requirements for 2023 and 
the associated percentage standards will not be in place prior to the 
beginning of 2023, and we are establishing the 2024 applicable volumes 
after the statutory deadline. For the reasons described in Section II, 
the standards are nonetheless appropriate.

VII. Percentage Standards for 2023-2025

    EPA has historically implemented the nationally applicable volume 
requirements by establishing percentage standards that apply to 
obligated parties, consistent with the statutory requirements at CAA 
section 211(o)(3)(B). The statute gives EPA discretion as to how 
applicable volume requirements should be implemented for years after 
2022. The CAA requires EPA to promulgate regulations that, regardless 
of the date of promulgation, contain compliance provisions applicable 
to refineries, blenders, distributors, and importers that ensure that 
the volumes in CAA section 211(o)(2)(B), which includes set volumes, 
are met.\222\ Further, under the statutory requirement that we review 
implementation of the program in prior years as part of our 
determination of the appropriate volume requirements for years after 
2022,\223\ we considered the past effectiveness of the use of 
percentage standards as the implementation mechanism for volume 
requirements. We determined that this mechanism continues to be 
effective and reasonable, and obligated parties are, at this point, 
very familiar with this implementation mechanism. We were also unable 
to identify any straightforward and easily implementable alternative 
mechanisms, nor were any suggested in comments on the proposal. 
Therefore, we are continuing to use percentage standards as the 
implementing mechanism for years after 2022.
---------------------------------------------------------------------------

    \222\ CAA section 211(o)(2)(A)(i) and (iii).
    \223\ CAA section 211(o)(2)(B)(ii).
---------------------------------------------------------------------------

    The obligated parties to which the percentage standards apply are 
producers and importers of gasoline and diesel, as defined by 40 CFR 
80.1406(a).\224\ Each obligated party multiplies the percentage 
standards by the sum of all non-renewable gasoline and diesel they 
produce or import to determine their Renewable Volume Obligations 
(RVOs).\225\ The RVOs are the number of RINs that the obligated party 
is responsible for procuring to demonstrate compliance with the 
applicable standards for that year. Since there are four separate 
standards under the RFS program, there are likewise four separate RVOs 
applicable to each obligated party for each year.\226\ The renewable 
fuel volumes used to determine the 2023, 2024, and 2025 percentage 
standards are described in Section VI.E and are shown in Table VII-1.
---------------------------------------------------------------------------

    \224\ Note that in this action, we are moving the definition of 
``obligated party'' without modification from 40 CFR 80.1406(a) to 
40 CFR 80.2. This is part of an effort to consolidate all defined 
terms into a single regulatory section. In Section IX.K, we further 
discuss the consolidation of all definitions in 40 CFR part 80, 
subpart M, into the definitions section at 40 CFR 80.2. EPA is not 
reopening the definition of obligated party.
    \225\ 40 CFR 80.1407.
    \226\ As discussed in Section V, we are finalizing a 
supplemental standard for 2023 to address the remand of the 2016 
standards under ACE. That supplemental standard is in addition to 
the four standards required under the statute, though as described 
in Section V, compliance demonstrations for total renewable fuel and 
the supplemental standard will be combined in annual compliance 
reports submitted under 40 CFR 80.1451.

                 Table VII-1--Volumes for Use in Determining the Applicable Percentage Standards
                                                 [Billion RINs]
----------------------------------------------------------------------------------------------------------------
                                                                       2023            2024            2025
----------------------------------------------------------------------------------------------------------------
Cellulosic biofuel..............................................            0.84            1.09            1.38
Biomass-based diesel \a\........................................            2.82            3.04            3.35
Advanced biofuel................................................            5.94            6.54            7.33
Renewable fuel..................................................           20.94           21.54           22.33
Supplemental standard...........................................            0.25             n/a             n/a
----------------------------------------------------------------------------------------------------------------
\a\ The BBD volumes are in physical gallons (rather than RINs).

    As described in Section II.D, EPA is permitted to establish 
applicable percentage standards for multiple future years after 2022 in 
a single action for as many years as it establishes volume 
requirements.

A. Calculation of Percentage Standards

    The formulas used to calculate the percentage standards applicable 
to obligated parties are provided in 40 CFR 80.1405(c). We are 
continuing to use the percentage standard mechanism to implement the 
volume requirements for years after 2022.
    In addition to the required volumes of renewable fuel, the formulas 
also require estimates of the volumes of non-renewable gasoline and 
diesel, for both highway and nonroad uses, that are projected to be 
used in the year in which the standards will apply. In previous annual 
standard-setting rules,

[[Page 44520]]

the statute required the Energy Information Administration (EIA) to 
provide to EPA projected volumes of transportation fuel to be sold or 
introduced into commerce in the United States for the following 
calendar year by October 31 of each year.\227\ However, the last year 
to which this statutory requirement applied was 2021 and therefore it 
does not apply to compliance years after 2022. Moreover, historically 
the transportation fuel projections EIA provided to EPA consisted of 
the gasoline and diesel volume projections from EIA's Short Term Energy 
Outlook (STEO).\228\ The STEO only provides volume projections for one 
future calendar year, which was sufficient to inform past annual 
standard-setting rulemakings as they never established applicable 
percentage standards for more than one future calendar year. In 
contrast, this rulemaking establishes volume requirements and 
associated percentage standards for three future calendar years. 
Therefore, we cannot use the STEO as a source for projections of 
gasoline and diesel for this action and are instead using EIA's 2023 
Annual Energy Outlook (AEO) for the purposes of calculating the 
percentage standards in this action.\229\
---------------------------------------------------------------------------

    \227\ CAA section 211(o)(3)(A).
    \228\ See, for example, ``EIA letter to EPA with 2020 volume 
projections 10-9-2019,'' available in the docket.
    \229\ Available at https://www.eia.gov/outlooks/aeo.
---------------------------------------------------------------------------

    Before using EIA's projections of gasoline and diesel, however, 
several adjustments need to be made. First, the projected gasoline and 
diesel volumes in AEO 2023 include projections of renewable fuels used 
in transportation fuel (e.g., ethanol, biodiesel, and renewable 
diesel). Since renewable fuels are not subject to the percentage 
standards, the volumes of renewable fuel are subtracted out of the EIA 
projections of gasoline and diesel. Second, the projected diesel 
volumes in AEO 2023 also include projections of diesel used in ocean-
going vessels. Since fuel used in ocean-going vessels is explicitly 
excluded from the definition of transportation fuel in 40 CFR 80.2--and 
therefore is not an obligated fuel and does not incur an RVO under the 
RFS program--the volumes of these fuels are subtracted out of the EIA 
projections of diesel. Third, the projected gasoline, diesel, and 
renewable fuel volumes in AEO 2023 include projections of these fuels 
used in Alaska. Since Alaska is not part of the RFS covered area--and 
therefore fuel used in this state is excluded from the RFS program--the 
volumes of gasoline, diesel, and renewable fuel used in Alaska are 
subtracted out of EIA's nationwide projections of these fuels.\230\ 
Finally, as discussed in RIA Chapter 1.11, EPA has determined that it 
is necessary to make an adjustment to the projections of gasoline and 
diesel provided by EIA in AEO 2023 to accurately reflect the gasoline 
and diesel volumes ultimately used by obligated parties in their RVO 
calculations. The table below provides the precise projections from AEO 
2023 used to calculate the percentage standards for 2023-2025.
---------------------------------------------------------------------------

    \230\ State-specific projections of gasoline, diesel, and 
renewable fuel usage are not provided in AEO 2023. Instead, we use 
data from EIA's State Energy Data System (SEDS) to estimate the 
portion of these fuels used in Alaska, available at https://www.eia.gov/state/seds/seds-data-fuel.php.

 Table VII.A-1--AEO 2023 Volumes Used for the Calculation of Percentage
                         Standards for 2023-2025
------------------------------------------------------------------------
        Fuel category                 Table                 Line
------------------------------------------------------------------------
Gasoline.....................  Table 11 \a\.......  Product Supplied/by
                                                     Fuel/Motor
                                                     Gasoline.
Renewables blended into        Table 2............  Energy Use & Related
 gasoline.                                           Statistics/Ethanol
                                                     (denatured)
                                                     Consumed in Motor
                                                     Gasoline.
                               Table 11...........  Biofuels/Other
                                                     Biomass-derived
                                                     Liquids.
Diesel.......................  Table 11...........  Product Supplied/by
                                                     Fuel/Distillate
                                                     fuel oil/of which:
                                                     Diesel.
Renewables blended into        Table 11...........  Biofuels/Biodiesel.
 diesel.
                                                    Biofuels/Renewable
                                                     Diesel.
Diesel used in ocean-going     Table 49...........  International
 vessels.                                            Shipping/Distillate
                                                     Fuel Oil (diesel).
------------------------------------------------------------------------
\a\ In the proposal for this action, we used the gasoline demand
  forecasts from Table 2 of AEO 2022 to calculate the proposed
  percentage standards. We intended to use Table 2 of AEO 2023 to
  calculate the percentage standards in this action as well; however,
  EIA informed EPA that 2023 gasoline demand forecast in Table 2 is not
  benchmarked to STEO whereas it is in Table 11 and directed EPA to use
  the values in Table 11 instead.

    In order to convert projections provided by EIA in energy units 
into the volumes needed for the calculation of percentage standards, we 
used the conversion factors provided in AEO 2023 Table 68.\231\
---------------------------------------------------------------------------

    \231\ Available at https://www.eia.gov/outlooks/aeo/data/browser/#/?id=20-AEO2023&cases=ref2023&sourcekey=0.
---------------------------------------------------------------------------

B. Treatment of Small Refinery Volumes

    In CAA section 211(o)(9), Congress provided for qualifying small 
refineries to be temporarily exempt from RFS compliance through 
December 31, 2010. Congress also provided that small refineries could 
receive an extension of the exemption beyond 2010 based either on the 
results of a required Department of Energy (DOE) study or in response 
to individual petitions demonstrating that the small refinery suffered 
``disproportionate economic hardship.'' CAA section 
211(o)(9)(A)(ii)(II) and (B)(i).
    The annual percentage standards herein are based on our projection 
that no gasoline or diesel produced by small refineries will be exempt 
from RFS requirements pursuant to CAA section 211(o)(9) for 2023-2025. 
In April and June 2022, EPA denied 105 pending SRE petitions for years 
spanning 2016 through 2020, finding that, consistent with the holding 
of the U.S. Court of Appeals for the Tenth Circuit in Renewable Fuels 
Association v. EPA, SREs can only be granted under CAA section 
211(o)(9) if a small refinery demonstrates that it would suffer 
disproportionate economic hardship caused by compliance with the RFS 
program requirements and not due, even in part, to other factors.\232\ 
In applying this new statutory interpretation, we found that that none 
of the small refinery petitioners suffered disproportionate economic 
hardship caused by their compliance with the RFS because all obligated 
parties, including small refineries, are able to pass through the costs 
of their RFS compliance (i.e., RIN costs) to their customers in the 
form of higher sales prices for gasoline and diesel. Accordingly, we 
denied all SRE petitions pending at that time.\233\
---------------------------------------------------------------------------

    \232\ Renewable Fuels Assn v. EPA, 948 F.3d 1206, 1253-54 (10th 
Cir. 2020); see generally, April 2022 SRE Denial Action and June 
2022 SRE Denial Action.
    \233\ For a fuller discussion of EPA's revised statutory 
interpretation and analysis of the costs of RFS compliance, see the 
April and June 2022 Denial Actions at Section IV.D.

---------------------------------------------------------------------------

[[Page 44521]]

    Absent new arguments and supporting data to the contrary, we 
anticipate that the CAA interpretation and analysis presented in the 
April and June 2022 SRE Denial Actions will also apply to these future-
year SRE petitions. Consequently, at this time, we anticipate that no 
SREs will be granted for these future years, including the 2023-2025 
compliance years covered by this action. Therefore, we project that the 
exempt volumes from SREs to be included in the calculation specified by 
40 CFR 80.1405(c) for 2023, 2024, and 2025 will be zero, and all small 
refineries will be required to comply with their proportional RFS 
obligations.\234\ Nevertheless, because the obligations are calculated 
by applying the percentage standards to gasoline and diesel production 
volume, the RFS volume obligations on small refineries are 
proportionally smaller than on larger obligated parties. Even were EPA 
to grant an SRE in the future for 2023-2025, we do not plan to revise 
the percentage standards to account for such an exemption.\235\
---------------------------------------------------------------------------

    \234\ We are not prejudging any SRE petitions in this action; 
however, absent a sufficient demonstration that a small refinery 
experiences DEH caused by compliance with the RFS program, we do not 
anticipate granting SREs in the future.
    \235\ See Renewable Fuel Standard (RFS) Program: RFS Annual 
Rules, Response to Comments, EPA-420-R-22-009, June 2022, at 145 for 
further discussion on our approach to this projection in the event 
we grant a future SRE.
---------------------------------------------------------------------------

C. Percentage Standards

    The formulas in 40 CFR 80.1405 for the calculation of the 
percentage standards require the specification of a total of 14 
variables comprising the renewable fuel volume requirements, projected 
gasoline and diesel demand for all states and territories where the RFS 
program applies, renewable fuels projected by EIA to be included in the 
gasoline and diesel demand, and projected gasoline and diesel volumes 
from exempt small refineries. The values of all the variables used for 
this rule are shown in Table VII.C-1 for 2023, 2024, and 2025.\236\
---------------------------------------------------------------------------

    \236\ See ``Calculation of Final 2023-2025 Percentage 
Standards,'' available in the docket for this action.

                   Table VII.C-1--Volumes for Terms in Calculation of the Percentage Standards
                                                 [Billion RINs]
----------------------------------------------------------------------------------------------------------------
                                                                                 2023
             Term                         Description               2023     Supplemental      2024       2025
----------------------------------------------------------------------------------------------------------------
RFVCB.........................  Required volume of cellulosic         0.84            0.00       1.09       1.38
                                 biofuel.
RFVBBD........................  Required volume of biomass-           2.82            0.00       3.04       3.35
                                 based diesel \a\.
RFVAB.........................  Required volume of advanced           5.94            0.00       6.54       7.33
                                 biofuel.
RFVRF.........................  Required volume of renewable         20.94            0.25      21.54      22.33
                                 fuel.
G.............................  Projected volume of gasoline...     138.62          138.62     139.57     137.49
D.............................  Projected volume of diesel.....      55.44           55.44      52.59      52.04
RG............................  Projected volume of renewables       14.48           14.48      14.89      14.77
                                 in gasoline.
RD............................  Projected volume of renewables        4.48            4.48       4.93       4.73
                                 in diesel.
GS............................  Projected volume of gasoline          0.00            0.00       0.00       0.00
                                 for opt-in areas.
RGS...........................  Projected volume of renewables        0.00            0.00       0.00       0.00
                                 in gasoline for opt-in areas.
DS............................  Projected volume of diesel for        0.00            0.00       0.00       0.00
                                 opt-in areas.
RDS...........................  Projected volume of renewables        0.00            0.00       0.00       0.00
                                 in diesel for opt-in areas.
GE............................  Projected volume of gasoline          0.00            0.00       0.00       0.00
                                 for exempt small refineries.
DE............................  Projected volume of diesel for        0.00            0.00       0.00       0.00
                                 exempt small refineries.
----------------------------------------------------------------------------------------------------------------
\a\ The BBD volume used in the formula represents physical gallons. The formula contains a 1.6 multiplier to
  convert this physical volume to ethanol-equivalent volume, consistent with the change to the BBD conversion
  factor discussed in Section X.D.

    Using the volumes shown in Table VII.C-1, we have calculated the 
percentage standards for 2023, 2024, and 2025 as shown in Table VII.C-
2.

                                       Table VII.C-2--Percentage Standards
----------------------------------------------------------------------------------------------------------------
                                                                     2023 (%)        2024 (%)        2025 (%)
----------------------------------------------------------------------------------------------------------------
Cellulosic biofuel..............................................            0.48            0.63            0.81
Biomass-based diesel............................................            2.58            2.82            3.15
Advanced biofuel................................................            3.39            3.79            4.31
Renewable fuel..................................................           11.96           12.50           13.13
Supplemental standard...........................................            0.14             n/a             n/a
----------------------------------------------------------------------------------------------------------------

    The percentage standards shown in Table VII.C-2 are included in the 
regulations at 40 CFR 80.1405(a) and apply to producers and importers 
of gasoline and diesel.

VIII. Administrative Actions

A. Assessment of the Domestic Aggregate Compliance Approach

[[Page 44522]]

    The RFS regulations specify an ``aggregate compliance'' approach 
for demonstrating that planted crops and crop residue from the U.S. 
comply with the ``renewable biomass'' requirements that address lands 
from which qualifying feedstocks may be harvested.\237\ In the 2010 
RFS2 rulemaking, EPA established a baseline number of acres for U.S. 
agricultural land in 2007 (the year of EISA's enactment) and determined 
that as long as this baseline number of acres is not exceeded, it is 
unlikely, based on our assessment of historical trends and economic 
considerations, that new land outside of the 2007 baseline is being 
devoted to crop production. The regulations specify, therefore, that 
renewable fuel producers using planted crops or crop residue from the 
U.S. as feedstock in renewable fuel production need not undertake 
individual recordkeeping and reporting related to documenting that 
their feedstocks come from qualifying lands, unless EPA determines 
through one of its annual evaluations that the 2007 baseline acreage of 
402 million acres agricultural land has been exceeded. The regulations 
promulgated in 2010 require EPA to make an annual finding concerning 
whether the 2007 baseline amount of U.S. agricultural land has been 
exceeded in a given year. If the baseline is found to have been 
exceeded, then producers using U.S. planted crops and crop residue as 
feedstocks for renewable fuel production would be required to comply 
with individual recordkeeping and reporting requirements to verify that 
their feedstocks are renewable biomass.
---------------------------------------------------------------------------

    \237\ 40 CFR 80.1454(g). EPA established the ``aggregate 
compliance'' approach in the 2010 RFS2 rule and has applied it for 
the U.S. in annual RFS rulemakings since then. See 75 FR 14701-04. 
In this final rule, we have not reexamined or reopened this policy, 
including the regulations at 40 CFR 80.1454(g) and 80.1457. 
Similarly, as further explained below, we have applied this approach 
for Canada since our approval of Canada's petition to use aggregate 
compliance in 2011. In this final rule, we have also not reexamined 
or reopened our decision on that petition. Any comments we received 
on these issues are beyond the scope of this rulemaking.
---------------------------------------------------------------------------

    Based on data provided by the USDA Farm Service Agency (FSA) and 
Natural Resources Conservation Service (NRCS), we have estimated that 
U.S. agricultural land reached approximately 384.7 million acres in 
2022 and thus did not exceed the 2007 baseline acreage of 402 million 
acres.238 239 We will continue to monitor total agricultural 
land annually to determine if national agricultural land acreage 
increases above this 2007 national aggregate baseline, as specified in 
the RFS2 Rule.\240\
---------------------------------------------------------------------------

    \238\ For additional analysis and the underlying USDA data, see 
``Assessment of Domestic Aggregate Compliance Approach 2022,'' 
available in the docket for this action.
    \239\ USDA also provided EPA with 2021 data from the 
discontinued Grassland Reserve Program (GRP) and Wetlands Reserve 
Program (WRP). Given this data, EPA estimated the total U.S. 
agricultural land both including and omitting the GRP and WRP 
acreage. In 2021, combined land under GRP and WRP totaled 2,993,177 
acres. Subtracting the GRP and WRP acreage in addition to the 
Agriculture Conservation Easement Program acreage yields an estimate 
of 379.6 million total acres of U.S. agricultural land in 2021. Just 
subtracting the Agriculture Conservation Easement Program leads to 
an estimate of 382.6 million total acres of U.S. agricultural land 
in 2021.
    \240\ 75 FR 14701.
---------------------------------------------------------------------------

B. Assessment of the Canadian Aggregate Compliance Approach

    The RFS regulations specify a petition process through which EPA 
may approve the use of an aggregate compliance approach for planted 
crops and crop residue from foreign countries.\241\ On September 29, 
2011, EPA approved such a petition from the Government of Canada.\242\ 
The total agricultural land in Canada in 2022 is estimated at 116.4 
million acres. This total agricultural land area includes 94.9 million 
acres of cropland and summer fallow, 11.7 million acres of pastureland, 
and 9.8 million acres of agricultural land under conservation 
practices. This acreage estimate is based on the same methodology used 
to set the 2007 baseline acreage for Canadian agricultural land in 
EPA's response to Canada's petition. This 2022 acreage does not exceed 
the 2007 baseline acreage of 122.1 million acres.\243\ We will continue 
to monitor total agricultural land annually to determine if Canadian 
agricultural land acreage increases above its 2007 aggregate baseline, 
as specified in the RFS2 Rule.\244\
---------------------------------------------------------------------------

    \241\ 40 CFR 80.1457.
    \242\ See ``EPA Decision on Canadian Aggregate Compliance 
Approach Petition'' (Docket Item No. EPA-HQ-OAR-2011-0199-0015).
    \243\ The data used to make this calculation can be found in 
``Assessment of Canadian Aggregate Compliance Approach 2022,'' 
available in the docket for this action.
    \244\ 75 FR 14701.
---------------------------------------------------------------------------

IX. Biogas Regulatory Reform

    We are finalizing biogas regulatory reform provisions to allow for 
the use of biogas as a biointermediate and RNG as a feedstock to 
produce biogas-derived renewable fuels other than renewable CNG/
LNG.\245\ The biogas regulatory reform provisions will also 
substantially help improve oversight of the program and mitigate 
against the potential for parties to double-count biogas and RNG given 
the program's expansion, thereby helping to ensure that only valid RINs 
are generated for biogas-derived renewable fuels. EPA received comment 
from many stakeholders on our proposed biogas regulatory reform 
provisions; we summarize and respond to all comments received in RTC 
Section 10.
---------------------------------------------------------------------------

    \245\ For purposes of this section of the preamble, by renewable 
natural gas or RNG, we mean a product derived from biogas that is 
produced from renewable biomass and that meets the natural gas 
commercial distribution pipeline specification for the pipeline that 
it is injected into. We refer to biogas that is produced from 
renewable biomass and that has undergone treatment to remove 
impurities and inert gases to a level suitable for its use to 
produce renewable CNG/LNG, but is not injected onto the natural gas 
commercial pipeline system as treated biogas. Generally, the primary 
difference between RNG and treated biogas is that RNG is injected 
onto the natural gas commercial distribution system and treated 
biogas is distributed via a closed, private distribution system. 
Biomethane is the methane component of biogas, treated biogas, and 
RNG that is derived from renewable biomass. Under the previous and 
new regulations, RIN generation is based on the energy, in BTUs, 
from biomethane (exclusive of impurities, inert gases often found 
with biomethane in biogas) that is demonstrated to be used as 
transportation fuel.
---------------------------------------------------------------------------

A. Background

1. Statutory Authority
    Congress established the RFS2 program in the 2007 Energy 
Independence and Security Act (EISA). Among other revisions to the 
prior RFS1 program that had been established by EPAct 2005, EISA 
defined renewable fuel as ``fuel that is produced from renewable 
biomass and that is used to replace or reduce the quantity of fossil 
fuel present in a transportation fuel.'' \246\ This definition has two 
relevant key components, both of which are necessary to generate RINs: 
(1) The fuel must be produced from renewable biomass, and (2) The fuel 
must be used to replace or reduce fossil fuel used as transportation 
fuel. EISA also provided a definition of ``renewable biomass,'' 
enumerating the seven categories of feedstocks that can be used to 
produce qualifying renewable fuel under RFS2.\247\ This statutory 
definition of renewable biomass includes, among other things, separated 
yard waste, separated food waste, animal waste material, and crop 
residue, any of which are commonly used to produce biogas through 
anaerobic digestion.\248\ EISA, as reflected in CAA section 
211(o)(2)(A)(i),

[[Page 44523]]

also directs EPA to ``promulgate'' and ``revise'' ``regulations . . . 
to ensure that transportation fuel sold or introduce into commerce . . 
. contains at least the applicable volume of renewable fuel, advanced 
biofuel, cellulosic biofuel, and biomass-based diesel.'' The 
regulations EPA is promulgating as part of biogas regulatory reform in 
this action are necessary to ensure that biogas and RNG used to produce 
fuels that are in turn used to satisfy the statutory volume 
requirements actually qualify as renewable fuel, i.e., are actually 
produced from renewable biomass and used as transportation fuel.
---------------------------------------------------------------------------

    \246\ CAA section 211(o)(1)(J).
    \247\ CAA section 211(o)(1)(I).
    \248\ Biogas was explicitly included in EPAct 2005 as a 
renewable fuel and therefore was included in the RFS1 program that 
applied from 2006-2009. In the 2010 rulemaking that established the 
RFS2 program based on changes to CAA section 211(o) enacted through 
EISA in 2007, we concluded that biogas was a qualifying renewable 
fuel if it is produced from ``renewable biomass.'' See 75 FR 14685-
14686 (March 26, 2010).
---------------------------------------------------------------------------

    Additionally, the statutory definition of advanced biofuel at CAA 
section 211(o)(1)(B)(ii)(V) explicitly identifies biogas as a valid 
form of advanced biofuel. However, the statute does not specify how 
biogas that is produced from renewable biomass must be used in order to 
qualify as renewable fuel (i.e., in the form of CNG or LNG, or in some 
other form). Biogas can be used as a feedstock to create renewable CNG/
LNG, through clean-up and compression, or to produce other fuels, such 
as hydrogen or Fischer-Tropsch fuels. In this action, we are putting in 
place provisions that will allow for biogas to be used as a 
biointermediate feedstock to produce renewable fuels other than 
renewable CNG/LNG. As explained in our action establishing a 
biointermediates program, biointermediates are simply renewable biomass 
feedstocks that are partially processed at one facility before being 
transported to a different facility to complete processing into 
renewable fuel.\249\ While EPA had historically not permitted 
feedstocks to be processed at multiple facilities due to implementation 
and oversight concerns, we recently expanded the program to allow 
processing at two different facilities under certain circumstances. In 
establishing the initial biointermediates program, EPA did not include 
biogas as a biointermediate because we acknowledged that the 
regulations we were promulgating at that time would not be appropriate 
for the more complex circumstances of biogas. The biogas regulatory 
reform regulations we are promulgating in this action provide the 
compliance and oversight mechanisms necessary to allow biogas to be 
processed into a biointermediate at one facility and then further 
processed into renewable fuel at a second facility while remaining 
consistent with the statutory requirements and applicable RFS 
pathway.\250\
---------------------------------------------------------------------------

    \249\ 87 FR 39600, 39635-51 (July 1, 2022).
    \250\ The regulations similarly allow RNG that has been placed 
on a commercial pipeline be withdrawn and used to produce renewable 
fuel.
---------------------------------------------------------------------------

2. Regulatory History
    In the 2010 RFS2 rule, EPA included regulatory provisions for the 
generation of advanced biofuel (D code 5, or D5) RINs from biogas used 
as transportation fuel. The RFS2 regulations listed biogas as the fuel 
and included provisions for how a party demonstrated that biogas was 
used as transportation fuel. However, biogas as the term is defined in 
EPA's regulations and often used by industry is not actually a product 
that can be used as a transportation fuel. Biogas must undergo 
significant treatment to be used as a fuel especially in the form CNG/
LNG because impurities found in biogas could cause substantial 
operability issues thereby harming CNG/LNG engines. Additionally, after 
promulgating the pathway for D5 RINs EPA received several pathway 
petitions requesting that EPA allow for the generation of cellulosic 
biofuel (D code 3, or D3) RINs for biogas produced from cellulosic 
feedstocks.
    In 2014, EPA finalized the RFS ``Pathways II'' rule, which among 
other things added specific RIN-generating pathways for renewable CNG, 
renewable LNG, and renewable electricity to rows Q and T to Table 1 of 
40 CFR 80.1426 (``Pathway Q'' and ``Pathway T'', respectively).\251\ 
Pathway Q allowed for D3 RIN generation for renewable CNG/LNG produced 
from biogas from landfills, municipal wastewater treatment facility 
digesters, agricultural digesters, and separated municipal solid waste 
(MSW) digesters, as well as biogas from the cellulosic components of 
biomass processed in other waste digesters. Pathway T allowed for D5 
RIN generation for renewable CNG/LNG from biogas from waste digesters, 
which encompasses non-cellulosic biogas. These two pathways were 
structured so that biogas from approved sources would be the feedstock 
and renewable CNG/LNG would be the finished fuel for RIN generation 
purposes.
---------------------------------------------------------------------------

    \251\ 79 FR 42128 (July 18, 2014).
---------------------------------------------------------------------------

    The Pathways II rule also established a then new set of regulatory 
provisions that detail the criteria necessary for biogas to be 
demonstrated to be renewable fuel and thus eligible to generate RINs. 
The regulations address two scenarios under which renewable CNG/LNG is 
produced and used for transportation. First, for renewable CNG/LNG 
produced from biogas that is only distributed via a closed, private, 
non-commercial system, the renewable CNG/LNG must be produced from 
renewable biomass under an EPA-approved pathway and demonstrated to be 
sold and used as transportation fuel.\252\ Under this scenario, only 
renewable CNG/LNG that was produced and distributed as transportation 
fuel in a closed, private non-commercial system could generate RINs. 
Typically, parties that generate RINs under the closed scenario are 
directly supplying renewable CNG/LNG to a CNG/LNG fleet in close 
proximity to where the biogas is produced and collected and in many 
cases the party that generates the RIN is the same party that owns/
operates the CNG/LNG fleet.
---------------------------------------------------------------------------

    \252\ 40 CFR 80.1426(f)(10)(i).
---------------------------------------------------------------------------

    The second scenario under which RINs could be generated for 
renewable CNG/LNG addresses when renewable CNG/LNG is introduced into a 
commercial distribution system (e.g., natural gas commercial pipeline 
system). In addition to demonstrating that the CNG/LNG is produced from 
renewable biomass under an EPA-approved pathways and sold and used as 
transportation fuel, potential RIN generators under this scenario must 
also demonstrate that the RNG was loaded onto and withdrawn from a 
physically-connected natural gas commercial distribution system, that 
the amount of CNG/LNG sold as transportation fuel corresponds with the 
amount of RNG placed onto the natural gas commercial distribution 
system, and that no other party relied on the RNG for the creation of 
RINs.\253\ These additional requirements for CNG/LNG transmitted via a 
natural gas commercial distribution system were designed to ensure that 
the amount of renewable CNG/LNG claimed to have been used as 
transportation fuel corresponds with the amount of RNG placed onto the 
natural gas commercial distribution system and that such CNG/LNG is not 
double counted for RIN generation.
---------------------------------------------------------------------------

    \253\ 40 CFR 80.1426(f)(11)(i).
---------------------------------------------------------------------------

    Since promulgation of the prior regulatory provisions in the RFS 
Pathways II rule,\254\ many parties have requested that EPA approve 
pathways to allow the use of biogas as a biointermediate to produce 
various types of fuels (e.g., steam methane reforming the biogas into 
hydrogen or using a Fischer-Tropsch process to turn biogas into 
renewable diesel). These parties have suggested that EPA should 
encourage these biogas-derived renewable fuels to increase the

[[Page 44524]]

production and use of advanced and cellulosic renewable fuels.
---------------------------------------------------------------------------

    \254\ See 79 FR 42128 (July 18, 2014).
---------------------------------------------------------------------------

    In the 2020-2022 RFS Standards Rule, we promulgated regulatory 
provisions that allowed for the generation of RINs from renewable fuels 
produced from biointermediates.\255\ However, we did not include the 
use of biogas as a biointermediate at that time. While we recognized 
the opportunity to increase the availability of advanced and cellulosic 
biogas-derived renewable fuels in support of the statutory goals, we 
also noted that allowing biogas or contracted RNG to be used as an 
input to produce a fuel other than renewable CNG/LNG entails adding 
further layers of complexity to a system that is already challenging to 
implement and oversee. In response to the significant number of 
comments requesting the inclusion of biogas a biointermediate in the 
2020-2022 RFS Standards Rule, we stated that we neither developed nor 
proposed the provisions that would be necessary to address the unique 
circumstances associated with biogas as a biointermediate and that we 
intended to address the use of biogas as a biointermediate in a future 
rulemaking.\256\ We believed then, and still believe, that the previous 
biogas provisions \257\ must be modified to ensure that biogas is not 
double counted in a situation where biogas may have multiple uses 
(e.g., as renewable CNG/LNG or as a biointermediate).
---------------------------------------------------------------------------

    \255\ 87 FR 39600 (July 1, 2022).
    \256\ See 87 FR 39600, 39641 (July 1, 2022).
    \257\ For purposes of this preamble, the previous biogas 
provisions refer to those regulatory requirements that apply for the 
generation of RINs from qualifying biogas under 40 CFR part 80, 
subpart M, that are being modified by this final action. These 
regulatory provisions will sunset and be replaced by the biogas 
regulatory reform provisions discussed in this section, which 
include a modified definition of biogas. Additionally, under the RFS 
program, biogas used to produce renewable fuels must be produced 
from renewable biomass. See id. (definition of ``renewable fuel''), 
Table 1 to 40 CFR 80.1426.
---------------------------------------------------------------------------

3. The Biogas and Biogas RIN Disposition and Generation Chain
    In this subsection, we introduce and briefly discuss a number of 
key concepts and terms that are used throughout our discussion of 
biogas regulatory reform, including the relevant parties that 
participate in the biogas disposition/generation chain.\258\
---------------------------------------------------------------------------

    \258\ For purposes of this preamble, we refer to the chain of 
parties that produce biogas, RNG and biogas-derived renewable fuels, 
distribute such products, use such biogas-derived renewable fuels as 
a transportation fuel, and generate and transfer RINs for biogas-
derived renewable fuels collectively as the biogas disposition/
generation chain.
---------------------------------------------------------------------------

a. Biogas and RNG
    Under the previous biogas provisions, EPA broadly defined biogas as 
``the mixture of hydrocarbons that is a gas at 60 degrees Fahrenheit 
and 1 atmosphere of pressure that is produced through the anaerobic 
digestion of organic matter.'' Biogas typically contains significant 
amounts of impurities and inert gases (e.g., carbon dioxide) and must 
undergo pre-treatment before it can be used to produce transportation 
fuel (e.g., CNG/LNG in vehicles). In order for commercial natural gas 
pipelines to accept injections of biogas, the biogas must first be 
upgraded to meet pipeline specifications prior to injection. In this 
action, we call this pipeline quality biogas RNG, and we define biogas 
to be the precursor to RNG. The biogas producer is the party that 
produces biogas at a biogas production facility, and the RNG producer 
is the party that produces RNG at an RNG production facility.
b. Renewable CNG and LNG From RNG
    For biogas to be used as renewable CNG/LNG to fuel a vehicle, the 
treated biogas or RNG is compressed into compressed natural gas 
(renewable CNG) or liquified natural gas (renewable LNG) and then used 
in CNG/LNG engines as transportation fuel. Under our previous biogas 
regulations,\259\ we required that parties demonstrate through 
contracts and affidavits that a specific volume of RNG was used as 
transportation fuel within the U.S., and for no other purpose. For RNG 
to renewable CNG/LNG, the chain of parties that are involved in 
ensuring that biogas is produced from renewable biomass and used as 
transportation fuel includes:
---------------------------------------------------------------------------

    \259\ 40 CFR 80.1426(f)(10)(ii), (f)(11)(ii).
---------------------------------------------------------------------------

     The biogas producer (i.e., the landfill or digester that 
produces the biogas)
     The party that upgrades the biogas into RNG (the RNG 
producer)
     The parties that distribute and store the RNG (e.g., 
pipeline operators)
     The parties that compress the RNG into renewable CNG/LNG
     The dispensers of the renewable CNG/LNG (e.g., refueling 
stations)
     The consumers of the CNG/LNG (e.g., a municipal bus fleet)
     And any third parties that help manage the information and 
records needed to show that the biogas was produced from renewable 
biomass and used as renewable CNG/LNG.
    If biogas is directly supplied to an end user via a private 
pipeline, the biogas disposition/generation chain can be much smaller; 
sometimes even being a single party if the same party produces the 
biogas, treats and compresses/liquifies it, and supplies an onsite 
fleet of CNG/LNG vehicles.
4. Need for Regulatory Change
    The previous biogas provisions lack specificity and clarity in 
several key areas, which, as EPA has gained experience in implementing 
the program, we have determined undermines EPA's ability to implement, 
oversee, and enforce the program. Critically, we have concerns that the 
existing regulations allow for double counting of biogas volumes or 
generating invalid RINs from biogas or RNG. These perversities could be 
exacerbated as EPA allows for multiple uses of biogas (i.e., allows 
biogas to be used as a biointermediate). The lack of specificity and 
clarity has also led to a high degree of program complexity, 
unnecessarily burdening both EPA and industry and hindering effective 
oversight.
    The previous biogas provisions do not specify how or where the 
quantity of CNG/LNG was to be measured, which party was the RIN 
generator, how a RIN generator was to demonstrate that the CNG/LNG was 
actually used as transportation fuel, or how the RIN generator 
demonstrated that the CNG/LNG was not double counted. The previous 
biogas provisions were also silent on whether and how parties could 
store biogas prior to and after registration, how parties reconcile 
stored volumes over periods of time, and when if ever such volumes had 
to be used as transportation fuel for RIN generation.
    Due to the lack of specificity in those previous biogas provisions 
for how potential RIN generators would demonstrate that CNG/LNG was 
produced from renewable biomass and used as a transportation fuel, the 
registration requests that EPA received over the past several years 
varied considerably in their approaches. The main point of variation 
concerned the party that would generate the RINs. Approaches in 
registration requests have included:
     Parties that use renewable CNG/LNG in a specified fleet 
(e.g., fleet operators)
     Parties that dispense renewable CNG/LNG
     Parties that generate RNG from qualifying biogas
     Parties that produce the qualifying biogas for renewable 
CNG/LNG generation

[[Page 44525]]

     Marketers that organize contracts between RNG producers 
and CNG/LNG users.
    EPA did not envision this broad range of differing approaches to 
RIN generation for renewable CNG/LNG when we designed the previous 
biogas regulations. While these regulations required registrants to 
demonstrate in their requests that another party could not double count 
the quantity of RINs generated for a volume of biogas and renewable 
CNG/LNG,\260\ the regulations are so open-ended that multiple parties--
the renewable CNG/LNG producer, the party distributing the CNG/LNG, 
biogas producer, fleet owners, and/or dispensing stations--could be in 
a position to claim a single volume. That is, while the regulations 
prohibit the double counting of RIN generation for the same quantity of 
renewable CNG/LNG, they also inadvertently made it relatively easy for 
double counting to occur.
---------------------------------------------------------------------------

    \260\ See 40 CFR 80.1426(f)(11)(ii)(H), which states that ``[n]o 
other party relied upon the volume of biogas/CNG/LNG for the 
creation of RINs.''
---------------------------------------------------------------------------

    The previous biogas provisions also allowed for a single renewable 
CNG/LNG dispenser to contract with multiple RNG producers and allowed a 
single RNG producer to contract with multiple CNG/LNG dispensers. This 
flexibility allowed for the creation of network of contracts which 
encompass many RNG producers, many RNG distributers and marketers, and 
many CNG/LNG dispensers, creating a complex paperwork system for EPA to 
track and that increased the difficulty of effectively overseeing the 
program.
    The regulatory revisions outlined in this section are necessary to 
promote expansion of renewable fuel volumes, to prevent invalid RINs, 
and to allow EPA and industry to effectively ensure compliance, as 
discussed in more detail below.
a. Supporting the Broad Goals of the RFS Program
    The broad goals of the RFS program are to reduce GHG emissions and 
enhance energy security through increases in renewable fuel use over 
time. Inclusion of new types of renewable fuel or expansion of existing 
types of renewable fuel in the program can help to accomplish these 
goals. Any fuel that is produced from renewable biomass and is used as 
transportation fuel (as defined in the Clean Air Act) has the potential 
to participate in the RFS program, provided in satisfies the applicable 
statutory and regulatory requirements. Biogas is already a major source 
of renewable fuel, with RNG used as renewable CNG/LNG currently 
representing the vast majority of cellulosic biofuel. As discussed in 
Section III.B.1, use of RNG has been growing at a rapid rate since 2016 
through the incentives created by the cellulosic RIN under the RFS 
program, in addition to LCFS credits in California and other states. 
However, the opportunity for continued growth of RNG is expected to be 
constrained in the future by two factors. First, the economics of 
developing biogas facilities becomes increasingly challenging for 
smaller facilities, and particularly for facilities located more 
remotely from natural gas pipeline interconnects. The first facilities 
brought into the program tended to be the largest and most economical, 
with it becoming increasingly costly to bring on incremental volume 
over time. Second, as discussed in Section III.B.1., the rate of growth 
in the consumption capacity of the in-use fleet of CNG/LNG vehicles is 
expected to slow. When the program started in 2016, there was a 
sizeable existing fleet of CNG/LNG vehicles that were operating on 
fossil natural gas and that could quickly be used to generate RINs 
through establishing contracts for RNG. Since the use of RNG has been 
saturating the existing in-use CNG/LNG vehicle fleet, particularly the 
largest and most economical fleets, the use of biogas as a feedstock 
for renewable fuel production will be increasingly constrained by the 
much slower growth in CNG/LNG fleet sales. At the same time, based on 
the number of existing landfills \261\ and wastewater treatment 
facilities and the potential for significant expansion of anaerobic 
digesters,\262\ there exists significant potential to increase the 
productive use of biogas by using it as a biointermediate to produce 
renewable fuel under the RFS program. By tapping into the greater 
market for that biogas that can be economically converted to other 
renewable fuels, the impending constraints on the use of biogas as a 
feedstock for renewable fuel production can be mitigated.
---------------------------------------------------------------------------

    \261\ https://www.epa.gov/lmop/landfill-gas-energy-project-data.
    \262\ https://www.epa.gov/agstar/livestock-anaerobic-digester-database.
---------------------------------------------------------------------------

    The use of biogas to produce fuels other than renewable CNG/LNG is 
also consistent with the statute's focus on growth in cellulosic 
biofuel over other advanced biofuels and conventional renewable fuel 
after 2015.\263\ However, due to concerns with the potential double 
counting of biogas/RNG for RIN generation, EPA has not registered 
parties to generate RINs for biogas used for fuels other than renewable 
CNG/LNG under the existing regulations, so biogas use has instead been 
limited to the CNG/LNG vehicle market under the RFS program. Allowing 
the program to incorporate biogas-derived renewable fuels other than 
renewable CNG/LNG would support the increase in usage of renewable 
fuels which can reduce GHGs emissions and promote energy independence.
---------------------------------------------------------------------------

    \263\ For years after 2015, conventional renewable fuel remains 
constant at 15 billion gallons, and non-cellulosic advanced biofuel 
increases by no more than 0.5 billion gallons annually. Annual 
increases in cellulosic biofuel, in contrast, accelerate from 1.25 
billion gallons in 2016 to 2.5 billion gallons in 2022.
---------------------------------------------------------------------------

b. Preventing Double Counting and Fraud
    In order for the RFS program to function, the RIN market must 
maintain foundational integrity: namely, the parties that transact RINs 
and use RINs for compliance must have confidence that those RINs are 
valid. While the vast majority of RINs generated over the RFS program's 
history have not been found to be invalid, a non-trivial quantity of 
invalid RINs have also been generated.\264\ The significant value of 
the RINs, particularly cellulosic RINs, provides incentives for 
fraudulent generation, and complicated renewable fuel production and 
distribution systems, such as the contractual network for demonstrating 
that CNG/LNG qualifies as renewable fuel described in Section IX.A.2, 
provide opportunities for fraudulent behavior. Fraudulent RINs can be 
generated, for example, by parties fabricating reports or records to 
generate RINs for volumes of biogas that have been used for a 
different, non-transportation fuel purpose. Furthermore, the more 
complicated the regulatory requirements and data systems, the more 
likely it is that parties may inadvertently generate invalid RINs due 
to simple errors such as reliance on a faulty meter that measured 
volumes incorrectly or made a calculation error. That is, invalid RIN 
generation, including double counting of RINs (generating more than one 
RIN for the same ethanol-equivalent gallon of renewable fuel), can 
result from either intentional or unintentional actions.
---------------------------------------------------------------------------

    \264\ For more information, see EPA's Civil Enforcement of the 
Renewable Fuel Standard Program page available at: https://www.epa.gov/enforcement/civil-enforcement-renewable-fuel-standard-program.
---------------------------------------------------------------------------

    In all cases of double counting, some or all of the RINs generated 
would be invalid and may additionally be deemed fraudulent. The 
generation of invalid RINs can have a deleterious effect on

[[Page 44526]]

RIN markets and impose a significant burden on regulated parties and 
EPA to identify and replace those invalid RINs, take enforcement action 
against liable parties, and remedy the invalidity.
    The potential for double counting of biogas, RNG, and biogas-
derived renewable fuels is a significant concern since it can undermine 
the credit system that EPA uses to implement the statutory volume 
requirements under CAA section 211(o). Even though the existing 
regulations prohibit such double counting,\265\ we have concerns that 
those regulations and the complex system of contracts and documentation 
they entail do not enable EPA to detect or protect against the double 
counting of RINs from biogas feedstocks because of the challenge 
tracking biogas through commercial pipelines.
---------------------------------------------------------------------------

    \265\ See 40 CFR 80.1426(f)(11)(i)(F).
---------------------------------------------------------------------------

    Invalid RINs can also create adverse market effects. In the short 
term, invalid RIN generation could oversupply the credit market and 
adversely impact credit values. In the longer term, remediation of 
invalid RINs could invalidate the data upon which EPA bases its 
projections of future supply to set standards and undermine investment 
in the growth of valid renewable fuels.
    Having a robust means of avoiding double counting and fraud is 
particularly important because once EPA begins accepting registration 
requests for biogas to be used as a biointermediate and biogas-derived 
renewable fuels other than renewable CNG/LNG, the opportunities for the 
double counting of biogas could increase dramatically. For example, 
without a robust system in place a party could easily generate RINs for 
a quantity of biogas used to produce RNG for use in CNG/LNG vehicles 
and then, through a complex contractual network, attempt to allow a 
different party to generate a RIN for production of other renewable 
fuel generated from the same volume of RNG.
    We believe that the biogas regulatory reform provisions we are 
finalizing virtually eliminate the potential for double counting and 
minimize opportunities for fraud by specifying the party that generates 
RINs, by holding all directly regulated parties in the biogas 
disposition/generation chain liable for transmitting or using invalid 
RINs, by tracking RNG through reporting requirements, and by leveraging 
third-party oversight mechanisms (i.e., third-party engineering 
reviews, RFS QAP, and annual attest engagements).
c. Enhancing Program Simplicity and RIN Integrity
    While the previous biogas provisions provide flexibility, as 
described in Section IX.A.2, they have also resulted in a complex 
program that is overly burdensome for both EPA and industry. Under the 
previous biogas provisions, parties demonstrate that biogas is used as 
renewable CNG/LNG for RIN generation through an extensive network of 
contractual relationships and documentation that shows that a specific 
volume of qualifying biogas is used as transportation fuel in the form 
of renewable CNG/LNG. These demonstrations occur during registration in 
the form of extensive paperwork, including contracts and associated 
documentation; registration packages can sometimes number over a 
thousand pages of contracts for a single RNG production facility. These 
contracts can also cover multiple facilities, creating an ever more 
complex network of contracts.
    The potential expanded use of biogas as a biointermediate and RNG 
as a feedstock to produce renewable fuels would make the program under 
the previous biogas provisions impracticable to oversee and, as 
discussed above, more susceptible to double counting and fraud. Since 
biogas may have multiple uses, it is crucial to minimize the potential 
for generating invalid or fraudulent RINs, including the double 
counting of RINs. As more uses of biogas are allowed under the program, 
additional regulatory measures are necessary because EPA will be 
tracking and overseeing increased volumes of biogas, and we want to 
ensure a program design that enables EPA to effectively track and 
oversee larger volumes of biogas (particularly in instances where 
biogas is converted into RNG and placed into a natural gas commercial 
pipeline system) going to multiple end uses. We also want to avoid 
situations in which opaque contractual mechanisms could potentially 
allow multiple parties to claim that the same volume of biogas is used 
as two or more biogas-derived renewable fuels.
    One of the revisions EPA is finalizing in this rulemaking is to 
track the flow of RNG in EMTS. Doing so will simplify oversight, ensure 
that quantities of biogas-derived renewable fuels used as 
transportation fuel are real, and provide confidence to encourage 
investment in these fuels. The biogas regulatory reform program 
includes those parties, and only those parties, that are necessary and 
best able to demonstrate the valid use of renewable fuel use for 
transportation: the biogas producer, the RNG producer, and the party 
that can demonstrate its use for transportation (e.g., the renewable 
CNG dispenser). Each party has a set of clearly defined roles and 
responsibilities under the program.
5. Summary of Changes
    In this rulemaking, EPA proposed to specify requirements for 
different parties within the biogas disposition/generation chain. We 
also proposed to expand how biogas can be used through provisions 
allowing biogas to be used as a biointermediate such that renewable 
fuel produced from biogas could be produced through sequential 
operations at more than one facility and allowing RNG to be used as a 
feedstock to produce a different renewable fuel. We are finalizing many 
elements of biogas regulatory reform largely as proposed. The key 
elements of the biogas regulatory reforms that we are now finalizing 
include the following:
     Specification of the party that upgrades the biogas to RNG 
(the RNG producer) as the RIN generator.
     A requirement that the RNG producer assign RINs generated 
for the RNG to the specific volume of RNG when the volume is injected 
into a natural gas commercial pipeline system.
     A requirement that the party that can demonstrate that the 
RNG was used as transportation fuel may separate the RIN.
     Specific regulatory requirements for key parties (i.e., 
biogas producer, RNG producer, RNG RIN owners, and RNG RIN separators) 
in the RNG production, distribution, and use.
     Conditions on the use of biogas and storage of RNG prior 
to registration.
     Specific provisions to address when biogas is used as a 
biointermediate and when RNG is used as a feedstock.
    These elements are applied to the following parties:
     The party that produces the biogas (the biogas producer).
     The party that upgrades the biogas to RNG, injects the RNG 
into the natural gas commercial pipeline system, and generates/assigns 
the RIN to the RNG (the RNG producer).
     Any party that transfers title of the assigned RIN (RNG 
RIN owner).
     The party that demonstrates that the RNG was used as 
transportation fuel in the form of renewable CNG/LNG (the RNG RIN 
separator) or used as a feedstock to produce a renewable fuel other 
than renewable CNG/LNG.
    We discuss each of these key elements and parties in more detail in 
the following sections.

[[Page 44527]]

    Regulatory requirements for each of these key activities and 
parties are necessary to ensure that the biogas is produced, converted 
to RNG, and eventually used as transportation fuel consistent with CAA 
and regulatory requirements. Specifying the requirements applicable to 
each party enables EPA to take a streamlined regulatory approach to the 
production, distribution, and use of RNG that allows for the flexible 
use of RNG without imposing strict limitations on which parties can 
take title to and use the RNG.
    Furthermore, we are also sunsetting regulatory provisions that will 
no longer be necessary. For example, much of the documentation of 
contracts between each party in the biogas distribution/generation 
chain previously required to be submitted to EPA at registration will 
no longer be necessary to submit.
    Finally, based on comments requesting more time for parties to 
comport with the biogas regulatory reform provisions, we are providing 
more time for both new and existing registrants to come into 
compliance, as discussed in Section IX.F.
    We did not propose to revisit or reopen the pathways for biogas 
established in the 2014 RFS Pathways II rule and are therefore not 
addressing any issues or comments received on the pathways themselves. 
We will continue to review pathway petitions under 40 CFR 80.1416 and 
may take separate regulatory action on additional pathways for biogas 
as appropriate in the future.

B. Biogas Under a Closed Distribution System

    Under the previous biogas provisions, there were two approaches for 
generating RINs from biogas to renewable CNG/LNG: (1) biogas in a 
closed, private, non-commercial distribution system that is compressed 
to renewable CNG/LNG, and (2) biogas upgraded to RNG, injected into a 
commercial pipeline system, and then compressed to renewable CNG/
LNG.\266\ The focus of this regulatory reform deals with RNG injected 
onto the natural gas commercial pipeline system. We are therefore 
finalizing as proposed only minor modifications to the existing 
regulatory provisions for biogas used to produce a renewable fuel when 
the biogas is produced and made into a biogas-derived renewable fuel in 
a closed distribution system. Because it is typically only a single 
party participating in a closed distribution system (i.e., the same 
party that produces the biogas is the same party that converts the 
biogas to renewable CNG/LNG and then uses that biogas in their own CNG/
LNG fleets), there is little opportunity for the double counting of 
biogas through multiple parties claiming the same volume across the 
biogas distribution/generation chain.
---------------------------------------------------------------------------

    \266\ See 40 CFR 80.1426(f)(10) and (11).
---------------------------------------------------------------------------

    We are finalizing as proposed that parties that generate RINs for 
biogas to renewable CNG/LNG via a closed distribution system will 
continue to operate under similar provisions to the previous biogas 
provisions. We are also finalizing as proposed a requirement that when 
the biogas producer is a separate party from the party that generates 
RINs for biogas to renewable CNG/LNG in a closed distribution system, 
the biogas producer will have to separately register with EPA. This 
provision ensures that biogas producers are treated consistently 
throughout the program and helps EPA identify how parties are related 
in the biogas distribution/generation chain. We recognize that this may 
require some parties to update their registration information with EPA, 
but we do not expect this to require new third-party engineering 
reviews or the resubmission of registration materials.
    To help ensure consistency in the regulatory requirements for all 
biogas-derived renewable fuels, we are moving the provisions for biogas 
to renewable CNG/LNG via a closed distribution system into the new 40 
CFR part 80, subpart E. We sought comment on whether and how to 
streamline the regulatory requirements for biogas to renewable CNG/LNG 
via a closed distribution system. We did not receive significant 
comments regarding parties producing renewable CNG/LNG from biogas via 
a closed distribution system, and we are finalizing that we are moving 
these provisions to subpart E as proposed.

C. RNG Producer as the RIN Generator

    For biogas upgraded to RNG and placed on a natural gas commercial 
pipeline system, we are finalizing as proposed that RNG producers will 
be the sole RIN generators, and that they will generate RINs for RNG 
they produce and inject into a commercial pipeline. The previous 
regulations allowed any party to generate RINs from biogas-derived 
renewable fuels, even parties that were not part of the biogas 
distribution/generation chain. In the RFS Pathways II rule, we did not 
specify a RIN generator because we believed that the complexities of 
the production and distribution of biogas-derived renewable fuels 
warranted a case-by-case approach to RIN generation.\267\ We noted that 
we would continue to monitor RIN generation practices and that we might 
reconsider specifying the RIN generator for biogas-derived renewable 
fuels at a later date. Based on our experience implementing the program 
since then, and in light of the expansion in the use of biogas as a 
biointermediate and RNG as a feedstock, we now believe that it is 
important to designate a RIN generator.
---------------------------------------------------------------------------

    \267\ 79 FR 42128, 42144 (July 18, 2014).
---------------------------------------------------------------------------

    We believe that RNG producers are best positioned to generate the 
RINs for two reasons. First, one of the goals of biogas regulatory 
reforms is to minimize the potential for double counting of biogas or 
RNG since such biogas or RNG could potentially be used to produce 
multiple types of fuels. By designating RNG producers as the RIN 
generators, the RINs will effectively be tracked in EMTS from RNG 
injection through withdrawal via the assignment, separation and/or 
retiring of RINs, as discussed in more detail in Section IX.D. This 
approach significantly reduces double counting concerns since a 
specific volume of RNG will have corresponding RINs assigned to it, and 
by specifying that the RINs can only be separated under specific 
circumstances.
    Second, we believe RNG producers are also well positioned to 
determine whether the RNG was produced from qualifying biogas and to 
determine the correct amount of biomethane that will qualify for RIN 
generation. RNG producers typically add non-renewable components to 
biogas to make pipeline quality RNG. They are often the only party 
aware of the non-renewable components, and the only party in a position 
to measure the biomethane content of the RNG prior to introducing non-
renewable components.
    We also considered designating other parties as the RIN generator. 
For example, we considered designating the party that produces or uses 
the renewable CNG/LNG as the RIN generator. However, if we finalized 
such an approach, then we will largely forgo any ability to track 
assigned RINs to volumes of RNG in EMTS because the RNG will have 
already traversed the entirety of the natural gas commercial pipeline 
system before the RIN was generated and assigned. This approach will 
not remedy the double counting and tracking concerns under the existing 
program. The RNG would still have to be tracked via a complicated 
series of contractual relationships instead of electronically in EMTS. 
The downstream party and EPA acting in its oversight capacity would 
still have to go

[[Page 44528]]

to great lengths to ensure that the RNG was not double counted before 
the RIN was generated.
    We recognize that the approach we are finalizing will affect a 
number of parties that are currently registered to generate RINs for 
biogas to renewable CNG/LNG, and we specifically sought comment on our 
proposal to designate the RNG producer as the RIN generator for RNG 
injected into a natural gas commercial pipeline system. We received a 
number of comments relating to who should be the RIN generator for RNG 
RINs. Multiple commenters suggested that our approach should be broader 
and that we should allow third parties, such as marketers, to be the 
RIN generator. These commenters stated that smaller entities might not 
have the expertise necessary and would not want to take on the 
liability associated with RIN generation. Commenters also expressed 
concern regarding the need to re-negotiate contracts that had 
previously let a party other than the RNG producer generate RINs.
    Given that in this action we are expanding the use of biogas as a 
biointermediate and RNG as a feedstock, we believe it is important for 
parties that generate RINs in the RFS program to be held responsible 
for complying with the regulations, and in general we believe that 
parties that have a direct role in the production or use of a fuel are 
the more appropriate parties to generate RINs. Parties involved in the 
production of feedstocks or renewable fuel should not be allowed to 
shift liability to third parties. While stakeholder comments provided 
perspectives on market dynamics, these commenters did not explain how 
allowing third parties to generate RINs would directly improve 
compliance and enforcement of this expanded program.
    Additionally after reviewing stakeholder comments and engaging 
directly with companies,\268\ we remain convinced that this step is 
necessary to implement the other proposed changes discussed below. By 
making the RNG producer the RIN generator, we will greatly improve our 
ability to track the movement of the RNG via RINs assigned at the point 
of injection as discussed in Section IX.D. This change will also 
simplify the program while improving our ability to effectively oversee 
it. In response to concerns on contract negotiation timing, we are 
finalizing modifications to our proposed implementation date, as 
discussed in Section IX.F.
---------------------------------------------------------------------------

    \268\ See ``Set Rule Log of Meetings,'' available in the docket 
for this action.
---------------------------------------------------------------------------

    Based on our experience with CNG/LNG, and from stakeholders' 
experience in California's LCFS program, we recognize that third 
parties will likely serve a useful role in supporting regulated parties 
in brokering and trading biogas, RNG, and biogas-derived renewable 
fuel. We also believe that biogas producers, RNG producers, and RNG RIN 
separators would likely contract with third parties to help them comply 
with the proposed regulatory requirements by preparing and submitting 
registration requests and periodic reports. Since our system for 
registration and RIN generation allows third parties to assist the 
regulated party in preparing to comply with the applicable regulatory 
requirements (e.g., by helping to prepare reports, broker RIN 
transactions, etc.), and we are not planning on changing this allowance 
under this rule, we believe this should provide most of the 
functionality the commenters requested.

