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



[[Page 80581]]

Vol. 87

Friday,

No. 250

December 30, 2022

Part II





 Environmental Protection Agency





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40 CFR Parts 80 and 1090





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

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

[[Page 80582]]


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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Parts 80 and 1090

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


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

AGENCY: Environmental Protection Agency (EPA).

ACTION: Proposed rule.

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SUMMARY: Under the Clean Air Act, the Environmental Protection Agency 
(EPA) is required to determine the applicable volume requirements for 
the Renewable Fuel Standard (RFS) for years after those specified in 
the statute. This action proposes the applicable volumes and percentage 
standards for 2023 through 2025 for cellulosic biofuel, biomass-based 
diesel, advanced biofuel, and total renewable fuel. This action also 
proposes the second supplemental standard addressing the remand of the 
2016 standard-setting rulemaking. Finally, this action proposes several 
regulatory changes to the RFS program including regulations governing 
the generation of qualifying renewable electricity and other 
modifications intended to improve the program's implementation.

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

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

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

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

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                                                   NAICS \a\
                   Category                          Codes          Examples of potentially affected entities
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Industry......................................          112111  Cattle farming or ranching.
Industry......................................          112210  Swine, hog, and pig farming.
Industry......................................          221117  Biomass electric power generation.
Industry......................................          221210  Manufactured gas production and distribution,
                                                                 and distribution of renewable natural gas
                                                                 (RNG).
Industry......................................          221320  Sewage treatment plants or facilities.
Industry......................................          324110  Petroleum refineries.
Industry......................................          325120  Biogases, industrial (i.e., compressed,
                                                                 liquefied, solid), manufacturing.
Industry......................................          325193  Ethyl alcohol manufacturing.
Industry......................................          325199  Other basic organic chemical manufacturing.
Industry......................................          336110  Electric automobiles for highway use
                                                                 manufacturing.
Industry......................................          424690  Chemical and allied products merchant
                                                                 wholesalers.
Industry......................................          424710  Petroleum bulk stations and terminals.
Industry......................................          424720  Petroleum and petroleum products merchant
                                                                 wholesalers.
Industry......................................          454319  Other fuel dealers.
Industry......................................          562212  Landfills.
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\a\ North American Industry Classification System (NAICS).

    This table is not intended to be exhaustive, but rather provides a 
guide for readers regarding entities likely to be affected by this 
proposed action. This table lists the types of entities that EPA is now 
aware could potentially be affected by this proposed action. Other 
types of entities not listed in the table could also be affected. To 
determine whether your entity would be affected by this proposed 
action, you should carefully examine the applicability criteria in 40 
CFR part 80. If you have any questions regarding the applicability of 
this proposed action to a particular entity, consult the person listed 
in the FOR FURTHER INFORMATION CONTACT section.

Outline of This Preamble

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

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

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

I. Executive Summary

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

     Table I-1--Years for Which the Statute Provides Volume Targets
------------------------------------------------------------------------
                          Category                               Years
------------------------------------------------------------------------
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 proposes the volume targets and applicable percentage 
standards for cellulosic biofuel, BBD, advanced biofuel, and total 
renewable fuel for 2023-2025. In association with these volume targets, 
we are also proposing new regulations governing the generation of 
Renewable Identification Numbers (RINs) for electricity made from 
renewable biomass that is used for transportation fuel, as well as a 
number of other regulatory changes intended to improve the operation of 
the RFS program.
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    \7\ See, e.g., 87 FR 39600 (July 1, 2022), establishing the 2022 
BBD volume requirement.
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    Low-carbon fuels are an important part of reducing greenhouse gas 
(GHG) emissions in the transportation sector, and the RFS program is a 
key federal policy that supports the development,

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

A. Summary of the Key Provisions of This Regulatory Action

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

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

    As discussed above, the statute requires that we analyze a 
specified set of factors in making our determination of the appropriate 
volume requirements to establish. However, many of those factors, 
particularly those related to economic and environmental impacts, would 
be difficult to analyze in the abstract. As a result, we needed to 
identify a set of renewable fuel volumes to analyze prior to 
determining the volume requirements that would be appropriate to 
propose. To this end, we began by using a subset of the statutory 
factors that are most closely related to production and consumption of 
renewable fuel to identify ``candidate volumes'' that we then subjected 
to the other economic and environmental factors that we are required to 
analyze. The derivation of these candidate volumes is discussed in 
Section III. Section IV discusses the analysis of those candidate 
volumes for the other economic and environmental factors. Finally, 
Section VI discusses our conclusions regarding the appropriate volume 
requirements to propose in light of all of the analyses that we 
conducted.
    We believe that proposing volume targets for more than one year is 
appropriate as it will provide the market with the certainty of demand 
needed for longer term business and investment plans. At the same time, 
setting volume targets too far out into the future can be difficult 
given the higher uncertainty associated with projecting supply for 
longer time periods and the increasing likelihood for unforeseen 
circumstances to upset supply. By proposing volume requirements for 
three years in this action but leaving the development of volume 
requirements for 2026 and beyond to a subsequent action, we believe we 
are striking a reasonable balance between certainty in our projections 
and providing certainty for investment. Nevertheless, recognizing that 
many regulated parties would appreciate knowing the applicable 
standards for as many years as is reasonably possible, we are 
requesting comment on establishing standards for 2026 in addition to 
2023-2025 through this rulemaking.
    The volume targets that we are proposing in this action would have 
the same status as those in the statute for the years shown in Table I-
1. That is, they would be the basis for the calculation of percentage 
standards applicable to producers and importers of gasoline and diesel 
unless they are waived in a future action using one or more of the 
available waiver authorities in CAA section 211(o)(7).
2. Applicable Percentage Standards for 2023-2025
    Although the statute requires EPA to establish applicable 
percentage standards annually by November 30 of the previous year, as 
discussed in Section II, this requirement does not apply to years after 
2022.\9\ For years after 2022, EPA can establish percentage standards 
for any number of years at the same time that it establishes the volume 
targets for those years. As this proposed rule is being released in 
2022, we are proposing the applicable percentage standards for 2023 in 
this action. In addition, we are proposing the percentage standards for 
the two other years (2024 and 2025) for which we are proposing volume 
requirements, the merits of which we discuss in Section II.D. The 
proposed percentage standards corresponding to the proposed volume 
requirements from Table I.A.1-1 are shown below.
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    \9\ CAA section 211(o)(3).

[[Page 80585]]



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

B. Environmental Justice

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

[[Page 80586]]

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

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

C. Comparison of Costs to Impacts

    CAA section 211(o)(2)(B)(ii) requires EPA to assess a number of 
factors when determining volume targets for calendar years after those 
shown in Table I-1. These factors are described in the introduction to 
this Executive Summary, and each factor is discussed in detail in the 
draft Regulatory Impact Analysis (DRIA) accompanying this proposed 
rule. However, the statute does not specify how EPA must assess each 
factor. For two of these statutory factors, costs and energy security 
impacts, we provide monetized impacts for the purpose of comparing 
costs and benefits. For the other statutory factors, we are either 
unable to quantify impacts, or we provide quantitative estimated 
impacts that cannot be easily monetized for comparison. Thus, we are 
unable to quantitatively compare all of the evaluated impacts when 
assessing the overall costs and impacts of this proposed rulemaking. We 
request comment generally on how costs and benefits quantified in this 
proposed rule are calculated and accounted for, methods to quantify and 
monetize additional statutory factors, and appropriate means of 
comparing the costs and benefits. Table ES-1 in the DRIA provides a 
list of all of the impacts that we assessed, both quantitative and 
qualitative. Our assessments of each factor, including the different 
components of the estimated costs, energy security methodology, climate 
impacts, and other environmental and economic impacts, are summarized 
in Section IV of this document. Additional detail for each of the 
assessed factors is provided in DRIA Chapters 4 through 10.
    Monetized cost and energy security impacts are summarized in Table 
I.C-1 below using two discount rates (3 percent and 7 percent) 
following federal guidance on regulatory impact analyses.\12\ 
Summarized impacts are calculated in comparison to a No RFS baseline as 
discussed in Section III.D and are summed across all three years of 
standards.
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    \12\ Office of Management and Budget (OMB). Circular A-4. 
September 17, 2003.

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

D. Policy Considerations

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

[[Page 80587]]

required volumes. Beyond providing continued support for fuels like 
ethanol and biodiesel, the set proposal provides a strong market signal 
for the continued growth of low carbon advanced biofuels, including 
``drop-in'' renewable diesel, cellulosic biofuels, and through a newly 
proposed program for electricity produced from qualifying renewable 
feedstocks and used as transportation fuel. Renewable fuels are a key 
policy tool identified by Congress for decarbonizing the transportation 
sector, and this rulemaking will set the stage for further growth and 
development of low-carbon biofuels in the coming years.
    With this proposal, EPA is asking for public comment on multiple 
elements of the rule, including our analysis, volume requirements, and 
proposed regulatory amendments. Simultaneously, EPA, having heard from 
a range of stakeholders who have raised concerns and questions 
reflecting a number of policy considerations that potentially bear on 
this proposal, is interested in the public's input about how this 
proposal intersects with the larger energy transition and energy 
security issues discussed above. EPA is interested, for example, in 
understanding how the proposed required RFS volume requirements 
interact with domestic refining capacity and associated energy security 
considerations. We are also interested in public input regarding ways 
in which EPA might enhance program administration to make the RFS 
program as efficient as possible, to increase program transparency, to 
address climate change, or otherwise improve program implementation.
    More specifically, EPA is interested in public and stakeholder 
input on the questions listed below, which will be considered and may 
inform the contents of the final rule. We note that for some of these 
topics, stakeholders may have previously provided information to EPA. 
We therefore ask that information provided in response to this request 
focus on new data, new information, or new policy suggestions.
     How can the proposed set rule further Congress' policy 
goal of enhancing energy security, specifically with respect to the 
transportation sector?
     How do the requirements of this proposed rule intersect 
with continued viability of domestic oil refining assets? How does the 
structure or positioning of refining assets in the marketplace, such as 
refineries that operate on a merchant basis, relate to a given 
obligated party's ability to participate, and associated costs with 
participation, in the RFS program?
     Are there policy changes or additional programmatic 
incentives that EPA should consider implementing under the RFS program 
to strengthen or accelerate the transition to a decarbonized 
transportation sector?
     If EPA were to incorporate some measure of the carbon 
intensity of each biofuel into the RFS program (e.g., providing a 
higher RIN value for fuels with a better carbon intensity score), what 
approach would best advance the program's environmental objectives, and 
at the same time be consistent with the statutory provisions of CAA 
section 211(o)?
     How can EPA best build upon the policy investments that 
the IRA established to further develop low carbon renewable fuels, 
including through incentives established through the RFS program?
     What role can the RFS program play, beyond what exists 
today, to further support the development of sustainable aviation fuel?
     Are there steps EPA should consider taking under the RFS 
program to integrate carbon capture and storage (CCS) opportunities 
related to the production of renewable fuels?
     Are there steps EPA should consider taking under the RFS 
program to capture opportunities related to hydrogen derived from 
renewable biomass?
     What actions should EPA consider to improve the 
transparency of how the Agency administers the RFS program? Are there 
steps EPA should consider taking to enhance RIN market liquidity, 
transparency, and efficiency, or otherwise improve market 
administration? For example, should EPA revisit some of the policy 
design conclusions of the 2019 RIN market reform rule such as the RIN 
holding thresholds that require parties to publicly disclose their 
positions? \13\ Are there other policy designs not considered in that 
rule that EPA should be considering in this rule?
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    \13\ 84 FR 26980 (June 10, 2019).
---------------------------------------------------------------------------

     As noted earlier, should the conventional renewable fuel 
volume requirement be set below the E10 blendwall, while keeping the 
total proposed renewable fuel volume requirement unchanged?
    In addition, the inclusion of a new regulatory program for eRINs 
significantly increases the uncertainty of our cellulosic biofuel 
projections for 2024 and 2025, and that uncertainty may warrant special 
consideration. Unlike other types of cellulosic biofuel, EPA has no 
history projecting the generation of eRINs under the RFS program. The 
number of eRINs generated could also be impacted by a number of 
interrelated and complex factors, such as the size and future growth 
rate of the EV fleet, the supply of qualifying biogas for electricity 
generation, competition for the biogas and electricity from other 
markets, and the rate at which electricity generators can register to 
participate in the RFS program. Our consideration of these factors in 
projecting eRIN volumes can be found in DRIA Chapter 6.1.4. We request 
comment on how to account for the uncertainty in projecting the 
quantity of eRINs in the RFS program, and specifically, whether we 
should be considering lower (or different) cellulosic volume 
requirements for 2024 and 2025 in this rule.

E. Endangered Species Act

    Section 7(a)(2) of the Endangered Species Act (ESA), 16 U.S.C. 
1536(a)(2), requires that Federal agencies such as EPA, along with the 
U.S. Fish and Wildlife Service (USFWS) and/or the National Marine 
Fisheries Service (NMFS) (collectively ``the Services''), ensure that 
any action authorized, funded, or carried out by the agency is not 
likely to jeopardize the continued existence of any endangered or 
threatened species or result in the destruction or adverse modification 
of designated critical habitat for such species. Under relevant 
implementing regulations, the action agency is required to consult with 
the Services only for actions that ``may affect'' listed species or 
designated critical habitat. 50 CFR 402.14. Consultation is not 
required where the action has no effect on such species or habitat. For 
several prior RFS annual standard-setting rules, EPA did not consult 
with the Services under section 7(a)(2).
    Consistent with ESA section 7(a)(2) and relevant ESA implementing 
regulations at 50 CFR part 402, for approximately two years, EPA has 
been engaged in informal consultation including technical assistance 
discussions with the Services regarding this rule.

II. Statutory Requirements and Conditions

A. Requirement To Set Volumes for Years After 2022

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

[[Page 80588]]

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

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

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

B. Factors That Must Be Analyzed

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

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

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

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

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

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

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

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

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

    \19\ 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; 
\20\ and
---------------------------------------------------------------------------

    \20\ 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.\21\
---------------------------------------------------------------------------

    \21\ CAA section 211(o)(2)(B)(ii)(VI).
---------------------------------------------------------------------------

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

    \22\ See Nat'l Wildlife Fed'n v. EPA, 286 F.3d 554, 570 (D.C. 
Cir. 2002) (analyzing factors within the Clean Water Act); accord 
Riverkeeper, Inc. v. U.S. EPA, 358 F.3d 174, 195 (2nd Cir. 2004) 
(same); BP Exploration & Oil, Inc. v. EPA, 66 F.3d 784, 802 (6th 
Cir. 1995) (same); see also Brown v. Watt, 668 F.3d 1290, 1317 (D.C. 
Cir. 1981) (``A balancing of factors is not the same as treating all 
factors equally. The obligation instead is to look at all factors 
and then balance the results. The Act does not mandate any 
particular balance, but vests the Secretary with discretion to weigh 
the elements . . . .'') (addressing factors articulated in the Out 
Continental Shelf Lands Act).
    \23\ See 87 FR 39600 (July 1, 2022).
    \24\ RFS Annual Rules Response to Comments Document at 10.
---------------------------------------------------------------------------

    In addition to those factors listed in the statute, we also have 
authority to consider other factors, including both implied authority 
to consider factors that inform our analysis of the statutory factors 
and explicit authority to consider ``the impact of the use of renewable 
fuels on other factors . . . .'' \25\ Accordingly, we have considered 
several other factors, including:
---------------------------------------------------------------------------

    \25\ CAA section 211(o)(2)(B)(ii)(VI).
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     The interaction between volume requirements for years 
2023-2025, including the nested nature of those volume requirements and 
the availability of carryover RINs;
     The ability of the market to respond given the timing of 
this rulemaking;
     Our obligation to respond to the ACE remand (Section V);
     The supply of qualifying renewable fuels to U.S. consumers 
(Section III.A.5) \26\;
---------------------------------------------------------------------------

    \26\ This is based on our analysis of this same statutory factor 
as well as of downstream constraints on biofuel use, including the 
statutory factors relating to infrastructure and costs.
---------------------------------------------------------------------------

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

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

     Environmental justice (Section IV.E and Chapter 8 of the 
RIA) \28\;
---------------------------------------------------------------------------

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

    \29\ The comparison of costs and benefits compares our 
quantitative analysis of various statutory factors, including costs, 
energy security, and climate impacts.
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C. Statutory Conditions on Volume Requirements

    As indicated above, the CAA does not provide instruction on how EPA 
should consider the factors or the weight each factor should be given 
when setting the applicable volumes, and thus leaves this to EPA's 
discretion. However, the Act does contain three conditions that affect 
our determination of the applicable volume requirements:
     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; and
     A floor on the applicable volume of BBD.
    Other than these limits, Congress has not provided instruction on 
how EPA must evaluate the statutorily enumerated factors, and courts 
have interpreted such congressional silence as conveying substantial 
discretion to the Agency.\30\
---------------------------------------------------------------------------

    \30\ Monroe Energy, LLC v. EPA, 750 F.3d 909, 915 (D.C. Cir. 
2014) (quoting Catawba Cty., N.C. v. EPA, 571 F.3d 20, 37 (D.C. Cir. 
2009) (``[W]hen a statute is silent with respect to all potentially 
relevant factors, it is eminently reasonable to conclude that the 
silence is meant to convey nothing more than a refusal to tie the 
agency's hands.'').
---------------------------------------------------------------------------

1. Advanced Biofuel as a Percentage of Total Renewable Fuel
    While the statute provides broad discretion in setting the 
applicable volume requirements for advanced biofuel and total renewable 
fuel, it also establishes a constraint on the relationship between 
these two volume

[[Page 80589]]

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

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

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

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

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

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

    CAA section 211(o)(7)(D) provides that if ``the projected volume of 
cellulosic biofuel production is less than the minimum applicable 
volume established under paragraph (2)(B),'' EPA ``shall reduce the 
applicable volume of cellulosic biofuel required under paragraph (2)(B) 
to the projected volume available during that calendar year.'' Thus, in 
order to avoid triggering the mandatory cellulosic waiver, EPA is 
proposing to set cellulosic volumes at the levels we believe to be 
achievable. Our discussion of the projected supply of cellulosic 
biofuel is addressed in Section III.A.1.
3. Biomass-Based Diesel
    EPA has established the BBD requirement under CAA section 
211(o)(2)(B)(ii) since 2013 because the statute only provided BBD 
volume targets through 2012. The statute also requires that the BBD 
volume requirement be set at or greater than the 1.0 billion gallon 
volume requirement for 2012 in the statute, but does not provide any 
other numerical criteria that EPA is to consider.\36\ We are proposing 
an applicable volume requirement for BBD for 2023, 2024, and 2025 under 
these authorities.
---------------------------------------------------------------------------

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

D. Authority To Establish Percentage Standards for Multiple Future 
Years

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

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

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

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

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

E. Considerations for Late Rulemaking

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

[[Page 80590]]

statutory deadlines.\39\ EPA has in the past also missed statutory 
deadlines for promulgating RFS standards, including the BBD Standards 
in 2014-2016, which were established under CAA section 
211(o)(2)(B)(ii). The U.S. Court of Appeals for the D.C. Circuit found 
that EPA retains authority to promulgate volumes and annual standards 
beyond the statutory deadlines, even those that apply retroactively, so 
long as EPA exercises this authority reasonably.\40\ In doing so, EPA 
must balance the burden on obligated parties of a delayed rulemaking 
with the broader goal of the RFS program to reduce GHG emissions and 
enhance energy security through increases in renewable fuel use.\41\ In 
upholding EPA's late and retroactive standards in ACE, the court 
considered several specific factors, including the availability of RINs 
for compliance, the amount of lead time and adequate notice for 
obligated parties, and the availability of compliance flexibilities. In 
addressing rulemakings that were late (i.e., those issued after the 
statutory deadline), but not retroactive, the court emphasized the 
amount of lead time and adequate notice for obligated parties.\42\ Most 
relevant here is EPA's action in 2015 that established the BBD volume 
requirements for 2014 and 2015.\43\ There, EPA missed the statutory 
criterion that EPA establish an applicable volume target for BBD no 
later than 14 months before the first year to which that volume 
requirement will apply.\44\ However, the court found that EPA properly 
balanced the relevant considerations and had provided sufficient notice 
to parties in establishing the applicable volume requirements for 2014 
and 2015.\45\
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    \39\ See CAA Section 211(o)(2)(B)(ii), requiring EPA promulgate 
applicable volume requirements no later than 14 months prior to the 
first year in which they will apply.
    \40\ Americans for Clean Energy v. EPA, 864 F.3d 691 (D.C. Cir. 
2017) (ACE) (EPA may issue late applicable volumes under CAA section 
211(o)(2)(B)(ii)); Monroe Energy, LLC v. EPA, 750 F.3d 909 (D.C. 
Cir. 2014); NPRA v. EPA, 630 F.3d 145, 154-58 (D.C. Cir. 2010).
    \41\ NPRA v. EPA, 630 F.3d 145, 164-165.
    \42\ ACE, 864 F.3d at 721-22.
    \43\ 80 FR 77420, 77427-77428, 77430-77431 (December 14, 2015).
    \44\ CAA section 211(o)(2)(B)(ii).
    \45\ ACE, 864 F.3d at 721-23.
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    In this rulemaking, we are proposing to exercise our authority to 
set the applicable renewable fuel volume requirements for 2023 and 2024 
after the statutory deadline to promulgate volumes no later than 14 
months before the first year to which those volume requirements 
apply.\46\ We also expect the final rule to be partly retroactive, as 
the 2023 standards are unlikely to be finalized prior to the beginning 
of the 2023 calendar year. Nevertheless, as discussed in Section VI.E, 
we believe that the 2023 standards being proposed in this action could 
be met. Additionally, we plan to finalize the 2024 standards prior to 
the beginning of the 2024 calendar year and do not expect those 
standards to apply retroactively.
---------------------------------------------------------------------------

    \46\ CAA section 211(o)(2)(B)(ii).
---------------------------------------------------------------------------

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

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

F. Impact on Other Waiver Authorities

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

    \48\ See J.E.M. Ag Supply, Inc. v. Pioneer Hi-Bred Intern., 
Inc., 534 U.S. 124, 143-44 (2001) (holding that when two statutes 
are capable of coexistence and there is not clearly expressed 
legislative intent to the contrary, each should be regarded as 
effective).
---------------------------------------------------------------------------

    However, we note that as described above CAA section 
211(o)(2)(B)(iv) requires that EPA set the cellulosic biofuel volume 
requirements for 2023 and beyond based on the assumption that the 
Administrator will not need to waive those volume requirements under 
the cellulosic waiver authority. Because we are, in this action, 
proposing to establish the applicable volume targets for 2023-2025 
under the set authority, we do not believe we could also waive those 
requirements using the cellulosic waiver authority in this same action 
in a manner that would be consistent with CAA section 211(o)(2)(B)(iv), 
since that waiver authority is only triggered when the projected 
production of cellulosic biofuel is less than the ``applicable volume 
established under [211(o)(2)(B)].'' In other words, it does not appear 
that EPA could use both the set authority and the cellulosic waiver 
authority to establish volumes at the same time in this action.
    Establishing the volume requirements for 2023-2025 using our set 
authority apart from the cellulosic waiver authority would have 
important implications for the availability of cellulosic waiver 
credits (CWCs) in these years. When EPA reduces cellulosic volumes 
under the cellulosic waiver authority, EPA is also required to make 
CWCs available under CAA section 211(o)(7)(D)(ii). In this rule we are, 
for the first time, proposing to establish a cellulosic biofuel 
standard without utilizing the cellulosic waiver authority. We 
interpret CAA section 211(o)(7)(D)(ii) such that CWCs are only made 
available in years in which EPA uses the cellulosic waiver authority to 
reduce the cellulosic biofuel volume. Because of this, cellulosic 
waiver credits would not be available as a compliance mechanism for 
obligated parties in these years absent a future action to exercise the 
cellulosic waiver authority. We recognized this likelihood in the 
recent rule establishing volume requirements for 2020-2022.\49\ There, 
we cited to the fact that CWCs were unlikely to be available in 2023 as 
part of our rationale for not requiring the use of cellulosic carryover 
RINs in setting the cellulosic volume requirements for 2020-2022. 
Despite the absence of CWCs, we expect that obligated parties will be 
able to satisfy their cellulosic biofuel obligations for these years 
because we are proposing to establish the cellulosic biofuel volume 
requirement based on the quantity of cellulosic biofuel we project will 
be produced and imported in the U.S. each year. Nevertheless, we 
recognize that the absence of CWCs is potentially a significant change 
to the operation of the RFS program, and we request comment on EPA's 
authority to offer CWCs in years in which we do not establish volume 
requirements using our cellulosic waiver authority.
---------------------------------------------------------------------------

    \49\ 87 FR 39600 (July 1, 2022).
---------------------------------------------------------------------------

G. Severability

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

[[Page 80591]]

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

III. Candidate Volumes and Baselines

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

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

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

A. Number of Years Analyzed

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

[[Page 80592]]

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

B. Production and Import of Renewable Fuel

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

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

[[Page 80593]]

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

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

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

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

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

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

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

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

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

[[Page 80594]]

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

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

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

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

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

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

[[Page 80595]]

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

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

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

[[Page 80596]]

[GRAPHIC] [TIFF OMITTED] TP30DE22.001

    There are also very small volumes of renewable jet fuel and heating 
oil that qualify as BBD, and there are currently significant efforts 
underway to incentivize growth in renewable jet fuel in particular 
(often referred to as sustainable aviation fuel or SAF).\59\ Jet fuel 
has qualified as a RIN-generating advanced biofuel under the RFS 
program since 2010, and must achieve at least a 50 percent reduction in 
GHGs in comparison to petroleum-based fuels. The technology and 
feedstocks that can be used to produce SAF today are often the same as 
those currently used to produce renewable diesel. For example, the same 
refinery process that produces renewable diesel from waste fats, oils, 
and greases or plant oils also produces hydrocarbons in the 
distillation range of jet fuel that can be separated and sold as SAF 
instead of being sold as renewable diesel. While relatively little SAF 
has been produced since 2010--less than 5 million gallons per year--
opportunities for increasing this category of advanced biofuel exist. 
In particular, other technologies and feedstocks are being developed 
that might enable new sources of SAF. In addition, in April 2022 the 
Administration announced a new Sustainable Aviation Fuel Grand 
Challenge to inspire the dramatic increase in the production of 
sustainable aviation fuels to at least 3 billion gallons per year by 
2030. This effort is accompanied by new and ongoing funding 
opportunities to support sustainable aviation fuel projects and fuel 
producers totaling up to $4.3 billion.
---------------------------------------------------------------------------

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

    Since the vast majority of BBD is biodiesel and renewable diesel, 
and since feedstock limitations are likely to cause any growth in 
renewable jet fuel to come at the expense of biodiesel and renewable 
diesel, we have focused on just biodiesel and renewable diesel in this 
section. The remainder of this section summarizes our assessment of the 
rate of production and use of qualifying BBD from 2023 to 2025, and 
some of the uncertainties associated with those volumes. Further 
details on these volume projections can be found in DRIA Chapter 6.2.
a. Biodiesel
    Historically the largest volumes of biomass-based diesel and 
advanced biofuel supplied in the RFS program have been biodiesel. 
Domestic biodiesel production increased from approximately 1.3 billion 
gallons in 2014 to approximately 1.8 billion gallons in 2018. Since 
2018 domestic biodiesel production has remained at approximately 1.8 
billion gallons per year. The U.S. has also imported significant 
volumes of biodiesel in previous years and has been a net importer of 
biodiesel since 2013. Biodiesel imports reached a peak in 2016 and 
2017, with the majority of the imported biodiesel coming from 
Argentina.\60\ In August 2017, the U.S. announced tariffs on biodiesel 
imported from Argentina and Indonesia.\61\ These tariffs were 
subsequently confirmed in April 2018.\62\ Since that time no biodiesel 
has been imported from Argentina or Indonesia, and net biodiesel 
imports have been relatively small.
---------------------------------------------------------------------------

    \60\ EIA U.S. Imports by Country of Origin (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.
    \61\ 82 FR 40748 (August 28, 2017).
    \62\ 83 FR 18278 (April 26, 2018).
---------------------------------------------------------------------------

    Available data suggests that there is significant unused biodiesel 
production capacity in the U.S., and thus domestic biodiesel production 
could grow without the need to invest in additional production 
capacity. Data reported by EIA shows that biodiesel production capacity 
in February 2022 was approximately 2.2 billion gallons per year.\63\ 
According to EIA data biodiesel production capacity grew slowly from 
about 2.15 billion gallons in 2012 to a peak of approximately 2.5 
billion gallons in 2018. This facility capacity data is collected by 
EIA in monthly surveys, which suggests that this capacity represents 
the production at facilities that are currently producing some volume 
of biodiesel and likely does not include inactive facilities that are 
far less likely to complete a monthly survey. EPA separately collects 
facility capacity information through the facility

[[Page 80597]]

registration process. This data includes both facilities that are 
currently producing biodiesel and those that are inactive. EPA's data 
shows a total domestic biodiesel production capacity of 3.1 billion 
gallons per year in April 2022, of which 2.8 billion gallons per year 
was at biodiesel facilities that generated RINs in 2021. These 
estimates of domestic production capacity strongly suggest that 
domestic biodiesel production capacity is unlikely to limit domestic 
biodiesel production through 2025.
---------------------------------------------------------------------------

    \63\ EIA Monthly Biofuels Feedstock and Capacity Update (https://www.eia.gov/biofuels/update).
---------------------------------------------------------------------------

b. Renewable Diesel
    Renewable diesel has historically been produced and imported in 
smaller quantities than biodiesel as shown in Figure III.B.2-1. In 
recent years, however, both domestic production and imports of 
renewable diesel have increased. Renewable diesel production facilities 
generally have higher capital costs and production costs relative to 
biodiesel, which likely accounts for the much higher volumes of 
biodiesel production relative to renewable diesel production to date. 
The higher cost of renewable diesel production can largely be off-set 
through the benefits of economies of scale as renewable diesel 
facilities tend to be much larger than biodiesel production facilities. 
More importantly, because renewable diesel more closely resembles 
petroleum-based diesel than biodiesel fuel (both renewable diesel and 
petroleum-based diesel are hydrocarbons while biodiesel is a methyl-
ester) renewable diesel can be blended at much higher levels than 
biodiesel. This allows renewable diesel producers to benefit to a 
greater extent from the LCFS credits in California and other states in 
addition to the RFS incentives and the federal tax credit and provides 
a significant advantage over biodiesel, which has largely saturated the 
California market.\64\ We expect that an increasing number of states 
will adopt clean fuels programs, and that these programs could provide 
an advantage to renewable diesel production relative to biodiesel 
production in the U.S. See DRIA Chapter 6.2 for further discussion.
---------------------------------------------------------------------------

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

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

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

    In addition to domestic production the U.S. has also imported 
significant volumes of renewable diesel, with nearly all of the 
imported renewable diesel coming from Singapore. In more recent years, 
the U.S. has also exported increasing volumes of renewable diesel. Net 
imports of renewable diesel were approximately 120 million gallons in 
2021. This situation, wherein significant volumes of renewable diesel 
are both imported and exported, is likely the result of a number of 
factors, including the design of the biodiesel tax credit (which is 
available to renewable diesel that is either produced or used in the 
U.S. and thus eligible for exported volumes as well), the varying 
structures of incentives for renewable diesel (with the level of 
incentives varying depending on the feedstocks used to produce the 
renewable diesel varying as well as by country), and logistical 
considerations (renewable diesel may be imported and exported from 
different parts of the country). We are projecting that net renewable 
diesel imports will continue through 2025 at approximately the levels 
observed in recent years, though we also recognize that increasing net 
imports of renewable diesel could be a significant source of additional 
renewable fuel supply in future years.
c. BBD Feedstocks
    When considering the likely production and import of biodiesel and 
renewable diesel in future years the availability of feedstock is an 
important consideration. Currently, biodiesel and renewable diesel in 
the U.S. are produced from a number of different feedstocks including 
fats, oils and greases (FOG), distillers corn oil, and virgin vegetable 
oils such as soybean oil and canola oil. As domestic production of 
biodiesel has increased since 2014, an increasing percentage of total 
biodiesel production has been produced from soybean oil, with smaller 
increases in the use of FOG, distillers corn oil, and canola oil.