D. Assignment, Separation, Retirement, and Expiration of RNG RINs

    EPA is finalizing revisions to the regulations to specify how 
parties will assign, separate, and retire RINs generated for RNG. Under 
the previous regulations, RINs were generated and immediately separated 
after any party in the biogas disposition/generation chain demonstrated 
that a specific amount of RNG was used as transportation fuel. Because 
RINs were generated and simultaneously separated based on the same 
event, the previous biogas provisions did not provide tracking of RNG 
or renewable CNG/LNG in EMTS through RIN assignment and separation.
    We are finalizing as proposed that the RNG producer must assign any 
and all RINs generated for a given volume of RNG to the same volume of 
RNG at the point of injection, and the RINs must follow transfer of 
title of that RNG until it is withdrawn from the same natural gas 
commercial pipeline system.\269\ The purpose of this requirement is to 
ensure that the RIN, as tracked through EMTS, follows the transfer of 
title of the RNG as the RNG moves through the natural gas commercial 
pipeline system.
---------------------------------------------------------------------------

    \269\ For purposes of this preamble, when we refer to the RNG 
producer we are collectively referring to the party that produces 
and injects the RNG into the natural gas commercial pipeline system 
or imports the RNG into the covered location. Unless otherwise 
specified, all proposed requirements as part of this proposal apply 
to both RNG producers and RNG importers.
---------------------------------------------------------------------------

    Regarding RIN separation, we are finalizing with technical 
modifications the proposal that only the party that demonstrates that 
the RNG was used as transportation fuel will be eligible to separate 
the RINs generated for the RNG from the RNG itself., This party is 
defined as the RNG RIN separator. This party may either be the party 
that withdrew the RNG from the natural gas commercial pipeline system 
or the party that produced or oversaw the production of the renewable 
CNG/LNG from the RNG. This is a different approach than the prior 
regulations. Previously, the party that generates the RINs from a 
volume of biogas separates any RINs generated for that biogas 
immediately after the party has demonstrated that the biogas was 
produced from renewable biomass under an EPA-approved pathway and used 
as transportation fuel. Separation does not necessarily occur at the 
end of the biogas distribution/generation chain, which necessitates 
tracking via contractual relationships, as discussed above, and forgoes 
any ability for EMTS to track the assigned RINs as the volumes of RNG 
move through the natural gas commercial pipeline system. Our changes 
will allow for RINs assigned to a given volume of RNG to be tracked via 
EMTS as the RNG moves through the natural gas commercial pipeline 
system from injection to withdrawal. Similarly, we are finalizing as 
proposed the clarification that the provisions that require obligated 
parties to separate assigned RINs when they take title to any assigned 
RINs do not apply to RINs assigned to RNG. Allowing obligated parties 
to separate assigned RINs for RNG would undermine the purpose of our 
proposal to use RINs assigned to RNG in EMTS to track transfers of RNG.
    In the case of RNG used to produce renewable CNG/LNG, the party 
that obtains the documentation needed to demonstrate that the RNG was 
used to produce transportation fuel in the form of renewable CNG/LNG is 
best positioned to separate the RIN. This is analogous to the 
provisions that require parties blending denatured fuel ethanol into 
gasoline to separate any assigned RINs for the denatured fuel ethanol 
at fuel terminals (i.e., the point at which it is reasonable to assume 
that the denatured fuel ethanol will be used as transportation 
fuel).\270\ Similarly, once a party has turned RNG into renewable CNG 
or renewable LNG, we can reasonably assume that the renewable CNG or 
renewable LNG will be used as transportation fuel. We proposed that the 
party that separates RNG RINs must have withdrawn the RNG from the 
natural gas commercial pipeline system and produced renewable CNG/LNG 
from that RNG, among other

[[Page 44529]]

requirements. We received comments that the party that withdraws the 
RNG from the natural gas commercial pipeline system is not always the 
same party that converts RNG into renewable CNG/LNG. We believe either 
the party that withdraws the RNG from the natural gas commercial 
pipeline system and produces renewable CNG/LNG from that RNG or the 
party that converts RNG into renewable CNG/LNG could have sufficient 
information to be positioned to demonstrate that the RNG is used as 
transportation fuel, so we have finalized the regulations to allow 
either party to separate RNG RINs.
---------------------------------------------------------------------------

    \270\ 40 CFR 80.1429.
---------------------------------------------------------------------------

    To address the potential issue of double counting an RNG RIN where 
a party claims that the RNG is used both as renewable CNG/LNG and as a 
different biogas-derived renewable fuel, we are finalizing as proposed 
the requirement that parties that use RNG to produce a biogas-derived 
renewable fuel other than renewable CNG/LNG will have to retire the 
assigned RINs for the RNG used as a feedstock and then generate a 
separate RIN using the procedures for RIN generation for the new 
renewable fuel.
    RNG RINs will expire consistent with the current regulatory 
requirements at 40 CFR 80.1428(c). Under 40 CFR 80.1428(c), any RIN 
that is not used for compliance purposes for the year in which it was 
generated, or for the following year, is considered an expired RIN, and 
expired RINs are considered invalid RINs under 40 CFR 80.1431. What 
this means for RNG RINs is that if no party separates an RNG RIN or 
retires the RNG RIN to produce renewable fuel by the annual compliance 
deadline for the compliance year following the year in which that RNG 
RIN was generated, the RNG RIN will expire. For example, if a RIN is 
generated for RNG injected into the natural gas commercial pipeline 
system in 2024, then that RNG RIN will expire after the 2025 annual 
compliance deadline. If no party separated the assigned RIN for the RNG 
because no party was able to demonstrate that the RNG was used as 
transportation fuel or as a feedstock, then the RNG RIN will expire and 
no longer be usable for compliance purposes. We note that this approach 
is consistent with existing regulations for how RIN expiration works 
under the RFS program generally. We also note that that this provision 
will allow for at least 15 months for any assigned RNG RIN to be 
separated (i.e., a RIN generated and assigned in December of a 
compliance year will have at least 15 months before it expires after 
the subsequent compliance year's annual compliance deadline), and in 
many cases much longer. We believe this to be sufficient time for 
parties to demonstrate that the RNG with the assigned RINs was used as 
transportation fuel and will help encourage parties to use RNG as 
transportation fuel under the RFS before the RIN expires.
    Separating the RIN assignment and RIN separation roles provides 
multiple benefits to both EPA and the regulated community. First, this 
approach will significantly increase the ability for the title to RNG 
to be tracked and overseen, because the transfer of title to RNG will 
follow the assigned RIN and will be reported in EMTS. EPA and third 
parties will be able to track the parties that transferred title to the 
RNG and follow the movement of the RNG via the assigned RIN in EMTS, as 
opposed to having to track a complex series of contractual 
relationships between each and every party in the RNG distribution 
system. This approach will also greatly simplify the auditing process 
for both EPA and for third parties, allowing for increased program 
oversight.
    Second, this approach allows us to streamline the registration, 
reporting, and recordkeeping requirements for RNG and RNG RINs by 
utilizing EMTS for tracking. This creates a number of efficiencies. 
With regard to registration, it eliminates the need for parties to 
submit contracts at registration, as discussed in Section IX.A. For 
reporting, since the RNG and RNG RINs will be tracked in EMTS, we will 
no longer require the reporting of affidavits and other documentation 
concerning the transfer of RNG that we currently require to ensure that 
the RIN generator has the information needed to demonstrate that a 
specific volume of RNG was used as transportation fuel. For 
recordkeeping, EMTS will electronically provide real-time data 
concerning how a given volume of RNG is transferred and ultimately 
used. This eliminates the need for the existing provisions that require 
RIN generators to obtain documents from every party in the biogas 
distribution/generation chain in the form of additional contracts, 
affidavits, or real-time electronic data. These registration, 
reporting, and recordkeeping requirements significantly streamline 
program implementation for EPA and reduce the compliance burden on 
regulated parties.
    Third, this mitigates the risk of counting a given volume of RNG 
more than once because we are clearly specifying the point in the 
process when RNG RINs must be generated (i.e., at the point where RNG 
is injected into the natural gas commercial pipeline system) and the 
point in the process when RNG RINs must be separated (i.e., when the 
RNG is demonstrated to be used as a transportation fuel). Because the 
RNG can only be injected into the natural gas commercial pipeline 
system once and because an assigned RNG RIN can only be separated once, 
this specificity virtually eliminates a party's ability to double count 
the RNG at the point of injection or claim that a given quantity of RNG 
was used for more than one purposes.

E. Structure of the Regulations

    Due to the comprehensive nature of the biogas regulatory reform 
provisions, we are creating a stand-alone subpart rather than embed 
them in the rest of the RFS regulatory requirements in 40 CFR part 80, 
subpart M. Thus, we are finalizing as proposed the creation of a new 
subpart for biogas-derived renewable fuels--subpart E in 40 CFR part 
80. This new subpart includes provisions not only for biogas and RNG 
used to produce renewable CNG/LNG, but also for other biogas-derived 
renewable fuels including biogas cases where biogas is used as a 
biointermediate and RNG is used as a feedstock. The provisions for 
these fuels under subpart M are being copied into the new subpart E, 
and the provisions within subpart M are being phased out as described 
in Section IX.F.
    Based on our general approach adopted in the Fuels Regulatory 
Streamlining Rule,\271\ we are structuring the new subpart for biogas-
derived renewable fuels as follows:
---------------------------------------------------------------------------

    \271\ See 85 FR 78415-78416 (December 4, 2020).
---------------------------------------------------------------------------

     Identify general provisions (e.g., implementation dates, 
scope, applicability etc.).
     Articulate the general requirements that apply to parties 
regulated under the subpart (e.g., biogas producers, RNG producers, and 
RNG RIN separators).
     Articulate the specific compliance and enforcement 
provisions for biogas-derived renewable fuels (e.g., registration, 
reporting, and recordkeeping requirements).
    We believe that this subpart and structure will make the biogas-
derived renewable fuel provisions more accessible to all stakeholders, 
help ensure compliance by making requirements more easily identifiable, 
and help future participants in biogas-derived biofuels better 
understand regulatory requirements in the future.

F. Implementation Date

    In response to extensive request from public comment to provide 
more lead time for the implementation of the biogas regulatory reform 
provisions, we

[[Page 44530]]

are finalizing more time than proposed for both new parties and 
existing registrants to come into compliance with the biogas regulatory 
reform provisions. Parties that are registered to generate RINs for 
renewable CNG/LNG prior to July 1, 2024 will have until January 1, 2025 
to come into compliance with the biogas regulatory reform provisions. 
Parties registered July 1, 2024 or after will have to meet the biogas 
regulatory reform provisions beginning July 1, 2024. On January 1, 
2025, all parties must comply with the biogas regulatory reform 
provisions and only biogas and RNG produced under the biogas regulatory 
reform provisions are eligible for RIN generation. Below we discuss our 
proposed timeline, the comments we received, and how we adjusted the 
timeline based on the comments.
    Recognizing the need to provide a transition period for parties 
that are already generating RINs for biogas under the prior provisions 
to the biogas regulatory reforms, we proposed that all parties 
operating under the previous biogas provisions would have to come into 
compliance with the proposed biogas regulatory reform provisions by 
January 1, 2024. We also proposed that parties that injected RNG into 
the natural gas commercial pipeline system under the previous biogas 
provisions prior to January 1, 2024 could use the RNG for the 
generation of RINs under the previous biogas regulatory provisions 
until January 1, 2025. We believed at the time that this was enough 
time for parties to come into compliance with the proposed biogas 
regulatory reform provisions and utilize for RIN generation the RNG 
stored on the natural gas commercial pipeline system. We sought comment 
on whether more time was needed for parties to transition to the 
proposed biogas regulatory reform provisions.
    In response, we received significant public comment suggesting that 
more time was needed by both parties already registered under the 
previous biogas provisions and parties looking to register new 
facilities under the biogas regulatory reform provisions. Commenters 
suggested that the new testing and measurement requirements for biogas 
and RNG could take considerable time for parties to install compliant 
meters and arrange for independent third-party engineers to ensure that 
such meters were installed consistent with the new regulatory 
requirements. Commenters suggested that the implementation timeline 
should also consider facilities that are not currently registered 
because it can take years for an RNG project to be developed and many 
new projects may need modification to comport with the new 
requirements. Additionally, several commenters suggested that it would 
take more than the approximately six months allotted for the 
renegotiation of contracts with parties that produce, distribute, and 
use RNG to align with the new requirements. Parties suggested that by 
not providing enough lead time to comport with the measurement 
requirements and to allow parties to renegotiate contracts, EPA would 
strand a significant volume of RNG that would otherwise be eligible for 
use as renewable CNG/LNG under the RFS program. Some commenters 
suggested that EPA should provide an additional year over what was 
proposed (i.e., a January 1, 2025 start date instead of the proposed 
January 1, 2024 date), while others suggested EPA push the deadline to 
January 1, 2026.
    In response to the requests for more time for existing registrants, 
we are finalizing a start date of January 1, 2025, for facilities 
registered under the previous biogas provisions by July 1, 2024. We 
believe this extension should afford enough time for those facilities 
to come into compliance with the new regulatory requirements. It would 
in practice allow for almost a year and a half for parties to update 
their facilities to comport with the new regulatory requirements, 
update their registration information with EPA, and renegotiate their 
contracts. This would also provide existing registrants enough time to 
use any RNG stored on the natural gas commercial pipeline system before 
the new RIN generation requirements for RNG begin on January 1, 2025.
    In response to the requests for more time for new registrations, we 
are finalizing a start date of July 1, 2024, which affords new parties 
enough time prepare to meet the new regulatory requirements for biogas 
regulatory reform. Because these facilities are still preparing to come 
into the RFS program, we believe that a full year is sufficient for 
them to make adjustments to their facilities and contractual 
relationships prior to registration. Furthermore, we must balance the 
need to provide facilities that have planned to participate in the RFS 
under the previous biogas provisions with our ability to implement and 
oversee the program.
    We are finalizing as proposed that any RIN generators under the 
previous biogas provisions must generate RINs for RNG stored in the 
natural gas commercial pipeline system by January 1, 2025. As stated in 
the proposal, we believe this is a sufficient amount of time to utilize 
the amount of stored RNG as transportation fuel, and it is important to 
begin the tracking in EMTS via the RIN of all RNG under the RFS program 
as soon as practicable. A January 1, 2025 deadline may encourage 
existing registrants to comply with the biogas regulatory reform 
provisions prior to the deadline because the RNG produced under those 
existing registrations may have difficulty using the RNG as 
transportation fuel for RIN separation by the January 1, 2025 deadline.
    To ensure a smooth transition, we are requiring that existing 
registrants submit registration updates comporting with the biogas 
regulatory reform provisions no later than October 1, 2024. We 
anticipate that 3 months is enough time for EPA to process the 
registration requests of the existing registrants; however, we 
encourage existing registrants to submit updates prior to the deadline 
if able to ensure a smooth transition to the biogas regulatory reform 
provisions. Existing RIN generators will be allowed to generate RINs 
under the previous biogas regulatory reform provisions for biogas and 
RNG used as transportation fuel prior to January 1, 2025.\272\ Any RINs 
generated for biogas used as transportation fuel or RNG on or after 
January 1, 2025 must adhere to the biogas regulatory reform provisions.
---------------------------------------------------------------------------

    \272\ We expect that RINs generated for biogas demonstrated to 
be used in as transportation fuel by December 31, 2024, under the 
previous biogas provisions will be generated by February 2025. 
Typically, because the RIN generator must collect documentation from 
various parties in the contractual chain to ensure that the biogas 
or RNG was used as transportation fuel prior to RIN generation, RIN 
generation can take around a month after the biogas or RNG was used 
as transportation fuel.
---------------------------------------------------------------------------

    In addition to extending some of the deadlines, to further address 
timing concerns raised by commenters related to the implementation of 
this biogas regulatory reform, we are finalizing several changes based 
on comments to the proposed provisions themselves which are designed to 
allow for a smoother transition to the reformed biogas regulatory 
provisions. These changes to what we proposed include, but are not 
limited to, streamlining the registration process for existing 
registered biogas and RNG production facilities by no longer requiring 
certificates of analysis for biogas and RNG at initial registration, no 
longer requiring at registration waivers from pipelines for RNG that 
did not meet applicable pipeline specifications, and removing the 
proposed emissions-related registration requirements. Also, as 
discussed in Section IX.H.2, we are intending to update our reporting

[[Page 44531]]

systems to more readily accommodate the submission of reports to 
streamline and modernize the submission of biogas and RNG-related 
information under biogas regulatory reform.

G. Definitions

    We are finalizing with modifications the proposed definitions of 
various regulated parties, their facilities, and the products related 
to the production of biogas-derived renewable fuels. We are also 
finalizing with modifications the proposed definitions of other terms 
as necessary for clarity and consistency. We have modified the proposed 
definitions related to biogas regulatory reform based on public 
comments and describe those changes in more detail either below or in 
the RTC document.
    We are also finalizing the proposal to move and consolidate all 
defined terms for the RFS program from 40 CFR 80.1401 to 80.2. We are 
doing this because we moved all of the non-RFS fuel quality 
regulations, including the relevant definitions, from 40 CFR part 80 to 
part 1090 as part of our Fuels Regulatory Streamlining Rule.\273\ As 
such, it is no longer necessary to have separate definitions sections 
for 40 CFR part 80, subpart M, as only requirements related to the RFS 
program are housed in 40 CFR part 80. We are not changing the meaning 
of the terms moved from 40 CFR 80.1401 to 80.2, but are simply 
relocating them to consolidate the definitions that apply to RFS in a 
single location. Because we have consolidated all definitions for the 
RFS program into 40 CFR 80.2, any newly defined terms under this action 
appear in 80.2.
---------------------------------------------------------------------------

    \273\ 85 FR 78417-78420 (December 4, 2020).
---------------------------------------------------------------------------

    For parties regulated under the biogas regulatory reform 
provisions, we are finalizing several new terms to specify which 
persons and parties are subject to the revised regulatory requirements 
in a manner that is consistent with our approach under our other fuel 
quality and RFS regulations. For example, a biogas producer is defined 
as any person who owns, leases, operates, controls, or supervises a 
biogas production facility, and a biogas production facility is any 
facility where biogas is produced from renewable biomass that qualifies 
under the RFS program. The same framework for applies to RNG producers.
    Under the previous RFS regulations, the term ``biogas'' is used to 
refer to many things and its use may differ depending on context. In 
some cases, we distinguish between raw biogas, i.e., biogas collected 
at a landfill or through a digester that contains impurities and large 
portions of inert gases, and pipeline-quality biogas which has many of 
the impurities removed for distribution through a commercial pipeline. 
Some stakeholders also use the pipeline-quality biogas term 
interchangeably with renewable CNG or renewable LNG, which are 
renewable fuels produced from biogas. To clarify our intent, we are 
finalizing specific definitions for biogas-derived renewable fuel, 
biogas, treated biogas, biomethane, and renewable natural gas (RNG).
    ``Biogas'' is often used to broadly mean any renewable fuel used in 
the transportation sector that has its origins in biogas. However, in 
the context of the RFS program, we have learned that it is necessary to 
distinguish between these products. We are therefore finalizing a 
definition of ``biogas-derived renewable fuel'' that includes renewable 
CNG, renewable LNG, or any other renewable fuel that is produced from 
biogas or its pipeline-quality derivative RNG now or in the future.
    We are defining biomethane as exclusively methane that is produced 
from renewable biomass. We believe a separate definition for biomethane 
is important because biomethane (exclusive of impurities and inert 
gases often found with biomethane in biogas) is what RIN generation is 
based on. In order to ensure the appropriate measurement of biomethane 
for RIN generation for RNG, we issued guidance under the existing 
regulations that cover cases where non-renewable components are added 
to biogas, and we are codifying provisions based on that previously 
issued guidance in this action.\274\ Biomethane is a component of 
biogas, RNG, treated biogas, renewable CNG, and renewable LNG, all of 
which, under the definitions being finalized in this action, must be 
produced through anaerobic digestion of renewable biomass.
---------------------------------------------------------------------------

    \274\ See ``Guidance on Biogas Quality and RIN Generation when 
Biogas is Injected into a Commercial Pipeline for use in Producing 
Renewable CNG or LNG under the Renewable Fuel Standard Program.'' 
September 2016. EPA-420-B-16-075.
---------------------------------------------------------------------------

    We are defining biogas as a mixture including biomethane that is 
produced from anaerobic digestion and may have undergone some 
processing to remove water vapor, particles, and some trace gases, but 
requires additional processing (such as removal of carbon dioxide, 
oxygen, or nitrogen) to be suitable for use to produce a biogas-derived 
renewable fuel. This new definition of biogas is intended to make it 
explicit that biogas includes gas collected at landfills or through a 
digester before that biogas is either upgraded to produce RNG or is 
used to make a biogas-derived renewable fuel, which was intended but 
not stated in the previous definition. Gas containing biomethane that 
has undergone treatment to remove components such that it is suitable 
for use to produce a biointermediate or biogas-derived renewable fuels 
is no longer biogas and is either RNG or treated biogas, depending on 
whether it meets pipeline specifications and is placed on a commercial 
pipeline.
    To describe biogas-derived pipeline-quality gas, we proposed to 
adopt a term now in common use--renewable natural gas, or RNG. Under 
the proposed definition, in order to meet the definition of RNG, the 
product would have to have met all of the following:
     The gas must be produced from biogas,
     The gas must contain at least 90 percent biomethane 
content,
     The gas must meet the commercial distribution pipeline 
specification submitted and accepted by EPA as part of registration, 
and
     The gas must be designated for use to produce a biogas-
derived renewable fuel.
    We proposed that RNG must contain at least 90 percent biomethane 
content because we believed this to be consistent with many commercial 
pipeline specifications that we have seen submitted as part of existing 
registration submissions for the biogas to renewable CNG/LNG pathways. 
We received public comments stating that the proposed 90 percent 
biomethane content limit was too stringent or unnecessary because of 
how EPA proposed to define a batch of RNG. Some public commenters noted 
that commercial pipeline specifications are typically specified in 
methane (i.e., not specific to biomethane) and that often non-renewable 
components are blended into RNG to meet pipeline specifications. The 
public commenters highlighted that it would be energy intensive to 
clean up biogas to meet a 90 percent biomethane threshold and that many 
pipeline's methane content specifications are well below the proposed 
level. Other public commenters noted that because of how EPA proposed 
to measure RNG (i.e., direct measurement of biomethane using specified 
meters) and to define a batch of RNG (i.e., by being the volume of 
directly measured biomethane), such a limit was unnecessary and 
confusing. Based on these comments, we are not finalizing the proposed 
90 percent biomethane threshold in the definition of RNG.
    We are finalizing as proposed to define RNG such that it only meets 
the

[[Page 44532]]

definition if the gas is designated for use to produce a biogas-derived 
renewable fuel under the RFS program. We are finalizing this element of 
the definition for consistency with the regulatory requirement that 
such fuels be used only for transportation under the RFS consistent 
with the Clean Air Act. This element is important to avoid the double-
counting of volumes of RNG that could be claimed as both a renewable 
fuel under the RFS program and as a product for a non-transportation 
use under a different federal or state program.
    EPA's previous biogas guidance explains that biogas injected onto 
the commercial pipeline should meet the specific pipeline 
specifications required by the commercial pipeline in order to qualify 
as transportation fuel for RIN generation.\275\ Commenters noted that 
our proposed definition excluded RNG that required addition of non-
renewable components. Based on these comments, we are modifying our 
proposed definition of RNG to specify that RNG must not require removal 
of components to be placed into a commercial pipeline. This definition 
would not disqualify gas that requires addition of non-renewable 
components in order to meet pipeline specifications. Since the 
definition of RNG is based on pipeline specifications, registration 
submissions for RNG must include these pipeline specifications to 
demonstrate that the definition of RNG will be met.
---------------------------------------------------------------------------

    \275\ See ``Guidance on Biogas Quality and RIN Generation when 
Biogas is Injected into a Commercial Pipeline for use in Producing 
Renewable CNG or LNG under the Renewable Fuel Standard Program.'' 
September 2016. EPA-420-B-16-075.
---------------------------------------------------------------------------

    Treated biogas results from processing biogas similar to RNG, but, 
unlike RNG, it is not intended to be placed on a commercial pipeline. 
We have created different regulatory provisions for treated biogas and 
RNG because we have different concerns regarding how to verify that 
they are used as transportation fuel. Treated biogas is a separate term 
from RNG to distinguish the different regulatory provisions.
    We have incorporated the use of these new definitions in both 40 
CFR part 80, subpart E and 40 CFR part 80, subpart M where applicable.

H. Registration, Reporting, Product Transfer Documents, and 
Recordkeeping

    We are finalizing with modifications the proposed compliance 
provisions necessary to ensure that the production, distribution, and 
use of biogas, RNG, and biogas-derived renewable fuels are consistent 
with Clean Air Act requirements under the RFS program. These compliance 
provisions include registration, reporting, PTDs, and recordkeeping 
requirements. Each of these compliance provisions is discussed below.
1. Registration
    Under the RFS program, biointermediate and renewable fuel producers 
are required to demonstrate at registration that their facilities can 
produce the specified biointermediates and renewable fuels from 
renewable biomass under an EPA-approved pathway. These producers 
demonstrate that they are capable of making qualifying biointermediates 
and renewable fuels by having an independent third-party engineer 
conduct a site visit and prepare a report confirming the accuracy of 
the producer's registration submission. These RFS registration 
requirements serve as an important step to ensure that only 
biointermediates and renewable fuels that can be demonstrated to meet 
the Clean Air Act requirements for producing qualifying renewable fuels 
are allowed into the program. We also require parties that transact 
RINs to register in order for them to gain access to EPA systems where 
RIN transactions are recorded and to submit required periodic reports, 
which are necessary to ensure that we can track and verify the validity 
of RINs.
    To that end, biogas producers, RNG producers, and RNG RIN 
separators must register with EPA prior to participation in the RFS 
program. Under these registration requirements, biogas producers, RNG 
producers, and RNG RIN separators must submit information that 
demonstrates that the facilities are capable of producing biogas, RNG, 
or renewable CNG/LNG from renewable biomass under an EPA-approved 
pathway. For biogas producers and RNG producers, this information must 
include the feedstocks that the producer intends to use, the process 
through which the feedstock is converted into biogas or RNG, and any 
other information necessary for EPA to determine whether the biogas or 
RNG, was produced in a manner consistent with Clean Air Act and EPA's 
regulatory requirements. Such information is necessary to ensure that 
biogas-derived renewable fuels are produced only from qualifying 
biogas. Biogas producers and RNG producers must also establish a 
baseline volume for their respective facilities at registration. This 
baseline volume is intended to represent the production capacity of the 
facility and serve as a check for EPA and third parties on the volumes 
reported by a facility of biogas or RNG to help identify potential 
fraud. Like biointermediate production and renewable fuel production 
facilities, we are requiring that biogas production and RNG production 
\276\ undergo a third-party engineering review as part of registration 
to have an independent professional engineer verify at registration 
that the facility is capable of producing biogas or RNG consistent with 
Clean Air Act and EPA regulatory requirements. For RNG RIN separators, 
we are requiring they submit a description of process and equipment 
used to compress RNG into renewable CNG/LNG at registration and a list 
of initial dispensing locations.
---------------------------------------------------------------------------

    \276\ See 40 CFR 80.1450(b)(2).
---------------------------------------------------------------------------

    We are also finalizing as proposed that biogas producers and RNG 
producers associate with one another as part of their registrations. An 
association is a process where two parties establish that they are 
related for purposes of complying with regulatory requirements under 
the RFS program. Such associations are needed to track the 
relationships between the parties and to allow RIN generators the 
ability to generate RINs in EMTS. For example, under the RFS QAP, RIN 
generators must associate with QAP auditors in order to generate Q-RINs 
in EMTS. Similarly, biointermediate producers and renewable fuel 
producers must associate with one another in order for the renewable 
fuel producer to generate RINs for renewable fuels produced from 
biointermediates. These associations must be submitted via registration 
because our registration system is currently set up to track these 
kinds of relationships. Similarly, when biogas is used to produce a 
biogas-derived renewable fuel or as a biointermediate in a biogas 
closed distribution system, biogas producers and RIN generators must 
also associate with one another at registration.
    It is important to note that under existing fuel quality 
regulations at 40 CFR part 1090 and RFS regulations at 40 CFR part 80, 
new registrants who require an annual attest engagement (see Section 
IX.K.2) must identify a third-party auditor and associate with that 
party via registration. To submit materials on behalf of the regulated 
party, any third-party auditor who is not already registered must 
register in accordance with existing requirements under 40 CFR parts 
1090 and 80 using forms and procedures specified by EPA. For parties 
required to complete an annual attest engagement under biogas 
regulatory reform, the registration and association of third-party 
auditors will

[[Page 44533]]

function the same because we did not propose and are not modifying the 
existing requirement that all parties do so. We only highlight this 
provision to aide affected stakeholder's understanding of how the 
biogas regulatory reform will work and discuss related attest 
engagement requirements in more detail in Section IX.K.2.
    We received several comments opposed to the requirement that biogas 
producers directly register. Commenters discussed how this might 
subject small parties to liability and regulatory burdens and suggested 
that the QAP process effectively oversees the process. However, it is 
important for parties that choose to produce biogas under the RFS 
program to be held responsible for complying with the regulations, 
because the biogas producer is the party best able to demonstrate that 
the biogas was produced from renewable biomass under an EPA-approved 
pathway. This is critical for EPA's oversight and enforcement 
capabilities, and to ensure that fuels that are used to satisfy the 
statutory volume requirements are actually qualifying renewable fuel. 
The RFS QAP mainly provides oversight for the facilities registered 
under the RFS and is not a substitute for holding biogas producers that 
do not comply with the regulatory requirements liable. As discussed in 
Section IX.C, we believe that third parties will continue to help 
smaller entities participate in the RFS program as they currently do 
for other renewable fuels.
2. Reporting
    Under the RFS program, we generally require reports from regulated 
parties for the following reasons: (1) To monitor compliance with the 
applicable RFS requirements; (2) To support the generation, 
transaction, and use of RINs via EMTS; (3) To have accurate information 
to inform EPA decisions; and (4) To promote public transparency. We 
already have reporting requirements for renewable fuels, including for 
renewable CNG/LNG, in 40 CFR 80.1451. We are establishing similar 
reporting requirements for biogas producers, RNG producers, and RNG RIN 
separators.
    For biogas producers, we are requiring monthly batch reports that 
include the amount of raw biogas produced as well as the biomethane 
content and energy for the biogas produced at each biogas production 
facility. In these reports, biogas producers must also break down each 
batch by its verification status, by its associated pathway information 
(e.g., D code, feedstock, and designated use), and by the party 
receiving the batch (e.g., RNG producer).\277\ The associated pathway 
information includes how the biogas will be used (i.e., whether the 
biogas would be used to make renewable CNG/LNG via a closed, private 
pipeline system; RNG; or used as a biointermediate). This information 
is necessary for EPA to ensure that the amount of biogas produced 
corresponds to the biogas producer's registration information and 
serves as the basis for RIN generation for biogas-derived renewable 
fuels. This information is also important for the verification of RINs 
under the RFS QAP and for annual attest audits.
---------------------------------------------------------------------------

    \277\ Multiple commenters noted a difference in the preamble to 
the NPRM and the proposed regulations regarding whether separate 
batches should be generated by digester or by facility. We are 
finalizing that batches should be generated by facility, as 
discussed in RTC Section 10.5.
---------------------------------------------------------------------------

    We intend to have biogas producers complete the monthly reporting 
requirement by entering batch reports directly into EMTS and then 
transferring each batch also in EMTS to a party that uses such biogas 
to produce a biogas-derived renewable fuel, RNG, or a biointermediate. 
Tracking the movement of biogas batches in EMTS between the biogas 
producer and the parties that use such biogas to produce biogas-derived 
renewable fuels, RNG, or as a biointermediate will improve the quality 
of information, enable better information sharing between parties, 
including third-party auditors, and define a structured reporting 
process.
    For RNG producers, we are requiring quarterly reports to support 
verification of the amount of RNG produced from qualifying biogas and 
injected into the natural gas commercial pipeline system. RNG producers 
must report the amount and energy content of biogas used to produce RNG 
and the quantity of RNG that was produced and placed onto the natural 
gas commercial pipeline system by verification status and associated 
pathway. Similar to the biogas reports, these reporting requirements 
are necessary to demonstrate the amount of RNG produced from qualifying 
biogas and to describe the amount of RNG placed on the natural gas 
commercial pipeline system, and to help track the associated pathways 
and D-codes of the produced RNG. We note that these reports are 
intended to replace the previous reporting requirements for renewable 
CNG/LNG RIN generators.\278\ Under biogas regulatory reform, we will no 
longer require that the contracts or affidavits were obtained from 
parties in the biogas distribution/generation chain, since this 
tracking will be done via EMTS. We believe this will greatly simplify 
the quarterly reporting requirements related to RNG when compared to 
the prior biogas to renewable CNG/LNG regulatory provisions.
---------------------------------------------------------------------------

    \278\ RFS0601: Renewable Fuel Producer Supplemental report.
---------------------------------------------------------------------------

    Similar to the reporting procedure for biogas producers, RNG 
producers will generate RNG RINs in EMTS and transact them to parties 
that use the RNG as a feedstock, for process heat, or to produce 
renewable CNG/LNG. RNG producers would match the corresponding batch of 
biogas to the batch of RNG through transactions in EMTS like how RINs 
are currently transacted. This allows a batch of RNG to be directly 
connected to a corresponding amount of biogas batches within the RNG 
producer's EMTS holdings. This process ensures the batch information 
has been properly reported and transferred between parties. The reports 
will also serve as the basis for third-party verification and EPA 
audits to help ensure the validity of RNG RINs.
    We are requiring that RNG RIN separators submit periodic reports 
related to their RNG RIN separation activities. For RNG to renewable 
CNG/LNG, these reports must denote which facilities/dispensers 
converted RNG to renewable CNG/LNG, where the renewable CNG/LNG was 
dispensed, and the amount of RNG that was converted to renewable CNG/
LNG and dispensed. This information is necessary to help demonstrate 
that the RNG was converted to renewable CNG/LNG and used as 
transportation fuel. These periodic reports also serve as the basis for 
attest auditors and EPA to verify RNG RIN separation activities.
    RNG RIN separators must also submit additional information related 
to the separation transaction in EMTS. Under the previous regulations, 
we established a series of codes to identify the reason that a RIN is 
separated, consistent with the regulatory requirements that allow for 
RIN separation.\279\ To implement the requirements for biogas 
regulatory reform, we are requiring that RNG RIN separators identify in 
EMTS the reason they were separating an assigned RIN from RNG via new 
separation codes; i.e., whether the RIN was separated from the RNG for 
conversion to renewable CNG/LNG. These parties may only separate the 
RIN from RNG after they have the documentation needed to demonstrate 
that the RNG was used as transportation fuel in the form of renewable 
CNG/LNG.\280\ These changes to EMTS will

[[Page 44534]]

help track the use of RNG under the RFS program, which we believe will 
improve program oversight.
---------------------------------------------------------------------------

    \279\ See 40 CFR 80.1429.
    \280\ Note, RIN separation transactions are reported in EMTS. 
RNG RIN separators must report RIN separations consistent with the 
regulatory requirements specified in 40 CFR 80.140(d) and 80.1452.
---------------------------------------------------------------------------

3. Product Transfer Documents (PTDs)
    We are requiring product transfer documents (PTDs) for transfers of 
title for biogas and RNG. We have historically used PTDs to create a 
record trail that demonstrates the movement of product and information 
between various parties, as a mechanism to designate and certify 
regulated products as meeting EPA's regulatory requirements, and to 
convey specific information to parties that take custody or title to 
the product.\281\ PTDs are important for biogas regulatory reform as 
they are necessary to document that qualifying biogas was transferred 
between biogas producers and RNG producers. EPA and third parties also 
review PTDs to help verify the RINs are validly generated.
---------------------------------------------------------------------------

    \281\ The PTD requirements for RFS are described at 40 CFR 
80.1453.
---------------------------------------------------------------------------

    For biogas title transfers, we are requiring that PTDs include 
information related to the transferer and transferee, the intended use 
of the biogas, the amount of biogas being transferred, and the date 
that title of the biogas was transferred. For RNG title transfers, we 
are requiring that PTDs include the names and addresses of the 
transferor and transferee, the transferor's and transferee's EPA 
company registration numbers, the amount of RNG being transferred, and 
the date of the transfer. Additionally, we are requiring that RNG 
producers clearly designate on the PTDs that the RNG must be used as 
transportation fuel. We note that the RIN PTD requirements at 40 CFR 
80.1453(a) also apply to transfers of title for the RINs assigned to 
the RNG. For cases when RNG is transferred prior to injection into the 
natural gas commercial pipeline system (i.e., between the RNG 
production facility and the injection point), we are also requiring 
PTDs for transfer of RNG custody that indicate that the RNG must be 
used for qualifying purpose. The purpose of requiring PTDs for custody 
transfers prior to injection into the natural gas commercial pipeline 
system is to create a paper trail so that third parties and EPA can 
audit whether the RNG claimed as injected into the pipeline was in fact 
injected into the natural gas commercial pipeline system. These 
elements of the PTDs largely mirror the elements included on the 
current PTD requirements for transfers of renewable fuels and 
biointermediates under the current RFS program in 80.1453.
4. Recordkeeping
    We are finalizing as proposed recordkeeping requirements for biogas 
producers, RNG producers, and RNG RIN separators. The purpose of 
recordkeeping requirements under the RFS program is to allow 
verification that the renewable fuels were produced from qualifying 
renewable biomass, under an EPA-approved pathway, and that the 
renewable fuel was used as transportation fuel, heating oil, or jet 
fuel. These records serve as the basis for information submitted to EPA 
as part of registration and reporting, as well as for the basis of 
audits conducted by independent third parties and EPA.
    For biogas producers, we are requiring records that are already 
required under the RFS for the production of renewable CNG/LNG from 
biogas. These records include information needed to show that biogas 
came from qualifying renewable biomass, copies of all registration 
information including information related to third-party engineering 
reviews, copies of all reports, and copies of any required testing and 
measurement under the RFS program.
    For RNG producers, we are including recordkeeping requirements 
consistent with other parties that produce renewable fuels under the 
RFS program. Relevant to RNG production, RNG producers must maintain 
records indicating how much biogas was received at their facility from 
a registered biogas producer, records demonstrating how much biogas was 
converted to RNG, and records showing the amount of non-renewable 
content added to ensure that applicable pipeline specifications are 
met. For RNG injection, RNG producers are required to maintain records 
showing the date of injection and the volume and energy content of the 
RNG injected into the natural gas commercial pipeline system.\282\ For 
RNG RIN generation, RNG producers must maintain records related to the 
generation of RINs in accordance with 40 CFR 80.1454(b). These 
recordkeeping requirements are necessary to ensure that the RNG was 
produced and injected in a manner consistent with CAA requirements and 
applicable regulatory requirements, and that the appropriate number of 
RINs was generated for the RNG injected into the natural gas commercial 
pipeline system. Since EPA will be tracking the movement of assigned 
RNG RINs in EMTS, we no longer require that the RIN generator (i.e., 
RNG producer under biogas regulatory reform) maintain records related 
to the contractual arrangements for the sale and transfer of RNG to 
parties that distribute the RNG to the end user. These records will no 
longer be needed since EMTS will memorialize the necessary information 
pertaining to the transfer of the assigned RINs.
---------------------------------------------------------------------------

    \282\ For specific cases where RNG that is trucked to an 
interconnect, we are proposing the RNG producer measure when loading 
and unloading each truck.
---------------------------------------------------------------------------

    We are also requiring that RNG RIN separators maintain records 
related to their RNG RIN separation activities. For RNG to renewable 
CNG/LNG, this includes information related to the location where the 
RNG was converted into renewable CNG/LNG, as well as the date, 
location, and amount of dispensed CNG/LNG. The recordkeeping 
requirements related to demonstrating that RNG was used as 
transportation fuel were previously maintained by the RIN generator but 
now must be maintained by the RNG RIN separator. These records are 
necessary to ensure that RNG is used as transportation fuel, and we 
believe that it is most appropriate to require that the party best 
positioned to demonstrate that the RNG is used as transportation fuel 
maintain the records.

I. Testing and Measurement Requirements

    We are finalizing specific testing and measurement procedures for 
biogas and RNG. Due to the value of RINs and the contribution that that 
value can make to company revenue, parties have clear incentives to 
manipulate testing and measurement results to appear to have produced 
more biogas, RNG, and biogas-derived renewable fuels than they actually 
did. By establishing clear and consistent testing and measurement 
requirements, we can ensure the validity of RINs and a level playing 
field for RIN generators.
    For the measurement of biogas and RNG, we are finalizing the 
incorporation of relevant portions of the previously published guidance 
into the regulations.\283\ Under the guidance, we allowed for parties 
to submit as part of their registrations whether they were using in-
line gas chromatography (GC) meters or an alternative sampling protocol 
for measurement of biogas. In this action, we are also allowing an 
alternative to continuous measurement,

[[Page 44535]]

specifying a specific standard for GC meters, and requiring measurement 
for both biogas and RNG.
---------------------------------------------------------------------------

    \283\ ``Guidance on Biogas Quality and RIN Generation when 
Biogas is Injected into a Commercial Pipeline for use in Producing 
Renewable CNG or LNG under the Renewable Fuel Standard Program'' See 
document ID: EPA-420-B-16-075.
---------------------------------------------------------------------------

    Multiple commenters raised concerns about the proposed measurement 
devices. They requested that EPA allow other types of measurement 
devices and allow use of the manufacturers' operating procedures in 
lieu of EPA's proposed standardized measurement techniques. However, 
federal regulations based on the National Technology Transfer and 
Advancement Act (NTTAA) state that agencies should give preference to 
standardized measurement techniques.\284\ Given that there are 
standards for measurement techniques that can be used in the 
measurement of methane concentration and flow of biogas and RNG, we do 
not believe it is appropriate to allow for the use of manufacturers' 
operating procedures or to allow parties to provide documentation to 
EPA when standards for such measurement exist. The appropriateness of 
using other techniques mentioned by the commenters depends on whether a 
standard meets the requirements. Commenters did not provide standards 
for the alternative measurement devices that they recommended EPA 
allow, although EPA did find one standard that is sufficient which is 
for thermal mass flow measurement devices and is therefore allowing 
those devices under the program. The standards for measurement that we 
are finalizing are as follows:
---------------------------------------------------------------------------

    \284\ 15 CFR 287.4(f).
---------------------------------------------------------------------------

     API MPMS 14.3.1, API MPMS 14.3.2, API MPMS 14.3.3, and API 
MPMS 14.3.4: These standards describe the measurement of gaseous flow 
by orifice meters for use in biogas production and RNG production 
facilities.
     API MPMS 14.12: This standard describes measurement of 
gaseous flow by vortex meter for use in biogas production and RNG 
production facilities.
     ASTM D7164: This standard describes measurement of methane 
concentration by gas chromatogram for use in biogas production and RNG 
production facilities.
     EN 17526: This standard describes how to measure gaseous 
flow by thermal mass flow meter for use in biogas and RNG production 
facilities.
    Similarly, we are also incorporating into the regulations part of 
the guidance related to analytical testing for the registration of 
biogas and RNG for use in the production of a biogas-derived renewable 
fuel.\285\ To balance the need for timely registration with our need to 
ensure product quality and to inform future regulations, we are 
finalizing the requirement that RNG producers need to submit 
certificates of analysis from an independent laboratory in its three-
year engineering reviews, but not at initial registration.
---------------------------------------------------------------------------

    \285\ ``Guidance on Biogas Quality and RIN Generation when 
Biogas is Injected into a Commercial Pipeline for use in Producing 
Renewable CNG or LNG under the Renewable Fuel Standard Program'' See 
document ID: EPA-420-B-16-075.
---------------------------------------------------------------------------

    To summarize the requirements we are finalizing, in all engineering 
reviews for facilities upgrading biogas to RNG, an RNG producer must 
supply specifications for the natural gas commercial pipeline system 
into which the RNG will be injected. The pipeline specifications must 
contain information on all parameters regulated by the pipeline (e.g., 
hydrogen sulfide, total sulfur, carbon dioxide, oxygen, nitrogen, 
heating content, moisture, and any other available data related to the 
gas components). Additionally, in all three-year engineering review 
updates for facilities upgrading biogas to RNG, an RNG producer must 
supply the following:
     A certificate of analysis (COA) for a representative 
sample of the biogas produced at the digester or landfill.
     A COA for a representative sample of the RNG prior to the 
addition of any non-renewable components.
     A COA for a representative sample of the RNG after 
blending with non-renewable components (if the RNG is blended with non-
renewable components prior to injection into a pipeline).
     Summary table with the results of the three COAs and the 
pipeline specifications (converted to the same units).
    We had proposed that facilities supply documentation of any waiver 
provided by the commercial distribution pipeline for any parameter of 
the RNG that does not meet the pipeline specifications, if applicable. 
Based on comments, we are no longer requiring that such waivers be 
supplied at registration. Instead, we are requiring parties to keep 
records of such waivers so that EPA can determine whether RNG producers 
brought RNG up to pipeline specifications consistent with EPA's 
regulatory requirements.
    We are finalizing as proposed that the RNG producers must include 
on the COAs submitted as part of a three-year engineering review update 
major and minor gas components (e.g., methane, carbon dioxide, 
nitrogen, oxygen, heating value, relative density, moisture, and any 
other available data related to the gas components), hydrocarbon 
analysis, and trace gas components (e.g., hydrogen sulfide, total 
sulfur, total organic silicon/siloxanes, moisture, etc.), plus any 
additional parameters and related specifications for the pipeline being 
used. We are also specifying methods that must be used when measuring 
biogas properties. These standards are based on methods used for these 
measurements which have been submitted to us in the past and which we 
believe provide sufficient accuracy. The standards we are codifying for 
biogas and RNG measurement for three-year engineering review update 
analysis are the following:
     ASTM D3588: This method describes how to calculate heating 
value and relative density.
     ASTM D4888: This method describes how to measure moisture 
content.
     ASTM D5504: This method describes how to measure hydrogen 
sulfide and other sulfur compounds.
     ASTM D6866: This method measures biogenic carbon.
     ASTM D8230: This method describes how to measure 
siloxanes.
     EPA Method 3C: This method describes how to measure 
methane, carbon dioxide, nitrogen, and oxygen.
     API MPMS 14.1: This method describes how to obtain 
representative samples.
    We also note in the guidance that parties must keep the COAs, 
pipeline specifications, and any measurement-related RIN generation 
components under the recordkeeping requirements of 40 CFR 80.1454. As 
part of the RFS program's third-party oversight provisions, the 
guidance recommends that third-party engineers review conformance with 
applicable recordkeeping requirements as part of their engineering 
reviews while third-party auditors review conformance with these 
recordkeeping requirements pursuant to the RFS QAP. We are finalizing 
as proposed that RNG producers must keep testing and measurement 
records of biogas and RNG and that third-party auditors must verify 
this information as part of QAP, if applicable, as mentioned in the 
guidance.\286\
---------------------------------------------------------------------------

    \286\ ``Guidance on Biogas Quality and RIN Generation when 
Biogas is Injected into a Commercial Pipeline for use in Producing 
Renewable CNG or LNG under the Renewable Fuel Standard Program'' See 
document ID: EPA-420-B-16-075.
---------------------------------------------------------------------------

    We are also finalizing as proposed additional measurement 
requirements

[[Page 44536]]

for RNG that is trucked to a gas pipeline interconnect. In this 
situation, RNG producers must measure RNG flow and energy content of 
biomethane both on loading into and unloading from the truck. We find 
that this requirement is necessary to ensure that RINs are only 
generated from renewable biomass.

J. RFS QAP Under Biogas Regulatory Reform

    Consistent with how QAP was treated under the previous biogas 
provisions, we are not requiring that biogas producers and RNG 
producers participate in the RFS QAP. We believe these biogas 
regulatory reforms will address the issues of double counting as 
discussed in Section IX.A.4.b, such that a requirement that biogas 
producers and RNG producers participate in the RFS QAP is not 
necessary.
    While we are not requiring RFS QAP participation, for parties that 
choose to participate in QAP under the updated biogas program, both the 
biogas producer and the RNG producer must be audited by the same 
independent third-party auditor in order to generate a Q-RIN for RNG. 
In the NPRM we proposed additional elements that a QAP auditor would 
have to verify under biogas regulatory reform consistent with the 
proposed regulatory requirements.\287\ These new QAP elements for RNG 
producers included requirements that the QAP auditor must: \288\
---------------------------------------------------------------------------

    \287\ See 87 FR 80737-80738 (December 30, 2022).
    \288\ See 40 CFR 80.180(c).
---------------------------------------------------------------------------

     Verify that the sampling, testing, and measurement of RNG 
is consistent with the new regulatory requirements.
     Verify that RINs were assigned correctly.
     Verify that RINs were separated and retired correctly.
     Verify that the RNG was injected into a natural gas 
commercial pipeline system.
     Verify that RINs were not generated on non-renewable 
components added to RNG prior to injection into a natural gas 
commercial pipeline system.
    These new QAP elements are necessary for QAP auditors to ensure 
that RNG and RNG RINs are produced and generated, respectively, 
consistent with the biogas regulatory reform provisions and, in 
addition to the generally applicable QAP elements at 40 CFR 80.1469, 
will provide a robust verification scheme to help ensure that RINs 
generated for RNG are valid. Therefore, we are finalizing them as 
proposed.
    We note that, under this action, the parties that transact the 
assigned RNG RIN and the RNG RIN separator do not need to be included 
as part of the RFS QAP. This approach is consistent with the current 
regulatory treatment of RINs generated for ethanol and biodiesel, and 
we are not modifying how the RFS QAP considers RIN separations in this 
action. We note that, as described in Section IX.K.2, we are requiring 
that RNG RIN separators undergo annual attest engagements, which we 
believe should provide sufficient third-party oversight to ensure that 
RNG RINs are separated consistent with the biogas regulatory reform 
provisions.
    Several commenters suggested that instead of finalizing the 
proposed biogas regulatory reform provisions, EPA should require QAP 
participation for parties that generate RINs for biogas to CNG/LNG. 
While we believe that QAP participation can provide added assurance for 
parties that transact RINs generated for biogas to CNG/LNG, the QAP is 
not a substitute for the biogas regulatory reform provisions. EPA 
cannot implement through QAP the modified measurement, reporting, and 
recordkeeping requirements that are necessary to ensure that qualifying 
biogas is used to produce biogas-derived renewable fuels or address our 
double-counting concerns in a situation where biogas may be used for 
multiple purposes under the RFS program. These requirements must be 
imposed on the parties that produce, distribute, and use biogas, RNG, 
and biogas-derived renewable fuels because those parties are best 
positioned to demonstrate compliance with the applicable statutory and 
regulatory requirements. The QAP auditor's role is to verify that the 
applicable regulatory requirements are met, not serve as a substitute 
for the compliance and enforcement provisions that compose biogas 
regulatory reform designed to ensure that qualifying biogas is produced 
and used to generate valid RINs. As we articulated in Section IX.A, we 
are modifying the compliance and enforcement mechanisms under the 
previous biogas provisions to address concerns with double counting to 
ensure that RINs generated from biogas meet Clean Air Act and EPA 
regulatory requirements.
    Commenters also failed to explain how QAP participation would 
effectively address any of EPA's concerns with oversight after we have 
allowed biogas and RNG to be used for multiple uses under the RFS 
program. As noted in the NPRM,\289\ we believe the previous biogas 
provisions were ill-suited for situations where biogas/RNG could have 
multiple uses and that the increased flexibility in the program would 
require additional oversight to ensure that biogas/RNG was not double-
counted and generating invalid RINs. QAP cannot effectively oversee 
this situation because individual auditors would only verify a small 
portion of the production/distribution system as part of their 
verification. Only through creating effective, systemwide tracking can 
such verification occur. Our biogas regulatory reform provisions will 
use EMTS to track the movement of biogas and RNG from production until 
ultimate use. QAP auditors and EPA can then use this tracking 
information to verify that double-counting did not occur.
---------------------------------------------------------------------------

    \289\ 87 FR 80693.
---------------------------------------------------------------------------

K. Compliance and Enforcement Provisions and Attest Engagements

    We are finalizing as proposed compliance and enforcement provisions 
for biogas-derived renewable fuels similar to the existing compliance 
and enforcement provisions under the RFS program. Under the RFS 
program, these provisions serve to deter fraud and ensure that EPA can 
effectively enforce when noncompliance occurs, and the compliance and 
enforcement provisions for biogas-derived renewable fuels will serve 
the same purposes. We discuss the specific provisions below.
1. Prohibited Actions, Liability, and Invalid RINs
    In order to deter noncompliance, the regulations must make clear 
what acts are prohibited, who is liable for violations, and what 
happens when biogas-derived RINs are found to be invalid. To this end, 
we are finalizing as proposed provisions that establish: (1) Prohibited 
actions relating to the generation of RINs from biogas-derived 
renewable fuels; (2) How biogas producers, RNG producers, and RIN 
generators for RNG will be held liable when RINs from biogas-derived 
renewable fuels are determined to be invalid; (3) How biogas producers 
and RNG producers may establish affirmative defenses; and (4) 
Provisions related to the treatment of invalid RINs from biogas-derived 
renewable fuels. Many of these provisions are similar to provisions 
under the existing RFS program and EPA's fuel quality programs in 40 
CFR part 1090.
a. Prohibited Actions
    The RFS program regulations enumerate specific prohibited acts 
under the RFS program. In our recent Fuels Regulatory Streamlining 
Rule, we consolidated the multiple prohibited acts statements in the 
various fuel quality provisions sections of 40 CFR part 80 into a 
single prohibition against causing, or causing someone else to,

[[Page 44537]]

violate any requirement of the part.\290\ For biogas regulatory reform, 
we are adopting a prohibited act that mirrors the consolidated 
prohibited acts provision from the Fuels Regulatory Streamlining Rule, 
and specify that any person who violates, or causes another person to 
violate, any requirement in the subpart for biogas-derived renewable 
fuels, i.e., 40 CFR part 80, subpart E, is liable for the violation. 
Consolidation of the prohibited actions is not meant to alter the scope 
of prohibited actions, but instead provides more clarity to the 
regulated community regarding what actions are prohibited.
---------------------------------------------------------------------------

    \290\ See 85 FR 29034, 29075 (May 14, 2020); 40 CFR 1090.1700.
---------------------------------------------------------------------------

b. Liability Provisions for Biogas, RNG, Biogas-Derived Renewable 
Fuels, and RINs generated for RNG and Biogas-Derived Renewable Fuels
    We are finalizing as proposed liability provisions similar to the 
liability provisions in other EPA fuels programs, including the 
existing RFS program and the recently finalized biointermediates rule. 
Specifically, we are requiring that when biogas, RNG, biogas-derived 
renewable fuels, or RINs from RNG or a biogas-derived renewable fuel 
are found to be in violation of regulatory requirements, the biogas 
producer, the RNG producer, the biogas-derived renewable fuel producer, 
and the person that generated RINs from RNG or a biogas-derived 
renewable fuel will all be liable for the violation. Consequently, RIN 
generators for biogas-derived renewable fuels are ultimately 
responsible for ensuring that any biogas or RNG used to produce the 
fuel complies with the regulations. The description of feedstocks and 
processes in registration materials accepted by EPA does not constitute 
a determination by EPA that the subsequent feedstocks and processes 
used subsequent to the registration are consistent with the RFS 
regulations. Rather it merely represents that the information provided 
at registration would allow for proper RIN generation. The 
responsibility of ensuring compliance with applicable requirements on a 
continuing basis for biogas, RNG, and RINs generated from RNG and 
biogas-derived renewable fuel rests with all parties in the biogas 
disposition/generation chain.
    As noted above, this approach to liability has been used 
extensively in other EPA fuels programs (e.g., the RFS program, 
gasoline, and diesel programs) where it is presumed that violations 
that occur at downstream locations (e.g., a retail station selling 
gasoline) were caused by all parties that produced, distributed, or 
carried the fuel. If upstream parties, such as RNG producers, are 
concerned about downstream non-compliance, they can take advantage of 
the affirmative defense provisions if all of the criteria are met.
    We note that the current RFS regulations include provisions for EPA 
to take certain administrative actions in cases where a regulated party 
has been found to engage in a prohibited practice under the RFS 
regulations. First, under 40 CFR 80.1450(h) EPA may deactivate a 
company registration in cases where a party has failed to comply with 
applicable regulatory requirements. The regulations provide that EPA 
will notify the party of the compliance issue, and the party has 30 
days from the date of the notification to correct the issue before EPA 
may deactivate the party's registration. However, in cases where the 
party's actions compromise public health, public interest, or public 
safety, EPA may deactivate the registration of the party without prior 
notice to the party. This would likely apply in cases where a party is 
found to be generating invalid or fraudulent RINs. Second, EPA may 
administratively revoke an RFS QAP plan for cause. The existing 
regulation at 40 CFR 80.1469(e)(4) specifies that EPA may revoke a QAP 
plan ``for cause, including, but not limited to, an EPA determination 
that the approved QAP has proven to be inadequate in practice.'' 
Furthermore, the regulation at 40 CFR 80.1469(e)(5) specifies that 
``EPA may void ab initio its approval of a QAP upon the EPA's 
determination that the approval was based on false information, 
misleading information, or incomplete information, or if there was a 
failure to fulfill, or cause to be fulfilled, any of the requirements 
of the QAP.''
    Under biogas regulatory reform, these existing provisions for 
administrative action will apply like they do currently under the RFS 
program. We would intend to deactivate registrations in cases where 
parties in the biogas disposition/generation chain have failed to meet 
their regulatory requirements or when it is identified that the party 
has willfully generated invalid or fraudulent RINs. The consequences of 
deactivation of a party in the biogas disposition/generation chain 
(i.e., a biogas producer, RNG producer, or RNG RIN separator) would 
result in the prohibition of the generation of RINs from any affected 
biogas, RNG, or biogas-derived renewable fuel from the party whose 
registration was deactivated. Similarly, if EPA has approved a QAP plan 
for a biogas-derived renewable fuel and EPA revokes the QAP plan, the 
RIN generator previously under that QAP plan would not be able to 
generate verified RINs for that fuel. We note that these administrative 
actions would be in addition to any civil penalties. We believe that in 
combination with the prohibited actions, liabilities, and provisions 
for dealing with invalid RINs from biogas-derived renewable fuel being 
finalized in this rule, regulated parties in the biogas disposition/
generation chain would have a strong incentive to comply with the 
biogas regulatory reform provisions.
c. Affirmative Defenses
    We are finalizing as proposed that biogas producers and RNG 
producers may establish affirmative defenses to certain violations if 
the biogas producer or RNG producer meets all elements specified to 
establish an affirmative defense. We allow for affirmative defenses in 
the RFS program and in our fuel quality program under 40 CFR part 1090 
in cases where a party did not cause or contribute to the violation or 
financially benefit from the violation. We are allowing biogas 
producers to establish an affirmative defense so long as all the 
following are met:
     The biogas producer or any of the biogas producer's 
employees or agents, did not cause the violation.
     The biogas producer did not know or have reason to know 
that the biogas, RNG, or RINs were in violation of a prohibition or 
regulatory requirement.
     The biogas producer has no financial interest in the 
company that caused the violation.
     If the biogas producer self-identified the violation, the 
biogas producer notified EPA within five business days of discovering 
the violation.
     The biogas producer submits a written report to EPA within 
30 days of discovering the violation, which includes all pertinent 
supporting documentation describing the violation and demonstrating 
that the applicable elements of this section were met.
     The biogas producer conducted or arranged to be conducted 
a quality assurance program that includes, at a minimum, a periodic 
sampling and testing program adequately designed to ensure its biogas 
meets the applicable requirements to produce the biogas.
     The biogas producer had all affected biogas verified by a 
third-party auditor under an approved QAP plan.
     The PTDs for the biogas indicate that the biogas was in 
compliance with the applicable requirements while in the biogas 
producer's control.
    For RNG producers, we are finalizing as proposed analogous 
requirements to