[[Page 80598]]

[GRAPHIC] [TIFF OMITTED] TP30DE22.002

    Use of soybean oil to produce biodiesel increased from 
approximately 10 percent of all domestic soybean oil production in the 
2009/2010 agricultural marketing year to 38 percent in the 2020/2021 
agricultural marketing year. In the intervening years, the total 
increase in domestic soybean oil production and the increase in the 
quantity of soybean oil used to produce biodiesel and renewable diesel 
were very similar, indicating that the increase in oil production was 
likely driven by the increasing demand for biofuel. However, as the 
production of renewable diesel has increased in recent years there has 
been a corresponding increase in competition for these feedstocks 
between biodiesel and renewable diesel. Notably, the percentage of the 
soybean value that came from the soybean oil (rather than the meal and 
hulls) had been relatively stable and averaged approximately 33 percent 
from 2016-2020. By August 2021, the percentage of the soybean value 
that came from the soybean oil had increased to approximately 50 
percent. This competition is expected to continue to increase through 
2025.
    Through 2020, most of the renewable diesel produced in the U.S. was 
made from FOG and distillers corn oil, with smaller volumes produced 
from soybean oil. While many biodiesel production facilities are unable 
to use these feedstocks, renewable diesel production facilities are 
generally able to use them. Additionally, nearly all the renewable 
diesel consumed in the U.S. is used in California, and under 
California's LCFS program renewable diesel produced from FOG and 
distillers corn oil receive more credits than renewable diesel produced 
from soybean oil. Available volumes of FOG and distillers corn oil are 
limited, however, and if renewable diesel production in future years 
increases rapidly as suggested by the large production capacity 
announcements, it will likely require increased use of vegetable oils 
such as soybean oil and canola oil. Data from 2021 appears to support 
this expectation, with increased soybean oil representing approximately 
half of the increase in feedstocks used to produce renewable diesel in 
the U.S. from 2020 to 2021.
    One likely source of feedstock for expanding renewable diesel 
production in 2023-2025 is soybean oil from new or expanded soybean 
crushing facilities. Several parties have announced plans to expand 
existing soybean crushing capacity and/or build new soybean crushing 
facilities.\68\ This new crushing capacity is expected to come online 
in the 2023-2025 timeframe. Increase crushing of soybeans in the U.S. 
will increase domestic soybean oil production. If domestic crushing of 
soybeans increases at the expense of soybean exports, domestic 
vegetable oil production could be increased without the need for 
additional soybean production. Alternatively, increased demand for 
soybeans from new or expanded crushing facilities could result in 
increased soybean production in the U.S. or increasing volumes of 
qualifying feedstocks such as soybean oil and canola oil may be 
diverted from existing markets to produce renewable diesel, with non-
qualifying feedstocks such as palm oil used in place of soybean and 
canola oil in food and oleochemical markets.
---------------------------------------------------------------------------

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

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

[[Page 80599]]

contribute to the supply of these fuels through 2025.
3. Other Advanced Biofuel
    In addition to BBD, other renewable fuels that qualify as advanced 
biofuel have been consumed in the U.S. in the past and would be 
expected to contribute to compliance with applicable volume 
requirements in the years after 2022. These other advanced biofuels 
include imported sugarcane ethanol, domestically produced advanced 
ethanol, biogas that is purified and compressed to be used in CNG or 
LNG vehicles, heating oil, naphtha, and renewable diesel that does not 
qualify as BBD.\69\ However, these biofuels have been consumed in much 
smaller quantities than biodiesel and renewable diesel in the past, 
and/or have been highly variable. In order to estimate the volumes of 
these other advanced biofuels that may be available in 2023-2025, we 
employed a methodology originally presented in the annual rulemaking 
establishing the applicable standards for 2020-2022.\70\ This 
methodology addresses the historical variability in these categories of 
advanced biofuel while recognizing that consumption in more recent 
years is likely to provide a better basis for making future projections 
than consumption in earlier years. Specifically, we applied a weighting 
scheme to historical volumes wherein the weighting was higher for more 
recent years and lower for earlier years. The result of this approach 
is shown in the table below. Details of the derivation of these 
estimates can be found in DRIA Chapter 5.4.
---------------------------------------------------------------------------

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

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

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

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

    Under the statute, there is no volume requirement for conventional 
renewable fuel. Instead, conventional renewable fuel is that portion of 
the total renewable fuel volume requirement that is not required to be 
advanced biofuel. In some cases, it is referred to as an ``implied'' 
volume requirement. However, obligated parties are not required to 
comply with it per se since any portion of it can be met with advanced 
biofuel volumes in excess of that needed to meet the advanced biofuel 
volume requirement.
a. Corn Ethanol
    Ethanol made from corn starch has dominated the renewable fuels 
market on a volume basis in the past and is expected to continue to do 
so for the time period addressed by this rulemaking. Corn starch 
ethanol is prohibited by statute from being an advanced biofuel 
regardless of its GHG performance in comparison to gasoline.\72\
---------------------------------------------------------------------------

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

    Conventional ethanol from feedstocks other than corn starch have 
been produced in the past, but at significantly lower volumes. 
Production of ethanol from grain sorghum reached an historical high of 
125 million gallons in 2019, representing just less than 1 percent of 
all conventional ethanol. Waste industrial ethanol and ethanol made 
from non-cellulosic portions of separated food waste have been produced 
more sporadically and at even lower volumes. We have ignored these 
other sources for our purposes here as they do not materially affect 
our assessment of volumes of conventional ethanol that can be produced.
    Total domestic corn ethanol production capacity increased 
dramatically between 2005 and 2010 and increased at a slower rate 
thereafter. In 2020, production capacity had reached 17.4 billion 
gallons.73 74 This production capacity was significantly 
underused in 2020 because the COVID-19 pandemic depressed gasoline 
demand in comparison to previous years and thus ethanol demand in the 
form of E10. Actual production of denatured ethanol in the U.S. reached 
just 12.82 billion gallons in 2020, compared to 14.72 billion gallons 
in 2019. Denatured ethanol production partially recovered in 2021, 
reaching 14.09 billion gallons.\75\
---------------------------------------------------------------------------

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

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

[[Page 80600]]

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

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

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

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

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

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

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


[[Page 80601]]

C. Candidate Volumes for 2023-2025

    Based on our analysis of supply-related factors as described in 
Section III.B above, we developed candidate volumes for 2023-2025 which 
we then subjected to the other economic and environmental analyses 
required by the statute. This section describes the candidate volumes, 
while Section IV summarizes the results of the additional analyses we 
performed.
    We have largely framed our assessment of volumes in terms of the 
component categories (cellulosic biofuel, non-cellulosic advanced 
biofuel, and conventional renewable fuel) rather than in terms of the 
statutory categories (cellulosic biofuel, advanced biofuel, total 
renewable fuel). The statutory categories are those addressed in CAA 
section 211(o)(2)(B)(i)-(iii), and cellulosic and advanced biofuel are 
nested within the overall total renewable fuel category. The component 
categories are the categories of renewable fuels which make up the 
statutory categories but which are not nested within one another. They 
possess distinct economic, environmental, technological, and other 
characteristics relevant to the factors we must analyze under the 
statute, making our focus on them rather than the nested categories in 
the statute technically sound. Finally, an analysis of the component 
categories is parsimonious as analyzing the statutory categories would 
effectively require us to evaluate the difference between various 
statutory categories (e.g., assessing ``the difference between volumes 
of advanced biofuel and total renewable fuel'' instead of assessing 
``the volume of conventional renewable fuel''), adding unnecessary 
complexity and length to our analysis. In any event, were we to frame 
our analysis in terms of the statutory categories, we believe that our 
substantive approach and conclusions would remain materially the same.
1. Cellulosic Biofuel
    The statutory volumes for cellulosic biofuel increased rapidly, 
from 100 million gallons in 2010 to 16 billion gallons in 2022 with the 
largest increases in the later years. While notable on its own, it is 
even more notable in comparison to the implied statutory volumes for 
the other renewable fuel volumes. BBD volumes did not increase after 
2012, conventional renewable fuel volumes did not increase after 2015, 
and non-cellulosic advanced biofuel volume increases tapered off in 
recent years with a final increment in 2022. Thus, the clear focus of 
the statute by 2022 was intended to be on growth in cellulosic biofuel 
volumes, which have the greatest greenhouse gas reduction threshold. 
The statutory cellulosic waiver provision, while acknowledging that the 
statutory cellulosic biofuel volumes may not be met, nevertheless 
expressed support for the cellulosic biofuel industry in directing EPA 
to establish the cellulosic biofuel volume at the projected volume 
available in years when the projected volume of cellulosic biofuel 
production was less than the statutory volume. This increasing emphasis 
on cellulosic biofuel in the RFS program is likely due to the 
expectations among proponents of cellulosic biofuel that it has 
significant potential to reduce GHG emissions (cellulosic biofuels are 
required to reduce GHG emissions by 60 percent relative to the gasoline 
or diesel fuel they displace),\79\ that cellulosic biofuel feedstocks 
could be produced or collected with relatively few negative 
environmental impacts, that the feedstocks would be inexpensive, 
allowing for lower cost biofuels to be produced than those produced 
from feedstocks with other primary uses such as food, and that the 
technological breakthroughs needed to convert cellulosic feedstocks 
into biofuel were right around the corner.
---------------------------------------------------------------------------

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

    The candidate volumes discussed in this section represent the 
volume of qualifying cellulosic biofuel we project will be produced or 
imported into the U.S. in 2022-2025, after taking into consideration 
the incentives provided by the RFS program and other available state 
and federal incentives. The candidate volumes for 2022-2025 are shown 
in Table III.C.1-1. Because the technical, economic, and regulatory 
challenges related to cellulosic biofuel production vary significantly 
between the various types of cellulosic biofuel, we have shown the 
candidate volumes for liquid cellulosic biofuel, CNG/LNG derived from 
biogas, and eRINs separately. Note that consistent with the proposed 
regulations for eRINs in this proposed rule, the candidate volumes for 
2023 do not include any generation of cellulosic RINs from eRINs.

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

2. Non-Cellulosic Advanced Biofuel
    Although there are no volume targets in the statute for years after 
2022, the statutory volume targets for prior years represent a useful 
point of reference in the consideration of volumes that may be 
appropriate for 2023-2025. For non-cellulosic advanced biofuel, the 
implied statutory requirement increased in every year between 2009 and 
2019. It remained at 4.5 billion gallons for three years before finally 
rising to 5.0 billion gallons in 2022.
    In calculating the applicable percentage standards in the past, we 
have used volumes for non-cellulosic advanced biofuel that are at least 
as high as those derived from the statutory targets, and occasionally 
higher. For 2022, we have set the implied volume requirement for non-
cellulosic advanced biofuel at 5.0 billion gallons, equivalent to the 
implied volume target in the statute.\80\ As described in that rule, we 
believe that this level can be reached, though likely not without 
market adjustments that could include some diversion of soybean oil 
from food and other uses to biofuel production.
---------------------------------------------------------------------------

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

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

[[Page 80602]]

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

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

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

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

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

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

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

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

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

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

[[Page 80603]]

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

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

     Reductions in the consumption of E0;
     Consumption of non-ethanol advanced biofuel, such as 
biodiesel and renewable diesel, in excess of the applicable advanced 
biofuel standard; and
     Domestic production and/or importation of conventional 
biodiesel or renewable diesel.
    As a result, our assessments from previous years remain applicable 
for 2023-2025 in broad strokes: 15.25 billion gallons of conventional 
renewable fuel is achievable through some collection of the avenues 
listed above. We believe it is appropriate to analyze this volume of 
conventional renewable fuel as part of the candidate volumes, even 
though corn ethanol alone would not be sufficient to meet that volume.
    The amount of corn ethanol that could be consumed between 2023 and 
2025 can be estimated from the total ethanol consumption projections 
from Table III.B.5-1 and our projections for other forms of ethanol as 
discussed earlier in this section.

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

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

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

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

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

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

[[Page 80604]]



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

    Based on our assessment of available supply, we do not believe that 
there would be a need for conventional biodiesel or renewable diesel to 
be imported in order to help meet an effective conventional renewable 
fuel candidate volume of 15.25 billion gallons in the 2023-2025 
timeframe. Nevertheless, such imports remain a potential source in the 
event that the market did not respond to the candidate volumes in the 
way that we have projected it would. As discussed in Section III.B.4.b, 
total foreign production capacity for qualifying palm-based biodiesel 
and renewable diesel is over 3.6 billion gallons.
4. Treatment of Carryover RINs
    In our assessment of supply-related factors, we focused on those 
factors that could directly or indirectly impact the consumption of 
renewable fuel in the U.S. and thereby determine the number of RINs 
generated in each year that could be available for compliance with the 
applicable standards in those same years. However, carryover RINs 
represent another source of RINs that can be used for compliance. A 
consideration of carryover RINs is also consistent with the statutory 
requirement at 211(o)(2)(B)(ii) that, in the context of determining 
appropriate volume requirements for years after 2022, we review the 
implementation of the program in prior years. We therefore investigated 
whether and to what degree carryover RINs should be considered in the 
context of determining appropriate levels for the candidate volumes and 
ultimately the proposed volume requirements (discussed in Section VI).
    CAA section 211(o)(5) requires that EPA establish a credit program 
as part of its RFS regulations, and that the credits be valid for 
obligated parties to show compliance for 12 months as of the date of 
generation. EPA implemented this requirement through the use of RINs, 
which are generated for the production of qualifying renewable fuels. 
Obligated parties can comply by blending renewable fuels themselves, or 
by purchasing the RINs that represent the renewable fuels from other 
parties that perform the blending. RINs can be used to demonstrate 
compliance for the year in which they are generated or the subsequent 
compliance year. Obligated parties can obtain more RINs than they need 
in a given compliance year, allowing them to ``carry over'' these 
excess RINs for use in the subsequent compliance year, although our 
regulations limit the use of these carryover RINs to 20 percent of the 
obligated party's renewable volume obligation (RVO).\86\ For the bank 
of carryover RINs to be preserved from one year to the next, individual 
carryover RINs are used for compliance before they expire and are 
essentially replaced with newer vintage RINs that are then held for use 
in the next year. For example, vintage 2020 carryover RINs must be used 
for compliance with 2021 compliance year obligations, or they will 
expire. However, vintage 2021 RINs can then be ``banked'' for use 
toward 2022 compliance.
---------------------------------------------------------------------------

    \86\ 40 CFR 80.1427(a)(5).
---------------------------------------------------------------------------

    As noted in past RFS annual rules, carryover RINs are a 
foundational element of the design and implementation of the RFS 
program.\87\ A bank of carryover RINs is extremely important in 
providing a liquid and well-functioning RIN market upon which success 
of the entire program depends, and in providing obligated parties 
compliance flexibility in the face of substantial uncertainties in the 
transportation fuel marketplace.\88\ Carryover RINs enable parties 
``long'' on RINs to trade them to those ``short'' on RINs instead of 
forcing all obligated parties to comply through physical blending. 
Carryover RINs also provide flexibility and reduce spikes in compliance 
costs in the face of a variety of unforeseeable circumstances--
including weather-related damage to renewable fuel feedstocks and other 
circumstances potentially affecting the production and distribution of 
renewable fuel--that could limit the availability of RINs.
---------------------------------------------------------------------------

    \87\ See, e.g., 72 FR 23904 (May 1, 2007).
    \88\ See 80 FR 77482-87 (December 14, 2015), 81 FR 89754-55 
(December 12, 2016), 82 FR 58493-95 (December 12, 2017), 83 FR 
63708-10 (December 11, 2018), 85 FR 7016 (February 6, 2020), 87 FR 
39600 (July 1, 2022).
---------------------------------------------------------------------------

    Just as the economy as a whole is able to function efficiently when 
individuals and businesses prudently plan for unforeseen events by 
maintaining inventories and reserve money accounts, we believe that the 
RFS program is able to function when sufficient carryover RINs are held 
in reserve for potential use by the RIN holders themselves, or for 
possible sale to others that may not have established their own 
carryover RIN reserves. Were there to be too few RINs in reserve, then 
even minor disruptions causing shortfalls in renewable fuel production 
or distribution, or higher than expected transportation fuel demand 
(requiring greater volumes of renewable fuel to comply with the 
percentage standards that apply to all volumes of transportation fuel, 
including the unexpected volumes) could result in deficits and/or 
noncompliance by parties without RIN reserves. Moreover, because 
carryover RINs are individually and unequally held by market 
participants, a non-zero but nevertheless small carryover RIN bank may 
negatively impact the RIN market, even when the market overall could 
satisfy the standards. In such a case, market disruptions could force 
the need for a retroactive waiver of the standards, undermining the 
market certainty so critical to the RFS program. For all of these 
reasons, the collective carryover RIN bank provides a necessary 
programmatic buffer that helps facilitate compliance by individual 
obligated parties, provides for smooth overall functioning of the 
program to the benefit of all market participants, and is consistent 
with the statutory provision allowing for the generation and use of 
credits.
    EPA can also rely on the availability of carryover RINs to support 
market-forcing volumes that may not be able to be met with renewable 
fuel production and use in that year, and in the context of the 2013 
RFS rulemaking we noted that an abundance of carryover RINs available 
in that year, together with possible increases in renewable fuel

[[Page 80605]]

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

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

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

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

    However, the standards we established for 2022 (including the 2022 
supplemental standard) were significantly higher than the volume of 
renewable fuel used in previous years, and the candidate volumes would 
represent increases for 2025. While we project that the volume 
requirements in 2022 and the candidate volumes for 2023-2025 could be 
achieved without the use of carryover RINs, there is nevertheless some 
uncertainty about how the market would choose to meet the applicable 
standards. The result is that there remains some uncertainty 
surrounding the ultimate number of carryover RINs that will be 
available for compliance with the 2023, 2024, and 2025 standards 
(including the 2023 supplemental standard). Furthermore, we note that 
there have been enforcement actions in past years that have resulted in 
the retirement of carryover RINs to make up for the generation and use 
of invalid RINs and/or the failure to retire RINs for exported 
renewable fuel. To the extent that there are enforcement actions in the 
future, they could have similar results and require that obligated 
parties or renewable fuel exporters settle past enforcement-related 
obligations in addition to complying with the annual standards. In 
light of these uncertainties, the net result could be a total carryover 
RIN bank larger or smaller than 1.83 billion RINs.
b. Treatment of Carryover RINs for 2023-2025
    We evaluated the volume of carryover RINs projected to be available 
and considered whether we should include any portion of them in the 
determination of the candidate volumes that we analyzed or the volume 
requirements that we propose for 2023-2025 (including the 2023 
supplemental volume). Doing so would be equivalent to intentionally 
drawing down the carryover RIN bank in setting those volume 
requirements. We do not believe that this would be appropriate. In 
reaching this proposed determination, we considered the functions of 
the carryover RIN bank, its projected size, the uncertainties 
associated with its projection, its potential impact on the production 
and use of renewable fuel, the ability and need for obligated parties 
to draw on it to comply with their obligations (both on an individual 
basis and on a market-wide basis), and the impacts of drawing it down 
on obligated parties and the fuels market more broadly. As previously 
described, the bank of carryover RINs provides important and necessary 
programmatic functions--including as a cost spike buffer--that will 
both facilitate individual compliance and provide for smooth overall 
functioning of the program. We believe that a balanced consideration of 
the possible role of carryover RINs in achieving the volume 
requirements, versus maintaining an adequate bank of carryover RINs for 
important programmatic functions, is appropriate when EPA exercises its 
discretion under its statutory authorities.
    Furthermore, as noted earlier, the advanced biofuel and total 
renewable fuel standards established for 2022 are significantly higher 
than the volume of renewable fuel used in previous years. As we 
explained in the 2020-2022 final rule, while we believe that the market 
can make sufficient renewable fuel available to meet the 2022 
standards, there may be some challenges, and carryover RINs will be 
available for those obligated parties who choose to use them for 
compliance.\91\ In addition, in this action we are for the first time 
proposing to establish volume requirements for three years 
prospectively. This inherently adds uncertainty and makes it more 
challenging to project with accuracy the number of carryover RINs that 
will actually be available for each of these years. Given these 
factors, and the uneven holding of carryover RINs among obligated 
parties, we believe that further increasing the volume requirements 
after 2022 with the intent to draw down the carryover RIN bank could 
lead to significant deficit carryovers and non-compliance by some 
obligated parties that own relatively few or no carryover RINs. We do 
not believe this would be an appropriate outcome. Therefore, consistent 
with the approach we have taken in recent annual rules, we are not 
proposing to include carryover RINs in the candidate volumes, nor to 
set the 2023, 2024, and 2025 volume requirements (including the 2023 
supplemental standard) at levels that would intentionally draw down the 
bank of carryover RINs.
---------------------------------------------------------------------------

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

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

[[Page 80606]]



                Table III.C.5-1--Candidate Volume Components Derived From Supply-Related Factors
                                               [Million RINs] \a\
----------------------------------------------------------------------------------------------------------------
                                                                       2023            2024            2025
----------------------------------------------------------------------------------------------------------------
Cellulosic biofuel (D3 & D7)....................................             719           1,419           2,131
Biomass-based diesel (D4).......................................           5,389           5,689           5,760
Other advanced biofuel (D5).....................................             256             256             256
Conventional renewable fuel (D6)................................          14,455          14,505          14,534
----------------------------------------------------------------------------------------------------------------
\a\ The D codes given for each component category are defined in 40 CFR 80.1425(g). D codes are used to identify
  the statutory categories which can be fulfilled with each component category according to 40 CFR
  80.1427(a)(2).

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

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

D. Baselines

    In order to estimate the impacts of the candidate volumes, we must 
identify an appropriate baseline. The baseline reflects the alternative 
collection of biofuel volumes by feedstock, production process (where 
appropriate), biofuel type, and use which would be anticipated to occur 
in the absence of applicable standards, and acts as the point of 
reference for assessing the impacts. To this end, we have developed a 
``No RFS'' scenario that we use as the baseline for analytical 
purposes. Many of the same supply-related factors that we used to 
develop the candidate volumes were also relevant in developing the No 
RFS baseline.
    We also considered other possible baselines that, as described 
below, we are not using to assess all the impacts of the candidate 
volumes. We discuss the alternative baselines here in an effort to 
describe our reasoning for the public and interested stakeholders, and 
because we understand there are differing, informative baselines that 
could be used in this type of analysis. Ultimately, we concluded that 
the No RFS scenario is the most appropriate to use.
1. No RFS Program
    Broadly speaking, the RFS program is designed to increase the use 
of renewable fuels in the transportation sector beyond what would occur 
in the absence of the program. It is appropriate, therefore, to use a 
scenario representing what would occur if the RFS program did not exist 
as the baseline for estimating the costs and impacts of the candidate 
volumes. Such a ``No RFS'' baseline is consistent with the Office of 
Management and Budget's Circular A-4, which says that the appropriate 
baseline would normally ``be a `no action' baseline: what the world 
will be like if the proposed rule is not adopted.'' In the final rule 
establishing the standards for 2020-2022, we indicated that a No RFS 
baseline would be preferable to using a previous year's volume 
requirements as the baseline, but that we could not develop such a 
baseline in the time available for that action.\92\
---------------------------------------------------------------------------

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

    Importantly, a ``No RFS'' baseline would not be equivalent to a 
market scenario wherein no biofuels were used at all. Prior to the RFS 
program, both biodiesel and ethanol were used in the transportation 
sector, whether due to state or local incentives, tax credits, or a 
price advantage over conventional petroleum-based gasoline and diesel. 
This same situation would exist in 2023-2025 in the absence of the RFS 
program. Federal, state, and local tax credits, incentives, and support 
payments will continue to be in place

[[Page 80607]]

for these fuels, as well as state programs such as blending mandates 
and Low Carbon Fuel Standard (LCFS) programs. Furthermore, now that 
capital investments in renewable fuels have been made and markets have 
been oriented towards their use, there are strong incentives in place 
for continuing their use even if the RFS program were to disappear. As 
a result, it would be improper and inaccurate to attribute all use of 
renewable fuel in 2023-2025 to the applicable standards under the RFS 
program.
    To inform our assessment of the volume of biofuels that would be 
used in the absence of the RFS program for the years 2023 through 2025, 
we began by analyzing the trends in biofuel blending in prior years. 
Assessing these trends is important because the economics for blending 
biofuels changes from year to year based on biofuel feedstock and 
petroleum product prices and other factors which affect the relative 
economics for blending biofuels into petroleum-based transportation 
fuels. A biofuel plant investor and the financiers who fund their 
projects will review the historical, current, and perceived future 
economics of the biofuel market when deciding whether to fund the 
construction of biofuel plants, and our analysis attempted to account 
for these factors.
    The economic analysis for 2023-2025 compares the biofuel value with 
the fossil fuel it displaces, at the point that the biofuel is blended 
with the fossil fuel, to assess whether the biofuel provides an 
economic advantage. If the biofuel is lower cost than the fossil fuel 
it displaces, it is assumed that the biofuel would be used absent the 
RFS standards. The economic analysis that we conducted to assess the 
volume of biofuel that would likely be produced and consumed in the 
absence of the RFS program mirrors the cost analysis described in 
Section IV.C, but there is one primary difference and a number of other 
differences. The primary difference is that the economic analysis 
relative to the No RFS baseline assesses whether the fuels industry 
would find it economically advantageous to blend the biofuel into the 
petroleum fuel in the absence of the RFS program, whereas the social 
cost analysis reflects the overall impacts on consumers (society at 
large). The primary example of a social cost not considered for the No 
RFS economic analysis is the fuel economy effect due to the lower 
energy density of the biofuel, as this cost is borne by consumers, not 
the fuels industry. Other ways that the No RFS economic analysis is 
different from the social cost analysis include:
     In the context of assessing production costs, we amortized 
the capital costs at a 10 percent after-tax rate of return more typical 
for industry investment instead of the 7 percent before-tax rate of 
return used for social costs.
     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 are forced to price 
E85 lower than the primary alternative E10 to account for this bias and 
they must consider this in their decisions to blend and sell E85. A 
similar situation exists with E15, although it is not clear what the 
factors are for E15 and this is discussed in more detail in the No RFS 
discussion in DRIA Chapter 2.
    We added these various cost components together to reflect the cost 
of each biofuel.
    We conducted a similar cost estimate for the fossil fuels being 
displaced since their relative cost to biofuels is used to estimate the 
net cost of using biofuels. Unlike for biofuels, we did not calculate 
production costs for the fossil fuels. Instead, we projected their 
production costs based solely on wholesale price projections by the 
Energy Information Administration in its Annual Energy Outlook (AEO).
    We also considered any applicable federal or state programs, 
incentives, or subsidies that could reduce the apparent blending cost 
of the biofuel at the terminal. For instance, there are a number of 
state programs that create subsidies for biodiesel and renewable diesel 
fuel, the largest being offered by California and Oregon through their 
LCFS programs. We accounted for state and local biodiesel mandates by 
including their mandated volume regardless of the economics. Several 
states offer tax credits for blending ethanol at 10 volume percent. 
Other states offer tax credits for E85, of which the largest is in New 
York. We are not aware of any state tax credits or subsidies for E15. 
In the case of higher ethanol blends, the retail cost associated with 
the equipment and/or use of compatible materials needed to enable the 
sale of these newer fuels is assumed to be reduced by 50 percent due to 
the Federal and/or state grant programs such as USDA's Higher Blends 
Infrastructure Incentive Program (HBIIP).
    For most biofuels, the economic analysis provided consistent 
results, indicating that they are either economical in all years or are 
not economical in any year. However, this was not true for biodiesel 
and renewable diesel, where the results varied from year to year. Such 
swings in the economic attractiveness of biodiesel and renewable diesel 
confound efforts on the part of investors to project future returns on 
their investments. Thus, to smooth out the swings in the economics for 
using biodiesel and renewable diesel and look at it the way investors 
would have in the absence of the RFS program, we made two different key 
assumptions. First, the economics for biodiesel and renewable diesel 
were modeled starting in 2009 and the trend in its use was made 
dependent on the relative economics in comparison to petroleum diesel 
over a four year period. As a result, the first year modeled was 
actually 2012. Second, the estimated biodiesel and renewable diesel 
volumes were limited in the analysis to no greater volume than what 
occurred under the RFS program in any year, since the existence of the 
RFS program would be expected to create a much greater incentive for 
using these biofuels than if no RFS program were in place.
    An economic analysis was also conducted for cellulosic biofuels, 
including cellulosic ethanol, corn kernel fiber ethanol, and biogas. 
Since the volumes of these biofuels were much smaller, a more 
generalized approach was used in lieu of the detailed state-by-state 
analysis conducted for corn ethanol, biodiesel, and renewable diesel 
fuel.
    The No RFS baseline for 2023-2025 is summarized below in Table 
III.D.1-1. A more complete description of the No RFS baseline and its 
derivation is provided in DRIA Chapter 2.

[[Page 80608]]



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

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

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

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

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

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

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

[[Page 80609]]

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

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

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

E. Volume Changes Analyzed

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

 Table III.E-1--Changes in Biofuel Consumption in the Transportation Sector in Comparison to the No RFS Baseline
                                                 [Million RINs]
----------------------------------------------------------------------------------------------------------------
                                                                       2023            2024            2025
----------------------------------------------------------------------------------------------------------------
Cellulosic biofuel (D3 & D7)....................................             363           1,034           1,714
Biomass-Based Diesel (D4).......................................           4,015           4,315           4,386
Other Advanced Biofuel (D5).....................................              40              40              40
Conventional Renewable Fuel (D6)................................             706             776             840
----------------------------------------------------------------------------------------------------------------

    Note that the change in cellulosic biofuel shown in the table above 
for 2024 and 2025 is primarily due to the increased use of biogas for 
electricity. Moreover, these values represent changes in the use of 
cellulosic biofuel in the transportation sector, not changes in the 
production of cellulosic biofuel. For renewable electricity in 
particular, we project that there will be no change in production in 
the 2023-2025 timeframe as a result of the standards we set. Instead, 
renewable electricity that is already generated will shift from general 
distribution on the grid to use as a transportation fuel. As described 
in more detail in DRIA Chapter 3, we took this distinction into account 
in our analysis of the impacts of the candidate volumes.

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 DRIA. 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.5-2 for the candidate volumes, and Table 
III.E-1 for the corresponding volume changes in comparison to the No 
RFS baseline), along with some implications of those analyses. In 
Section VI we provide our consideration of all factors in determining 
the volume requirement that we believe would be appropriate for 2023-
2025.

A. Climate Change

    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,\97\ and GHG emissions contribute to climate 
change,\98\ so we believe it is reasonable to use lifecycle GHG 
emissions

[[Page 80610]]

estimates as a proxy for climate change impacts.
---------------------------------------------------------------------------

    \97\ 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.'').
    \98\ 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)).
---------------------------------------------------------------------------

    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, while cellulosic biofuel is required to have lifecycle 
emissions at least 60 percent less than the baseline fuels. Congress 
also allowed for facilities that existed or were under construction 
when EISA was passed to be grandfathered into the RFS program and 
exempt from the lifecycle GHG emission reduction requirements.
    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 in general 
and crop-based biofuels in particular. New models have been developed 
to evaluate biofuels and more models--developed for other purposes--
have been modified to evaluate the GHG emissions associated with 
biofuel production and use. There has also been rapid growth in 
available data on land use, farming practices, crude oil extraction and 
many other relevant factors. 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 an updated framework is needed. In this 
rulemaking, EPA is not proposing to reopen the related aspects of the 
2010 RFS2 rule or any prior EPA lifecycle greenhouse gas analyses, 
methodologies, or actions. That is beyond the scope of this rulemaking. 
However, EPA has initiated work to develop a revised modeling framework 
of the GHG impacts associated with biofuels. We intend to present the 
results of a model comparison exercise in the final rulemaking as an 
initial step in this update to our modeling framework. As an interim 
step in the process, for this proposed rule, we present biofuel LCA 
estimates from the range of published values from the scientific/
technical literature.
    Our assessment of the climate change impacts of the candidate 
volumes relies on an extrapolation of lifecycle GHG analyses. As we did 
in the 2020-2022 RVO rulemaking, this approach involves multiplying 
lifecycle emissions of individual fuels by the change in the candidate 
volumes 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. In the 2020-2022 RVO rulemaking, we applied the LCA estimates 
that we developed in the March 2010 RFS2 rule (75 FR 14670) and in 
subsequent agency actions. In this rulemaking, we are updating our 
approach to use a range of LCA estimates that are in the literature. 
Instead of providing one estimate of the GHG impacts of each candidate 
volume, we provide a high and low estimate of the potential GHG 
impacts, which is inclusive of the values we estimated in the 2010 RFS 
final rule and subsequent agency actions. We then use this range of 
values for considering the GHG impacts of the candidate renewable fuel 
volumes that change relative to the No RFS baseline described and 
developed in Section III.
    As described in more detail in the DRIA, to develop the new range 
of LCA values, we conducted a high-level review of relevant literature 
for the biofuel pathways (combination of biofuel type, feedstock, and 
production process) that would be most likely to satisfy the candidate 
renewable fuel volumes. Our literature review was broad and includes 
studies that estimate the lifecycle GHG emissions associated with the 
relevant biofuel pathways and the petroleum-based fuels they replace. 
Our compilation includes journal articles, major reports and studies 
that inform biofuel-related policies. We included studies that were 
published after the March 2010 RFS2 rule, as that rule considered the 
available science at the time. In cases where there were multiple 
studies that include updates to the same general model and approach, we 
included only the most recent study. However, we include a subset of 
older estimates that are still used for particular regulatory programs 
or that continue to be widely cited for other reasons. We focused on 
estimates of the average type of each fuel produced in the United 
States.\99\ 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.\100\ Some of the studies included estimate 
lifecycle GHG emissions whereas others only estimate land use change 
GHG emissions. For purposes of developing a quantitative range of 
estimates of the overall GHG impacts of the candidate volumes in the 
DRIA, we relied only on the available LCA estimates; however, our 
qualitative discussion includes a review of the literature that covers 
only land use change estimates.
---------------------------------------------------------------------------

    \99\ 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 widely 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.
    \100\ 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.
---------------------------------------------------------------------------

    The range of values in the literature for different types of 
renewable fuels varies considerably, particularly for crop-based 
biofuels. The ranges of estimates for non-crop based biofuel pathways 
are narrower relative to the crop-based pathways (See Table IV.A-1). 
Based on our literature review we can also make some general 
observations about what contributes to lower and higher GHG estimates. 
For crop-based biofuels, higher GHG estimates tend to be associated 
with assessments that show greater land use change emissions, assumed 
higher levels of energy and fertilizer use for feedstock production, 
and more intensive energy use for biofuel production. Lower GHG 
emissions are generally characterized by improvements in technology 
over time lower land use change emissions (e.g., estimates that include 
more intensive use of existing agricultural land through double-
cropping and other practices that increase yield without bringing more 
land into production), widespread

[[Page 80611]]

adoption of agricultural practices intended to maintain soil carbon 
(e.g., cover crops), and the trend toward more efficient biofuel 
production practices. Consistent with our prior estimates, our 
literature compilation also suggests that biofuels produced from 
byproducts and wastes tend to have lower lifecycle GHG emissions than 
crop-based biofuels. For example, the GHG estimates for renewable 
diesel produced from used cooking oil are significantly lower than 
those for renewable diesel produced from soybean oil. For these non-
crop-based pathways, different approaches of accounting for co-products 
can have a large effect on results, as well as whether pre-existing 
markets for these feedstocks will be backfilled. An important factor 
dictating the GHG emissions associated with biogas-to-CNG pathways 
include the extent of methane leakage during the collection, 
processing, and transport of renewable natural gas.

 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.
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.........................  15 to 58.
Tallow Renewable Diesel..................  14 to 81.
Distillers Corn Oil Biodiesel............  10 to 37.
Distillers Corn Oil Renewable Diesel.....  12 to 46.
Natural Gas CNG..........................  72 to 81.
Landfill Gas CNG.........................  9 to 70.
Manure Biogas CNG........................  -533 to 44.
------------------------------------------------------------------------

    Our compilation of the current literature reveals a wide range of 
estimates of the lifecycle GHG emissions associated with renewable 
fuels. The range of estimates is particularly wide for fuels derived 
from crop-based feedstocks due to variation in land use change GHG 
estimates. There is also a wide range of estimates for tallow renewable 
diesel depending on whether or not the studies allocate GHG emissions 
from meat production to the tallow or treat it as a byproduct. 
Estimates for landfill gas and manure biogas CNG vary substantially 
based on assumptions about methane emissions in the baseline scenario. 
Given the ongoing uncertainty associated with the science of analyzing 
biofuel GHG effects, our current assessment of the GHG impacts does not 
support significantly raising or lowering the candidate volumes derived 
from the supply-related factors discussed in Section III.
    For the final rule, we intend to advance our understanding of the 
lifecycle GHG emissions associated with changes in crop-based biofuel 
consumption, including through new modeling of biofuel lifecycle GHG 
impacts and a comparison of available models for biofuel GHG analysis. 
In the DRIA we discuss models that have been used since 2010 to 
estimate biofuel GHG emissions, including the market-mediated indirect 
emissions associated with increasing the production of crop-based 
fuels. We intend to run similar scenarios through some of these models 
and to compare the results. For example, we intend to align the amount 
of U.S. biofuel consumption in a reference scenario and use the models 
to estimate the GHG emissions associated with scenarios that include an 
increased volume of corn ethanol and separately an increased volume of 
soybean oil biodiesel. We also intend to compare key input assumptions 
used in the models, and time permitting, align some of these 
assumptions.
    We believe the model comparison exercise will provide valuable 
information about the capabilities of these models, and the effects of 
model choice and key input assumptions on biofuel lifecycle GHG 
estimates. While this model comparison exercise can provide helpful 
information for the final rule, we recognize that crop-based biofuel 
lifecycle GHG emissions are inherently uncertain to a large degree. 
Thus, we do not expect this exercise to produce a single robust 
estimate of the GHG impacts associated with the volume requirements 
that will be established with the final rule. However, we do expect 
this model comparison exercise to advance our understanding for the 
final rule, by more precisely locating the reasons that model estimates 
differ, and by identifying future priorities for updating and aligning 
particular assumptions across the models.
    We invite comment on the range of lifecycle GHG emissions impacts 
of the biofuels considered as part of this proposed rulemaking, and 
input on the proposed approach, or other potential approaches, for 
conducting a model comparison exercise for the final rule. We invite 
comment on the scope of this review as well as comment on the specific 
studies included in the review. We also invite comment on how this 
information may be used to inform the final rule. Given the different 
types of modeling frameworks currently available, we also invite 
comments on the appropriateness of these different approaches for 
conducting lifecycle GHG emissions analysis and whether model results 
can or should be weighted if we choose a multi-model approach to 
assessing GHG emissions for purposes of RFS volumes assessment. Since 
models treat time differently (e.g., different time steps, static 
versus dynamic models), we invite comment on the most appropriate way 
to handle the GHG impacts of biofuels over time. As we undertake this 
expanded examination of the changes in GHG emissions attributable to 
biofuels and the RFS program, we solicit input on how we should refine 
our analysis by revising or incorporating various effects such as land 
use change, the effectiveness of conservation programs targeted at soil 
sequestration of carbon, international leakage (e.g., effects of 
potentially backfilling vegetable oil feedstocks with palm oil), 
facility-level variability in GHG emissions, and others. We also 
request comment on how we can incorporate new research that examines 
the effectiveness of the RFS program in mitigating GHG emissions.

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 imports of 
petroleum, which in turn would have a direct impact on 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 independence and energy security are distinct but related

[[Page 80612]]

concepts.\101\ The goal of U.S. energy independence is the elimination 
of all U.S. imports of petroleum and other foreign sources of 
energy.\102\ U.S. energy security is broadly defined as the continued 
availability of energy sources at an acceptable price.\103\ Most 
discussions of U.S. energy security revolve around the topic of the 
economic costs of U.S. dependence on oil imports.
---------------------------------------------------------------------------

    \101\ Greene, D. 2010. Measuring energy security: Can the United 
States achieve oil independence? Energy Policy 38, pp. 1614-1621.
    \102\ Ibid.
    \103\ Ibid.
---------------------------------------------------------------------------

    The U.S.'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.\104\ Domestic oil consumption in 2022 
returned to pre-COVID-19 levels and is expected to be relatively steady 
during the timeframe of this proposed rule, 2023-2025. The U.S. has 
increased its production of oil, particularly ``tight'' (i.e., shale) 
oil, over the last decade.\105\ 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 proposed 
rule, 2023-2025.\106\ \107\ This is a significant reversal of the 
U.S.'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.\108\
---------------------------------------------------------------------------

    \104\ U.S. Energy Information Administration. 2022. Total 
Energy. Monthly Energy Review. Table 3.1. Petroleum Overview. March.
    \105\ https://www.eia.gov/energyexplained/oil-and-petroleum-products/images/u.s.tight_oil_production.jpg.
    \106\ https://www.eia.gov/energyexplained/oil-and-petroleum-products/imports-and-exports.php.
    \107\ U.S. Energy Information Administration. 2022. Annual 
Energy Outlook 2022. Reference Case. Table A11. Petroleum and Other 
Liquids Supply and Disposition.
    \108\ See EIA https://www.eia.gov/energyexplained/oil-and-petroleum-products/imports-and-exports.php.
---------------------------------------------------------------------------

    More recently, in the beginning of 2022, world oil prices have 
risen fairly rapidly. For example, as of January 3, 2022, the West 
Texas Intermediate (WTI) crude oil price was roughly $76 per barrel. 
The WTI oil price increased to roughly $124 per barrel on March 8th, 
2022, a 63 percent increase.\109\ High and volatile oil prices in 2022 
are a result of a combination of several factors: supply not rising 
fast enough to meet rebounding world oil demand from increased economic 
activity as COVID-19 recedes, reduced supply from some leading oil-
producing nations, and geopolitical events/conflicts (i.e., war in 
Ukraine). It is not clear to what extent the current oil price 
volatility will continue, increase, or be transitory in the 2023-2025 
period addressed by this proposed rule.
---------------------------------------------------------------------------

    \109\ U.S. Energy Information Administration daily spot prices, 
available at: https://www.eia.gov/dnav/pet/pet_pri_spt_s1_d.htm.
---------------------------------------------------------------------------

    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 from potentially unstable regions of the 
world. 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).\110\
---------------------------------------------------------------------------

    \110\ Monopsony impacts stem from changes in the demand for 
imported oil, which changes the price of all imported oil.
---------------------------------------------------------------------------

    For this proposed 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.\111\ 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.
---------------------------------------------------------------------------

    \111\ See the DRIA for more discussion of EPA's assessment of 
monopsony impacts of this proposed 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 proposed 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 2022 Annual Energy Outlook.\112\ 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 the DRIA accompanying this proposal.
---------------------------------------------------------------------------

    \112\ See DRIA 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 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 
crude oil imports/U.S. petroleum product imports from the candidate 
volumes is provided in the DRIA. Table IV.B-1 below presents the 
macroeconomic oil security premiums and the total energy security 
benefits for the candidate volumes for 2023-2025.

[[Page 80613]]



   Table IV.B-1--Macroeconomic Oil Security Premiums and Total Energy
                   Security Benefits for 2023-2025 \a\
------------------------------------------------------------------------
                                 Macroeconomic oil
                                 security premiums       Total energy
             Year                 (2021$/barrel of    security benefits
                                  reduced imports)     (millions 2021$)
------------------------------------------------------------------------
2023 (Including the                           $3.37                 $211
 supplemental standard).......        ($0.88-$6.20)           ($55-$389)
2023 (Excluding the                           $3.37                 $200
 supplemental standard).......        ($0.88-$6.20)           ($52-$368)
2024..........................                $3.46                 $219
                                      ($0.89-$6.36)           ($56-$403)
2025..........................                $3.46                 $223
                                      ($0.83-$6.40)           ($53-$412)
------------------------------------------------------------------------
\a\ Top values in each cell are the mean values, while the values in
  parentheses define 90 percent confidence intervals.

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.C.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 DRIA Chapter 9.
    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, of which the biofuel feedstock usually is 
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.
     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.
     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 which is reflected in the relative 
fossil fuel volume being displaced.
    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.
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. A detailed discussion of the renewable fuel 
costs relative to the fossil fuel costs is contained in DRIA Chapter 
10.
    For each year for which we are proposing 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.
    This rulemaking includes proposed regulatory provisions that would 
govern the generation of RINs from renewable electricity (eRINs) 
generated from biogas (see Section VIII). Because there is a 
substantial quantity of biogas already being used to generate 
electricity today, and there is a limited number of electricity-powered 
vehicles projected to be in the light-duty vehicle fleet through 2025, 
we determined that existing biogas to electricity generation would be 
sufficient to supply light-duty vehicles. As a result, the RFS program 
would not drive any new biogas-based electricity production through 
2025 and as a consequence there would be no biogas-to-electricity 
production costs. Nevertheless, since biogas to electricity will be a 
new aspect of the RFS program, the sunk cost of using biogas to produce 
electricity is estimated and presented in the RIA Chapter.

                                       Table IV.C.2-1--Total Social Costs
                                           [Million 2021 dollars] \a\
----------------------------------------------------------------------------------------------------------------
                                                                     2023 with
                                                       2023        supplemental        2024            2025
                                                                     standard
----------------------------------------------------------------------------------------------------------------
Gasoline........................................             252             252             258             303

[[Page 80614]]

 
Diesel..........................................          10,855          11,512           8,919           8,651
Natural Gas.....................................              92              92             119             148
                                                 ---------------------------------------------------------------
    Total.......................................          11,119          11,856           9,295           9,100
----------------------------------------------------------------------------------------------------------------
\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
                                                 [2021 dollars]
----------------------------------------------------------------------------------------------------------------
                                                                     2023 with
                                      Units            2023        supplemental        2024            2025
                                                                     standard
----------------------------------------------------------------------------------------------------------------
Gasoline......................  [cent]/gal......            0.18            0.18            0.18            0.22
Diesel........................  [cent]/gal......            19.6            20.7            16.2            15.6
Natural Gas...................  [cent]/thousand             0.30            0.30            0.39            0.48
                                 ft\3\.
Gasoline and Diesel...........  [cent]/gal......             5.7             6.1             4.8             4.7
----------------------------------------------------------------------------------------------------------------
\a\ Per-gallon or per thousand cubic feet cost of the renewable fuel expressed over the fossil fuel it is
  blended into; the last row expresses the cost over the obligated pool of gasoline and diesel fuel.

    The biofuel costs are higher than the costs of the gasoline, 
diesel, and natural gas that they displace as evidenced by the 
increases in fuel costs shown in the above table associated with the 
candidate volumes. Despite increasing renewable diesel fuel volumes 
over the 2023 to 2025 year timeframe, the projected cost to diesel fuel 
for the increased renewable diesel volume is decreasing due to year-
over-year decreases in projected vegetable oil prices which in turn 
decreases the relative cost of renewable diesel. However, as described 
more fully in DRIA Chapter 10, our assessment of costs did not yield a 
specific threshold value below which the incremental costs of biofuels 
are reasonable and above which they are not. 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 proposed 
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 DRIA 
Chapter 10.5. Table IV.C.3-1 summarizes the estimated impacts of the 
candidate volumes on gasoline, diesel, and natural gas fuel prices at 
retail when the costs of each biofuel is amortized over the fossil fuel 
it displaces. In the final row of the table, we show the estimated 
retail costs when the total costs are amortized evenly over the entire 
gasoline and diesel fuel pools since these are the obligated fuel 
pools.

                       Table IV.C.3-1--Estimated Effect of Biofuels on Retail Fuel Prices
                                                  [[cent]/gal]
----------------------------------------------------------------------------------------------------------------
                                                                       2023            2024            2025
----------------------------------------------------------------------------------------------------------------
Relative to No RFS Baseline:
    Gasoline....................................................             0.6             1.8             3.1
    Diesel......................................................            14.1            14.4            14.9
    Gasoline and Diesel.........................................             4.3             5.3             6.3
Relative to 2022 Baseline:
    Gasoline....................................................             1.7             2.6             3.3
    Diesel......................................................             0.8             1.5             3.2
    Gasoline and Diesel.........................................             1.4             2.3             3.3
----------------------------------------------------------------------------------------------------------------

    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 14.9[cent] per gallon for diesel 
fuel in 2025.
    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

[[Page 80615]]

produce.\113\ Applying the price correlation from the USDA study would 
indicate that the 14.9[cent] per gallon diesel fuel cost increment 
associated with the 2025 RFS volumes which increases retail prices by 
about 5.1 percent, would then increase the wholesale price of produce 
by about 1.18 percent. If produce being transported by a diesel truck 
costs $3 per pound, the increase in that product's price would be 
$0.035 per pound.\114\ If all the estimated program subsidized costs 
are averaged over the combined gasoline and diesel fuel pool as shown 
in the bottom row of Table IV.C.3-1, the impact on produce prices would 
be proportionally lower based on the lower per-gallon cost.
---------------------------------------------------------------------------

    \113\ Volpe, Richard; How Transportation Costs Affect Fresh 
Fruit and Vegetable Prices; United States Department of Agriculture; 
November 2013.
    \114\ Comparing Prices on Groceries; May 4, 2021: http://www.coupons.com/thegoodstuff/comparing-prices-on-groceries.
---------------------------------------------------------------------------

D. Comparison of Costs and Impacts

    As explained in Section III of this rule, the statutory factors for 
which the potential impacts of the candidate volumes are reasonably 
quantifiable are compared against a No RFS baseline, which assumes the 
RFS program remains intact through 2022 but ceases to exist thereafter. 
The statute does not specify how EPA should assess each factor, 
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.\115\ Information and specifics on how fuel costs 
are calculated are presented in DRIA Chapter 9, while energy security 
benefits are discussed in DRIA Chapter 4. A summary of the fuel costs 
and energy security benefits is shown in Tables IV.D-1 and 2. 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 DRIA. 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. We request comment on our assessment of these factors and 
methods that could be used to quantify the impact of the RFS on these 
factors in future actions.
---------------------------------------------------------------------------

    \115\ Due to the uncertainty related to the GHG emission impacts 
of the candidate volumes (discussed in further detail in Chapter 3.2 
of the RIA) we have not included a quantified projection of the GHG 
emission impacts in this proposal.

                                Table IV.D-1--Fuel Costs of the Candidate Volumes
                                          [2021 Dollars, millions] \a\
----------------------------------------------------------------------------------------------------------------
                                                                                   Discount rate
                              Year                               -----------------------------------------------
                                                                        0%              3%              7%
----------------------------------------------------------------------------------------------------------------
2023:
    Excluding Supplemental Standard.............................          11,199          11,199          11,199
    Including Supplemental Standard.............................          11,856          11,856          11,856
2024............................................................           9,295           9,025           8,687
2025............................................................           9,100           8,578           7,948
Cumulative Discounted Costs:
    Excluding Supplemental Standard.............................  ..............          28,801          27,835
    Including Supplemental Standard.............................  ..............          29,458          28,492
----------------------------------------------------------------------------------------------------------------
\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 Candidate Volumes
                                            [2021 Dollars, millions]
----------------------------------------------------------------------------------------------------------------
                                                                                   Discount rate
                              Year                               -----------------------------------------------
                                                                        0%              3%              7%
----------------------------------------------------------------------------------------------------------------
2023:
    Excluding Supplemental Standard.............................             200             200             200
    Including Supplemental Standard.............................             211             211             211
2024............................................................             219             213             205
2025............................................................             223             210             195
Cumulative Discounted Benefits:
    Excluding Supplemental Standard.............................  ..............             623             600
    Including Supplemental Standard.............................  ..............             634             611
----------------------------------------------------------------------------------------------------------------

    Regardless of whether or not we were able to quantify or monetize 
the impact of the candidate volumes on each of the statutory factors, 
consideration of these factors is still required by the statute. We 
request comment generally on how costs and benefits quantified in this 
proposed rule are calculated and accounted for, as well as methods to 
quantify and monetize additional statutory factors where appropriate.

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. However, Executive Order 
12898 (59 FR 7629; February 16, 1994) establishes federal executive 
policy on environmental justice. Its main provision directs federal 
agencies, to the greatest extent practicable and permitted by law, to

[[Page 80616]]

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 minority populations and low-income populations 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.\1\ 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.
    When assessing the potential for disproportionately high and 
adverse health or environmental impacts of regulatory actions on 
minority populations, low-income populations, tribes, and/or indigenous 
peoples, EPA strives to answer three broad questions:
     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 then 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, the Agency 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.116 117 118 119 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.\120\ 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.121 122 123 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.
---------------------------------------------------------------------------

    \116\ Mohai, P.; Pellow, D.; Roberts Timmons, J. (2009) 
Environmental justice. Annual Reviews 34: 405-430. https://doi.org/10.1146/annurev-environ-082508-094348.
    \117\ 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.
    \118\ 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.
    \119\ 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.
    \120\ 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.
    \121\ 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.
    \122\ 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.
    \123\ 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.\124\ 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.\125\
---------------------------------------------------------------------------

    \124\ U.S. EPA (2022) Health and environmental effects of 
pollutants discussed in chapter 4 of draft regulatory impact 
analysis (DRIA) supporting proposed RFS standards for 2023-2025. 
Memorandum from Rich Cook to Docket No. EPA-HQ-OAR-2021-0427, July 
21, 2022.
    \125\ 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.
---------------------------------------------------------------------------

    DRIA Chapter 4.1 summarizes what is known about potential air 
quality impacts of the candidate volumes assessed for this rule. We 
expect that

[[Page 80617]]

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 magnitude and direction of travel of facility-
specific emissions associated with the candidate volumes, and therefore 
we are unable to evaluate impacts on air quality in the specific EJ 
communities 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 DRIA 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 registered biofuel facilities and within 5 
kilometers of petroleum refineries to identify any disproportionate 
impacts these volume changes may have on nearby minority or low-income 
populations.\126\ Information on these populations and potential 
impacts upon them are further discussed in DRIA 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 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 facilities are in 
sparsely populated areas or have lower impacts on air quality. RNG or 
biogas electricity 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 require greater production of corn ethanol or biogas electricity 
than exists already, and therefore we would not expect any adverse 
impacts on EJ communities near biogas facilities that upgrade to RNG 
nor to biogas facilities combusting on site for electricity generation 
during the timeframe of this rule.
---------------------------------------------------------------------------

    \126\ 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.
---------------------------------------------------------------------------

2. Other Environmental Impacts
    As discussed in DRIA 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, as a result, 
soil quality, which could in turn have disproportionate impacts on 
communities of concern. This does not apply to biogas used to produce 
electricity or upgraded to RNG, since while land use impacts from 
agriculture, waste management, and wastewater treatment may impact 
water and soil quality on their own, biogas feedstock capture is a net 
benefit to soil and water quality, as it captures otherwise wasted 
product. At this time, we are not able to assess any contributions to 
these potential effects from biofuels apart from biogas. To better 
understand the relationship between the annual RFS volume requirements 
and air, water and soil quality issues that may impact EJ communities, 
we seek comment on additional information on the impacted populations 
in order to evaluate any environmental justice concerns associated with 
the candidate volumes. We seek comment on the following:
     Where are the populations that are currently being 
impacted to the greatest degree?
     Who resides in those areas?
     How are resident populations using the water and soil?
     How are the changes in water quality and availability 
impacting those uses and, thereby, those populations?
3. Economic Impacts
    The candidate volumes could have an impact on food and fuel prices 
nationwide, as discussed in DRIA Chapters 8.5. We estimate that the 
candidate volumes would result in food prices that are 0.57 percent 
higher in 2023 and 2024 and 0.58 percent higher in 2025, that the food 
prices we project with the No RFS baseline. 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 as shown in Table IV.E.3-1. 
We request comment on these estimates of the impacts of the candidate 
volumes on food prices, and the methodology used to derive these 
estimates.
---------------------------------------------------------------------------

    \127\ Bureau of Labor and Statistics Consumer Expenditure 
Survey, 2020. https://www.bls.gov/cex/tables/calendar-year/aggregate-group-share/cu-income-quintiles-before-taxes-2020.pdf.

                     Table IV.E.3-1--Proportion of Total Expenditures on Food and Fuel \127\
----------------------------------------------------------------------------------------------------------------
                                                                                    Lowest 20%     Second-lowest
                                                                   All consumer      consumer      20% consumer
                                                                       units          income          income
----------------------------------------------------------------------------------------------------------------
Total expenditures..............................................         $61,350         $28,782         $39,846
Food expenditures...............................................          $7,316          $4,095          $5,380
Percent of total expenditures on food...........................           11.9%           14.3%           13.5%
Fuel expenditures...............................................          $1,568            $814          $1,254
Percent of total expenditures on fuel...........................            2.6%            2.8%            3.1%
Percent Women...................................................             53%             65%             56%
Percent Black...................................................             13%             19%             15%

[[Page 80618]]

 
Percent With a High School Degree or Less.......................             30%             49%             41%
----------------------------------------------------------------------------------------------------------------

V. Response to Remand of 2016 Rulemaking

    In this action, we are proposing to complete 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.128 129 As discussed in 
the final rule establishing applicable standards for 2020-2022,\130\ 
our intended 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.\131\ We required the first 
250-million-gallon supplement in 2022. We are now proposing a second 
250-million-gallon supplement to be complied with in 2023. This 2023 
supplemental volume requirement, if finalized, in combination with the 
2022 supplement would constitute a meaningful remedy and complete our 
response to the ACE vacatur and remand.
---------------------------------------------------------------------------

    \128\ 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).
    \129\ 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).
    \130\ 87 FR 39600, 39627-39631 (July 1, 2022).
    \131\ 864 F.3d at 691.
---------------------------------------------------------------------------

    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.\132\ We also 
discussed our consideration of alternative approaches to respond to the 
remand.\133\ We maintain the same views on the alternatives discussed 
in that rulemaking, including those identified by commenters, and in 
the intervening period of time 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. This 
section will therefore only provide a short summary of the 
appropriateness of the proposed 2023 supplement, as well as how it 
would be implemented.
---------------------------------------------------------------------------

    \132\ 87 FR 39600, 39627-39628 (July 1, 2022).
    \133\ 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.
---------------------------------------------------------------------------

A. Supplemental 2023 Standard

    We are proposing to complete 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 would thus avoid the difficulties 
associated with reopening 2016 compliance, as discussed in detail in 
the 2020-2022 proposed rulemaking.\134\ This supplemental standard will 
have 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 will provide a meaningful remedy in response to 
the court's vacatur and remand in ACE and will effectuate 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. It is with emphasis on these considerations that we are proposing 
a different approach from the one proposed in the 2020 proposal.\135\ 
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 any 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 will 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,\136\ and obligated 
parties had an opportunity at that time to utilize those RINs for 
compliance or sell them to other parties, while ``banking'' RINs that 
could be utilized for future compliance years.
---------------------------------------------------------------------------

    \134\ 86 FR 72436, 72459-72460 (Dec. 21, 2022).
    \135\ See FCC v. Fox, 556 U.S. 502 (2009), acknowledging an 
agency's ability to change policy direction.
    \136\ 2016 RINs could also be used for up to 20 percent of an 
obligated party's 2017 compliance demonstrations.
---------------------------------------------------------------------------

    In applying a supplemental standard to 2023, we would treat 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 
would also be subject to the supplemental standard. The applicable 
deadlines for attest engagements and compliance demonstrations that 
apply to the 2023 standards would also apply to the supplemental 
standard. The gasoline and diesel volumes used by obligated parties to 
calculate their obligation would be their 2023 gasoline and diesel 
production or importation. Additionally, obligated parties could use 
2022 RINs for up to 20 percent of their 2023 supplemental standard.

[[Page 80619]]

    We seek comment on this approach of applying a supplemental 
standard for 2023 associated with the ACE remand on top of the proposed 
standards for 2023.
1. Demonstrating Compliance With the 2023 Supplemental Standard
    As we have done for the 2022 supplemental standard, we are 
proposing to prescribe formats and procedures as specified in 40 CFR 
80.1451(j) for how obligated parties would demonstrate compliance with 
the 2023 supplemental standard that simplifies the process in this 
unique circumstance. Although the proposed 2023 supplemental standard 
would be a regulatory requirement separate from and in addition to the 
2023 total renewable fuel standard, obligated parties would submit a 
single annual compliance report for both the 2023 annual standards and 
the supplemental standard and would only report a single number for 
their total renewable fuel obligation in the 2023 annual compliance 
report. Obligated parties would 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 unique compliance situation, 
we would issue guidance with instructions on how to calculate and 
report the values to be submitted in their 2023 compliance reports.
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 designed to address the approach that 
we are proposing in this action, namely the use of a 2016 volume 
requirement to calculate a 2023 percentage standard. Nonetheless, we 
can apply the same general approach to calculating a supplemental 
percentage standard for 2023.
    If this proposed approach to the ACE remand is finalized, the 
numerator in the formula in 40 CFR 80.1405(c) would be the supplemental 
volume of 250 million gallons of total renewable fuel. The values in 
the denominator would remain the same as those used to calculate the 
proposed 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 would be 0.14 percent.
    The proposed supplemental standard for 2023 would be a requirement 
for obligated parties separate from and in addition to the 2023 
standard for total renewable fuel. The two percentage standards would 
be listed separately in the regulations at 40 CFR 80.1405(a), but in 
practice obligated parties would 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 the 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.'' 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 were only providing a partial response to the 
court's remand and vacatur. This proposed action, if finalized, would 
complete our response. Additionally, as we have in the past, we propose 
to rely on our authority in CAA section 211(o)(2)(A)(i) to promulgate 
late standards.\137\ CAA section 211(o)(2)(A)(i) requires that EPA 
``ensure'' that ``at least'' the applicable volumes ``are met.'' \138\ 
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 in 2023, as we are 
proposing in this action.
---------------------------------------------------------------------------

    \137\ 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 7545(o)(2). 75 FR 14670, 
14718.
    \138\ 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 will not finalize this action prior to the 
beginning of the 2023 compliance year. Thus, our action is partly 
retroactive. In analyzing the benefits and burdens attendant to this 
approach, we have also considered the partially retroactive nature of 
the rule.
    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.\139\ EPA must consider and 
mitigate the burdens on obligated parties associated with a delayed 
rulemaking.\140\ 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.\141\ The approach we are proposing in this action would implement 
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 retroactive standard on 
obligated parties, but because obligated parties would comply with the 
proposed supplemental standard in 2023, it would instead be a late 
standard applied in 2023, with partially retroactive effects. Pursuant 
to

[[Page 80620]]

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.
---------------------------------------------------------------------------

    \139\ See ACE, 864 F.3d at 718; Monroe Energy, LLC v. EPA, 750 
F.3d at 920; NPRA, 630 F.3d at 154-58.
    \140\ ACE, 864 F.3d at 718.
    \141\ NPRA, 630 F.3d at 154-58.
---------------------------------------------------------------------------

    We believe that the approach proposed in this action, if finalized, 
could provide benefits that outweigh potential burdens. Consistent with 
the 2016 renewable fuel volume requirement established by Congress, our 
proposed and intended 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 
would provide 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 that while the additional volume in 2023 will put 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. We are 
soliciting comment on the feasibility of the proposed 250-million-
gallon supplemental standard in 2023. As explained earlier, there are 
insufficient 2015 and 2016 RINs available to satisfy the proposed 250-
million-gallon volume requirement. Instead, we are proposing a 
supplemental volume requirement to the 2023 standards that will apply 
prospectively. Doing so would allow 2022 and 2023 RINs to be used for 
compliance with the 2023 supplemental standard, in keeping with 
existing RFS regulations. We believe there would 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. We believe that compliance 
through the use of carryover RINs would not be necessary, but 
nevertheless would remain available as an option for obligated parties 
for compliance.\142\
---------------------------------------------------------------------------

    \142\ See Section IV.F for further discussion of the carryover 
RIN bank.
---------------------------------------------------------------------------

    Second, we provide significant lead-time for obligated parties by 
proposing this supplemental standard for 2023 no less than 18 months 
prior to the 2023 compliance deadline.\143\ Moreover, we initially 
provided obligated parties notice of the 250-million-gallon 
supplemental standard for 2022 in December of 2021,\144\ no less than 
18 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 
actual 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.
---------------------------------------------------------------------------

    \143\ See 40 CFR 80.1427.
    \144\ 86 FR 72436 (December 21, 2021).
---------------------------------------------------------------------------

    Third, we are proposing 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 will be a supplement to 
the 2023 standards. This approach would not only allow the use of 2022 
and 2023 RINs for compliance with the 2023 standard, as described 
earlier, but it would also avoid 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, our proposal allows obligated parties to satisfy both the 
2023 standards and the supplemental standard in a single set of 
compliance and attest engagement demonstrations. We are also proposing 
to extend 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 proposed 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.\145\
---------------------------------------------------------------------------

    \145\ 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,\146\ reopening 2016 compliance and applying a supplemental 
standard to the 2016 compliance year,\147\ 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.\148\
---------------------------------------------------------------------------

    \146\ 84 FR 36762, 36787-36789 (July 29, 2019).
    \147\ 86 FR 72459.
    \148\ 87 FR 39600 (July 1, 2022). See also Response to Comments 
document, Chapter 8.
---------------------------------------------------------------------------

    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 would be 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. We seek comment on this 
approach, as well as other alternative approaches to fully address the 
remand.