[[Page 44538]]

establish an affirmative defense except that, instead of relating to 
biogas producers, the elements relate to RNG producers. We believe 
these elements to establish an affirmative defense will allow RNG 
producers to avoid liability only in cases where they could not 
reasonably be expected to know that a violation took place; for 
example, if an RNG RIN separator separated RINs improperly.
    We are also finalizing as proposed that RNG producers and biogas-
derived RIN generators may not establish an affirmative defense against 
violations when the RNG or biogas-derived renewable fuel, respectively, 
is found to be in violation. Under the RFS program, the RIN generator 
is always responsible for the validity of the RIN. As such, biogas-
derived renewable fuel RIN generators will not have the ability to 
establish an affirmative defense for biogas-derived renewable fuels and 
RINs generated for such fuels. We expect these parties, like all RIN 
generators under the RFS program, to diligently ensure that other 
parties that are part of the biogas distribution/generation chain are 
meeting their regulatory requirements. Similarly, when the RNG producer 
produces RNG and generates a RIN for such RNG, the RNG producer will 
not be able to establish an affirmative defense for the RNG or RNG 
RINs.
d. Invalid RINs
    We are finalizing as proposed provisions similar to the existing 
RFS regulations to address the treatment of invalid RINs generated for 
RNG and biogas-derived renewable fuels. Under biogas regulatory reform, 
if a RIN generated for RNG or a biogas-derived renewable fuel is 
identified as potentially invalid by any party (e.g., the RIN 
generator, an independent third-party auditor, or EPA), certain 
notifications and remedial actions will be required to address the 
potentially invalid RIN. These provisions are necessary to ensure that 
RINs represent biogas-derived renewable fuels that were produced from 
renewable biomass under an EPA-approved pathway and used as 
transportation fuel.
    We are also finalizing as proposed provisions that require biogas 
and RNG producers to notify the next party in the biogas disposition/
generation chain if they become aware that inaccurate amounts of biogas 
or RNG were transferred to that party. In addition, any person must 
notify EPA within five business days of discovery if they become aware 
of any biogas or RNG producers taking credit for the sale of the same 
volumes of biogas/RNG to multiple downstream parties. These provisions 
are necessary to help prevent the generation of invalid RINs by 
ensuring that parties in the biogas disposition/generation chain are 
informing all affected parties of issues when they arise.
2. Attest Engagements
    We are finalizing as proposed attest engagement provisions similar 
to the attest engagement provisions in other EPA fuels programs, 
including the existing RFS program and the recently finalized 
biointermediates rule. These provisions are designed to ensure 
compliance with the regulatory requirements, and this action simply 
extends those requirements to the newly regulated parties under biogas 
regulatory reform. Specifically, we are finalizing as proposed that 
biogas producers, RNG producers, and RNG RIN separators separately 
undergo an annual attest engagement. Annual attest engagements are 
annual audits of registration information, reports, and records to 
ensure compliance with regulatory requirements. Under our fuel quality 
and RFS programs, we require that attest engagements be performed by an 
independent third-party certified professional accountant that notifies 
EPA of any discrepancies they identify in their prepared report. The 
audited parties typically correct areas identified by the attest 
auditor, and we review the reports for areas of concern that need to be 
addressed in future actions. We have a long history of successfully 
employing annual attest engagements to help ensure integrity of our 
fuel quality and RFS programs, and we believe that attest engagements 
are an important component of third-party oversight of biogas-derived 
renewable fuels.
    Attest engagements for biogas producers involve an audit of 
underlying records (including measurement records and PTDs), reports, 
and registration information (including the third-party engineering 
review report) for batches of biogas. These attest engagement 
procedures for biogas producers help ensure that biogas is generated 
from qualifying feedstocks and consistent with EPA's regulatory 
requirements.
    Attest audits for RNG producers involve additional procedures that 
are specific to the production and injection of RNG into the natural 
gas commercial pipeline system. These provisions involve verifying that 
records of the measurement of RNG injection are consistent with the 
measurement requirements for RNG described in Section IX.I and 
verifying that pipeline injection statements match the amount of RNG 
reported by RNG producers in quarterly reports. Attest auditors must 
also confirm that the correct number of RINs were generated in EMTS as 
compared to the underlying records. The purpose of these new attest 
engagement procedures for RNG producers is to help ensure that RNG RINs 
are validly generated consistent with EPA's regulatory requirements for 
RNG.
    We are also requiring specific annual attest engagement procedures 
to verify RNG RIN separation. These annual attest engagement procedures 
are in addition to those currently required for RINs separated under 40 
CFR 80.1464. Specifically, an independent attest auditor must obtain 
the underlying records for reported information regarding an RNG RIN 
separator's operations and ensure that the RNG RIN separator has only 
separated RNG RINs in a manner consistent with their ability to 
demonstrate that RNG was used as transportation fuel. Similar to other 
annual attest engagement procedures under EPA's fuels program, issues 
identified by the independent attest auditor are required to be flagged 
in the annual attest engagement report. These annual attest engagement 
provisions are necessary to ensure that RNG RINs are only separated 
when consistent with applicable regulations.
    The attest engagements for all parties under biogas regulatory 
reform follow the same general requirements for other attest 
engagements under EPA's other fuel programs.\291\ In their registration 
information, parties must identify their independent attest auditors, 
and their independent attest auditors must electronically submit annual 
attest engagement reports directly to EPA using forms and procedures 
prescribed by EPA. In addition, an independent auditor (i.e., a CPA 
without any interest in the audited party) must conduct the audit on a 
representative sample of information, prepare the annual attest 
engagement report detailing any discrepancies or findings from the 
audit, and submit the report to EPA by the annual June 1st deadline. 
Attest engagements are appropriate for parties involved in the 
generation of RINs for biogas-derived renewable fuels as they serve to 
maintain consistency across the three regulated parties and serve as 
valuable third-party oversight.
---------------------------------------------------------------------------

    \291\ See 40 CFR 80.1464 and 1090.1800.
---------------------------------------------------------------------------

L. RNG Used as a Feedstock

    We are finalizing as proposed provisions to address situations in 
which RNG is used as a feedstock to make biogas-derived renewable fuel

[[Page 44539]]

other than renewable CNG/LNG. Specifically, renewable fuel producers 
must retire the RINs assigned to a given volume of RNG prior to using 
that volume to produce biogas-derived renewable fuels. When RNG is used 
as a feedstock to produce a biogas-derived renewable fuel, the 
applicable RIN generation procedures would vary depending on what fuel 
is made from the RNG. For example, if a renewable fuel producer were to 
use RNG as a feedstock to produce hydrogen, the renewable fuel producer 
would retire any RINs assigned to the volume of RNG and then generate 
new RINs for the hydrogen so long as the hydrogen met all other 
applicable regulatory requirements to qualify as a renewable fuel.
    We believe this approach allows for multiple uses of RNG without 
imposing strict limits on the parties that produce or distribute RNG. 
By assigning RINs to the RNG injected into the natural gas commercial 
pipeline system and using EMTS to track the transfer of the assigned 
RINs between parties that produced the RNG and those that use the RNG, 
we believe we can provide flexibility in the use of RNG while 
maintaining adequate oversight. We believe requiring the RNG RINs to be 
retired sufficiently mitigates concerns with possible double counting 
of the RNG, i.e., a party could not generate an additional RIN or 
allotment for the RNG unless any assigned RINs were first retired.
    We received a significant number of public comments that supported 
allowing RNG to be used as a feedstock to produce biogas-derived 
renewable fuels other than renewable CNG/LNG. However, some of these 
commenters also suggested that the proposed biogas regulatory reform 
provisions were not needed to allow this activity. For reasons more 
thoroughly discussed in Section IX.A.4 and in the RTC document, the 
biogas regulatory reform provisions are necessary to ensure that RINs 
generated for biogas-derived renewable fuels are valid and to allow 
biogas and RNG to be used as a biointermediate or as a feedstock, 
respectively, under the RFS program. Without the biogas regulatory 
reform provisions, we could not adequately oversee the program, and 
without clear regulatory requirements and compliance mechanisms to 
appropriately account for the production, distribution, and use of 
biogas and RNG, there would be increased opportunities to double-count 
biogas/RNG.

M. RNG Imports and Exports

    For imported RNG, we are maintaining, as proposed, the existing 
regulatory structure of the RFS whereby either the RNG importer or the 
producer of the foreign RNG may generate RINs. Under the previous 
biogas provisions, approximately 10 percent of D3 RINs are generated 
from imported Canadian RNG. Under this action, we are maintaining the 
flexibility of allowing either the foreign renewable fuel producer (in 
this case, the foreign RNG producer) or an importer of foreign RNG may 
generate RINs. A difference between the new regulations and the 
previous biogas provisions is that instead of any foreign party in the 
biogas distribution/generation chain being allowed to generate RINs, 
only a foreign RNG producer or RNG importer may generate the RIN. We do 
not believe these approach changes will significantly affect which 
parties currently generate RINs for Canadian RNG because to date only 
the RNG importer has generated RINs.
    We note that consistent with the treatment of any foreign party 
that generates RINs under the RFS program, where a foreign RNG producer 
generates a RIN, that foreign producer must satisfy the additional 
regulatory requirements at 40 CFR 80.1466, which include submitting to 
U.S. jurisdiction, complying with inspection requirements, and posting 
a bond. We also note that any foreign party that owns RNG RINs must 
also meet the additional regulatory requirements for foreign RIN owners 
at 40 CFR 80.1467.
    We are treating exports of RNG similarly to exports of renewable 
fuel under the RFS program because like when a renewable fuel that was 
exported, exported RNG would no longer be eligible for use as 
transportation fuel in the covered location thereby invalidating any 
RINs generated for the RNG. We have become increasingly aware that, due 
to demands abroad for pipeline quality natural gas and RNG, some 
parties may wish to export RNG. Under this action, since a RIN is 
generated for RNG at the point of injection into a natural gas 
commercial pipeline system, any party that exports the RNG outside of 
the covered location incurs an exporter RVO under 40 CFR 80.1430 and is 
required to satisfy that RVO by retiring the appropriate number and 
type(s) of RINs.

N. Biogas/RNG Storage Prior to Registration

    We are finalizing as proposed provisions that address biogas or RNG 
that is produced and stored prior to EPA's acceptance of a biogas or 
RNG producer's registration submission. We proposed that biogas or RNG 
may be stored on site (i.e., at a storage facility co-located at the 
biogas or RNG production facility \292\) prior to EPA's acceptance of a 
registration submission, provided that certain conditions are met. In 
order to ensure equal treatment of all parties, we also proposed that 
these storage provisions also apply to all other biointermediates and 
renewable fuels under the RFS program.
---------------------------------------------------------------------------

    \292\ ``Facility'' is defined at 40 CFR 80.1401 to mean ``all of 
the activities and equipment associated with the production of 
renewable fuel starting from the point of delivery of feedstock 
material to the point of final storage of the end product, which are 
located on one property, and are under the control of the same 
person (or persons under common control).''
---------------------------------------------------------------------------

    We received multiple comments on these proposed provisions. Several 
commenters stated that not allowing RINs to be generated for RNG stored 
off-site prior to EPA's acceptance of a registration would impose a 
burden on stakeholders due to, among other things, the long amount of 
time it takes EPA to process and accept registration requests In the 
NPRM, we explained that we believed the streamlined registration 
requirements for RNG producers should greatly decrease the time 
necessary to process registrations and thus eliminate the need for 
offsite storage prior to EPA acceptance of registration. After 
reviewing the comments, we continue to believe this to be the case, as 
discussed more fully in the RTC document. Consequently, we are 
finalizing as proposed that any biogas or RNG which is produced and 
stored prior to EPA's acceptance of a biogas or RNG producer's 
registration submission must be stored on-site to participate in RFS. 
What follows is background and detail about what we are finalizing.
    Under the RFS1 program, we issued guidance \293\ stating that 
parties may assign RINs for renewable fuels that had left the renewable 
fuel production facility prior to EPA acceptance of registration 
because the RFS1 regulations required that RINs be assigned to 
renewable fuels at the point of production but did not specifically 
define what ``point of production'' meant. We took this approach under 
RFS1 because the program did not require that the renewable fuel be 
produced under an EPA-approved pathway (i.e., the renewable fuel 
qualified by virtue of meeting the

[[Page 44540]]

definition of ``renewable fuel'' under the RFS1 program).
---------------------------------------------------------------------------

    \293\ Questions and Answers on the Renewable Fuel Standard 
Program. Page 7. https://nepis.epa.gov/Exe/ZyPDF.cgi?Dockey=P1001T9Z.pdf.
---------------------------------------------------------------------------

    Under the RFS2 program, in general, EPA does not allow parties that 
produce renewable fuels to generate RINs for renewable fuel that has 
left the control of the renewable fuel producer prior to EPA acceptance 
of the renewable fuel producer's registration. We have not allowed this 
because of the possibility that EPA may determine that the fuel was not 
produced consistently with EPA's regulatory requirements and, 
therefore, may not be eligible for RIN generation. In contrast, 
however, we had allowed parties to generate RINs for biogas and RNG 
that was produced prior to EPA acceptance of the RIN generator's 
registration and was stored offsite, provided several conditions were 
met. First, the biogas/RNG must have been produced after the third-
party engineer conducted the site visit as described in 40 CFR 
80.1450(b)(2). Second, the biogas/RNG must have been produced 
consistent with the requirements of an EPA-approved pathway. Third, the 
RIN generator must not have changed the facility after the site visit 
by the third-party engineer. We had allowed this greater flexibility to 
allow biogas/RNG to be stored offsite prior to registration for 
pathways converting biogas to renewable CNG/LNG in large part due to 
the length of time it has taken EPA to review and accept registrations 
as a result of the previous registration requirements. However, this 
flexibility has hindered our ability to verify the validity of RIN 
generation for stored biogas/RNG. From our experience implementing 
biogas pathways, allowing RNG to be stored offsite has posed challenges 
when overseeing the production of RNG, since the production of RNG from 
the facility would often not match the number of RINs generated. The 
information used to generate the RINs was often different from the 
information used to demonstrate RNG production for the month. The main 
reason this information did not align under the previous biogas 
provisions was likely because RNG is typically stored for an 
undisclosed period of time. Because of how difficult it is to track 
discrete volumes of RNG that are claimed for RIN generation, production 
and use information rarely matched up, and the only way to compare RNG 
production information with RNG use information was to review all of 
the underlying records for every party in the entire distribution 
system over the entire period, which could involve the collection and 
evaluation of hundreds of thousands of records for the production, 
transfer, and use of each discrete volume of biogas/RNG since the 
beginning of the program, i.e., 2014. By disallowing storage prior to 
registration, we can fully utilize the RIN assigned to RNG volumes to 
track the production and use of RNG and eliminate the risk of 
noncompliant, stored RNG generating RINs.
    As explained in Section X.H.4, as part of biogas regulatory reform 
we are no longer requiring that biogas and RNG producers demonstrate 
that there are contracts between each party in the biogas distribution/
generation chain in order to demonstrate transportation use. This will 
streamline registration of facilities, so we believe it is no longer 
appropriate to allow for RINs to be generated for biogas/RNG produced 
and stored offsite of the biogas/RNG production facility prior to EPA 
acceptance of the biogas and RNG producer's registrations. Also, as 
discussed in Section IX.I, we are further streamlining the registration 
requirements by no longer requiring RNG producers to supply COAs for 
biogas and RNG at initial registration. The removal of this COA 
requirement at initial registration will likely further reduce the 
amount of time it will take RNG producers to be registered.
    We are, however, continuing to allow for the storage onsite of 
biogas/RNG, consistent with other renewable fuels and biointermediates, 
produced prior to EPA acceptance of a registration submission if 
certain conditions are met. Specifically, we are allowing for storage 
onsite when all of the following conditions are met:
     The stored biogas, RNG, biointermediate, or renewable fuel 
was produced after an independent third-party engineer has conducted an 
engineering review for the renewable fuel production or biointermediate 
production facility.
     The stored biogas, RNG, biointermediate, or renewable fuel 
was produced in accordance with all applicable regulatory requirements 
under the RFS program.
     The biogas producer, RNG producer, biointermediate 
producer, or renewable fuel producer made no change to the facility 
after the independent third-party engineer completed the engineering 
review.
     The stored biogas, RNG, biointermediate, or renewable fuel 
was stored at the facility that produced the biogas, RNG, 
biointermediate, or renewable fuel.
     The biogas producer, RNG producer, biointermediate 
producer, or renewable fuel producer maintains custody and title to the 
stored biogas, RNG, biointermediate, or renewable fuel until EPA 
accepts the biogas or RNG producer's registration.
    These conditions are necessary for biogas/RNG to be stored onsite 
prior to registration to ensure that RINs are not generated for fuels 
that fail to meet the applicable Clean Air Act and regulatory 
requirements for the production of renewable fuels. We believe that so 
long as the biogas or RNG producer has had a third-party engineer 
confirm that the facility could produce products consistent with the 
applicable RFS regulatory requirements and so long as the producer does 
not modify their facility, the biogas and RNG produced at these 
facilities should be eligible to generate RINs. These products have to 
be produced in accordance with the applicable regulatory requirements. 
We are requiring that the biogas or RNG producer maintain custody of 
the product because once the product has left its facility, the 
producer would be less able to remedy issues with the product; this 
could also result in other parties downstream becoming liable for the 
product should it not meet applicable regulatory requirements. After 
EPA has accepted the biogas or RNG producer's registration, the stored 
products could then be used under the RFS program.

O. Single Use for Biogas Production Facilities

    To minimize program complexity and avoid the double-counting of 
biogas, we are also finalizing as proposed provisions to govern the use 
of biogas from a biogas production facility. Under these provisions, 
biogas producers are limited to supplying biogas or treated biogas for 
a single use (e.g., RNG, renewable CNG/LNG, or to produce a 
biointermediate). We understand that in real-world applications there 
may often not be a perfect match between biogas production capacity and 
the quantity of biogas for a particular use. However, limiting biogas 
from each biogas production facility to a single use serves the goals 
of minimizing program complexity and safeguarding against double 
counting by eliminating the opportunity for double counting in the 
first place.
    We received comments asking that EPA not finalize this proposed 
condition. Commenters stated that imposing such a condition would 
preclude significant volumes of biogas from being used at biogas 
production facilities that had projects that could supply biogas for 
multiple uses under the RFS program, especially if EPA finalized the 
eRINs proposal. Furthermore, some commenters

[[Page 44541]]

suggested that EPA's condition related to a single biogas use precluded 
the use of biogas for purposes outside of the RFS program.
    While we appreciate commenters' perspectives, we have concluded 
that retaining the proposed condition on single use is necessary given 
the expansion of the biogas program we are also finalizing in this 
rule. Allowing only a single use of biogas under the RFS program will 
significantly reduce the ability for parties to double count biogas for 
purposes of RIN generation under the RFS program. Were we to allow for 
multiple uses from a single facility, we would need more enhanced 
compliance and enforcement mechanisms than were proposed in order to 
adequately oversee the additional complexity. We intend to monitor the 
effects of the single use limitation on biogas production facilities 
and may consider ways to permit multiple uses of biogas at a single 
facility under the RFS program after we have more experience 
implementing the new, expanded biogas program.
    In response to commenters concerns that we are limiting the ability 
for biogas producers to supply biogas for purposes outside of the RFS, 
we are clarifying that parties may use biogas for purposes outside of 
the RFS program; i.e., the condition on the single use of biogas at a 
biogas facility only applies to a single use under the RFS program. We 
discuss related public comments and respond more thoroughly in RTC 
Section 10.

P. Requirements for Parties That Own and Transact RNG RINs

    We are finalizing as proposed the requirement that parties that 
solely transact assigned RNG RINs (i.e., parties that transact RNG RINs 
but that do not generate or separate the RNG RINs) must comply with all 
current regulatory requirements for owning and transacting RINs under 
the RFS program. The sole difference is that only a party that is a 
registered RNG RIN separator and has demonstrated that the RNG has been 
used as renewable CNG/LNG will be allowed to separate the RNG RIN. In 
other words, parties that simply transact assigned RNG RINs are not 
allowed to separate RINs, and we intend to design EMTS to prevent them 
from doing so. As described in more detail in Section IX.H.4, this 
provision is necessary to ensure that RNG is used as transportation 
fuel consistent with the CAA and applicable regulatory requirements.
    Except for the limitation on RNG RIN separation, we note that we 
are not otherwise modifying the requirements for parties that own and 
transact RNG RINs; we are simply highlighting how parties that solely 
own and transact RNG RINs will operate in the context of the biogas 
regulatory reform provisions.

X. Other Changes to Regulations

    This section describes the other regulatory changes beyond those 
already discussed that we are finalizing for the fuel quality and RFS 
programs. We address comments related to these regulatory changes in 
RTC Section 11.

A. RFS Third-Party Oversight Enhancement

    Independent third-party auditors and engineers play critical roles 
in ensuring the integrity of the RFS program.\294\ The independent 
third-party engineer ensures that a renewable fuel producer's facility 
can actually produce renewable fuel in accordance with the RFS 
regulations and thus generate valid RINs. The independent third-party 
auditor, when hired by a renewable fuel producer, verifies that the 
renewable fuel produced adheres to its registered and approved 
feedstocks and processes, and therefore verifies the RINs generated 
under the RFS QAP.\295\ Given EPA's recent promulgation of a program 
allowing renewable fuel to be produced from biointermediates,\296\ we 
expect there will be an expansion in the scope and number of regulated 
entities under the RFS program in the future, making third-party 
verifications even more critical.
---------------------------------------------------------------------------

    \294\ We note that independent third parties serve a different 
function than the third parties discussed in Section IX.C. In this 
case, the independent third party must meet regulatorily specified 
requirements that ensure that the independent third party will 
objectively conduct verification activities under the RFS program. 
Third parties that informally assist compliance by regulated parties 
are not subject to those same independence requirements.
    \295\ Independent third-party engineers and auditors are 
referred to separately based on their roles in the RFS program. In 
order to participate in the RFS program, renewable fuel producers 
must have a third-party engineering review of their facility prior 
to generating RINs, and every three years thereafter. References to 
third-party professional engineers in this preamble refer to the 
third parties that conduct those engineering reviews. Third-party 
auditors verify that the renewable fuel produced by renewable fuel 
producers adheres to their registered and approved feedstocks and 
processes to generated QAPed RINs. These auditors may be 
professional engineers as well, but references to third-party 
auditors in this preamble refer to third parties (engineers and 
other types of professionals) that perform that QAP-related 
function.
    \296\ 87 FR 39600 (July 1, 2022).
---------------------------------------------------------------------------

    We proposed changes to third-party verifications and submissions in 
the 2016 Renewables Enhancement Growth and Support (REGS) proposed 
rule; \297\ however, those proposed changes were not finalized. We re-
proposed (i.e., proposed anew) some, but not all of those changes in 
conjunction with this rulemaking and are now finalizing a modified 
version of those proposed changes in this action.
---------------------------------------------------------------------------

    \297\ 81 FR 80828 (November 16, 2016).
---------------------------------------------------------------------------

    As we explained in the 2016 REGS proposal, EPA has taken a number 
of enforcement actions against renewable fuel producers that generated 
invalid RINs, and the extent of the unlawful and fraudulent activities 
associated with the RFS program, as demonstrated by these cases, is 
troubling given the roles that independent third parties play in the 
RFS program. Because we are concerned that independent third-party 
auditors and engineers may not be sufficiently mitigating unlawful and 
fraudulent activities in the RFS program to the extent needed for a 
successful program, we are strengthening requirements that apply to 
these entities. Consequently, we are modifying the requirements for 
independent third-party auditors that use approved QAPs to audit 
renewable fuel production to verify that RINs are validly generated by 
the producer. The purpose of these modifications is to protect against 
conflicts of interest of QAP providers by strengthening the 
independence requirements for them. We are also making several changes 
to the requirements for the professional engineer serving as an 
independent third party conducting an engineering review for a 
renewable fuel producer as part of their RFS duties in connection to a 
renewable fuel producer's initial registration and subsequent 
registration updates.
    The changes to the regulations that we are making fall into six 
areas. First, we are strengthening the independence requirements for 
third-party engineers by requiring those engineers to comply with 
similar requirements to those that apply to independent third-party 
auditors.
    Second, we are requiring that the third-party engineer sign an 
electronic certification when submitting engineering reviews to EPA to 
ensure that the third-party engineer has personally reviewed the 
required facility documentation, including site visit requirements, and 
that the third-party engineer meets the applicable independence 
requirements. Previously, the third-party engineer signed a 
certification statement within the engineering review documents. We 
believe that an electronic certification at the time of submission will 
help to ensure that the third-party engineer conducts their duties with 
impartiality and independence.
    Third, we are requiring that third-party engineers provide 
documents and

[[Page 44542]]

more detailed engineering review write-ups that demonstrate the 
professional engineer performed the required site visit and 
independently verified the information through the site visit and 
independent calculations.
    Fourth, we are requiring that three-year engineering review updates 
be conducted by a third-party engineer while the facility being 
reviewed is producing renewable fuel. We believe that the efficacy of a 
third-party engineer's review is greatly enhanced when the facility is 
operating under normal conditions and not in a shut down or maintenance 
posture. Conducting the engineering review while the facility is 
operational will allow the third-party engineer to accurately and 
completely verify the elements of the engineering review necessary to 
certify to EPA that the facility is in compliance with its registration 
materials.
    Fifth, we are specifying that third-party auditors must ensure that 
personnel involved in third-party audits (including verification 
activities) are not negotiating for future employment with the owner or 
operator of the audited party. In the NPRM, we proposed to disallow a 
person employed by an independent third-party auditor who is involved 
in a specific activity by the auditor from accepting future employment 
with the owner or operator of the audited party for a period of at 
least 12 months. Several commentors opposed this prohibition and 
claimed that it may deter candidates from working for an auditor due to 
future job restrictions or constitute an unlawful workplace restriction 
in jurisdictions that have adopted ``right to work'' laws. We agree 
that the proposed prohibition can be more narrowly tailored to address 
our primary concern, which is auditors negotiating for future 
employment while conducting auditing activities. We believe that third-
party auditors could be unduly influenced in their QAP verification 
activities if they are negotiating for future employment while 
providing auditing services, and are finalizing a narrower prohibition 
that only applies to auditors that are negotiating for future 
employment with the audited party. This ensures the impartiality needed 
in third-party auditors without restricting individuals' ability to 
obtain future employment.
    Sixth, we are specifying prohibited acts and liability provisions 
applicable to third-party engineers to reduce the potential of a 
conflict of interest with the renewable fuel producer. These 
requirements will help EPA and obligated parties better ensure that 
third-party audits and engineering reviews are being correctly 
conducted, provide greater accountability, and ensure that third-party 
auditors and engineers maintain a proper level of independence from the 
renewable fuel producer.
    Taken together, we believe these six requirements will help avoid 
RIN fraud by strengthening third-party verification of renewable fuel 
producers' registration information. Additional information on third-
party auditors and engineers is provided below.
1. Third-Party Auditors
    Third-party independence is critical to the success of any third-
party compliance program. We believe that the independence requirements 
applicable to third-party auditors in the RFS program should be 
clarified and strengthened to further minimize (and hopefully 
eliminate) any conflicts of interest between auditors and renewable 
fuel producers that might lead to improper RIN validation. We are 
clarifying the prohibition against an appearance of a conflict of 
interest to include:
     Acting impartially when performing all auditing 
activities.
     Prohibiting independent third-party auditors that were 
involved in the design or construction of a facility from auditing that 
facility.
     Prohibiting a person employed by an independent third-
party auditor who is negotiating for future employment with the owner 
or operator of the audited party from participating in that audit.
    These provisions are intended to prevent, among other things, 
third-party auditors that were involved in the design of a facility or 
who are negotiating for employment with the audited party from 
conducting QAP verification activities. In both instances, we believe 
that third-party auditors could be unduly influenced in their QAP 
verification activities as a result.
    In the 2023-2025 NPRM, we proposed to prohibit third parties that 
offered QAP services from offering other business services to audited 
parties for a period of at least one year. One commentor stated that 
this prohibition was overreaching and would stifle the ability of large 
firms to provide QAP services because large firms often provide other 
services not associated with the design of the facility or the RFS 
program (e.g., tax services), which would discourage large firms from 
providing QAP services. As discussed in RTC Section 11.1, we appreciate 
the commenter's concern and, therefore, are finalizing a narrower 
prohibition that only applies to third parties that were involved in 
the design or construction of the audited facility. This achieves the 
goal of the proposed provision without unnecessarily limiting the pool 
of third parties who can qualify as third-party auditors.
2. Third-Party Engineers
    Engineering reviews from independent third-party engineers are 
integral to the successful implementation of the RFS program. Not only 
do they ensure that RINs are properly categorized, but they also 
provide a check against fraudulent RIN generation. As we have designed 
our registration system to accommodate the association between third-
party auditors and renewable fuel producers to implement the RFS QAP, 
we have realized that both the way engineering reviews are conducted 
and the nature of the relationships among the third-party engineers, 
affiliates, and renewable fuel producers are analogous to third-party 
auditors and renewable fuel producers. As a result, we are 
strengthening the independence requirements for third-party engineers 
by requiring those engineers to comply with requirements similar to 
those that apply to independent third-party auditors.
    We are also improving the RFS registration requirements for three-
year engineering review updates by requiring site visits to take place 
when the facility is producing renewable fuel. This will provide the 
regulated community and EPA with greater confidence in the production 
capabilities of the renewable fuel facility. Since the adoption of the 
RFS2 requirements in 2010, most engineering reviews have been conducted 
by a handful of third-party engineers. Some of these engineers are 
using templates that make it difficult for EPA to determine whether 
registration information was verified.
    We are concerned that, in some instances, the third-party engineers 
are relying too heavily on information provided by the renewable fuel 
producers, and not conducting a truly independent verification. In 
order to provide greater confidence in third-party engineering reviews, 
we are requiring that the engineering review submission include 
evidence of a site visit while the facility is producing the renewable 
fuel that it is registered to produce. We are also incorporating EPA's 
current interpretation and guidance into the regulations regarding 
actions that third-party engineers must take to verify information in 
the renewable fuel producer's registration application. The amendments 
explain that in order to verify the applicable registration 
information, the third-party

[[Page 44543]]

auditor must independently evaluate and confirm the information and 
cannot rely on representations made by the renewable fuel producer. We 
are also requiring that the third-party engineer electronically 
certifies that the third-party meets the independence requirements 
whenever the third-party submits engineering reviews or engineering 
review updates to EPA. Previously, the third-party engineer signed a 
certification statement within the engineering review documents. 
Requiring the certification to be signed at the time of submission will 
remind the third-party engineer of the independence requirements prior 
to submitting the engineering reviews.
    We believe these amendments will help provide greater assurance 
that third-party engineering reviews are based upon independent 
verification of the required registration information in 40 CFR 
80.1450, helping to provide enhanced assurance of the integrity of the 
registration materials submitted by the facility, as well as the 
renewable fuel they produce.
    Finally, we are specifying prohibited activities for third-party 
engineers failing to properly conduct an engineering review, or failing 
to disclose to EPA any financial, professional, business, or other 
interest with parties for whom the third-party engineer provides 
services for under the RFS registration requirements. Based on its 
review of RFS registrations, EPA has concerns that third-party 
engineers may not be appropriately conducting engineering reviews 
consistent with EPA's intent because they may not meet the requirements 
for independence to qualify as a third party. We believe that making 
third-party engineers more accountable for properly conducting 
engineering reviews under the regulations and requiring that they 
interact more directly with EPA will help us to identify potential 
conflicts of interest and to bring enforcement actions should an issue 
arise.
    During discussions with stakeholders after publication of the NPRM, 
some parties suggested that EPA delay the implementation date for the 
enhancements to third-party oversight because third-party engineers 
will have already conducted three-year engineering site visits for 
facilities prior to the effective date of the rule that are due January 
31, 2024, and it was unclear how these new changes would affect 
previously conducted site visits by independent third-party engineers 
that are due January 31, 2024. To address these concerns, we are 
specifying that the new requirements for independent third-party 
engineers and for engineering reviews will begin on February 1, 2024. A 
February 1, 2024, implementation date will ensure that three-year 
engineering reviews conducted to meet the January 31, 2024, deadline 
are not impacted by the new regulatory requirements avoiding 
duplicative effort on the part of independent third-party engineers.

B. Deadline for Third-Party Engineering Reviews for Three-Year Updates

    We are finalizing with modification our proposal that third-party 
engineers conduct engineering review site visits no sooner than July 1 
of the calendar year prior to the January 31 deadline for three-year 
registration updates. In response to public comments, we are also 
finalizing additional flexibility that will allow parties to reset 
their three-year update due date if they comply with the three-year 
update requirement before it was due. We believe this flexibility will 
allow parties to simultaneously comply with the RFS program and CARB's 
LCFS verification requirements. Finally, in response to public comments 
requesting more time to comply with the new requirements, we are 
finalizing that the new deadline for engineering review site visits 
will begin after the 2023 three-year registration update deadline 
(i.e., after January 31, 2024) to minimize the impact on those parties 
that may have already arranged for engineering review site visits under 
the previous regulatory requirements.
    Previously, renewable fuel producers were required to have a third-
party engineer conduct an updated engineering review three years after 
initial registration. The regulations stated that the three-year 
engineering review reports were due by January 31 three years after the 
first year of registration. However, the regulations did not specify 
when the third-party engineer must conduct the site visit. We received 
several inquiries from renewable fuel producers and third-party 
engineers concerning when the third-party engineer must conduct the 
site visit ahead of the January 31 deadline. We originally published 
guidance that stated that the site visits for three-year updates should 
occur no later than 120 days prior to the January 31 deadline. Due to 
extenuating circumstances, we have on a case-by-case basis allowed for 
site visits to occur up to a full calendar year prior to the deadline.
    However, we continue to have concerns that third-party engineers 
are conducting site visits well ahead of the January 31 deadline and 
that the renewable fuel production facilities they visited may have 
undergone significant alteration between the time of the site visit and 
the time that the third-party engineering review report is due. To 
address our concern, we are requiring that the site visit occur no 
sooner than July 1 of the preceding calendar year. We believe that this 
amount of time will provide third-party engineers enough time (seven 
months) to conduct site visits and prepare and submit engineering 
review reports to EPA without the site visit becoming out-of-date. We 
believe this additional time is reasonable as the number of facilities 
that require three-year updates has increased.
    We are also specifying which batches of RINs should be included in 
the VRIN calculation portion of the three-year registration 
update. Under this provision, third-party engineers must select from 
batches of renewable fuel produced through at least the second quarter 
of the calendar year prior to the applicable January 31 deadline for 
VRIN calculations. We believe this is necessary because some 
third-party engineers conduct VRIN calculations for 
facilities' RIN generation materials that only cover two years. 
Furthermore, we have noticed that the period from which batches are 
selected for VRIN calculations can vary significantly across 
third-party engineers and we want to ensure that this portion of the 
engineering review update is conducted consistently.
    We received comments suggesting that we should accept engineering 
reviews with site visits that occurred within 12 months of the 
deadline, in part to align with California's verification requirements 
under their LCFS program. While we appreciate commenters' concerns that 
there may be overlapping verification requirements for the RFS program 
and California's LCFS, we note that most renewable fuel producers under 
the RFS program do not participate in California's program. However, in 
order to allow parties to utilize a single site visit for both 
programs, the final rule allows parties to reset their three-year 
updates, as long as they have complied with the regulatory requirements 
before the three-year update is due. This would have the added benefit 
of allowing a party that needed to undergo a new engineering review as 
required under 40 CFR 80.1450(d)(1) to use that new engineering review 
to fulfil their three-year engineering review update (assuming all 
applicable requirements for the three-year update are met).
    Several commenters suggested that we postpone the implementation 
date for these provisions to avoid parties having

[[Page 44544]]

to redo their three-year updates and engineering reviews because the 
regulatory requirements changed in the middle of a three-year update 
cycle. We agree with commenters' concerns and note that it was not our 
intent to require parties to comply with two sets of regulatory 
requirements for the same three-year update. Therefore, to address 
commenters' concerns and clarify our intent, we are requiring that the 
new deadline for three-year update site visits and VRIN requirements 
begins after the conclusion of the compliance year 2023 three-year 
update deadline (i.e., February 1, 2024). We believe this 
implementation date will minimize the effects of these changes on 
parties that have already started complying with previous three-year 
update requirements and will allow for a smooth transition.

C. RIN Apportionment in Anaerobic Digesters

    In the Pathways II rule, we created a pathway to allow D3 RINs to 
be generated for renewable CNG/LNG produced from biogas from digester 
types that process only predominately cellulosic \298\ feedstocks 
(i.e., municipal wastewater treatment facility digesters, agricultural 
digesters, and separated MSW digesters), as well as from the cellulosic 
components of biomass processed in other waste digesters.\299\ We also 
created a renewable CNG/LNG pathway to allow for D5 RINs to be 
generated for biogas produced from other waste digesters.\300\ If a 
party simultaneously converts a predominately cellulosic feedstock and 
a non-predominantly cellulosic feedstock in a waste digester, it must 
apportion the resulting RINs under the appropriate D3 and D5 pathways 
accordingly. To support this calculation, we required parties to 
calculate the cellulosic converted fraction (i.e., the portion of a 
cellulosic feedstock that is converted into renewable fuel) based on 
measurements of cellulose obtained using a method that produces 
reasonably accurate results. For a heterogeneous feedstock such as 
separated food waste--which may be simultaneously converted with 
cellulosic feedstocks in waste digesters--the cellulosic content can 
vary widely between batches, making it very difficult for renewable 
fuel producers to determine the cellulosic content of the feedstock 
with any degree of accuracy.
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    \298\ A predominately cellulosic feedstock is a feedstock with 
an adjusted cellulosic content of greater than 75 percent.
    \299\ See row Q in Table 1 to 40 CRF 80.1426; 79 FR 42168 (July 
18, 2014). D3 RINs may also be generated for renewable CNG/LNG 
produced from biogas from landfills--the landfill biogas pathway is 
not implicated by these changes.
    \300\ See row T in Table 1 to 40 CFR 80.1426; 79 FR 42168 (July 
18, 2014). This pathway must be used if the feedstock being 
processed in a digester is not predominantly cellulosic.
---------------------------------------------------------------------------

    Since the Pathways II rule was finalized, stakeholders have 
inquired how to apportion RINs in the specific case wherein feedstocks 
that are not predominantly cellulosic--specifically, separated food 
waste--are simultaneously converted with predominantly cellulosic 
feedstocks into biogas in a digester.\301\ EPA's previous registration 
and RIN apportionment equations were designed assuming that the 
converted fractions of the cellulosic and non-cellulosic feedstocks 
could be accurately determined through chemical testing. However, 
apportioning RINs for biogas produced from co-processed feedstocks is 
distinct from apportioning RINs for other co-processed cellulosic and 
non-cellulosic feedstocks (e.g., corn kernel fiber co-processed with 
corn starch). In the NPRM, we explained that some of the existing 
requirements are unnecessary or otherwise inappropriate for these 
circumstances and that there are features of co-processing in a 
digester that make it reasonable to consider a different regulatory 
approach to RIN apportionment. The feedstocks in question are generated 
as physically separate streams such that the mass, moisture content, 
and methane production potential of each feedstock can be determined 
before mixing, a possibility that was not contemplated by the previous 
apportionment equations. Further, we understand that parties interested 
in co-processing predominantly cellulosic feedstocks with separated 
food waste are not planning on claiming any credit for the cellulosic 
components of the food waste due to challenges accurately measuring 
cellulosic content of the variable food waste feedstock, which means 
that chemical analysis of the cellulosic content of the food waste 
feedstock and digestate is not required. Another factor that reduces 
the risk of D3 RINs being generated from non-cellulosic feedstock is 
that mixing of non-cellulosic food waste in anaerobic digestion does 
not lead to a decrease in biogas production relative to when the 
feedstocks are processed separately,\302\ so the biogas production from 
the cellulosic feedstock processed alone provides an accurate or 
conservative estimate of the same feedstock's biogas production when 
mixed with non-cellulosic feedstocks.
---------------------------------------------------------------------------

    \301\ See Byron Bunker (EPA), ``Reply to American Biogas Council 
on the Treatment of Agricultural Digesters under the Renewable Fuel 
Standard (RFS) Program,'' March 15, 2017.
    \302\ Karki et al. Bioresource Technology 330 (2021) 125001. 
DOI: 10.1016/j.biortech.2021.125001.
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    In this action we are finalizing as proposed specific equations to 
determine feedstock energy for when predominantly cellulosic and non-
predominantly cellulosic feedstocks are simultaneously converted in 
anaerobic digesters. We have made slight technical adjustments to these 
equations and changed their location relative to what was proposed to 
address commenter concerns. The cellulosic feedstock energy equation is 
similar to the existing, broader equations, with a few modifications. 
The new equation uses a volatile solids measurement since non-volatile 
solids do not generally produce biogas, increasing the accuracy over 
the existing equation. For calculating total solids and volatile 
solids, we are requiring the use of American Public Health Association 
method number 2540, which is already used by the wastewater treatment 
industry in their operations of anaerobic digesters. The non-
predominantly cellulosic biogas is the difference between total biogas 
produced and cellulosic biogas as calculated by the cellulosic 
feedstock apportionment equation. We believe these equations will 
ensure that cellulosic RINs are only generated for predominately 
cellulosic feedstocks because they make a conservative assumption of 
the cellulosic biogas production and ensure that the biogas produced 
from non-predominantly cellulosic feedstocks generates entirely non-
cellulosic RINs. Along with this updated equation, we are requiring 
biogas producers to keep records of feedstocks necessary to verify 
apportionment calculations.
    To support this apportionment, we are finalizing that at 
registration biogas producers provide the converted fraction of the 
predominantly cellulosic feedstock used in an anerobic digester when it 
is simultaneously converted with a non-predominantly cellulosic 
feedstock as well as relevant supporting data. Instead of chemical data 
supporting a cellulosic converted fraction as required under the 
existing regulations, which will continue to apply for situations other 
than anaerobic digesters, we are requiring that, at registration, a 
facility producing biogas from anaerobic digestion either choose a 
predetermined, conservative value for converted fraction (explained in 
more detail below) or provide the following:
     Operational data showing the biogas yield from digesters 
which process solely the cellulosic feedstock(s) and which operate 
under similar conditions as the digesters addressed in the 
registration.

[[Page 44545]]

     A description including any calculations demonstrating how 
the data were used to determine the cellulosic converted fraction.
     The cellulosic converted fraction that will be used in the 
RIN apportionment.
    Operational data used to determine the cellulosic converted 
fraction will necessarily be obtained at a particular range of 
temperatures, pressures, residence times, feedstock composition, and 
other process variables. Since biogas production can change based on 
processing conditions, we are requiring a registrant to identify the 
conditions in its registration under which the facility will need to 
operate to properly apportion RINs. In specifying those processing 
conditions, we are requiring parties to place limitations on a 
combination of temperature, amount of each cellulosic feedstock source, 
solids retention time, hydraulic retention time, or other processing 
conditions established at registration which may impact the conversion 
of the predominantly cellulosic feedstock. These limitations must be 
based on the data used to derive the cellulosic converted fraction so 
that when it is simultaneously converting multiple feedstocks, the 
facility is operating under conditions essentially the same as those 
for the digesters from which the cellulosic converted fraction was 
derived. For example, a registrant that calculates a cellulosic 
converted fraction from historical data of a given digester processing 
a single type of cellulosic feedstock could use that historical 
operational data to identify the limitations on temperature, residence 
times, and other operational variables such that the converted fraction 
remains valid.
    As an alternative to specifying operational data, we are allowing 
registrants to select a standard converted fraction value specified in 
the regulations for the specific cellulosic feedstock which they are 
simultaneously converting with a non-predominantly cellulosic feedstock 
in anaerobic digesters. We are providing specific standard values for 
four cellulosic feedstocks (bovine manure, chicken manure, swine 
manure, and WWTP sludge), which are 50 percent of the measured 
biochemical methane potential (BMP) obtained from published 
literature.\303\ BMP typically results in a higher converted fraction 
than when the same feedstock is processed in industrial scale 
digesters. One study that looked at two digesters over the course of 
less than a year identified sustained periods where full scale 
digesters produced over 30 percent less methane than predicted by BMP 
and recommended that designers of digestion systems should assume 10-20 
percent lower methane production in full scale digesters than from 
BMP.\304\ Given the limited types of feedstocks, the limited number of 
digesters evaluated in this study, and the different goals behind the 
recommendations,\305\ we chose a more conservative estimate of 50 
percent lower methane production and added specific processing 
requirements to ensure that D3 RINs generated meet the statutory 
goal.\306\ In the NPRM, we requested comments for other default values 
of converted fractions. We received multiple comments suggesting that 
EPA use a conservative default value for cellulosic converted fraction 
that is 80% of the biomethane potential instead of 50% of the 
biomethane potential which we proposed. However, as discussed in more 
detail in the RTC document, the commenters did not provide necessary 
detail or representative data to justify a higher value, nor did they 
explain why the higher value was necessary given the ability to submit 
operational data at registration to establish a higher value. Given 
these factors, we are finalizing as proposed that the conservative 
estimates are 50 percent of the biomethane potential. Additionally, one 
commenter identified a discrepancy between higher heating and lower 
heating values, and we have corrected the default cellulosic converted 
fraction to use higher heating values, consistent with the equations in 
which the value is used.
---------------------------------------------------------------------------

    \303\ Dairy manure value comes from Labatut et al. (2011) 
Bioresource Technology, 102, p. 2255-2264. DOI: 10.1016/
j.biortech.2010.10.035. Swine manure data comes from Vedrenne et al. 
(2008) Bioresource Technology, 99, p. 146-155. DOI: 10.1016/
j.biortech.2006.11.043. Chicken manure data comes from Li et al. 
(2013) Applied Biochemistry Biotechnology 171, p. 117-127. DOI: 
10.1007/s12010-013-0335-7. Municipal sludge data comes from Holliger 
et al. (2017) Frontiers in Energy Research, 5, 12. DOI: 10.3389/
fenrg.2017.00012. Values were converted using the ideal gas law at 
the stated or inferred conditions and 21,496 Btu lower heating value 
methane per lb methane.
    \304\ Holliger et al. (2017) Frontiers in Energy Research, 5, 
12. DOI: 10.3389/fenrg.2017.00012.
    \305\ When designing a gas treatment system, one may use a 
slight overestimate of biogas production to maximize RNG production. 
Overestimating is less of a problem in designing a gas treatment 
system than it is in the RFS program, since overestimating 
production of biogas will lead to invalidly generated RINs.
    \306\ See memo ``Final calculation of cellulosic converted 
fraction values from biochemical methane potential,'' available in 
the docket for this action.
---------------------------------------------------------------------------

    As with other biogas, biogas produced from simultaneously 
converting predominantly cellulosic and non-predominantly cellulosic 
feedstocks is also eligible to be used as renewable CNG/LNG; a 
biointermediate; or other renewable fuel. We are requiring that the 
different D-codes be tracked through PTDs from biogas producers and RNG 
producers, as well as reporting of D-code information into EMTS. Under 
this approach, biogas producers will specify the proportion of biogas 
by D-code on their PTDs. The parties using the biogas to generate RINs 
for RNG (as discussed in Section IX) will use this proportion to 
calculate the appropriate number of D3 and D5 RINs.

D. BBD Conversion Factor for Percentage Standard

    In the 2020-2022 proposed rule, we proposed a change to the 
conversion factor used in the calculation of applicable percentage 
standards for BBD.\307\ We did not finalize that proposed change in the 
2020-2022 final rule. We are now finalizing that change to be 
implemented for compliance years 2023 and beyond, and we are including 
data from 2022 in the determination of the appropriate revised 
conversion factor.
---------------------------------------------------------------------------

    \307\ 86 FR 72474 (December 21, 2021).
---------------------------------------------------------------------------

    In the 2010 RFS2 rule, we determined that because the BBD standard 
was a ``diesel'' standard, its volume must be met on a biodiesel-
equivalent energy basis.\308\ In contrast, the other three standards 
(cellulosic biofuel, advanced biofuel, and total renewable fuel) must 
be met on an ethanol-equivalent energy basis. At that time, biodiesel 
was the only advanced renewable fuel that could be blended into diesel 
fuel, qualified as an advanced biofuel, and was available at greater 
than de minimis quantities.
---------------------------------------------------------------------------

    \308\ See 75 FR 14670, 14682 (March 26, 2010).
---------------------------------------------------------------------------

    When we established the formula for calculating the applicable 
percentage standards for BBD in 2010, the formula needed to accommodate 
the fact that the volume requirement for BBD would be based on 
biodiesel equivalence while the other three volume requirements would 
be based on ethanol equivalence. Given the nested nature of the 
standards, however, RINs representing BBD would also need to be valid 
for complying with the advanced biofuel and total renewable fuel 
standards. To this end, we designed the formula for calculating the 
percentage standard for BBD to include a factor that would convert 
biodiesel volumes into their ethanol equivalent. This factor was the 
same as the Equivalence Value (EqV) for biodiesel, 1.5, as discussed in 
the 2007

[[Page 44546]]

RFS1 final rule.\309\ The resulting formula \310\ (incorporating the 
recent modification to the definitions of GEi and 
DEi) \311\ is shown below:
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    \309\ See 72 FR 23900, 23921 at Table III.B.4-1 (May 1, 2007).
    \310\ See 40 CFR 80.1405(c).
    \311\ See 85 FR 7016 (February 6, 2020).
    [GRAPHIC] [TIFF OMITTED] TR12JY23.004
    
---------------------------------------------------------------------------
Where:

StdBBD,i = The biomass-based diesel standard for year i, 
in percent.
RFVBBD,i = Annual volume of biomass-based diesel required 
by 42 U.S.C. 7545(o)(2)(B) for year i, in gallons.
Gi = Amount of gasoline projected to be used in the 48 
contiguous states and Hawaii, in year i, in gallons.
Di = Amount of diesel projected to be used in the 48 
contiguous states and Hawaii, in year i, in gallons.
RGi = Amount of renewable fuel blended into gasoline that 
is projected to be consumed in the 48 contiguous states and Hawaii, 
in year i, in gallons.
RDi = Amount of renewable fuel blended into diesel that 
is projected to be consumed in the 48 contiguous states and Hawaii, 
in year i, in gallons.
GSi = Amount of gasoline projected to be used in Alaska 
or a U.S. territory, in year i, if the state or territory has opted-
in or opts-in, in gallons.
RGSi = Amount of renewable fuel blended into gasoline that is 
projected to be consumed in Alaska or a U.S. territory, in year i, 
if the state or territory opts-in, in gallons.
DSi = Amount of diesel projected to be used in Alaska or 
a U.S. territory, in year i, if the state or territory has opted-in 
or opts-in, in gallons.
RDSi = Amount of renewable fuel blended into diesel that 
is projected to be consumed in Alaska or a U.S. territory, in year 
i, if the state or territory opts-in, in gallons.
GEi = The total amount of gasoline projected to be exempt 
in year i, in gallons, per Sec. Sec.  80.1441 and 80.1442.
DEi = The total amount of diesel projected to be exempt 
in year i, in gallons, per Sec. Sec.  80.1441 and 80.1442.

    In the years following 2010 when the percentage standard formula 
for BBD was first promulgated, advanced renewable diesel production has 
grown. Most renewable diesel has an EqV of 1.7, and its growing 
presence in the BBD pool means that the average EqV of BBD has also 
grown.\312\
---------------------------------------------------------------------------

    \312\ Under 40 CFR 80.1415(b)(4), renewable diesel with a lower 
heating value of at least 123,500 Btu/gallon is assigned an EqV of 
1.7. A minority of renewable diesel has a lower heating value below 
123,500 BTU/gallon and is therefore assigned an EqV of 1.5 or 1.6 
based on applications submitted under 40 CFR 80.1415(c)(2).
[GRAPHIC] [TIFF OMITTED] TR12JY23.005

    Because the formula currently specified in the regulations for 
calculation of the BBD percentage standard assumes that all BBD used to 
satisfy the BBD standard is biodiesel, it biases the resulting 
percentage standard low, given that in reality there is some renewable 
diesel in BBD. The bias is small, on the order of two percent, and has 
not impacted the supply of BBD since it is the higher advanced biofuel 
standard--rather than the BBD standard--that has driven the demand for 
BBD. Nevertheless, we believe that it is appropriate to modify the 
factor used in the formula to more accurately reflect the amount of 
renewable diesel in the BBD pool.
    The average EqV of BBD appears to have grown over time without 
stabilizing. This trend has continued and is consistent with the growth 
in facilities producing renewable diesel.\313\ We proposed to replace 
the factor of 1.5 in the percentage standard formula for BBD with a 
factor of 1.57 based on the average EqV for BBD in 2021, while also

[[Page 44547]]

noting that ``we believe that the factor used in the formula for 
calculating the percentage standard for BBD should be at least 1.57.'' 
\314\ Commenters were generally supportive of this change, with some 
suggesting the factor should be higher than proposed, and others 
suggesting we should be open to revisiting this factor again in the 
future as renewable diesel production increases. Based on the updated 
data for 2022 shown in Figure X.D-1 showing an average EqV for BBD of 
1.59 in 2022, we now believe that the factor used in the formula for 
calculating the percentage standard for BBD should be at least 1.59. 
However, we also believe that maintaining consistency with the rounding 
protocol adopted for EqVs in 2007 is important. As described in the 
RFS1 rule, all EqVs are rounded to the first decimal place.\315\ 
Applying that rounding protocol here results in factor of 1.6. This is 
slightly higher than the proposed value of 1.57, but is more consistent 
with the additional data for 2022 and application of the aforementioned 
rounding protocol. We are therefore replacing the factor of 1.5 in the 
percentage standard formula for BBD with a factor of 1.6.\316\ Note 
that we are not changing any other aspect of the percentage standard 
formula for BBD.
---------------------------------------------------------------------------

    \313\ See RIA Chapter 5.2.
    \314\ 87 FR 80582, 80686 (December 30, 2022).
    \315\ 72 FR 23921, May 1, 2007.
    \316\ While we are revising the factor of 1.5 in the percentage 
standard formula for BBD, we have included all four of the 
percentage standard formulas in our amendatory text for 40 CFR 
80.1405(c). This is due to the manner in which the original formulas 
were published in the CFR, which does not allow for revisions to a 
single formula without republishing all of the formulas. We are not 
modifying any aspect of these formulas beyond the change to the 
factor of 1.5 in the BBD formula.
---------------------------------------------------------------------------

E. Flexibility for RIN Generation

    We are revising 40 CFR 80.1426 to simplify and clarify the 
requirement that renewable fuel producers and importers may only 
generate RINs if they meet all applicable requirements under the RFS 
program for the generation of RINs. The regulations EPA promulgated in 
the 2010 RFS2 final rule at 40 CFR 80.1426(a)(1), (a)(2), and (b) 
state, in part, that renewable fuel producers ``must'' generate RINs if 
they meet certain requirements, and 40 CFR 80.1426(c), in turn, 
prohibits the generation of RINs if a renewable fuel producer cannot 
demonstrate that they meet the requirements in 40 CFR 80.1426(a)(1), 
(a)(2), and (b). That rule retained the word ``must'' from the RFS1 
regulations but also made it clear that parties cannot generate RINs 
for biofuel if the feedstock used to produce that biofuel does not 
satisfy the renewable biomass requirements or if the renewable fuel 
producer has not met all other applicable requirements, including 
registration, reporting, and recordkeeping requirements.\317\ EPA's 
longstanding interpretation of these regulatory requirements is that 
renewable fuel producers that do not want to generate RINs can choose 
to not register, keep records, or report to EPA. In light of this 
approach, we have determined that a more straightforward approach will 
be to revise the regulations to allow, rather than require, RINs to be 
generated for qualifying renewable fuel. Thus, we are revising 40 CFR 
80.1426(a)(1), (a)(2) and (b) to state that RINs ``may only'' be 
generated if certain requirements are met. We are also removing the 
provisions for small volume renewable fuel producers at 40 CFR 
80.1426(c)(2), (c)(3), and 40 CFR 80.1455 because those provisions are 
no longer necessary. If any renewable fuel producer, regardless of 
size, has the ability to choose to generate RINs, then there is no 
longer a need to provide flexibility for small producers because they 
will only choose to generate RINs if it were economically beneficial to 
do so.
---------------------------------------------------------------------------

    \317\ 40 CFR 80.1426(a)(1)(iii).
---------------------------------------------------------------------------

F. Changes to Tables in 40 CFR 80.1426

    We are making changes to Tables 1 through 4 to 40 CFR 80.1426 in 
order to conform with current guidelines from the Office of Federal 
Register (OFR).\318\ These tables were designated to 40 CFR 80.1426 and 
we refer to them as ``Table 1 to 40 CFR 80.1426,'' ``Table 2 to 40 CFR 
80.1426,'' etc. Under OFR's guidelines, this way of referring to the 
tables meant that they should be located at the very end of 40 CFR 
80.1426. However, Tables 1 and 2 were located after 40 CFR 
80.1426(f)(1)(vi), Table 3 was located in 40 CFR 80.1426(f)(3)(v), and 
Table 4 was located in 40 CFR 80.1426(f)(3)(vi)(A).
---------------------------------------------------------------------------

    \318\ Office of the Federal Register, National Archives and 
Records Administration, ``Document Drafting Handbook,'' August 2018 
Edition (Revision 1.4), January 7, 2022.
---------------------------------------------------------------------------

    In order to conform with OFR's guidelines, we are moving Tables 1 
and 2 to the end of 40 CFR 80.1426, consistent with their current 
designation. Since we are not changing the designations or contents of 
these tables as part of this move, all of the existing references to 
these tables throughout 40 CFR part 80, subpart M, as well as all 
references in existing EPA actions and documents (including Federal 
Register notices, guidance documents, and adjudications) will remain 
accurate and valid. In contrast, for Tables 3 and 4, we are creating 
new provisions within the regulations into which we are moving and 
consolidating the formulas in these tables. Specifically, we are moving 
and consolidating the five formulas previously in Table 3 into 40 CFR 
80.1426(f)(3)(v), and moving and consolidating the five formulas 
previously in Table 4 into 40 CFR 80.1426(f)(3)(vi)(A). The formulas 
themselves remain unchanged and since there are no other references to 
these tables outside of the paragraphs in which they were located, no 
additional revisions are necessary to implement this change.