[[Page 80621]]

VI. Proposed 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.\149\ As described in Section III, we did this by first 
deriving a set of ``candidate volumes'' using several supply-related 
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 DRIA. 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 proposal. We intend to consider the 
best available information and science, including information provided 
through comments and any other information that becomes available, when 
setting the volume requirements in the final rule.
---------------------------------------------------------------------------

    \149\ CAA section 211(o)(2)(B)(ii).
---------------------------------------------------------------------------

    In this section, we summarize and discuss the implications of all 
our analyses as they apply 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 would be equal to the sum of cellulosic biofuel and 
non-cellulosic advanced biofuel, while the volume requirement for total 
renewable fuel would be equal to the sum of advanced biofuel and 
conventional renewable fuel.\150\
---------------------------------------------------------------------------

    \150\ 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.
---------------------------------------------------------------------------

    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 delegate to EPA the discretion to decide how and 
at what level of specificity to analyze the statutory factors. This 
section supplements the analyses discussed in Sections III and IV by 
providing a narrative summary of the key criteria that apply 
distinctively to each component category insofar as we have deemed them 
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, we remain 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 proposing 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 the 
EISA.
    As discussed in Section VIII.A, EPA determined that electricity 
may, under certain circumstances, qualify as a renewable fuel in the 
RFS2 rulemaking in 2010,\151\ and in the 2014 Pathways II rule we 
promulgated a pathway for the generation of D3 RINs for renewable 
electricity produced from biogas (eRINs).\152\ However, it subsequently 
became apparent that our regulations were not set up to appropriately 
enable the generation of eRINs under the RFS program. With this action 
we are proposing to not only revise the existing eRIN regulations, but 
to also include the cellulosic biofuel volumes that would result from 
allowing for the generation of RINs for renewable electricity from 
biogas under the program. Under this proposal, generation of eRINs 
would first begin in 2024.
---------------------------------------------------------------------------

    \151\ 75 FR 14670 (March 26, 2010).
    \152\ 79 FR 42128 (July 18, 2014).
---------------------------------------------------------------------------

    As discussed in Section III.B.1, we developed candidate volumes for 
cellulosic biofuel based on a consideration of 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 
electric vehicles in the fleet) and of the availability of qualifying 
feedstocks, primarily but not exclusively biogas. With an eye towards 
estimating candidate volumes which represent levels that can be 
achieved but which would not need to be waived under the cellulosic 
waiver authority (per CAA 211(o)(2)(B)(iv)), we estimated the 
following:

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


[[Page 80622]]

    We then analyzed these candidate volumes according to the other 
statutory factors. 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.\153\ 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 and electricity) are not expected to cause significant land use 
changes that might lead to adverse environmental impacts.
---------------------------------------------------------------------------

    \153\ 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, 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.\154\ 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.
---------------------------------------------------------------------------

    \154\ 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 this similarity, there are also significant differences 
between liquid cellulosic biofuels and CNG/LNG or electricity derived 
from biogas. In particular, the cost of producing liquid cellulosic 
biofuel is 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.
    Cellulosic biofuels derived from biogas, most notably CNG/LNG and 
renewable electricity, are also generally produced from waste materials 
or residues (e.g., through biogas collection from landfills, municipal 
wastewater treatment facility digesters, agricultural digesters, and 
separated MSW digesters) and thus are also not expected to affect the 
conversion of wetlands, ecosystems and wildlife habitat, soil and water 
quality, the price and supply of agricultural commodities, and food 
prices. However, in contrast to the feedstocks generally used to 
produce liquid cellulosic biofuels, significant quantities of biogas 
from these sources are already used to produce electricity, while 
smaller quantities are injected into natural gas pipelines.\155\ In 
some situations, such as at larger landfills, CNG/LNG derived from 
biogas may also be able to be produced at a price comparable to fossil 
natural gas. Because of the relatively low cost of production, biogas 
is expected to remain as the dominant feedstock for cellulosic biofuel 
through 2025, continuing to expand its use as CNG/LNG as well as its 
use to generate renewable electricity.
---------------------------------------------------------------------------

    \155\ See Landfill Gas Energy Project Data from EPA's Landfill 
Methane Outreach Program.
---------------------------------------------------------------------------

    Despite the relatively low cost of production for CNG/LNG and 
electricity derived from biogas, the combination of the high cellulosic 
biofuel RIN price and the significant volume potential for CNG/LNG and 
renewable electricity 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 $0.03 per gallon in 2025.\156\ eRINs alone are projected to 
increase the price of gasoline and diesel by $0.01 per gallon in 2024 
and approximately $0.02 per gallon in 2025.\157\
---------------------------------------------------------------------------

    \156\ See DRIA Chapter 10 for a further discussion of the 
expected impact of RINs generated for CNG/LNG or electricity derived 
from biogas on costs.
    \157\ See DRIA Chapter 10.5.5.2 for more information on the 
projected fuel price impacts of eRINs.
---------------------------------------------------------------------------

    Based on our analyses of all of the statutory factors, we believe 
that the candidate volumes shown in Table VI.A-1 would be reasonable 
and appropriate to require. As a result, in this action we are 
proposing cellulosic biofuel volume requirements through 2025 at the 
levels that we project will be produced in the U.S. or imported in each 
year and used as transportation fuel. Starting in 2024 the proposed 
volumes would also include RINs generated for renewable electricity 
used as transportation fuel. The proposed volumes, shown in Table VI.A-
2, are generally consistent with the volumes shown in Table VI.A-1, 
with one minor exception. More recent data suggests that liquid 
cellulosic biofuel production will be slightly lower than the candidate 
volumes and we have adjusted the proposed volumes accordingly (3 
million ethanol-equivalent gallons in 2024 and 5 million ethanol 
equivalent gallons in 2025). The proposed increases in the cellulosic 
biofuel volume relative to previous years reflect the statutory intent 
to support the development of increasing volumes of cellulosic biofuel 
as evidenced by the dramatic increases evident in the statutory volume 
targets in prior years, and the potential for significant GHG 
reductions that may result.

                                Table VI.A-2--Proposed Cellulosic Biofuel Volumes
----------------------------------------------------------------------------------------------------------------
                                                                       2023            2024            2025
----------------------------------------------------------------------------------------------------------------
Liquid Cellulosic Biofuel.......................................               0               3               5
CNG/LNG Derived from Biogas.....................................             719             814             921
eRINs...........................................................               0             600           1,200
                                                                 -----------------------------------------------
    Total Cellulosic Biofuel....................................             719           1,417           2,126
----------------------------------------------------------------------------------------------------------------

    The basis for these projections of cellulosic biofuel production is 
discussed in further detail in DRIA Chapter 6.1. In this chapter we 
acknowledge that there is significant uncertainty regarding cellulosic 
biofuel

[[Page 80623]]

production through 2025, particularly for CNG/LNG derived from biogas 
and for eRINs. For CNG/LNG derived from biogas the primary source of 
uncertainty is whether future growth in the production of these fuels 
will more closely resemble the lower growth rates observed in the past 
two years or whether it will return to the higher rates of growth 
observed in earlier years prior to the COVID pandemic. For eRINs, the 
primary sources of uncertainty are related to the sales of electric 
vehicles through 2025, how quickly electricity generators and OEMS will 
be able to complete the necessary steps to register under the RFS 
program, and the rate of participation/registration of these parties 
through 2025. Alternative projections for CNG/LNG derived from biogas 
are shown in Table IV.A-3. Further detail on these alternative 
projections can be found in DRIA Chapter 6.1. We request comment on our 
projections of cellulosic biofuel production for 2023-2025, including 
whether our primary projections, the alternative projections, or other 
projections presented by commenters are more likely in these years. We 
also welcome any other information or data that would inform our 
projections of cellulosic biofuel production in 2023-2025.

                      Table VI.A-3--Alternative Projections of CNG/LNG Derived From Biogas
                                      [Million ethanol equivalent gallons]
----------------------------------------------------------------------------------------------------------------
                                                                   Projected production of CNG/LNG derived from
                                                  Average growth                      biogas
             Growth rate time period                 rate (%)    -----------------------------------------------
                                                                       2023            2024            2025
----------------------------------------------------------------------------------------------------------------
2015-2019.......................................            30.4           955.4         1,245.8         1,624.5
2015-2021.......................................            26.3           896.2         1,131.9         1,429.7
----------------------------------------------------------------------------------------------------------------

    We recognize that with this proposed Set rule we are beginning 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). We note that there are 
several important changes in EPA's statutory authority in years after 
2022, and we seek input from commenters on how these changes can or 
should impact the required cellulosic biofuel volumes.
    EPA has the authority to establish RFS volumes for multiple years 
in one action, as we have proposed to do in this rule. We believe that 
proposing cellulosic biofuel volumes for multiple years (2023-2025) at 
a level equal to the projected production of cellulosic biofuel in 
these years will help provide the consistent market signals that the 
cellulosic biofuel industry needs to develop. We also recognize that 
there is increased uncertainty in our cellulosic biofuel projections 
due to the multi-year nature of this proposed rule, the inclusion of 
regulations governing the generation of eRINs, and the potential for 
the development and deployment of new cellulosic biofuel production 
pathways. The inclusion of eRINs in particular significantly increases 
the uncertainty of our cellulosic biofuel projections for 2024 and 
2025. Unlike other types of cellulosic biofuel EPA has no history 
projecting the generation of eRINs under the RFS program. The number of 
eRINs generated could also be impacted by a number of interrelated and 
complex factors, such as the size and future growth rate of the EV 
fleet, the supply of qualifying biogas for electricity generation, 
competition for the biogas and electricity from other markets, and the 
rate at which electricity generators can register to participate in the 
RFS program. We intend to closely monitor the generation of all 
cellulosic RINs, including eRINs, in future years and will consider 
adjusting the cellulosic biofuel volume requirements through a 
rulemaking or other mechanism if necessary, and we request comment on 
the impact the inclusion of eRINs in this rule could have on the 
volatility of the cellulosic RIN price.
    At the same time, we also believe that the eRIN proposal provides 
greater confidence for investments in biogas by creating a new, larger 
market for the use of biogas as transportation fuel at a time when the 
production of CNG/LNG derived from biogas may begin to be constrained 
by the number of CNG/LNG vehicles in the fleet. The significantly 
higher cellulosic biofuel volumes that we are proposing 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.
    In comments on previous RFS annual rules and discussions with EPA 
staff a number of cellulosic biofuel producers and parties developing 
cellulosic biofuel production technologies have stated that despite the 
incentive provided by the RFS program, variability and uncertainty in 
cellulosic RIN prices and future cellulosic biofuel requirements are 
hindering the development of the cellulosic biofuel industry.\158\ Many 
of these parties have stated that while uncertainties related to the 
demand for biofuels created by the RFS program and relatively volatile 
RIN prices are not unique to cellulosic biofuels, these factors are 
especially challenging in situations where cellulosic biofuel producers 
are considering investing in novel technologies that in many cases 
require significant capital investment. Some of these parties have 
noted that there is greater uncertainty in projecting cellulosic 
biofuel volumes in this Set rule relative to previous RFS annual rules, 
particularly as EPA has stated our intent to include a regulatory 
structure that would allow for the generation of eRINs for the first 
time and the fact that in this rule we are projecting cellulosic 
biofuel for several years rather than just a single year. These parties 
have 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 higher or lower 
than the actual production of cellulosic biofuel.
---------------------------------------------------------------------------

    \158\ For example, see Letter from Anew, Energy Power Partners, 
Opal Fuels, DTE Vantage, and Iogen to US EPA. August 26, 2022.
---------------------------------------------------------------------------

    Consequently, these cellulosic biofuel stakeholders have stated 
that EPA must consider the impacts this potential variability may have 
on both their industry and obligated parties. In a scenario where 
cellulosic biofuel production and imports are significantly lower than 
the cellulosic biofuel volume requirements (a RIN shortfall) there 
would be insufficient RINs for obligated parties to meet their RFS 
obligations.

[[Page 80624]]

This could result in some obligated parties being forced to carry RFS 
compliance deficits into future years, and if cellulosic biofuel 
production and imports continued to fall short of the volume 
requirements obligated parties could be forced into non-compliance. 
Alternatively, in a scenario where cellulosic biofuel production and 
imports are significantly higher than the cellulosic biofuel volumes 
requirements (a RIN surplus) the price of cellulosic RINs could fall to 
a level at or approaching the advanced biofuel RIN price. This could 
negatively impact investment in cellulosic biofuel production, and some 
stakeholders have argued that even the possibility that this scenario 
could occur in the future could negatively impact investment.
    In discussions with stakeholders, we have identified several 
existing mechanisms to address a potential cellulosic RIN shortfall 
should one occur in a future year. For example, we have consistently 
used our cellulosic waiver authority when necessary to reduce the 
statutory cellulosic biofuel targets. Consistent with our statutory 
authority, we have offered cellulosic waiver credits to obligated 
parties in years we have used our cellulosic waiver authority to reduce 
the statutory targets. We believe that we retain the ability to use the 
cellulosic waiver authority to reduce the cellulosic biofuel volumes we 
are establishing in this rule if necessary via a subsequent rule, and 
that were we to use this authority we would continue to set the 
cellulosic volume using a principle of ``taking neutral aim at 
accuracy.'' In such a scenario EPA would make available cellulosic 
waiver credits to obligated parties. These existing tools appear 
sufficient to address any potential RIN shortfalls in a future year. We 
request comment on the sufficiency of these tools to address a 
potential RIN shortfall, and other mechanisms that can or should be 
used to protect obligated parties against the negative impacts of a RIN 
shortfall.
    The RFS program as currently structured also contains a mechanism 
to help stabilize demand for cellulosic biofuel and cellulosic RINs in 
the event of a RIN surplus. Obligated parties have the ability to use 
RINs from the previous compliance year to satisfy up to 20 percent of 
the current year's obligation. These carryover provisions provide 
protection for the value of RINs in the event of a RIN surplus, as 
these RINs can be carried forward and used in the next compliance year. 
In the event of a surplus of RINs in a current year, the fact that 
these RINs will still be of value in the following year when RINs may 
be in short supply helps to stabilize the D3 RIN value over time. The 
RIN carryover provisions, however, do not eliminate all risk that an 
oversupply of cellulosic RINs will negatively impact the RIN price. 
Especially if, for example, the oversupply exceeds the 20 percent 
carryover limit we would expect to see an impact on the price of 
cellulosic RINs.
    Because of this, a number of cellulosic biofuel producers have 
communicated to EPA that the existing mechanisms in the RFS regulations 
to address the negative outcomes that could result from a RIN surplus 
are insufficient. They have recommended options that EPA could 
implement to address a potential future RIN surplus that would further 
protect them against potential RIN price volatility and/or lower RIN 
prices.\159\ Specifically, these parties suggested that EPA could 
address potential future RIN surpluses through either future 
rulemakings or an automatic adjustment mechanism established in our 
regulations. If EPA decided to address any potential future RIN surplus 
via rulemaking these parties suggested that the rule be completed prior 
to the start of the compliance year in which it applied (e.g., 
adjustments to the 2025 cellulosic volume would be completed by 
November 2024) and that the rule should be limited in scope to only 
increasing the cellulosic biofuel volume requirement for the upcoming 
year. The parties suggested that EPA consider whether increasing the 
cellulosic biofuel volume requirement could be done via a direct final 
rule or whether such an adjustment would require a full rulemaking. 
Alternatively, these stakeholders suggested that EPA could include a 
formula in the Set rule that would authorize EPA to adjust the 
cellulosic biofuel volume requirement through a public notification if 
our projection of cellulosic biofuel production and imports, including 
available carryover RINs, for the coming year exceeded or fell short of 
the cellulosic biofuel volume requirement by more than an undefined de 
minimis amount. As an example, stakeholders suggested that EPA could 
establish cellulosic volumes in the set rule, and notify all 
stakeholders of our intent to increase or decrease the required volumes 
to account for carryover RINs in excess of an established threshold or 
RIN deficits on an annual basis. The stakeholders suggested that 
including such a formula in the Set rule would allow these adjustments 
to be made without the need for a rulemaking process.
---------------------------------------------------------------------------

    \159\ Letter from Anew, Energy Power Partners, Opal Fuels, DTE 
Vantage, and Iogen to US EPA. August 26, 2022.
---------------------------------------------------------------------------

    We acknowledge that either of these mechanisms would likely reduce, 
and potentially even eliminate, the investment risk associated with a 
potential surplus of cellulosic RINs causing RIN price volatility or 
lower RIN prices. However, these options are not without potential 
challenges. The proponents of these changes to the RFS program 
acknowledge that regularly adjusting the RFS volume requirements 
through a rulemaking process would leave market participants exposed to 
variability in EPA RFS policy perspectives and could re-introduce some 
level of uncertainty and litigation risk that EPA is hoping to minimize 
in issuing a multi-year Set rule. They also recognize that changing the 
required volume of cellulosic biofuel via a direct final rule creates a 
litigation risk if even a single party opposes the changes. 
Alternatively, adjusting the cellulosic biofuel volume requirements 
using a public notice according to a formula in the Set rule without a 
rulemaking process is not clearly within our statutory authority. The 
statute requires that the cellulosic biofuel volumes in 2023 and future 
years be established through a rule and based on an assessment of the 
statutory factors. Were EPA to attempt to modify the cellulosic biofuel 
obligation outside a rulemaking process these changes could be 
overturned by a court, prompting additional rules to cure issues 
identified by a court and resulting in ongoing uncertainty. We further 
note that historically our projections of cellulosic biofuel production 
have been subject to a notice and comment process, and that there are 
potential drawbacks to adjusting the cellulosic biofuel volumes based 
on a projection without the benefit of public comment, whether through 
a rulemaking process or some other public process.
    We request comment on the sufficiency of the existing carryover RIN 
provisions to stabilize demand for cellulosic biofuel and cellulosic 
RINs in the event of a surplus of cellulosic RINs. We also request 
comment on other mechanisms that could be adopted to further address a 
potential RIN surplus, including the mechanisms suggested by cellulosic 
biofuel producers discussed in the preceding paragraphs, and on any 
other ways that EPA could help provide the necessary support for 
continued development of the cellulosic biofuel industry while also 
being consistent with our statutory obligations.

[[Page 80625]]

B. Non-Cellulosic Advanced Biofuel

    The volume targets established by Congress through 2022 anticipated 
significant growth in advanced biofuel beyond what is 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 indeed the applicable standards for 2022 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. This process included a consideration not only of 
production and import of non-cellulosic advanced biofuels, but also of 
the availability of qualifying feedstocks. Based on this analysis of 
supply-related factors, we estimated that some moderate growth after 
2022 was achievable.

     Table VI.B-1--Non-Cellulosic Advanced Biofuel Candidate Volumes
------------------------------------------------------------------------
                                                         Volume (million
                         Year                                 RINs)
------------------------------------------------------------------------
2023..................................................             5,100
2024..................................................             5,200
2025..................................................             5,300
------------------------------------------------------------------------

    We then analyzed these candidate volumes according to the other 
statutory factors.
    In practice 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. Some of the statutory factors assessed by EPA suggest that 
the targets for non-cellulosic advanced biofuel established by 
Congress, or even higher volumes, are still appropriate. Notably, 
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.\160\
---------------------------------------------------------------------------

    \160\ 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. We have therefore focused our attention on 
the impacts of these fuels in determining appropriate levels of non-
cellulosic advanced biofuel for 2023-2025.\161\ High domestic 
production capacity and availability of imports indicate that volumes 
of non-cellulosic advanced biofuel through 2025 may meet or even 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 these feedstocks have many existing 
uses that may require replacement with other suitable substitutes, 
there is also potential for ongoing growth in the production of some of 
these feedstocks. Higher implied volume requirements for non-cellulosic 
advanced biofuel may also have energy security benefits, increase 
domestic employment in the biofuels industry, and increase income for 
biofuel feedstock producers.
---------------------------------------------------------------------------

    \161\ 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.
---------------------------------------------------------------------------

    Some of the factors assessed would support lower volumes of non-
cellulosic advanced biofuel. For instance, as described in DRIA 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 some 
adverse consequences. As described in DRIA Chapter 6.2, 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. We expect that the primary feedstock available to 
biodiesel and renewable diesel producers in significant quantities 
through 2025 will be soybean oil and other vegetable oils whose primary 
markets are for food. Increased demand for soybean oil could lead to 
diversion of feedstocks from food and other current uses in addition to 
further incentivizing increased soybean crushing and soybean 
production. Increased soybean production in the U.S. and abroad 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 shown in Table VI.B-1 would be reasonable 
and appropriate to require. As a result, in this action we are 
proposing increases of 100 million gallons per year from 2023-2025 of 
non-cellulosic advanced biofuel over the implied volume requirement of 
five billion gallons finalized for 2022. These increases reflect our 
consideration of the potential for significant GHG reductions that may 
result from their use, balanced with the relatively small projected 
increases in related feedstock production through 2025 and the 
potential negative impacts associated with diverting some feedstock 
from existing uses to biofuel production. As discussed in greater 
detail in Section VI.D, the relatively modest proposed increases in the 
non-cellulosic advanced biofuel implied volume requirement also 
recognize that some quantities of non-cellulosic advanced biofuel 
beyond what is required may be used to help satisfy the implied 
conventional renewable fuel volume requirement.

C. Biomass-Based Diesel

    As described in the preceding section, we are proposing increases 
of 100 million gallons per year in the implied non-cellulosic advanced 
biofuel volume requirement from 2023 through 2025. In concert, we are 
also proposing to increase the BBD volume requirement by an energy-
equivalent amount (65 million physical gallons) per year from 2023 
through 2025. This approach would be 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.
    As in recent years, we believe that excess volumes of BBD beyond 
the BBD volume requirements that we are proposing 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

[[Page 80626]]

has driven the use of BBD in the market. Moreover, BBD can also be 
driven by the implied conventional renewable fuel volume requirement 
insofar as corn ethanol use as E15 and E85 is less economical as a 
means of compliance with the applicable standards than BBD. We believe 
these trends will continue through 2025.
    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. We seek comment on the proposed increase to the BBD 
standard and whether other options should be considered.

D. Conventional Renewable Fuel

    Although Congress had intended cellulosic biofuel to dominate the 
renewable fuel pool by 2022, instead, conventional renewable fuel has 
remained as the majority of renewable fuel supply since the beginning 
of the RFS program. The favorable economics of blending corn ethanol at 
10 percent into gasoline caused it to quickly saturate the gasoline 
supply shortly after the RFS2 program began and it has remained in 
nearly every gallon of gasoline 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.\162\ \163\ 
Arguably, the market has come to expect that the applicable percentage 
standards will include 15 billion gallons of conventional renewable 
fuel, and has oriented its operations accordingly.
---------------------------------------------------------------------------

    \162\ 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 proposes to respond to this remand through the 
application of supplemental standard in 2023 that, combined with an 
identical supplemental standard in 2022, would rectify our 
inappropriate use of the general waiver authority for 2016 through 
which we had reduced implied volume requirement below 15 billion 
gallons.
    \163\ 87 FR 39600 (July 1, 2022).
---------------------------------------------------------------------------

    As discussed in Sections III.B.4 and III.B.5, based on supply-
related factors we determined that 15 billion gallons of conventional 
renewable fuel remains a reasonable candidate volume for years after 
2022. It was this volume that we analyzed according to the other 
statutory factors.
    As discussed in Section III.B.5, constraints on ethanol consumption 
have made reaching 15 billion gallons with ethanol alone infeasible, 
and we expect these constraints to continue in at least the near term. 
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 decrease over these three years. 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 be met with conventional renewable fuel or advanced 
biofuel, and with ethanol or non-ethanol biofuels.
    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.
    Several of the factors that we analyzed highlight the importance of 
ongoing support for 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 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,\164\ 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.
---------------------------------------------------------------------------

    \164\ CAA section 211(o)(2)(A)(i).
---------------------------------------------------------------------------

    As discussed in Section V, we are proposing a supplemental volume 
requirement of 250 million gallons for 2023, representing the second 
step of our response to the remand of the 2016 standards. This 
supplemental volume requirement could be met with any qualifying 
renewable fuel, including corn ethanol. It could also be met with 
carryover RINs rather than RINs representing new renewable fuel 
consumption. In establishing the 250-million-gallon supplemental 
standard for 2022, we indicated that we thought the market could 
generate additional RINs to meet the standard. We believe the same is 
true for 2023. In the alternative, obligated parties could choose to 
comply with carryover RINs.\165\ As a result, the inclusion of a 
supplemental volume requirement of 250 million gallons in 2023 would 
have the net effect that the implied conventional renewable fuel volume

[[Page 80627]]

requirement is effectively 15.25 billion gallons rather than 15.00 
billion gallons.
---------------------------------------------------------------------------

    \165\ In past years we have noted a strong reluctance on the 
part of obligated parties to use carryover RINs for compliance with 
the applicable standards. They appear to prefer using RINs 
associated with new renewable fuels consumption when possible, 
preserving their carryover RIN banks for use in the event that 
future supply falls short of that needed to meet the applicable 
standards.
---------------------------------------------------------------------------

    Since the market will likely have oriented itself to supplying 
15.25 billion gallons of conventional renewable fuel in 2023 (or some 
combination of conventional renewable fuel and advanced biofuel), we 
considered whether it could do so in subsequent years as well. Although 
gasoline demand is projected to decrease between 2023 and 2025, that 
decrease is small: 0.1 percent from 2023 to 2024, and 0.3 percent from 
2024 to 2025.\166\ Given the increased use of E15 and E85 over this 
same timeframe, we project that total ethanol use will actually 
increase between 2023 and 2025 as discussed in Section III.A.5. We are 
thus proposing that the implied volume requirement for conventional 
renewable fuel in 2024 and 2025 be 15.25 billion gallons.
---------------------------------------------------------------------------

    \166\ As projected by EIA's Annual Energy Outlook 2022. We note 
that this outlook occurred prior to the sharp increase in world oil 
prices and thus gasoline prices as a result of the war in Ukraine. 
Future outlooks may thus have a lower gasoline demand forecast.
---------------------------------------------------------------------------

    Nevertheless, we recognize that any increase in the implied volume 
requirement for conventional renewable fuel above 15 billion gallons 
could be seen as inconsistent with Congress's implied intention that 
all increases in renewable fuel after 2015 be in advanced biofuel, the 
vast majority of which was cellulosic biofuel. And as stated above, it 
is possible that the 250-million-gallon supplemental volume requirement 
for 2023 could be met entirely with carryover RINs, requiring the 
market to supply 250 million gallons of additional renewable fuel for 
the first time in 2024. If limitations in domestic supply result in 
increased imports to meet the need for 250 million gallons, we believe 
that those imports would most likely be in the form of renewable diesel 
produced from palm oil. While grandfathered under 40 CFR 80.1403 and 
thus qualifying, this form of renewable fuel would be unlikely to 
provide any meaningful GHG benefits and could contribute to deleterious 
environmental impacts in places where palm oil is produced, such as in 
Malaysia and Indonesia. We therefore request comment on whether the 
implied volume requirement for conventional renewable fuel should 
remain at 15.00 billion gallons in 2024 and 2025.

E. Summary of Proposed Volume Requirements

    For the reasons described above, we are proposing the following 
volume requirements for the four component categories. Also shown is 
the supplemental volume requirement addressing the 2016 remand, 
discussed more fully in Section V.

                       Table VI.E-1--Proposed Volume Requirements for Component Categories
                                                 [Billion RINs]
----------------------------------------------------------------------------------------------------------------
                                                                       2023            2024            2025
----------------------------------------------------------------------------------------------------------------
Cellulosic biofuel..............................................            0.72            1.42            2.13
Biomass-based diesel \a\........................................            2.82            2.89            2.95
Non-cellulosic advanced biofuel.................................            5.10            5.20            5.30
Conventional renewable fuel.....................................           15.00           15.25           15.25
Supplemental volume requirement.................................            0.25               0               0
----------------------------------------------------------------------------------------------------------------
\a\ BBD volumes are given in billion gallons.

    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--Proposed Volume Requirements for Statutory Categories
                                                 [Billion RINs]
----------------------------------------------------------------------------------------------------------------
                                                                       2023            2024            2025
----------------------------------------------------------------------------------------------------------------
Cellulosic biofuel..............................................            0.72            1.42            2.13
Biomass-based diesel \a\........................................            2.82            2.89            2.95
Advanced biofuel................................................            5.82            6.62            7.43
Total renewable fuel............................................           20.82           21.87           22.68
Supplemental volume requirement.................................            0.25               0               0
----------------------------------------------------------------------------------------------------------------
\a\ BBD volumes are given in billion gallons.

    We believe that these proposed volume requirements would preserve 
and continue the gains made through biofuels in previous years when the 
statute specified applicable volume targets. In particular, these 
proposed volume requirements would help ensure that the transportation 
sector would realize additional reductions in GHGs and that the U.S. 
would experience greater energy independence and energy security. The 
proposed volume requirements would also promote ongoing development 
within the biofuels and agriculture industries as well as the economies 
of the rural areas in which biofuels production facilities and 
feedstock production reside.
    As discussed in Section II, our volume requirements for 2023 and 
the associated percentage standards will not be in place prior to 2023. 
Therefore, our standards for 2023 will be late and partially 
retroactive. Nonetheless, we believe that the proposed volume 
requirements for 2023 could be met despite this fact. With the issuance 
of this action, we are providing obligated parties with notice prior to 
2023 of the likely volumes for that year. Thus, the market can have a 
reasonable expectation that the proposed volume requirements will be 
the basis for the final applicable percentage standards unless public 
comments that we receive in response to this proposal compel us

[[Page 80628]]

to modify them. Even in that case, meaningful changes to the proposed 
volume requirements would require a supplemental proposal, giving the 
market another opportunity to adjust expectations. While we anticipate 
that the 2023 standards will require increases in renewable fuel use 
over the 2022 standards, we also anticipate that such increases can be 
met by the market. We project that there will be sufficient RINs 
available for 2023 compliance. Obligated parties will also have at 
least nine months from the time of promulgation of this final rule 
before they are required to submit associated compliance reports.\167\
---------------------------------------------------------------------------

    \167\ Based on the deadline of June 14, 2023, for EPA to sign a 
rulemaking to finalize the 2023 volumes pursuant to the consent 
decree in Growth Energy v. Regan, et al., No. 1:22-cv-01191 
(D.D.C.), EPA expects the 2023 compliance deadline to be March 31, 
2024. See 40 CFR 80.1451(f)(1)(A).
---------------------------------------------------------------------------

F. Request for Comment on Volume Requirements for 2026

    Although we are proposing volume requirements and applicable 
percentage standards for three years, we are also requesting comment on 
finalizing the same for an additional year, 2026. If we were to do 
this, we would intend to extend to 2026 the same trends that we are 
proposing for 2023-2025 for BBD, non-cellulosic advanced biofuel, and 
conventional renewable fuel. As a result, non-cellulosic advanced 
biofuel would increase an additional 100 million RINs in 2026, BBD 
would continue to increase at a rate consistent with the growth in non-
cellulosic advanced biofuel, and conventional renewable fuel would 
remain at 15.25 million RINs. Cellulosic biofuel volumes would continue 
to increase through projected growth in the use of renewable 
electricity as both the electric vehicle fleet expands and additional 
biogas to electricity generation capacity comes online as discussed in 
DRIA Chapter 6.1.4. Projecting these impacts for 2026 is considerably 
more uncertain than the projections for 2023-2025 given that growth in 
biogas electricity generating capacity is expected to be needed beyond 
the current supply and that growth is expected to be influenced by the 
availability of eRINs, for which we do not yet have a track record to 
evaluate.
    If we were to finalize volume requirements and the associated 
percentage standards for 2026, we would intend to use the values shown 
below. We solicit comment on these volume requirements, including 
whether we should take final action to adopt them at the same time as 
we establish the requirements and standards for 2023-2025.

Table VI.F-1--Possible 2026 Volume Requirements for Component Categories
------------------------------------------------------------------------
                                                                 Volume
                           Category                             (billion
                                                                  RINs)
------------------------------------------------------------------------
Cellulosic biofuel............................................      2.56
Biomass-based diesel \a\......................................      3.02
Non-cellulosic advanced biofuel...............................      5.40
Conventional renewable fuel...................................     15.25
------------------------------------------------------------------------
\a\ BBD volumes are given in billion gallons,


Table VI.F-2--Possible 2026 Volume Requirements for Statutory Categories
------------------------------------------------------------------------
                                                                 Volume
                           Category                             (billion
                                                                  RINs)
------------------------------------------------------------------------
Cellulosic biofuel............................................      2.56
Biomass-based diesel \a\......................................      3.02
Advanced biofuel..............................................      7.96
Total renewable fuel..........................................     23.21
------------------------------------------------------------------------
\a\ BBD volumes are given in billion gallons.

G. Request for Comment on Alternative Volume Requirements

    As described above, we are proposing volume requirements that we 
believe are both supported by the analyses that we are required to 
conduct and that would meet the policy goals of increasing the use of 
renewable fuels over time and reducing emissions of greenhouse gases. 
Nevertheless, we recognize that our provisional decisions to establish 
volume requirements for three years that include an effective 
conventional volume requirement of 15.25 billion gallons represent a 
significant policy choice for the program. We further recognize that 
stakeholders have suggested to EPA that we establish lower volume 
requirements than we are proposing in this action, particularly with 
respect to conventional renewable fuel. We are therefore requesting 
comment on various alternative approaches that we could take, both with 
respect to volumes as well as certain other policy parameters. We 
welcome general comments on our policy choices as well as specific 
comments on the particular topics identified below.
    As discussed in Section III.A, we believe that proposing volume 
requirements for three years provides an appropriate balance between, 
on the one hand, our desire to strengthen market certainty by 
establishing applicable standards for as many years as is practical, 
and on the other hand our expectation that longer time periods increase 
uncertainty in the projected volumes. Greater uncertainty increases the 
likelihood that the applicable standards could turn out to be not 
reasonably achievable or to accomplish programmatic goals and might 
need to be waived or revisited at a later date. Moreover, while we have 
made projections regarding how the market might respond to the 
applicable standards, establishing volume requirements for three years 
in this rulemaking means that those projections will be based on data 
available today that might be inapplicable by 2024 or 2025. The annual 
standard-setting rulemaking process that came to define the RFS program 
in previous years permitted us to adjust the next year's applicable 
volume requirements more frequently according to how the market was 
responding to previous year volume requirements. As a result, we 
request comment on establishing volume requirements through this 
rulemaking for only one or two years rather than three years. Doing so 
would enable us to account for the evolution of the fuels market in 
something closer to real time, and more generally to assess newer data, 
potentially making the standards that we set more reasonably achievable 
or more aligned with programmatic goals. However, establishing 
standards for only one or two years would also make it more difficult 
to establish future standards by the statutory deadlines (October 31, 
2022, for the 2024 standards, and October 31, 2023, for the 2025 
standards).
    Separately, and as discussed in Section III.C.3, the proposed 
inclusion of a supplemental volume requirement of 250 million gallons 
in 2023 to address the remand of the 2016 standards would effectively 
result in an implied conventional renewable fuel volume requirement of 
15.25 billion gallons in that year.\168\ \169\ We believe that this 
implied volume requirement could be met without the need for obligated 
parties to use carryover RINs for compliance, and without the need for 
imports of palm-based renewable diesel. We also determined that once 
the market had oriented itself to supply 15.25 billion gallons in 2023, 
it could also do so for 2024 and 2025. Nevertheless, we recognize that 
uncertainty in volume projections for longer periods, as well as 
potentially

[[Page 80629]]

increasing demand for domestic soybean oil and other vegetable oils, 
could impel the market to turn to imports of palm-based renewable 
diesel to help fulfill an implied conventional renewable fuel volume 
requirement in 2024 and 2025 of 15.25 billion gallons. Therefore, we 
request comment on maintaining the implied conventional renewable fuel 
volume requirement at 15.00 billion gallons for these two years.
---------------------------------------------------------------------------

    \168\ The implied conventional volume requirement itself would 
be 15.00 billion gallons in 2023, but the inclusion of the 250 
million gallon supplemental standard would effectively make it 15.25 
billion gallons.
    \169\ See also the discussion of our obligations regarding the 
2016 remand in Section V.
---------------------------------------------------------------------------

    Finally, we acknowledge concerns among some stakeholders about the 
impacts of the volume requirements on the price of Renewable 
Identification Numbers (RINs). More specifically, the level of the 
implied conventional renewable fuel volume requirement has a largely 
binary impact on D6 RIN prices: If it is set below the E10 blendwall as 
was the case before 2013, D6 RIN prices are very low (perhaps a few 
[cent]/RIN), whereas if it is set above the E10 blendwall, D6 RIN 
prices are considerably higher, rising to a level near that of advanced 
biofuel RINs.\170\ \171\ Our proposal includes an effective volume 
requirement for conventional renewable fuel of 15.25 billion gallons 
for 2023-2025 which is considerably higher than the E10 blendwall. As a 
result, we do not expect D6 RIN prices to be on the order of a few 
[cent]/RIN.
---------------------------------------------------------------------------

    \170\ The E10 blendwall represents the volume of ethanol that 
could be consumed if all gasoline was E10, and there was no E0, E15, 
or E85.
    \171\ Above the E10 blendwall, D6 RIN prices can also vary 
considerably due to a variety of market factors.
---------------------------------------------------------------------------

    While we believe that 15.25 billion gallons can be achieved in 
2023-2025, we do not believe that it is possible with corn ethanol 
alone. Instead, we expect that significant volumes of BBD in excess of 
that needed to meet the applicable volume requirement for advanced 
biofuel would also be needed.\172\ As shown in Table III.C.3-3, we 
project that about 14.5 billion gallons of the implied conventional 
renewable fuel volume requirement would be met with corn ethanol, with 
the remainder being met with BBD.\173\ The same market outcome could be 
expected if the implied conventional volume requirement was set at 14.5 
billion gallons and the advanced biofuel volume requirement was 
increased in concert, such that the total renewable fuel volume 
requirement remained unchanged. While this approach would guarantee 
that no amount of renewable fuel in excess of corn ethanol could be 
imported palm-based renewable diesel, thus maximizing the probability 
that the GHG benefits associated with our proposed standards occur, it 
would not be likely to have any impact on D6 RIN prices because 14.5 
billion gallons is still above the E10 blendwall. In order to have a 
meaningful impact on D6 RIN prices, we would need to reduce the implied 
conventional renewable fuel volume requirement to below the E10 
blendwall.
---------------------------------------------------------------------------

    \172\ See discussion in Section III.C.3.
    \173\ The 14.5 billion gallons of corn ethanol would include 
some used as E15 and/or E85.
---------------------------------------------------------------------------

    As discussed in Section III.C.3, our projection of the volume of 
corn ethanol that could be consumed in 2023-2025 incorporates the 
additional ethanol that could be consumed in the form of E15 and E85, 
and also accounts for some gasoline consumed as E0. In the absence of 
any E15 or E85, but under the assumption that the market would continue 
to offer some E0, the E10 blendwall would be as follows:

              Table VI.G-1--Projected E10 Blendwall \a\ \b\
------------------------------------------------------------------------
                                                           E10 Blendwall
                          Year                               (billion
                                                             gallons)
------------------------------------------------------------------------
2023....................................................          13,885
2024....................................................          13,865
2025....................................................          13,828
------------------------------------------------------------------------
\a\ Based on total gasoline energy demand from EIA's Annual Energy
  Outlook 2022, Table 2.
\b\ Assumes that the average denatured ethanol content of E10 is 10.1
  percent, and that the market continues to supply 2,128 million gallons
  of E0. See DRIA Chapter 6.5.2.

    In order to ensure a meaningful impact on D6 RIN prices, the market 
would have to have confidence that the standard was in fact below the 
E10 blendwall. Thus, the implied conventional renewable fuel volume 
requirement would need to be somewhat lower than the levels shown in 
Table VI.G-1, possibly on the order of about 200 million gallons. The 
resulting reduction in the conventional renewable fuel volume (after 
accounting for other advanced ethanol) would then be added to the 
advanced biofuel volume, resulting in the volume targets shown in Table 
VI.G-2 rather than the volume requirements shown in Table I.A.1-1.

                                      Table VI.G-2--Proposed Volume Targets
                                                 [Billion RINs]
----------------------------------------------------------------------------------------------------------------
                                                                       2023            2024            2025
----------------------------------------------------------------------------------------------------------------
Cellulosic biofuel..............................................            0.72            1.42            2.13
Biomass-based diesel \a\........................................            2.82            2.89            2.95
Advanced biofuel................................................            7.27            8.34            9.19
Renewable fuel..................................................           20.82           21.87           22.68
Supplemental standard...........................................            0.25             n/a             n/a
----------------------------------------------------------------------------------------------------------------
\a\ The BBD volumes are in physical gallons (rather than RINs).

    If we were to establish volume requirements according to the values 
in Table VI.G-2, we would expect that portion of the implied 
conventional renewable fuel volume requirement that would be met with 
ethanol in the form of E15 and E85 under our proposal to instead be met 
with additional BBD; by design, this alternative approach would 
essentially eliminate any incentive for E15 and E85. On the one hand, 
such a shift might be expected to increase the GHG benefits of the 
program since BBD is required under the statute to meet a GHG reduction 
threshold of 50 percent while conventional renewable fuel is required 
to meet a GHG reduction threshold of 20 percent. On the other hand, an 
increase in supply of BBD could place additional strain on the BBD 
feedstock supplies, resulting on some backfilling with imported palm 
oil, which could offset some or all of the GHG benefit one might 
otherwise expect.
    We request comment on these alternative approaches to establishing 
standards in this proposed rulemaking, including the number of years 
for which we would establish standards, whether the implied 
conventional renewable fuel volume requirement should be 15.00 billion 
gallons rather than 15.25 billion gallons in 2024 and 2025, and whether 
the implied conventional renewable fuel

[[Page 80630]]

volume requirement should be reduced by some other amount, such as 
below the E10 blendwall, while keeping the total renewable fuel volume 
requirement unchanged. While we have not conducted a detailed 
assessment of all of the impacts of these alternatives, we have 
estimated the impacts of these alternatives on retail fuel prices in 
DRIA Chapter 10.5.5.

VII. Proposed 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 is silent with regard to how 
applicable volume requirements should be implemented for years after 
2022. 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, we considered the 
use of percentage standards as the implementation mechanism for volume 
requirements. We determined that this mechanism was effective and 
reasonable. We also determined that no straightforward and easily 
implementable alternative mechanisms existed. Therefore, we propose to 
continue to use percentage standards as the implementing mechanism for 
years after 2022.
    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). 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).\174\ The RVOs 
are the number of RINs that the obligated party is responsible for 
procuring to demonstrate compliance with the RFS rule 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.\175\ The volumes used to determine the proposed 2023, 2024, 
and 2025 percentage standards are described in Section VI.E and are 
shown in Table VII-1.
---------------------------------------------------------------------------

    \174\ 40 CFR 80.1407.
    \175\ As discussed in Section V, we are proposing a supplemental 
standard for 2023 to address the remand of the 2016 standards under 
ACE. That supplemental standard would be 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 could be combined.

            Table VII-1--Volumes for Use in Determining the Proposed Applicable Percentage Standards
                                                 [Billion RINs]
----------------------------------------------------------------------------------------------------------------
                                                                       2023            2024            2025
----------------------------------------------------------------------------------------------------------------
Cellulosic biofuel..............................................            0.72            1.42            2.13
Biomass-based diesel \a\........................................            2.82            2.89            2.95
Advanced biofuel................................................            5.82            6.62            7.43
Renewable fuel..................................................           20.82           21.87           22.68
Supplemental standard...........................................            0.25             n/a             n/a
----------------------------------------------------------------------------------------------------------------
\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 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). As we are 
continuing to use the percentage standard mechanism to implement the 
volume requirements for years after 2022, we are not proposing any 
changes to those formulas. In addition to the required volumes of 
renewable fuel, the formulas also require estimates of the volumes of 
non-renewable gasoline and diesel fuel, for both highway and nonroad 
uses, which are projected to be used in the year in which the standards 
will apply. In previous annual standard-setting rules, the projected 
volumes of gasoline and diesel were provided by the Energy Information 
Administration (EIA) in a letter that was required under the statute to 
be sent to EPA by October 31 of each year.\176\ However, this statutory 
requirement ends in 2021 and therefore does not apply to compliance 
years after 2022. Moreover, historically those letters received by EPA 
from EIA provided gasoline and diesel volume projections reflecting 
those in EIA's Short Term Energy Outlook (STEO).\177\ While the STEO 
only provides volume projections for one future calendar year, this was 
sufficient for past annual standard-setting rulemakings since they 
never established applicable percentage standards for more than one 
future calendar year. This rulemaking, in contrast, proposes volume 
requirements and associated percentage standards for three future 
calendar years. Therefore, we could not use the STEO as a source for 
projections of gasoline and diesel for this action. Instead, we are 
proposing to use an alternative EIA publication for the purposes of 
calculating the percentage standards in this proposal, namely EIA's 
2022 Annual Energy Outlook (AEO).
---------------------------------------------------------------------------

    \176\ CAA section 211(o)(3)(A)
    \177\ See, for example, ``EIA letter to EPA with 2020 volume 
projections 10-9-2019,'' available in the docket.
---------------------------------------------------------------------------

    The projected gasoline and diesel volumes in AEO 2022 include 
projections of ethanol and biomass-based diesel used in transportation 
fuel. Since the percentage standards apply only to the non-renewable 
gasoline and diesel, the volumes of renewable fuel are subtracted out 
of the EIA projections of gasoline and diesel. The table below provides 
the precise projections from AEO 2022 that we have used to calculate 
the proposed percentage standards for 2023-2025.

[[Page 80631]]



 Table VII.A-1--AEO2022 Gasoline and Diesel Volumes for the Calculation
                  of Percentage Standards for 2023-2025
------------------------------------------------------------------------
        Fuel category                 Table                 Line
------------------------------------------------------------------------
Gasoline.....................  Table 2............  Total Energy
                                                     Consumption/Motor
                                                     Gasoline.
Renewables blended into        Table 2............  Energy Use & Related
 gasoline.                                           Statistics/Ethanol
                                                     (denatured)
                                                     Consumed in Motor
                                                     Gasoline.
Diesel.......................  Table 11...........  Product Supplied/by
                                                     Fuel/Distillate
                                                     fuel oil/of which:
                                                     Diesel
Renewables blended into        Table 11...........  Biofuels/Biodiesel +
 diesel.                                             Biofuels/Other
                                                     Biomass-derived
                                                     Liquids.
------------------------------------------------------------------------

    In order to convert projections in energy units into volumes, we 
used the conversion factors provided in AEO 2022 Table 68.

B. Treatment of Small Refinery Volumes

    Because we are proposing to continue the use percentage standards 
as the implementation mechanism through which the volume requirements 
would be effectuated, small refineries will continue to be required to 
produce proportionally smaller RFS volumes than larger obligated 
parties. And importantly, we do not anticipate that during the years 
covered by this proposal small refineries would be able to secure SREs 
to excuse compliance with these proportional RFS 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 volumes proposed 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. This 
is because in April and June 2022, EPA denied all pending SRE petitions 
for years spanning 2016 through 2020, finding that, consistent with 
Renewable Fuel Association v. EPA, SREs can only be granted if a small 
refinery demonstrates disproportionate economic hardship caused by 
compliance with the RFS program requirements and not other 
factors.\178\ Consistent with our prior actions, we found that that 
none of the small refinery petitioners suffered disproportionate 
economic hardship caused by their compliance with the RFS because 
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 fuel. 
Accordingly, we denied all SRE petitions.
---------------------------------------------------------------------------

    \178\ See generally,``April 2022 Denial of Petitions for RFS 
Small Refinery Exemptions,'' EPA-420-R-22-005, April 2022; ``June 
2022 Denial of Petitions for RFS Small Refinery Exemptions,'' EPA-
420-R-22-011, June 2022.
---------------------------------------------------------------------------

    Because the CAA interpretation and analysis presented in the April 
and June 2022 SRE Denials will apply equally to these future-year SRE 
petitions, we anticipate no SREs will be granted for these future 
years, including the 2023-2025 compliance years covered by this 
proposal. 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; therefore all small refineries will be 
required to comply with their proportional RFS obligations.\179\ Even 
were EPA to grant a SRE in the future for 2023-2025, such an action 
would not meaningfully alter our projection of SREs used in calculating 
the percentage standards.
---------------------------------------------------------------------------

    \179\ We are not prejudging any small refinery exemptions in 
this action; however, absent a compelling demonstration that a small 
refinery experiences DEH caused by compliance with the RFS program, 
we do not anticipate granting small refinery exemptions in the 
future.
---------------------------------------------------------------------------

C. Proposed 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 proposed rule are shown in Table VII.C-1 for 2023, 2024, and 2025.

              Table VII.C-1--Volumes for Terms in Calculation of the Proposed Percentage Standards
                                                 [Billion RINs]
----------------------------------------------------------------------------------------------------------------
                                                                                 2023
             Term                         Description               2023     Supplemental      2024       2025
----------------------------------------------------------------------------------------------------------------
RFVCB.........................  Required volume of cellulosic         0.72               0       1.42       2.13
                                 biofuel.
RFVBBD........................  Required volume of biomass-           2.82               0       2.89       2.95
                                 based diesel\a\.
RFVAB.........................  Required volume of advanced           5.82               0       6.62       7.43
                                 biofuel.
RFVRF.........................  Required volume of renewable         20.82            0.25      21.87      22.68
                                 fuel.
G.............................  Projected volume of gasoline...     139.71          139.71     139.46     139.13
D.............................  Projected volume of diesel.....      52.62           52.62      52.47      52.47
RG............................  Projected volume of renewables       14.50           14.50      14.50      14.62
                                 in gasoline.
RD............................  Projected volume of renewables        3.22            3.22       3.22       3.22
                                 in diesel.
GS............................  Projected volume of gasoline             0               0          0          0
                                 for opt-in areas.
RGS...........................  Projected volume of renewables           0               0          0          0
                                 in gasoline for opt-in areas.
DS............................  Projected volume of diesel for           0               0          0          0
                                 opt-in areas.
RDS...........................  Projected volume of renewables           0               0          0          0
                                 in diesel for opt-in areas.
GE............................  Projected volume of gasoline             0               0          0          0
                                 for exempt small refineries.

[[Page 80632]]

 
DE............................  Projected volume of diesel for           0               0          0          0
                                 exempt small refineries.
----------------------------------------------------------------------------------------------------------------
\a\ The BBD volume used in the formula represents physical gallons. The formula contains a 1.57 multiplier to
  convert this physical volume to ethanol-equivalent volume, consistent with the proposed change to the BBD
  conversion factor discussed in Section IX.D.

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

                                  Table VII.C-2--Proposed Percentage Standards
----------------------------------------------------------------------------------------------------------------
                                                                       2023            2024            2025
----------------------------------------------------------------------------------------------------------------
Cellulosic biofuel..............................................           0.41%            0.82            1.23
Biomass-based diesel............................................            2.54            2.60            2.67
Advanced biofuel................................................            3.33            3.80            4.28
Renewable fuel..................................................           11.92           12.55           13.05
Supplemental standard...........................................            0.14             n/a             n/a
----------------------------------------------------------------------------------------------------------------

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

VIII. Regulatory Program for Renewable Electricity

    Renewable fuels under the RFS program can be broadly categorized as 
liquid biofuels, such as ethanol or biodiesel, or non-liquid biofuels 
such as renewable compressed natural gas (renewable CNG) or renewable 
liquified natural gas (renewable LNG) used as transportation fuel. Non-
liquid renewable fuels have played a part in the RFS since 2010, when 
EPA promulgated final regulations establishing the RFS2 program (2010 
final rule).\180\ In that final rule, EPA discussed the relevant 
differences between liquid and non-liquid renewable fuels and 
established regulatory provisions for non-liquid fuels that recognized 
those distinctions, including for renewable CNG/LNG and electricity 
derived from renewable biomass (renewable electricity) that is used as 
a transportation fuel.
---------------------------------------------------------------------------

    \180\ 75 FR 14670, 14729 (March 26, 2010).
---------------------------------------------------------------------------

    EPA has registered multiple facilities and companies since 2010 
that generate RINs under approved renewable CNG/LNG pathways, and today 
those entities produce hundreds of millions of ethanol-equivalent 
gallons of renewable CNG/LNG every year. CNG/LNG vehicles and engines, 
while not as widespread as other technologies used for transportation, 
have existed for decades and are often seen, for example, in company 
and municipal fleets. Today, renewable CNG/LNG comprises the vast 
majority of cellulosic biofuel generating RINs under the RFS.
    The development of renewable electricity's role in the RFS program, 
however, has differed from that of renewable CNG/LNG. The 2010 RFS2 
final rule determined that renewable electricity is, in certain 
circumstances, a qualifying renewable fuel and established regulatory 
provisions governing the generation of RINs representing renewable 
electricity in anticipation of a future action in which EPA would 
provide a RIN-generating pathway for electricity made from renewable 
biomass and used as transportation fuel. In 2014, EPA established such 
a RIN-generating pathway for electricity made from biogas.\181\
---------------------------------------------------------------------------

    \181\ 79 FR 42128 (July 18, 2014).
---------------------------------------------------------------------------

    Despite the fact that renewable electricity has been part of the 
RFS program since 2010, EPA has not, to date, registered any party to 
generate RINs from renewable electricity. Since 2014, several 
stakeholders have submitted registration requests to generate RINs for 
renewable electricity. EPA reviewed these registration requests and met 
with a range of stakeholders; however, we ultimately determined that 
the structure of a program to generate RINs for electricity in the RFS 
program could present unique, unanticipated policy and implementation 
questions that needed to be resolved prior to registering any party, 
particularly in light of the competing policy preferences of 
stakeholders. Based on (1) our review of registration requests, (2) 
information gathered from stakeholders via both comments provided in 
response to EPA requests and ongoing discussions, and (3) an analysis 
of how to best incorporate renewable electricity into the RFS program, 
we concluded that EPA's existing regulations governing the generation 
of RINs for renewable electricity are insufficient to guarantee overall 
programmatic integrity, especially in light of the range of different 
and often competing approaches proposed by registrants. As a result, we 
determined it was necessary to establish a new regulatory program to 
govern the generation of RINs representing renewable electricity 
(``eRINs''). This proposed regulatory program for eRINs is intended to 
further the statutory goal to increase the use of renewable fuels over 
time, to do so in a manner that ensures that renewable electricity that 
generates RINs is produced from renewable biomass and is used as 
transportation fuel, and to incorporate qualifying renewable 
electricity used as transportation fuel into the RFS program in the 
same manner that liquid fuels have been since the inception of the RFS 
program.
    EPA has gained significant experience since 2014 in implementing an 
RFS program that allows qualifying RIN generation for both liquid and 
non-liquid renewable fuels that can inform the design and 
implementation of a program for renewable electricity. In this notice, 
we are proposing a new set of regulations to govern the implementation 
and oversight of the

[[Page 80633]]

generation of eRINs under the existing RIN-generating pathways for 
renewable electricity. While EPA previously approved electricity as a 
valid renewable fuel under the statutory definition, the existing 
regulations are not sufficient to enable electricity to fully 
participate in the RFS program. This proposal is intended to remedy the 
deficiencies in the existing regulations and to allow for the 
generation of RINs for renewable electricity that is qualifying 
renewable fuel. We believe that the new regulations we are proposing in 
this action would serve the purposes of CAA section 211(o) to increase 
the use of renewable fuel in the transportation sector, would enable 
qualifying renewable electricity to participate in the RFS program, and 
would ensure that all renewable electricity that generates RINs is 
produced from biogas made from qualifying renewable biomass \182\ and 
is used to replace or reduce the quantity of fossil fuel present in a 
transportation fuel, consistent with the statute.
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    \182\ For purposes of this preamble, we use the term 
``qualifying biogas'' to refer to biogas made from renewable biomass 
under an EPA-approved pathway. An EPA-approved pathway is any 
pathway listed in Table 1 to 40 CFR 80.1426 or in a petition 
approved under 40 CFR 80.1416. In Table 1 to 40 CFR 80.1426, Rows Q 
and T contain the currently listed pathways for biogas used as a 
feedstock. Pathways that involve the use of biogas as a feedstock 
approved under 40 CFR 80.1416 are available on our website, 
``Approved Pathways for Renewable Fuel,'' at https://www.epa.gov/renewable-fuel-standard-program/approved-pathways-renewable-fuel.
---------------------------------------------------------------------------

    The RFS program includes a range of biofuels that qualify as 
renewable fuel under the CAA. Consistent with the statutory volume 
targets requiring increasing volumes of renewable fuel to be used for 
transportation in the United States (see section 211(o)(2) generally), 
EPA has promulgated regulatory requirements for each participating 
renewable fuel that are designed to incentivize increased use of that 
fuel. EPA recognized in 2014 that renewable fuels such as CNG/LNG and 
electricity could support this statutory purpose, noting in the 2014 
rulemaking that established RIN-generating frameworks for renewable 
CNG/LNG and electricity that the pathways and programs being added to 
the regulations ``have the potential to provide notable volumes of 
cellulosic biofuel.'' \183\ We also explained that the changes being 
made ``will facilitate the introduction of new renewable fuels under 
the RFS program. By qualifying these new fuel pathways, this rule 
provides opportunities to increase the volume of advanced, low-GHG 
renewable fuels--such as cellulosic biofuels--under the RFS program.'' 
\184\ As a result of the regulatory program that EPA designed and 
implemented for renewable CNG/LNG, volumes of this biofuel increased 
from 32 million ethanol-equivalent gallons in 2014 to 561 million 
ethanol-equivalent gallons in 2021.
---------------------------------------------------------------------------

    \183\ 79 FR 42128 (July 18, 2014).
    \184\ Id.
---------------------------------------------------------------------------

    Thus, this proposal to revise the RFS regulations governing eRIN 
generation is consistent with both the statutory goal of increasing 
volumes of renewable fuels and with the treatment of renewable fuels 
generally under the RFS program. As with other renewable fuels, we 
intend and expect the incentives created by the new regulations 
governing the generation of eRINs to result in increased volumes of 
renewable electricity being used for transportation in the United 
States. We also expect that the incentive to use qualifying renewable 
electricity in electric vehicles would, in turn, incentivize increased 
vehicle electrification that would continue to allow for increased 
generation of qualifying renewable electricity. These ancillary impacts 
are consistent with efforts elsewhere in the federal government to, for 
example, support the ongoing electrification of the vehicle fleet.\185\ 
However, we emphasize that we are proposing this action in order to 
effectuate the determination we made in 2010 that renewable electricity 
can be a qualifying renewable fuel under the RFS program and consistent 
with the program's statutory mandate to increase the amount of 
qualifying renewable fuel used for transportation in the United States.
---------------------------------------------------------------------------

    \185\ See, e.g., Executive Order 14057 (Dec. 8, 2021), which 
sets a target of 100 percent acquisition of zero-emission vehicles 
for federal agencies by 2027, and Executive Order 14037 (August 5, 
2021), which sets a goal that 50 percent of all new passenger cars 
and light-duty trucks sold in 2030 would be zero-emission vehicles, 
including battery electric, plug-in hybrid electric, or fuel cell 
electric vehicles.
---------------------------------------------------------------------------

    In this proposed action we are not reopening the 2010 decision to 
allow for the generation of RINs for renewable electricity if it is 
produced from renewable biomass and can be identified as actually 
having been used as transportation fuel.\186\ Nor are we reopening the 
lifecycle analysis for the 2014 promulgation of RIN-generating pathways 
for renewable electricity in rows Q and T of Table 1 to 40 CFR 80.1426. 
We are also not proposing any new RIN-generating pathways in this 
action. Any comments on the 2010 or 2014 actions, or on potential new 
RIN-generating pathways for eRINs, will be considered beyond the scope 
of this rulemaking.
---------------------------------------------------------------------------

    \186\ See 75 FR 14686 (March 26, 2010).
---------------------------------------------------------------------------

    Our proposed approach, detailed below, would permit vehicle 
original equipment manufacturers (OEMs) to generate eRINs based on the 
light-duty electric vehicles \187\ they sell by establishing contracts 
with parties that produce electricity from qualifying biogas (renewable 
electricity generators). Under this proposal, eRINs would represent the 
quantity of renewable electricity determined to be used by both new and 
previously sold (legacy) light-duty electric vehicles for 
transportation, provided that sufficient renewable electricity has been 
produced and contracted by the OEM.
---------------------------------------------------------------------------

    \187\ For purposes of this preamble, by light-duty vehicle 
(sometimes referred to as light-duty cars and trucks), we mean 
collectively light-duty vehicles and light-duty trucks as defined in 
40 CFR 86.1803-01. By electric vehicle or EV, also for purposes of 
this preamble, we mean collectively electric vehicles and plug-in 
hybrid electric vehicles as defined in 40 CFR 86.1803-01. A light-
duty electric vehicle is a vehicle that is both a light-duty vehicle 
(i.e., light-duty vehicle or light-duty truck) and an electric 
vehicle (i.e., electric vehicle or plug-in electric hybrid vehicle).
---------------------------------------------------------------------------

    We are proposing that qualifying renewable electricity (i.e., 
renewable electricity generated under Row Q or T of Table 1 to 40 CFR 
80.1426) produced and put on a commercial electrical grid serving the 
conterminous U.S. could be contracted for eRIN generation so long as 
the OEM demonstrates that the vehicles it produced have used a 
corresponding quantity of electricity. Under the proposed approach, EPA 
would establish requirements for biogas generators and electricity 
producers, but only an OEM would be allowed to generate the eRIN, 
though the value of the eRIN would be expected to be distributed after 
its generation amongst multiple parties. In this notice, we describe in 
detail our proposed approach and associated design elements and propose 
regulations that would implement the approach. We also describe several 
other alternative approaches to designing the eRIN program and ask for 
comment on those alternatives. The alternative approaches include 
allowing producers of renewable electricity to generate eRINs, allowing 
public access charging stations to generate eRINs, allowing independent 
third parties to generate eRINs, and a number of hybrid approaches that 
would allow multiple parties to generate eRINs. We also considered how 
other programs, like California's Low Carbon Fuel Standard, address 
similar policy goals and challenges.
    This section is divided into multiple subsections. The first two 
subsections provide the context within which our

[[Page 80634]]

proposed eRIN program was developed, including the historical treatment 
of electricity in the RFS program and the unique elements of renewable 
electricity as a qualifying transportation fuel. In subsequent 
subsections we introduce and discuss, among other things:

 Policy goals in developing the eRIN program
 Regulatory goals in developing the eRIN Program
 The proposed applicability of the eRIN program
 The proposed eRIN program structure
 Alternatives to the proposed structure
 Proposed changes to equivalence values
 Proposed compliance and enforcement provisions

    We request comment on all aspects of our proposed eRIN program, 
including elements related to renewable natural gas (RNG) addressed 
separately in Section IX.I and our projections of future eRIN supply 
discussed in Section III.B.1.b.