G. Prohibition on RIN Generation for Fuels Not Used in the Covered 
Location

    We are revising 40 CFR 80.1426(c) and 40 CFR 80.1431 to reiterate 
that parties (e.g., foreign RIN-generating renewable fuel producers and 
importers) cannot generate RINs for renewable fuel unless it was 
produced for use in the covered location. The CAA and RFS regulations 
already limit RIN generation to renewable fuel produced for use in the 
United States, and these amendments are intended to address any 
potential confusion on the part of stakeholders. The amendments specify 
that RINs cannot be generated for renewable fuel that is not produced 
for use in in the covered location and make such RINs invalid. We note 
that it is a prohibited activity under 40 CFR 80.1460(b)(2) to generate 
or transfer invalid RINs, and this revision reinforces that generating 
RINs for fuel not produced for use in the covered location is a 
prohibited activity.

H. Separated Food Waste Recordkeeping Requirements

    Under the CAA, qualifying renewable fuel must be produced from 
renewable biomass.\319\ To ensure that RIN-generating renewable fuels 
satisfy this requirement, RFS regulations contain, among other things, 
recordkeeping provisions that require renewable fuel producers to 
``keep documents associated with feedstock purchases and transfers that 
identify where the feedstocks were produced and are sufficient to 
verify that feedstocks used are renewable biomass if RINs are 
generated.'' \320\ In addition to the generally applicable 
requirements, the RFS regulations also contain provisions for specific 
types of feedstocks where necessary to ensure that their use is 
consistent with the statutory and regulatory definitions of renewable 
biomass.
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    \319\ CAA section 211(o)(1)(J).
    \320\ 40 CFR 80.1454(d).

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[[Page 44548]]

    One such set of feedstock-specific requirements exists for 
separated food waste used to produce renewable fuel. In 2010, EPA 
promulgated a requirement that renewable fuel producers using separated 
food waste submit, at the time of their registration with EPA to 
generate RINs: (1) The location of any facility from which the waste 
stream consisting solely of separated food waste is collected; and (2) 
A separated food waste plan.\321\ However, an unintended effect of 
requiring renewable fuel producers to submit the locations of the 
facilities from which separated food waste was collected as part of 
their facility registration was that producers were required to update 
their information with EPA every time their feedstock suppliers 
changed. EPA recognized this could be burdensome for producers and, in 
2016, proposed to revise the regulations to remove this provision as a 
registration requirement and to simply rely on the corresponding 
recordkeeping requirement.\322\ At that time, we noted that renewable 
fuel producers were also required to retain this information under the 
recordkeeping requirements under 40 CFR 80.1454.\323\
---------------------------------------------------------------------------

    \321\ 40 CFR 80.1450(b)(1)(vii)(B).
    \322\ 81 FR 80828, 80902-03 (November 16, 2016).
    \323\ Id. (``The recordkeeping section of the regulations 
requires renewable fuel producers to keep documents associated with 
feedstock purchases and transfers that identify where the feedstocks 
were produced and are sufficient to verify that the feedstocks meet 
the definition of renewable biomass.'').
---------------------------------------------------------------------------

    In 2020, we finalized the removal of this registration requirement 
and also reiterated that, pursuant to the existing recordkeeping 
provisions at 40 CFR 80.1454(d), renewable fuel producers were still 
required to ``keep documents associated with feedstock purchases and 
transfers that identify where the feedstocks were produced; these 
documents must be sufficient to verify that the feedstocks meet the 
definition of renewable biomass.'' \324\ To emphasize that this 
requirement remained in the regulations in light of removing the 
corresponding registration requirement, we also promulgated a provision 
at 40 CFR 80.1454(j)(1)(ii) requiring renewable fuel producers to keep 
documents demonstrating the location of any establishment from which 
the separated food waste stream is collected.
---------------------------------------------------------------------------

    \324\ 85 FR 7016, 7062 (February 6, 2020).
---------------------------------------------------------------------------

    The Clean Fuels Alliance America challenged EPA's promulgation of 
the separated food waste recordkeeping provision at 40 CFR 
80.1454(j)(1)(ii). Petitioners alleged the requirement that renewable 
fuel producers keep records demonstrating the location of any 
establishment from which separated food waste is collected is arbitrary 
and capricious and that renewable fuel producers ``had no opportunity 
to comment because EPA failed to mention this new recordkeeping 
requirement in the proposed rule.'' \325\
---------------------------------------------------------------------------

    \325\ RFS Power Coalition v. U.S. EPA, No. 20-1046 (D.C. Cir.), 
Doc. # 1882940 at 38-39, filed Jan. 29, 2021.
---------------------------------------------------------------------------

    In the proposal for this action, we emphasized that 40 CFR 
80.1454(d), which was introduced in 2010, requires renewable fuel 
producers to keep records associated with feedstock purchases and 
transfers that identify where the feedstocks were produced and are 
sufficient to verify that feedstocks used are renewable biomass. 
However, recognizing that affected stakeholders may have had 
suggestions for how to better apply this requirement specifically to 
separated food waste feedstocks, we sought comment on the separated 
food waste-specific recordkeeping requirement in 40 CFR 
80.1454(j)(1)(ii).\326\ In particular, we sought comment on how 
renewable fuel producers using separated food waste as feedstocks could 
best implement, in a manner consistent with standard business practices 
within the industry, the requirement to keep records demonstrating 
where their feedstocks were produced and that the records would be 
sufficient to verify that the feedstocks meet the definition of 
renewable biomass. Based on previous discussions with third party 
feedstock suppliers, independent auditors, and renewable fuel producers 
we did not propose to modify the provisions of 40 CFR 80.1454. After 
review and consideration of the comments received on this action, we 
are not finalizing any of the modifications to the language from those 
comments. However, we are finalizing the alternative approach that we 
did propose with modifications based on the comments we received as 
described below.
---------------------------------------------------------------------------

    \326\ We are not reopening the requirement at 40 CFR 80.1454(d).
---------------------------------------------------------------------------

    We understand there is a desire for independent auditors to play a 
role in satisfying the requirement that renewable fuel producers keep 
records demonstrating the location of any establishment from which 
separate food waste is collected. Specifically, stakeholders have 
requested that, rather than renewable fuel producers holding the 
records themselves, independent auditors be allowed to verify the 
records directly from the feedstock aggregator. While the regulations 
require the renewable fuel producer to keep the records on the 
feedstock source and amount as specified under 40 CFR 80.1454(j), as 
further explained below, we are providing an option to allow 
independent auditors to verify records held by the feedstock aggregator 
by leveraging the biointermediates provisions of the RFS program. While 
most interest in this provision centers around used cooking oil 
collection, we believe this option can also be useful to third-party 
collectors of separated yard waste, separated food waste, and separated 
municipal solid waste.
    Under the new option, instead of the renewable fuel producers 
holding records demonstrating that the feedstock used to produce 
renewable fuel is renewable biomass, feedstock aggregators may hold 
them provided that alternative regulatory requirements for the 
renewable fuel producer and feedstock aggregator are met. The 
alternative requirements needed to be met are summarized as follows:
     The feedstock aggregator will need to register with EPA 
and must keep all applicable records of feedstock collection.
     The renewable fuel producer will need to participate in 
the QAP program.
     PTDs will need to be supplied to the transferee for 
feedstocks after leaving the feedstock aggregator that include the 
volume, date, location at time of transfer, and transferor and 
transferee information.
    The feedstock aggregator and the renewable fuel producer that 
processes those feedstocks will also be subject to the same liability 
provisions that apply to biointermediate producers and renewable fuel 
producers that process biointermediates. We note that under the RFS 
program, other than the limited alternative that we are finalizing in 
this action, renewable fuel producers must keep records to demonstrate 
that their renewable fuels are produced from renewable biomass as 
specified under 40 CFR 80.1454, as applicable. We are finalizing the 
alternative approach to address the specific circumstance where it is 
impractical for renewable fuel producers to provide the records 
specified under the recordkeeping requirements. We also note that if 
the records do not demonstrate the feedstock is renewable biomass, then 
the recordkeeping requirement is not met regardless of who is holding 
the records.
    We received comments that having both the renewable fuel producer 
and feedstock aggregator be subject to QAP would be overly burdensome. 
We did not intend to have the feedstock aggregator directly participate 
in the QAP program like a biointermediate

[[Page 44549]]

producer as proposed in the NRPM, and we recognize that imposing direct 
participation of the feedstock aggregator could significantly increase 
the burden associated with the proposed option on feedstock 
aggregators. Based on these comments, we are requiring that only the 
renewable fuel producer needs to participate in the QAP program 
(instead of the proposed requirement to have the aggregator also 
participate). To ensure adequate oversight, we are also requiring that 
the QAP plan include a description of how the third-party auditor will 
audit each feedstock aggregator.
    We also received comments asking for clarity regarding which 
obligations apply to feedstock suppliers versus feedstock aggregators. 
We intended the regulations to cover feedstock aggregators, not 
feedstock suppliers. We have clarified this in the regulations by 
updating the language and adding new definitions for feedstock 
aggregator and feedstock supplier.
    Some commenters inquired about third parties holding records on 
behalf of the feedstock renewable fuel producer.\327\ Under EPA's fuels 
programs, which includes the RFS program, we do not specify how parties 
must employ persons to fulfill their regulatory burdens so long as the 
specified party meets all applicable regulatory requirements. We 
believe that a party may arrange for a contractor to perform actions 
that meet regulatory requirements (e.g., taking samples, analyzing 
samples, and reporting results to EPA) so long as that contractor 
adheres to the regulatory requirements, is acting on behalf of the 
regulated party, and the party understands that they will remain liable 
for ensuring the applicable regulatory requirements have been met. We 
believe this same arrangement is allowed for the separated food waste 
recordkeeping requirements. We want to reiterate, however, that the 
regulated party is liable for meeting the CAA and regulatory 
requirements and for any action of any party working on their behalf, 
whether it is a contractor, subcontractor, or other entity. The 
renewable fuel producer must make or arrange for the records to be made 
available to EPA upon request consistent with the regulatory 
requirements at 40 CFR 80.1454(t). Since the parties that are 
completing work on behalf of the regulated party are not independent of 
the company, they do not meet the independence requirements for QAP 
auditors or attest auditors, so they cannot audit the company in these 
roles. With the important conditions described here, we believe EPA's 
acceptance of contractors to conduct work on behalf of regulated 
parties addresses the commenters request to describe more clearly the 
circumstances when a contractor may hold the required feedstock records 
on behalf of a renewable fuel producer.
---------------------------------------------------------------------------

    \327\ Commenters recommended this in part because they would 
like to use third-party tracking software to manage the collection 
and disclosure of data.
---------------------------------------------------------------------------

    Since the feedstock aggregators are not substantially altering the 
feedstock before transferring the feedstock, we believe fewer 
requirements are necessary than for biointermediates to provide 
sufficient oversight of the feedstock and renewable fuel production 
process. Specifically, we are not requiring that the feedstock 
aggregator supply an engineering review, separated food waste plan, 
separated yard waste plan, or separated MSW plan as a part of 
registration. However, the renewable fuel producer will still need to 
supply these documents as part of their registration. In addition, the 
feedstock is not considered a biointermediate, so the feedstock 
aggregator can sell feedstock to a biointermediate producer, which 
could then sell a biointermediate to a renewable fuel facility.

I. Definition of Ocean-Going Vessels

    We are revising the definition of ``fuel used in ocean-going 
vessels'' as proposed with slight modification to ensure that obligated 
parties include diesel fuel in their RVOs in a consistent manner and as 
required by the CAA and so that renewable fuel producers know which 
fuels used in marine applications are eligible for RIN generation.
    Fuel used in ocean-going vessels is explicitly excluded from the 
CAA's definition of ``transportation fuel,'' \328\ and does not need to 
be included in RVO calculations.\329\ Relatedly, renewable fuel 
producers cannot generate RINs on renewable fuel used in ocean-going 
vessel because such fuel is not considered transportation fuel.\330\ 
The RFS regulations defined the term ``[f]uel for use in an ocean-going 
vessel'' to mean: ``(1) any marine residual fuel (whether burned in 
ocean waters, Great Lakes, or other internal waters); (2) Emission 
Control Area (ECA) marine fuel, pursuant to Sec.  80.2 and 40 CFR 
1090.80 (whether burned in ocean waters, Great Lakes, or other internal 
waters); and (3) Any other fuel intended for use only in ocean-going 
vessels.'' \331\ The term ``ocean-going vessels'' referenced in sub-
prong (3), however, was not further defined in the regulations.
---------------------------------------------------------------------------

    \328\ CAA section 211(o)(1)(L).
    \329\ 40 CFR 80.1407(f)(8).
    \330\ 40 CFR 80.1426(a)(1)(iv).
    \331\ 40 CFR 80.1401.
---------------------------------------------------------------------------

    In the RFS2 final rule, we stated that EISA specifies that 
``transportation fuels'' do not include fuels for use in ocean-going 
vessels and that we were interpreting that ``fuels for use in ocean-
going vessels'' means residual or distillate fuels other than motor 
vehicle, nonroad, locomotive, or marine diesel fuel (MVNRLM) intended 
to be used to power large ocean-going vessels (e.g., those vessels that 
are powered by Category 3 (C3), and some Category 2 (C2), marine 
engines and that operate internationally).\332\ This statement made 
clear that vessels powered by C3 marine engines are ocean-going vessels 
and that fuel supplied to those vessels does not need to be included in 
obligated parties' RVO calculations.
---------------------------------------------------------------------------

    \332\ 75 FR 14670, 14721 (March 26, 2010).
---------------------------------------------------------------------------

    We further explained the reference to ``and some Category (C2) 
marine engines'' in the RFS2 RTC document, in which we noted that while 
Category 1 (C1) and C2 engines are generally required to use MVNLRM 
diesel fuel (i.e., transportation fuel), we had, at the time, recently 
established new standards for C3 marine engines that allowed C1 and C2 
auxiliary engines equipped on vessels powered by C3 marine engines to 
utilize fuels other than MVNRLM diesel fuel.\333\ We noted further that 
this could result in a vessel carrying three fuels: MVNRLM, ECA marine 
fuel, and residual fuels, and the latter two would not be considered 
transportation fuel under the program. In other words, the reference to 
``and some Category (C2) marine engines'' in the RFS2 final rule refers 
to auxiliary engines equipped on vessels that are primarily powered by 
C3 marine engines.
---------------------------------------------------------------------------

    \333\ U.S. EPA, Renewable Fuel Standards Program (RFS2) Summary 
and Analysis of Comments, at 3-198-3-200. (February 2010).
---------------------------------------------------------------------------

    Since the RFS2 regulations were promulgated, we have received 
several questions from the regulated community on the subject of what 
constitutes an ocean-going vessel, and what fuel must be included in 
obligated parties' RVO calculations. To address this, we proposed to 
define ocean-going vessels as ``vessels that are primarily (i.e., >=75 
percent) propelled by engines meeting the definition of `Category 3' in 
40 CFR 1042.901.'' In other words, if a vessel is primarily propelled 
by C3 marine engines, it is an ocean-going vessel. Further, fuel used 
in Category 1 (C1) and Category 2 (C2) auxiliary engines installed on 
ocean-going vessels--which

[[Page 44550]]

are often used for purposes other than propulsion--do not need to be 
included in obligated parties' RVO calculations because the inquiry 
turns on the type of engine that primarily propels the vessel, not the 
actual engines that use the fuel. On the other hand, if a vessel is 
primarily propelled by C1 or C2 marine engines, they are not ocean-
going vessels regardless of whether those vessels operate on 
international waters, and fuel supplied to these vessels must be 
included in obligated parties' RVO calculations.
    We received one comment on the proposed definition of ``ocean-going 
vessel.'' The commentor stated that is unclear from the proposed 
definition how an obligated party supplying marine fuel would have 
knowledge about the percentage of propulsion provided by a vessel's 
various Category 1, 2, or 3 engines. As explained in the NPRM, 
auxiliary engines equipped on large ocean-going vessels are typically 
used for purposes other than propulsion (e.g., electricity generation). 
Auxiliary engines, however, can be used for propulsion in emergencies, 
which is why the proposed definition was based on the primary type of 
engine used to propel a vessel. However, if a vessel is equipped with a 
Category 3 engine it can be assumed that the vessel will primarily use 
that engine for propulsion because it would not be practical or 
economical to propel that vessel primarily with smaller engines. 
Therefore, we are finalizing a modified definition of ocean-going 
vessel that is consistent with the intent of the proposed definition 
that turns exclusively on whether the vessel is equipped with a 
Category 3 engine. Specifically, we are defining ocean-going vessels as 
``vessels that are equipped with engines meeting the definition of 
`Category 3' in 40 CFR 1042.901.''
    We are also revising the definitions of MVNRLM diesel fuel and ECA 
marine fuel to be consistent with the flexibilities that allow for the 
exclusion of certified NTDF from refiners' RVOs \334\ and the 
flexibilities to certify diesel fuel for multiple purposes as allowed 
under EPA's fuel quality regulations.\335\ Specifically, we are 
removing the restriction that fuel that meets the requirements of 
MVNRLM diesel fuel cannot be ECA marine fuel, as this exclusion 
conflicts with the designation provisions in 40 CFR part 1090.\336\
---------------------------------------------------------------------------

    \334\ 40 CFR 80.1407(f)(11).
    \335\ 40 CFR 1090.1015(a).
    \336\ We note that we are not changing the treatment of 
certified NTDF under the RFS program in this action.
---------------------------------------------------------------------------

    The previous definitions for MVNRLM diesel fuel and ECA marine fuel 
excluded fuel that conforms to the requirements of MVNRLM diesel fuel 
from the definition of ECA marine fuel, without regard to its actual 
use. Under this language, obligated parties who produced 15 ppm diesel 
fuel had to include the designated MVNRLM diesel fuel in their RVO 
calculations even if the fuel was designated and used as ECA marine 
fuel. In the 2020 annual rule, we intended that obligated parties could 
use the certified NTDF provisions to exclude ECA marine fuel used in 
ocean-going vessels but did not revise the definitions of MVNRLM diesel 
fuel and ECA marine fuel consistent with our intent. In this action, we 
are amending the definitions of MVNRLM diesel fuel and ECA marine fuel 
to clarify that 15 ppm distillate fuel that is properly designated as 
certified NTDF may also be designated as ECA marine fuel and excluded 
from a producer or importer's RVO calculations.

J. Bond Requirement for Foreign RIN-Generating Renewable Fuel Producers 
and Foreign RIN Owners

    We are finalizing two changes to the bonding requirements for 
foreign RIN-generating renewable fuel producers and foreign RIN owners. 
First, we are increasing the amount of the foreign bond amount from 
$0.01 to $0.22 per RIN. The bond requirement previously applicable to 
foreign RIN-generating renewable fuel producers and foreign RIN owners 
was developed in the RFS1 rule to deter noncompliance and to assist 
with the collection of any judgments that result from a foreign RIN-
generating renewable fuel producer's noncompliance with the RFS 
regulations.\337\ In that rulemaking, the bond was set to $0.01 per 
RIN, when the expected value of RINs was much lower. Since 2013, RIN 
prices have hovered significantly above $0.01, and recently, RINs in 
all categories have consistently sold above $1.00 per RIN.\338\ As 
explained in the 2023-2025 NPRM, the increased value of RINs makes a 
bond requirement of $0.01 per RIN neither sufficient to deter potential 
noncompliance nor likely to yield bonds of sufficient size to satisfy 
judicial or administrative judgments against foreign RIN-generating 
renewable fuel producers or foreign RIN owners. For these reasons, we 
are raising the bond requirement to more accurately reflect the current 
value of RINs, so that bonds can serve their intended purposes. While 
we had proposed raising the bond requirement to $0.30 per RIN--which 
was 10 percent of the price of a D3 RIN at the time of the proposal--
after considering the comments received, we have re-calculated the 
amount to $0.22 per RIN, which is 10 percent of the average price of a 
D3 RIN for the most recent, full five-year period (2018-2022).\339\ 
This approach accounts for recent fluctuations in price over a longer 
and representative time period.
---------------------------------------------------------------------------

    \337\ 72 FR 24007 (May 1, 2007).
    \338\ See RFS pricing data available at: https://www.epa.gov/fuels-registration-reporting-and-compliance-help/rin-trades-and-price-information.
    \339\ We selected average D3 RIN prices over the previous five 
years to smooth out fluctuations in RIN prices over time. We did not 
base our bond amount on projected RIN prices because estimating 
future RIN prices involves a lot of uncertainty and would not 
necessarily provide a more appropriate bond price. We pegged our 
bond prices to D3 RINs because D3 RINs have historically been the 
most valuable, and the purpose of the change is to ensure that bond 
prices serve as a sufficient deterrent to non-compliance by foreign 
parties. Pegging the price to a less valuable RIN would erode the 
efficacy of the deterrent. We chose 10 percent because we believed a 
higher percentage may be too costly for foreign RIN generators/
owners to participate in the program. Percentages lower than 10 
percent would have resulted in an insufficient deterrent against 
non-compliance.
---------------------------------------------------------------------------

    Second, we are removing the option to make a direct payment to the 
U.S. Treasury under 40 CFR 80.1466(h) and are adopting the surety bond 
as the sole method to fulfill the foreign bond requirement. We have 
considered a variety of options used by other EPA programs and by other 
Federal agencies, including examining the financial assurance methods 
used by EPA for the Resource Conservation and Recovery Act (RCRA) and 
for the Transition Program for Equipment Manufacturers (TPEM) program. 
We also considered approaches used by other federal agencies, such as 
the Alcohol and Tobacco Trade Board (TTB) brewer's bonds, including 
surety and collateral (``cash'') bonds. Our inquiry led us to conclude 
that alternative approaches either do not work with the RFS program or 
are too burdensome to implement, and that the surety bond approach is 
the most appropriate and workable for the RFS program.
    The effective date for the new bonding provisions will be April 1, 
2024. We are giving a later effective date because we appreciate that 
parties may need this additional time to come into compliance with 
these new bonding requirements.

[[Page 44551]]

K. Definition of Produced From Renewable Biomass

    We are not finalizing at this time a definition of produced from 
renewable biomass or the related amendments to the regulatory 
provisions related to co-processed fuels. CAA section 211(o)(1)(J) 
defines renewable fuel as ``fuel that is produced from renewable 
biomass and that is used to replace or reduce the quantity of fossil 
fuel present in a transportation fuel.'' \340\ However, neither the CAA 
nor EPA regulations define what it means for a fuel to be produced from 
renewable biomass. In the 2020-2022 NPRM, we proposed to define in 40 
CFR 80.1401 that ``produced from renewable biomass'' means the energy 
in the finished fuel comes from renewable biomass. After reviewing 
comments on that proposal, we decided not to finalize a definition for 
``produced from renewable biomass'' in that action. In the 2023-2025 
NPRM, we re-proposed the definition of ``produced from renewable 
biomass'' again based on the energy content approach that was in the 
2020-2022 NPRM. We also sought comment on alternative definitions and 
ways that renewable fuel producers could demonstrate that the fuel they 
produce meets this statutory requirement. These included both a ``mass-
based'' definition where the mass in the finished fuel comes from the 
renewable biomass, as well as a ``broad'' approach whereby either the 
energy or the mass could come from the renewable biomass.
---------------------------------------------------------------------------

    \340\ CAA section 211(o)(2)(A)(i) adds the requirement that 
renewable fuel must have ``lifecycle [GHG] emissions that are at 
least 20 percent less than baseline lifecycle [GHG] emissions'' 
(unless exempted under the statutory grandfather provision as 
implemented in 40 CFR 80.1403).
---------------------------------------------------------------------------

    We received near universal support from stakeholders in comment on 
the proposal for the broad approach. In order to allow us more time to 
fully consider the comments received, as well as to determine what 
would be needed to implement such a broad approach, we are not 
finalizing a definition of ``produced from renewable biomass'' in this 
action. Nevertheless, we still believe a definition of ``produced from 
renewable biomass'' would be useful because we have received multiple 
questions from stakeholders on this aspect of the renewable fuel 
definition. Clarifying what it means for a fuel to be produced from 
renewable biomass will reduce confusion on this issue and avoid a 
situation where a party expends resources on researching or developing 
a new fuel technology with the hopes of generating RINs only to later 
discover that the fuel does not qualify as having been produced from 
renewable biomass.
    Given that we are not finalizing this definition in this action, we 
are also not finalizing the proposed changes to corresponding 
regulations in 80.1426(f)(4) nor are we finalizing the proposed changes 
to the definition of co-processed fuel or co-processed intermediate.

L. Technical Amendments

    We are making numerous technical amendments to the RFS and fuel 
quality regulations. These amendments are being made to correct minor 
inaccuracies and clarify the current regulations. These changes are 
described in Table X.L-1.

 Table X.L-1--Miscellaneous Technical Corrections and Clarifications to
                    RFS and Fuel Quality Regulations
------------------------------------------------------------------------
 Part and section of Title 40           Description of revision
------------------------------------------------------------------------
80.2.........................  Adding definition of business days
                                consistent with the definition at 40 CFR
                                1090.80.
80.2.........................  Clarifying the definition of renewable
                                fuel to specify that fuel must be used
                                in the covered location.
80.4; 80.7; 80,11; 80.1415;    Removing all references to ``the
 80.1416; 80.1426; 80.1431;     Administrator'' and replacing them with
 80.1441; 80.1443; 80.1449      ``EPA.''
 through 80.1454; 80.1456;
 80.1466; 80.1467; 80.1469;
 80.1474; and 80.1478.
80.2, 80.1408, and 1090.1015.  Amending the definition of certified non-
                                transportation distillate fuel (NTDF) at
                                40 CFR 80.2 and the diesel fuel
                                designation requirements under 40 CFR
                                1090.1015 to clarify that the certified
                                NTDF provisions at 40 CFR 80.1408 may be
                                used for NTDF other than heating oil or
                                ECA marine fuel.
80.2 and 80.1453(a)(12)......  Clarifying that renewable naphtha may be
                                blended to make E85.
80.1450(b)(1)(viii)(E).......  Clarifying that independent third-party
                                engineers must visit material recovery
                                facilities as part of the engineering
                                review for facilities that produce
                                renewable fuels from separated MSW.
80.1469(c)(6)................  Clarifying that independent third-party
                                auditors must review all relevant
                                documentation required under the RFS
                                program when verifying elements under
                                the QAP program.
1090.55(c)...................  Amending to correct cross-reference from
                                40 CFR part 32 to 2 CFR part 1532.
1090.80......................  Amending to correct the list of states
                                that are part of PADD II.
1090.805(a)(1)(iv)...........  Clarifying that RCOs may add a delegate,
                                as allowed under 1090.800(d).
1090.1830(a)(3)..............  Amending to add a missing word.
------------------------------------------------------------------------

XI. Statutory and Executive Order Reviews

    Additional information about these statutes and Executive Orders 
can be found at https://www.epa.gov/laws-regulations/laws-and-executive-orders.

A. Executive Order 12866: Regulatory Planning and Review and Executive 
Order 13563: Improving Regulation and Regulatory Review

    Under section 3(f)(1) of Executive Order 12866, as amended by 
Executive Order 14094, this action is a significant regulatory action 
that was submitted to the Office of Management and Budget (OMB) for 
review. Any changes made in response to suggestions or recommendations 
received as part of the Executive Order 12866 review process have been 
documented in the docket. EPA prepared an analysis of potential costs 
and benefits associated with this action. This analysis is presented in 
the RIA, available in the docket for this action.

B. Paperwork Reduction Act (PRA)

    The information collection activities in this rule have been 
submitted for

[[Page 44552]]

approval to the Office of Management and Budget (OMB) under the PRA. 
The Information Collection Request (ICR) document that EPA prepared has 
been assigned EPA ICR number 2722.02. You can find a copy of the ICR in 
the docket for this rule, and it is briefly summarized here. The 
information collection requirements are not enforceable until OMB 
approves them.
    We are finalizing compliance provisions necessary to ensure that 
the production, distribution, and use of biogas, RNG, and RINs are 
consistent with Clean Air Act requirements under the RFS program. These 
compliance provisions include registration, reporting, product transfer 
documents (PTDs), and recordkeeping requirements. The information 
requirements are under 40 CFR part 80, subparts E and M, and 40 CFR 
part 1090. Interested parties may wish to review the following related 
ICRs: Fuels Regulatory Streamlining (Final Rule), OMB Control Number 
2060-0731, expires January 31, 2024; Renewable Fuel Standard (RFS) 
Program: RFS Final Rules, OMB Control No. 2060-0740, expires October 
31, 2025; and Renewable Fuel Standard (RFS) Program (Renewal), OMB 
Control Number 2060-0725, expires November 30, 2025.
    Respondents/affected entities: Biogas producers; RNG producers; RNG 
importers; biogas closed-distribution RIN generators; QAP providers; 
RIN separators; parties including renewable fuel producers, 
biointermediate producers, or feedstock aggregators who use alternative 
recordkeeping under 80.1479; producers of renewable fuel from biogas 
used as a biointermediate or RNG used as a feedstock; and third 
parties, including third-party engineers and attest auditors.
    Respondent's obligation to respond: Mandatory, under 40 CFR parts 
80 and 1090.
    Estimated number of respondents: 7,835.
    Frequency of response: On occasion, monthly, quarterly, or 
annually.
    Total estimated burden: 82,441 hours (per year). Burden is defined 
at 5 CFR 1320.3(b).
    Total estimated cost: $5,684,472 (per year), of which $5,659,472 is 
purchased services, and which includes $25,000 annualized capital or 
operation & maintenance costs.
    An agency may not conduct or sponsor, and a person is not required 
to respond to, a collection of information unless it displays a 
currently valid OMB control number. The OMB control numbers for EPA's 
regulations in 40 CFR are listed in 40 CFR part 9. When OMB approves 
this ICR, EPA will announce that approval in the Federal Register and 
publish a technical amendment to 40 CFR part 9 to display the OMB 
control number for the approved information collection activities 
contained in this final rule.

C. Regulatory Flexibility Act (RFA)

    I certify that this action will not have a significant economic 
impact on a substantial number of small entities under the RFA.
    For the biogas regulatory reform provisions, we are modifying the 
previous biogas provisions to make compliance less burdensome for 
regulated parties. With respect to the other amendments to the RFS and 
fuel quality regulations, this action makes minor corrections and 
modifications to those regulations. As such, we do not anticipate that 
there will be any significant adverse economic impact on directly 
regulated small entities as a result of these revisions.
    The small entities directly regulated by the annual percentage 
standards associated with the RFS volumes are small refiners that 
produce gasoline or diesel fuel, which are defined by the Small 
Business Administration (SBA) at 13 CFR 121.201. To evaluate the 
impacts of the 2023-2025 volume requirements on small entities, we have 
conducted a screening analysis \341\ to assess whether we should make a 
finding that this action will not have a significant economic impact on 
a substantial number of small entities. Currently available information 
shows that the impact on small entities from implementation of this 
rule will not be significant. We have reviewed and assessed the 
available information, which shows that obligated parties, including 
small entities, are able to recover the cost of acquiring the RINs 
necessary for compliance with the RFS standards through higher sales 
prices of the petroleum products they sell than would be expected in 
the absence of the RFS program.\342\ This is true whether they acquire 
RINs by purchasing renewable fuels with attached RINs or purchasing 
separated RINs. The costs of the RFS program are thus being passed on 
to consumers in a highly competitive marketplace.
---------------------------------------------------------------------------

    \341\ See RIA Chapter 11.
    \342\ For a further discussion of the ability of obligated 
parties--including small refiners--to recover the cost of RINs, see 
April 2022 SRE Denial Action and June 2022 SRE Denial Action.
---------------------------------------------------------------------------

    While the rule will not have a significant economic impact on a 
substantial number of small entities, there are existing compliance 
flexibilities in the program that are available to small entities. 
These flexibilities include being able to comply through RIN trading 
rather than renewable fuel blending, 20 percent RIN rollover allowance 
(up to 20 percent of an obligated party's RVO can be met using 
previous-year RINs), and deficit carry-forward (the ability to carry 
over a deficit from a given year into the following year, provided that 
the deficit is satisfied together with the next year's RVO). In the 
2010 RFS2 final rule, we discussed other potential small entity 
flexibilities that had been suggested by the Small Business Regulatory 
Enforcement Fairness Act (SBREFA) panel or through comments, but we did 
not adopt them, in part because we had serious concerns regarding our 
authority to do so.\343\
---------------------------------------------------------------------------

    \343\ 75 FR 14858-62 (March 26, 2010).
---------------------------------------------------------------------------

    In sum, this rule will not change the compliance flexibilities 
currently offered to small entities under the RFS program and available 
information shows that the impact on small entities from implementation 
of this rule will not be significant.

D. Unfunded Mandates Reform Act (UMRA)

    This action does not contain an unfunded mandate of $100 million or 
more as described in UMRA, 2 U.S.C. 1531-1538, for state, local, or 
tribal governments. This action imposes no enforceable duty on any 
state, local or tribal governments. This action contains a federal 
mandate under UMRA that may result in expenditures of $100 million or 
more for the private sector in any one year. Accordingly, the costs 
associated with this rule are discussed in Section IV and in the RIA.
    This action is not subject to the requirements of section 203 of 
UMRA because it contains no regulatory requirements that might 
significantly or uniquely affect small governments.

E. Executive Order 13132: Federalism

    This action does not have federalism implications. It will not have 
substantial direct effects on the states, on the relationship between 
the National Government and the states, or on the distribution of power 
and responsibilities among the various levels of government.

F. Executive Order 13175: Consultation and Coordination With Indian 
Tribal Governments

    This action does not have tribal implications as specified in 
Executive Order 13175. This action will be implemented at the Federal 
level and affects transportation fuel refiners,

[[Page 44553]]

blenders, marketers, distributors, importers, exporters, and renewable 
fuel producers and importers. Tribal governments will be affected only 
to the extent they produce, purchase, or use regulated fuels. Thus, 
Executive Order 13175 does not apply to this action.

G. Executive Order 13045: Protection of Children From Environmental 
Health Risks and Safety Risks

    This action is subject to Executive Order 13045 because it is a 
significant regulatory action under section 3(f)(1) of Executive Order 
12866, and EPA believes that the environmental health or safety risks 
of the pollutants impacted by this action may have a disproportionate 
effect on children. The 2021 Policy on Children's Health also applies 
to this action.\344\
---------------------------------------------------------------------------

    \344\ U.S. Environmental Protection Agency (2021). 2021 Policy 
on Children's Health. Washington, DC. https://www.epa.gov/system/files/documents/2021-10/2021-policy-on-childrens-health.pdf.
---------------------------------------------------------------------------

    Children make up a substantial fraction of the U.S. population, and 
often have unique factors that contribute to their increased risk of 
experiencing a health effect from exposures to ambient air pollutants 
because of their continuous growth and development. Children are more 
susceptible than adults to many air pollutants because they have: (1) A 
developing respiratory system; (2) Increased ventilation rates relative 
to body mass compared with adults; (3) An increased proportion of oral 
breathing, particularly in boys, relative to adults; and (4) Behaviors 
that increase chances for exposure. Even before birth, the developing 
fetus may be exposed to air pollutants through the mother that affect 
development and permanently harm the individual when the mother is 
exposed. Certain motor vehicle emissions present greater risks to 
children as well. Early life stages (e.g., children) are thought to be 
more susceptible to tumor development than adults when exposed to 
carcinogenic chemicals that act through a mutagenic mode of 
action.\345\ Exposure at a young age to these carcinogens could lead to 
a higher risk of developing cancer later in life.
---------------------------------------------------------------------------

    \345\ U.S. Environmental Protection Agency. (2005). Supplemental 
guidance for assessing susceptibility from early-life exposure to 
carcinogens. Washington, DC: Risk Assessment Forum. EPA/630/R-03/
003F. https://www.epa.gov/sites/default/files/2013-09/documents/childrens_supplement_final.pdf.
---------------------------------------------------------------------------

    The biofuel volumes associated with this rulemaking may reduce 
GHGs, potentially mitigating the impacts of climate change on children. 
Because children have greater susceptibility to the impacts of a 
changing climate, as referenced in RIA Chapter 9.6, these standards 
could have particular benefits for children's health.\346\ As discussed 
in RIA Chapter 4, the biofuel volumes associated with the rulemaking 
may also impact other air pollutant emissions both positively and 
negatively. Because of their greater susceptibility to air pollution 
and their increased time spent outdoors these standards could also have 
more pronounced impacts on children's health.
---------------------------------------------------------------------------

    \346\ The Impacts of Climate Change on Human Health in the 
United States: A Scientific Assessment, USGCRP 2016.
---------------------------------------------------------------------------

H. Executive Order 13211: Actions Concerning Regulations That 
Significantly Affect Energy Supply, Distribution, or Use

    This action is not a ``significant energy action'' because it is 
not likely to have a significant adverse effect on the supply, 
distribution, or use of energy. This action establishes the required 
renewable fuel content of the transportation fuel supply for 2023, 
2024, and 2025 pursuant to the CAA. The RFS program and this rule are 
designed to achieve positive effects on the nation's transportation 
fuel supply by increasing energy independence and security.

I. National Technology Transfer and Advancement Act (NTTAA) and 1 CFR 
Part 51

    This action involves technical standards. In accordance with the 
requirements of 1 CFR 51.5, we are incorporating by reference the use 
of test methods and standards from the American Petroleum Institute 
(API), American Public Health Association (APHA), ASTM International 
(ASTM), and European Committee for Standardization (CEN). A detailed 
discussion of these test methods and standards can be found in Sections 
IX.I and X.C. The standards and test methods referenced in this action 
may be obtained through the following avenues:
    For API standards, copies of these materials may be obtained from 
the API website (www.api.org) or by calling API at (202) 682-8000. API 
standards referenced in this rule are also available for public review 
in read-only format in the API IBR Reading Room at 
publications.api.org.
    For APHA standards, copies of these materials may be obtained from 
the standard methods website (www.standardmethods.org) or by calling 
APHA at (202) 777-2742.
    For ASTM standards, copies of these materials may be obtained from 
the ASTM website (www.astm.org) or by calling ASTM at (877) 909-2786. 
ASTM standards referenced in this rule are also available for public 
review in read-only format in the ASTM Reading Room at www.astm.org/epa.htm.
    For CEN standards, copies of these materials may be obtained from 
the CEN website (www.cencenelec.eu) or by calling CEN at + 32 2 550 08 
11.
    To meet the Office of the Federal Register requirements for 
incorporation by reference structure and formatting requirements, EPA 
is moving the centralized IBR section (Sec.  80.1468, which applies to 
all of part 80) out of subpart M and into subpart A (which also applies 
to all of part 80). EPA is also adding standards that were approved for 
Sec.  80.8 but never consolidated in the original centralized IBR 
section into the new centralized section at Sec.  80.12.
    In addition to the standards and test methods listed below, ASTM 
D1250, ASTM D4442, ASTM D4444, ASTM D6866, and ASTM E870 are also 
referenced in the regulatory text of this final rule. They were 
approved for IBR for the sections referenced as of July 1, 2022, and no 
changes are being made aside from those described to the centralized 
IBR section. ASTM D4057, ASTM D4177, ASTM D5842, and ASTM D5854 are 
also referenced in the regulatory text of this final rule. They were 
approved for IBR for the sections referenced as of April 28, 2014, and 
no changes are being made aside from those described to the centralized 
IBR section. ASTM E711 is also referenced in the regulatory text of 
this final rule. It was approved for IBR for the section referenced as 
of July 1, 2010, and no changes are being made aside from those 
described to the centralized IBR section.

[[Page 44554]]

Table XI.I-1--Standards and Test Methods To Be Incorporated by Reference
------------------------------------------------------------------------
   Organization and standard or test
                 method                            Description
------------------------------------------------------------------------
API MPMS 14.1-2016, Manual of Petroleum  Standard describing how to
 Measurement Standards Chapter 14--       collect, handle, and transfer
 Natural Gas Fluids Measurement Section   gas samples for chemical
 1--Collecting and Handling of Natural    analysis.
 Gas Samples for Custody Transfer, 7th
 Edition, May 2016.
API MPMS 14.3.1-2012, Manual of          Standard describing engineering
 Petroleum Measurement Standards          equations, installation
 Chapter 14.3.1--Orifice Metering of      requirements, and uncertainty
 Natural Gas and Other Related            estimations of square-edged
 Hydrocarbon Fluids--Concentric,          orifice meters in measuring
 Square[hyphen]edged Orifice Meters       the flow of natural gas and
 Part 1: General Equations and            similar fluids.
 Uncertainty Guidelines, 4th Edition,
 including Errata July 2013,
 Reaffirmed, July 2022.
API MPMS 14.3.2-2016, Manual of          Standard describing design and
 Petroleum Measurement Standards          installation of square-edged
 Chapter 14.3.2--Orifice Metering of      orifice meters for measuring
 Natural Gas and Other Related            flow of natural gas and
 Hydrocarbon Fluids--Concentric,          similar fluids.
 Square[hyphen]edged Orifice Meters
 Part 2: Specification and Installation
 Requirements, 5th Edition, March 2016.
API MPMS 14.3.3-2013, Manual of          Standard describing
 Petroleum Measurement Standards          applications using square-
 Chapter 14.3.3--Orifice Metering of      edged orifice meters for
 Natural Gas and Other Related            measuring flow of natural gas
 Hydrocarbon Fluids--Concentric,          and similar fluids.
 Square[hyphen]edged Orifice Meters
 Part 3: Natural Gas Applications, 4th
 Edition, Reaffirmed, June 2021.
API MPMS 14.3.4-2019, Manual of          Standard describing the
 Petroleum Measurement Standards          development of equations for
 Chapter 14.3.4--Orifice Metering of      coefficient of discharge,
 Natural Gas and Other Related            including a calculation
 Hydrocarbon Fluids--Concentric,          procedure, for square-edged
 Square[hyphen]edged Orifice Meters       orifice meters measuring flow
 Part 4--Background, Development,         of natural gas and similar
 Implementation Procedure, and Example    fluids.
 Calculations, 4th Edition, October
 2019.
API MPMS 14.12-2017, Manual of           Standard describing the
 Petroleum Measurement Standards          calculation of flow using gas
 Chapter 14--Natural Gas Fluid            vortex meters for measuring
 Measurement Section 12--Measurement of   the flow of natural gas and
 Gas by Vortex Meters, 1st Edition,       similar fluids.
 March 2017.
APHA SM 2540, Solids, revised June 10,   Standard describing how to
 2020.                                    measure the total solids,
                                          volatile solids, and other
                                          solid properties of wastewater
                                          sludge and similar substances.
ASTM D975-21, Standard Specification     Diesel fuel specifications that
 for Diesel Fuel, approved August 1,      must be met to qualify for
 2021.                                    RINs for renewable fuels.
ASTM D3588-98(R2017)e1, Standard         Calculation protocol for
 Practice for Calculating Heat Value,     aggregate properties of
 Compressibility Factor, and Relative     gaseous fuels from
 Density of Gaseous Fuels, approved       compositional measurements.
 April 1, 2017.
ASTM D4888-20, Standard Test Method for  Standard specifying how to
 Water Vapor in Natural Gas Using         measure water vapor
 Length-of-Stain Detector Tubes,          concentration in gaseous fuel
 approved December 15, 2020.              samples
ASTM D5504-20, Standard Test Method for  Standard specifying how to
 Determination of Sulfur Compounds in     measure sulfur-containing
 Natural Gas and Gaseous Fuels by Gas     compounds in a gaseous fuel
 Chromatography and Chemiluminescence,    sample.
 approved November 1, 2020.
ASTM D6751-20a, Standard Specification   Biodiesel fuel specifications
 for Biodiesel Fuel Blend Stock (B100)    that must be met to qualify
 for Middle Distillate Fuels, approved    for RINs for renewable fuels.
 August 1, 2020.
ASTM D6866-22, Standard Test Methods     Radiocarbon dating test method
 for Determining the Biobased Content     to determine the renewable
 of Solid, Liquid, and Gaseous Samples    content of biogas and RNG.
 Using Radiocarbon Analysis, approved
 March 15, 2022.
ASTM D7164-21, Standard Practice for On- Standard specifying how to use
 line/At-line Heating Value               and maintain an on-line gas
 Determination of Gaseous Fuels by Gas    chromatogram for determining
 Chromatography, approved April 1, 2021.  heating value of a gaseous
                                          fuel.
ASTM D8230-19, Standard Test Method for  Standard specifying how to
 Measurement of Volatile Silicon-         measure silicon-containing
 Containing Compounds in a Gaseous Fuel   compounds in a gaseous fuel
 Sample Using Gas Chromatography with     sample.
 Spectroscopic Detection, approved June
 1, 2019.
EN 17526:2021(E), Gas meter--Thermal-    Standard specifying the
 mass flow-meter based gas meter,         measurement of flow using a
 approved July 11, 2021.                  thermal mass flow meter.
------------------------------------------------------------------------

J. Executive Orders 12898 (Federal Actions To Address Environmental 
Justice in Minority Populations, and Low-Income Populations) and 14096 
(Revitalizing Our Nation's Commitment to Environmental Justice for All)

    Executive Order 12898 (59 FR 7629, February 16, 1994) directs 
federal agencies, to the greatest extent practicable and permitted by 
law, to make 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.
    EPA believes that the human health and environmental conditions 
that exist prior to this action result in disproportionate and adverse 
effects on communities with environmental justice concerns. A summary 
of our approach for considering potential EJ concerns as a result of 
this action can be found in Sections I.B and IV.E, and our EJ analysis 
(including a discussion of this action's potential impacts on GHGs, air 
quality, water quality, and fuel and food prices) can be found in RIA 
Chapter 9.
    EPA believes that this action may result in some new 
disproportionate and adverse effects on communities with environmental 
justice concerns, while also mitigating some effects on these 
populations. Some of these effects are not practicable to assess. This 
rule will reduce GHG emissions, which will benefit communities with

[[Page 44555]]

environmental justice concerns. The manner in which the market responds 
to the provisions in this rule could also have non-GHG impacts. 
Replacing petroleum fuels with renewable fuels can also have localized 
impacts on water and air exposure for communities living near 
facilities that produce renewable fuel, gasoline, or diesel fuel. 
Replacing petroleum fuels with renewable fuels is projected to have 
marginal impacts on food and fuel prices. These price impacts may have 
disproportionate impacts on low-income populations who spend a larger 
proportion of their income on food and fuel. EPA received public 
comment from several groups concerned about the use of biogas in the 
RFS, particularly from landfills and concentrated animal feeding 
operations. EPA solicited further discussion from these groups when 
considering the environmental justice impacts of this rule. The 
majority of the comments and feedback received was focused on potential 
impacts of the proposed renewable electricity provisions, which we have 
decided not to finalize with this action. However, EPA will continue to 
engage with stakeholders on impacts of the RFS program related to 
biogas use and expansion.

K. Congressional Review Act (CRA)

    This action is subject to the CRA, and EPA will submit a rule 
report to each House of the Congress and to the Comptroller General of 
the United States. This action is a ``major rule'' as defined by 5 
U.S.C. 804(2).

XII. Statutory Authority

    Statutory authority for this action comes from sections 114, 203-
05, 208, 211, and 301 of the Clean Air Act, 42 U.S.C. 7414, 7522-24, 
7542, 7545, and 7601.

List of Subjects

40 CFR Part 80

    Environmental protection, Administrative practice and procedure, 
Air pollution control, Diesel fuel, Fuel additives, Gasoline, Imports, 
Incorporation by reference, Oil imports, Petroleum, Renewable fuel.

40 CFR Part 1090

    Environmental protection, Administrative practice and procedure, 
Air pollution control, Diesel fuel, Fuel additives, Gasoline, Imports, 
Oil imports, Petroleum, Renewable fuel.

Michael S. Regan,
Administrator.

    For the reasons set forth in the preamble, EPA amends 40 CFR parts 
80 and 1090 as follows:

PART 80--REGULATION OF FUELS AND FUEL ADDITIVES

0
1. The authority citation for part 80 continues to read as follows:

    Authority:  42 U.S.C. 7414, 7521, 7542, 7545, and 7601(a).

Subpart A--General Provisions

0
2. Revise Sec.  80.2 to read as follows:

Sec.  80.2  Definitions.