A. Historical Treatment of Electricity in the RFS Program

1. Statutory Authority and Regulatory History
    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 EPAct2005, 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.'' \188\ 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.\189\ 
This statutory definition of renewable biomass includes separated yard 
waste, separated food waste, animal waste material, and crop residue, 
any of which could be used to produce biogas through anaerobic 
digestion.\190\ Additionally, the statutory definition of advanced 
biofuel codified at CAA section 211(o)(1)(B)(ii)(V) explicitly 
identifies biogas as a valid form of advanced biofuel.
---------------------------------------------------------------------------

    \188\ CAA section 211(o)(1)(J).
    \189\ CAA section 211(o)(1)(I).
    \190\ Biogas was explicitly included in EPAct2005 as a renewable 
fuel at CAA section 211(o)(1)(C)(i)(I)(bb) and therefore was 
included in the RFS1 program that applied from 2006-2009. In the 
2010 rulemaking which established the RFS2 program based on changes 
to 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).
---------------------------------------------------------------------------

    It is important to note that, consistent with the statutory 
definition of renewable fuel provided by EISA, qualifying renewable 
electricity under the RFS program must be generated from a feedstock 
that qualifies as renewable biomass under Clean Air Act Section 
211(o)(1)(I). Unlike some other renewable electricity programs, 
electricity generated from energy sources such as solar, wind, and 
hydropower does not qualify as renewable electricity or renewable fuel 
under the RFS program.
    EPA is required to develop regulations to, inter alia, ``ensure 
that transportation fuel sold or introduced into commerce in the United 
States (except in non-conterminous States or territories), on an annual 
average basis, contains at least the applicable volume of renewable 
fuel, advanced biofuel, cellulosic biofuel, and biomass-based diesel [. 
. .].'' \191\ Congress further required that EPA's regulations provide 
for a credit mechanism under which a person could generate credits and 
use or transfer them for the purpose of achieving the required annual 
volumes of renewable fuels. Although the credit system must provide 
``for the generation of an appropriate amount of credits by any person 
that refines, blends, or imports gasoline that contains a quantity of 
renewable fuel that is greater than'' the statutory volume, as well as 
for the generation of credits for biodiesel and by small 
refineries,\192\ the statute does not limit credit generation to these 
parties, nor does it specify the mechanics of credit generation, 
transfer, or disposition.
---------------------------------------------------------------------------

    \191\ CAA section 211(o)(2)(A)(i).
    \192\ CAA section 211(o)(5).
---------------------------------------------------------------------------

    Finally, EISA required EPA to conduct a study and issue a report to 
Congress on the feasibility of issuing credits under the RFS program 
for renewable electricity used in electric vehicles.\193\ In the 2010 
rulemaking in which EPA promulgated regulations to implement the RFS2 
program, EPA determined that electricity, as well as natural gas and 
propane, could meet the statutory definition of renewable fuel and thus 
be eligible to generate RINs if it was made from renewable biomass and 
if parties could ``identify the specific quantities of their product 
which are actually used as a transportation fuel.'' \194\ In the same 
rulemaking, EPA established a qualifying RIN-generating pathway for 
biogas used as transportation fuel as an advanced biofuel when derived 
from landfills, sewage waste treatment plants, and manure 
digesters.\195\ While EPA did not promulgate a specific pathway for 
renewable electricity at that time, it did establish provisions 
governing the treatment of renewable electricity as well as natural gas 
and propane (i.e., CNG and LNG), provided that those fuels were derived 
from biogas and that specific quantities of the fuels used as 
transportation fuels could be measured.
---------------------------------------------------------------------------

    \193\ Public Law 110-140, 206(b)-(c) (2007).
    \194\ 75 FR 14670, 14686 (March 26, 2010).
    \195\ 75 FR 14670 (March 26, 2010). The CAA includes ``biogas'' 
as one of the types of renewable fuels ``eligible for consideration 
as advanced biofuel.'' CAA section 211(o)(1)(B)(ii).
---------------------------------------------------------------------------

    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.\196\ Inclusion of these new pathways in Table 1 was 
intended to allow for the generation of RINs for renewable electricity 
(along with renewable CNG and renewable LNG) that is used in 
transportation and is produced from a qualifying biogas (i.e., biogas 
that is produced from renewable biomass). Pathway Q allowed for 
cellulosic biofuel RIN generation for renewable electricity 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 
advanced biofuel RINs generation for renewable electricity from biogas 
from waste digesters, which encompasses non-cellulosic biogas. These 
two new pathways were structured so that biogas from approved sources 
would be the feedstock and renewable electricity would be the finished 
fuel for RIN generation purposes.
---------------------------------------------------------------------------

    \196\ 79 FR 42128 (July 18, 2014).
---------------------------------------------------------------------------

    The Pathways II rule also established a set of regulatory 
provisions that detail the criteria necessary for renewable electricity 
to be demonstrated to be renewable fuel and thus eligible to generate 
RINs under two scenarios. First, for electricity that is only 
distributed via a closed, private, non-commercial system, the 
electricity must be produced from renewable biomass under an EPA-
approved pathway and demonstrated to be sold and used as transportation 
fuel.\197\ Under this scenario, only renewable electricity that was 
generated inside a closed transmission network (e.g., an electricity 
generating unit co-located at a landfill)

[[Page 80635]]

where the renewable electricity is directly supplied as transportation 
fuel to EVs could generate RINs.
---------------------------------------------------------------------------

    \197\ 40 CFR 80.1426(f)(10)(i).
---------------------------------------------------------------------------

    The second scenario under which RINs could be generated for 
renewable electricity addresses when electricity is introduced into a 
commercial distribution system (i.e., a transmission grid). In addition 
to the criteria noted above, potential RIN generators under this 
scenario must also demonstrate that the renewable electricity was 
loaded onto and withdrawn from a physically connected transmission 
grid, that the amount of electricity sold as transportation fuel is 
covered by the amount of renewable electricity placed onto the 
transmission grid, and that no other party relied on the renewable 
electricity for the creation of RINs.\198\ These additional 
requirements for electricity transmitted via a transmission grid were 
designed to ensure that the amount of renewable electricity claimed to 
have been used as transportation fuel corresponds with the amount of 
renewable electricity placed onto the transmission grid and that such 
electricity is not double counted for RIN generation. Notably, however, 
the regulations do not specify how or where the quantity of electricity 
is measured, which party is the RIN generator, how a RIN generator 
demonstrates that the electricity was actually used as transportation 
fuel, nor how the RIN generator demonstrates that the electricity is 
not double counted.
---------------------------------------------------------------------------

    \198\ 40 CFR 80.1426(f)(11)(i).
---------------------------------------------------------------------------

2. Need for New Regulations
    Due to the lack of specificity in the current regulations for how 
potential RIN generators would demonstrate that electricity was 
produced from renewable biomass and used as a transportation fuel, the 
registration requests that EPA has received vary considerably in their 
approaches. The main point of variation is the party that would 
generate the eRINs. Suggestions have included:

 Parties that use renewable electricity in a specified fleet of 
EVs (e.g., fleet operators)
 Parties that dispense renewable electricity at public charging 
stations
 Parties that generate renewable electricity from qualifying 
biogas
 Parties that produce the qualifying biogas for renewable 
electricity generation
 Groups of interested EV owners that use renewable electricity 
(e.g., groups representing individual light-duty EV owners)
 EV manufacturers whose vehicles use renewable electricity.

    The existing regulations did not envision this broad range of 
differing approaches to eRIN generation. Registrants must be able to 
demonstrate in their requests that the quantity of eRINs to be 
generated could not be counted by another party \199\ (i.e., the 
regulations prohibit the double counting of RIN generation for the same 
quantity of renewable electricity). Thus, for a given quantity of 
renewable electricity, at most one party--whether it is the renewable 
electricity generator, the utility distributing the electricity, the EV 
owner, the charging station, or the vehicle manufacturer--can generate 
the corresponding eRINs. However, many of the current eRIN registration 
requests use different sources and types of information to verify the 
use of renewable electricity as transportation fuel and therefore 
conflict with one other. Given the wide variety of approaches in 
registration requests submitted to EPA, double counting would be almost 
certain to occur were we to register more than one of the current 
applicants. In other words, to prevent double counting, acceptance of 
any one of these eRIN generation registration requests under the 
existing regulations would necessarily preclude the acceptance of 
others and constrain the ability of the RFS program to grow renewable 
electricity volumes out into the future.
---------------------------------------------------------------------------

    \199\ See 40 CFR 80.1426(f)(11)(F), which states that ``[n]o 
other party relied upon the renewable electricity for the creation 
of RINs.''
---------------------------------------------------------------------------

    In light of this situation, we requested comment on the need for 
regulatory changes related to several foundational eRIN-related topics 
in the 2016 Renewable Enhancement and Growth Support (REGS) proposed 
rule.\200\ We did not propose any amendments to the existing 
regulations governing eRIN generation at 40 CFR 80.1426(f)(10)(i) and 
(11)(i) at that time. Topics on which we requested comment include 
preventing double-counting, eRIN program structure, and the equivalence 
value \201\ for renewable electricity. Below we provide a high-level 
summary of comments EPA received in response to the 2016 notice.
---------------------------------------------------------------------------

    \200\ 81 FR 80828 (November 16, 2016).
    \201\ See Section VIII.I for a discussion of our proposal to 
revise the equivalence value for renewable electricity.
---------------------------------------------------------------------------

    Preventing double counting of RINs is critical to the integrity of 
the RFS program. The credit program EPA established pursuant to Clean 
Air Act 211(o)(5) is the mechanism for ensuring that transportation 
fuel in the United States contains the required volumes of renewable 
fuel; if RINs do not correspond to the appropriate volume of renewable 
fuel, the credit mechanism breaks down. As noted above, because the 
existing eRIN regulations could potentially allow different parties 
using different information to generate RINs for the same volumes of 
renewable electricity, we determined that the existing regulations are 
not sufficient to prevent double counting and we sought comment on this 
issue (i.e., on ways to prevent double counting) in the 2016 REGS 
proposal. However, in general, the public comments we received on the 
REGS proposal focused primarily on eRIN program structure and whether 
EPA should change the equivalence value for renewable electricity. The 
limited public comment on double-counting we did receive focused on the 
fact that EPA could avoid double-counting if EPA would specify, to the 
exclusion of other parties, a specific RIN generator and rely upon a 
single set of information for eRIN generation.
    We received a significant number of comments regarding eRIN program 
structure. This level of response was not unexpected given the 
importance to the stakeholders regarding which entity in the supply 
chain would be regulatorily permitted to act as the RIN generator, and 
which entities would be able to receive revenue from the eRIN. 
Stakeholders from numerous parts of the renewable electricity lifecycle 
(biogas producers, renewable electricity generators, vehicle 
manufacturers, public access charging station operators, etc.) 
submitted comments which indicated they were the most reasonable entity 
to act as the RIN generator. Often these positions were predicated on a 
specific set of data that a particular stakeholder uniquely had access 
to and in their estimation was the most logical data on which to base 
eRIN generation. EPA received suggestions for many different program 
structures, and our review of these comments confirmed that many of the 
recommended structures and existing registration requests were mutually 
exclusive.
    We evaluated the comments received in response to the REGS 
proposal, the registration requests that have been submitted, and the 
additional potential eRIN generation approaches that have been 
suggested to us. In light of the complexity associated with tracking 
valid eRIN generation and qualified use (i.e., transportation use) 
under the RFS program, we have concluded that it is necessary and 
prudent to develop a modified and expanded set of comprehensive 
regulatory provisions to ensure that renewable electricity which 
qualifies under an approved RIN-generating pathways (e.g., Row Q or T) 
is used as transportation fuel, and is not

[[Page 80636]]

double-counted.\202\ We acknowledge that the proposed approach 
contained in this action is only one of many approaches that could be 
established, and that stakeholders have diverse opinions on program 
design. We look forward to further stakeholder input on the proposed 
approach contained herein, the multiple policy and technical questions 
associated with that approach, and alternative regulatory structures 
that could potentially accomplish the same goals.
---------------------------------------------------------------------------

    \202\ As discussed in Section IX.I, we also believe that a new 
set of regulatory provisions is needed for the production, transfer, 
and use of biogas to accommodate a program that allows for multiple 
uses of biogas--as renewable CNG/LNG, to generate renewable 
electricity, and as a biointermediate to produce renewable fuels 
other than renewable CNG/LNG or renewable electricity. The proposed 
allowance for the use of biogas, in the form of RNG, for multiple 
purposes under the RFS program would create an increased risk for 
the multiple counting of the biogas for RIN generation resulting in 
invalid and fraudulent RINs. The proposed biogas regulatory reform 
provisions, discussed in Section IX.I, are designed to work in 
tandem with the eRINs proposal to put in place a cohesive biogas 
program that would minimize the potential for the multiple counting 
of biogas for different uses. The proposed biogas regulatory reform 
provisions are intended to provide the specificity needed to 
streamline the onboarding of potentially hundreds of EGUs producing 
renewable electricity from biogas into the program in a very short 
amount of time. Were we not to finalize the proposed biogas 
regulatory reform provisions discussed in Section IX.I, then we 
would need to put in place additional/different requirements for 
eRINs in order to avoid multiple counting of eRINs.
---------------------------------------------------------------------------

    We understand that some stakeholders who have submitted eRIN 
registration requests take the position that their requests could and 
should be accepted without any further action on the part of EPA to 
modify the applicable regulations. Regardless of whether any one 
registration request meets the regulatory requirements, under the 
existing regulations, EPA very likely cannot approve one request 
without denying all subsequent requests. Such an outcome would be 
contrary to the purpose of the RFS program and thus to broader EPA 
policy and implementation goals. While we acknowledge that it may be 
possible to develop a renewable electricity generation and use a 
business model that could enable registration under the existing 
regulations, it would require that all aspects--from biogas production 
to electrical generation and use in transportation--be carried out on-
site by the same entity. Such a model would result in an overly narrow 
eRIN program that would limit the potential growth of renewable 
electricity. Although it would avoid double counting, it would also 
preclude the development of a more broadly applicable and equitable 
framework for an eRIN program that would be capable of incentivizing 
the full potential volume of renewable electricity used as 
transportation fuel.
    We believe that the policy and regulatory design questions 
confronting the Agency are sufficiently broad and complex that issuing 
new regulations to govern an eRIN program is necessary. We further 
believe that doing so provides maximum transparency into our policy 
development process and offers stakeholders a chance to provide comment 
on and improve our proposed approach.

B. The eRIN Generation and Disposition Chain

    In this subsection, we introduce and briefly discuss a number of 
key concepts and terms that are used throughout our discussion of eRINs 
and our proposed approach for governing their generation. As mentioned 
above, in designing this new eRIN program EPA is able to draw upon its 
experience implementing an RFS program that currently includes both 
liquid and non-liquid fuels. Even with this experience, however, there 
are aspects to the generation and use of renewable electricity in the 
program that are unique, and which raise implementation and design 
questions that we have not addressed before in other parts of the 
program. This subsection is intended to provide descriptions of 
foundational concepts that underlie and/or are used throughout this 
notice, including all the various actors that participate in the eRIN 
value chain. A starting point for this discussion relates to how biogas 
is converted into electricity.
1. Biogas and Renewable Natural Gas
    Under the current RFS program, we broadly define 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.'' \203\ Biogas typically contains a significant 
amount of impurities and inert gases (e.g., carbon dioxide) and must 
undergo pre-treatment before it can be used to generate electricity and 
especially before it can be used as CNG/LNG in vehicles. In order for 
the natural gas commercial pipelines to accept injections of biogas, 
the biogas must first be upgraded to meet pipeline specifications prior 
to injection. This pipeline quality biogas is called renewable natural 
gas (RNG) \204\ and is fungible with fossil-based natural gas. 
Electricity can be produced by combusting treated biogas or RNG; the 
only difference is that the former is not pipeline quality while the 
latter is.
---------------------------------------------------------------------------

    \203\ See 40 CFR 80.1401. 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. 
Also note, as discussed in Section VIII.K, we are proposing to 
modify the definition of biogas consistent with the proposed eRIN 
program and proposed biogas regulatory reform described in Section 
IX.I.
    \204\ For purposes of this preamble, by renewable natural gas or 
RNG, we mean a product derived from biogas that contains at least 90 
percent biomethane content and meets the commercial distribution 
pipeline specification for the pipeline that the biogas is injected 
into. Biomethane is the methane component of biogas and RNG that is 
derived from renewable biomass. Under the current regulations, 
parties generate RINs for the energy, in BTUs, from the biomethane 
content (exclusive of impurities, inert gases often found with 
biomethane in biogas) that is demonstrated to be used as 
transportation fuel.
---------------------------------------------------------------------------

2. Renewable CNG and LNG
    For biogas to be used as renewable CNG/LNG to fuel a vehicle (i.e., 
not used to generate electricity), 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 current regulations,\205\ we require 
that parties demonstrate through contracts and affidavits that a 
specific volume of RNG is used as transportation fuel within the U.S., 
and for no other purpose. RNG that parties can demonstrate via contract 
is used for transportation is often called contracted RNG. Although not 
required by EPA's regulations, typically under the RFS program, in 
order for parties to enter into a contract to help the RIN generator 
demonstrate that a volume of RNG was produced from renewable biomass 
and is used as transportation fuel, that party contracts for a portion 
of the value of the RIN generated for the volume.
---------------------------------------------------------------------------

    \205\ 40 CFR 80.1426(f)(10)(ii), (f)(11)(ii).
---------------------------------------------------------------------------

    We call the chain of parties that are involved in ensuring that 
biogas is produced from renewable biomass and used as transportation 
fuel the generation/disposition chain. For renewable CNG/LNG, this 
chain includes:

 The biogas producer (i.e., the landfill or digester that 
produces the biogas)
 The party that upgrades the biogas into RNG
 The parties that distribute and store the RNG (e.g., 
pipelines)
 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

[[Page 80637]]

produced from renewable biomass and used as renewable CNG/LNG.

    If biogas is directly supplied to an end user via a private 
pipeline, the CNG/LNG generation/disposition 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. Under EPA's current regulations, any party 
in a biogas generation/disposition chain can generate the RINs, but as 
part of this action we are proposing to modify the biogas-to-renewable 
CNG/LNG regulations to specify a particular RIN generator, as discussed 
in detail in Section IX.I.
3. Converting Biogas/RNG to Electricity
    In a majority of situations where biogas is combusted to produce 
electricity, an electricity generation unit (EGU) is collocated with 
the source of the biogas. For example, a landfill operation may have an 
onsite electricity generation unit like a reciprocating internal 
combustion engine or a gas turbine.\206\ In these situations, only a 
relatively minimal amount of gas cleanup is needed prior to combustion. 
In some cases, though, non-collocated electricity generators buy 
contracted RNG. In both cases--onsite generation from biogas, or 
offsite generation from RNG--the generation/disposition chain for the 
electricity includes all the parties in the renewable CNG/LNG chain for 
the production and distribution of the biogas or RNG. As discussed in 
more detail later in this section, however, the chain lengthens 
significantly once the biogas or RNG is converted to electricity.
---------------------------------------------------------------------------

    \206\ For more basic information on landfill gas energy 
projects, for example, see https://www.epa.gov/lmop/basic-information-about-landfill-gas.
---------------------------------------------------------------------------

4. Tracking Renewable Electricity to Transportation Use in the United 
States
    For most fuels under the RFS program, it is unnecessary to track 
the fuel from the point of its production to the point of end-use in 
order to demonstrate that the renewable fuel was actually used as 
transportation fuel. For example, once ethanol is denatured, it is 
reasonably presumed that it will be used as transportation fuel as it 
has no other practical uses.\207\ Similarly, once biodiesel meets 
highway fuel specifications, it is presumed that it will be used as 
transportation fuel.
---------------------------------------------------------------------------

    \207\ The regulations at 40 CFR 80.1401 states that in order for 
ethanol to meet the definition of renewable fuel, the ethanol must 
be denatured under the Department of Treasury's denaturant 
requirements at 27 CFR parts 19 through 21.
---------------------------------------------------------------------------

    This is not the case, however, with RNG injected into a natural gas 
commercial pipeline system, where it is mixed with fossil natural gas. 
In that case, we are unable to assume that the main use of the RNG will 
be for transportation because only a small percentage of natural gas 
used in the United States is used for transportation.\208\ When RNG 
moves through a pipeline system for distribution, the RNG is mixed with 
a much larger proportion of fossil natural gas using the same system. 
The two natural gases--one derived from renewable sources, the other 
from fossil sources--are fungible at that point.
---------------------------------------------------------------------------

    \208\ EIA estimates that in 2020 only about 3 percent of natural 
gas was used for transportation, see https://www.eia.gov/energyexplained/natural-gas/use-of-natural-gas.php.
---------------------------------------------------------------------------

    Consequently, by the time the natural gas is used to fuel a 
vehicle, there is no meaningful way to identify which molecules of 
methane were originally sourced from biogas and which came from fossil 
sources. As discussed above, and in light of this dynamic, when EPA 
introduced RNG as a transportation fuel in the RFS program in the 
Pathways II rule, we set up a system whereby the demonstration that RNG 
was used as transportation fuel relied on accounting protocols, 
recordkeeping requirements, and requirements for contracts and 
affidavits attesting that a specific volume of RNG was used as 
transportation fuel, and for no other purpose.\209\
---------------------------------------------------------------------------

    \209\ See 40 CFR 80.1426(f)(11)(ii).
---------------------------------------------------------------------------

    We face a similar situation with renewable electricity. Like 
natural gas, electricity's main use is for purposes other than 
transportation. Like RNG, the distribution of renewable electricity 
relies on and is fungibly distributed through the same distribution 
system (i.e., the commercial electrical transmission grid) as for non-
renewable electricity. The renewable electricity, once produced, is 
physically impossible to distinguish from non-renewable electricity. 
Whether produced from coal, wind, solar, hydro, natural gas, or biogas, 
and whether produced in California, New York, Canada, or Mexico, once 
electricity is on the commercial electrical transmission grid, it is 
only identifiable as electricity. The electricity that shows up in the 
vehicle's battery is an indistinct commodity. This means that, for any 
eRIN program that involves use of the commercial transmission grid, the 
tracking and verification that a given quantity of renewable 
electricity made from renewable biomass was in fact used as 
transportation fuel can only be done through accounting and records 
management. As with the generation of RINs for RNG, since the relevant 
records and the data on which those records are based exist at 
different locations and are managed by different parties, any eRIN 
program thus will also need to be based on the contractual transfer of 
information between parties.
    There are multiple steps, and multiple actors, involved in the 
process chain from the point at which biogas is produced to the point 
where electricity is used to charge an EV. The actors, whom we will be 
discussing in various parts of this notice, include:

 Biogas producers (e.g., landfills and agricultural digesters)
 Parties that clean up and compress biogas to pipeline-quality 
renewable natural gas (RNG)
 Biogas and RNG distributors (e.g., natural gas pipelines)
 Renewable electricity generators
 Electricity transmission and distribution owners
 EV charging station owners
 Electric vehicle (EV) owners
 Vehicle manufacturers (original equipment manufacturers or 
OEMs)

    Throughout the discussion in this notice, we refer to this process 
chain--from renewable electricity generation through use as a 
transportation fuel--along with all of the actors in that chain, as the 
``eRIN generation/disposition chain.''
    As is discussed throughout this proposal, in order to establish an 
eRIN program that is both consistent with the statutory requirements 
and implementable, information is needed to demonstrate that: (1) 
renewable electricity is being generated from qualifying biogas, and 
(2) that a commensurate amount of electricity is stored in the vehicle 
battery and thus actually used as transportation fuel. However, at 
points in between generation and use, all that is being transported is 
fungible electricity that is neither identifiable as renewable nor 
uniquely used for transportation. Consequently, the critical 
information needed for eRIN generation purposes is from parties on the 
front end where the electricity is produced and on the back end where 
it is consumed. Because the information is often not proprietary (e.g., 
a vehicle owner, vehicle OEM and charge station will all have data on a 
vehicle's charge event, and almost all parties could have records on 
the quantity of electricity used for transportation), there is arguably 
no one single point in the eRIN generation/

[[Page 80638]]

disposition chain, nor one single type of entity within that chain, 
that is clearly more appropriate to designate as the eRIN generator 
than any other from a technical perspective.
    While from a technical perspective there may not be one party 
ideally suited to act as the eRIN generator, from a legal, program 
implementation, and policy perspective there are reasons to propose to 
designate one party in the chain as eligible to generate eRINs in the 
first instance (acknowledging that the RIN value could subsequently be 
shared among different parties). From a legal perspective, we must 
ensure that our choice of the designated eRIN generator is consistent 
with any applicable statutory requirements. From a policy perspective, 
we must ensure that our choice of the designated eRIN generator 
supports the program's ability to address key market constraints to the 
increased use of renewable electricity in transportation: renewable 
electricity production, EV fleet growth, and/or EV charging 
infrastructure. From a program implementation perspective, the nature 
of the eRIN generation/disposition chain also means there are different 
ways that EPA could structure the program to ensure that statutory 
requirements--that qualifying renewable electricity is being used for 
transportation--are met. Although each of the parties described in the 
chain play some role in facilitating the production, distribution, and 
use of renewable electricity produced from qualifying biogas and used 
as transportation fuel, some of them might be considered more critical 
to ensuring that the statutory requirements are met. We sought to 
include elements in our proposed program that we believe could both 
maximally encourage the generation of eRINs and ensure that the eRINs 
are valid. Ultimately, we concluded that the key factors/parties on 
which to focus for the proposal for purposes of program implementation 
are biogas production, renewable electricity generation, and EV fleet 
growth (through OEMs).

C. Policy Goals in Developing the eRIN Program

    Renewable electricity used for transportation has been included in 
the RFS program since 2010; EPA's current task is to develop a revised 
set of regulations governing RIN generation for this renewable fuel. 
EPA's foremost policy goal in developing the proposed eRIN program is 
to support the RFS program's mandate to increase the use of renewable 
fuels, in particular cellulosic biofuels, over time, consistent with 
the statute's focus on growth in this category for years after 2015. 
Moreover, an eRIN program can also support Congress' goals of reducing 
GHGs and increasing energy security,\210\ both of which can be affected 
by the design of that program. We anticipate that increasing renewable 
fuel volumes, in the form of allowing the generation of RINs for 
renewable electricity for use in transportation, will also have the 
ancillary effect of incentivizing increased electrification of the 
vehicle fleet. Where possible and consistent with our statutory 
mandate, we have considered these and other ancillary effects in 
formulating the eRIN program we are proposing in this action. We also 
believe it is critical to take into account the views expressed by 
stakeholders as well as our experience with biogas-derived renewable 
CNG/LNG under the RFS. Each of these goals is discussed below, and the 
discussion of the proposed program that we believe fulfills these goals 
is described in Sections VIII.E and F.
---------------------------------------------------------------------------

    \210\ 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).
---------------------------------------------------------------------------

1. 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. 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. However, as also 
discussed in Section III.B.1, the opportunity for continued growth of 
RNG is expected to be constrained in the future due to the consumption 
capacity of the in-use fleet of CNG/LNG vehicles. As the use of RNG 
saturates the existing in-use fleet, the use of biogas as a feedstock 
for renewable fuel production will be constrained by the much slower 
growth in CNG/LNG fleet sales. At the same time, based on the number of 
existing landfills \211\ and wastewater treatment facilities and the 
potential for significant expansion of anaerobic digesters,\212\ there 
exists significant potential to increase the productive use of biogas 
to produce renewable fuel under the RFS program. By tapping into the 
greater market for that biogas that is and can be converted to 
renewable electricity, the impending constraints on the use of biogas 
as a feedstock for renewable fuel production can be mitigated. 
Specifically, by coupling the existing capacity for electricity 
generation from qualifying biogas with the expansion of EVs in the 
fleet that is already underway, the RFS program can increase renewable 
fuel use in transportation in keeping with the overarching goal of the 
program.
---------------------------------------------------------------------------

    \211\ https://www.epa.gov/lmop/landfill-gas-energy-project-data.
    \212\ https://www.epa.gov/agstar/livestock-anaerobic-digester-database.
---------------------------------------------------------------------------

    The use of renewable electricity from qualifying biogas as 
transportation fuel is also consistent with the statute's focus on 
growth in cellulosic biofuel over other advanced biofuels and 
conventional renewable fuel after 2015.\213\ The existing RIN-
generating pathways in rows Q and T of Table 1 to 40 CFR 80.1426 
provide for the generation of D-code 3 (cellulosic) and D-code 5 
(advanced) RINs, respectively. The determination that biogas from 
landfills, municipal wastewater treatment facility digesters, 
agricultural digesters, and separated MSW digesters; and biogas from 
cellulosic components of biomass processed in other waste digesters is 
predominantly cellulosic was made in the 2014 Pathways II Rule.\214\ In 
that rule, EPA further concluded that:
---------------------------------------------------------------------------

    \213\ 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.
    \214\ 79 FR 42128 (July 18, 2014).
---------------------------------------------------------------------------

     Biogas-based renewable electricity achieved at least a 60 
percent reduction in greenhouse gases relative to gasoline; and
     The majority of the biogas was likely to come from 
cellulosic material in a landfill or digesters that processed 
predominantly cellulosic materials.\215\
---------------------------------------------------------------------------

    \215\ The pathway in Row Q of Table 1 to 80.1426 allows for the 
generation of D3 RINs from renewable CNG/LNG produced from biogas 
from landfills, municipal wastewater treatment facility digesters, 
agricultural digesters, and separated MSW digesters; and biogas from 
the cellulosic components of biomass processed in other waste 
digesters. For purposes of this preamble, a predominantly cellulosic 
material is a feedstock that has an adjusted cellulosic content of 
at least 75 percent.

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[[Page 80639]]

    However, as described in Section VIII.A, because we have not 
registered parties to generate eRINs under the existing regulations, 
biogas use has instead been limited to the CNG/LNG vehicle market under 
the RFS program. Moreover, based on conversations with stakeholders, we 
believe that other factors have also limited the ability of potential 
biogas production facilities from participating in the RFS program: the 
costs of biogas cleanup to the quality needed for injection into common 
carrier pipelines and use in CNG/LNG vehicles can be prohibitive, and 
many existing landfills and digesters are located a significant 
distance from the natural gas commercial pipeline system and cannot 
cost effectively connect. Enabling biogas to be used to generate 
renewable electricity and eRINs under the RFS program would open up not 
only a lower cost option for many biogas production facilities, but 
also enable an even lower GHG-emitting means of using available biogas 
resources for transportation.\216\ Thus, we anticipate that one 
important consequence of this proposal would be to enable a 
substantially increased number of biogas production facilities to 
participate in the RFS program, thus expanding the opportunity for 
biogas to be used as a feedstock to produce a lower GHG-emitting 
renewable fuel.
---------------------------------------------------------------------------

    \216\ Converting the biogas to electricity at the same location 
where the biogas is produced tends to be the lowest GHG and lowest 
cost means of using it for transportation since it avoids the 
additional expense and energy consumption associated with cleaning 
up the gas, transporting it in a pipeline, and compressing/
liquifying it prior to fueling a vehicle.
---------------------------------------------------------------------------

    The renewable electricity generators are an essential component of 
the production and use of renewable electricity as transportation fuel. 
Throughout the development of this proposal, we have heard from many 
stakeholders involved in the production of renewable electricity that 
have spoken about the financial difficulty of building new renewable 
electricity projects and keeping existing projects operational in order 
to increase electricity production. Given that sufficient renewable 
electricity generation is necessary in order to increase available 
volumes of renewable fuel, and in particular cellulosic biofuels, a 
primary consideration for this proposal was creating a mechanism 
through which renewable electricity generators would be provided an 
incentive to participate in the RFS program and increase renewable 
electricity production. We believe that the proposed program described 
in Section VIII.F would, through the eRIN revenue sharing agreements we 
anticipate would be created, significantly increase the participation 
in the program of renewable electricity generators, and thus the 
potential for growth in the production and use of renewable fuel in the 
form of renewable electricity used for transportation.
2. Incentivizing Growth in Renewable Fuel
    Congress designed the RFS program to create incentives for and 
reduce barriers to the increased production and use of renewable fuel 
in the United States. For liquid biofuels, the primary constraints have 
generally been around renewable fuel production and the higher costs of 
renewable fuels relative to petroleum-based fuels; the existing vehicle 
fleet was typically capable of consuming the types and quantities of 
renewable fuels in the blends offered and has therefore not generally 
been a constraint. As a result, EPA's regulatory framework targeted the 
incentive, i.e., the RIN value, at the renewable fuel producers. As 
explained above, existing constraints on certain parts of the renewable 
electricity generation/disposition chain have, to date, limited its 
potential use as transportation fuel in the United States. Thus, 
consistent with our approach to renewable fuels generally under the RFS 
program, in designing this proposed eRINs program one of our goals has 
been to target the eRIN incentive to where it is most likely to 
alleviate existing constraints on the increased use of renewable 
electricity as transportation fuel.
    However, unlike liquid biofuels, electricity is not predominantly 
used as transportation fuel and renewable electricity cannot be 
renewable fuel unless and until it is demonstrated to actually have 
been used for transportation (liquid fuels can generally be assumed to 
be used for transportation once they enter the distribution system). 
This means that in order to address existing constraints on renewable 
electricity that qualifies as renewable fuel, we need to consider and 
incentivize both renewable electricity generation and transportation 
end use.
    First, in order to increase renewable electricity used as renewable 
fuel it is necessary to ensure that adequate renewable electricity 
generation from qualifying biogas exists and will continue to exist 
into the future. Enabling the generation of eRINs under the RFS program 
has the potential to provide an incentive for the renewable electricity 
generation, which in turn directly supports the goal of increasing 
renewable fuel use over time. That is, incentivizing growth in 
renewable electricity is both a natural outcome of including 
electricity in the program and necessary to serve the statutory purpose 
of the RFS program. The renewable electricity market has many 
interrelated components, including the biogas production (e.g., 
landfills and agricultural digesters), biogas and natural gas 
pipelines, the renewable electricity generating units, the electricity 
transmission and distribution grid, EV charge stations, EV 
manufacturing, and EV ownership and use. The design of the eRIN program 
has the ability to direct the incentives to the market components that 
can have the greatest impact on growing the use of renewable 
electricity for transportation purposes. We have heard from 
stakeholders representing almost every segment of this market. In 
general, each party we have heard from that is connected in some way to 
the renewable electricity market believes it is important that they 
either be able to generate the eRIN themselves or at least in some way 
derive some revenue from the eRIN to support investments in their 
component of the renewable electricity market.
    The current RIN-generating pathways for renewable electricity are 
based on biogas production, which has been driven by factors other than 
the RFS program for many years that are likely to continue into the 
future. These factors include the proliferation of landfills and 
wastewater treatment facilities needed to support an expanding 
population, and various types of waste digesters whose biogas can be 
used to comply with the California LCFS program or to provide a new 
source of onsite energy. Enabling value from the eRIN to flow to 
support investment for growth in biogas and to expand the conversion of 
that biogas to renewable electricity (either onsite or offsite) is 
another component of increasing the use of renewable electricity and 
thus of renewable fuel under the RFS program.
    A second significant constraint on increasing renewable electricity 
used as renewable fuel is the composition of the existing vehicle 
fleet. Just as with E15 and E85 compatible vehicles for ethanol and 
natural gas vehicles for RNG, without growth in the vehicle fleet that 
can consume renewable electricity, growth in the use of such 
electricity as renewable fuel will be constrained. In designing an 
eRINs program, it is thus

[[Page 80640]]

also important to consider whether and how it can support increased 
electrification of the transportation sector.
    An eRINs program can help ensure that the increased use of 
renewable fuel is not limited by the size of the EV fleet. Growth in 
renewable electricity used as renewable fuel will depend in part on the 
economic attractiveness of EVs relative to their internal combustion 
engine counterparts. An eRIN program that is designed to meet the 
statutory objective of increasing renewable fuel use should thus allow 
for revenue from eRINs to incentivize activities that can increase 
electrification of the fleet, which could include lowering the cost of 
EVs and/or increasing the availably of public access charging 
infrastructure. From this perspective, enabling value from the eRIN to 
also flow toward EV manufacturers, EV charging stations, or even EV 
consumers would also be appropriate.
    Regardless of the party that generates the eRINs, we believe an 
eRIN program should be designed so that all parties with regulatory 
responsibilities under an eRIN program would benefit under the proposed 
program (i.e., would receive some portion of the value of eRINs). This 
is because, as explained above, qualifying renewable electricity as a 
transportation fuel depends on all parties in the regulatory framework 
having a financial incentive to participate. We expect that the market 
would adjust to apportion the value of eRINs among regulated parties in 
such a way as to ensure that they are all incentivized to increase 
production of qualifying renewable fuel.\217\ Furthermore, regardless 
of the parties that are included in the regulatory framework for eRINs 
and therefore might benefit directly through some portion of the eRIN 
value, we believe that all parties in the value chain would benefit 
from the proposed eRIN program as it encourages renewable fuel growth.
---------------------------------------------------------------------------

    \217\ See further discussion in Section VIII.F.
---------------------------------------------------------------------------

    Different eRIN program design structures can affect which aspect of 
the renewable electricity transportation value chain is most directly 
supported through the eRIN value. The proposed eRIN program structure 
outlined in Section VIII.F is intended to support the increased use of 
renewable fuel though targeted incentives for reducing the cost of EVs 
and the generation of renewable electricity from qualifying biogas. 
However, we acknowledge that other eRIN program structures are possible 
and, in Section VIII.H, discuss alternative eRIN program structures, 
including structures that are more focused on facilitating greater 
access to public access charging infrastructure, which may increase the 
use of renewable electricity as transportation fuel as well. Increasing 
the use of renewable electricity as transportation fuel is a multi-
aspect challenge that is unlikely to be achieved through any singularly 
targeted policy. We are aware that both EV cost and access to public 
access charging infrastructure are important aspects of the challenge 
to increase use of renewable electricity as transportation fuel. That 
said, these are only two such aspects of a broader challenge, and that 
the need to target policy support to address them, may shift over time.
3. Taking Into Account Stakeholder Views and Needs
    In our efforts to develop a functional eRIN program, we have 
identified numerous issues that are often complex and intertwined. 
These issues are evidenced by the disparate approaches presented in the 
registration requests we have received to date for eRIN generation, and 
in other feedback we have received from stakeholders in response to the 
2016 REGS proposal and subsequent annual standard-setting rulemakings. 
There is clear and strong interest on the part of many parties in not 
only having a functional eRIN program as soon as possible, but also in 
ensuring that the program provides incentives to parties at particular 
stages in the eRIN generation/disposition chain. For these and other 
reasons, it is important for us to understand the views of all parties 
that are or could be regulated under the eRIN program. We encourage all 
parties to provide comments on all aspects of our proposed eRIN 
program.

D. Regulatory Goals in Developing the eRIN Program

    In the course of developing the proposed eRIN program, we have 
evaluated and balanced as many factors as possible in order to 
construct a program that would ensure that the statutory requirements 
are met and that all eRINs generated are valid. This section describes 
the importance of ensuring that renewable electricity which can be used 
to comply with the applicable standards under the RFS program is 
generated from qualifying renewable biomass and is used as 
transportation fuel. Relatedly, we also considered how the regulatory 
program could be constructed to ensure that eRINs are not double 
counted and cannot be generated fraudulently. Finally, we discuss the 
regulatory goal of minimizing complexity while ensuring the integrity 
of eRINs. To these ends, we have drawn from experience with existing 
programs such as the current regulations governing biogas-based CNG/LNG 
and California's Low Carbon Fuel Standard (LCFS) program.
    Details of our proposed eRIN program structure which we believe 
meet these goals are presented in Section VIII.F. A discussion of 
alternative program structures that we considered is then provided in 
Section VIII.H.
1. Ensuring That Renewable Electricity Is Produced From Renewable 
Biomass
    Section 211(o)(1)(J) of the Clean Air Act requires that renewable 
fuels that qualify under the RFS program be produced from renewable 
biomass and used as transportation fuel, or, under certain 
circumstances, as heating oil or jet fuel.\218\ Under the existing EPA-
approved pathways, only biogas can be used to generate qualifying 
electricity, and that biogas must be produced from renewable biomass as 
defined in 40 CFR 80.1401. Rows Q and T of Table 1 to 40 CFR 80.1426 
provide additional criteria regarding the biogas production processes 
that have been approved for RIN generation. Under Row Q, renewable 
electricity may be eligible to generate cellulosic (D-code 3) RINs if 
it is produced from biogas from landfills, municipal wastewater 
treatment facility digesters, agricultural digesters, or separated MSW 
digesters; or if it is produced from biogas from the cellulosic 
components of biomass process in other waste digesters. In each of 
these cases, EPA has determined that the feedstocks in the landfill or 
digester that are generating biogas are predominantly cellulosic.\219\ 
Under Row T, renewable electricity may be eligible to generate advanced 
biofuel (D-code 5) RINs if it is produced from biogas from waste 
digesters.\220\
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    \218\ While the Clean Air Act and EPA regulations provide for 
renewable fuels used as a transportation fuel, heating oil, or jet 
fuel, renewable electricity is only available for use as a renewable 
fuel as transportation fuel due to technological, implementation 
and/or regulatory barriers. Therefore, for purposes of this 
preamble, we refer to transportation fuel as the only qualifying use 
of renewable electricity.
    \219\ 79 FR 42128 (July 18, 2014).
    \220\ Ibid.
---------------------------------------------------------------------------

    As mentioned earlier, we are not proposing to reopen the 
determination that renewable electricity made from renewable biomass 
and used as transportation fuel qualifies as renewable fuel, nor the 
renewable electricity pathways in Rows Q and T, and we are not 
proposing any new RIN-generating pathways in this action. However, we 
are proposing a new set of implementation requirements including

[[Page 80641]]

registration, recordkeeping, and reporting requirements for biogas 
producers and renewable electricity generators that would be used to 
demonstrate that electricity that generates eRINs is produced from 
renewable biomass. These new requirements would more robustly ensure 
that biogas producers can demonstrate that their biogas is produced 
from renewable biomass and that they can contract with electricity 
generators for the purchase of such biogas to produce renewable 
electricity. The demonstration that renewable electricity is generated 
from biogas that is, in turn, produced from qualifying renewable 
biomass is the same regardless of the many eRIN program structures 
considered for this proposal. That is, the information collection and 
other requirements pertaining to the demonstration that electricity is 
produced from renewable biomass are largely independent of the other 
eRIN program elements that govern which party(ies) produces, collects, 
and uses that information in order to generate eRINs. Our proposed 
registration, recordkeeping, and reporting requirements are discussed 
in Section VIII.L.
2. Ensuring That Renewable Electricity Is Used as Transportation Fuel
    In addition to being produced from renewable biomass, Clean Air Act 
section 211(o)(1)(J) requires that qualifying renewable electricity be 
used for transportation fuel. For every renewable fuel in the RFS 
program, we have imposed regulatory requirements to help ensure that 
the renewable fuel was used as transportation fuel as required by the 
Clean Air Act. Because each renewable fuel has a different production, 
distribution, and use chain, we tailor our regulatory requirements to 
the specific fuel. For example, for ethanol, we require that the 
ethanol be denatured in accordance with TTB requirements prior to the 
generation of RINs. We imposed this requirement because until the 
ethanol has been denatured, the ethanol could be used for non-
qualifying (i.e., non-transportation) use. After the ethanol has been 
denatured, the denatured ethanol is virtually guaranteed to be used as 
transportation fuel. Similarly, for biodiesel and renewable diesel, we 
require that such fuels must meet specified quality standards needed 
for the fuels to be used in diesel engines. After biodiesel and 
renewable diesel have been demonstrated to meet fuel quality 
specifications, we can be reasonably assured that those fuels will be 
used as transportation fuel. In cases where a biofuel has many 
purposes, making it relatively difficult to show that a fuel will be 
used as transportation fuel and nothing else, we impose additional 
regulatory requirements prior to RIN generation.\221\ For example, in 
the case of natural gas where the majority is used for purposes other 
than transportation, we require that documentation be provided that 
demonstrates that the renewable CNG/LNG produced from biogas was used 
as transportation fuel and for no other purpose.
---------------------------------------------------------------------------

    \221\ See 40 CFR 80.1426(f)(17).
---------------------------------------------------------------------------

    Similar to natural gas, the vast majority of electricity is 
currently used for non-transportation purposes. This fact was discussed 
in the 2010 RFS2 rulemaking where we highlighted the need for 
regulations to ensure that RIN-generating renewable electricity is 
actually used for transportation.\222\ Therefore, in order to ensure 
compliance with the statutory definition of renewable fuel, a 
regulatory framework is needed to ensure that eRINs are generated only 
for the amount of renewable electricity used as transportation fuel.
---------------------------------------------------------------------------

    \222\ See, e.g., 75 FR 14686, 14729 (March 26, 2010).
---------------------------------------------------------------------------

a. Approaches for Quantifying Renewable Electricity Consumption in 
Transportation
    Quantification under an eRIN system must take place both for 
renewable electricity production by EGUs and renewable electricity 
consumption by EVs. The ability to quantify how much electricity is 
used in an EV, and to quantify and verify how much of that can be 
``claimed'' to be renewable electricity generated from qualifying 
biogas, is the foundation for determining how many eRINs may be 
generated, and for ensuring the program is structurally sound. 
Quantifying how much renewable electricity produced from qualifying 
biogas is a relatively straightforward matter, as it is metered when it 
is put on a commercial electrical grid serving the conterminous U.S. 
Quantifying the use of that electricity as transportation fuel, on the 
other hand, presents a more complex challenge. Based on a review of 
approaches used in other programs, like California's LCFS, and on 
approaches suggested to us by stakeholders, EPA considered two general 
approaches for how we could assess the amount of renewable electricity 
consumed in the EV fleet: a ``bottom-up'' and a ``top-down'' approach 
as described below. We acknowledge that both approaches are potentially 
implementable. The choice of which type of approach to use has 
implications for other program considerations discussed throughout this 
section, including implementation complexity, compliance burden, data 
privacy, and prevention of double counting and fraud.
    Broadly speaking, a bottom-up approach would rely on using granular 
levels of data for EV charging events collected at vehicle charge 
stations and/or through vehicle telematics. California's LCFS program, 
discussed in Section VIII.H.5, uses a bottom-up approach to determining 
vehicle consumption data. In developing our proposed approach, we 
investigated several different bottom-up data sources and approaches to 
determining how much electricity is used and in which vehicles. 
Examples of sources EPA could potentially rely on to gather consumption 
data in such an approach include:

 Data from charging stations showing the amount of electricity 
each vehicle used to charge
 Data from onboard vehicle telematics, which records the 
vehicle battery's state of charge
 Dedicated meters added to Electric Vehicle Servicing Equipment 
(EVSE)
 Data loggers added to EVs
 Statistical methods

    By recording, reporting, tracking, and verifying this data one can 
have reasonable assurance in the accuracy of both the individual eRIN 
generation events and the overall eRIN volumes when aggregated. 
However, the many potential sources of error and the sheer quantity of 
millions and eventually billions of individual vehicle charge events 
present a considerable challenge to verifying the authenticity and 
accuracy of the data which would be needed to ensure measured 
quantities actually represented real and/or not double-counted 
quantities of renewable electricity used in transportation. The level 
of effort associated with collecting, reporting and verifying all of 
this information on a continuous basis to support RIN generation at the 
national level would be considerable and affect a number of other 
programmatic design considerations. For example, regulated parties and 
EPA would have to develop mechanisms to store and report the millions 
of charging events in a consistent and implementable way. After such a 
mechanism was developed, procedures by regulated parties, third-party 
auditors, and EPA would have to be developed to ensure that such data 
representing charging events were appropriately utilized in the 
generation of RINs. Because of the sheer volume of

[[Page 80642]]

charging events, errors and duplicative charging events would likely 
result in the almost continuous correction of electricity consumption 
data used for RIN generation in a ``bottom-up'' approach. These changes 
would necessitate specified procedures for dealing with any invalid 
eRINs generated on the erroneous data by the regulated party and by 
EPA. While addressing the volume of data and resulting errors presents 
a significant challenge, we acknowledge that the program could be 
structured in ways to minimize burden (e.g., through targeted audits of 
the data, automated data quality control mechanisms designed into 
information collection systems, or the use of statistical methods to 
estimate and evaluate electricity consumption).
    By contrast, and as further discussed in Section VIII.F, a top-down 
approach would use higher-level, aggregate data on EV fleet electricity 
use to generate consumption measurements. Such an approach would use 
existing data and information to generate overall market average values 
that could be used for eRIN generation. It would rely on the law of 
averages to ensure the overall accuracy of the result and would 
minimize errors associated with individual measurements.
    For example, a top-down approach, rather than requiring granular 
detail on individual charge events, could determine consumption based 
on an equation that includes an OEM's EV fleet population and the 
average electricity consumption of those vehicles. Such an approach 
would be reliant upon an accurate characterization of the population of 
vehicles and the average electricity consumption of those vehicles in 
order to appropriately quantify the electricity consumed each year. A 
key factor, and a potential source of uncertainty for this approach, 
would be ensuring the data used to calculate the average annual energy 
consumption of EVs are in fact representative of what happens in the 
fleet. From a statistical standpoint, the central limit theorem 
dictates that the standard error of the population mean is far less 
than the standard error of any individual sample, suggesting that a 
population approach is more appropriate. Therefore, our use of the 
population-wide, annual average energy consumption of EVs would 
minimize uncertainty. Utilizing the entire electrified vehicle 
population, rather than a sample, also allows us to differentiate 
between the different types of EVs in use, something that would be much 
more challenging if we were to use information on individual charging 
events, which may not have precise data about the different EV types. 
Pairing the population data for vehicle type with vehicle use data 
(average annual energy consumption for BEV and PHEVs) would allow the 
program to appropriately credit average annual electricity consumption 
for each vehicle in the fleet. Within the PHEV category, it can also be 
used to differentiate between the all-electric range of the vehicle and 
the average annual electricity consumed.\223\ Such a top-down approach 
(i.e., based on average, aggregate electricity consumption) could 
provide a robust basis for quantifying the amount of electricity that 
is used in electric vehicles at the scale relevant to a national eRIN 
program. While we acknowledge that the approach may not be as precise 
for individual EV circumstances, it might be more accurate for 
electricity consumption of the national EV fleet and thus more 
appropriately capture renewable fuel use and further the statutory goal 
to increase the use of such fuel over time.
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    \223\ We discuss the differentiation between BEVs and PHEVs 
further in RIA Chapters 1 and 2.
---------------------------------------------------------------------------

    A top-down approach would also lend itself well to addressing a 
number of other important program considerations discussed throughout 
this section, including complexity, compliance burden, data privacy, 
and prevention of double counting and fraud. For example, a top-down 
approach would provide a means for demonstrating the use of electricity 
as transportation fuel without requiring any data that could 
potentially be used to identify individuals or their behaviors.
b. Data Privacy
    The RFS program and its requirements generally apply to companies 
and the facilities those companies own/operate, with individual 
consumers quite removed from the RIN generation process as they simply 
fill up their tanks with renewable fuels (neat or blended) at their 
convenience. That is, for liquid biofuels, the determination that a 
fuel is used for transportation takes place upstream of the actual 
customer. While biogas used as CNG/LNG does require that the 
demonstration of transportation use occur at the fueling station, 
because this fuel is almost exclusively used by private or public fleet 
vehicles, the privacy of individual vehicle owners and users has never 
been a significant concern.
    Electricity is fundamentally different than other renewable fuels 
that participate in the RFS program because individual consumers, in 
particular those charging their EVs at their homes, may be the parties 
that are best able to ultimately demonstrate that electricity is used 
for transportation, as opposed to some other purpose. When we evaluated 
many of the RIN generation structures proposed by stakeholders (e.g., 
public access charging stations, LCFS, and vehicle telematics), it is 
the data associated with the unique charging behavior of individual 
vehicle owners for their vehicles such as charge location, time, and 
quantity that ultimately can be used to demonstrate the quantity of 
electricity used for transportation.
    In the case of charge stations, it may be possible for the station 
owner to submit aggregated charging data that span charging events 
across locations and a specific period of time. However, even in this 
case, individual records with personal identifiable information would 
need to be kept and potentially audited for oversight and compliance 
purposes. In other situations, every unique charging event (including 
personal identifiable information, parameters of the charging event, 
and perhaps location) would need to be submitted so that the 
disaggregation of charge events could be performed. In the case of our 
proposed program, the information regarding vehicle use would be 
handled by the OEMs rather than EPA and would not be used directly for 
RIN generation. The process of how this data is intended to be utilized 
in the RIN generation process is outlined in greater detail in a 
technical memo to this proposal.\224\
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    \224\ Such data privacy concerns are not relevant for the top-
down approach, as discussed further in the technical memorandum, 
``Examples of RIN generation under the proposed RFS eRIN 
provisions,'' available in the docket for this action.
---------------------------------------------------------------------------

    We appreciate the fact that many individuals have concerns about 
information on their location and behaviors being submitted to, and 
retained by, a government agency. We have also heard from stakeholders 
about the challenges and limitations associated with the use of 
Personal Identifying Information (PII) in other programs given the 
existing and expanding constraints placed on the use of PII in state 
laws, including those in LCFS states such as California and Washington. 
They expressed concern that reliance on PII might unnecessarily 
constrain the generation of eRINs and thus the volume of renewable 
electricity that qualifies under the program. In an effort to respect 
these concerns, we believe that the approach we take to ensuring that 
renewable electricity is used as transportation fuel should avoid, to 
the extent possible, the

[[Page 80643]]

collection and use of potentially sensitive, private information such 
as vehicle charging data that identifies a person's location at any 
particular point in time and how they may have been using their 
vehicle. Up to this point, we have been able to design the RFS program 
in a manner that avoids the collection and use of potentially 
sensitive, private information, and we believe it is important to 
continue to do so to the extent practicable.
3. Preventing Double Counting and Fraud
    In order for the RFS program to function, the RIN market must have 
integrity, i.e., 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 been valid, a not 
insignificant quantity of invalid RINs have been generated.\225\ The 
significant value of the RINs, particularly cellulosic RINs, provides 
incentives for fraudulent generation, and complicated renewable fuel 
production and distribution systems provide an opportunity for parties 
who are so inclined. Fraudulent RINs can be generated by parties 
fabricating reports or records to make RINs generated for non-existent 
fuels appear valid. 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. 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.
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    \225\ 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.
---------------------------------------------------------------------------

    As we noted in the REGS proposal, the potential for double counting 
of eRINs is a significant concern due to the potential for double 
counting to undermine the credit system that EPA uses to implement the 
statutory volume requirements under CAA section 211(o). We noted that 
even though the existing regulations prohibit such double 
counting,\226\ we had concerns that those regulations would not enable 
EPA to detect or protect against the double counting of eRINs because 
multiple types of data can be used to demonstrate the use of 
electricity as transportation fuel and some of these data overlap 
across datasets and are not proprietary to one party. For example, 
under the existing regulations, if an EV owner charged their vehicle at 
a public charging station, it is possible that the vehicle owner, 
charging station owner, and vehicle manufacturer would all have 
information documenting the amount of renewable electricity used in 
this single charging event and could all potentially use that data to 
generate eRINs.
---------------------------------------------------------------------------

    \226\ See 40 CFR 80.1426(f)(11)(i)(F).
---------------------------------------------------------------------------

    Because of the similarities between renewable electricity used in 
EVs and RNG used in CNG/LNG vehicles, both of which are not 
predominately used as transportation fuel, double-counting concerns are 
also similar for both. As we have considered ways in which we can 
prevent double counting for renewable electricity, we considered how we 
might also strengthen the regulations to prevent double counting for 
RNG. As with the existing eRINs regulations, under the existing 
regulatory structure for biogas used to produce renewable CNG/LNG, 
parties generating RINs must demonstrate that no other party relied on 
that same volume of biogas, renewable CNG, or renewable LNG to generate 
RINs.\227\ As stated previously, to date we have only approved 
registrations for the use of biogas used in CNG/LNG vehicles, not for 
the use of biogas to generate renewable electricity. However, we have 
concerns that, once we begin approving registration requests for 
renewable electricity, the opportunities for the double counting of 
biogas could increase dramatically. For example, a party may 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 renewable electricity 
generated from the same volume of RNG. We are proposing revisions to 
the regulatory requirements for RNG to prevent such double counting, 
which are presented in Section IX.I.
---------------------------------------------------------------------------

    \227\ See 40 CFR 80.1426(f)(11)(ii)(H).
---------------------------------------------------------------------------

    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 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 infraction. A material quantity 
of invalid RINs would create adverse market effects, as well. 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 electricity. Any viable eRIN program 
design must eliminate, to the extent possible, the ability of parties 
to generate invalid RINs, whether for double-counted renewable 
electricity or for double-counted biogas that is used to generate 
renewable electricity. Doing so could include, for instance, limiting 
the number of parties involved in the generation of a specific quantity 
of eRINs, holding all directly regulated parties in the eRIN 
generation/disposition chain liable for transmitting or using invalid 
RINs, and/or leveraging third-party oversight mechanisms (i.e., third-
party engineering reviews, RFS QAP, and annual attest engagements) to 
help identify, verify, and correct potential issues related to invalid 
RIN generation.
4. Program Complexity and Implementation Burden
    In general, the more complex a regulatory program, the more 
resource-intensive it is for EPA to develop, implement, and oversee 
that program, and likewise the more difficult and resource-intensive it 
is for regulated parties to understand and successfully comply with it. 
Additionally, the more complex the program, the later its effective 
date must be in order to permit sufficient time for registration 
requests to be reviewed and accepted, and for regulated parties to 
establish the necessary compliance mechanisms. Furthermore, the more 
complicated and resource-intensive a new program, the greater the 
disproportionate effect on smaller entities, which often lack the 
resources and expertise to quickly understand and meet the new 
program's requirements. Finally, the more complex the program design, 
the more value is devoted to resources required to administer the 
program throughout the generation/disposition chain. These 
administrative costs have the potential to erode the program's key 
objectives. Therefore, one of our goals in developing the applicable 
regulations for the eRIN program was to minimize implementation burden 
by limiting the complexity of the program to the extent it is 
practicable to do so.
    In the case of eRINs, we anticipate the participation of 
potentially hundreds of biogas-to-electricity projects using a variety 
of feedstocks and electricity generation technologies. These hundreds 
of parties would, in turn, contractually associate with hundreds of 
other parties as necessary to connect

[[Page 80644]]

renewable biomass to biogas production, biogas to electricity 
generation, electricity to transportation use, and transportation use 
to eRIN generation. Given these facts, the complexity of the eRIN 
program could prove prohibitive to implement. A viable program design 
will depend, among other things, on which parties would be required to 
register with EPA and the data, information, and mechanisms parties use 
to demonstrate compliance with the regulatory requirements. The greater 
the number of registrants, the more complex and time consuming it will 
be to register parties to generate eRINs. Furthermore, the greater the 
amount of data and information that must be reported, reviewed, and 
verified, the greater the resource needs and time needed to design and 
implement the compliance oversight systems. Our goal in designing the 
eRIN program is to do so using a regulatory structure that is as 
straightforward as possible and that attempts to minimize undue 
complexity.
    One aspect of program design we have investigated relates to the 
tracking of contractual information. When we implemented the 
requirements for RNG under the current regulations, we did so by 
requiring that contractual relationships between each and every party 
in the distribution system be provided and tracked to enable 
verification of RIN validity. However, we believe that we can design 
the eRIN program to largely avoid a similar level of complexity. In 
particular, while we have requirements in place for biogas under the 
current regulations to track such contractual relationships, we believe 
that they could be largely unnecessary in an eRIN program moving 
forward.\228\ We also investigated ways to minimize program complexity 
by reducing the need for regulated parties to obtain and submit large 
amounts of data to the EPA that track billions of charging events. 
Section VIII.M presents our conclusions regarding these aspects of the 
eRIN program.
---------------------------------------------------------------------------

    \228\ In fact, as discussed in more detail in Section IX.I, we 
are proposing to reform the current biogas regulations in part to 
reduce the burden associated with implementation and oversight.
---------------------------------------------------------------------------

    In addition, we have implemented the current regulatory provisions 
for biogas to renewable CNG/LNG for over eight years and have gleaned 
important lessons from this experience. As described in more detail in 
Section IX.I, the current provisions for biogas-derived renewable CNG/
LNG contain a flexible, but resource-intensive set of regulatory 
provisions that we believe needs to be amended to allow for the use of 
biogas to produce renewable electricity. The two primary issues from 
our experience implementing the biogas to renewable CNG/LNG regulatory 
provisions that we believe should be addressed in an effective eRIN 
program are minimizing program complexity and avoiding double-counting.
    One key determinant of program complexity concerns whether 
regulations permit more than one category of parties to be the RIN 
generator, or whether they designate only one category as eligible to 
generate RINs. To help inform this decision with respect to eRINs, EPA 
reviewed our experience implementing our CNG/LNG program in the RFS, 
where our current regulations allow any party in the biogas CNG/LNG 
generation/disposition chain to generate the RINs. We have concluded 
that while this approach does provide flexibility, it has also resulted 
in a complex program that arguably is overly burdensome for both EPA 
and industry. Under the current regulations, 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 was used as 
transportation fuel in the form of renewable CNG/LNG. These 
demonstrations occur both during registration in the form of voluminous 
registration requests, which can sometimes number over a thousand pages 
of contracts, and on an ongoing basis to support RIN generation in the 
form of contracts and affidavits from each party in the CNG/LNG 
generation/disposition chain to show that the biogas or RNG was used as 
transportation fuel. Because we anticipate that there are hundreds of 
existing biogas-to-electricity projects ready to participate in the 
proposed eRIN on the effective date of the rule, we believe that the 
existing program for biogas to CNG/LNG is likely not the appropriate 
model on which to base an eRIN program that will have many times more 
participating parties and facilities.
    Renewable electricity also qualifies as transportation fuel under 
California LCFS program. We engaged in a number of conversations with 
California Air Resources Board (CARB) staff who developed and 
implemented the LCFS program, along with several companies which 
currently participate in it. These conversations gave us a better 
appreciation for how the LCFS program functions. While the LCFS program 
is governed by different legal requirements and other constraints than 
the RFS program and therefore cannot be used as a direct model for an 
eRIN program under CAA section 211(o), we were able to glean some 
valuable information from LCFS and CARB's experience implementing it 
that has factored into our proposed eRINs approach. Further discussion 
of the LCFS program as a model for eRINs under the RFS program is 
provided in Sections VIII.H.1 and VIII.H.5.a.i.