    The definitions of this section apply in this part unless otherwise 
specified. Note that many terms defined here are common terms that have 
specific meanings under this part.
    Actual peak capacity means 105% of the maximum annual volume of 
renewable fuels produced from a specific renewable fuel production 
facility on a calendar year basis.
    (1) For facilities that commenced construction prior to December 
19, 2007, the actual peak capacity is based on the last five calendar 
years prior to 2008, unless no such production exists, in which case 
actual peak capacity is based on any calendar year after startup during 
the first three years of operation.
    (2) For facilities that commenced construction after December 19, 
2007 and before January 1, 2010, that are fired with natural gas, 
biomass, or a combination thereof, the actual peak capacity is based on 
any calendar year after startup during the first three years of 
operation.
    (3) For all other facilities not included above, the actual peak 
capacity is based on the last five calendar years prior to the year in 
which the owner or operator registers the facility under the provisions 
of Sec.  80.1450, unless no such production exists, in which case 
actual peak capacity is based on any calendar year after startup during 
the first three years of operation.
    Adjusted cellulosic content means the percent of organic material 
that is cellulose, hemicellulose, and lignin.
    Advanced biofuel means renewable fuel, other than ethanol derived 
from cornstarch, that has lifecycle greenhouse gas emissions that are 
at least 50 percent less than baseline lifecycle greenhouse gas 
emissions.
    Agricultural digester means an anaerobic digester that processes 
only animal manure, crop residues, or separated yard waste with an 
adjusted cellulosic content of at least 75%. Each and every material 
processed in an agricultural digester must have an adjusted cellulosic 
content of at least 75%.
    Algae grown photosynthetically are algae that are grown such that 
their energy and carbon are predominantly derived from photosynthesis.
    Annual cover crop means an annual crop, planted as a rotation 
between primary planted crops, or between trees and vines in orchards 
and vineyards, typically to protect soil from erosion and to improve 
the soil between periods of regular crops. An annual cover crop has no 
existing market to which it can be sold except for its use as feedstock 
for the production of renewable fuel.
    Approved pathway means a pathway listed in table 1 to Sec.  80.1426 
or in a petition approved under Sec.  80.1416 that is eligible to 
generate RINs of a particular D code.
    Areas at risk of wildfire are those areas in the ``wildland-urban 
interface'', where humans and their development meet or intermix with 
wildland fuel. Note that, for guidance, the SILVIS laboratory at the 
University of Wisconsin maintains a website that provides a detailed 
map of areas meeting this criteria at: www.silvis.forest.wisc.edu/projects/US_WUI_2000.asp. The SILVIS laboratory is located at 1630 
Linden Drive, Madison, Wisconsin 53706 and can be contacted at (608) 
263-4349.
    A-RIN means a RIN verified during the interim period by a 
registered independent third-party auditor using a QAP that has been 
approved under Sec.  80.1469(a) following the audit process specified 
in Sec.  80.1472.
    Assigned RIN means a RIN assigned to a volume of renewable fuel or 
RNG pursuant to Sec.  80.1426(e) or Sec.  80.125(c), respectively, with 
a K code of 1.
    Audited facility means any facility audited under an approved 
quality assurance plan under this part.
    Audited party means a party that pays for or receives services from 
an independent third party under this part.
    Baseline lifecycle greenhouse gas emissions means the average 
lifecycle greenhouse gas emissions for gasoline or diesel (whichever is 
being replaced by the renewable fuel) sold or distributed as 
transportation fuel in 2005.
    Baseline volume means the permitted capacity or, if permitted 
capacity cannot be determined, the actual peak capacity or nameplate 
capacity as applicable pursuant to Sec.  80.1450(b)(1)(v)(A) through 
(C), of a specific renewable fuel

[[Page 44556]]

production facility on a calendar year basis.
    Batch pathway means each combination of approved pathway, 
equivalence value as determined under Sec.  80.1415, and verification 
status for which a facility is registered.
    Biocrude means a liquid biointermediate that meets all the 
following requirements:
    (1) It is produced at a biointermediate production facility using 
one or more of the following processes:
    (i) A process identified in row M under table 1 to Sec.  80.1426.
    (ii) A process identified in a pathway listed in a petition 
approved under Sec.  80.1416 for the production of renewable fuel 
produced from biocrude.
    (2) It is to be used to produce renewable fuel at a refinery as 
defined in 40 CFR 1090.80.
    Biodiesel means a mono-alkyl ester that meets ASTM D6751 
(incorporated by reference, see Sec.  80.12).
    Biodiesel distillation bottoms means the heavier product from 
distillation at a biodiesel production facility that does not meet the 
definition of biodiesel.
    Biogas means a mixture of biomethane, inert gases, and impurities 
that meets all the following requirements:
    (1) It is produced through the anaerobic digestion of renewable 
biomass under an approved pathway.
    (2) Non-renewable components have not been added.
    (3) It requires removal of additional components to be suitable for 
its designated use (e.g., as a biointermediate, to produce RNG, or to 
produce biogas-derived renewable fuel).
    Biogas closed distribution system means the infrastructure 
contained between when biogas is produced and when biogas or treated 
biogas is used to produce biogas-derived renewable fuel within a 
discrete location or series of locations that does not include 
placement of biogas, treated biogas, or RNG on a natural gas commercial 
pipeline system.
    Biogas closed distribution system RIN generator means any party 
that generates RINs for renewable CNG/LNG in a biogas closed 
distribution system.
    Biogas-derived renewable fuel means renewable CNG/LNG or any other 
renewable fuel that is produced from biogas or RNG, including from 
biogas used as a biointermediate.
    Biogas producer means any person who owns, leases, operates, 
controls, or supervises a biogas production facility.
    Biogas production facility means any facility where biogas is 
produced from renewable biomass under an approved pathway.
    Biogas used as a biointermediate means biogas or treated biogas 
that a renewable fuel producer uses to produce renewable fuel other 
than renewable CNG/LNG at a separate facility from where the biogas is 
produced.
    Biointermediate means any feedstock material that is intended for 
use to produce renewable fuel and meets all the following requirements:
    (1) It is produced from renewable biomass.
    (2) It has not previously had RINs generated for it.
    (3) It is produced at a facility registered with EPA that is 
different than the facility at which it is used as feedstock material 
to produce renewable fuel.
    (4) It is produced from the feedstock material identified in an 
approved pathway, will be used to produce the renewable fuel listed in 
that approved pathway, and is produced and processed in accordance with 
the process(es) listed in that approved pathway.
    (5) Is one of the following types of biointermediate:
    (i) Biocrude.
    (ii) Biodiesel distillate bottoms.
    (iii) Biomass-based sugars.
    (iv) Digestate.
    (v) Free fatty acid (FFA) feedstock.
    (vi) Glycerin.
    (vii) Soapstock.
    (viii) Undenatured ethanol.
    (ix) Biogas used to make a renewable fuel other than renewable CNG/
LNG.
    (6) It is not a feedstock material identified in an approved 
pathway that is used to produce the renewable fuel specified in that 
approved pathway.
    Biointermediate import facility means any facility as defined in 40 
CFR 1090.80 where a biointermediate is imported from outside the 
covered location into the covered location.
    Biointermediate importer means any person who owns, leases, 
operates, controls, or supervises a biointermediate import facility.
    Biointermediate producer means any person who owns, leases, 
operates, controls, or supervises a biointermediate production 
facility.
    Biointermediate production facility means all of the activities and 
equipment associated with the production of a biointermediate starting 
from the point of delivery of feedstock material to the point of final 
storage of the end biointermediate product, which are located on one 
property, and are under the control of the same person (or persons 
under common control).
    Biomass-based diesel means a renewable fuel that has lifecycle 
greenhouse gas emissions that are at least 50 percent less than 
baseline lifecycle greenhouse gas emissions and meets all of the 
requirements of paragraph (1) of this definition:
    (1)(i) Is a transportation fuel, transportation fuel additive, 
heating oil, or jet fuel.
    (ii) Meets the definition of either biodiesel or non-ester 
renewable diesel.
    (iii) Is registered as a motor vehicle fuel or fuel additive under 
40 CFR part 79, if the fuel or fuel additive is intended for use in a 
motor vehicle.
    (2) Renewable fuel produced from renewable biomass that is co-
processed with petroleum is not biomass-based diesel.
    Biomass-based sugars means sugars (e.g., dextrose, sucrose, etc.) 
extracted from renewable biomass under an approved pathway, other than 
through a form change specified in Sec.  80.1460(k)(2).
    Biomethane means methane produced from renewable biomass.
    B-RIN means a RIN verified during the interim period by a 
registered independent third-party auditor using a QAP that has been 
approved under Sec.  80.1469(b) following the audit process specified 
in Sec.  80.1472.
    Business day has the meaning given in 40 CFR 1090.80.
    Canola/Rapeseed oil means either of the following:
    (1) Canola oil is oil from the plants Brassica napus, Brassica 
rapa, Brassica juncea, Sinapis alba, or Sinapis arvensis, and which 
typically contains less than 2 percent erucic acid in the component 
fatty acids obtained.
    (2) Rapeseed oil is the oil obtained from the plants Brassica 
napus, Brassica rapa, or Brassica juncea.
    Carrier means any distributor who transports or stores or causes 
the transportation or storage of gasoline or diesel fuel without taking 
title to or otherwise having any ownership of the gasoline or diesel 
fuel, and without altering either the quality or quantity of the 
gasoline or diesel fuel.
    Category 3 (C3) marine vessels, for the purposes of this part 80, 
are vessels that are propelled by engines meeting the definition of 
``Category 3'' in 40 CFR 1042.901.
    CBOB means gasoline blendstock that could become conventional 
gasoline solely upon the addition of oxygenate.
    Cellulosic biofuel means renewable fuel derived from any cellulose, 
hemi-cellulose, or lignin that has lifecycle greenhouse gas emissions 
that are at least 60 percent less than the baseline lifecycle 
greenhouse gas emissions.
    Cellulosic biogas feedstock means an individual feedstock used to 
produce biogas that contains at least 75%

[[Page 44557]]

average adjusted cellulosic content and whose batch pathway has been 
assigned a D code of 3 or 7.
    Cellulosic diesel is any renewable fuel which meets both the 
definitions of cellulosic biofuel and biomass-based diesel. Cellulosic 
diesel includes heating oil and jet fuel produced from cellulosic 
feedstocks.
    Certified non-transportation 15 ppm distillate fuel or certified 
NTDF means distillate fuel that meets all the following:
    (1) The fuel has been certified under 40 CFR 1090.1000 as meeting 
the ULSD standards in 40 CFR 1090.305.
    (2) The fuel has been designated under 40 CFR 1090.1015 as 
certified NTDF.
    (3) The fuel has also been designated under 40 CFR 1090.1015 as 15 
ppm heating oil, 15 ppm ECA marine fuel, or other non-transportation 
fuel (e.g., jet fuel, kerosene, or distillate global marine fuel).
    (4) The fuel has not been designated under 40 CFR 1090.1015 as ULSD 
or 15 ppm MVNRLM diesel fuel.
    (5) The PTD for the fuel meets the requirements in Sec.  
80.1453(e).
    Combined heat and power (CHP), also known as cogeneration, refers 
to industrial processes in which waste heat from the production of 
electricity is used for process energy in a biointermediate or 
renewable fuel production facility.
    Continuous measurement means the automated measurement of specified 
parameters of biogas, treated biogas, or natural gas as follows:
    (1) For in-line GC meters, automated measurement must occur and be 
recorded no less frequent than once every 15 minutes.
    (2) For flow meters, automated measurement must occur no less 
frequent than once every 6 seconds, and weighted totals of such 
measurement must be recorded at no more than 1 minute intervals.
    (3) For all other meters, automated measurement and recording must 
occur at a frequency specified at registration.
    Contractual affiliate means one of the following:
    (1) Two parties are contractual affiliates if they have an explicit 
or implicit agreement in place for one to purchase or hold RINs on 
behalf of the other or to deliver RINs to the other. This other party 
may or may not be registered under the RFS program.
    (2) Two parties are contractual affiliates if one RIN-owning party 
purchases or holds RINs on behalf of the other. This other party may or 
may not be registered under the RFS program.
    Control area means a geographic area in which only oxygenated 
gasoline under the oxygenated gasoline program may be sold or 
dispensed, with boundaries determined by Clean Air Act section 211(m) 
(42 U.S.C. 7545(m)).
    Control period means the period during which oxygenated gasoline 
must be sold or dispensed in any control area, pursuant to Clean Air 
Act section 211(m)(2) (42 U.S.C. 7545(m)(2)).
    Conventional gasoline (CG) means any gasoline that has been 
certified under 40 CFR 1090.1000(b) and is not RFG.
    Co-processed means that renewable biomass or a biointermediate was 
simultaneously processed with fossil fuels or other non-renewable 
feedstock in the same unit or units to produce a fuel that is partially 
derived from renewable biomass or a biointermediate.
    Co-processed cellulosic diesel is any renewable fuel that meets the 
definition of cellulosic biofuel and meets all the requirements of 
paragraph (1) of this definition:
    (1)(i) Is a transportation fuel, transportation fuel additive, 
heating oil, or jet fuel.
    (ii) Meets the definition of either biodiesel or non-ester 
renewable diesel.
    (iii) Is registered as a motor vehicle fuel or fuel additive under 
40 CFR part 79, if the fuel or fuel additive is intended for use in a 
motor vehicle.
    (2) Co-processed cellulosic diesel includes all the following:
    (i) Heating oil and jet fuel produced from cellulosic feedstocks.
    (ii) Cellulosic biofuel produced from cellulosic feedstocks co-
processed with petroleum.
    Corn oil extraction means the recovery of corn oil from the thin 
stillage and/or the distillers grains and solubles produced by a dry 
mill corn ethanol plant, most often by mechanical separation.
    Corn oil fractionation means a process whereby seeds are divided in 
various components and oils are removed prior to fermentation for the 
production of ethanol.
    Corporate affiliate means one of the following:
    (1) Two RIN-holding parties are corporate affiliates if one owns or 
controls ownership of more than 20 percent of the other.
    (2) Two RIN-holding parties are corporate affiliates if one parent 
company owns or controls ownership of more than 20 percent of both.
    Corporate affiliate group means a group of parties in which each 
party is a corporate affiliate to at least one other party in the 
group.
    Covered location means the contiguous 48 states, Hawaii, and any 
state or territory that has received an approval from EPA to opt-in to 
the RFS program under Sec.  80.1443.
    Crop residue means biomass left over from the harvesting or 
processing of planted crops from existing agricultural land and any 
biomass removed from existing agricultural land that facilitates crop 
management (including biomass removed from such lands in relation to 
invasive species control or fire management), whether or not the 
biomass includes any portion of a crop or crop plant. Biomass is 
considered crop residue only if the use of that biomass for the 
production of renewable fuel has no significant impact on demand for 
the feedstock crop, products produced from that feedstock crop, and all 
substitutes for the crop and its products, nor any other impact that 
would result in a significant increase in direct or indirect GHG 
emissions.
    Cropland is land used for production of crops for harvest and 
includes cultivated cropland, such as for row crops or close-grown 
crops, and non-cultivated cropland, such as for horticultural or 
aquatic crops.
    Diesel fuel means any of the following:
    (1) Any fuel sold in any State or Territory of the United States 
and suitable for use in diesel engines, and that is one of the 
following:
    (i) A distillate fuel commonly or commercially known or sold as No. 
1 diesel fuel or No. 2 diesel fuel.
    (ii) A non-distillate fuel other than residual fuel with comparable 
physical and chemical properties (e.g., biodiesel fuel).
    (iii) A mixture of fuels meeting the criteria of paragraphs (1)(i) 
and (ii) of this definition.
    (2) For purposes of subpart M of this part, any and all of the 
products specified at Sec.  80.1407(e).
    Digestate means the material that remains following the anaerobic 
digestion of renewable biomass in an anaerobic digester. Digestate must 
only contain the leftovers that were unable to be completely converted 
to biogas in an anaerobic digestor that is part of an EPA-accepted 
registration under Sec.  80.1450.
    Distillate fuel means diesel fuel and other petroleum fuels that 
can be used in engines that are designed for diesel fuel. For example, 
jet fuel, heating oil, kerosene, No. 4 fuel, DMX, DMA, DMB, and DMC are 
distillate fuels; and natural gas, LPG, gasoline, and residual fuel are 
not distillate fuels. Blends containing residual fuel may be distillate 
fuels.
    Distillers corn oil means corn oil recovered at any point 
downstream of when a dry mill ethanol or butanol plant grinds the corn, 
provided that the

[[Page 44558]]

corn starch is converted to ethanol or butanol, the recovered oil is 
unfit for human food use without further refining, and the distillers 
grains remaining after the dry mill and oil recovery processes are 
marketable as animal feed.
    Distillers sorghum oil means grain sorghum oil recovered at any 
point downstream of when a dry mill ethanol or butanol plant grinds the 
grain sorghum, provided that the grain sorghum is converted to ethanol 
or butanol, the recovered oil is unfit for human food use without 
further refining, and the distillers grains remaining after the dry 
mill and oil recovery processes are marketable as animal feed.
    Distributor means any person who transports or stores or causes the 
transportation or storage of gasoline or diesel fuel at any point 
between any gasoline or diesel fuel refinery or importer's facility and 
any retail outlet or wholesale purchaser-consumer's facility.
    DX RIN means a RIN with a D code of X, where X is the D code of the 
renewable fuel as identified under Sec.  80.1425(g), generated under 
Sec.  80.1426, and submitted under Sec.  80.1452. For example, a D6 RIN 
is a RIN with a D code of 6.
    ECA marine fuel is diesel, distillate, or residual fuel that meets 
the criteria of paragraph (1) of this definition, but not the criteria 
of paragraph (2) of this definition.
    (1) All diesel, distillate, or residual fuel used, intended for 
use, or made available for use in Category 3 marine vessels while the 
vessels are operating within an Emission Control Area (ECA), or an ECA 
associated area, is ECA marine fuel, unless it meets the criteria of 
paragraph (2) of this definition.
    (2) ECA marine fuel does not include any of the following fuel:
    (i) Fuel used by exempted or excluded vessels (such as exempted 
steamships), or fuel used by vessels allowed by the U.S. government 
pursuant to MARPOL Annex VI Regulation 3 or Regulation 4 to exceed the 
fuel sulfur limits while operating in an ECA or an ECA associated area 
(see 33 U.S.C. 1903).
    (ii) Fuel that conforms fully to the requirements of this part for 
MVNRLM diesel fuel (including being designated as MVNRLM).
    (iii) Fuel used, or made available for use, in any diesel engines 
not installed on a Category 3 marine vessel.
    Ecologically sensitive forestland means forestland that meets 
either of the following criteria:
    (1) An ecological community with a global or state ranking of 
critically imperiled, imperiled or rare pursuant to a State Natural 
Heritage Program. For examples of such ecological communities, see 
``Listing of Forest Ecological Communities Pursuant to 40 CFR 80.1401; 
S1-S3 communities,'' which is number EPA-HQ-OAR-2005-0161-1034.1 in the 
public docket, and ``Listing of Forest Ecological Communities Pursuant 
to 40 CFR 80.1401; G1-G2 communities,'' which is number EPA-HQ-OAR-
2005-0161-2906.1 in the public docket. This material is available for 
inspection at the EPA Docket Center, EPA/DC, EPA West, Room 3334, 1301 
Constitution Ave. NW, Washington, DC. The telephone number for the Air 
Docket is (202) 566-1742.
    (2) Old growth or late successional, characterized by trees at 
least 200 years in age.
    End of day means 7 a.m. Coordinated Universal Time (UTC).
    Energy cane means a complex hybrid in the Saccharum genus that has 
been bred to maximize cellulosic rather than sugar content. For the 
purposes of this part:
    (1) Energy cane excludes the species Saccharum spontaneum, but may 
include hybrids derived from S. spontaneum that have been developed and 
publicly released by USDA; and
    (2) Energy cane only includes cultivars that have, on average, at 
least 75% adjusted cellulosic content on a dry mass basis.
    EPA Moderated Transaction System (EMTS) means a closed, EPA 
moderated system that provides a mechanism for screening and tracking 
RINs under Sec.  80.1452.
    Existing agricultural land is cropland, pastureland, and land 
enrolled in the Conservation Reserve Program (administered by the U.S. 
Department of Agriculture's Farm Service Agency) that was cleared or 
cultivated prior to December 19, 2007, and that, on December 19, 2007, 
was:
    (1) Nonforested; and
    (2) Actively managed as agricultural land or fallow, as evidenced 
by records which must be traceable to the land in question, which must 
include one of the following:
    (i) Records of sales of planted crops, crop residue, or livestock, 
or records of purchases for land treatments such as fertilizer, weed 
control, or seeding.
    (ii) A written management plan for agricultural purposes.
    (iii) Documented participation in an agricultural management 
program administered by a Federal, state, or local government agency.
    (iv) Documented management in accordance with a certification 
program for agricultural products.
    Exporter of renewable fuel means all buyers, sellers, and owners of 
the renewable fuel in any transaction that results in renewable fuel 
being transferred from a covered location to a destination outside of 
the covered locations.
    Facility means all of the activities and equipment associated with 
the production of renewable fuel, biogas, treated biogas, RNG, or a 
biointermediate--starting from the point of delivery of feedstock 
material to the point of final storage of the end product--that are 
located on one property and are under the control of the same person 
(or persons under common control).
    Fallow means cropland, pastureland, or land enrolled in the 
Conservation Reserve Program (administered by the U.S. Department of 
Agriculture's Farm Service Agency) that is intentionally left idle to 
regenerate for future agricultural purposes with no seeding or 
planting, harvesting, mowing, or treatment during the fallow period.
    Feedstock aggregator means any person who collects feedstock from 
feedstock suppliers or other feedstock aggregators and distributes such 
feedstock to a renewable fuel producer, biointermediate producer, or 
other feedstock aggregator.
    Feedstock supplier means any person who generates and supplies 
feedstock to a feedstock aggregator, renewable fuel producer, biogas 
producer, or biointermediate producer.
    Foreign biogas producer means any person who owns, leases, 
operates, controls, or supervises a biogas production facility outside 
of the United States.
    Foreign ethanol producer means a foreign renewable fuel producer 
who produces ethanol for use in transportation fuel, heating oil, or 
jet fuel but who does not add ethanol denaturant to their product as 
specified in paragraph (2) of the definition of ``renewable fuel'' in 
this section.
    Foreign renewable fuel producer means a person from a foreign 
country or from an area outside the covered location who produces 
renewable fuel for use in transportation fuel, heating oil, or jet fuel 
for export to the covered location. Foreign ethanol producers are 
considered foreign renewable fuel producers.
    Foreign RNG producer means any person who owns, leases, operates, 
controls, or supervises an RNG production facility outside of the 
United States.

[[Page 44559]]

    Forestland is generally undeveloped land covering a minimum area of 
1 acre upon which the primary vegetative species are trees, including 
land that formerly had such tree cover and that will be regenerated and 
tree plantations. Tree-covered areas in intensive agricultural crop 
production settings, such as fruit orchards, or tree-covered areas in 
urban settings, such as city parks, are not considered forestland.
    Free fatty acid (FFA) feedstock means a biointermediate that is 
composed of at least 50 percent free fatty acids. FFA feedstock must 
not include any free fatty acids from the refining of crude palm oil.
    Fuel for use in an ocean-going vessel means, for this part only:
    (1) Any marine residual fuel (whether burned in ocean waters, Great 
Lakes, or other internal waters);
    (2) Emission Control Area (ECA) marine fuel, pursuant to Sec.  80.2 
and 40 CFR 1090.80 (whether burned in ocean waters, Great Lakes, or 
other internal waters); and
    (3) Any other fuel intended for use only in ocean-going vessels.
    Gasoline means any of the following:
    (1) Any fuel sold in the United States for use in motor vehicles 
and motor vehicle engines, and commonly or commercially known or sold 
as gasoline.
    (2) For purposes of subpart M of this part, any and all of the 
products specified at Sec.  80.1407(c).
    Gasoline blendstock or component means any liquid compound that is 
blended with other liquid compounds to produce gasoline.
    Gasoline blendstock for oxygenate blending (BOB) has the meaning 
given in 40 CFR 1090.80.
    Gasoline treated as blendstock (GTAB) means imported gasoline that 
is excluded from an import facility's compliance calculations, but is 
treated as blendstock in a related refinery that includes the GTAB in 
its refinery compliance calculations.
    Glycerin means a coproduct from the production of biodiesel that 
primarily contains glycerol.
    Heating oil means any of the following:
    (1) Any No. 1, No. 2, or non-petroleum diesel blend that is sold 
for use in furnaces, boilers, and similar applications and which is 
commonly or commercially known or sold as heating oil, fuel oil, and 
similar trade names, and that is not jet fuel, kerosene, or MVNRLM 
diesel fuel.
    (2) Any fuel oil that is used to heat or cool interior spaces of 
homes or buildings to control ambient climate for human comfort. The 
fuel oil must be liquid at STP and contain no more than 2.5% mass 
solids.
    Importer means any person who imports transportation fuel or 
renewable fuel into the covered location from an area outside of the 
covered location.
    Independent third-party auditor means a party meeting the 
requirements of Sec.  80.1471(b) that conducts QAP audits and verifies 
RINs, biointermediates, or biogas.
    Interim period means the period between February 21, 2013, and 
December 31, 2014.
    Jet fuel means any distillate fuel used, intended for use, or made 
available for use in aircraft.
    Kerosene means any No.1 distillate fuel commonly or commercially 
sold as kerosene.
    Liquefied petroleum gas (LPG) means a liquid hydrocarbon fuel that 
is stored under pressure and is composed primarily of species that are 
gases at atmospheric conditions (temperature = 25 [deg]C and pressure = 
1 atm), excluding natural gas.
    Locomotive engine means an engine used in a locomotive as defined 
under 40 CFR 92.2.
    Marine engine has the meaning given in 40 CFR 1042.901.
    Membrane separation means the process of dehydrating ethanol to 
fuel grade (>99.5% purity) using a hydrophilic membrane.
    Mixed digester means an anaerobic digester that has received 
feedstocks under both an approved pathway with D code 3 or 7 and an 
approved pathway with D code 5 during the current calendar month or the 
previous two calendar months.
    Motor vehicle has the meaning given in Section 216(2) of the Clean 
Air Act (42 U.S.C. 7550(2)).
    Municipal wastewater treatment facility digester means an anaerobic 
digester that processes only municipal wastewater treatment plant 
sludge with an adjusted cellulosic content of at least 75%.
    MVNRLM diesel fuel means any diesel fuel or other distillate fuel 
that is used, intended for use, or made available for use in motor 
vehicles or motor vehicle engines, or as a fuel in any nonroad diesel 
engines, including locomotive and marine diesel engines, except the 
following: Distillate fuel with a T90 at or above 700 [deg]F that is 
used only in Category 2 and 3 marine engines is not MVNRLM diesel fuel, 
and ECA marine fuel is not MVNRLM diesel fuel (note that fuel that 
conforms to the requirements of MVNRLM diesel fuel is excluded from the 
definition of ``ECA marine fuel'' in this section without regard to its 
actual use). Use the distillation test method specified in 40 CFR 
1065.1010 to determine the T90 of the fuel.
    (1) Any diesel fuel that is sold for use in stationary engines that 
are required to meet the requirements of 40 CFR 1090.300, when such 
provisions are applicable to nonroad engines, is considered MVNRLM 
diesel fuel.
    (2) [Reserved]
    Nameplate capacity means the peak design capacity of a facility for 
the purposes of registration of a facility under this part.
    Naphtha means a blendstock or fuel blending component falling 
within the boiling range of gasoline, which is composed of only 
hydrocarbons, is commonly or commercially known as naphtha, and is used 
to produce gasoline or E85 (as defined in 40 CFR 1090.80) through 
blending.
    Natural gas means a fuel whose primary constituent is methane. 
Natural gas includes RNG.
    Natural gas commercial pipeline system means one or more connected 
pipelines that transport natural gas that meets all the following:
    (1) The natural gas originates from multiple parties.
    (2) The natural gas meets specifications set by the pipeline owner 
or operator.
    (3) The natural gas is delivered to multiple parties in the covered 
location.
    Neat renewable fuel is a renewable fuel to which 1% or less of 
gasoline (as defined in this section) or diesel fuel has been added.
    Non-ester renewable diesel or renewable diesel means renewable fuel 
that is not a mono-alkyl ester and that is either:
    (1) A fuel or fuel additive that meets the Grade No. 1-D or No. 2-D 
specification in ASTM D975 (incorporated by reference, see Sec.  80.12) 
and can be used in an engine designed to operate on conventional diesel 
fuel; or
    (2) A fuel or fuel additive that is registered under 40 CFR part 79 
and can be used in an engine designed to operate using conventional 
diesel fuel.
    Nonforested land means land that is not forestland.
    Non-petroleum diesel means a diesel fuel that contains at least 80 
percent mono-alkyl esters of long chain fatty acids derived from 
vegetable oils or animal fats.
    Non-qualifying fuel use means a use of renewable fuel in an 
application other than transportation fuel, heating oil, or jet fuel.
    Non-renewable component means any material (or any portion thereof) 
blended into biogas or RNG that does

[[Page 44560]]

not meet the definition of renewable biomass.
    Non-renewable feedstock means a feedstock (or any portion thereof) 
that does not meet the definition of renewable biomass or 
biointermediate.
    Non-RIN-generating foreign producer means a foreign renewable fuel 
producer that has been registered by EPA to produce renewable fuel for 
which RINs have not been generated.
    Nonroad diesel engine means an engine that is designed to operate 
with diesel fuel that meets the definition of nonroad engine in 40 CFR 
1068.30, including locomotive and marine diesel engines.
    Nonroad vehicle has the meaning given in Section 216(11) of the 
Clean Air Act (42 U.S.C. 7550(11)).
    Obligated party means any refiner that produces gasoline or diesel 
fuel within the covered location, or any importer that imports gasoline 
or diesel fuel into the covered location, during a compliance period. A 
party that simply blends renewable fuel into gasoline or diesel fuel, 
as specified in Sec.  80.1407(c) or (e), is not an obligated party.
    Ocean-going vessel means vessels that are equipped with engines 
meeting the definition of ``Category 3'' in 40 CFR 1042.901.
    Oxygenate means any substance which, when added to gasoline, 
increases the oxygen content of that gasoline. Lawful use of any of the 
substances or any combination of these substances requires that they be 
``substantially similar'' under section 211(f)(1) of the Clean Air Act 
(42 U.S.C. 7545(f)(1)), or be permitted under a waiver granted by EPA 
under the authority of section 211(f)(4) of the Clean Air Act (42 
U.S.C. 7545(f)(4)).
    Oxygenated gasoline means gasoline which contains a measurable 
amount of oxygenate.
    Pastureland is land managed for the production of select indigenous 
or introduced forage plants for livestock grazing or hay production, 
and to prevent succession to other plant types.
    Permitted capacity means 105% of the maximum permissible volume 
output of renewable fuel that is allowed under operating conditions 
specified in the most restrictive of all applicable preconstruction, 
construction and operating permits issued by regulatory authorities 
(including local, regional, state or a foreign equivalent of a state, 
and federal permits, or permits issued by foreign governmental 
agencies) that govern the construction and/or operation of the 
renewable fuel facility, based on an annual volume output on a calendar 
year basis. If the permit specifies maximum rated volume output on an 
hourly basis, then annual volume output is determined by multiplying 
the hourly output by 8,322 hours per year.
    (1) For facilities that commenced construction prior to December 
19, 2007, the permitted capacity is based on permits issued or revised 
no later than December 19, 2007.
    (2) For facilities that commenced construction after December 19, 
2007 and before January 1, 2010 that are fired with natural gas, 
biomass, or a combination thereof, the permitted capacity is based on 
permits issued or revised no later than December 31, 2009.
    (3) For facilities other than those specified in paragraphs (1) and 
(2) of this definition, permitted capacity is based on the most recent 
applicable permits.
    Pipeline interconnect means the physical injection or withdrawal 
point where RNG is injected or withdrawn into or from the natural gas 
commercial pipeline system.
    Planted crops are all annual or perennial agricultural crops from 
existing agricultural land that may be used as feedstocks for renewable 
fuel, such as grains, oilseeds, sugarcane, switchgrass, prairie grass, 
duckweed, and other species (but not including algae species or planted 
trees), providing that they were intentionally applied by humans to the 
ground, a growth medium, a pond or tank, either by direct application 
as seed or plant, or through intentional natural seeding or vegetative 
propagation by mature plants introduced or left undisturbed for that 
purpose.
    Planted trees are trees harvested from a tree plantation.
    Pre-commercial thinnings are trees, including unhealthy or diseased 
trees, removed to reduce stocking to concentrate growth on more 
desirable, healthy trees, or other vegetative material that is removed 
to promote tree growth.
    Professional liability insurance means insurance coverage for 
liability arising out of the performance of professional or business 
duties related to a specific occupation, with coverage being tailored 
to the needs of the specific occupation. Examples include abstracters, 
accountants, insurance adjusters, architects, engineers, insurance 
agents and brokers, lawyers, real estate agents, stockbrokers, and 
veterinarians. For purposes of this definition, professional liability 
insurance does not include directors and officers liability insurance.
    Q-RIN means a RIN verified by a registered independent third-party 
auditor using a QAP that has been approved under Sec.  80.1469(c) 
following the audit process specified in Sec.  80.1472.
    Quality assurance audit means an audit of a renewable fuel 
production facility or biointermediate production facility conducted by 
an independent third-party auditor in accordance with a QAP that meets 
the requirements of Sec. Sec.  80.1469, 80.1472, and 80.1477.
    Quality assurance plan (QAP) means the list of elements that an 
independent third-party auditor will check to verify that the RINs 
generated by a renewable fuel producer or importer are valid or to 
verify the appropriate production of a biointermediate. A QAP includes 
both general and pathway specific elements.
    Raw starch hydrolysis means the process of hydrolyzing corn starch 
into simple sugars at low temperatures, generally not exceeding 100 
[deg]F (38 [deg]C), using enzymes designed to be effective under these 
conditions.
    Refiner means any person who owns, leases, operates, controls, or 
supervises a refinery.
    Refinery means any facility, including but not limited to, a plant, 
tanker truck, or vessel where gasoline or diesel fuel is produced, 
including any facility at which blendstocks are combined to produce 
gasoline or diesel fuel, or at which blendstock is added to gasoline or 
diesel fuel.
    Reformulated gasoline (RFG) means any gasoline whose formulation 
has been certified under 40 CFR 1090.1000(b), and which meets each of 
the standards and requirements prescribed under 40 CFR 1090.220.
    Reformulated gasoline blendstock for oxygenate blending (RBOB) 
means a petroleum product that, when blended with a specified type and 
percentage of oxygenate, meets the definition of reformulated gasoline, 
and to which the specified type and percentage of oxygenate is added 
other than by the refiner or importer of the RBOB at the refinery or 
import facility where the RBOB is produced or imported.
    Renewable biomass means each of the following (including any 
incidental, de minimis contaminants that are impractical to remove and 
are related to customary feedstock production and transport):
    (1) Planted crops and crop residue harvested from existing 
agricultural land cleared or cultivated prior to December 19, 2007 and 
that was nonforested and either actively managed or fallow on December 
19, 2007.
    (2) Planted trees and tree residue from a tree plantation located 
on non-federal land (including land belonging to an Indian tribe or an 
Indian individual that is held in trust by the U.S. or subject to a 
restriction against alienation imposed

[[Page 44561]]

by the U.S.) that was cleared at any time prior to December 19, 2007 
and actively managed on December 19, 2007.
    (3) Animal waste material and animal byproducts.
    (4) Slash and pre-commercial thinnings from non-federal forestland 
(including forestland belonging to an Indian tribe or an Indian 
individual, that are held in trust by the United States or subject to a 
restriction against alienation imposed by the United States) that is 
not ecologically sensitive forestland.
    (5) Biomass (organic matter that is available on a renewable or 
recurring basis) obtained from within 200 feet of buildings and other 
areas regularly occupied by people, or of public infrastructure, in an 
area at risk of wildfire.
    (6) Algae.
    (7) Separated yard waste or food waste, including recycled cooking 
and trap grease.
    Renewable compressed natural gas or renewable CNG means biogas, 
treated biogas, or RNG that is compressed for use as transportation 
fuel and meets the definition of renewable fuel.
    Renewable electricity means electricity that meets the definition 
of renewable fuel.
    Renewable fuel means a fuel that meets all the following 
requirements:
    (1)(i) Fuel that is produced either from renewable biomass or from 
a biointermediate produced from renewable biomass.
    (ii) Fuel that is used in the covered location to replace or reduce 
the quantity of fossil fuel present in a transportation fuel, heating 
oil, or jet fuel.
    (iii) Has lifecycle greenhouse gas emissions that are at least 20 
percent less than baseline lifecycle greenhouse gas emissions, unless 
the fuel is exempt from this requirement pursuant to Sec.  80.1403.
    (2) Ethanol covered by this definition must be denatured using an 
ethanol denaturant as required in 27 CFR parts 19 through 21. Any 
volume of ethanol denaturant added to the undenatured ethanol by a 
producer or importer in excess of 2 volume percent must not be included 
in the volume of ethanol for purposes of determining compliance with 
the requirements of this part.
    Renewable gasoline means renewable fuel produced from renewable 
biomass that is composed of only hydrocarbons and that meets the 
definition of gasoline.
    Renewable gasoline blendstock means a blendstock produced from 
renewable biomass that is composed of only hydrocarbons and which meets 
the definition of gasoline blendstock in Sec.  80.2.
    Renewable Identification Number (RIN) is a unique number generated 
to represent a volume of renewable fuel pursuant to Sec. Sec.  80.1425 
and 80.1426.
    (1) Gallon-RIN is a RIN that represents an individual gallon of 
renewable fuel used for compliance purposes pursuant to Sec.  80.1427 
to satisfy a renewable volume obligation.
    (2) Batch-RIN is a RIN that represents multiple gallon-RINs.
    Renewable liquefied natural gas or renewable LNG means biogas, 
treated biogas, or RNG that is liquified (i.e., it is cooled below its 
boiling point) for use as transportation fuel and meets the definition 
of renewable fuel.
    Renewable natural gas (RNG) means a product that meets all the 
following requirements:
    (1) It is produced from biogas.
    (2) It does not require removal of additional components to be 
suitable for injection into the natural gas commercial pipeline system.
    (3) It is used to produce renewable fuel.
    Residual fuel means a petroleum fuel that can only be used in 
diesel engines if it is preheated before injection. For example, No. 5 
fuels, No. 6 fuels, and RM grade marine fuels are residual fuels. Note: 
Residual fuels do not necessarily require heating for storage or 
pumping.
    Responsible corporate officer (RCO) has the meaning given in 40 CFR 
1090.80.
    Retail outlet means any establishment at which gasoline, diesel 
fuel, natural gas or liquefied petroleum gas is sold or offered for 
sale for use in motor vehicles or nonroad engines, including locomotive 
or marine engines.
    Retailer means any person who owns, leases, operates, controls, or 
supervises a retail outlet.
    RIN-generating foreign producer means a foreign renewable fuel 
producer that has been registered by EPA to generate RINs for renewable 
fuel it produces.
    RIN generator means any party allowed to generate RINs under this 
part.
    RIN-less RNG means RNG produced by a foreign RNG producer and for 
which RINs were not generated by the foreign RNG producer.
    RNG importer means any person who imports RNG into the covered 
location and generates RINs for the RNG as specified in Sec.  80.125.
    RNG producer means any person who owns, leases, operates, controls, 
or supervises an RNG production facility.
    RNG production facility means a facility where biogas is upgraded 
to RNG under an approved pathway.
    RNG RIN separator means any person registered to separate RINs for 
RNG under Sec.  80.125(d).
    RNG used as a feedstock or RNG as a feedstock means any RNG used to 
produce renewable fuel under Sec.  80.125.
    Separated food waste means a feedstock stream consisting of food 
waste kept separate since generation from other waste materials, and 
which includes food and beverage production waste and post-consumer 
food and beverage waste.
    Separated municipal solid waste or separated MSW means material 
remaining after separation actions have been taken to remove recyclable 
paper, cardboard, plastics, rubber, textiles, metals, and glass from 
municipal solid waste, and which is composed of both cellulosic and 
non-cellulosic materials.
    Separated RIN means a RIN with a K code of 2 that has been 
separated from a volume of renewable fuel or RNG pursuant to Sec.  
80.1429.
    Separated yard waste means a feedstock stream consisting of yard 
waste kept separate since generation from other waste materials.
    Slash is the residue, including treetops, branches, and bark, left 
on the ground after logging or accumulating as a result of a storm, 
fire, delimbing, or other similar disturbance.
    Small refinery means a refinery for which the average aggregate 
daily crude oil throughput (as determined by dividing the aggregate 
throughput for the calendar year by the number of days in the calendar 
year) does not exceed 75,000 barrels.
    Soapstock means an emulsion, or the oil obtained from separation of 
that emulsion, produced by washing oils listed as a feedstock in an 
approved pathway with water.
    Standard temperature and pressure (STP) means 60 degrees Fahrenheit 
and 1 atmosphere of pressure.
    Transportation fuel means fuel for use in motor vehicles, motor 
vehicle engines, nonroad vehicles, or nonroad engines (except fuel for 
use in ocean-going vessels).
    Treated biogas means a product that meets all the following 
requirements:
    (1) It is produced from biogas.
    (2) It does not require removal of additional components to be 
suitable for its designated use (e.g., as a biointermediate or to 
produce biogas-derived renewable fuel).
    (3) It is used in a biogas closed distribution system as a 
biointermediate or to produce biogas-derived renewable fuel.

[[Page 44562]]

    Tree plantation is a stand of no less than 1 acre composed 
primarily of trees established by hand- or machine-planting of a seed 
or sapling, or by coppice growth from the stump or root of a tree that 
was hand- or machine-planted. Tree plantations must have been cleared 
prior to December 19, 2007 and must have been actively managed on 
December 19, 2007, as evidenced by records which must be traceable to 
the land in question, which must include:
    (1) Sales records for planted trees or tree residue together with 
other written documentation connecting the land in question to these 
purchases;
    (2) Purchasing records for seeds, seedlings, or other nursery stock 
together with other written documentation connecting the land in 
question to these purchases;
    (3) A written management plan for silvicultural purposes;
    (4) Documentation of participation in a silvicultural program 
sponsored by a Federal, state, or local government agency;
    (5) Documentation of land management in accordance with an 
agricultural or silvicultural product certification program;
    (6) An agreement for land management consultation with a 
professional forester that identifies the land in question; or
    (7) Evidence of the existence and ongoing maintenance of a road 
system or other physical infrastructure designed and maintained for 
logging use, together with one of the above-mentioned documents.
    Tree residue is slash and any woody residue generated during the 
processing of planted trees from tree plantations for use in lumber, 
paper, furniture, or other applications, provided that such woody 
residue is not mixed with similar residue from trees that do not 
originate in tree plantations.
    Undenatured ethanol means a liquid that meets one of the 
definitions in paragraph (1) of this definition:
    (1)(i) Ethanol that has not been denatured as required in 27 CFR 
parts 19 through 21.
    (ii) Specially denatured alcohol as defined in 27 CFR 21.11.
    (2) Undenatured ethanol is not renewable fuel.
    United States has the meaning given in 40 CFR 1090.80.
    Verification status means a description of whether biogas, treated 
biogas, RNG, or a RIN has been verified under an EPA-approved quality 
assurance plan.
    Verified RIN means a RIN generated by a renewable fuel producer 
that was subject to a QAP audit executed by an independent third-party 
auditor, and determined by the independent third-party auditor to be 
valid. Verified RINs includes A-RINs, B-RINs, and Q-RINs.
    Wholesale purchaser-consumer means any person that is an ultimate 
consumer of gasoline, diesel fuel, natural gas, or liquefied petroleum 
gas and which purchases or obtains gasoline, diesel fuel, natural gas 
or liquefied petroleum gas from a supplier for use in motor vehicles or 
nonroad engines, including locomotive or marine engines and, in the 
case of gasoline, diesel fuel, or liquefied petroleum gas, receives 
delivery of that product into a storage tank of at least 550-gallon 
capacity substantially under the control of that person.

0
3. Add Sec.  80.3 to read as follows:

Sec.  80.3  Acronyms and abbreviations.

------------------------------------------------------------------------
 
------------------------------------------------------------------------
AB................................  Advanced biofuel.
APHA..............................  American Public Health Association.
API...............................  American Petroleum Institute.
ASTM..............................  ASTM International.
BBD...............................  Biomass-based diesel.
BMP...............................  Best management practices.
BOB...............................  Gasoline before oxygenate blending.
CAA...............................  Clean Air Act.
CB................................  Cellulosic biofuel.
CBOB..............................  Conventional gasoline before
                                     oxygenate blending.
CF................................  Converted fraction.
CG................................  Conventional gasoline.
CHP...............................  Combined heat and power.
CNG...............................  Compressed natural gas.
CPI-U.............................  Consumer Price Index for All Urban
                                     Consumers.
ECA...............................  Emission Control Area.
EDRR..............................  Early detection and rapid response.
EIA...............................  Energy Information Administration.
EMTS..............................  EPA Moderated Transaction System.
EPA...............................  Environmental Protection Agency.
EqV...............................  Equivalence value.
ERVO..............................  Exporter renewable volume
                                     obligation.
FE................................  Feedstock energy.
FFA...............................  Free-fatty acid.
GC................................  Gas chromatography.
GHG...............................  Greenhouse gas.
GTAB..............................  Gasoline treated as blendstock.
HACCP.............................  Hazard Analysis Critical Control
                                     Point.
HHV...............................  Higher heating value.
IBR...............................  Incorporation by reference.
ID................................  Identification.
kWh...............................  Kilowatt-hour.
LE................................  Limited exemption.
LHV...............................  Lower heating value.
LNG...............................  Liquified natural gas.
MSW...............................  Municipal solid waste.
MVNRLM............................  Motor vehicle, nonroad, locomotive,
                                     or marine.
NARA..............................  National Archives and Records
                                     Administration.
NTDF..............................  Non-transportation 15 ppm distillate
                                     fuel.
PIR...............................  Potentially invalid RIN.
PM10..............................  Particulate matter generally 10
                                     micrometers or smaller.
PM2.5.............................  Particulate matter generally 2.5
                                     micrometers or smaller.
PTD...............................  Product transfer document.
QAP...............................  Quality assurance plan.
RBOB..............................  Reformulated gasoline before
                                     oxygenate blending.
RCO...............................  Responsible corporate officer.
RF................................  Renewable fuel.
RFS...............................  Renewable Fuel Standard.
RFS-FRRF..........................  RFS foreign refiner renewable fuel.
RIN...............................  Renewable identification number.
RNG...............................  Renewable natural gas.
RVO...............................  Renewable volume obligation.
STP...............................  Standard temperature and pressure.
U.S...............................  United States.
ULSD..............................  Ultra-low-sulfur diesel fuel.
USDA..............................  United States Department of
                                     Agriculture.
UTC...............................  Coordinated Universal Time.
VCSB..............................  Voluntary consensus standards body.
------------------------------------------------------------------------

Sec.  80.4  [Amended]

0
4. Amend Sec.  80.4 by removing the text ``The Administrator or his 
authorized representative'' and adding in its place the text ``EPA''.

0
5. Amend Sec.  80.7 by:
0
a. Revising paragraph (a) introductory text;
0
b. In paragraph (b), removing the text ``the Administrator, the 
Regional Administrator, or their delegates'' and adding in its place 
the text ``EPA''; and
0
c. Revising the first sentence of paragraph (c).
    The revisions read as follows:

Sec.  80.7  Requests for information.

    (a) When EPA has reason to believe that a violation of section 
211(c) or section 211(n) of the Clean Air Act and the regulations 
thereunder has occurred, EPA may require any refiner, distributor, 
wholesale purchaser-consumer, or retailer to report the following 
information regarding receipt, transfer, delivery, or sale of gasoline 
represented to be unleaded gasoline and to allow the reproduction of 
such information at all reasonable times.
* * * * *
    (c) Any refiner, distributor, wholesale purchaser-consumer, 
retailer, or importer must provide such other information as EPA may 
reasonably require to enable the Agency to

[[Page 44563]]

determine whether such refiner, distributor, wholesale purchaser-
consumer, retailer, or importer has acted or is acting in compliance 
with sections 211(c) and 211(n) of the Clean Air Act and the 
regulations thereunder and must, upon request of EPA, produce and allow 
reproduction of any relevant records at all reasonable times. * * *
* * * * *

0
6. Revise Sec.  80.8 to read as follows:

Sec.  80.8  Sampling methods for gasoline, diesel fuel, fuel additives, 
and renewable fuels.

    (a) Manual sampling. Manual sampling of tanks and pipelines shall 
be performed according to the applicable procedures specified in ASTM 
D4057 (incorporated by reference, see Sec.  80.12).
    (b) Automatic sampling. Automatic sampling of petroleum products in 
pipelines shall be performed according to the applicable procedures 
specified in ASTM D4177 (incorporated by reference, see Sec.  80.12).
    (c) Sampling and sample handling for volatility measurement. 
Samples to be analyzed for Reid Vapor Pressure (RVP) shall be collected 
and handled according to the applicable procedures specified in ASTM 
D5842 (incorporated by reference, see Sec.  80.12).
    (d) Sample compositing. Composite samples shall be prepared using 
the applicable procedures specified in ASTM D5854 (incorporated by 
reference, see Sec.  80.12).

0
7. Revise Sec.  80.9 to read as follows:

Sec.  80.9  Rounding.

    (a) Test results and calculated values reported to EPA under this 
part must be rounded according to 40 CFR 1090.50(a) through (d).
    (b) Calculated values under this part may only be rounded when 
reported to EPA.
    (c) Reported values under this part must be submitted using forms 
and procedures specified by EPA.

0
8. Add Sec.  80.12 to subpart A to read as follows:

Sec.  80.12  Incorporation by reference.

    Certain material is incorporated by reference into this part with 
the approval of the Director of the Federal Register under 5 U.S.C. 
552(a) and 1 CFR part 51. All approved incorporation by reference (IBR) 
material is available for inspection at U.S. EPA and at the National 
Archives and Records Administration (NARA). Contact U.S. EPA at: U.S. 
EPA, Air and Radiation Docket and Information Center, WJC West 
Building, Room 3334, 1301 Constitution Ave. NW, Washington, DC 20460; 
(202) 566-1742. For information on the availability of this material at 
NARA, visit: www.archives.gov/federal-register/cfr/ibr-locations.html 
or email [email protected]. The material may be obtained from the 
following sources:
    (a) American Petroleum Institute (API), 200 Massachusetts Avenue 
NW, Suite 1100, Washington, DC 20001-5571; (202) 682-8000; www.api.org.
    (1) API MPMS 14.1-2016, Manual of Petroleum Measurement Standards 
Chapter 14--Natural Gas Fluids Measurement Section 1--Collecting and 
Handling of Natural Gas Samples for Custody Transfer, 7th Edition, May 
2016 (``API MPMS 14.1''); IBR approved for Sec.  80.155(b).
    (2) API MPMS 14.3.1-2012, Manual of Petroleum Measurement Standards 
Chapter 14.3.1--Orifice Metering of Natural Gas and Other Related 
Hydrocarbon Fluids--Concentric, Square[hyphen]edged Orifice Meters Part 
1: General Equations and Uncertainty Guidelines, 4th Edition, including 
Errata July 2013, Reaffirmed, July 2022 (``API MPMS 14.3.1''); IBR 
approved for Sec.  80.155(a).
    (3) API MPMS 14.3.2-2016, Manual of Petroleum Measurement Standards 
Chapter 14.3.2--Orifice Metering of Natural Gas and Other Related 
Hydrocarbon Fluids--Concentric, Square[hyphen]edged Orifice Meters Part 
2: Specification and Installation Requirements, 5th Edition, March 2016 
(``API MPMS 14.3.2''); IBR approved for Sec.  80.155(a).
    (4) API MPMS 14.3.3-2013, Manual of Petroleum Measurement Standards 
Chapter 14.3.3--Orifice Metering of Natural Gas and Other Related 
Hydrocarbon Fluids--Concentric, Square[hyphen]edged Orifice Meters Part 
3: Natural Gas Applications, 4th Edition, Reaffirmed, June 2021 (``API 
MPMS 14.3.3''); IBR approved for Sec.  80.155(a).
    (5) API MPMS 14.3.4-2019, Manual of Petroleum Measurement Standards 
Chapter 14.3.4--Orifice Metering of Natural Gas and Other Related 
Hydrocarbon Fluids--Concentric, Square[hyphen]edged Orifice Meters Part 
4--Background, Development, Implementation Procedure, and Example 
Calculations, 4th Edition, October 2019 (``API MPMS 14.3.4''); IBR 
approved for Sec.  80.155(a).
    (6) API MPMS 14.12-2017, Manual of Petroleum Measurement Standards 
Chapter 14--Natural Gas Fluid Measurement Section 12--Measurement of 
Gas by Vortex Meters, 1st Edition, March 2017 (``API MPMS 14.12''); IBR 
approved for Sec.  80.155(a).

    Note 1 to paragraph (a): API MPMS 14.3.1, 14.3.2, 14.3.3, and 
141.3.4, are co-published as AGA Report 3, Parts 1, 2, 3, and 4, 
respectively.

    (b) American Public Health Association (APHA), 1015 15th Street NW, 
Washington, DC 20005; (202) 777-2742; www.standardmethods.org.
    (1) SM 2540, revised June 10, 2020; IBR approved for Sec.  
80.155(c).
    (2) [Reserved]
    (c) ASTM International (ASTM), 100 Barr Harbor Dr., P.O. Box C700, 
West Conshohocken, PA 19428-2959; (877) 909-2786; www.astm.org.
    (1) ASTM D975-21, Standard Specification for Diesel Fuel, approved 
August 1, 2021 (``ASTM D975''); IBR approved for Sec. Sec.  80.2; 
80.1426(f); 80.1450(b); 80.1451(b); 80.1454(l).
    (2) ASTM D1250-19e1, Standard Guide for the Use of the Joint API 
and ASTM Adjunct for Temperature and Pressure Volume Correction Factors 
for Generalized Crude Oils, Refined Products, and Lubricating Oils: API 
MPMS Chapter 11.1, approved May 1, 2019 (``ASTM D1250''); IBR approved 
for Sec.  80.1426(f).
    (3) ASTM D3588-98 (Reapproved 2017)e1, Standard Practice for 
Calculating Heat Value, Compressibility Factor, and Relative Density of 
Gaseous Fuels, approved April 1, 2017 (``ASTM D3588''); IBR approved 
for Sec.  80.155(b) and (f).
    (4) ASTM D4057-12, Standard Practice for Manual Sampling of 
Petroleum and Petroleum Products, approved December 1, 2012 (``ASTM 
D4057''); IBR approved for Sec.  80.8(a).
    (5) ASTM D4177-95 (Reapproved 2010), Standard Practice for 
Automatic Sampling of Petroleum and Petroleum Products, approved May 1, 
2010 (``ASTM D4177''); IBR approved for Sec.  80.8(b).
    (6) ASTM D4442-20, Standard Test Methods for Direct Moisture 
Content Measurement of Wood and Wood-Based Materials, approved March 1, 
2020 (``ASTM D4442''); IBR approved for Sec.  80.1426(f).
    (7) ASTM D4444-13 (Reapproved 2018), Standard Test Method for 
Laboratory Standardization and Calibration of Hand-Held Moisture 
Meters, reapproved July 1, 2018 (``ASTM D4444''); IBR approved for 
Sec.  80.1426(f).
    (8) ASTM D4888-20, Standard Test Method for Water Vapor in Natural 
Gas Using Length-of-Stain Detector Tubes, approved December 15, 2020 
(``ASTM D4888''); IBR approved for Sec.  80.155(b).
    (9) ASTM D5504-20, Standard Test Method for Determination of Sulfur 
Compounds in Natural Gas and Gaseous Fuels by Gas Chromatography and 
Chemiluminescence, approved

[[Page 44564]]

November 1, 2020 (``ASTM D5504''); IBR approved for Sec.  80.155(b).
    (10) ASTM D5842-14, Standard Practice for Sampling and Handling of 
Fuels for Volatility Measurement, approved January 15, 2014 (``ASTM 
D5842''); IBR approved for Sec.  80.8(c).
    (11) ASTM D5854-96 (Reapproved 2010), Standard Practice for Mixing 
and Handling of Liquid Samples of Petroleum and Petroleum Products, 
approved May 1, 2010 (``ASTM D5854''); IBR approved for Sec.  80.8(d).
    (12) ASTM D6751-20a, Standard Specification for Biodiesel Fuel 
Blend Stock (B100) for Middle Distillate Fuels, approved August 1, 2020 
(``ASTM D6751''); IBR approved for Sec.  80.2.
    (13) ASTM D6866-22, Standard Test Methods for Determining the 
Biobased Content of Solid, Liquid, and Gaseous Samples Using 
Radiocarbon Analysis, approved March 15, 2022 (``ASTM D6866''); IBR 
approved for Sec. Sec.  80.155(b); 80.1426(f); 80.1430(e).
    (14) ASTM D7164-21, Standard Practice for On-line/At-line Heating 
Value Determination of Gaseous Fuels by Gas Chromatography, approved 
April 1, 2021 (``ASTM D7164''); IBR approved for Sec.  80.155(a).
    (15) ASTM D8230-19, Standard Test Method for Measurement of 
Volatile Silicon-Containing Compounds in a Gaseous Fuel Sample Using 
Gas Chromatography with Spectroscopic Detection, approved June 1, 2019 
(``ASTM D8230''); IBR approved for Sec.  80.155(b).
    (16) ASTM E711-87 (Reapproved 2004), Standard Test Method for Gross 
Calorific Value of Refuse-Derived Fuel by the Bomb Calorimeter, 
reapproved 2004 (``ASTM E711''); IBR approved for Sec.  80.1426(f).
    (17) ASTM E870-82 (Reapproved 2019), Standard Test Methods for 
Analysis of Wood Fuels, reapproved April 1, 2019 (``ASTM E870''); IBR 
approved for Sec.  80.1426(f).
    (d) European Committee for Standardization (CEN), Rue de la Science 
23, B-1040 Brussels, Belgium; + 32 2 550 08 11; www.cencenelec.eu.
    (1) EN 17526:2021(E), Gas meter--Thermal-mass flow-meter based gas 
meter, approved July 11, 2021 (``EN 17526''); IBR approved for Sec.  
80.155(a).
    (2) [Reserved]

0
9. Add subpart E, consisting of Sec. Sec.  80.100 through 80.185, to 
read as follows:
Subpart E--Biogas-Derived Renewable Fuel
Sec.
80.100 Scope and application.
80.105 Biogas producers.
80.110 RNG producers, RNG importers, and biogas closed distribution 
system RIN generators.
80.115 RNG RIN separators.
80.120 Parties that use biogas as a biointermediate or RNG as a 
feedstock or as process heat or energy.
80.125 RINs for RNG.
80.130 RINs for renewable CNG/LNG from a biogas closed distribution 
system.
80.135 Registration.
80.140 Reporting.
80.145 Recordkeeping.
80.150 Product transfer documents.
80.155 Sampling, testing, and measurement.
80.160 RNG importers, foreign biogas producers, and foreign RNG 
producers.
80.165 Attest engagements.
80.170 Quality assurance plan.
80.175 Prohibited acts and liability provisions.
80.180 Affirmative defense provisions.
80.185 Potentially invalid RINs.

Sec.  80.100  Scope and application.

    (a) Applicability.
    (1) The provisions of this subpart E apply to all the following:
    (i) Biogas.
    (ii) Treated biogas.
    (iii) Biogas-derived renewable fuel.
    (iv) RNG used to produce a biogas-derived renewable fuel.
    (v) RINs generated for RNG or a biogas-derived renewable fuel.
    (2) This subpart also specifies requirements for specified parties 
that engage in activities associated with the production, distribution, 
transfer, or use of biogas, treated biogas, biogas-derived renewable 
fuel, RNG used to produce a biogas-derived renewable fuel, and RINs 
generated for a biogas-derived renewable fuel under the RFS program.
    (b) Relationship to other fuels regulations. (1) The provisions of 
subpart M of this part also apply to the parties and products regulated 
under this subpart E.
    (2) The provisions of 40 CFR part 1090 include provisions that may 
apply to the parties and products regulated under this subpart E.
    (3) Parties and products subject to this subpart E may need to 
register a fuel or fuel additive under 40 CFR part 79.
    (c) Geographic scope. RINs must only be generated for biogas-
derived renewable fuel used in the covered location.
    (d) Implementation dates. (1) General. The provisions of this 
subpart E apply beginning July 1, 2024, unless otherwise specified.
    (2) Registration. (i) Parties not registered to generate RINs under 
Sec.  80.1426(f)(10)(ii) or (11)(ii) prior to July 1, 2024, must 
register with EPA under Sec.  80.135. EPA will not accept registration 
submissions for the generation of RINs under Sec.  80.1426(f)(10)(ii) 
and (11)(ii) on or after July 1, 2024.
    (ii) Parties registered to generate RINs under Sec.  
80.1426(f)(10)(ii) or (11)(ii) must submit updated registration 
information under Sec.  80.135 no later than October 1, 2024.
    (iii) Independent third-party engineers may conduct engineering 
reviews for parties required to register under Sec.  80.135 prior to 
July 1, 2024, as long as the engineering review satisfies all 
applicable requirements under Sec. Sec.  80.135 and 80.1450.
    (3) Generation of RINs for RNG. RNG producers may only generate 
RINs for RNG produced on or after July 1, 2024, as specified in Sec.  
80.125.
    (4) Generation of RINs for renewable CNG/LNG for previously 
registered facilities. (i)(A) Prior to January 1, 2025, RIN generators 
may generate RINs as specified in Sec.  80.1426(f)(10)(ii) or (11)(ii) 
for renewable CNG/LNG produced from a facility covered by a 
registration accepted by EPA under Sec.  80.1450(b) prior to July 1, 
2024.
    (B) Biogas or RNG produced under a registration accepted by EPA 
under Sec.  80.1450(b) for the generation of RINs as specified in Sec.  
80.1426(f)(10)(ii) or (11)(ii) prior to July 1, 2024, may only be used 
to generate RINs for renewable CNG/LNG.
    (ii) For biogas produced on or after January 1, 2025, biogas closed 
distribution system RIN generators must generate RINs for renewable 
CNG/LNG as specified in Sec.  80.130.
    (5) Generation of RINs for renewable fuel produced from biogas used 
as a biointermediate. Renewable fuel producers must only generate RINs 
for renewable fuel produced from biogas used as a biointermediate 
produced on or after July 1, 2024.

Sec.  80.105  Biogas producers.

    (a) General requirements. (1) Any biogas producer that produces 
biogas for use to produce RNG or a biogas-derived renewable fuel, or 
that produces biogas used as a biointermediate, must comply with the 
requirements of this section.
    (2) The biogas producer must also comply with all other applicable 
requirements of this part and 40 CFR part 1090.
    (3) If the biogas producer meets the definition of more than one 
type of regulated party under this part or 40 CFR part 1090, the biogas 
producer must comply with the requirements applicable to each of those 
types of regulated parties.
    (4) The biogas producer must comply with all applicable 
requirements of this part, regardless of whether the requirements are 
identified in this section.

[[Page 44565]]

    (b) Registration. The biogas producer must register with EPA under 
Sec. Sec.  80.135, 80.1450, and 40 CFR part 1090, subpart I, as 
applicable.
    (c) Reporting. The biogas producer must submit reports to EPA under 
Sec. Sec.  80.140 and 80.1451, as applicable.
    (d) Recordkeeping. The biogas producer must create and maintain 
records under Sec. Sec.  80.145 and 80.1454.
    (e) PTDs. On each occasion when the biogas producer transfers title 
of any biogas, the transferor must provide to the transferee PTDs under 
Sec.  80.150.
    (f) Sampling, testing, and measurement.
    (1) All sampling, testing, and measurements must be done in 
accordance with Sec.  80.155.
    (2)(i) A biogas producer must measure the volume of biogas, in Btu 
HHV, prior to converting biogas to any of the following:
    (A) RNG.
    (B) Treated biogas.
    (C) Biointermediate.
    (D) Biogas-derived renewable fuel.
    (E) Process heat or energy under Sec.  80.1426(f)(12) or (13).
    (ii) Except for biogas produced from a mixed digester, a biogas 
producer must measure the volume of biogas, in Btu HHV, for each batch 
pathway prior to mixing with biogas produced under a different batch 
pathway or with non-qualifying gas.
    (iii) For biogas produced from a mixed digester, a biogas producer 
must do all the following for each mixed digester:
    (A) Measure the volume of biogas, in Btu HHV, prior to mixing with 
any other gas.
    (B) Measure the daily mass of the cellulosic biogas feedstock, in 
pounds, added to the mixed digester.
    (C) Collect a daily representative sample of each cellulosic biogas 
feedstock and test for total solids and volatile solids as specified in 
Sec.  80.155(c).
    (D) Measure and calculate the digester operating conditions as 
specified in Sec.  80.155(d).
    (iv) A biogas producer must measure each volume of gas containing 
biogas, in Btu HHV, that leaves the facility.
    (g) Foreign biogas producer requirements. A foreign biogas producer 
must meet all the requirements that apply to a biogas producer under 
this part, as well as the additional requirements for foreign biogas 
producers specified in Sec.  80.160.
    (h) Attest engagements. The biogas producer must submit annual 
attest engagement reports to EPA under Sec. Sec.  80.165 and 80.1464 
using procedures specified in 40 CFR 1090.1800 and 1090.1805.
    (i) QAP. Prior to the generation of Q-RINs for a biogas-derived 
renewable fuel, the biogas producer must meet all applicable 
requirements specified in Sec.  80.170.
    (j) Batches. (1) Except for biogas produced from a mixed digester, 
the batch volume of biogas is the volume of biogas measured under 
paragraph (f) of this section for a single batch pathway at a single 
facility for a calendar month, in Btu HHV.
    (2) For biogas produced from a mixed digester, the batch volume of 
biogas must be calculated as follows:
    (i) The batch volume of biogas produced under an approved pathway 
with a D code of 5 must be calculated as follows:

VBG,D5 = VBG-VBG,D3/7

Where:

    VBG,D5 = The batch volume of biogas for an approved 
pathway with a D code of 5 for the calendar month, in Btu HHV. If 
the result of this equation is negative, then VBG,D5,p 
equals 0.
VBG = The total volume of biogas produced by the mixed 
digester for the calendar month, in Btu HHV, as measured under 
paragraph (f)(2)(iii)(A) of this section.
VBG,D3/7 = The total batch volume of biogas produced 
under approved pathways with a D code of 3 or 7 for the calendar 
month, in Btu HHV, per paragraph (j)(2)(ii) of this section.

    (ii) The batch volume of biogas produced under an approved pathway 
with a D code of 3 or 7 must be calculated as follows:

VBG,D3/7,p = BED3/7,i
VBG,D3/7,p = The batch volume of biogas for batch pathway 
p with a D code of 3 or 7 for the calendar month, in Btu HHV.
BED3/7,i = The total energy from cellulosic biogas 
feedstock i that forms energy in the biogas and whose batch pathway 
has been assigned a D code of 3 or 7 for the calendar month, in Btu 
HHV, per paragraph (j)(2)(iii) of this section.

    (iii) The biogas energy value for each cellulosic biogas feedstock 
must be calculated as follows:

BED3/7,i,j = Mi,j * TSi,j * 
VSi,j * CFi,j

Where:

BED3/7,i,j = The amount of energy from cellulosic biogas 
feedstock i that forms energy in the biogas and whose batch pathway 
has been assigned a D code of 3 or 7 on day j, in Btu HHV.
Mi,j = Mass of cellulosic biogas feedstock i, in pounds, 
measured on day j, per paragraph (f)(2)(iii)(B) of this section.
TSi,j = Total solids of cellulosic biogas feedstock i, as 
a mass fraction, in pounds total solids per pound feedstock, for the 
sample obtained on day j, per paragraph (f)(2)(iii)(C) of this 
section. If sample results are not available, then TSi,j 
equals 0.
VSi,j = Volatile solids of cellulosic biogas feedstock i, 
as a mass fraction, in pounds volatile solids per pound total 
solids, for the sample obtained on day j, per paragraph 
(f)(2)(iii)(C) of this section. If sample results are not available, 
then VSi,j equals 0.
CFi,j = Converted fraction in annual average Btu HHV/lb, 
representing the portion of cellulosic biogas feedstock i that is 
converted to biomethane by the producer on day j, per paragraph 
(j)(2)(iv) of this section. If data for digester operating 
conditions required under paragraph (f)(2)(iii)(D) of this section 
are outside the range of operating conditions specified in paragraph 
(j)(2)(v) of this section or such data to determine the operating 
conditions does not meet the requirements in Sec.  80.155(d), then 
CFi,j equals 0.

    (iv) Biogas producers must use one of the following cellulosic 
conversion factors, as applicable:
    (A) Swine manure: 1,936 Btu HHV/lb.
    (B) Bovine manure: 2,077 Btu HHV/lb.
    (C) Chicken manure: 3,001 Btu HHV/lb.
    (D) Municipal wastewater treatment sludge: 3,479 Btu HHV/lb.
    (E) A cellulosic conversion factor accepted at registration under 
Sec.  80.135(c)(10)(vi).
    (v) Applicable operating conditions for the cellulosic converted 
fractions specified in paragraph (j)(2)(iv) of this section are the 
following:
    (A) For the cellulosic converted fraction values specified in 
paragraphs (j)(2)(iv)(A) through (D) of this section, the mixed 
digester must continuously operate above 95 degrees Fahrenheit with 
hydraulic and solids mean residence times greater than 20 days.
    (B) For the cellulosic converted fraction value specified in 
paragraph (j)(2)(iv)(E) of this section, the mixed digester must 
operate according to the conditions accepted at registration under 
Sec.  80.135(c)(10)(vi)(A)(4).
    (3) The biogas producer must assign a number (the ``batch number'') 
to each batch of biogas consisting of their EPA-issued company 
registration number, the EPA-issued facility registration number, the 
last two digits of the calendar year in which the batch was produced, 
and a unique number for the batch, beginning with the number one for 
the first batch produced each calendar year and each subsequent batch 
during the calendar year being assigned the next sequential number 
(e.g., 4321-54321-23-000001, 4321-54321-23-000002, etc.).
    (k) Limitations. (1) For each biogas production facility, the 
biogas producer must only supply biogas for only one of the following 
uses:
    (i) Production of renewable CNG/LNG via a biogas closed 
distribution system.
    (ii) As a biointermediate via a biogas closed distribution system.

[[Page 44566]]

    (iii) Production of RNG.
    (2) For each biogas production facility producing biogas for use as 
a biointermediate in a biogas closed distribution system, the biogas 
producer must only supply biogas or treated biogas to a single 
renewable fuel production facility.
    (3) If the biogas producer operates a municipal wastewater 
treatment facility digester, the biogas producer must not introduce any 
feedstocks into that digester that do not contain at least 75% average 
adjusted cellulosic content.
    (4) The transfer and batch segregation limits specified in Sec.  
80.1476(g) do not apply.

Sec.  80.110  RNG producers, RNG importers, and biogas closed 
distribution system RIN generators.

    (a) General requirements. (1) Any RNG producer, RNG importer, or 
biogas closed distribution system RIN generator that generates RINs 
must comply with the requirements of this section.
    (2) The RNG producer, RNG importer, or biogas closed distribution 
system RIN generator must also comply with all other applicable 
requirements of this part and 40 CFR part 1090.
    (3) If the RNG producer, RNG importer, or biogas closed 
distribution system RIN generator meets the definition of more than one 
type of regulated party under this part or 40 CFR 1090, the RNG 
producer, RNG importer, or biogas closed distribution system RIN 
generator must comply with the requirements applicable to each of those 
types of regulated parties.
    (4) The RNG producer, RNG importer, or biogas closed distribution 
system RIN generator must comply with all applicable requirements of 
this part, regardless of whether the requirements are identified in 
this section.
    (5) The transfer and batch segregation limits specified in Sec.  
80.1476(g) do not apply.
    (b) Registration. The RNG producer, RNG importer, or biogas closed 
distribution system RIN generator must register with EPA under 
Sec. Sec.  80.135, 80.1450, and 40 CFR part 1090, subpart I, as 
applicable.
    (c) Reporting. The RNG producer, RNG importer, or biogas closed 
distribution system RIN generator must submit reports to EPA under 
Sec. Sec.  80.140, 80.1451, and 80.1452, as applicable.
    (d) Recordkeeping. The RNG producer, RNG importer, or biogas closed 
distribution system RIN generator must create and maintain records 
under Sec. Sec.  80.145 and 80.1454.
    (e) PTDs. On each occasion when the RNG producer, RNG importer, or 
biogas closed distribution system RIN generator transfers RNG, 
renewable fuel, or RINs to another party, the transferor must provide 
to the transferee PTDs under Sec. Sec.  80.150 and 80.1453, as 
applicable.
    (f) Sampling, testing, and measurement. (1) All sampling, testing, 
and measurements must be done in accordance with Sec.  80.155.
    (2)(i) An RNG producer must measure the volume of RNG, in Btu LHV, 
prior to injection of RNG from the RNG production facility into a 
natural gas commercial pipeline system.
    (ii) An RNG producer that trucks RNG from the RNG production 
facility to a pipeline interconnect must measure the volume of RNG, in 
Btu LHV, upon loading and unloading of each truck.
    (iii) An RNG producer that injects RNG from an RNG production 
facility into a natural gas commercial pipeline system must sample and 
test a representative sample of all the following at least once per 
calendar year, as applicable:
    (A) Biogas used to produce RNG.
    (B) RNG before blending with non-renewable components.
    (C) RNG after blending with non-renewable components.
    (iv) A party that upgrades biogas to treated biogas must separately 
measure all the following, as applicable:
    (A) The volume of biogas, in Btu HHV, used to produce treated 
biogas, a biogas-derived renewable fuel, or as a biointermediate.
    (B) The volume of treated biogas, in Btu HHV, prior to addition of 
any non-renewable components.
    (C) The volume of biointermediate or biogas-derived renewable fuel 
produced from the biogas or treated biogas. If the biogas-derived 
renewable fuel is renewable CNG/LNG, then this volume must be measured 
in both Btu HHV and Btu LHV.
    (3) A biogas closed distribution RIN generator must measure 
renewable CNG/LNG in Btu LHV.
    (g) Foreign RNG producer, RNG importer, and foreign biogas closed 
distribution system RIN generator requirements. (1)(i) A foreign RNG 
producer must meet all the requirements that apply to an RNG producer 
under this part, as well as the additional requirements for foreign RNG 
producers specified in Sec.  80.160.
    (ii) A foreign RNG producer must either generate RINs under Sec.  
80.125 or enter into a contract with an RNG importer as specified in 
Sec.  80.160(e).
    (2) An RNG importer must meet all the requirements specified in 
Sec.  80.160(h).
    (3) A foreign biogas closed distribution system RIN generator must 
meet all the requirements that apply to a biogas closed distribution 
system RIN generator under this part, as well as the additional 
requirements for foreign biogas closed distribution system RIN 
generators specified in Sec.  80.160 and for RIN-generating foreign 
renewable fuel producers specified in Sec.  80.1466.
    (h) Attest engagements. The RNG producer, RNG importer, or biogas 
closed distribution system RIN generator must submit annual attest 
engagement reports to EPA under Sec. Sec.  80.165 and 80.1464 using 
procedures specified in 40 CFR 1090.1800 and 1090.1805.
    (i) QAP. Prior to the generation of a Q-RIN for RNG or biogas-
derived renewable fuel, the RNG producer, RNG importer, or biogas 
closed distribution system RIN generator must meet all applicable 
requirements specified in Sec.  80.170.
    (j) Batches. (1) A batch of RNG is the total volume of RNG produced 
at an RNG production facility under a single batch pathway for the 
calendar month, in Btu LHV, as determined under paragraph (j)(4) of 
this section.
    (2) A batch of biogas-derived renewable fuel must comply with the 
requirements specified in Sec.  80.1426(d).
    (3) The RNG producer, RNG importer, or biogas closed distribution 
system RIN generator must assign a number (the ``batch number'') to 
each batch of RNG or biogas-derived renewable fuel consisting of their 
EPA-issued company registration number, the EPA-issued facility 
registration number, the last two digits of the calendar year in which 
the batch was produced, and a unique number for the batch, beginning 
with the number one for the first batch produced each calendar year and 
each subsequent batch during the calendar year being assigned the next 
sequential number (e.g., 4321-54321-23-000001, 4321-54321-23-000002, 
etc.).
    (4) The batch volume of RNG must be calculated as follows:
    [GRAPHIC] [TIFF OMITTED] TR12JY23.006
    
Where:

VRNG,p = The batch volume of RNG for batch pathway p, in 
Btu LHV.
VNG = The total volume of natural gas produced at the RNG 
production facility for the calendar month, in Btu LHV, as measured 
under Sec.  80.155.
VBG,p = The total volume of biogas used to produce RNG 
under batch pathway p for the calendar month, in Btu HHV, per Sec.  
80.105(j).
VBG,total = The total volume of biogas used to produce 
RNG under all batch pathways for the calendar month, in Btu HHV, per 
Sec.  80.105(j).

[[Page 44567]]

R = The renewable fraction of the natural gas produced at the RNG 
production facility for the calendar month. For natural gas produced 
only from renewable feedstocks, R is equal to 1. For natural gas 
produced from both renewable and non-renewable feedstocks, R must be 
measured by a carbon-14 dating test method, per Sec.  80.1426(f)(9).

Sec.  80.115  RNG RIN separators.

    (a) General requirements. (1) Any RNG RIN separator must comply 
with the requirements of this section.
    (2) The RNG RIN separator must also comply with all other 
applicable requirements of this part and 40 CFR part 1090.
    (3) If the RNG RIN separator meets the definition of more than one 
type of regulated party under this part or 40 CFR 1090, the RNG RIN 
separator must comply with the requirements applicable to each of those 
types of regulated parties.
    (4) The RNG RIN separator must comply with all applicable 
requirements of this part, regardless of whether the requirements are 
identified in this section.
    (b) Registration. (1) The RNG RIN separator must register with EPA 
under Sec. Sec.  80.135, 80.1450, and 40 CFR part 1090, subpart I, as 
applicable.
    (2) A dispensing location may only be included in one RNG RIN 
separator's registration at a time.
    (c) Reporting. The RNG RIN separator must submit reports to EPA 
under Sec. Sec.  80.140, 80.1451, and 80.1452, as applicable.
    (d) Recordkeeping. The RNG RIN separator must create and maintain 
records under Sec. Sec.  80.145 and 80.1454.
    (e) PTDs. On each occasion when the RNG RIN separator transfers 
title of renewable fuel and RINs to another party, the transferor must 
provide to the transferee PTDs under Sec.  80.1453.
    (f) Measurement. (1) All measurements must be done in accordance 
with Sec.  80.155.
    (2) An RNG RIN separator must measure the volume of natural gas, in 
Btu LHV, withdrawn from the natural gas commercial pipeline system.
    (g) Attest engagements. The RNG RIN separator must submit annual 
attest engagement reports to EPA under Sec. Sec.  80.165 and 80.1464 
using procedures specified in 40 CFR 1090.1800 and 1090.1805.

Sec.  80.120  Parties that use biogas as a biointermediate or RNG as a 
feedstock or as process heat or energy.

    (a) General requirements. (1) Any renewable fuel producer that uses 
biogas as a biointermediate or RNG as a feedstock or as process heat or 
energy under Sec.  80.1426(f)(12) or (13) must comply with the 
requirements of this section.
    (2) The renewable fuel producer must also comply with all other 
applicable requirements of this part and 40 CFR part 1090.
    (3) If the renewable fuel producer meets the definition of more 
than one type of regulated party under this part or 40 CFR 1090, the 
renewable fuel producer must comply with the requirements applicable to 
each of those types of regulated parties.
    (4) The renewable fuel producer must comply with all applicable 
requirements of this part, regardless of whether they are identified in 
this section.
    (5) The transfer and batch segregation limits specified in Sec.  
80.1476(g) do not apply.
    (b) Registration. The renewable fuel producer must register with 
EPA under Sec. Sec.  80.135, 80.1450, and 40 CFR part 1090, subpart I, 
as applicable.
    (c) Reporting. The renewable fuel producer must submit reports to 
EPA under Sec. Sec.  80.140, 80.1451, and 80.1452, as applicable.
    (d) Recordkeeping. The renewable fuel producer must create and 
maintain records under Sec. Sec.  80.145 and 80.1454.
    (e) PTDs. On each occasion when the renewable fuel producer 
transfers title of biogas-derived renewable fuel and RINs to another 
party, the transferor must provide to the transferee PTDs under 
Sec. Sec.  80.150 and 80.1453.
    (f) Measurement. (1) All measurements must be done in accordance 
with Sec.  80.155.
    (2) A renewable fuel producer must measure the volume of natural 
gas, in Btu LHV, withdrawn from the natural gas commercial pipeline 
system.
    (g) Attest engagements. The renewable fuel producer must submit 
annual attest engagement reports to EPA under Sec. Sec.  80.165 and 
80.1464 using procedures specified in 40 CFR 1090.1800 and 1090.1805.
    (h) QAP. Prior to the generation of a Q-RIN for biogas-derived 
renewable fuel produced from biogas used as a biointermediate or RNG 
used as a feedstock, the renewable fuel producer must meet all 
applicable requirements specified in Sec.  80.170.

Sec.  80.125  RINs for RNG.

    (a) General requirements. (1) Any party that generates, assigns, 
transfers, receives, separates, or retires RINs for RNG must comply 
with the requirements of this section.
    (2) Any party that transacts RINs for RNG under this section must 
transact the RINs as specified in Sec.  80.1452.
    (b) RIN generation. (1) Only RNG producers may generate RINs for 
RNG injected into a natural gas commercial pipeline system.
    (2) RNG producers must generate RINs for only the biomethane 
content of biogas supplied by a biogas producer registered under Sec.  
80.135.
    (3) RNG producers must generate RINs using the applicable 
requirements for RIN generation in Sec.  80.1426.
    (4) If non-renewable components are blended into RNG, the RNG 
producer must generate RINs for only the biomethane content of the RNG 
prior to blending.
    (5) RNG producers must use the measurement procedures specified in 
Sec.  80.155 to determine the heating value of RNG for the generation 
of RINs.
    (6) The number of RINs generated for a batch volume of RNG under 
each batch pathway must be calculated as follows:
[GRAPHIC] [TIFF OMITTED] TR12JY23.007

Where:

RINRNG,p = The number of RINs generated for a batch of 
RNG under batch pathway p, in gallon-RINs.
VRNG,p = The batch volume of RNG for batch pathway p, in 
Btu LHV, per Sec.  80.110(j)(4).
EqVRNG = The equivalence value for RNG, in Btu LHV per 
RIN, per Sec.  80.1415(b)(5).

    (7) When RNG is injected from multiple RNG production facilities at 
a pipeline interconnect, the total number of RINs generated must not be 
greater than the total number of RINs eligible to be generated under 
Sec.  80.1415(b)(5) for the total volume of RNG injected by all RNG 
production facilities at that pipeline interconnect.
    (8) For RNG that is trucked prior to injection into a natural gas 
commercial pipeline system, the total volume of RNG injected for the 
calendar month, in Btu LHV, must not be greater than the lesser of the 
total loading or unloading volume measurement for the month, in Btu 
LHV, as required under Sec.  80.110(f)(2)(ii).
    (9) Renewable fuel producers that retire RINs for RNG used as a 
feedstock under paragraph (e) of this section may only generate RINs 
for the renewable fuel produced from RNG if all applicable requirements 
under this part are met.
    (c) RIN assignment and transfer. (1) RNG producers must assign the 
RINs generated for a batch of RNG to the specific volume of RNG 
injected into the natural gas commercial pipeline system.
    (2) Except as specified in paragraph (c)(1) of this section, no 
party may assign a RIN to a volume of RNG.
    (3) Each party that transfers title of a volume of RNG to another 
party must

[[Page 44568]]

transfer title of any assigned RINs for the volume of RNG to the 
transferee.
    (d) RIN separation. (1) Only the following parties may separate a 
RIN from RNG:
    (i) The party that withdrew the RNG from the natural gas commercial 
pipeline system.
    (ii) The party that produced or oversaw the production of the 
renewable CNG/LNG from the RNG.
    (iii) The party that used or dispensed for use the renewable CNG/
LNG as transportation fuel.
    (2) An RNG RIN separator must only separate a RIN from RNG if all 
the following requirements are met:
    (i) The RNG used to produce the renewable CNG/LNG was measured 
using the procedures specified in Sec.  80.155.
    (ii) The RNG RIN separator has the following documentation 
demonstrating that the volume of renewable CNG/LNG was used as 
transportation fuel:
    (A) If the RNG RIN separator sold or used the renewable CNG/LNG, 
records demonstrating the date, location, and volume of renewable CNG/
LNG sold or used as transportation fuel.
    (B) If the RNG RIN separator is relying on documentation from 
another party, all the following as applicable:
    (1) A written contract with the other party for the sale or use of 
the renewable CNG/LNG as transportation fuel.
    (2) Records from the other party demonstrating the date, location, 
and volume of renewable CNG/LNG sold or used as transportation fuel.
    (3) An affidavit from each other party confirming all the 
following:
    (i) That the volume of renewable CNG/LNG was used as transportation 
fuel and for no other purpose.
    (ii) That the party will not separate RINs for this volume of RNG.
    (iii) That the party has not provided affidavits to any other party 
for the purpose of complying with the requirements of this paragraph 
(d)(2)(ii).
    (iii) The volume of RNG was only used to produce renewable CNG/LNG 
that is used as transportation fuel and for no other purpose.
    (iv) No other party used the measurement information under 
paragraph (d)(2)(i) of this section or the information required under 
paragraph (d)(2)(ii) of this section to separate RINs for the RNG.
    (v) No other party has separated RINs for the RNG using the same 
dispensing location during the calendar month.
    (vi) The RNG RIN separator follows the applicable provisions under 
Sec.  80.1429(a), (b)(10), and (c) through (e).
    (3) An obligated party must not separate RINs for RNG under Sec.  
80.1429(b)(1) unless the obligated party meets the requirements in 
paragraph (d)(1) of this section.
    (4) A party must only separate a number of RINs equal to the total 
volume of RNG (where the Btu LHV are converted to gallon-RINs using the 
conversion specified in Sec.  80.1415(b)(5)) that the party 
demonstrates is used as renewable CNG/LNG under paragraph (d)(2) of 
this section.
    (e) RIN retirement. (1) A party must retire RINs generated for RNG 
if any of the conditions specified in Sec.  80.1434(a) apply and must 
comply with Sec.  80.1434(b).
    (2)(i) A party must retire all assigned RINs for a volume of RNG if 
the RINs are not separated under paragraph (d) of this section by the 
date the assigned RINs expire under Sec.  80.1428(c).
    (ii) A party must retire any expired RINs under paragraph (e)(2)(i) 
of this section by March 31 of the subsequent year. For example, if an 
RNG producer assigns RINs for RNG in 2025, the RINs expire if they are 
not separated under paragraph (d) of this section by December 31, 2026, 
and must be retired by March 31, 2027.
    (3) A party that uses RNG for a purpose other than to produce 
renewable CNG/LNG (e.g., as a feedstock, as process heat under Sec.  
80.1426(f)(12), or as process energy under Sec.  80.1426(f)(13)) must 
retire any assigned RINs for the volume of RNG within 5 business days 
of such use of the RNG.

Sec.  80.130  RINs for renewable CNG/LNG from a biogas closed 
distribution system.

    (a) General requirements. (1) Any party that generates, assigns, 
separates, or retires RINs for renewable CNG/LNG from a biogas closed 
distribution system must comply with the requirements of this section.
    (2) Parties must report all RIN transactions to EMTS as specified 
in Sec.  80.1452.
    (b) RIN generation. (1) Biogas closed distribution system RIN 
generators must generate RINs using the applicable requirements for RIN 
generation in under this part.
    (2) RINs for renewable CNG/LNG from a biogas closed distribution 
system may be generated if all the following requirements are met:
    (i) The renewable CNG/LNG is produced from renewable biomass and 
qualifies to generate RINs under an approved pathway.
    (ii) The biogas closed distribution system RIN generator has 
entered into a written contract for the sale or use of a specific 
quantity of renewable CNG/LNG for use as transportation fuel, and has 
obtained affidavits from all parties selling or using the renewable 
CNG/LNG certifying that the renewable CNG/LNG was used as 
transportation fuel.
    (iii) The renewable CNG/LNG is used as transportation fuel and for 
no other purpose.
    (c) RIN separation. A biogas closed distribution system RIN 
generator must separate RINs generated for renewable CNG/LNG under 
Sec.  80.1429(b)(5)(ii).
    (d) RIN retirement. A party must retire RINs generated for 
renewable CNG/LNG from a biogas closed distribution if any of the 
conditions specified in Sec.  80.1434(a) apply and must comply with 
Sec.  80.1434(b).

Sec.  80.135  Registration.

    (a) Applicability. The following parties must register using the 
procedures specified in this section, Sec.  80.1450 and 40 CFR 
1090.800:
    (1) Biogas producers.
    (2) RNG producers.
    (3) RNG importers.
    (4) Biogas closed distribution system RIN generators.
    (5) RNG RIN separators.
    (6) Renewable fuel producers using biogas as a biointermediate or 
RNG as a feedstock.
    (b) General registration requirements. Parties must submit 
applicable information for companies and facilities as specified in 40 
CFR 1090.805.
    (1) New registrants. (i) Parties required to register under this 
subpart must have an EPA-accepted registration prior to engaging in 
regulated activities under this subpart.
    (ii) Registration information must be submitted at least 60 days 
prior to engaging in regulated activities under this subpart.
    (iii) Parties may engage in regulated activities under this subpart 
once EPA has accepted their registration and they have met all other 
applicable requirements under this subpart.
    (2) Existing renewable CNG/LNG registrations. (i) Parties listed in 
paragraph (a) of this section must submit updated registration 
information that complies with the applicable requirements of this 
section for any company or facility covered by a registration accepted 
under Sec.  80.1450(b) for the generation of RINs under Sec.  
80.1426(f)(10)(ii) or (11)(ii) no later than October 1, 2024.
    (ii) A biogas closed distribution system RIN generator or biogas 
producer does not need to submit an updated engineering review for any 
facility in the biogas closed distribution system as specified in Sec.  
80.1450(d)(1) before the next three-year engineering review update is 
due as specified in Sec.  80.1450(d)(3).

[[Page 44569]]

    (3) Engineering reviews. (i) Any party required to register a 
facility under this section must undergo all the following:
    (A) A third-party engineering review as specified in Sec.  
80.1450(b)(2).
    (B) Three-year engineering review updates as specified in Sec.  
80.1450(d)(3).
    (ii) Third-party engineering reviews and three-year engineering 
review updates required under paragraph (b)(3)(i) of this section must 
evaluate all applicable registration information submitted under this 
section as well as all applicable requirements in Sec.  80.1450(b).
    (iii) A party may arrange for an independent third-party engineer 
to conduct a single site visit and submit a single engineering review 
report for a facility that performs multiple activities (e.g., a 
facility that both produces biogas and upgrades it to RNG) under this 
subpart as long as the site visit and engineering review report 
includes all the requirements for each activity performed.
    (4) Registration updates. (i) Parties registered under this section 
must submit updated registration information to EPA within 30 days when 
any of the following occur:
    (A) The registration information previously supplied becomes 
incomplete or inaccurate.
    (B) Facility information is updated under Sec.  80.1450(d)(1), as 
applicable.
    (C) A change of ownership is submitted under 40 CFR 1090.820.
    (ii) Parties registered under this section must submit updated 
registration information to EPA within 7 days when any facility 
information is updated under Sec.  80.1450(d)(2).
    (iii) Parties that register a facility under this section must 
update their registration information and undergo a three-year 
engineering review update as specified in Sec.  80.1450(d)(3).
    (5) Registration deactivations. EPA may deactivate the registration 
of a party registered under this section as specified in Sec.  
80.1450(h), 40 CFR 1090.810, or 40 CFR 1090.815, as applicable.
    (c) Biogas producer. In addition to the information required under 
paragraph (b) of this section, a biogas producer must submit all the 
following information for each biogas production facility:
    (1) Information describing the biogas production capacity for the 
biogas production facility, in Btu HHV, including the following:
    (i) Information regarding the permitted capacity in the most recent 
applicable air permits issued by EPA, a state, a local air pollution 
control agency, or a foreign governmental agency that governs the 
biogas production facility, if available.
    (ii) Documents demonstrating the biogas production facility's 
nameplate capacity.
    (iii) Information describing the biogas production facility's 
biogas production for each of the last three calendar years prior to 
the registration submission, if available.
    (2) Whether the biogas will be used to produce RNG, renewable CNG/
LNG, or biointermediate and information identifying the facility that 
will be supplied.
    (3) The following information related to biogas measurement:
    (i) A description of how biogas will be measured under Sec.  
80.155(a), including the specific standards under which the meters are 
operated.
    (ii) A description of the biogas production process, including a 
process flow diagram that includes metering type(s) and location(s).
    (iii) For an alternative measurement protocol under Sec.  
80.155(a)(3), all the following:
    (A) A description of why the biogas producer is unable to use 
meters that comply with the requirements specified in Sec.  
80.155(a)(1) and (2), as applicable.
    (B) A description of how measurement is conducted.
    (C) Any standards or specifications that apply.
    (D) A description of all routine maintenance and the frequency that 
such maintenance will be conducted.
    (E) A description of the frequency of all measurements and how 
often such measurements will be recorded under the alternative 
measurement protocol.
    (F) A comparison between the accuracy, precision, and reliability 
of the alternative measurement protocol and the requirements specified 
in Sec.  80.155(a)(1) and (2), as applicable, including any supporting 
data.
    (4) For biogas used to produce renewable CNG/LNG in a biogas closed 
distribution system, all the following additional information:
    (i) A process flow diagram of each step of the physical process 
from feedstock entry to the point where the renewable CNG/LNG is 
dispensed as transportation fuel. This includes all the following:
    (A) Feedstock processing.
    (B) Biogas production.
    (C) Biogas processing.
    (D) Renewable CNG/LNG production.
    (E) Points where non-renewable natural gas may be added.
    (F) Dispensing stations.
    (G) Measurement locations and equipment.
    (H) Major equipment (e.g., tanks, pipelines, flares, separation 
equipment, compressors, and dispensing infrastructure).
    (I) Any other process-related information as requested by EPA.
    (ii) A description of losses of heating content going from biogas 
to renewable CNG/LNG and an explanation of how such losses would be 
accounted for.
    (iii) A description of the physical process from biogas production 
to dispensing of renewable CNG/LNG as transportation fuel, including 
the biogas closed distribution system.
    (iv) A description of the vehicle fleet and dispensing stations 
that are expected to use and distribute the renewable CNG/LNG as 
transportation fuel.
    (5) For biogas used as a biointermediate, all the information 
specified in Sec.  80.1450(b)(1)(ii)(B).
    (6) For biogas used to produce RNG, all the following additional 
information:
    (i) The RNG producer that will upgrade the biogas.
    (ii) A process flow diagram of the physical process from biogas 
production to entering the RNG production facility, including major 
equipment (e.g., tanks, pipelines, flares, separation equipment).
    (iii) A description of the physical process from biogas production 
to entering the RNG production facility, including an explanation of 
how the biogas reaches the RNG production facility.
    (7) For biogas produced in an agricultural digester, all the 
following information:
    (i) A separated yard waste plan specified in Sec.  
80.1450(b)(1)(vii)(A), as applicable.
    (ii) Crop residue information specified in Sec.  80.1450(b)(1)(xv), 
as applicable.
    (iii) A process flow diagram of the physical process from feedstock 
entry to biogas production, including major equipment (e.g., feedstock 
preprocessing equipment, tanks, digesters, pipelines, flares).
    (8) For biogas produced in a municipal wastewater treatment 
facility digester, a process flow diagram of the physical process from 
feedstock entry to biogas production, including major equipment (e.g., 
feedstock preprocessing equipment, tanks, digesters, pipelines, 
flares).
    (9) For biogas produced in a separated MSW digester, all the 
following information:
    (i) Separated MSW plan specified in Sec.  80.1450(b)(1)(viii).
    (ii) A process flow diagram of the physical process from feedstock 
entry to biogas production, including major equipment (e.g., feedstock 
preprocessing equipment, tanks, digesters, pipelines, flares).

[[Page 44570]]

    (10) For biogas produced in other waste digesters, all the 
following information, as applicable:
    (i) A separated MSW plan specified in Sec.  80.1450(b)(1)(viii).
    (ii) A separated yard waste plan specified in Sec.  
80.1450(b)(1)(vii)(A).
    (iii) Crop residues information specified in Sec.  
80.1450(b)(1)(xv).
    (iv) A separated food waste plan or biogenic waste oils/fats/
greases plan specified in Sec.  80.1450(b)(1)(vii)(B).
    (v) A process flow diagram of each step of the physical process 
from feedstock entry to the point where the biogas either leaves the 
facility or is used to produce RNG, biointermediate, or biogas-derived 
renewable fuel. This includes all the following:
    (A) Feedstock processing.
    (B) Biogas production.
    (C) Biogas processing.
    (D) Major equipment (e.g., feedstock preprocessing equipment, 
tanks, digesters, pipelines, flares).
    (E) Measurement locations and equipment.
    (F) Any other process-related information as requested by EPA.
    (vi) For biogas produced in a mixed digester, all the following:
    (A) For biogas producers using a value under Sec.  
80.105(j)(2)(iv)(E), all the following:
    (1) The cellulosic converted fraction (CF) for each cellulosic 
biogas feedstock that will be used in Sec.  80.105(j)(2)(iii), in Btu 
HHV/lb feedstock, rounded to the nearest whole number.
    (2) Data supporting the cellulosic CF from each cellulosic biogas 
feedstock. Data must be derived from processing of cellulosic biogas 
feedstock(s) in anaerobic digesters without simultaneous conversion 
under similar conditions as will be run in the simultaneously converted 
process. Data must be either from the facility when it was processing 
solely the feedstock that does have a minimum 75% adjusted cellulosic 
content or from a representative sample of other representative 
facilities processing the feedstock that does have a minimum 75% 
adjusted cellulosic content.
    (3) A description of how the cellulosic CF was determined, 
including any calculations demonstrating how the data were used.
    (4) A list of ranges of processing conditions, including 
temperature, solids mean residence time, and hydraulic mean residence 
time, for which the cellulosic CF is accurate and a description of how 
such processing conditions will be measured by the facility.
    (5) A demonstration that no biogas generated from non-cellulosic 
biogas feedstocks could be used to generate RINs for a batch of 
renewable fuel with a D code of 3 or 7. EPA may reject this 
demonstration if it is not sufficiently protective.
    (B) A description of the meters used to determine the mass of 
cellulosic biogas feedstock.
    (C) The location of feedstock sampling, additive (e.g., water) 
addition, and mass measurement for use in Sec.  80.105(j)(2)(iii) 
included in the process flow diagram required under paragraph 
(c)(10)(v) of this section.
    (D) For facilities using composite sampling under Sec.  
80.155(c)(3), a composite sampling plan, including all the following:
    (1) A description of when and where the samples will be collected.
    (2) A description of how the samples will be stored prior to 
testing.
    (3) A description of how daily representative samples will be 
mixed, including how the ratio of each sample will be determined.
    (4) A description of how often testing will occur.
    (5) A description of how the plan complies with Sec.  80.155(c)(2).
    (d) RNG producer. In addition to the information required under 
paragraph (b) of this section, an RNG producer must submit all the 
following information for each RNG production facility:
    (1) All applicable information in Sec.  80.1450(b)(1)(ii).
    (2) Information to establish the RNG production capacity for the 
RNG production facility, in Btu LHV, including all the following, as 
applicable:
    (i) Information regarding the permitted capacity in the most recent 
applicable air permits issued by EPA, a state, a local air pollution 
control agency, or a foreign governmental agency that governs the RNG 
production facility, if available.
    (ii) Documents demonstrating the RNG production facility's 
nameplate capacity.
    (iii) Information describing the RNG production facility's RNG 
production for each of the last three calendar years prior to the 
registration submission, if available.
    (3) The following information related to RNG measurement:
    (i) A description of how RNG will be measured under Sec.  
80.155(a), including the specific standards under which the meters are 
operated.
    (ii) A description of the RNG production process, including a 
process flow diagram that includes metering type(s) and location(s).
    (iii) For an alternative measurement protocol under Sec.  
80.155(a)(3), all the following:
    (A) A description of why the RNG producer is unable to use meters 
that comply with the requirements specified in Sec.  80.155(a)(1) and 
(2), as applicable.
    (B) A description of how measurement is conducted.
    (C) Any standards or specifications that apply.
    (D) A description of all routine maintenance and the frequency that 
such maintenance will be conducted.
    (E) A description of the frequency of all measurements and how 
often such measurements will be recorded under the alternative 
measurement protocol.
    (F) A comparison between the accuracy, precision, and reliability 
of the alternative measurement protocol and the requirements specified 
in Sec.  80.155(a)(1) and (2), as applicable, including any supporting 
data.
    (4) The natural gas commercial pipeline system name and pipeline 
interconnect location into which the RNG will be injected.
    (5) A description of the natural gas specifications for the natural 
gas commercial pipeline system into which the RNG will be injected, 
including information on all parameters regulated by the pipeline 
(e.g., hydrogen sulfide, total sulfur, carbon dioxide, oxygen, 
nitrogen, heating content, moisture, siloxanes, and any other available 
data related to the gas components).
    (6) For three-year registration updates, information related to RNG 
quality, including all the following:
    (i) A certificate of analysis--including the major and minor gas 
components--from an independent laboratory for a representative sample 
of the biogas produced at the biogas production facility as specified 
in Sec.  80.155(b).
    (ii) A certificate of analysis--including the major and minor gas 
components--from an independent laboratory for a representative sample 
of the RNG prior to addition of non-renewable components as specified 
in Sec.  80.155(b).
    (iii) If the RNG is blended with non-renewable components prior to 
injection into a natural gas commercial pipeline system, a certificate 
of analysis from an independent laboratory for a representative sample 
of the RNG after blending with non-renewable components as specified in 
Sec.  80.155(b).
    (iv) A summary table with the results of the certificates of 
analysis required under paragraphs (d)(6)(i) through (iii) of this 
section and the natural gas specifications required under paragraph 
(d)(5) of this section converted to the same units.

[[Page 44571]]

    (v) EPA may approve an RNG producer's request of an alternative 
analysis in lieu of the certificates of analysis and summary table 
required under paragraphs (d)(6)(i) through (iv) of this section if the 
RNG producer demonstrates that the alternative analysis provides 
information that is equivalent to that provided in the certificates of 
analysis and that the RNG will meet all natural gas specifications 
required under paragraph (d)(5) of this section.
    (7) A RIN generation protocol that includes all the following 
information:
    (i) The procedure for allocating RNG injected into the natural gas 
commercial pipeline system to each RNG production facility and each 
biogas production facility, including how discrepancies in meter values 
will be handled.
    (ii) A diagram showing the locations of flow meters, gas analyzers, 
and in-line GC meters used in the allocation procedure.
    (iii) A description of when RINs will be generated (e.g., receipt 
of monthly pipeline statement, etc).
    (8) For an RNG production facility that injects RNG at a pipeline 
interconnect that also has RNG injected from other sources, a 
description of how the RNG producers will allocate RINs to ensure that 
all facilities comply with the requirements specified in Sec.  
80.125(b)(7).
    (9) For a foreign RNG producer, all the following additional 
information:
    (i) The applicable information specified in Sec.  80.160.
    (ii) Whether the foreign RNG producer will generate RINs for their 
RNG.
    (iii) For non-RIN generating foreign RNG producers, the name and 
EPA-issued company and facility IDs of the contracted importer under 
Sec.  80.160(e).
    (e) RNG importer. In addition to the information required under 
paragraph (b) of this section, an RNG importer must submit all the 
following information:
    (1) The name and EPA-issued company and facility IDs of the 
contracted non-RIN generating foreign RNG producer under Sec.  
80.160(e).
    (2) The name and contact information for the independent third 
party specified in Sec.  80.160(h).
    (f) RNG RIN separator. In addition to the information required 
under paragraph (b) of this section, an RNG RIN separator must submit a 
list of locations of any dispensing stations where the RNG RIN 
separator supplies or intends to supply renewable CNG/LNG for use as 
transportation fuel.
    (g) Renewable fuel producer using biogas as a biointermediate. In 
addition to the information required under paragraph (b) of this 
section, a renewable fuel producer using biogas as a biointermediate 
must submit all the following:
    (1) All applicable information in Sec.  80.1450(b).
    (2) Documentation demonstrating a direct connection between the 
biogas production facility and the renewable fuel production facility.

Sec.  80.140  Reporting.

    (a) General provisions--(1) Applicability. Parties must submit 
reports to EPA according to the schedule and containing all applicable 
information specified in this section.
    (2) Forms and procedures for report submission. All reports 
required under this section must be submitted using forms and 
procedures specified by EPA.
    (3) Additional reporting elements. In addition to any applicable 
reporting requirement under this section, parties must submit any 
additional information EPA requires to administer the reporting 
requirements of this section.
    (4) English language reports. All reported information submitted to 
EPA under this section must be submitted in English, or must include an 
English translation.
    (5) Signature of reports. Reports required under this section must 
be signed and certified as meeting all the applicable requirements of 
this subpart by the RCO or their delegate identified in the company 
registration under 40 CFR 1090.805(a)(1)(iv).
    (6) Report submission deadlines. Reports required under this 
section must be submitted by the following deadlines:
    (i) Monthly reports must be submitted by the applicable monthly 
deadline in Sec.  80.1451(f)(4).
    (ii) Quarterly reports must be submitted by the applicable 
quarterly deadline in Sec.  80.1451(f)(2).
    (iii) Annual reports must be submitted by the applicable annual 
deadline in Sec.  80.1451(f)(1).
    (8) Volume standardization. (i) All volumes reported to EPA in scf 
under this section must be standardized to STP.
    (ii) All volumes reported to EPA in Btu under this section must be 
converted according to Sec.  80.155(f), if applicable.
    (iii) All other volumes reported to EPA under this section must be 
standardized according to Sec.  80.1426(f)(8).
    (b) Biogas producers. A biogas producer must submit monthly reports 
to EPA containing all the following information for each batch of 
biogas:
    (1) Batch number.
    (2) Production date (end date of the calendar month).
    (3) Verification status of the batch.
    (4) The batch volume of biogas supplied to the downstream party, in 
Btu HHV and scf, as measured under Sec.  80.155.
    (5) The associated pathway information, including D code, 
designated use of the biogas (e.g., biointermediate, renewable CNG/LNG, 
or RNG), and feedstock information.
    (6) The EPA-issued company and facility IDs for the RNG producer, 
biogas closed distribution system RIN generator, or renewable fuel 
producer that received the batch of the biogas.
    (c) RNG producers. (1) An RNG producer must submit quarterly 
reports to EPA containing all the following information:
    (i) The total volume of RNG, in Btu LHV and scf, produced and 
injected into the natural gas commercial pipeline system as measured 
under Sec.  80.155.
    (ii) The total volume of non-renewable components, in Btu LHV, 
added to RNG prior to injection into the natural gas commercial 
pipeline system.
    (2) A non-RIN generating foreign RNG producer must submit monthly 
reports to EPA containing all the following information for each batch 
of RNG:
    (i) Batch number.
    (ii) Production date (end date of the calendar month).
    (iii) Verification status of the batch.
    (iv) The associated pathway information, including D code, 
production process, and feedstock information.
    (v) The EPA-issued company and facility IDs for the RNG importer 
that will generate RINs for the batch.
    (d) Biogas closed distribution system RIN generators. A biogas 
closed distribution system RIN generator must submit monthly reports to 
EPA containing all the following information:
    (1)(i) For fuels that are gaseous at STP, the type and volume of 
biogas-derived renewable fuel, in Btu LHV.
    (ii) For all other fuels, the type and volume of biogas-derived 
renewable fuel, in gallons.
    (2) Each of the following, as applicable, as measured under Sec.  
80.155:
    (i) The volume of biogas, in Btu HHV, used to produce the treated 
biogas that is used to produce the biogas-derived renewable fuel.
    (ii) The volume of biogas, in Btu HHV, used to produce the biogas-
derived renewable fuel.
    (iii) The volume of treated biogas, in Btu HHV, used to produce the 
biogas-derived renewable fuel.
    (3) The name(s) and location(s) of where the biogas-derived 
renewable fuel is used or sold for use as transportation fuel.

[[Page 44572]]

    (4)(i) For fuels that are gaseous at STP, the volume of biogas-
derived renewable fuel, in Btu LHV, used at each location where the 
biogas-derived renewable fuel is used or sold for use as transportation 
fuel.
    (ii) For all other fuels, the volume of biogas-derived renewable 
fuel, in gallons, used at each location where the biogas-derived 
renewable fuel is used or sold for use as transportation fuel.
    (5) All applicable information in Sec.  80.1451(b).
    (e) RNG RIN separators. (1) An RNG RIN separator must submit 
quarterly reports to EPA containing all the following information:
    (i) Name and location of each point where RNG was withdrawn from 
the natural gas commercial pipeline system.
    (ii) Volume of RNG, in Btu LHV, withdrawn from the natural gas 
commercial pipeline system during the reporting period by withdrawal 
location.
    (iii) Volume of renewable CNG/LNG, in Btu LHV, dispensed during the 
reporting period by withdrawal location.
    (2) An RNG RIN separator must submit monthly reports to EPA 
containing all the following information for each batch of biogas:
    (i) The location where renewable CNG/LNG was dispensed as 
transportation fuel.
    (ii) The volume of renewable CNG/LNG, in Btu LHV, dispensed as 
transportation fuel at the location.
    (f) Retirement of RINs for RNG used as a feedstock or process heat. 
A party that retires RINs for RNG used as a feedstock or as process 
heat or energy under Sec.  80.1426(f)(12) or (13) must submit quarterly 
reports to EPA containing all the following information:
    (1) The name(s) and location(s) of the natural gas commercial 
pipeline where the RNG was withdrawn.
    (2) Volume of RNG, in Btu LHV, withdrawn from the natural gas 
commercial pipeline during the reporting period by location.
    (3) The EPA-issued company and facility IDs for the facility that 
used the withdrawn RNG as a feedstock or as process heat.
    (4) For each facility, the following information, as applicable:
    (i) For fuels that are gaseous at STP, the volume of biogas-derived 
renewable fuel, in Btu LHV, produced using the withdrawn RNG.
    (ii) For all other fuels, the volume of biogas-derived renewable 
fuel, in gallons, produced using the withdrawn RNG.
    (5) The number of RINs for RNG retired during the reporting period 
by D code and verification status.

Sec.  80.145  Recordkeeping.

    (a) General requirements--(1) Records to be kept. All parties 
subject to the requirements of this subpart must keep the following 
records:
    (i) Compliance report records. Records related to compliance 
reports submitted to EPA under this part as follows:
    (A) Copies of all reports submitted to EPA.
    (B) Copies of any confirmation received from the submission of such 
reports to EPA.
    (C) Copies of all underlying information and documentation used to 
prepare and submit the reports.
    (D) Copies of all calculations required under this subpart.
    (ii) Registration records. Records related to registration under 
this part and 40 CFR part 1090, subpart I, as follows:
    (A) Copies of all registration information and documentation 
submitted to EPA.
    (B) Copies of all underlying information and documentation used to 
prepare and submit the registration request.
    (iii) PTD records. Copies of all PTDs required under this part.
    (iv) Subpart M records. Any applicable record required under 40 CFR 
part 80, subpart M.
    (v) QAP records. Information and documentation related to 
participation in any QAP program, including contracts between the 
entity and the QAP provider, records related to verification activities 
under the QAP, and copies of any QAP-related submissions.
    (vi) Sampling, testing, and measurement records. Documents 
supporting the sampling, storage, testing, and measurement results 
relied upon under Sec.  80.155, including all results, maintenance 
records, and calibration records.
    (vii) Other records. Any other records relied upon by the party to 
demonstrate compliance with this subpart.
    (viii) Potentially invalid RINs. Any records and copies of 
notifications related to potentially inaccurate or non-qualifying 
biogas volumes or potentially invalid RINs under Sec.  80.185.
    (ix) RNG importers and foreign parties. Any records related to RNG 
importers and foreign parties under Sec. Sec.  80.160, 80.1466, and 
80.1467, as applicable.
    (2) Length of time records must be kept. The records required under 
this subpart must be kept for five years from the date they were 
created, except that records related to transactions involving RINs 
must be kept for five years from the date of the RIN transaction.
    (3) Make records available to EPA. Any party required to keep 
records under this section must make records available to EPA upon 
request by EPA. For records that are electronically generated or 
maintained, the party must make available any equipment and software 
necessary to read the records or, upon approval by EPA, convert the 
electronic records to paper documents.
    (4) English language records. Any record requested by EPA under 
this section must be submitted in English, or include an English 
translation.
    (b) Biogas producers. In addition to the records required under 
paragraph (a) of this section, a biogas producer must keep all the 
following records:
    (1) Copies of all contracts, PTDs, affidavits required under this 
part, and all other commercial documents with any RNG producer, 
biointermediate producer, or renewable fuel producer.
    (2) Documents supporting the volume of biogas, in Btu HHV and scf, 
produced for each batch.
    (3) Documents supporting the composition and cleanup of biogas 
produced for each batch (e.g., meter readings of composition, records 
of adsorbent replacement, records showing equipment operation including 
maintenance and energy usage, and records of component streams 
separated from the biomethane-enriched stream).
    (4) Information and documentation related to participation in any 
QAP program, including contracts between the biogas producer and the 
QAP provider, records related to verification activities under the QAP, 
and copies of any QAP-related submissions.
    (5) Records related to measurement, including types of equipment 
used, metering process, maintenance and calibration records, documents 
supporting adjustments related to error correction, and measurement 
data.
    (6) Documents supporting the use of each process heat source and 
supporting the amount of each source used in the production process for 
each batch.
    (7) All the applicable recordkeeping requirements for digester 
feedstocks under Sec.  80.1454.
    (8) The following information and documents showing that the biogas 
came from renewable biomass:
    (i) For all anaerobic digesters, documentation showing the mass of 
each feedstock type input into the digester for each batch of biogas.
    (ii) For agricultural digesters, a quarterly affidavit signed by 
the RCO or

[[Page 44573]]

their delegate that only animal manure, crop residue, or separated yard 
waste that had an adjusted cellulosic content of at least 75% were used 
to produce biogas during the quarter.
    (iii) For municipal wastewater treatment facility digesters and 
separated MSW digesters, a quarterly affidavit signed by the RCO or 
their delegate that only feedstocks that had an adjusted cellulosic 
content of at least 75% were used to produce biogas during the quarter.
    (iv) For biogas produced from separated yard waste, separated food 
waste, or biogenic waste oils/fats/greases, documents required under 
Sec.  80.1454(j)(1).
    (v) For biogas produced from separated MSW, documents required 
under Sec.  80.1454(j)(2).
    (9) For biogas produced in a mixed digester, all the following:
    (i) Documents for each delivery of feedstock to the biogas 
production facility, demonstrating all the following for each unique 
combination of feedstock supplier and type of feedstock:
    (A) The name of the feedstock supplier.
    (B) The type of feedstock.
    (C) The mass of that feedstock delivered from that supplier.
    (ii) Data, documents, and calculations related to digester 
operating conditions required under Sec.  80.105(f)(2)(iii)(D).
    (iii) Documents for each batch showing how measurement data for 
volatile solids, total solids, and mass were used to calculate batch 
volume under Sec.  80.105(j)(2).
    (iv) Documents showing the amounts of additives (e.g., water), 
timing of additive addition, and location of additive addition for all 
additives added to the feedstock.
    (v) For samples tested for volatile solids and total solids, 
documents showing the time and location that each sample was obtained 
and tested.
    (c) RNG producers. In addition to the records required under 
paragraph (a) of this section, an RNG producer must keep all the 
following records:
    (1) Records related to the generation and assignment of RINs, 
including all the following information:
    (i) Batch volume.
    (ii) Batch number.
    (iii) Production date when RINs were assigned to RNG.
    (iv) Injection point into the natural gas commercial pipeline 
system.
    (v) Volume of biogas, in Btu HHV and scf, respectively, received at 
each RNG production facility.
    (vi) Volume of RNG, in Btu LHV, Btu HHV, and scf, produced at each 
RNG production facility.
    (vii) Pipeline injection statements describing the energy and 
volume of natural gas for each pipeline interconnect.
    (2) Records related to each RIN transaction, separately for each 
transaction, including all the following information:
    (i) A list of the RINs generated, owned, purchased, sold, 
separated, retired, or reinstated.
    (ii) The parties involved in each transaction including the 
transferor, transferee, and any broker or agent.
    (iii) The date of the transfer of the RINs.
    (iv) Additional information related to details of the transaction 
and its terms.
    (3) Documentation recording the transfer and sale of RNG, from the 
point of biogas production to the facility that sells or uses the fuel 
for transportation purposes.
    (4) A copy of the RNG producer's Compliance Certification required 
under Title V of the Clean Air Act.
    (5) Results of any laboratory analysis of chemical composition or 
physical properties.
    (6) Documents supporting the composition of biogas and RNG and 
cleanup of biogas for each batch (e.g., meter readings of composition, 
records of adsorbent replacement, records showing equipment operation 
including maintenance and energy usage, and records of component 
streams separated from the biomethane-enriched stream).
    (7) Documents supporting the use of each process heat source and 
supporting the amount of each source used in the production process for 
each batch.
    (8) Records related to measurement, including types of equipment 
used, metering process, maintenance and calibration records, documents 
supporting adjustments related to error correction, and measurement 
data.
    (9) Information and documentation related to participation in any 
QAP program, including contracts between the RNG producer and the QAP 
provider, records related to verification activities under the QAP, and 
copies of any QAP-related submissions.
    (10) For an RNG production facility that injects RNG at a pipeline 
interconnect that also has RNG injected from other sources, documents 
showing that RINs generated for the facility comply with the 
requirements specified in Sec.  80.125(b)(7).
    (11) Documentation of any waiver provided by the natural gas 
commercial pipeline system for any parameter of the RNG that does not 
meet the natural gas specifications submitted under Sec.  80.135(d)(5).
    (d) Biogas closed distribution system RIN generators. In addition 
to the records required under paragraph (a) of this section, a biogas 
closed distribution system RIN generator must keep all the following 
records:
    (1) Documentation demonstrating that the renewable CNG/LNG was 
produced from renewable biomass and qualifies to generate RINs under an 
approved pathway.
    (2) Copies of any written contract for the sale or use of renewable 
CNG/LNG as transportation fuel, and copies of any affidavit from a 
party that sold or used the renewable CNG/LNG as transportation fuel.
    (e) RNG RIN separators. In addition to the records required under 
paragraph (a) of this section, an RNG RIN separator must keep all the 
following records:
    (1) Documentation indicating the volume of RNG, in Btu LHV, 
withdrawn from each interconnect of the natural gas commercial pipeline 
system.
    (2) Documentation demonstrating the volume of RNG, in Btu LHV, 
withdrawn from the natural gas commercial pipeline system that was used 
to produce renewable CNG/LNG.
    (3) Documentation indicating the volume of renewable CNG/LNG, in 
Btu LHV, dispensed as transportation fuel from each dispensing 
location.
    (4) Copies of all documentation required under Sec.  
80.125(d)(2)(ii), as applicable.
    (5) Documentation showing how the number of RINs separated was 
determined using the information specified in paragraphs (e)(1) through 
(4) of this section and the applicable RIN separation reports.
    (f) Renewable fuel producers that use biogas as a biointermediate 
or RNG as a feedstock. In addition to the records required under 
paragraph (a) of this section, a renewable fuel producer that uses 
biogas as a biointermediate or RNG as a feedstock must keep all the 
following records:
    (1) Documentation supporting the volume of renewable fuel produced 
from biogas used as a biointermediate or RNG that was used as a 
feedstock.
    (2) For biogas, all the following additional information:
    (i) For each facility, documentation supporting the volume of 
biogas, in Btu HHV and scf, that was used as a biointermediate.
    (ii) Copies of all applicable contracts over the past 5 years with 
each biointermediate producer.
    (3) For RNG, all the following additional information:
    (i) Documentation supporting the volume of RNG, in Btu LHV, 
withdrawn

[[Page 44574]]

from the natural gas commercial pipeline system.
    (ii) Documentation supporting the retirement of RINs for RNG used 
as a feedstock (e.g., contracts, purchase orders, invoices).

Sec.  80.150  Product transfer documents.

    (a) General requirements--(1) PTD contents. On each occasion when 
any person transfers title of any biogas or imported RNG without 
assigned RINs, the transferor must provide the transferee PTDs that 
include all the following information:
    (i) The name, EPA-issued company and facility IDs, and address of 
the transferor.
    (ii) The name, EPA-issued company and facility IDs, and address of 
the transferee.
    (iii) The volume (in Btu HHV for biogas or Btu LHV for RNG) of the 
product being transferred by D code and verification status.
    (iv) The location of the product at the time of the transfer.
    (v) The date of the transfer.
    (vi) Period of production.
    (2) Other PTD requirements. A party must also include any 
applicable PTD information required under Sec.  80.1453 or 40 CFR part 
1090, subpart L.
    (b) Additional PTD requirements for transfers of biogas. In 
addition to the information required in paragraph (a) of this section, 
on each occasion when any person transfers title of biogas, the 
transferor must provide the transferee PTDs that include all the 
following information:
    (1) An accurate and clear statement of the applicable designation 
of the biogas.
    (2) If the biogas is designated as a biointermediate, any 
applicable requirement specified in Sec.  80.1453(f).
    (3) One of the following statements, as applicable:
    (i) For biogas designated for use to produce renewable CNG/LNG, 
``This volume of biogas is designated and intended for use to produce 
renewable CNG/LNG.''
    (ii) For biogas designated for use to produce RNG, ``This volume of 
biogas is designated and intended for use to produce renewable natural 
gas.''
    (iii) For biogas designated for use as a biointermediate, the 
language found at Sec.  80.1453(f)(1)(vi).
    (iv) For biogas designated for use as process heat or energy under 
Sec.  80.1426(f)(12) or (13), ``This volume of biogas is designated and 
intended for use as process heat or energy.''
    (c) PTD requirements for custodial transfers of RNG. On each 
occasion when custody of RNG is transferred prior to injection into a 
pipeline interconnect (e.g., via truck), the transferor must provide 
the transferee PTDs that include all the following information:
    (1) The applicable information listed in paragraph (a) of this 
section.
    (2) The following statement, ``This volume of RNG is designated and 
intended for transportation use and may not be used for any other 
purpose.''
    (d) PTD requirements for imported RIN-less RNG. On each occasion 
when title of RIN-less RNG is transferred and ultimately imported into 
the covered location, the transferor must provide the transferee PTDs 
that include all the following information:
    (1) The applicable information listed in paragraph (a) of this 
section.
    (2) The following statement, ``This volume of RNG is designated and 
intended for transportation use in the contiguous United States and may 
not be used for any other purpose.''
    (3) The name, EPA-issued company and facility IDs, and address of 
the contracted RNG importer under Sec.  80.160(e).
    (4) The name, EPA-issued company and facility IDs, and address of 
the transferee.

Sec.  80.155  Sampling, testing, and measurement.

    (a) Biogas and RNG continuous measurement. Any party required to 
measure the volume of biogas, RNG, or renewable CNG/LNG under this 
subpart must continuously measure using meters that comply with the 
requirements in paragraphs (a)(1) and (2) of this section, or have an 
accepted alternative measurement protocol as specified in paragraph 
(a)(3) of this section:
    (1) In-line GC meters compliant with ASTM D7164 (incorporated by 
reference, see Sec.  80.12), including sections 9.2, 9.3, 9.4, 9.5, 
9.7, 9.8, and 9.11 of ASTM D7164.
    (2) Flow meters compliant with one of the following:
    (i) API MPMS 14.3.1, API MPMS 14.3.2, API MPMS 14.3.3, and API MPMS 
14.3.4 (incorporated by reference, see Sec.  80.12).
    (ii) API MPMS 14.12 (incorporated by reference, see Sec.  80.12).
    (iii) EN 17526 (incorporated by reference, see Sec.  80.12) 
compatible with gas type H.
    (3) EPA may accept an alternative measurement protocol if all the 
following conditions are met:
    (i) The party demonstrates that they are unable to continuously 
measure using meters that comply with the requirements in paragraphs 
(a)(1) and (2) of this section, as applicable.
    (ii) The party demonstrates that the alternative measurement 
protocol is at least as accurate and precise as the methods specified 
in paragraphs (a)(1) and (2) of this section, as applicable.
    (b) Biogas and RNG sampling and testing. Any party required to 
sample and test biogas or RNG under this subpart must do so as follows:
    (1) Collect representative samples of biogas or RNG using API MPMS 
14.1 (incorporated by reference, see Sec.  80.12).
    (2) Perform all the following measurements on each representative 
sample:
    (i) Methane, carbon dioxide, nitrogen, and oxygen using EPA Method 
3C (see Appendix A-2 to 40 CFR part 60).
    (ii) Hydrogen sulfide and total sulfur using ASTM D5504 
(incorporated by reference, see Sec.  80.12).
    (iii) Siloxanes using ASTM D8230 (incorporated by reference, see 
Sec.  80.12).
    (iv) Moisture using ASTM D4888 (incorporated by reference, see 
Sec.  80.12).
    (v) Hydrocarbon analysis using EPA Method 18 (see Appendix A-6 to 
40 CFR part 60).
    (vi) Heating value and relative density using ASTM D3588 
(incorporated by reference, see Sec.  80.12).
    (vii) Additional components specified in the natural gas 
specifications submitted under Sec.  80.135(d)(5) or specified by EPA 
as a condition of registration under this part.
    (viii) Carbon-14 analysis using ASTM D6866 (incorporated by 
reference, see Sec.  80.12).
    (c) Digester feedstock. Any party required to test for total solids 
and volatile solids of a digester feedstock under this subpart must do 
so as follows:
    (1) Samples must be tested in accordance with Part G of SM 2540 
(incorporated by reference, see Sec.  80.12).
    (2) Samples must be obtained, stored, and tested in accordance with 
Part A of SM 2540, including Sections 2, 3, and 5 (Sources of Error and 
Variability, Sample Handling and Preservation, and Quality Control).
    (3) Parties must test each daily representative sample under 
paragraphs (c)(1) and (2) of this section unless the party has a 
composite sampling plan submitted to EPA under Sec.  
80.135(c)(10)(vi)(D). Parties with a composite sampling plan must 
either test each daily representative sample or test samples in 
accordance with Part A of SM 2540 and as specified in the facility's 
composite sampling plan.
    (d) Digester operations. Any biogas producer required to measure or 
calculate digester operating conditions under this subpart must 
determine digester operating conditions for each

[[Page 44575]]

mixed digester that meet all the following requirements:
    (1) Digester temperature readings must be recorded no less frequent 
than every 30 minutes and represent the average temperature in the 
tank.
    (2) Digester hydraulic and solids mean residence times must be 
calculated no less frequent than once a day using measurements of 
inflows, outflows, and tank levels, as applicable.
    (3) Other parameters must be measured and calculated as specified 
in the facility's registration under Sec.  80.135(c)(10)(vi)(A)(4).
    (e) Third parties. Samples required to be obtained under this 
subpart may be collected and analyzed by third parties.
    (f) Unit conversions. A party converting between Btu HHV and Btu 
LHV for biogas, treated biogas, natural gas, or CNG/LNG must use the 
ratio of HHV and LHV of methane as specified in ASTM D3588 
(incorporated by reference, see Sec.  80.12).
    (g) Liquid measurement and standardization. Any substance that is 
liquid at STP must be measured in gallons and standardized according to 
Sec.  80.1426(f)(8).

Sec.  80.160  RNG importers, foreign biogas producers, and foreign RNG 
producers.

    (a) Applicability. The provisions of this section apply to any RNG 
importer or any foreign party subject to requirements of this subpart 
outside the United States.
    (b) General requirements. Any foreign party must meet all the 
following requirements:
    (1) Letter from RCO. The foreign party must provide a letter signed 
by the RCO that commits the foreign party to the applicable provisions 
specified in paragraphs (b)(4) and (c) of this section as part of their 
registration under Sec.  80.135.
    (2) Bond posting. A foreign party that generates RINs must meet the 
bond requirements of Sec.  80.1466(h).
    (3) Foreign RIN owners. A foreign party that owns RINs must meet 
the requirements of Sec.  80.1467, including any foreign party that 
separates or retires RINs under Sec.  80.125.
    (4) Foreign party commitments. Any foreign party must commit to the 
following provisions as a condition of being registered as a foreign 
party under this subpart:
    (i) Any EPA inspector or auditor must be given full, complete, and 
immediate access to conduct inspections and audits of all facilities 
subject to this subpart.
    (A) Inspections and audits may be either announced in advance by 
EPA, or unannounced.
    (B) Access will be provided to any location where:
    (1) Biogas, RNG, biointermediate, or biogas-derived renewable fuel 
is produced.
    (2) Documents related to the foreign party operations are kept.
    (3) Any product subject to this subpart (e.g., biogas, RNG, 
biointermediates, or biogas-derived renewable fuel) that is stored or 
transported outside the United States between the foreign party's 
facility and the point of importation into the United States, including 
storage tanks, vessels, and pipelines.
    (C) EPA inspectors and auditors may be EPA employees or contractors 
to EPA.
    (D) Any documents requested that are related to matters covered by 
inspections and audits must be provided to an EPA inspector or auditor 
on request.
    (E) Inspections and audits may include review and copying of any 
documents related to the following:
    (1) The volume or properties of any product subject to this subpart 
produced or delivered to a renewable fuel production facility.
    (2) Transfers of title or custody to the any product subject to 
this subpart.
    (3) Work performed and reports prepared by independent third 
parties and by independent auditors under the requirements of this 
subpart, including work papers.
    (4) Records required under Sec.  80.145.
    (5) Any records related to claims made during registration.
    (F) Inspections and audits by EPA may include interviewing 
employees.
    (G) Any employee of the foreign party must be made available for 
interview by the EPA inspector or auditor, on request, within a 
reasonable time period.
    (H) English language translations of any documents must be provided 
to an EPA inspector or auditor, on request, within 10 business days.
    (I) English language interpreters must be provided to accompany EPA 
inspectors and auditors, on request.
    (ii) An agent for service of process located in the District of 
Columbia will be named, and service on this agent constitutes service 
on the foreign party or any employee of the party for any action by EPA 
or otherwise by the United States related to the requirements of this 
subpart.
    (iii) The forum for any civil or criminal enforcement action 
related to the provisions of this subpart for violations of the Clean 
Air Act or regulations promulgated thereunder are governed by the Clean 
Air Act, including the EPA administrative forum where allowed under the 
Clean Air Act.
    (iv) United States substantive and procedural laws apply to any 
civil or criminal enforcement action against the foreign party or any 
employee of the foreign party related to the provisions of this 
subpart.
    (v) Applying to be an approved foreign party under this subpart, or 
producing or exporting any product subject to this subpart under such 
approval, and all other actions to comply with the requirements of this 
subpart relating to such approval constitute actions or activities 
covered by and within the meaning of the provisions of 28 U.S.C. 
1605(a)(2), but solely with respect to actions instituted against the 
foreign party, its agents and employees in any court or other tribunal 
in the United States for conduct that violates the requirements 
applicable to the foreign party under this subpart, including conduct 
that violates the False Statements Accountability Act of 1996 (18 
U.S.C. 1001) and section 113(c)(2) of the Clean Air Act (42 U.S.C. 
7413).
    (vi) The foreign party, or its agents or employees, will not seek 
to detain or to impose civil or criminal remedies against EPA 
inspectors or auditors for actions performed within the scope of EPA 
employment or contract related to the provisions of this subpart.
    (vii) In any case where a product produced at a foreign facility is 
stored or transported by another company between the foreign facility 
and the point of importation to the United States, the foreign party 
must obtain from each such other company a commitment that meets the 
requirements specified in paragraphs (b)(4)(i) through (vi) of this 
section before the product is transported to the United States, and 
these commitments must be included in the foreign party's application 
to be a registered foreign party under this subpart.
    (c) Sovereign immunity. By submitting an application to be a 
registered foreign party under this subpart, or by producing or 
exporting any product subject to this subpart to the United States 
under such registration, the foreign party, and its agents and 
employees, without exception, become subject to the full operation of 
the administrative and judicial enforcement powers and provisions of 
the United States without limitation based on sovereign immunity, with 
respect to actions instituted against the party, its agents and 
employees in any court or other tribunal in the United States for 
conduct that violates the requirements applicable to the foreign

[[Page 44576]]

party under this subpart, including conduct that violates the False 
Statements Accountability Act of 1996 (18 U.S.C. 1001) and section 
113(c)(2) of the Clean Air Act (42 U.S.C. 7413).
    (d) English language reports. Any document submitted to EPA by a 
foreign party must be in English, or must include an English language 
translation.
    (e) Foreign RNG producer contractual relationship. A non-RIN 
generating foreign RNG producer must establish a contractual 
relationship with an RNG importer, prior to the sale of RIN-less RNG.
    (f) Withdrawal or suspension of registration. EPA may withdraw or 
suspend a foreign party's registration where any of the following 
occur:
    (1) The foreign party fails to meet any requirement of this 
subpart.
    (2) The foreign government fails to allow EPA inspections or audits 
as provided in paragraph (b)(4)(i) of this section.
    (3) The foreign party asserts a claim of, or a right to claim, 
sovereign immunity in an action to enforce the requirements in this 
subpart.
    (4) The foreign party fails to pay a civil or criminal penalty that 
is not satisfied using the bond required under paragraph (b)(2) of this 
section.
    (g) Additional requirements for applications, reports, and 
certificates. Any application for registration as a foreign party, or 
any report, certification, or other submission required under this 
subpart by the foreign party, must be:
    (1) Submitted using formats and procedures specified by EPA.
    (2) Signed by the RCO of the foreign party's company.
    (3) Contain the following declarations:
    (i) Certification.
    ``I hereby certify:
    That I have actual authority to sign on behalf of and to bind [NAME 
OF FOREIGN PARTY] with regard to all statements contained herein.
    That I am aware that the information contained herein is being 
Certified, or submitted to the United States Environmental Protection 
Agency, under the requirements of 40 CFR part 80, subparts E and M, and 
that the information is material for determining compliance under these 
regulations.
    That I have read and understand the information being Certified or 
submitted, and this information is true, complete, and correct to the 
best of my knowledge and belief after I have taken reasonable and 
appropriate steps to verify the accuracy thereof.''
    (ii) Affirmation.
    ``I affirm that I have read and understand the provisions of 40 CFR 
part 80, subparts E and M, including 40 CFR 80.160, 80.1466, and 
80.1467 apply to [NAME OF FOREIGN PARTY]. Pursuant to Clean Air Act 
section 113(c) and 18 U.S.C. 1001, the penalty for furnishing false, 
incomplete, or misleading information in this certification or 
submission is a fine of up to $10,000 U.S., and/or imprisonment for up 
to five years.''
    (h) Requirements for RNG importers. An RNG importer must meet all 
the following requirements:
    (1) For each imported batch of RNG, the RNG importer must have an 
independent third party that meets the requirements of Sec.  
80.1450(b)(2)(i) and (ii) do all the following:
    (i) Determine the volume of RNG, in Btu LHV, injected into the 
natural gas commercial pipeline system as specified in Sec.  80.155.
    (ii) Determine the name and EPA-assigned company and facility 
identification numbers of the foreign non-RIN generating RNG producer 
that produced the RNG.
    (2) The independent third party must submit reports to the foreign 
non-RIN generating RNG producer and the RNG importer within 30 days 
following the date the RNG was injected into a natural gas commercial 
pipeline system for import into the United States containing all the 
following:
    (i) The statements specified in paragraph (g) of this section.
    (ii) The name of the foreign non-RIN generating RNG producer, 
containing the information specified in paragraph (g) of this section, 
and including the identification of the natural gas commercial pipeline 
system terminal at which the product was offloaded.
    (iii) PTDs showing the volume of RNG, in Btu LHV, transferred from 
the foreign non-RIN generating RNG producer to the RNG importer.
    (3) The RNG importer and the independent third party must keep 
records of the audits and reports required under paragraphs (h)(1) and 
(2) of this section for five years from the date of creation.

Sec.  80.165  Attest engagements.

    (a) General provisions. (1) The following parties must arrange for 
annual attestation engagement using agreed-upon procedures:
    (i) Biogas producers.
    (ii) RNG producers.
    (iii) RNG importers.
    (iv) Biogas closed distribution system RIN generators.
    (v) RNG RIN separators.
    (vi) Renewable fuel producers that use RNG as a feedstock.
    (2) The auditor performing attestation engagements required under 
this subpart must meet the requirements in 40 CFR 1090.1800(b).
    (3) The auditor must perform attestation engagements separately for 
each biogas production facility, RNG production facility, and renewable 
fuel production facility, as applicable.
    (4) Except as otherwise specified in this section, attest auditors 
may use the representative sampling procedures specified in 40 CFR 
1090.1805.
    (5) Except as otherwise specified in this section, attest auditors 
must prepare and submit the annual attestation engagement following the 
procedures specified in 40 CFR 1090.1800(d).
    (b) General procedures for biogas producers. An attest auditor must 
conduct annual attestation audits for biogas producers using the 
following procedures:
    (1) Registration and EPA reports. The auditor must review 
registration and EPA reports as follows:
    (i) Obtain copies of all the following:
    (A) The biogas producer's registration information submitted under 
Sec. Sec.  80.135 and 80.1450.
    (B) All reports submitted under Sec. Sec.  80.140 and 80.1451.
    (ii) For each biogas production facility, confirm that the 
facility's registration is accurate based on the activities reported 
during the compliance period and confirm any related updates were 
completed prior to conducting regulated activities at the facility and 
report as a finding any exceptions.
    (iii)(A) Report the date of the last engineering review conducted 
under Sec. Sec.  80.135(b)(3) and 80.1450(b), as applicable.
    (B) Report as a finding if the last engineering review is outside 
of the schedule specified in Sec.  80.1450(d)(3)(ii).
    (iv) Confirm that the biogas producer submitted all reports 
required under Sec. Sec.  80.140 and 80.1451 for activities performed 
during the compliance period and report as a finding any exceptions.
    (2) Measurement method review. The auditor must review measurement 
methods for each meter as follows:
    (i) Obtain records related to measurement under Sec.  
80.145(a)(1)(vi).
    (ii)(A) Identify and report the name of the method(s) used for 
measuring the volume of biogas, in Btu HHV and scf.
    (B) Report as a finding any method that is not specified in Sec.  
80.155 or the biogas producer's registration.
    (iii)(A) Identify whether maintenance and calibration records were 
kept for each meter and report the last date of calibration.
    (B) Report as a finding if no records were obtained.

[[Page 44577]]

    (3) Listing of batches. The auditor must review listings of batches 
as follows:
    (i) Obtain the batch reports submitted under Sec.  80.140.
    (ii) Compare the reported volume for each batch to the measured 
volume and report as a finding any exceptions.
    (4) Testing of biogas transfers. The auditor must review biogas 
transfers as follows:
    (i) Obtain the associated PTD for each batch of biogas produced 
during the compliance period.
    (ii) Using the batch number, confirm that the correct PTD is 
obtained for each batch and compare the volume, in Btu HHV and scf, on 
each batch report to the associated PTD and report as a finding any 
exceptions.
    (iii) Confirm that the PTD associated with each batch contains all 
applicable language requirements under Sec.  80.150 and report as a 
finding any exceptions.
    (c) General procedures for RNG producers and importers. An attest 
auditor must conduct annual attestation audits for RNG producers and 
importers using the following procedures, as applicable:
    (1) Registration and EPA reports. The auditor must review 
registration and EPA reports as follows:
    (i) Obtain copies of all the following:
    (A) The RNG producer or importer's registration information 
submitted under Sec. Sec.  80.135 and 80.1450.
    (B) All reports submitted under Sec. Sec.  80.140 and 80.1451.
    (ii) For each RNG production facility, confirm that the facility's 
registration is accurate based on the activities reported during the 
compliance period and confirm any related updates were completed prior 
to conducting regulated activities at the facility and report as a 
finding any exceptions.
    (iii)(A) Report the date of the last engineering review conducted 
under Sec. Sec.  80.135(b)(3) and 80.1450(b), as applicable.
    (B) Report as a finding if the last engineering review is outside 
of the schedule specified in Sec.  80.1450(d)(3)(ii).
    (iv) Confirm that the RNG producer or importer submitted all 
reports required under Sec. Sec.  80.140 and 80.1451 for activities 
performed during the compliance period and report as a finding any 
exceptions.
    (2) Feedstock received. The auditor must perform an inventory of 
biogas received as follows:
    (i) Obtain copies of all the following:
    (A) Records documenting the source and volume of biogas, in Btu and 
scf, received by the RNG producer.
    (B) Records showing the volume of biogas used to produce RNG, in 
Btu HHV and scf, and the volume of RNG produced, in Btu HHV and scf.
    (C) Records showing whether non-renewable components were blended 
into RNG.
    (ii) Report the number of parties the RNG producer received biogas 
from and the total volume received separately from each party.
    (iii)(A) Report the total volume of biogas used to produce RNG, in 
Btu HHV and scf, and the total volume of RNG produced, in Btu HHV and 
scf.
    (B) Report as a finding if the volume of RNG produced is greater 
than the volume of biogas used to produce RNG, in Btu HHV.
    (iv) Report as a finding if any RINs were generated for the non-
renewable components of the blended batch.
    (3) Measurement method review. The auditor must review measurement 
methods for each meter as follows:
    (i) Obtain records related to measurement under Sec.  
80.145(a)(1)(vi).
    (ii)(A) Identify and report the name of the method(s) used for 
measuring the volume of RNG, in Btu and in scf.
    (B) Report as a finding any method that is not specified in Sec.  
80.155 or the RNG producer's registration.
    (iii) Identify whether maintenance and calibration records were 
kept and report as a finding if no records were obtained.
    (4) Listing of batches. The auditor must review listings of batches 
as follows:
    (i) Obtain the batch reports submitted under Sec.  80.140.
    (ii) Compare the reported volume for each batch to the measured 
volume and report as a finding any exceptions.
    (iii) Report as a finding any batches with reported values that did 
not meet the natural gas specifications submitted under Sec.  
80.135(d)(5).
    (5) Testing of RNG transfers. The auditor must review RNG transfers 
as follows:
    (i) Obtain the associated PTD for each batch of RNG produced or 
imported during the compliance period.
    (ii) Using the batch number, confirm that the correct PTD is 
obtained for each batch and compare the volume, in Btu and scf, on each 
batch report to the associated PTD and report as a finding any 
exceptions.
    (iii) Confirm that the PTD associated with each batch contains all 
applicable language requirements under Sec.  80.150 and report as a 
finding any exceptions.
    (6) RNG RIN generation. The auditor must perform the following 
procedures for monthly RIN generation:
    (i) Obtain the RIN generation reports submitted under Sec.  
80.1451.
    (ii) Compare the number of RINs generated for each batch to the 
batch report and report as a finding any exceptions.
    (iii)(A) Compare the number of RINs generated multiplied by 77,000 
Btu to the amount of RNG injected into the natural gas commercial 
pipeline system.
    (B) Report as a finding if the volume of RNG injected is less than 
the number of RINs generated multiplied by 77,000 Btu.
    (d) General procedures for biogas closed distribution system RIN 
generators. An attest auditor must conduct annual attestation audits 
for biogas closed distribution system RIN generators using the 
following procedures:
    (1) Registration and EPA reports. The auditor must review 
registration and EPA reports as follows:
    (i) Obtain copies of all the following:
    (A) The biogas closed distribution system RIN generator's 
registration information submitted under Sec.  80.135.
    (B) All reports submitted under Sec.  80.140.
    (ii) Confirm that the biogas closed distribution system RIN 
generator's registration is accurate based on the activities reported 
during the compliance period and that any required updates were 
completed prior to conducting regulated activities and report as a 
finding any exceptions.
    (iii) Confirm that the biogas closed distribution system RIN 
generator submitted all reports required under Sec. Sec.  80.140 and 
80.1451 for activities performed during the compliance period and 
report as a finding any exceptions.
    (2) RIN generation. The auditor must complete all applicable 
requirements specified in Sec.  80.1464.
    (e) General procedures for RNG RIN separators. An attest auditor 
must conduct annual attestation audits for RNG RIN separators using the 
following procedures:
    (1) Registration and EPA reports. The auditor must review 
registration and EPA reports as follows:
    (i) Obtain copies of all the following:
    (A) The RNG RIN separator's registration information submitted 
under Sec. Sec.  80.135 and 80.1450.
    (B) All reports submitted under Sec. Sec.  80.140 and 80.1451.
    (ii) Confirm that the RNG RIN separator's registration is accurate 
based on the activities reported during the compliance period and that 
any required updates were completed prior to conducting regulated 
activities and report as a finding any exceptions.
    (iii) Confirm that the RNG RIN separator submitted all reports 
required under Sec. Sec.  80.140 and 80.1451 for activities performed 
during the

[[Page 44578]]

compliance period and report as a finding any exceptions.
    (2) RIN separation events. The auditor must review records 
supporting RIN separation events as follows:
    (i) Obtain copies of all the following:
    (A) RIN separation reports submitted under Sec. Sec.  80.140(e) and 
80.1452.
    (B) RNG withdrawal records required under Sec.  80.145(e).
    (ii)(A) Compare the volume of RNG, in Btu LHV, withdrawn from the 
natural gas commercial pipeline system to the reported number of 
separated RINs multiplied by 77,000 Btu used to produce the renewable 
CNG/LNG.
    (B) Report as a finding if the volume of RNG, in Btu LHV, is less 
than the number of separated RINs multiplied by 77,000 Btu.
    (iii)(A) Compare the volume of renewable CNG/LNG, in Btu LHV, to 
the reported number of separated RINs multiplied by 77,000 Btu.
    (B) Report as a finding if the volume of renewable CNG/LNG, in Btu 
LHV, is less than the number of separated RINs multiplied by 77,000 
Btu.
    (3) RIN owner. The auditor must complete all the requirements 
specified in Sec.  80.1464(c).
    (f) General procedures for renewable fuel producers that use RNG as 
a feedstock. An attest auditor must conduct annual attestation audits 
for renewable fuel producers that use RNG as a feedstock using the 
following procedures:
    (1) Registration and EPA reports. The auditor must review 
registration and EPA reports as follows:
    (i) Obtain copies of all the following:
    (A) The renewable fuel producer's registration information 
submitted under Sec.  80.135.
    (B) All reports submitted under Sec.  80.140.
    (ii) Confirm that the renewable fuel producer's registration is 
accurate based on the activities reported during the compliance period 
and that any required updates were completed prior to conducting 
regulated activities and report as a finding any exceptions.
    (iii) Confirm that the renewable fuel producers submitted all 
reports required under Sec. Sec.  80.140 and 80.1451 for activities 
performed during the compliance period and report as a finding any 
exceptions.
    (2) RIN retirements. The attest auditor must review RIN retirements 
as follows:
    (i) Obtain copies of all the following:
    (A) RIN retirement reports submitted under Sec. Sec.  80.140(f) and 
80.1452.
    (B) Records related to measurement under Sec.  80.145(a)(1)(vi).
    (ii) Compare the measured volume of RNG used as a feedstock to the 
reported number of RINs retired for RNG.
    (iii) Report as a finding if the measured volume of RNG used as a 
feedstock does not match the number of RINs retired for RNG.

Sec.  80.170  Quality assurance plan.

    (a) General requirements. This section specifies the requirements 
for QAPs related to the verification of RINs generated for RNG and 
biogas-derived renewable fuel.
    (1) For the generation of Q-RINs for RNG or biogas-derived 
renewable fuel, the same independent third-party auditor must verify 
each party as follows:
    (i) For RNG, all the RNG production facilities that inject into the 
same pipeline interconnect and all the biogas production facilities 
that provide feedstock to those RNG production facilities.
    (ii) For renewable CNG/LNG produced from RNG, the biogas producer 
and the RNG producer.
    (iii) For renewable CNG/LNG produced from biogas in a biogas closed 
distribution system, the biogas producer, the biogas closed 
distribution system RIN generator, and any party deemed necessary by 
EPA to ensure that the renewable CNG/LNG was used as transportation 
fuel.
    (iv) For biogas-derived renewable fuel produced from biogas used as 
a biointermediate, the biogas producer, the producer of the biogas-
derived renewable fuel, and any other party deemed necessary by EPA to 
ensure that the biogas-derived renewable fuel was produced under an 
approved pathway and used as transportation fuel.
    (v) For biogas-derived renewable fuel produced from RNG used as a 
feedstock, the producer of the biogas-derived renewable fuel and any 
other party deemed necessary by EPA to ensure that the biogas-derived 
renewable fuel was produced under an approved pathway and used as 
transportation fuel.
    (2) Independent third-party auditors that verify RINs generated 
under this subpart must meet the requirements in Sec.  80.1471(a) 
through (c), (g), and (h).
    (3)(i) QAPs approved by EPA to verify RINs generated under this 
subpart must meet the applicable requirements in Sec.  80.1469.
    (ii) EPA may revoke or void a QAP as specified in Sec.  
80.1469(e)(4) or (5).
    (4) Independent third-party auditors must conduct quality assurance 
audits at biogas production facilities, RNG production facilities, 
renewable fuel production facilities, and any facility or location 
deemed necessary by EPA to ensure that the biogas-derived renewable 
fuel was produced under an approved pathway and used as transportation 
fuel, heating oil, or jet fuel as specified in Sec.  80.1472.
    (5) Independent third-party auditors must ensure that mass and 
energy balances performed under Sec.  80.1469(c)(2) are consistent 
between facilities that are audited as part of the same chain.
    (b) Requirements for biogas production facilities. In addition to 
the applicable elements verified under Sec.  80.1469, the independent 
third-party auditor must do all the following for each biogas 
production facility:
    (1) Verify that the biogas was measured as required under Sec.  
80.155.
    (2) Verify that the PTDs for biogas transfers meet the applicable 
PTD requirements in Sec. Sec.  80.150 and 80.1453.
    (c) Requirements for RNG production facilities. In addition to the 
applicable elements verified under Sec.  80.1469, the independent 
third-party auditor must do all the following for each RNG production 
facility:
    (1) Verify that the RNG was sampled, tested, and measured as 
required under Sec.  80.155.
    (2) Verify that RINs were assigned, separated, and retired as 
required under Sec.  80.125(c), (d), and (e), respectively.
    (3) Verify that the RNG was injected into a natural gas commercial 
pipeline system.
    (4) Verify that RINs were not generated on non-renewable components 
added to RNG prior to injection into a natural gas commercial pipeline 
system.
    (d) Requirements for renewable fuel production facilities using 
biogas as a biointermediate. The independent third-party auditor must 
meet all the requirements specified in paragraph (b) of this section 
and Sec.  80.1477 for each renewable fuel production facility using 
biogas as a biointermediate.
    (e) Responsibility for replacement of invalid verified RINs. The 
generator of RINs for RNG or a biogas-derived renewable fuel, and the 
obligated party that owns the Q-RINs, are required to replace invalidly 
generated Q-RINs with valid RINs as specified in Sec.  80.1431(b).

Sec.  80.175  Prohibited acts and liability provisions.

    (a) Prohibited acts. (1) It is a prohibited act for any person to 
act in violation of this subpart or fail to meet a requirement that 
applies to that person under this subpart.
    (2) No person may cause another person to commit an act in 
violation of this subpart.
    (b) Liability provisions--(1) General. (i) Any person who commits 
any prohibited act or requirement in this subpart is liable for the 
violation.

[[Page 44579]]

    (ii) Any person who causes another person to commit a prohibited 
act under this subpart is liable for that violation.
    (iii) Any parent corporation is liable for any violation committed 
by any of its wholly-owned subsidiaries.
    (iv) Each partner to a joint venture, or each owner of a facility 
owned by two or more owners, is jointly and severally liable for any 
violation of this subpart that occurs at the joint venture facility or 
facility owned by the joint owners, or any violation of this subpart 
that is committed by the joint venture operation or any of the joint 
owners of the facility.
    (v) Any person listed in paragraphs (b)(2) through (4) of this 
section is liable for any violation of a prohibition specified in 
paragraph (a) of this section or failure to meet a requirement of any 
provision of this subpart regardless of whether the person violated or 
caused the violation unless the person establishes an affirmative 
defense under Sec.  80.180.
    (vi) The liability provisions of Sec.  80.1461 also apply to any 
person subject to the provisions of this subpart.
    (2) Biogas liability. When biogas is found in violation of a 
prohibition specified in paragraph (a) of this section or Sec.  
80.1460, the following persons are deemed in violation:
    (i) The biogas producer that produced the biogas.
    (ii) Any RNG producer that used the biogas to produce RNG.
    (iii) Any biointermediate producer that used the biogas to produce 
a biointermediate.
    (iv) Any person that used the biogas, RNG produced from the biogas, 
or biointermediate produced from the biogas to produce a biogas-derived 
renewable fuel.
    (v) Any person that generated a RIN from a biogas-derived renewable 
fuel produced from the biogas, RNG produced from the biogas, or 
biointermediate produced from the biogas.
    (vi) Any person that used the biogas or RNG produced from the 
biogas as process heat or energy under Sec.  80.1426(f)(12) or (13).
    (3) RNG liability. When RNG is found in violation of a prohibition 
specified in paragraph (a) of this section or Sec.  80.1460, the 
following persons are deemed in violation:
    (i) The biogas producer that produced the biogas used to produce 
the RNG.
    (ii) The RNG producer that produced the RNG.
    (iii) Any person that used the RNG as a feedstock.
    (iv) Any person that used the RNG as process heat or energy under 
Sec.  80.1426(f)(12) or (13).
    (v) Any person that generated a RIN from a biogas-derived renewable 
fuel produced from the RNG or biointermediate produced from the RNG.
    (4) Third-party liability. Any party allowed under this subpart to 
act on behalf of a regulated party and does so to demonstrate 
compliance with the requirements of this subpart must meet those 
requirements in the same way that the regulated party must meet those 
requirements. The regulated party and the third party are both liable 
for any violations arising from the third party's failure to meet the 
requirements of this subpart.

Sec.  80.180  Affirmative defense provisions.

    (a) Applicability. A person may establish an affirmative defense to 
a violation that person is liable for under Sec.  80.175(b) if that 
person satisfies all applicable elements of an affirmative defense in 
this section.
    (1) No person that generates a RIN for biogas-derived renewable 
fuel may establish an affirmative defense under this section.
    (2) A person that is a biogas producer may not establish an 
affirmative defense under this section for a violation that the biogas 
producer is liable for under Sec.  80.175(b)(1) and (2).
    (3) A person that is an RNG producer may not establish an 
affirmative defense under this section for a violation that the RNG 
producer is liable for under Sec.  80.175(b)(1) and (3).
    (b) General elements. A person may only establish an affirmative 
defense under this section if the person meets all the following 
requirements:
    (1) The person, or any of the person's employees or agents, did not 
cause the violation.
    (2) The person did not know or have reason to know that the biogas, 
treated biogas, RNG, biogas-derived renewable fuel, or RIN was in 
violation of a prohibition or requirement under this subpart.
    (3) The person must have had no financial interest in the company 
that caused the violation.
    (4) If the person self-identified the violation, the person 
notified EPA within five business days of discovering the violation.
    (5) The person must submit a written report to the EPA including 
all pertinent supporting documentation, demonstrating that the 
applicable elements of this section were met within 30 days of the 
person discovering the invalidity.
    (c) Biogas producer elements. In addition to the elements specified 
in paragraph (b) of this section, a biogas producer must also meet all 
the following requirements to establish an affirmative defense:
    (1) The biogas producer conducted or arranged to be conducted a 
quality assurance program that includes, at a minimum, a periodic 
sampling, testing, and measurement program adequately designed to 
ensure their biogas meets the applicable requirements to produce biogas 
under this part.
    (2) The biogas producer had all affected biogas verified by a 
third-party auditor under an approved QAP under Sec. Sec.  80.170 and 
80.1469.
    (3) The PTDs for the biogas indicate that the biogas was in 
compliance with the applicable requirements while in the biogas 
producer's control.
    (d) RNG producer elements. In addition to the elements specified in 
paragraph (b) of this section, an RNG producer must also meet all the 
following requirements to establish an affirmative defense:
    (1) The RNG producer conducted or arranged to be conducted a 
quality assurance program that includes, at a minimum, a periodic 
sampling, testing, and measurement program adequately designed to 
ensure that the biogas used to produce their RNG meets the applicable 
requirements to produce biogas under this part and that their RNG meets 
the applicable requirements to produce RNG under this part.
    (2) The RNG producer had all affected biogas and RNG verified by a 
third-party auditor under an approved QAP under Sec. Sec.  80.170 and 
80.1469.
    (3) The PTDs for the biogas used to produce their RNG and for their 
RNG indicate that the biogas and RNG were in compliance with the 
applicable requirements while in the RNG producer's control.

Sec.  80.185  Potentially invalid RINs.

    (a) Identification and treatment of potentially invalid RINs 
(PIRs). (1) Any RIN can be identified as a PIR by the biogas producer, 
the RIN generator, the independent third-party auditor that verified 
the RIN, or EPA.
    (2) Any party listed in paragraph (a)(1) of this section must use 
the procedures specified in Sec.  80.1474(b) for identification and 
treatment of PIRs and retire any PIRs under Sec.  80.1434(a).
    (b) Potentially inaccurate or non-qualifying volumes of biogas-
derived renewable fuel. (1) Any party that becomes aware of a volume of 
biogas-derived renewable fuel that does not meet the applicable 
requirements for such fuel under this part must notify the next party 
in the production chain within 5 business days.

[[Page 44580]]

    (i) Biointermediate producers must notify the renewable fuel 
producer receiving the biointermediate within 5 business days.
    (ii) If the volume of biogas-derived renewable fuel was audited 
under Sec.  80.170, the party must notify the independent third-party 
auditor within 5 business days.
    (iii) Non-RIN generating foreign RNG producers must comply with the 
requirements of this section and notify the importer generating RINs 
and other parties in the production chain, as applicable.
    (iv) Each notified party must notify EPA within 5 business days.
    (2) Any party that is notified of a volume of biogas-derived 
renewable fuel that does not meet the applicable requirements for such 
fuel under this part must correct affected volumes of biogas-derived 
renewable fuel under paragraph (a)(2) of this section, as applicable.
    (c) Potential double counting. (1)(i) When any party becomes aware 
of any of the following, they must notify EPA and the RIN generator, if 
known, within 5 business days of initial discovery:
    (A) More than one RIN being generated for renewable fuel produced 
from the same volume of biogas, treated biogas, or RNG.
    (B) More than one RIN being generated for the same volume of 
biogas-derived renewable fuel or RNG.
    (C) A party taking credit for biogas, treated biogas, or RNG under 
a non-transportation program (e.g., a stationary-source renewable 
electricity program) and also generating RINs for renewable fuel 
produced from that same volume of biogas, treated biogas, or RNG.
    (D) A party taking credit for biogas-derived renewable fuel or RNG 
under a non-transportation program (e.g., a stationary-source renewable 
electricity program) and also generating RINs for that same volume of 
biogas-derived renewable fuel or RNG.
    (E) A party taking credit for biogas, treated biogas, or RNG used 
outside the covered location and also generating RINs for renewable 
fuel produced from that same volume of biogas, treated biogas, or RNG.
    (F) A party taking credit for biogas-derived renewable fuel or RNG 
used outside the covered location and also generating RINs for that 
same volume of biogas-derived renewable fuel or RNG.
    (ii) When any party becomes aware of another party separating or 
retiring a RIN from the same volume of RNG, they must notify EPA and 
the RIN generator, if known, within 5 business days of initial 
discovery.
    (2) EPA will notify the RIN generator of the potential double 
counting if the party that identified the potential double counting 
does not know the party that generated the potentially affected RINs.
    (3) Upon notification, the RIN generator must then calculate any 
impacts to the number of RINs generated for the volume of impacted RNG 
or renewable fuel. The RIN generator must then notify EPA and the 
independent third-party auditor, if any, of the impacted RINs within 5 
business days of initial notification.
    (4) For any number of RINs over-generated due to the double 
counting of volumes of biogas or RNG, the RIN generator must follow the 
applicable procedures for invalid RINs specified in Sec.  80.1431.
    (d) Failure to take corrective action. Any person who fails to meet 
a requirement under paragraph (b) or (c) of this section is liable for 
full performance of such requirement, and each day of non-compliance is 
deemed a separate violation pursuant to Sec.  80.1460(f). The 
administrative process for replacement of invalid RINs does not, in any 
way, limit the ability of the United States to exercise any other 
authority to bring an enforcement action under section 211 of the Clean 
Air Act, the fuels regulations under this part, 40 CFR part 1090, or 
any other applicable law.
    (e) Replacing PIRs or invalid RINs. The following specifications 
apply when retiring valid RINs to replace PIRs or invalid RINs:
    (1) When a RIN is retired to replace a PIR or invalid RIN, the D 
code of the retired RIN must be eligible to be used towards meeting all 
the renewable volume obligations as the PIR or invalid RIN it is 
replacing, as specified in Sec.  80.1427(a)(2).
    (2) The number of RINs retired must be equal to the number of PIRs 
or invalid RINs being replaced.
    (f) Forms and procedures. (1) All parties that retire RINs under 
this section must use forms and procedures specified by EPA.
    (2) All parties that must notify EPA under this section must submit 
those notifications to EPA as specified in 40 CFR 1090.10.

Subpart M--Renewable Fuel Standard

0
10. Revise Sec.  80.1401 to read as follows:

Sec.  80.1401  Definitions.

    The definitions of Sec.  80.2 apply for the purposes of this 
subpart M.

Sec.  80.1402  [Amended]

0
11. Amend Sec.  80.1402 by, in paragraph (f), removing the text 
``notwithstanding'' and adding in its place the text ``regardless of''.

0
12. Amend Sec.  80.1405 by revising paragraphs (a) and (c) to read as 
follows:

Sec.  80.1405  What are the Renewable Fuel Standards?

    (a) The values of the renewable fuel standards are as follows:

                            Table 1 to Paragraph (a)--Annual Renewable Fuel Standards
----------------------------------------------------------------------------------------------------------------
                                                                                                   Supplemental
                                    Cellulosic     Biomass-based     Advanced     Renewable fuel       total
              Year                    biofuel         diesel          biofuel      standard (%)   renewable fuel
                                   standard (%)    standard (%)    standard (%)                    standard (%)
----------------------------------------------------------------------------------------------------------------
2010............................           0.004            1.10            0.61            8.25             n/a
2011............................             n/a            0.69            0.78            8.01             n/a
2012............................             n/a            0.91            1.21            9.23             n/a
2013............................          0.0005            1.13            1.62            9.74             n/a
2014............................           0.019            1.41            1.51            9.19             n/a
2015............................           0.069            1.49            1.62            9.52             n/a
2016............................           0.128            1.59            2.01           10.10             n/a
2017............................           0.173            1.67            2.38           10.70             n/a
2018............................           0.159            1.74            2.37           10.67             n/a
2019............................           0.230            1.73            2.71           10.97             n/a
2020............................            0.32            2.30            2.93           10.82             n/a
2021............................            0.33            2.16            3.00           11.19             n/a

[[Page 44581]]

 
2022............................            0.35            2.33            3.16           11.59            0.14
2023............................            0.48            2.58            3.39           11.96            0.14
2024............................            0.63            2.82            3.79           12.50             n/a
2025............................            0.81            3.15            4.31           13.13             n/a
----------------------------------------------------------------------------------------------------------------

* * * * *
    (c) EPA will calculate the annual renewable fuel percentage 
standards using the following equations:
[GRAPHIC] [TIFF OMITTED] TR12JY23.008

[GRAPHIC] [TIFF OMITTED] TR12JY23.009

[GRAPHIC] [TIFF OMITTED] TR12JY23.010

[GRAPHIC] [TIFF OMITTED] TR12JY23.011

Where:

StdCB,i = The cellulosic biofuel standard for year i, in 
percent.
StdBBD,i = The biomass-based diesel standard for year i, 
in percent.
StdAB,i = The advanced biofuel standard for year i, in 
percent.
StdRF,i = The renewable fuel standard for year i, in 
percent.
RFVCB,i = Annual volume of cellulosic biofuel required by 
42 U.S.C. 7545(o)(2)(B) for year i, or volume as adjusted pursuant 
to 42 U.S.C. 7545(o)(7)(D), in gallons.
RFVBBD,i = Annual volume of biomass-based diesel required 
by 42 U.S.C. 7545 (o)(2)(B) for year i, in gallons.
RFVAB,i = Annual volume of advanced biofuel required by 
42 U.S.C. 7545(o)(2)(B) for year i, in gallons.
RFVRF,i = Annual volume of renewable fuel required by 42 
U.S.C. 7545(o)(2)(B) for year i, in gallons.
Gi = Amount of gasoline projected to be used in the 
covered location, in year i, in gallons.
Di = Amount of diesel projected to be used in the covered 
location, in year i, in gallons.
RGi = Amount of renewable fuel blended into gasoline that 
is projected to be consumed in the covered location, in year i, in 
gallons.
RDi = Amount of renewable fuel blended into diesel that 
is projected to be consumed in the covered location, in year i, in 
gallons.
GSi = Amount of gasoline projected to be used in Alaska 
or a U.S. territory, in year i, if the state or territory has opted-
in or opts-in, in gallons.
RGSi = Amount of renewable fuel blended into gasoline 
that is projected to be consumed in Alaska or a U.S. territory, in 
year i, if the state or territory opts-in, in gallons.
DSi = Amount of diesel projected to be used in Alaska or 
a U.S. territory, in year i, if the state or territory has opted-in 
or opts-in, in gallons.
RDSi = Amount of renewable fuel blended into diesel that 
is projected to be consumed in Alaska or a U.S. territory, in year 
i, if the state or territory opts-in, in gallons.
GEi = The total amount of gasoline projected to be exempt 
in year i, in gallons, per Sec. Sec.  80.1441 and 80.1442.
DEi = The total amount of diesel fuel projected to be 
exempt in year i, in gallons, per Sec. Sec.  80.1441 and 80.1442.
* * * * *

0
13. Amend Sec.  80.1406 by:
0
a. Revising the section heading; and
0
b. Removing and reserving paragraph (a).
    The revision reads as follows:

Sec.  80.1406  Obligated party responsibilities.

* * * * *

Sec.  80.1407  [Amended]

0
14. Amend Sec.  80.1407 by:
0
a. In paragraphs (a)(1) through (4), removing the text ``48 contiguous 
states or Hawaii'' wherever it appears and adding in its place the text 
``covered location'';
0
b. In paragraphs (b) and (d), removing the text ``as defined in'' and 
adding in its place the text ``per'';
0
c. In paragraph (e), removing the text ``MVNRLM diesel fuel at Sec.  
80.2'' and adding in its place the text ``MVNRLM diesel fuel''; and
0
d. In paragraph (f)(5), removing the text ``48 United States and 
Hawaii'' and adding in its place the text ``covered location''.

0
15. Amend Sec.  80.1415 by:
0
a. In paragraph (b)(2), removing the text ``(mono-alkyl ester)'';
0
b. Revising paragraph (b)(5);
0
c. In paragraph (b)(6), removing the text ``kW-hr'' and adding in its 
place the text ``kWh'';
0
d. Revising paragraph (b)(7);

[[Page 44582]]

0
e. In paragraph (c)(1), removing the text ``EV'' wherever it appears 
and adding in its place the text ``EqV'';
0
f. In paragraph (c)(2)(ii), removing the text ``derived'' and adding in 
its place the text ``produced''; and
0
g. In paragraph (c)(5), removing the text ``the Administrator'' and 
adding in its place the text ``EPA''.
    The revisions read as follows:

Sec.  80.1415  How are equivalence values assigned to renewable fuel?

* * * * *
    (b) * * *
    (5) 77,000 Btu LHV of renewable CNG/LNG or RNG shall represent one 
gallon of renewable fuel with an equivalence value of 1.0.
* * * * *
    (7) For all other renewable fuels, a producer or importer must 
submit an application to EPA for an equivalence value following the 
provisions of paragraph (c) of this section. A producer or importer may 
also submit an application for an alternative equivalence value 
pursuant to paragraph (c) of this section if the renewable fuel is 
listed in this paragraph (b), but the producer or importer has reason 
to believe that a different equivalence value than that listed in this 
paragraph (b) is warranted.
* * * * *

Sec.  80.1416  [Amended]

0
16. Amend Sec.  80.1416 by:
0
a. In paragraphs (b)(1)(vii) and (b)(2)(vii), removing the text ``The 
Administrator'' and adding in its place the text ``EPA'';
0
b. In paragraph (c)(4), removing the text ``definitions in Sec.  
80.1401'' and adding in its place the text ``definition''; and
0
c. In paragraph (d), removing the text ``The Administrator'' and adding 
in its place the text ``EPA''.

0
17. Amend Sec.  80.1426 by:
0
a. Revising paragraph (a)(1) introductory text;
0
b. In paragraph (a)(1)(iv), removing the text ``renewable'';
0
c. Revising paragraphs (b)(1) and (c)(1) and (2);
0
d. Removing and reserving paragraph (c)(3);
0
e. Revising paragraph (c)(6);
0
f. In paragraph (c)(7), removing the text ``Sec.  80.1401'' and adding 
in its place the text ``Sec.  80.2'';
0
g. Adding a sentence to the end of paragraph (d)(1) introductory text;
0
h. Revising paragraphs (e)(1) and (f)(1)(i);
0
i. Moving table 1 to Sec.  80.1426 and table 2 to Sec.  80.1426 
immediately following paragraph (f)(1) to the end of the section;
0
j. In paragraph (f)(2)(i), removing the text ``EV'' wherever it appears 
and adding in its place the text ``EqV'';
0
k. In paragraph (f)(2)(ii), removing the text ``Table 1 to this 
section, or a D code as approved by the Administrator, which'' and 
adding in its place the text ``the approved pathway that'';
0
l. In paragraph (f)(3)(i), removing the text ``Table 1 to this section, 
or a D code as approved by the Administrator, which'' and adding in its 
place the text ``the approved pathways that'';
0
m. In paragraph (f)(3)(ii), removing the text ``EV'' wherever it 
appears and adding in its place the text ``EqV'';
0
n. In paragraph (f)(3)(iii), removing the text ``EVi'' 
wherever it appears and adding in its place the text 
``EqVi'';
0
o. In paragraph (f)(3)(iv), removing the text ``EV'' wherever it 
appears and adding in its place the text ``EqV'';
0
p. Revising paragraph (f)(3)(v);
0
q. Removing table 3 to Sec.  80.1426 immediately following paragraph 
(f)(3)(v);
0
r. Revising paragraph (f)(3)(vi);
0
s. Removing table 4 to Sec.  80.1426 immediately following paragraph 
(f)(3)(vi)(A);
0
t. In paragraphs (f)(4)(i)(A)(1) and (f)(4)(i)(B), removing the text 
``EV'' wherever it appears and adding in its place the text ``EqV'';
0
u. In paragraph (f)(4)(iv), removing the text ``80.1468'' and adding in 
its place the text ``80.12'';
0
v. In paragraphs (f)(5)(iv)(A) and (B), and (f)(5)(v), removing the 
text ``EV'' wherever it appears and adding in its place the text 
``EqV'';
0
w. In paragraph (f)(5)(v), removing the text ``biogas-derived fuels'' 
and adding in its place the text ``biogas-derived renewable fuel'';
0
x. In paragraph (f)(5)(vi), removing the text ``Table 1 to this 
section, or a D code as approved by the Administrator, which'' and 
adding in its place the text ``the approved pathway that'';
0
y. Revising paragraph (f)(6) introductory text;
0
z. In paragraph (f)(6)(i), removing the text ``EV'' wherever it appears 
and adding in its place the text ``EqV'';
0
aa. In paragraphs (f)(7)(v)(A) and (B), removing the text ``Sec.  
80.1468'' wherever it appears and adding in its place the text ``Sec.  
80.12'';
0
bb. In paragraph (f)(8)(ii) introductory text, removing the text 
``(mono-alkyl esters)'';
0
cc. In paragraphs (f)(8)(ii)(B) and (f)(9)(ii), removing the text 
``Sec.  80.1468'' wherever it appears and adding in its place the text 
``Sec.  80.12'';
0
dd. In paragraph (f)(10)(i)(A), removing the text ``the Administrator'' 
and adding in its place the text ``EPA'';
0
ee. Revising paragraph (f)(10)(ii);
0
ff. In paragraph (f)(11)(i)(A), removing the text ``the Administrator'' 
and adding in its place the text ``EPA'';
0
gg. Revising paragraphs (f)(11)(ii), (f)(12), (f)(13) introductory 
text, and (f)(13)(iii) through (v);
0
hh. Removing paragraph (f)(13)(vi);
0
ii. Revising paragraphs (f)(15), (f)(17), and (g)(1)(i) introductory 
text;
0
jj. In paragraph (g)(1)(iii), removing the text ``48 contiguous states 
plus Hawaii'' wherever it appears and adding in its place the text 
``covered location'';
0
kk. Revising paragraph (g)(2) introductory text; and
0
ll. In paragraphs (g)(3) introductory text, (g)(5)(i) introductory 
text, (g)(7) introductory text, (g)(7)(i) introductory text, and 
(g)(10) introductory text, removing the text ``48 contiguous states 
plus Hawaii'' wherever it appears and adding in its place the text 
``covered location''.
    The revisions and additions read as follows:

Sec.  80.1426  How are RINs generated and assigned to batches of 
renewable fuel?

    (a) * * *
    (1) Renewable fuel producers, importers of renewable fuel, and 
other parties allowed to generate RINs under this part may only 
generate RINs to represent renewable fuel if they meet the requirements 
of paragraphs (b) and (c) of this section and if all the following 
occur:
* * * * *
    (b) * * *
    (1) Except as provided in paragraph (c) of this section, a RIN may 
only be generated by a renewable fuel producer or importer for a batch 
of renewable fuel that satisfies the requirements of paragraph (a)(1) 
of this section if it is produced or imported for use as transportation 
fuel, heating oil, or jet fuel in the covered location.
* * * * *
    (c) * * *
    (1) No person may generate RINs for fuel that does not satisfy the 
requirements of paragraph (a)(1) of this section.
    (2) A party must not generate RINs for renewable fuel that is not 
produced for use in the covered location.
* * * * *
    (6) A party is prohibited from generating RINs for a volume of fuel 
that it produces if the fuel has been produced by a process that uses a 
renewable fuel as a feedstock, and the renewable fuel that is used as a

[[Page 44583]]

feedstock was produced by another party, except that RINs may be 
generated for such fuel if allowed by the EPA in response to a petition 
submitted pursuant to Sec.  80.1416 and the petition approval specifies 
a mechanism to prevent double counting of RINs or where RINs are 
generated for RNG.
* * * * *
    (d) * * *
    (1) * * * Biogas producers and RNG producers must use the 
definitions of batch for biogas and RNG in Sec. Sec.  80.105(j) and 
80.110(j), respectively.
* * * * *
    (e) * * *
    (1) Except as provided in paragraph (g) of this section for delayed 
RINs, the producer or importer of renewable fuel must assign all RINs 
generated from a specific batch of renewable fuel to that batch of 
renewable fuel.
* * * * *
    (f) * * *
    (1) * * *
    (i) D codes must be used in RINs generated by producers or 
importers of renewable fuel according to approved pathways or as 
specified in paragraph (f)(6) of this section.
* * * * *
    (3) * * *
    (v) If a producer produces batches that are comprised of a mixture 
of fuel types with different equivalence values and different 
applicable D codes, then separate values for VRIN must be 
calculated for each category of renewable fuel according to the 
following formula. All batch-RINs thus generated must be assigned to 
unique batch identifiers for each portion of the batch with a different 
D code.

VRIN,DX = EqVDX * VS,DX

Where:

VRIN,DX = RIN volume, in gallons, for use in determining 
the number of gallon-RINs that must be generated for the portion of 
the batch with a D code of X.
EqVDX = Equivalence value for the portion of the batch 
with a D code of X, per Sec.  80.1415.
VS,DX = Standardized volume at 60 [deg]F of the portion 
of the batch that must be assigned a D code of X, in gallons, per 
paragraph (f)(8) of this section.

    (vi)(A) If a producer produces a single type of renewable fuel 
using two or more different feedstocks that are processed 
simultaneously, and each batch is comprised of a single type of fuel, 
then the number of gallon-RINs that must be generated for a batch of 
renewable fuel and assigned a particular D code must be calculated as 
follows:
[GRAPHIC] [TIFF OMITTED] TR12JY23.012

Where:

VRIN,DX = RIN volume, in gallons, for use in determining 
the number of gallon-RINs that must be generated for a batch of 
renewable fuel with a D code of X.
EqV = Equivalence value for the renewable fuel per Sec.  80.1415.
VS = Standardized volume of the batch of renewable fuel 
at 60 [deg]F, in gallons, per paragraph (f)(8) of this section.
FEDX = The total feedstock energy from all feedstocks 
whose pathways have been assigned a D code of X, in Btu HHV, per 
paragraphs (f)(3)(vi)(B) and (C) of this section.
FEtotal = The total feedstock energy from all feedstocks, 
in Btu HHV, per paragraphs (f)(3)(vi)(B) and (C) of this section.

    (B) Except for biogas produced from anaerobic digestion, the 
feedstock energy value of each feedstock must be calculated as follows:

FEDX,i = Mi * (1-mi) * CFi

Where:

FEDX,i = The amount of energy from feedstock i that forms 
energy in the renewable fuel and whose pathway has been assigned a D 
code of X, in Btu HHV.
Mi = Mass of feedstock i, in pounds, measured on a daily 
or per-batch basis.
mi = Average moisture content of feedstock i, as a mass 
fraction.
CFi = Converted fraction in annual average Btu HHV/lb, 
except as otherwise provided by Sec.  80.1451(b)(1)(ii)(U), 
representing that portion of feedstock i that is converted to fuel 
by the producer.

    (C) For biogas produced from anaerobic digestion, the volume of 
biogas must be measured under Sec.  80.105(f) and the feedstock energy 
value of each feedstock must be calculated as specified in Sec.  
80.105(j) by substituting ``feedstock energy'' for ``batch volume of 
biogas'' in all cases.
* * * * *
    (6) Renewable fuel not covered by an approved pathway. If no 
approved pathway applies to a producer's operations, the party may 
generate RINs if the fuel from its facility is produced from renewable 
biomass and qualifies for an exemption under Sec.  80.1403 from the 
requirement that renewable fuel achieve at least a 20 percent reduction 
in lifecycle greenhouse gas emissions compared to baseline lifecycle 
greenhouse gas emissions.
* * * * *
    (10) * * *
    (ii) RIN generators may only generate RINs for renewable CNG/LNG 
produced from biogas that is distributed via a closed, private, non-
commercial system if all the following requirements are met:
    (A) The renewable CNG/LNG was produced from renewable biomass under 
an approved pathway.
    (B) The RIN generator has entered into a written contract for the 
sale or use of a specific quantity of renewable CNG/LNG for use as 
transportation fuel, or has obtained affidavits from all parties 
selling or using the renewable CNG/LNG as transportation fuel.
    (C) The renewable CNG/LNG was used as transportation fuel and for 
no other purpose.
    (D) The biogas was introduced into the closed, private, non-
commercial system no later and the renewable CNG/LNG produced from the 
biogas was used as transportation fuel no later than December 31, 2024.
    (E) RINs may only be generated on biomethane content of the 
renewable CNG/LNG used as transportation fuel.
* * * * *
    (11) * * *
    (ii) RINs for renewable CNG/LNG produced from RNG that is 
introduced into a commercial distribution system may only be generated 
if all the following requirements are met:
    (A) The renewable CNG/LNG was produced from renewable biomass and 
qualifies for a D code in an approved pathway.
    (B) The RIN generator has entered into a written contract for the 
sale or use of a specific quantity of RNG, taken from a commercial 
distribution system (e.g., physically connected pipeline, barge, truck, 
rail), for use as transportation fuel, or has obtained affidavits from 
all parties selling or using the RNG taken from a commercial 
distribution system as transportation fuel.
    (C) The renewable CNG/LNG produced from the RNG was sold for use as 
transportation fuel and for no other purpose.
    (D) The RNG was injected into and withdrawn from the same 
commercial distribution system.
    (E) The RNG was withdrawn from the commercial distribution system 
in a manner and at a time consistent with the transport of the RNG 
between the injection and withdrawal points.
    (F) The volume of RNG injected into the commercial distribution 
system and the volume of RNG withdrawn are measured by continuous 
metering.
    (G) The volume of renewable CNG/LNG sold for use as transportation 
fuel corresponds to the volume of RNG that was injected into and 
withdrawn from the commercial distribution system.
    (H) No other party relied upon the volume of biogas, RNG, or 
renewable CNG/LNG for the generation of RINs.
    (I) The RNG was introduced into the commercial distribution system 
no later than December 31, 2024, and the renewable CNG/LNG was used as

[[Page 44584]]

transportation fuel no later than December 31, 2024.
    (J) RINs may only be generated on biomethane content of the biogas, 
treated biogas, RNG, or renewable CNG/LNG.
    (K)(1) On or after January 1, 2025, RINs may only be generated for 
RNG injected into a natural gas commercial pipeline system for use as 
transportation fuel as specified in subpart E of this part.
    (2) RINs may be generated for RNG as specified in subpart E of this 
part prior to January 1, 2025, if all applicable requirements under 
this part are met.
* * * * *
    (12) Process heat produced from combustion of biogas or RNG at a 
renewable fuel production facility is considered ``derived from 
biomass'' under an approved pathway if all the following requirements 
are met, as applicable:
    (i) For biogas transported to the renewable fuel production 
facility via a biogas closed distribution system:
    (A) The renewable fuel producer has entered into a written contract 
for the procurement of a specific volume of biogas with a specific heat 
content.
    (B) The volume of biogas was sold to the renewable fuel production 
facility, and to no other facility.
    (C) The volume of biogas injected into the biogas closed 
distribution system and the volume of biogas used as process heat were 
measured under Sec.  80.155.
    (ii) For RNG injected into a natural gas commercial pipeline system 
prior to July 1, 2024:
    (A) The producer has entered into a written contract for the 
procurement of a specific volume of RNG with a specific heat content.
    (B) The volume of RNG was sold to the renewable fuel production 
facility, and to no other facility.
    (C) The volume of RNG was withdrawn from the natural gas commercial 
pipeline system in a manner and at a time consistent with the transport 
of RNG between the injection and withdrawal points.
    (D) The volume of RNG injected into the natural gas commercial 
pipeline system and the volume of RNG withdrawn were measured under 
Sec.  80.155.
    (E) The natural gas commercial pipeline system into which the RNG 
was injected ultimately serves the renewable fuel production facility.
    (iii) Process heat produced from combustion of biogas or RNG is not 
considered produced from renewable biomass if any other party relied 
upon the volume of biogas or RNG for the generation of RINs.
    (iv) For RNG used as process heat on or after July 1, 2024, the 
renewable fuel producer must retire RINs for RNG as specified in Sec.  
80.125(e).
    (13) In order for a renewable fuel production facility to satisfy 
the requirements of the advanced biofuel grain sorghum pathway, all the 
following requirements must be met:
* * * * *
    (iii) For biogas transported to the renewable fuel production 
facility via a biogas closed distribution system and used as process 
energy, the requirements in paragraph (f)(12)(i) of this section must 
be met.
    (iv)(A) For RNG injected into a commercial distribution system 
prior to July 1, 2024, and used as process energy, the requirements in 
paragraph (f)(12)(ii) of this section must be met.
    (B) For RNG injected into a natural gas commercial pipeline system 
on or after July 1, 2024, and used as process energy, the renewable 
fuel producer must retire RINs for RNG as specified in Sec.  80.125(e).
    (v) The biogas or RNG used as process energy at the renewable fuel 
production facility is not considered ``produced from renewable 
biomass'' under an approved pathway if any other party relied upon the 
volume of biogas or RNG for the generation of RINs.
* * * * *
    (15) Application of formulas in paragraph (f)(3)(vi) of this 
section to certain producers generating D3 or D7 RINs. If a producer 
seeking to generate D code 3 or 7 RINs produces a single type of 
renewable fuel using two or more feedstocks or biointermediates 
converted simultaneously, and at least one of the feedstocks or 
biointermediates does not have a minimum 75% average adjusted 
cellulosic content, one of the following additional requirements apply:

    (i) If the producer is using a thermochemical process to convert 
cellulosic biomass into cellulosic biofuel, the producer is subject to 
additional registration requirements under Sec.  
80.1450(b)(1)(xiii)(A).
    (ii) If the producer is using any process other than a 
thermochemical process, or is using a combination of processes, the 
producer is subject to additional registration requirements under Sec.  
80.1450(b)(1)(xiii)(B) or (C), and reporting requirements under Sec.  
80.1451(b)(1)(ii)(U), as applicable.
* * * * *
    (17) Qualifying use demonstration for certain renewable fuels. For 
purposes of this section, any renewable fuel other than ethanol, 
biodiesel, renewable gasoline, or renewable diesel that meets the Grade 
No. 1-D or No. 2-D specification in ASTM D975 (incorporated by 
reference, see Sec.  80.12) is considered renewable fuel and the 
producer or importer may generate RINs for such fuel only if all the 
following apply:
    (i) The fuel is produced from renewable biomass and qualifies to 
generate RINs under an approved pathway.
    (ii) The fuel producer or importer maintains records demonstrating 
that the fuel was produced for use as a transportation fuel, heating 
oil or jet fuel by any of the following:
    (A) Blending the renewable fuel into gasoline or distillate fuel to 
produce a transportation fuel, heating oil, or jet fuel that meets all 
applicable standards under this part and 40 CFR part 1090.
    (B) Entering into a written contract for the sale of the renewable 
fuel, which specifies the purchasing party must blend the fuel into 
gasoline or distillate fuel to produce a transportation fuel, heating 
oil, or jet fuel that meets all applicable standards under this part 
and 40 CFR part 1090.
    (C) Entering into a written contract for the sale of the renewable 
fuel, which specifies that the fuel must be used in its neat form as a 
transportation fuel, heating oil or jet fuel that meets all applicable 
standards.
    (ii) The fuel was sold for use in or as a transportation fuel, 
heating oil, or jet fuel, and for no other purpose.
    (g) * * *
    (1) * * *
    (i) The renewable fuel volumes can be described by a new approved 
pathway that was added after July 1, 2010.
* * * * *
    (2) When a new approved pathway is added, EPA will specify in its 
approval action the effective date on which the new pathway becomes 
valid for the generation of RINs and whether the fuel in question meets 
the requirements of paragraph (g)(1)(ii) of this section.
* * * * *

Sec.  80.1427  [Amended]

0
18. In Sec.  80.1427 amend paragraph (a)(1) introductory text by 
removing the text ``under Sec.  80.1406''.

0
19. Amend Sec.  80.1428 by revising paragraphs (a) and (b) to read as 
follows:

Sec.  80.1428  General requirements for RIN distribution.

    (a) RINs assigned to volumes of renewable fuel or RNG. (1) Except 
as provided in Sec. Sec.  80.1429 and 80.125(d), no person can separate 
a RIN that has

[[Page 44585]]

been assigned to a volume of renewable fuel or RNG pursuant to Sec.  
80.1426(e).
    (2) An assigned RIN cannot be transferred to another person without 
simultaneously transferring a volume of renewable fuel or RNG to that 
same person.
    (3) Assigned gallon-RINs with a K code of 1 can be transferred to 
another person based on the following:
    (i) Except for RNG, no more than 2.5 assigned gallon-RINs with a K 
code of 1 can be transferred to another person with every gallon of 
renewable fuel transferred to that same person.
    (ii) For RNG, the transferor of assigned RINs for RNG must transfer 
RINs under Sec.  80.125(c).
    (4)(i) Except for RNG, on each of the dates listed in paragraph 
(a)(4)(ii) of this section in any calendar year, the following equation 
must be satisfied for assigned RINs and volumes of renewable fuel owned 
by a person:

RINd <= Vd * 2.5

Where:

RINd = Total number of assigned gallon-RINs with a K code 
of 1 that are owned on date d.
Vd = Standardized total volume of renewable fuel owned on 
date d, in gallons, per Sec.  80.1426(f)(8).

    (ii) The applicable dates are March 31, June 30, September 30, and 
December 31.
    (5) Any transfer of ownership of assigned RINs must be documented 
on product transfer documents generated pursuant to Sec.  80.1453.
    (i) The RIN must be recorded on the product transfer document used 
to transfer ownership of the volume of renewable fuel or RNG to another 
person; or
    (ii) The RIN must be recorded on a separate product transfer 
document transferred to the same person on the same day as the product 
transfer document used to transfer ownership of the volume of renewable 
fuel or RNG.
    (b) RINs separated from volumes of renewable fuel or RNG.
    (1) Unless otherwise specified, any person that has registered 
pursuant to Sec.  80.1450 can own a separated RIN.
    (2) Separated RINs can be transferred any number of times.
* * * * *

0
20. Amend Sec.  80.1429 by:
0
a. Revising the section heading;
0
b. In paragraphs (a)(1), (a)(2) and (b) introductory text, removing the 
text ``renewable fuel'' wherever it appears and adding in its place the 
text ``renewable fuel or RNG'';
0
c. Revising paragraph (b)(1);
0
d. Redesignating paragraph (b)(5) as paragraph (b)(5)(i);
0
e. Adding paragraph (b)(5)(ii);
0
f. In paragraph (b)(6) introductory text, removing the text ``(mono-
alkyl ester)'' wherever it appears;
0
g. Revising paragraph (b)(10); and
0
h. In paragraphs (c), (d), and (e), removing the text ``renewable 
fuel'' and adding in its place the text ``renewable fuel or RNG''.
    The revisions and addition read as follows:

Sec.  80.1429  Requirements for separating RINs from volumes of 
renewable fuel or RNG.

* * * * *
    (b) * * *
    (1) Except as provided in paragraphs (b)(7) and (9) of this section 
and Sec.  80.125(d)(3), an obligated party must separate any RINs that 
have been assigned to a volume of renewable fuel if that party owns 
that volume.
* * * * *
    (5) * * *
    (ii)(A) Any biogas closed distribution system RIN generator that 
generates RINs for a batch of renewable CNG/LNG under Sec.  80.130(b) 
may only separate RINs that have been assigned to that batch after the 
party demonstrates that the renewable CNG/LNG was used as 
transportation fuel.
    (B) Only an RNG RIN separator may only separate the RINs that have 
been assigned to a volume of RNG after meeting all applicable 
requirements in Sec.  80.125(d)(2).
* * * * *
    (10) Any party that produces a volume of renewable fuel or RNG may 
separate any RINs that have been generated to represent that volume of 
renewable fuel or RNG if that party retires the separated RINs to 
replace invalid RINs according to Sec.  80.1474.
* * * * *

Sec.  80.1430  [Amended]

0
21. Amend Sec.  80.1430 by, in paragraph (e)(2), removing the text 
``Sec.  80.1468'' and adding in its place the text ``Sec.  80.12''.

0
22. Amend Sec.  80.1431 by:
0
a. Revising paragraph (a)(1)(vi);
0
b. Adding paragraphs (a)(1)(viii), (a)(1)(x), and (a)(4);
0
c. Revising paragraphs (b) introductory text and (c) introductory text; 
and
0
d. In paragraph (c)(7)(ii)(P), removing the text ``the Administrator'' 
and adding in its place the text ``that EPA''.
    The revisions and additions read as follows:

Sec.  80.1431  Treatment of invalid RINs.

    (a) * * *
    (1) * * *
    (vi) Does not represent renewable fuel or RNG.
* * * * *
    (viii) Was generated for fuel that was not used in the covered 
location.
* * * * *
    (x) Was inappropriately separated under Sec.  80.125(d).
* * * * *
    (4) If any RIN generated for a batch of renewable fuel that had 
RINs apportioned through Sec.  80.1426(f)(3) is invalid, then all RINs 
generated for that batch of renewable fuel are deemed invalid, unless 
EPA in its sole discretion determines that some portion of those RINs 
are valid.
    (b) Except as provided in paragraph (c) of this section and Sec.  
80.1473, the following provisions apply in the case of RINs that are 
invalid:
* * * * *
    (c) Improperly generated RINs may be used for compliance provided 
that all the following conditions and requirements are satisfied and 
the RIN generator demonstrates that the conditions and requirements are 
satisfied through the reporting and recordkeeping requirements set 
forth below, that:
* * * * *

0
23. Amend Sec.  80.1434 by:
0
a. Revising paragraphs (a)(1) and (5); and
0
b. Redesignating paragraph (a)(11) as paragraph (a)(13) and adding new 
paragraphs (a)(11) and (12).
    The revisions and additions read as follows:

Sec.  80.1434  RIN retirement.

    (a) * * *
    (1) Demonstrate annual compliance. Except as specified in paragraph 
(b) of this section or Sec.  80.1456, an obligated party required to 
meet the RVO under Sec.  80.1407 must retire a sufficient number of 
RINs to demonstrate compliance with an applicable RVO.
* * * * *
    (5) Spillage, leakage, or disposal of renewable fuels. Except as 
provided in Sec.  80.1432(c), in the event that a reported spillage, 
leakage, or disposal of any volume of renewable fuel, the owner of the 
renewable fuel must notify any holder or holders of the attached RINs 
and retire a number of gallon-RINs corresponding to the volume of 
spilled or disposed of renewable fuel multiplied by its equivalence 
value in accordance with Sec.  80.1432(b).
* * * * *
    (11) Used to produce other renewable fuel. Any party that uses 
renewable fuel

[[Page 44586]]

or RNG to produce other renewable fuel must retire any assigned RINs 
for the volume of the renewable fuel or RNG.
    (12) Expired RINs for RNG. Any party owning RINs assigned to RNG as 
specified in Sec.  80.125(e) must retire the assigned RIN.
* * * * *

Sec.  80.1435  [Amended]

0
24. Amend Sec.  80.1435 by:
0
a. In paragraphs (b)(1)(i) and (ii) and (b)(2)(i) through (iv), 
removing the text ``RIN-gallons'' wherever it appears and adding in its 
place the text ``gallon-RINs''; and
0
b. In paragraph (b)(2)(iii), removing the text ``48 contiguous states 
or Hawaii'' wherever it appears and adding in its place the text 
``covered location''.

0
25. Amend Sec.  80.1441 by:
0
a. Revising paragraph (a)(1);
0
b. Removing and reserving paragraph (a)(3);
0
c. Removing paragraph (b)(3);
0
d. In paragraph (e)(1) and (2) introductory text, removing the text 
``the Administrator'' and adding in its place the text ``EPA'';
0
e. In paragraph (e)(2)(ii), removing the text ``The Administrator'' and 
adding in its place the text ``EPA''.
0
f. In paragraph (e)(2)(iii), removing the text ``Sec.  80.1401'' 
wherever it appears and adding in its place the text ``Sec.  80.2''; 
and
0
g. In paragraph (g), removing the text ``defined under'' and adding in 
its place the text ``specified in''.
    The revision reads as follows:

Sec.  80.1441  Small refinery exemption.

    (a)(1) Transportation fuel produced at a refinery by a refiner is 
exempt from January 1, 2010, through December 31, 2010, from the 
renewable fuel standards of Sec.  80.1405, and the owner or operator of 
the refinery is exempt from the requirements that apply to obligated 
parties under this subpart M for fuel produced at the refinery if the 
refinery meets the definition of ``small refinery'' in Sec.  80.2 for 
calendar year 2006.
* * * * *

0
26. Amend Sec.  80.1442 by:
0
a. Removing and reserving paragraph (a)(2);
0
b. Removing paragraphs (b)(4) and (5); and
0
c. Revising paragraph (c)(1).
    The revision reads as follows

Sec.  80.1442  What are the provisions for small refiners under the RFS 
program?

* * * * *
    (c) * * *
    (1) Transportation fuel produced by a small refiner pursuant to 
paragraph (b)(1) of this section is exempt from January 1, 2010, 
through December 31, 2010, from the renewable fuel standards of Sec.  
80.1405 and the requirements that apply to obligated parties under this 
subpart if the refiner meets all the criteria of paragraph (a)(1) of 
this section.
* * * * *

Sec.  80.1443  [Amended]

0
27. Amend Sec.  80.1443 by:
0
a. In paragraphs (a), (b), and (e) introductory text, removing the text 
``the Administrator'' and adding in its place the text ``EPA''; and
0
b. In paragraph (e)(2), removing the text ``as defined in Sec.  
80.1406''.

Sec.  80.1449  [Amended]

0
28. Amend Sec.  80.1449 by, in paragraph (e), removing the text ``the 
Administrator'' and adding in its place the text ``EPA''.

0
29. Amend Sec.  80.1450 by:
0
a. Revising the first sentence of paragraph (a);
0
b. Revising paragraphs (b)(1) introductory text and (b)(1)(ii);
0
c. In paragraph (b)(1)(v) introductory text, removing the text ``as 
defined in Sec.  80.1401'';
0
d. Revising paragraph (b)(1)(v)(E);
0
e. Adding paragraph (b)(1)(v)(F);
0
f. In paragraph (b)(1)(vi), removing the text ``defined' and adding in 
its place the text ``specified'';
0
g. Adding paragraph (b)(1)(viii)(E);
0
h. In paragraphs (b)(1)(xi) introductory text, (b)(1)(xi)(A), and (B), 
removing the text ``Sec.  80.1401'' and adding in its place the text 
``Sec.  80.2'';
0
i. In paragraph (b)(1)(xii) introductory text, removing the text 
``Sec.  80.1468'' and adding in its place the text ``Sec.  80.12'';
0
j. Revising paragraph (b)(1)(xiii)(B) introductory text;
0
k. Adding paragraph (b)(1)(xiii)(C);
0
l. Revising paragraph (b)(1)(xv)(B);
0
m. Revising the first sentence of paragraph (b)(2) introductory text;
0
n. In paragraph (b)(2)(iii), removing the text ``the Administrator'' 
and adding in its place the text ``EPA'';
0
o. Adding paragraph (b)(2)(vii);
0
p. Revising paragraphs (d)(3) and (g)(10)(ii); and
0
q. In paragraphs (g)(11)(i), (ii), (iii), and (i)(1), removing the text 
``The Administrator'' and adding in its place the text ``EPA''.
    The revisions and additions read as follows:

Sec.  80.1450  What are the registration requirements under the RFS 
program?

    (a) * * * Any obligated party or any exporter of renewable fuel 
must provide EPA with the information specified for registration under 
40 CFR 1090.805, if such information has not already been provided 
under the provisions of this part. * * *
    (b) * * *
    (1) A description of the types of renewable fuels, RNG, ethanol, or 
biointermediates that the producer intends to produce at the facility 
and that the facility is capable of producing without significant 
modifications to the existing facility. For each type of renewable 
fuel, RNG, ethanol, or biointermediate the renewable fuel producer or 
foreign ethanol producer must also provide all the following:
* * * * *
    (ii) A description of the facility's renewable fuel, RNG, ethanol, 
or biointermediate production processes, including:
* * * * *
    (v) * * *
    (E)(1) For parties registered to generate RINs for renewable CNG/
LNG prior to July 1, 2024, the registration requirements under 
paragraph (b)(1)(v)(D) under this section apply until December 31, 
2024.
    (2) For biogas producers, RNG producers, and biogas closed 
distribution system RIN generators not registered prior to July 1, 
2024, the registration requirements under Sec.  80.135 apply.
    (F) Any other records as requested by EPA.
* * * * *
    (viii) * * *
    (E) The independent third-party engineer must visit all material 
recovery facilities as part of the engineering review site visit under 
Sec.  80.1450(b)(2) and (d)(3), as applicable.
* * * * *
    (xiii) * * *
    (B) A renewable fuel producer seeking to generate D code 3 or D 
code 7 RINs, a foreign ethanol producer seeking to have its product 
sold as cellulosic biofuel after it is denatured, or a biointermediate 
producer seeking to have its biointermediate made into cellulosic 
biofuel, who intends to produce a single type of fuel using two or more 
feedstocks converted simultaneously, where at least one of the 
feedstocks does not have a minimum 75% adjusted cellulosic content, and 
who uses a process other than a thermochemical process, excluding 
anerobic digestion, or a combination of processes to convert feedstock 
into renewable fuel or biointermediate, must provide all the following:
* * * * *

[[Page 44587]]

    (C) A renewable fuel producer seeking to generate D code 3 or D 
code 7 RINs or a biointermediate producer seeking to have its 
biointermediate made into cellulosic biofuel, who intends to produce 
biogas using two or more feedstocks converted simultaneously in an 
anaerobic digester, where at least one of the feedstocks does not have 
a minimum 75% adjusted cellulosic content, must supply the information 
specified in Sec.  80.135(c)(10).
* * * * *
    (xv) * * *
    (B) A written justification which explains why each feedstock a 
producer lists according to paragraph (b)(1)(xv)(A) of this section 
meets the definition of crop residue.
* * * * *
    (2) An independent third-party engineering review and written 
report and verification of the information provided pursuant to 
paragraph (b)(1) of this section and Sec.  80.135, as applicable. * * *
* * * * *
    (vii) Reports required under this paragraph (b)(2) must be 
electronically submitted directly to EPA by an independent third-party 
engineer using forms and procedures established by EPA.
* * * * *
    (d) * * *
    (3) All renewable fuel producers, foreign ethanol producers, and 
biointermediate producers must update registration information and 
submit an updated independent third-party engineering review as 
follows:
    (i) For all renewable fuel producers and foreign ethanol producers 
registered in calendar year 2010, the updated registration information 
and independent third-party engineering review must be submitted to EPA 
by January 31, 2013, and by January 31 of no less frequent than every 
third calendar year thereafter.
    (ii) For all renewable fuel producers, foreign ethanol producers, 
and biointermediate producers registered in any calendar year after 
2010, the updated registration information and independent third-party 
engineering review must be submitted to EPA by January 31 of no less 
frequent than every third calendar year after the date of the first 
independent third-party engineering review site visit conducted under 
paragraph (b)(2) of this section. For example, if a renewable fuel 
producer arranged for a third-party engineer to conduct the first site 
visit on December 15, 2023, the three-year independent third-party 
engineer review must be submitted by January 31, 2027.
    (iii) For all renewable fuel producers, the updated independent 
third-party engineering review must include all the following:
    (A) The engineering review and written report and verification 
required by paragraph (b)(2) of this section.
    (B) A detailed review of the renewable fuel producer's calculations 
and assumptions used to determine VRIN of a representative 
sample of batches of each type of renewable fuel produced since the 
last registration. This representative sampling must adhere to all the 
following, as applicable:
    (1) The representative sample must be selected in accordance with 
the sample size guidelines set forth at 40 CFR 1090.1805.
    (2) For updated independent third-party engineering reviews 
submitted after January 31, 2024, the representative sample must be 
selected from batches of renewable fuel produced through at least the 
second quarter of the calendar year prior to the applicable January 31 
deadline.
    (iv) For biointermediate producers, in addition to conducting the 
engineering review and written report and verification required by 
paragraph (b)(2) of this section, the updated independent third-party 
engineering review must include a detailed review of the 
biointermediate producer's calculations used to determine the renewable 
biomass and cellulosic renewable biomass proportions, as required to be 
reported to EPA under Sec.  80.1451(j), of a representative sample of 
batches of each type of biointermediate produced since the last 
registration. The representative sample must be selected in accordance 
with the sample size guidelines set forth at 40 CFR 1090.1805.
    (v) For updated independent third-party engineering reviews 
submitted after January 31, 2024, independent third-party engineers 
must conduct site visits required under this paragraph (d) no sooner 
than July 1 of the calendar year prior to the applicable January 31 
deadline.
    (vi) For updated independent third-party engineering reviews 
submitted after January 31, 2024, the site visits required under this 
paragraph (d) must occur when the renewable fuel production facility is 
producing renewable fuel or when the biointermediate production 
facility is producing biointermediates.
    (vii) If a renewable fuel producer, foreign ethanol producer, or 
biointermediate producer updates their registration information and 
independent third-party engineering review prior to the next applicable 
January 31 deadline, and the registration information and independent 
third-party engineering review meet all applicable requirements under 
paragraphs (b)(2) and (d)(3)(iii) of this section, the next required 
registration information and independent third-party engineering review 
update is due by January 31 of every third calendar year after the date 
of the updated independent third-party engineering review site visit.
* * * * *
    (g) * * *
    (10) * * *
    (ii) The independent third-party auditor submits an affidavit 
affirming that they have only verified RINs and biointermediates using 
a QAP approved under Sec.  80.1469 and notified all appropriate parties 
of all potentially invalid RINs as described in Sec.  80.1471(d).
* * * * *

0
30. Effective February 1, 2024, amend Sec.  80.1450 by revising 
paragraph (b)(2)(ii) and adding paragraphs (b)(2)(viii) through (x) to 
read as follows:

Sec.  80.1450  What are the registration requirements under the RFS 
program?

* * * * *
    (b) * * *
    (2) * * *
    (ii) The independent third-party engineer and its contractors and 
subcontractors must meet the independence requirements specified in 
Sec.  80.1471(b)(1), (2), (4), (5), and (7) through (12).
* * * * *
    (viii) The independent third-party engineer must conduct 
engineering reviews as follows:
    (A)(1) To verify the accuracy of the information provided in 
paragraph (b)(1)(ii) of this section, the independent third-party 
engineer must conduct independent calculations of the throughput rate-
limiting step in the production process, take digital photographs of 
all process units depicted in the process flow diagram during the site 
visit, and certify that all process unit connections are in place and 
functioning based on the site visit.
    (2) Digital photographs of a process unit are not required if the 
third-party engineer submits documentation demonstrating why they were 
unable to access certain locations due to access issues or safety 
concerns. EPA may not accept a registration if EPA is unable to 
determine whether the facility is capable of producing the requested 
renewable fuel, biointermediate, biogas, or RNG, as applicable, due to 
the lack

[[Page 44588]]

of sufficient digital photographs of process units for the facility.
    (B) To verify the accuracy of the information in paragraph 
(b)(1)(iii) of this section, the independent third-party engineer must 
obtain independent documentation from parties in contracts with the 
producer for any co-product sales or disposals. The independent third-
party engineer may use representative sampling as specified in 40 CFR 
1090.1805 to verify co-product sales or disposals.
    (C) To verify the accuracy of the information provided in paragraph 
(b)(1)(iv) of this section, the independent third-party engineer must 
obtain independent documentation from all process heat fuel suppliers 
of the process heat fuel supplied to the facility. The independent 
third-party engineer may use representative sampling as specified in 40 
CFR 1090.1805 to verify fuel suppliers.
    (D) To verify the accuracy of the information provided in paragraph 
(b)(1)(v) of this section, the independent third-party engineer must 
conduct independent calculations of the Converted Fraction that will be 
used to generate RINs.
    (ix) The independent third-party engineer must provide to EPA 
documentation demonstrating that a site visit, as specified in 
paragraph (b)(2) of this section, occurred. Such documentation must 
include digital photographs with date and geographic coordinates taken 
during the site visit and a description of what is depicted in the 
photographs.
    (x) The independent third-party engineer must sign, date, and 
submit to EPA with the written report the following conflict of 
interest statement:
    ``I certify that the engineering review and written report required 
and submitted under 40 CFR 80.1450(b)(2) was conducted and prepared by 
me, or under my direction or supervision, in accordance with a system 
designed to assure that qualified personnel properly gather and 
evaluate the information upon which the engineering review was 
conducted and the written report is based. I further certify that the 
engineering review was conducted and this written report was prepared 
pursuant to the requirements of 40 CFR part 80 and all other applicable 
auditing, competency, independence, impartiality, and conflict of 
interest standards and protocols. Based on my personal knowledge and 
experience, and inquiry of personnel involved, the information 
submitted herein is true, accurate, and complete. I am aware that there 
are significant penalties for submitting false information, including 
the possibility of fines and imprisonment for knowing violations.''
* * * * *

0
31. Amend Sec.  80.1451 by:
0
a. In paragraph (a) introductory text, removing the text ``described in 
Sec.  80.1406'' and ``described in Sec.  80.1430'';
0
b. Revising paragraph (a)(1)(iii);
0
c. In paragraph (a)(1)(vi), removing the text ``defined'' and adding in 
its place the text ``specified'';
0
d. Revising paragraphs (a)(1)(viii) and (ix);
0
e. In paragraph (a)(1)(xiii), removing the text ``the Administrator'' 
and adding in its place the text ``EPA'';
0
f. Revising paragraphs (a)(1)(xvi), (xvii), and (xviii);
0
g. In paragraph (b)(1)(ii)(O), removing the text ``as defined in Sec.  
80.1401'';
0
h. In paragraph (b)(1)(ii)(T), removing the text ``Sec.  80.1468'' and 
adding in its place the text ``Sec.  80.12'';
0
i. Revising paragraph (b)(1)(ii)(U) introductory text;
0
j. In paragraph (b)(1)(ii)(W), removing the text ``the Administrator'' 
and adding in its place the text ``that EPA'';
0
k. In paragraph (c)(1)(iii)(K), removing the text ``the Administrator'' 
and adding in its place the text ``EPA'';
0
l. In paragraphs (c)(2)(i)(J) and (L), removing the text ``as defined 
in'' and adding in its place the text ``under'';
0
m. In paragraph (c)(2)(i)(R), removing the text ``the Administrator'' 
and adding in its place the text ``EPA'';
0
n. In paragraphs (c)(2)(ii)(D)(8) and (10), removing the text ``as 
defined in'' and adding in its place the text ``under'';
0
o. In paragraph (c)(2)(ii)(I), removing the text ``the Administrator'' 
and adding in its place the text ``EPA'';
0
p. In paragraph (e) introductory text, removing the text ``as defined 
in Sec.  80.1401 who'' and adding in its place the text ``that'';
0
q. Adding paragraph (f)(4);
0
r. Revising paragraphs (g) introductory text, (g)(1), (g)(2) 
introductory text, and (g)(2)(vii) through (xi);
0
s. Adding paragraph (g)(2)(xii);
0
t. In paragraph (h)(2), removing the text ``the Administrator'' and 
adding in its place the text ``EPA'';
0
u. In paragraph (j)(1)(xvi), removing the text ``the Administrator'' 
and adding in its place the text ``that EPA''; and
0
v. In paragraph (k), removing the text ``the Administrator'' and adding 
in its place the text ``EPA''.
    The revisions and additions read as follows:

Sec.  80.1451  What are the reporting requirements under the RFS 
program?

    (a) * * *
    (1) * * *
    (iii) Whether the refiner is complying on a corporate (aggregate) 
or facility-by-facility basis.
* * * * *
    (viii) The total current-year RINs by category of renewable fuel 
(i.e., cellulosic biofuel, biomass-based diesel, advanced biofuel, 
renewable fuel, and cellulosic diesel), retired for compliance.
    (ix) The total prior-year RINs by renewable fuel category retired 
for compliance.
* * * * *
    (xvi) The total current-year RINs by category of renewable fuel 
(i.e., cellulosic biofuel, biomass-based diesel, advanced biofuel, 
renewable fuel, and cellulosic diesel), retired for compliance that are 
invalid as specified in Sec.  80.1431(a).
    (xvii) The total prior-year RINs by renewable fuel category retired 
for compliance that are invalid as specified in Sec.  80.1431(a).
    (xviii) A list of all RINs that were retired for compliance in the 
reporting period and are invalid as specified in Sec.  80.1431(a).
* * * * *
    (b) * * *
    (1) * * *
    (ii) * * *
    (U) Producers generating D code 3 or 7 RINs for cellulosic biofuel 
other than RNG or biogas-derived renewable fuel, and that was produced 
from two or more feedstocks converted simultaneously, at least one of 
which has less than 75% average adjusted cellulosic content, and using 
a combination of processes or a process other than a thermochemical 
process or a combination of processes, must report all the following:
* * * * *
    (f) * * *
    (4) Monthly reporting schedule. Any party required to submit 
information or reports on a monthly basis must submit such information 
or reports by the end of the subsequent calendar month.
    (g) Independent third-party auditors. Any independent third-party 
auditor must submit quarterly reports as follows:
    (1) The following information for each verified batch, as 
applicable:
    (i) The audited party's name.
    (ii) The audited party's EPA company registration number.
    (iii) The audited party's EPA facility registration number.
    (iv)(A) The renewable fuel importer's EPA facility registration 
number and foreign renewable fuel producer's company registration 
number.
    (B) The RNG importer's EPA facility registration number and foreign 
RNG

[[Page 44589]]

producer's company registration number.
    (v) The applicable reporting period.
    (vi) The quantity of RINs generated for each verified batch 
according to Sec. Sec.  80.125, 80.130, and 80.1426.
    (vii) The production date of each verified batch.
    (viii) The D-code of each verified batch.
    (ix) The volume of ethanol denaturant and applicable equivalence 
value of each verified batch.
    (x) The volume of each verified batch produced.
    (xi) The volume and type of each feedstock and biointermediate used 
to produce the verified batch.
    (xii) Whether the feedstocks and biointermediates used to produce 
each verified batch met the definition of renewable biomass.
    (xiii) Whether appropriate RIN generation and verified batch volume 
calculations under this part were followed for each verified batch.
    (xiv) The quantity and type of co-products produced.
    (xv) Invoice document identification numbers associated with each 
verified batch.
    (xvi) Laboratory sample identification numbers for each verified 
batch associated with the generation of any certificates of analysis 
used to verify fuel type and quality.
    (xvii) Any additional information that EPA may require.
    (2) The following aggregate verification information, as 
applicable:
* * * * *
    (vii) A list of all audited facilities, including the EPA's company 
and facility registration numbers, along with the date the independent 
third-party auditor conducted the on-site visit and audit.
    (viii) Mass and energy balances calculated for each audited 
facility.
    (ix) A list of all RINs that were identified as Potentially Invalid 
RINs (PIRs) pursuant to Sec. Sec.  80.185 and 80.1474, along with a 
narrative description of why the RINs were not verified or were 
identified as PIRs.
    (x) A list of all biointermediates that were identified as 
potentially improperly produced biointermediates under Sec.  
80.1477(d).
    (xi) A list of all biogas that was identified as potentially 
inaccurate or non-qualifying under Sec.  80.185(b).
    (xii) Any additional information that EPA may require.
* * * * *

Sec.  80.1452  [Amended]

0
32. Amend Sec.  80.1452 by:
0
a. In paragraph (b)(14), removing the text ``as defined in Sec.  
80.1401'';
0
b. In paragraph (b)(18), removing the text ``the Administrator'' and 
adding in its place the text ``that EPA''; and
0
c. In paragraphs (c)(14) and (d), removing the text ``the 
Administrator'' and adding in its place the text ``EPA''.

0
33. Amend Sec.  80.1453 by:
0
a. Revising paragraphs (a) introductory text, (a)(12) introductory 
text, and (a)(12)(v);
0
b. Adding paragraph (a)(12)(viii);
0
c. In paragraphs (d) and (f)(1)(vi), removing the text ``Sec.  
80.1401'' and adding in its place the text ``Sec.  80.2''; and
0
d. Adding paragraph (f)(1)(vii).
    The revisions and additions read as follows:

Sec.  80.1453  What are the product transfer document (PTD) 
requirements for the RFS program?

    (a) On each occasion when any party transfers ownership of neat or 
blended renewable fuels or RNG, except when such fuel is dispensed into 
motor vehicles or nonroad vehicles, engines, or equipment, or separated 
RINs subject to this subpart, the transferor must provide to the 
transferee documents that include all the following information, as 
applicable:
* * * * *
    (12) For the transfer of renewable fuel or RNG for which RINs were 
generated, an accurate and clear statement on the product transfer 
document of the fuel type from the approved pathway, and designation of 
the fuel use(s) intended by the transferor, as follows:
* * * * *
    (v) Naphtha. ``This volume of neat or blended naphtha is designated 
and intended for use as transportation fuel or jet fuel in the 48 U.S. 
contiguous states and Hawaii. This naphtha may only be used as a 
gasoline blendstock, E85 blendstock, or jet fuel. Any person exporting 
this fuel is subject to the requirements of 40 CFR 80.1430.''.
* * * * *
    (viii) RNG. ``This volume of RNG is designated and intended for 
transportation use in the 48 U.S. contiguous states and Hawaii or as a 
feedstock to produce a renewable fuel and may not be used for any other 
purpose. Any person exporting this fuel is subject to the requirements 
of 40 CFR 80.1430. Assigned RINs to this volume of RNG must not be 
separated unless the RNG is used as transportation fuel in the 48 U.S. 
contiguous states and Hawaii.''
* * * * *
    (f) * * *
    (1) * * *
    (vii) For biogas designated for use as a biointermediate, any 
applicable PTD requirements under Sec.  80.150.
* * * * *

0
34. Amend Sec.  80.1454 by:
0
a. In paragraph (a) introductory text, removing the text ``(as 
described at Sec.  80.1406)'' and ``(as described at Sec.  80.1430)'';
0
b. In paragraph (b) introductory text, removing the text ``as defined 
in Sec.  80.1401'';
0
c. Revising paragraphs (b)(3)(ix) and (xii);
0
d. In paragraph (b)(8), removing the text ``Sec.  80.1401'' and adding 
in its place the text ``Sec.  80.2'';
0
e. In paragraph (c)(1) introductory text, removing the text ``(as 
defined in Sec.  80.1401)'';
0
f. In paragraph (c)(1)(iii), removing the text ``as defined in Sec.  
80.1401'';
0
g. In paragraph (c)(2) introductory text, removing the text ``(as 
defined in Sec.  80.1401)'';
0
h. Adding paragraphs (c)(2)(vii) and (c)(3);
0
i. Removing paragraph (d) introductory text;
0
j. Redesignating paragraphs (d)(1) through (4) as paragraphs (d)(2) 
through (5), respectively, and adding a new paragraph (d)(1);
0
k. In newly redesignated paragraph (d)(2)(ii), removing the text 
``(d)(1)(i)'' and adding in its place the text ``(d)(2)(i)'';
0
l. In newly redesignated paragraph (d)(4)(ii)(B), removing the text 
``(d)(3)(ii)(A)'' and adding in its place the text ``(d)(4)(ii)(A)'';
0
m. Revising newly redesignated paragraph (d)(5);
0
n. Adding paragraph (d)(6);
0
o. In paragraphs (h)(3)(iv) and (v), removing the text ``as defined in 
Sec.  80.1401'';
0
p. Removing paragraphs (h)(6)(vi) and (vii);
0
q. Revising paragraph (j) introductory text;
0
r. In paragraphs (j)(1)(iii), (j)(2)(iv), and (k)(1)(vii), removing the 
text ``the Administrator'' and adding in its place the text ``EPA'';
0
s. Revising paragraphs (k)(2) and (l) introductory text;
0
t. In paragraphs (l)(4) and (m)(11), removing the text ``the 
Administrator'' and adding in its place the text ``EPA'';
0
u. In paragraph (t), removing the text ``the Administrator or the 
Administrator's authorized representative'' and adding in its place the 
text ``EPA''; and
0
v. In paragraph (v), removing the text ``the Administrator'' and adding 
in its place the text ``EPA''.

[[Page 44590]]

    The revisions and additions read as follows:

Sec.  80.1454  What are the recordkeeping requirements under the RFS 
program?

* * * * *
    (b) * * *
    (3) * * *
    (ix) All facility-determined values used in the calculations under 
Sec.  80.1426(f)(4) and the data used to obtain those values.
* * * * *
    (xii) For RINs generated for ethanol produced from corn starch at a 
facility using an approved pathway that requires the use of one or more 
of the advanced technologies listed in Table 2 to Sec.  80.1426, 
documentation to demonstrate that employment of the required advanced 
technology or technologies was conducted in accordance with the 
specifications in the approved pathway and Table 2 to Sec.  80.1426, 
including any requirement for application to 90% of the production on a 
calendar year basis.
* * * * *
    (c) * * *
    (2) * * *
    (vii) For renewable fuel or biointermediate produced from a type of 
renewable biomass not specified in paragraphs (c)(1)(i) through (vi) of 
this section, documents from their feedstock suppliers and feedstock 
aggregators, as applicable, certifying that the feedstock qualifies as 
renewable biomass, describing the feedstock.
    (3) Producers of renewable fuel or biointermediate produced from 
separated yard and food waste, biogenic oils/fats/greases, or separated 
MSW must comply with either the recordkeeping requirements in paragraph 
(j) of this section or the alternative recordkeeping requirements in 
Sec.  80.1479.
    (d) Additional requirements for domestic producers of renewable 
fuel. (1) Except as provided in paragraphs (g) and (h) of this section, 
any domestic producer of renewable fuel that generates RINs for such 
fuel must keep documents associated with feedstock purchases and 
transfers that identify where the feedstocks were produced and are 
sufficient to verify that feedstocks used are renewable biomass if RINs 
are generated.
* * * * *
    (5) Domestic producers of renewable fuel or biointermediates 
produced from a type of renewable biomass not specified in paragraphs 
(d)(2) through (4) of this section must have documents from their 
feedstock suppliers and feedstock aggregators, as applicable, 
certifying that the feedstock qualifies as renewable biomass, 
describing the feedstock.
    (6) Producers of renewable fuel or biointermediate produced from 
separated yard and food waste, biogenic oils/fats/greases, or separated 
MSW must comply with either the recordkeeping requirements in paragraph 
(j) of this section or the alternative recordkeeping requirements in 
Sec.  80.1479.
* * * * *
    (j) Additional requirements for producers that use separated yard 
waste, separate food waste, separated MSW, or biogenic waste oils/fats/
greases. Except for parties complying with the alternative 
recordkeeping requirements in Sec.  80.1479, a renewable fuel or 
biointermediate producer that produces fuel or biointermediate from 
separated yard waste, separated food waste, separated MSW, or biogenic 
waste oils/fats/greases must keep all the following additional records:
* * * * *
    (k) * * *
    (2) Biogas and electricity in pathways involving grain sorghum as 
feedstock. A renewable fuel producer that produces fuel pursuant to a 
pathway that uses grain sorghum as a feedstock must keep all the 
following additional records, as appropriate:
    (i) Contracts and documents memorializing the purchase and sale of 
biogas and the transfer of biogas from the point of generation to the 
ethanol production facility.
    (ii) If the advanced biofuel pathway is used, documents 
demonstrating the total kilowatt-hours (kWh) of electricity used from 
the grid, and the total kWh of grid electricity used on a per gallon of 
ethanol basis, pursuant to Sec.  80.1426(f)(13).
    (iii) Affidavits from the biogas producer used at the facility, and 
all parties that held title to the biogas, confirming that title and 
environmental attributes of the biogas relied upon under Sec.  
80.1426(f)(13) were used for producing ethanol at the renewable fuel 
production facility and for no other purpose. The renewable fuel 
producer must obtain these affidavits for each quarter.
    (iv) The biogas producer's Compliance Certification required under 
Title V of the Clean Air Act.
    (v) Such other records as may be requested by EPA.
    (l) Additional requirements for producers or importers of any 
renewable fuel other than ethanol, biodiesel, renewable gasoline, 
renewable diesel, biogas-derived renewable fuel, or renewable 
electricity. A renewable fuel producer that generates RINs for any 
renewable fuel other than ethanol, biodiesel, renewable gasoline, 
renewable diesel that meets the Grade No. 1-D or No. 2-D specification 
in ASTM D975 (incorporated by reference, see Sec.  80.12), biogas-
derived renewable fuel or renewable electricity must keep all the 
following additional records:
* * * * *

Sec.  80.1455  [Removed and Reserved]

0
35. Remove and reserve Sec.  80.1455.

Sec.  80.1457  [Amended]

0
36. Amend Sec.  80.1457 by, in paragraph (b)(8), removing the text 
``the Administrator'' and adding in its place the text ``that EPA''.
    37. Add Sec.  80.1458 to read as follows:

Sec.  80.1458  Storage of renewable fuel, RNG, or biointermediate prior 
to registration.

    (a) Applicability. (1) A renewable fuel producer may store 
renewable fuel for the generation of RINs prior to EPA acceptance of 
their registration under Sec.  80.1450(b) if all the requirements of 
this section are met.
    (2) An RNG producer may store RNG prior to EPA acceptance of their 
registration under Sec.  80.135 if all the requirements of this section 
are met.
    (3) A biointermediate producer may store biointermediate (including 
biogas used to produce a biogas-derived renewable fuel) prior to EPA 
acceptance of their registration under Sec.  80.1450(b) if all the 
requirements of this section are met.
    (b) Storage requirements. In order for a renewable fuel, RNG, or 
biointermediate producer to store renewable fuel, RNG, or 
biointermediate under this section, the producer must do the following:
    (1) Produce the stored renewable fuel, RNG, or biointermediate 
after an independent third-party engineer has conducted an engineering 
review for the renewable fuel, RNG, or biointermediate production 
facility under Sec.  80.1450(b)(2).
    (2) Produce the stored renewable fuel, RNG, or biointermediate in 
accordance with all applicable requirements under this part.
    (3) Make no change to the facility after the independent third-
party engineer completed the engineering review.
    (4) Store the renewable fuel, RNG, or biointermediate at the 
facility that produced the renewable fuel, RNG, or biointermediate.
    (5) Maintain custody and title to the stored renewable fuel, RNG, 
or biointermediate until EPA accepts the

[[Page 44591]]

producer's registration under Sec.  80.1450(b).
    (c) RIN generation. (1) A RIN generator may only generate RINs for 
stored renewable fuel, stored RNG, or renewable fuel produced from 
stored biointermediate if the RIN generator generates the RINs under 
Sec. Sec.  80.125, 80.1426, and 80.1452, as applicable, after EPA 
accepts their registration under Sec.  80.1450(b) and meets all other 
applicable requirements under this part for RIN generation.
    (2) The RIN year of any RINs generated for stored renewable fuel, 
stored RNG, or renewable fuel produced from stored biointermediate is 
the year that the renewable fuel or RNG was produced.
    (d) Limitations. RNG injected into a natural gas commercial 
pipeline system prior to EPA acceptance of a renewable fuel producer's 
registration under Sec.  80.135 does not meet the requirements of this 
section and may not be stored.

0
38. Amend Sec.  80.1460 by:
0
a. In paragraph (a), removing the text ``Except as provided in Sec.  
80.1455, no'' and adding in its place the text ``No'';
0
b. In paragraphs (c)(2) and (3), removing the text ``(as defined in 
Sec.  80.1401)'';
0
c. In paragraph (d), removing the text ``Sec.  80.1428(a)(5)'' and 
adding in its place the text ``Sec.  80.1428(a)(4)''
0
d. In paragraph (g), removing the text ``Sec.  80.1401'' and adding in 
its place the text ``Sec.  80.2''; and
0
e. Adding paragraph (l).
    The addition reads as follows:

Sec.  80.1460  What acts are prohibited under the RFS program?

* * * * *
    (l) Independent third-party engineer violations. No person shall do 
any of the following:
    (1) Fail to identify any incorrect information submitted by any 
party as specified in Sec.  80.1450(b)(2).
    (2) Fail to meet any requirement related to engineering reviews as 
specified in Sec.  80.1450(b)(2).
    (3) Fail to disclose to EPA any financial, professional, business, 
or other interests with parties for whom the independent third-party 
engineer provides services under Sec.  80.1450.
    (4) Fail to meet any requirement related to the independent third-
party engineering review requirements in Sec.  80.1450(b)(2) or (d)(1).

0
39. Amend Sec.  80.1461 by adding paragraph (f) to read as follows:

Sec.  80.1461  Who is liable for violations under the RFS program?

* * * * *
    (f) Third-party liability. Any party allowed under this subpart to 
conduct sampling and testing on behalf of a regulated party and does so 
to demonstrate compliance with the requirements of this subpart must 
meet those requirements in the same way that the regulated party must 
meet those requirements. The regulated party and the third party are 
both liable for any violations arising from the third party's failure 
to meet the requirements of this subpart.

Sec.  80.1464  [Amended]

0
40. Amend Sec.  80.1464 by:
0
a. In the introductory text, removing the reference ``Sec. Sec.  
80.1465 and 80.1466'' and adding in its place the reference ``Sec.  
80.1466'';
0
b. In paragraph (a) introductory text, removing the text ``(as 
described at Sec.  80.1406(a))'' and ``(as described at Sec.  
80.1430)'';
0
c. In paragraph (b)(1)(iii), removing the text ``a pathway in Table 1 
to Sec.  80.1426'' and adding in its place the text ``an approved 
pathway'';
0
d. In paragraph (b)(1)(v)(B), removing the text ``in Sec.  80.1401''; 
and
0
e. In paragraphs (i)(1) and (2), removing the text ``RIN and 
biointermediate''.

0
41. Effective April 1, 2024, amend Sec.  80.1466 by:
0
a. In paragraph (d)(2)(ii), removing the text ``The Administrator'' and 
adding in its place the text ``EPA'';
0
b. In paragraph (f)(1)(viii), removing the text ``working'' and adding 
in its place the text ``business'';
0
c. Revising paragraphs (h)(1) and (2);
0
d. In paragraph (k)(4)(i), removing the text ``The Administrator'' and 
adding in its place the text ``EPA'';
0
e. In paragraph (o)(1), removing the text ``the Administrator'' 
wherever it appears and adding in its place the text ``EPA''; and
0
f. In paragraph (o)(2)(ii), removing the text ``40 CFR 80.1465'' and 
adding in its place the text ``40 CFR 80.1466''.
    The revisions read as follows:

Sec.  80.1466  What are the additional requirements under this subpart 
for foreign renewable fuel producers and importers of renewable fuels?

* * * * *
    (h) * * *
    (1) The RIN-generating foreign producer must post a bond of the 
amount calculated using the following equation.

Bond = G * $0.22

Where:

Bond = Amount of the bond in U.S. dollars.
G = The greater of: (1) The largest volume of renewable fuel 
produced by the RIN-generating foreign producer and exported to the 
United States, in gallons, during a single calendar year among the 
five preceding calendar years; or (2) The largest volume of 
renewable fuel that the RIN-generating foreign producers expects to 
export to the United States during any calendar year identified in 
the Production Outlook Report required by Sec.  80.1449. If the 
volume of renewable fuel exported to the United States increases 
above the largest volume identified in the Production Outlook Report 
during any calendar year, the RIN-generating foreign producer must 
increase the bond to cover the shortfall within 90 days.
    (2) Bonds must be obtained in the proper amount from a third-party 
surety agent that is payable to satisfy United States administrative or 
judicial judgments against the foreign producer, provided EPA agrees in 
advance as to the third party and the nature of the surety agreement.
* * * * *

0
42. Effective April 1, 2024, amend Sec.  80.1467 by:
0
a. In paragraph (c)(1)(viii), removing the text ``working'' and adding 
in its place the text ``business'';
0
b. Revising paragraphs (e)(1) and (2); and
0
c. In paragraph (j)(1), removing the text ``the Administrator'' 
wherever it appears and adding in its place the text ``EPA''.
    The revisions read as follows:

Sec.  80.1467  What are the additional requirements under this subpart 
for a foreign RIN owner?

* * * * *
    (e) * * *
    (1) The foreign entity must post a bond of the amount calculated 
using the following equation:

Bond = G * $ 0.22

Where:

Bond = Amount of the bond in U.S. dollars.
G = The total of the number of gallon-RINs the foreign entity 
expects to obtain, sell, transfer, or hold during the first calendar 
year that the foreign entity is a RIN owner, plus the number of 
gallon-RINs the foreign entity expects to obtain, sell, transfer, or 
hold during the next four calendar years. After the first calendar 
year, the bond amount must be based on the actual number of gallon-
RINs obtained, sold, or transferred so far during the current 
calendar year plus the number of gallon-RINs obtained, sold, or 
transferred during the four calendar years immediately preceding the 
current calendar year. For any year for which there were fewer than 
four preceding years in which the foreign entity obtained, sold, or 
transferred RINs, the bond must be based on the total of the number 
of gallon-RINs sold or transferred so far during the current 
calendar year plus the number of gallon-RINs obtained, sold, or 
transferred

[[Page 44592]]

during any immediately preceding calendar years in which the foreign 
entity owned RINs, plus the number of gallon-RINs the foreign entity 
expects to obtain, sell or transfer during subsequent calendar 
years, the total number of years not to exceed four calendar years 
in addition to the current calendar year.

    (2) Bonds must be obtained in the proper amount from a third-party 
surety agent that is payable to satisfy United States administrative or 
judicial judgments against the foreign RIN owner, provided EPA agrees 
in advance as to the third party and the nature of the surety 
agreement.
* * * * *

Sec.  80.1468  [Removed and Reserved]

0
43. Remove and reserve Sec.  80.1468.

0
44. Amend Sec.  80.1469 by:
0
a. In paragraph (a)(1)(i)(A), removing the text ``as defined in Sec.  
80.1401'';
0
b. In paragraphs (a)(1)(i)(F) and (a)(2)(i)(B), removing the text ``as 
permitted under Table 1 to Sec.  80.1426 or a petition approved through 
Sec.  80.1416'' and adding in its place the text ``from the approved 
pathway'';
0
c. In paragraph (a)(3)(i)(F), removing the text ``EV'' and adding in 
its place the text ``EqV'';
0
d. In paragraph (b)(1)(i), removing the text ``as defined in Sec.  
80.1401'';
0
e. In paragraphs (b)(1)(vi) and (b)(2)(ii), removing the text ``as 
permitted under Table 1 to Sec.  80.1426 or a petition approved through 
Sec.  80.1416'' and adding in its place the text ``from the approved 
pathway'';
0
f. In paragraph (b)(3)(v), removing the text ``EV'' and adding in its 
place the text ``EqV'';
0
g. In paragraph (c)(1)(i), removing the text ``as defined in Sec.  
80.1401'';
0
h. In paragraph (c)(3)(v), removing the text ``EV'' and adding in its 
place the text ``EqV'';
0
i. Revising paragraph (c)(4) paragraph heading;
0
j. In paragraph (c)(4)(i), removing the text ``Sec.  80.1429(b)(4)'' 
and adding in its place the text ``Sec.  80.1429(b)'';
0
k. Adding paragraph (c)(6);
0
l. Revising paragraph (d); and
0
m. In paragraph (e)(1), removing the text ``the Administrator'' and 
adding in its place the text ``EPA''.
    The revisions and addition read as follows:

Sec.  80.1469  Requirements for Quality Assurance Plans.

* * * * *
    (c) * * *
    (4) Other RIN-related components. * * *
* * * * *
    (6) Documentation. Independent third-party auditors must review all 
relevant registration information under Sec.  80.1450, reporting 
information under Sec.  80.1451, and recordkeeping information under 
Sec.  80.1454, as well as any other relevant information and 
documentation required under this part, to verify elements in a QAP 
approved by EPA under this section.
    (d) In addition to a general QAP encompassing elements common to 
all pathways, for each QAP there must be at least one pathway-specific 
plan for an approved pathway, which must contain elements specific to 
particular feedstocks, production processes, and fuel types, as 
applicable.
* * * * *

0
45. Amend Sec.  80.1471 by:
0
a. Revising paragraphs (b) introductory text and (b)(1);
0
b. In paragraph (b)(2), removing the text ``as defined in Sec.  
80.1406'';
0
c. Revising paragraphs (b)(4) through (6); and
0
d. Adding paragraphs (b)(8) through (12).
    The revisions and additions read as follows:

Sec.  80.1471  Requirements for QAP auditors.

* * * * *
    (b) To be considered an independent third-party auditor under 
paragraph (a) of this section, all the following conditions must be 
met:
    (1) The independent third-party auditor and its contractors and 
subcontractors must not be owned or operated by the audited party or 
any subsidiary or employee of the audited party.
* * * * *
    (4) The independent third-party auditor and its contractors and 
subcontractors must be free from any interest or the appearance of any 
interest in the audited party's business.
    (5) The audited party must be free from any interest or the 
appearance of any interest in the third-party auditor's business and 
the businesses of third-party auditor's contractors and subcontractors.
    (6) The independent third-party auditor and its contractors and 
subcontractors must not have performed an attest engagement under Sec.  
80.1464(b) for the audited party for the same compliance period as a 
QAP audit conducted pursuant to Sec.  80.1472.
* * * * *
    (8) The independent third-party auditor and its contractors and 
subcontractors must act impartially when performing all activities 
under this section.
    (9) The independent third-party auditor and its contractors and 
subcontractors must be free from any interest in the audited party's 
business and receive no financial benefit from the outcome of auditing 
service, apart from payment for the auditing services.
    (10) The independent third-party auditor and its contractors and 
subcontractors must not have been involved in the design or 
construction of the audited facility.
    (11) The independent third-party auditor and its contractors and 
subcontractors must ensure that all personnel involved in the third-
party audit (including the verification activities) under this section 
are not negotiating for future employment with the owner or operator of 
the audited party. At a minimum, prior to conducting the audit, the 
independent third-party auditor must obtain an attestation (or similar 
document) from each person involved in the audit stating that they are 
not negotiating for future employment with the owner or operator of the 
audited party.
    (12) The independent third-party auditor and its contractors and 
subcontractors must have written policies and procedures to ensure that 
the independent third-party auditor and all personnel under the 
independent third-party auditor's direction or supervision comply with 
the competency, independence, and impartiality requirements of this 
section.
* * * * *

Sec.  80.1473  [Amended]

0
46. Amend Sec.  80.1473 by, in paragraphs (c)(1), (d)(1), and (e)(1), 
removing the text ``defined'' and adding in its place the text 
``specified''.

Sec.  80.1474  [Amended]

0
47. Amend Sec.  80.1474 by, in paragraph (g), removing the text ``the 
Administrator'' and adding in its place the text ``EPA''.

Sec.  80.1478  [Amended]

0
48. Amend Sec.  80.1478 by, in paragraph (g)(1), removing the text 
``the Administrator'' wherever it appears and adding in its place the 
text ``EPA''.

0
49. Add Sec.  80.1479 to read as follows:

Sec.  80.1479  Alternative recordkeeping requirements for separated 
yard waste, separated food waste, separated MSW, and biogenic waste 
oils/fats/greases.

    (a) Alternative recordkeeping. In lieu of complying with the 
recordkeeping requirements in Sec.  80.1454(j), a renewable fuel 
producer or biointermediate producer that produces renewable fuel or 
biointermediate from separated yard waste, separated food

[[Page 44593]]

waste, separated MSW, or biogenic waste oils/fats/greases and uses a 
feedstock aggregator to supply these feedstocks may comply with the 
alternative recordkeeping requirements of this section.
    (b) Registration of the feedstock aggregator. The feedstock 
aggregator must register under 40 CFR 1090.805.
    (c) QAP participation. (1) The renewable fuel or biointermediate 
producer must have their RINs or biointermediate, as applicable, 
verified by an independent third-party auditor under an approved QAP 
that includes a description of how the independent third-party auditor 
will audit each feedstock aggregator.
    (2) The independent third-party auditor must conduct a site visit 
of each feedstock aggregator's establishment as specified in Sec.  
80.1471(f). Instead of verifying RINs with a site visit of the 
feedstock aggregator's establishment every 200 days as specified in 
Sec.  80.1471(f)(1)(ii), the independent third-party auditor may verify 
RINs with a site visit every 380 days.
    (d) PTDs. PTDs must accompany transfers of separated yard waste, 
separated food waste, separated MSW, and biogenic waste oils/fats/
greases from the point where the feedstock leaves the feedstock 
aggregator's establishment to the point the feedstock is delivered to 
the renewable fuel production facility, as specified in Sec.  
80.1453(f)(1)(i) through (v).
    (e) Recordkeeping. The feedstock aggregator must keep all 
applicable records for the collection of separated yard waste, 
separated food waste, separated MSW, and biogenic waste oils/fats/
greases as specified in Sec.  80.1454(j).
    (f) Liability. The feedstock aggregator and renewable fuel producer 
are liable for violations as specified in Sec.  80.1461(e).

PART 1090--REGULATION OF FUELS, FUEL ADDITIVES, AND REGULATED 
BLENDSTOCKS

0
50. The authority citation for part 1090 continues to read as follows:

    Authority: 42 U.S.C. 7414, 7521, 7522-7525, 7541, 7542, 7543, 
7545, 7547, 7550, and 7601.

Subpart A--General Provisions

0
51. Amend Sec.  1090.55 by revising paragraph (c) to read as follows:

Sec.  1090.55  Requirements for independent parties.

* * * * *
    (c) Suspension and disbarment. Any person suspended or disbarred 
under 2 CFR part 1532 or 48 CFR part 9, subpart 9.4, is not qualified 
to perform review functions under this part.

0
52. Amend Sec.  1090.80 by:
0
a. In the definition for ``PADD'', revising entry ``II'' in the table; 
and
0
b. In the definition of ``Ultra low-sulfur diesel (ULSD)'', removing 
the text ``Ultra low-sulfur diesel (ULSD)'' and adding in its place the 
text ``Ultra-low-sulfur diesel (ULSD)''.
    The revision reads as follows:

Sec.  1090.80  Definitions.

* * * * *
    PADD * * *

------------------------------------------------------------------------
                                     Regional
             PADD                  description       State or territory
------------------------------------------------------------------------
 
                              * * * * * * *
II............................  Midwest..........  Illinois, Indiana,
                                                    Iowa, Kansas,
                                                    Kentucky, Michigan,
                                                    Minnesota, Missouri,
                                                    Nebraska, North
                                                    Dakota, Ohio,
                                                    Oklahoma, South
                                                    Dakota, Tennessee,
                                                    Wisconsin
 
                              * * * * * * *
------------------------------------------------------------------------

* * * * *

Subpart I--Registration

0
53. Amend Sec.  1090.805 by revising paragraph (a)(1)(iv) to read as 
follows:

Sec.  1090.805  Contents of registration.

    (a) * * *
    (1) * * *
    (iv) Name(s), title(s), telephone number(s), and email address(es) 
of an RCO and their delegate, if applicable.
* * * * *

Subpart S--Attestation Engagements

Sec.  1090.1830  [Amended]

0
54. Amend Sec.  1090.1830 by, in paragraph (a)(3), adding the text 
``all'' after the text ``submitted''.

[FR Doc. 2023-13462 Filed 7-11-23; 8:45 am]
BILLING CODE 6560-50-P