E. Proposed Applicability of the eRIN Program

    In the sections that follow, we discuss the structure of our 
proposed eRIN program in two parts. This section presents our proposal 
for the program's applicability in terms of the renewable electricity 
for which RIN can be generated, the specific types of electric 
vehicles/engines which we propose would be covered, the geographic 
scope, and the timing for registrations and eRIN generation. 
Subsequently, Section VIII.F describes our proposed approach to eRIN 
generation, including designation of the eRIN generator and details 
regarding how eRIN generation would be quantified.
1. Approved RIN-Generating Pathways for Renewable Electricity
    As discussed in Section VIII.A.1, EPA promulgated pathways for the 
generation of cellulosic (Row Q of Table 1 to 40 CFR 80.1426) and 
advanced (Row T) RINs for renewable electricity produced from biogas in 
the 2014 Pathways II rulemaking.\229\ This proposal is limited to 
revising the regulatory structure for implementation of these existing 
pathways, which we are not revisiting or reopening here. While a number 
of stakeholders have requested that EPA promulgate additional pathways 
for production of renewable electricity from feedstocks other than 
biogas from renewable biomass, we are not doing so in this 
rulemaking.\230\ Thus, at this time, only renewable electricity 
produced from biogas under one of the approved pathways in Rows Q and T 
of Table 1 to 40 CFR 80.1426 would be eligible to generate eRINs under 
our proposed program.\231\ We anticipate promulgating

[[Page 80645]]

additional eRIN pathways in the future and intend to revise the 
regulations to accommodate them as needed.
---------------------------------------------------------------------------

    \229\ 79 FR 42128, July 18, 2014.
    \230\ We reiterate that the promulgation of additional pathways 
is a separate action from promulgation of regulations to implement 
the existing pathways. Any comments on this proposal requesting that 
EPA promulgate additional pathways for the generation of eRINs, 
beyond those already contained in Table 1 to 40 CFR 80.1426, are 
outside the scope of this rulemaking.
    \231\ We note that if we were to finalize the proposed eRINs 
program, eRINs could also be generated under a facility-specific 
pathway for biogas to electricity approved under 40 CFR 80.1416. We 
have not approved any pathways for biogas to electricity under 40 
CFR 80.1416 at the time of this proposal.
---------------------------------------------------------------------------

2. Covered Vehicles and Engines
    As stated earlier, in order to qualify as renewable fuel under the 
Clean Air Act, renewable electricity generated from qualifying 
renewable biomass must be used for transportation. As part of 
developing a proposed program structure, we need to determine what 
qualifies as use for transportation and what data and information are 
then needed to demonstrate it. As explained below, while for some types 
of electric vehicles or engines we believe sufficient data are 
available to demonstrate that the electricity used is renewable fuel 
and quantify such use, we do not believe that is the case for all types 
of electric vehicles or engines at this time. Therefore, we are 
proposing a program under which only renewable electricity used in 
light-duty electric vehicles would be eligible to generate eRINs.
a. Light-Duty Electric Vehicles
    Electrification of light-duty vehicles is relatively far along in 
its development compared to other applications within the 
transportation sector. The significant degree of light-duty 
electrification that has already occurred means that the data and 
information needed to link renewable electricity to transportation use 
are readily available. This information includes data related to real-
world operation of light-duty electric vehicles that can be used to 
determine the amount of electricity used for transportation, including 
average vehicle use patterns and the efficiency of vehicle charging and 
vehicle operation. We discuss the particular vehicle information 
required for our proposed structure in Section VIII.F.5.a. 
Additionally, experience with electrification of light-duty vehicles to 
date has provided an understanding of which parties play what roles in 
the electrification of the vehicle fleet, including who holds what data 
and who is in a position to best ensure that double counting of eRINs 
does not occur.
    As discussed further below, other end-uses within the 
transportation sector are at a considerably more nascent stage in their 
electrification and thus have considerably less data and information 
available. Although the Clean Air Act's definition of renewable fuel 
does not differentiate between renewable fuel used by one vehicle or 
engine type versus another, at this time we do not have sufficient 
information about electricity use in vehicles and engines other than 
light-duty EVs to determine the amount of renewable electricity that is 
used and to ensure that double counting of eRINs will not occur. 
Therefore, we are proposing in this action to limit eRIN generation to 
light-duty EVs. However, we intend to adopt a ``learning by doing'' 
approach for eRINs and anticipate that opportunities for expansion into 
other applications within the transportation sector may materialize as 
the program matures and sufficient information becomes available.
b. Treatment of Legacy Fleet
    We are proposing to allow for the generation of eRINs from 
renewable electricity used in both new light-duty electric vehicles and 
light-duty electric vehicles that are part of the existing fleet (i.e., 
legacy electric vehicles). So long as sufficient data and information 
exist for EPA to ensure that eRINs are generated only for renewable 
electricity that qualifies as renewable fuel, whether that renewable 
fuel is used in legacy or new electric vehicles is not relevant under 
the RFS program. This treatment is consistent with the treatment of 
other renewable fuels used in vehicles and engines under the RFS 
program. For example, the RFS program does not provide any more or less 
credit for ethanol blended into gasoline if the gasoline-ethanol blend 
is used in a model year (MY) 1970 light-duty vehicle or a MY 2022 
light-duty vehicle; each gallon of ethanol can have a RIN generated for 
it regardless of the vehicle the ethanol will ultimately be used in. 
Therefore, consistent with other renewable fuels under the RFS program, 
we are proposing to allow the generation of eRINs for the use of 
renewable electricity in all light-duty EVs inclusive of the legacy 
fleet. We seek comment on this proposal.
    As explained below, our proposal to permit eRINs to be generated 
for both new and legacy light-duty electric vehicles is viable because 
it does not rely on information collected from individual vehicles. For 
further detail, see Section VIII.F for a discussion of our proposed 
approach and Section VIII.H for a discussion of alternative approaches 
that we considered.
c. BEVs and PHEVs
    The term ``electric vehicle'' covers a wide range of types of 
electric vehicles (e.g., mild hybrids, hybrids, plug-in hybrids, and 
battery electric vehicles). However, there are two main types of 
electric vehicles that are potentially eligible to generate eRINs 
because they derive power from the commercial electrical grid serving 
the conterminous U.S. and therefore have the potential to use renewable 
electricity for transportation purposes.\232\ The first, and most 
straightforward, type is full battery electric vehicles (BEVs).\233\ 
Full BEVs only have an electrified drivetrain and rely entirely on 
electricity stored in their battery for all motive power. From a RIN 
accounting perspective, BEVs are relatively simple as it must be the 
case that all miles traveled by BEVs, i.e., all transportation use, is 
reliant upon electricity.
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    \232\ There are other categories of hybrid electric vehicles, 
but generate their electricity onboard the vehicle and do not plug 
into the electric grid.
    \233\ The regulations at 40 CFR 86.1803-01 define this type of 
EV, and we are proposing to use the same definition.
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    The second type of vehicle that is potentially eligible to generate 
eRINs is plug-in hybrid electric vehicles (PHEVs). While PHEVs utilize 
electricity in their onboard battery, they also have an internal 
combustion engine in addition to the battery from which they can source 
motive power. Because of this duality, our proposed structure must 
include a mechanism for parsing the fraction of vehicle miles traveled 
(VMT) powered by electricity (often referred to as eVMT) from the 
fraction of VMT sourced from the internal combustion engine. A 
description of the proposed method used to accomplish this parse, along 
with the data collected to establish the procedure, are discussed in 
DRIA Chapter 6.1.4.
d. Applications Outside the Scope of the Proposed eRIN Program
    As explained above, the eRIN program we are proposing in this 
action would cover only light-duty electric vehicles. We recognize, 
however, that other applications within the transportation sector, 
namely medium-duty and heavy-duty vehicles and nonroad equipment, can 
be electrified. In fact, just as with the light-duty market over the 
past decade, there are rapid advancements being made in electrification 
of these sectors, in particular in the highway medium-duty and heavy-
duty vehicle sectors, where virtually every manufacturer has announced 
plans to commercialize electric vehicles and where early product 
offerings are now available. While we do not believe that it would be 
appropriate to include them in the eRIN program at this time, we intend 
to continue monitoring the electrification of heavy-duty vehicles and 
nonroad equipment and may consider including them in the future.

[[Page 80646]]

i. Medium- and Heavy-Duty Vehicles
    In contrast to light-duty vehicles and trucks, we do not believe we 
have sufficient information and data on electrified medium- and heavy-
duty vehicle production and use to allow for eRIN generation associated 
with such vehicles at this time. The electrified medium- and heavy-duty 
markets are relatively nascent and there are relatively few vehicles 
currently being operated or offered for sale in the marketplace when 
compared to the light-duty vehicle sector.\234\ This results in a 
general lack of data and information which would be needed to develop 
the regulatory program in terms of both ensuring the appropriateness of 
programmatic responsibilities and supporting the eRIN generation 
calculations required to quantify potential RIN generation. At the same 
time, the heavy-duty industry is at the beginning stages of expected 
rapid growth in zero emission vehicle technology, including battery 
electric vehicles, which we expect will help address this general lack 
of data in the coming years, as discussed further below.
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    \234\ https://calstart.org/wp-content/uploads/2022/07/ZIO-ZETs-June-2022-Market-Update.pdf
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    We considered whether the proposed structure for light-duty 
electric vehicles and trucks could simply be extended to the medium- 
and heavy-duty markets. However, we concluded that until the market 
further develops it would not be possible to ensure the same regulatory 
requirements we are proposing for light-duty EVs would be appropriate 
for the future market of medium- and heavy-duty EVs. In the light-duty 
sector, the OEM builds the vehicle and powertrain and then introduces 
the entire vehicle to commerce. This is the pattern that the light-duty 
sector appears to be following as it transitions from internal 
combustion engines to EVs as well. Although this vertical integration 
occasionally exists in the heavy-duty markets, it is not typical at 
present. In the current heavy-duty vehicle market, it is often not 
clear who is the original equipment manufacturer (OEM). The engine, 
chassis, and trailers which together comprise a vehicle are often made 
by different manufacturers. The situation for the medium-duty market is 
often somewhere between that of light-duty and heavy-duty. How the 
medium- and heavy-duty EV markets develop is yet to be determined.
    In addition, given the current low production volume of medium- and 
heavy-duty EVs, the manufacturers have little sales volume over which 
to spread the compliance and implementation burden associated with 
generating eRINs. These manufacturers are initially unlikely to be able 
to cost-effectively comply with or choose to devote the necessary 
resources to the proposed regulatory requirements to generate eRINs, 
e.g., through the hiring of RIN market specialists and other resources 
to fulfill the obligations affiliated with generation and transacting 
of RINs.
    Furthermore, because there are relatively few medium- and heavy-
duty EVs and so little operational data from them it is not yet clear 
how such EVs will be used. Since the fueling, range, and cost-per-mile 
characteristics of medium- and heavy-duty EVs differ from light-duty 
vehicles, it is likely that medium- and heavy-duty EVs will be operated 
differently than their light-duty counterparts. Furthermore, given 
their different use cases, it is also likely that vehicle charging will 
be considerably different. Thus, there simply is not reliable 
information at this time for the medium- and heavy-duty sectors on 
factors such as vehicle miles traveled on electricity, charging 
efficiency, or specific energy consumption on which to base eRIN 
calculations and programmatic design decisions.
    These are not sufficient reasons to propose to exclude medium- and 
heavy-duty vehicles from the eRIN program indefinitely, but we believe 
that they are relevant considerations to exclude them at this time. We 
recognize that the medium- and heavy-duty vehicle industry is at the 
early stages of a major transition to EV technologies, and over the 
next several years we will see a large growth in the range of EV 
product offerings and sales volumes. As this market grows, we will 
reassess the potential inclusion of medium- and heavy-duty electric 
vehicles once the eRIN program is established and more in-use data for 
medium- and heavy-duty electricity vehicles becomes available. For 
example, as a result of financial incentives put in place by the 
Bipartisan Infrastructure Law of 2021, a large number of electric 
school buses are expected to be introduced into the fleet in just the 
next few years. In addition, the Inflation Reduction Act of 2022 
contains many significant incentives for zero emission heavy-duty 
vehicles (including infrastructure, R&D, manufacturing and purchase 
incentives), and we expect the industry and market to respond rapidly 
to take advantage of those incentives. Consequently, we anticipate that 
the same type of data and information that was necessary to propose 
eRIN provisions for the light-duty fleet will soon be available for at 
least the school bus fleet, if not other portions of the medium- and 
heavy-duty market. While we are not proposing a program that will 
include medium- and heavy-duty electric vehicles in this rulemaking, we 
welcome public comment on this proposal, as well as on the data and 
information that would be needed to incorporate them in the future.
ii. Non-Road Vehicles, Engines, and Equipment
    Another component of the transportation sector that already has 
considerable electrification and could experience growth in the future 
is nonroad vehicles, engines, and equipment. However, at this time we 
are proposing to exclude nonroad vehicles, engines, and equipment from 
generating eRINs for both regulatory and policy reasons. As with 
medium-duty and heavy-duty vehicles, at this time there would be 
significant challenges associated with extending an eRIN program to 
nonroad vehicles, engines, and equipment, related in large part due to 
their diversity and the associated difficulty in procuring the 
necessary data. Nonroad vehicles, engines, and equipment include 
everything from small weed trimmers and leaf blowers to airport ground 
equipment to large excavators, all of which have different market 
structures and different use cases for electricity. This makes it 
challenging to ensure we have the data and information necessary to 
develop the regulatory program in terms of both ensuring the 
appropriateness of programmatic responsibilities and creating eRIN 
generation calculations which accurately reflect the use of renewable 
electricity in these engines. In addition, there is some question as to 
whether under the RFS program, off-highway vehicles, engines, and 
equipment with electric motors would meet the definition of nonroad 
vehicles and engines under our regulations at 40 CFR 80.1401 and 
whether fuel used in nonroad vehicles, engines, and equipment is used 
as ``transportation fuel.'' We seek comment on the exclusion of 
renewable electricity used in non-road vehicles, engines, and equipment 
under this proposal.
3. Geographic Scope
    Clean Air Act section 211(o)(2)(A)(i) requires that the RFS program 
``ensure that transportation fuel sold or introduced into commerce in 
the United States (except in non-conterminous States or territories), 
on an annual average basis, contains at least the applicable volume of 
renewable fuel, advanced biofuel, cellulosic biofuel, and

[[Page 80647]]

biomass-based diesel.'' \235\ Thus, under the RFS program generally, 
renewable fuel that is produced in or imported into the 48 continuous 
United States or Hawaii is eligible to generate RINs. Additionally, EPA 
has imposed regulatory requirements to ensure that eligible fuel is 
actually used as transportation fuel in the conterminous 48 states or 
Hawaii.\236\
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    \235\ The Clean Air Act requires that the RFS program apply to 
the conterminous 48 states, and permitted Hawaii, Alaska, and U.S. 
territories to opt in. To date, only Hawaii has opted in. EPA refers 
to conterminous 48 states and Hawaii the ``covered location'' under 
the RFS program (see the definition of ``covered location'' in 40 
CFR 80.1401).
    \236\ Note that for any renewable fuels that are exported from 
the covered location, the exporter of the renewable fuel must 
satisfy an exporter RVO under the regulations at 40 CFR 80.1430.
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    We evaluated the appropriate geographic scope of an eRIN program 
against this statutory backdrop. There are two aspects of geographic 
coverage to consider: the boundaries within which renewable electricity 
generation can occur and where light-duty electric vehicles using that 
electricity must be located. We address the first here. For liquid 
biofuels, this is addressed by focusing primarily on where the 
renewable fuel was produced or imported while accounting for any 
renewable fuel that is exported. However, as discussed in Section 
VIII.B, electricity has some unique characteristics that make 
determining the appropriate geographic scope a challenge, notably, that 
(1) once qualifying renewable electricity is loaded onto the commercial 
electrical grid serving the conterminous U.S. it is indistinguishable 
from non-qualifying electricity, and (2) electricity withdrawn from a 
commercial electrical grid serving the conterminous U.S.as myriad uses, 
most of which are not for transportation. As a result, once renewable 
electricity is loaded onto a commercial electrical grid serving the 
conterminous U.S., it is necessary to rely on a series of contractual 
relationships, rather than direct tracking, to connect renewable 
electricity to transportation end use. We discuss the implications of 
these two factors for the geographic scope of our proposed eRIN program 
in the subsections that follow. See Section VIII.F.4 for further 
explanation.
a. Connection to Grids in the Conterminous United States
    Electricity used by customers in the conterminous United States is 
transmitted primarily via three interconnections--the Eastern, Western 
and, Texas Interconnections; the Eastern Interconnection also extends 
into Canada and the Western Interconnection covers parts of Canada and 
Mexico.\237\ Once renewable electricity generated from qualifying 
biogas is loaded onto a commercial transmission grid that is part of 
one of these Interconnections, it is impossible to distinguish that 
renewable electricity from electricity of any other origin. 
Additionally, given that EVs are not geographically constrained to 
charging on just one Interconnection, it would be arbitrary to limit 
the scope of the eRIN program thusly. We are therefore proposing that 
any electricity that is produced from qualifying biogas and transmitted 
via an interconnection supplying consumers in the conterminous United 
States is eligible to participate in the program (i.e., is eligible to 
be contracted for to generate eRINs). Furthermore, as discussed in 
Section VIII.F.5.a, we are proposing that any EV that is registered by 
a state in the conterminous 48 states be eligible to generate eRINs.
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    \237\ See https://www.energy.gov/oe/services/electricity-policy-coordination-and-implementation/transmission-planning/recovery-act-0.
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    Additionally, as with other renewable fuel production under the RFS 
program, foreign produced renewable electricity could also qualify for 
eRIN generation. As noted above, the interconnections extend beyond 
U.S. borders to Canada and Mexico and electricity is regularly traded 
across these international borders to and from transmission networks 
serving customers in the conterminous United States. Consequently, we 
are proposing that electricity generators using qualifying renewable 
biogas in Canada and Mexico that are capable of establishing bilateral 
contracts with a load serving entity in the conterminous United States 
be allowed to participate in the program. That is, we are proposing 
that electricity generators using qualifying renewable biogas that are 
capable of selling their electricity for use in the conterminous United 
States are eligible to participate. Any foreign producers in Canada or 
Mexico wishing to participate would be subject to the requirements 
described in Section VIII.Q in addition to satisfying the generally 
applicable requirements for participation in the eRIN program as a 
renewable electricity generator. We request comment on whether defining 
the geographic scope of the program to allow electricity generators 
using qualifying biogas in Canada and Mexico that are capable of 
serving the conterminous United States is appropriate. We also request 
comment on alternative approaches to defining the geographic scope of 
the program, including descriptions of how any alternatives are 
consistent with the requirement that RIN-generating renewable fuel be 
produced or imported for use in the conterminous United States (see 
Section VIII.E.3.c below for discussion of Hawaii).
    Under this proposal, renewable electricity produced in other 
foreign countries not meeting the aforementioned criteria would not 
qualify under the program. Unlike other fuels, there is no way to 
import renewable electricity produced in foreign countries into the 
conterminous United States unless they are connected to transmission 
networks serving electricity to customers in the conterminous United 
States. That is, there is no way renewable electricity can be used for 
transportation in the United States unless it is placed on a 
transmission grid that serves U.S. customers. We also seek comment on 
our proposed determination that renewable electricity produced in 
foreign countries, other than renewable electricity produced in the 
circumstances described in the previous paragraph, cannot qualify under 
the program.
b. Hawaii
    While our proposed approach for the conterminous U.S. both allows 
for the connection of renewable electricity generation to 
transportation use and provides for maximum flexibility for the eRIN 
program, the State of Hawaii uses geographically separate electricity 
transmission systems. Therefore, under the proposed approach, it cannot 
be assumed that renewable electricity generated in Hawaii is used to 
charge the U.S. fleet of electric vehicles as a general matter. 
Similarly, it could not be assumed that EVs operated within Hawaii are 
fueled on renewable electricity supplied from qualifying electrical 
generation occurring outside of Hawaii. Consequently, under our 
proposed eRIN program structure, electrified vehicles registered in 
Hawaii would be unable to participate in the proposed eRIN program at 
this time. Similarly, electricity generators in Hawaii would also be 
unable to participate in the proposed eRIN program at this time. While 
we acknowledge that there most likely are both electricity generation 
from qualifying biogas and light-duty electric vehicles in Hawaii and 
that it may be possible to connect the two, at this stage in the eRIN 
program development we believe it would significantly increase the 
implementation burden and program complexity to include

[[Page 80648]]

renewable electricity generated and used as a transportation fuel in 
Hawaii. Due to the increase in implementation burden and program 
complexity, inclusion of Hawaii into the eRIN program could ultimately 
delay the start date of the program.
    We request comment, including data and other information, on these 
limitations and methods by which electrified vehicle and electricity 
generators using qualifying renewable biomass in the state of Hawaii 
could be incorporated into the program. In particular, we request 
comment on the efficacy of setting up a separate parallel program just 
for the state of Hawaii, including whether it would necessitate 
manufacturers to have a separate fleet and records just for Hawaii.
4. Timing and Start Date
    The expansion of the RFS program to include new regulations 
governing the generation of eRINs will result in many new parties 
registering and participating for the first time. The process of 
registering these parties, and of them becoming familiar with and 
complying with the RFS program, will require significant time and 
resources, both for participants and the EPA. Consequently, we do not 
believe that it is realistically feasible for the generation of eRINs 
to be permitted in 2023. Instead, we are proposing to permit eRIN 
generation beginning on January 1, 2024.
    A January 1, 2024 start date would serve a number of important 
purposes. First, it should allow eRIN generation to align temporally 
with the proposed volume requirements, which include a projection of 
eRIN generation. That is, it would be inappropriate for eRIN generation 
to begin in the year prior to or in the year following the year in 
which a projection of eRIN generation is included in the determination 
of the applicable standards. Were eRIN generation to lag the volume 
requirements, there could be a significant shortfall in cellulosic RINs 
which would disrupt the market and could potentially necessitate a 
waiver action. Conversely, were eRIN generation to proceed the volume 
requirements, there could be a significant oversupply of cellulosic 
RINs that would likely depress RIN prices, adversely affecting 
participation. Second, it would allow regulated parties more time to 
get their engineering reviews conducted, register, and develop their 
internal operating and compliance systems to comport with the new 
regulations in an orderly manner thereby avoiding the inevitable 
problems that would otherwise be expected if done in haste. Third, the 
proposed January 1, 2024 start date would allow parties interested in 
participating in the program or impacted by the program more time to 
establish the necessary contractual relationships necessary to 
implement the new program. Fourth, the proposed start date would allow 
EPA time to modify EMTS and evaluate registration requests as they are 
submitted to the agency. Finally, the proposed start date would align 
the start of the program with the existing calendar year structure of 
the RFS program. Based on our experience implementing the RFS program, 
this alignment makes the submission of quarterly and annual reports 
more straightforward and results in a smoother implementation than a 
mid-year effective date because compliance demonstrations under the RFS 
program are built around a compliance period that begins on the first 
day of the calendar year.
    We recognize that some parties believe that EPA could include a 
projection of eRINs in the applicable 2023 standards, and thus permit 
eRINs to be generated in 2023. However, it is highly uncertain whether 
the parties necessary to generate eRINs--biogas producers, renewable 
electricity generators, and OEMs--will be prepared to participate in 
2023. It is also not clear if and how many contracts would be 
established between participants in 2023. As a result, a projection of 
eRIN generation for 2023 in this rulemaking would be considerably less 
accurate than our projections for 2024 and 2025, potentially resulting 
in a substantial oversupply or shortfall in the availability of 
cellulosic RINs with the attendant consequences described above.
    Although we have confidence that at least some parties will be 
registered and contracts established by January 1, 2024, there is a 
significant amount of uncertainty in the number of biogas production 
facilities and renewable electricity generation facilities that will be 
able to arrange for independent third-party engineering reviews and 
establish contractual relationships with eRIN generators to enable RIN 
generation to begin on that date. As noted in DRIA Chapter 6, we 
estimate that there are over 500 landfill-to-electricity projects and 
over 200 digester-to-electricity projects already in operation. A large 
majority of the electricity output from these facilities would be 
needed to meet the electricity demands of the national light-duty EV 
fleet. However, prior to their production being used to generate RINs, 
each of these projects would have to arrange for an independent third-
party professional engineer (PE) to conduct an engineering review. 
Based on the currently anticipated timing for signature and effective 
date of the final rule establishing an eRINs program, industry will 
only have three to four months before the proposed start of the eRIN 
program on January 1, 2024, to conduct engineering reviews, submit 
registration submissions, and make contractual arrangements for eRIN 
generation. As discussed in the DRIA, we estimate that, on average, the 
current pool of PEs conducts around 300 engineering reviews per year. 
Most of these occur in the second half of the year prior to the January 
31 deadline for 3-year registration updates. Because of the overlap 
between eRIN implementation and the typical 3-year registration update 
cycle, the number of PEs needed to both complete the registration 
updates and conduct reviews for the new eRIN participants would need to 
more than double to accommodate the electricity demands of the entire 
national light-duty EV fleet in 2024. Additionally, first-time 
engineering reviews are more difficult than 3-year updates because the 
facility has not previously been visited by a PE and the regulated 
parties (biogas producers and renewable electricity generators) are 
less acquainted with the regulatory requirements. The time and effort 
we anticipate it would take to conduct these reviews would be 
compounded by the fact that because the eRINs regulatory provisions 
would be new, the PEs themselves would not be acquainted with the new 
regulatory requirements, which would increase the amount of time for 
them to complete their reviews. For these reasons, it is highly 
unlikely that industry would be able to develop and submit the 
registration materials needed to register the hundreds of facilities to 
cover all of the electricity used in the light-duty EV fleet at the 
start of the eRIN program.
    We thus believe the volumes of eRINs that will be produced in 2024 
and 2025 will be defined by the pace at which biogas electricity 
facilities will be able to complete their engineering reviews and 
enable eRIN generation. We have projected potential eRIN volumes at the 
start of the program based on how many and when such facilities could 
be registered. Using these estimates, we can estimate the amount of 
eRINs that would be generated for 2024 and 2025 based on reasonable 
assumptions for how quickly facilities could become registered and 
produce qualifying biogas and renewable electricity. The volumes we are 
proposing based upon our assessment are 600 million RINs from renewable 
electricity in 2024 and 1.2

[[Page 80649]]

billion RINs from renewable electricity in 2025. We discuss the 
methodology for these volumes in DRIA Chapter 6, and we seek comment on 
our approach and assumptions. We also seek comment on ways to 
streamline the registration process to increase the number of 
facilities that we are able to bring into the program by January 1, 
2024.
    We also recognize that EPA may need more time to review and accept 
the initial registration submissions for the potentially hundreds of 
new facilities that would be able to participate in the program by 
January 1, 2024. As such, we are considering providing parties wishing 
to participate in the eRIN program additional flexibilities in the case 
where they are able to submit timely registration requests, but EPA is 
unable to accept those requests prior to January 1, 2024, if certain 
conditions are met. We describe this potential flexibility in more 
detail in Section VIII.K.2.

F. Proposed Program Structure for Light-Duty Vehicles

    This section describes the proposed program governing the 
generation of eRINs. The proposed regulations in new subpart E of 40 
CFR part 80 would implement the program as described in this section. 
Topics covered in this section include key participants, identification 
of the party to be the RIN generator, and the requirements for RIN 
generation and program participation. Section VIII.H provides a 
discussion of the alternative program structures that we considered, 
including approaches wherein parties other than the OEM would generate 
the eRINs. We discuss in greater detail the specific regulatory 
requirements in Sections VIII.L through R.
1. Contract-Based Structure for eRIN Program
    As discussed in Section VIII.B, electricity on the commercial 
electrical grid serving the conterminous U.S. is fungible. This fact 
directly informs the proposed eRIN program design to ensure renewable 
electricity is used as transportation fuel. Renewable electricity that 
is generated from qualifying biogas at an EGU is loaded onto a 
commercial electrical grid serving the conterminous U.S. and at that 
point it becomes impossible to distinguish the renewable electricity 
from electricity generated from any non-qualifying energy sources. 
This, in turn, makes it impossible to track the physical renewable 
electricity or to determine its ultimate disposition. Therefore, rather 
than tracking physical quantities of electricity from generation to 
disposition, regulatory and voluntary programs for the use of renewable 
electricity typically use a contractual relationship between a 
generator and end-user (or another party in the electricity value 
chain) as a proxy. Examples of this type of contractual-based program 
relationship include the Renewable Portfolio Standards discussed in 
Section XIII.H.2 and the California LCFS Program discussed in Section 
XIII.H.1.
    As explained previously, the CAA's definition of renewable fuel 
requires that qualifying renewable electricity be both produced from 
renewable biomass and used for transportation. Given the impossibility 
of tracking physical electricity from its point of generation into 
electric vehicles, EPA's proposed eRIN program relies on a contract-
based framework similar to the RFS program's current approach to CNG/
LNG, as well other renewable electricity programs. That is, we are 
proposing to require eRIN generators to demonstrate that the 
electricity used as transportation fuel was produced from renewable 
biomass under an EPA-approved pathway through, among other things, the 
existence of a bilateral contract between the eRIN generator and 
renewable electricity generator. This contract, which we refer to as 
the RIN generation agreement, would establish the exclusive ability of 
the RIN generator to generate RINs for a given quantity of renewable 
electricity produced from qualifying biogas at a renewable electricity 
generation facility. The mechanism of RIN generation agreements would 
ensure that renewable electricity produced from qualifying biogas is 
able to generate RINs only once, and that only one party, in this case 
the eRIN generator, would be able to claim that quantity of renewable 
electricity as transportation fuel.\238\ We believe that, given the 
unique circumstances of electricity used as a transportation fuel, 
relying on RIN generation agreements is a reasonable approach to 
meeting the Clean Air Act's requirement that renewable fuel be produced 
from renewable biomass and used for transportation. As explained above, 
once electricity is loaded on a commercial electrical grid serving the 
conterminous U.S., it is impossible to track specific quantities--
renewable electricity is entirely indistinguishable from fossil-based 
electricity. Thus, any eRIN program that involves the use of a 
commercial electrical grid serving the conterminous U.S. will 
necessarily rely on a contractually based mechanism to satisfy the 
statutory requirements.
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    \238\ We note that under our proposal, RIN generation agreements 
would cover 100 percent of renewable electricity generation for a 
facility except for any electricity generation from the facility 
that is sold outside the RFS program. In other words, our proposal 
would not require that all electricity generated at a facility be 
part of the RFS program, but would rather only allow RIN generation 
for renewable electricity covered by a RIN generation agreement.
---------------------------------------------------------------------------

    We recognize that this type of contractual mechanism would not be 
necessary for an EGU that generates electricity from qualifying biogas 
and distributes it via a closed, private, non-commercial system from 
which EVs are charged.\239\ However, establishing an eRIN program that 
requires a closed, private, non-commercial system would effectively 
limit participation to projects where a biogas-powered EGU is 
collocated with a fleet of EVs (e.g., a municipally owned landfill that 
has a co-located EGU and a dedicated mini-grid that is used to charge a 
fleet of EVs). We anticipate these circumstances would be rare and that 
an eRIN program predicated on this approach would capture only a very 
small portion of potentially qualifying renewable electricity that is 
used for transportation. Given the goal of the RFS program to increase 
the use of renewable fuels and replace or reduce the quantity of fossil 
fuel present in transportation fuel, we do not believe an eRIN program 
that provides credit to a very narrow portion of the potentially 
qualifying renewable fuel serves Congress's purpose. Thus, we believe 
it is reasonable to interpret the definition of renewable fuel in Clean 
Air Act 211(o)(1)(J) to allow eRIN generators to demonstrate that 
renewable electricity is used for transportation through the 
contractually-based framework described in this notice. We request 
comment on this proposed framework for linking renewable electricity 
produced from qualifying biogas to transportation use.
---------------------------------------------------------------------------

    \239\ EPA's existing regulations contain a framework for RIN 
generation for electricity distributed only via a closed, private, 
non-commercial system at 40 CFR 80.1426(f)(10)(i). To date, due to 
the very limited amount of renewable electricity that could be used 
in a closed system, the closed, private, non-commercial system 
approach for eRIN generation has not been the focus of registration 
requests and stakeholder interest for eRIN generation. Instead, 
registration requests and stakeholder interest has focused on the 
use of renewable electricity distributed via a commercial electrical 
grid.
---------------------------------------------------------------------------

2. eRIN Program Participants
    As discussed in Section VIII.B, there is a wide variety of parties 
involved in the eRIN generation/disposition chain, including the biogas 
producer, the biogas and RNG distributors, the

[[Page 80650]]

renewable electricity generator, the electricity transmission and 
distribution owners, the EV owners, charge station owners, and OEMs. As 
a result, there are a variety of options for how to structure a program 
that leverages the incentives provided by eRINs to increase the use of 
renewable electricity in transportation. However, some participants are 
better positioned than others to ensure that biogas used to generate 
renewable electricity is used as transportation fuel in a manner 
consistent with the Clean Air Act and EPA regulatory requirements. We 
sought to include elements in our program that we believed could both 
maximally incent the generation of eRINs and ensure that the eRINs 
represent renewable electricity used as transportation fuel. 
Ultimately, as discussed in VIII.G., we believe the goals described in 
Section VIII.C would best be served by focusing the eRIN program 
requirements on biogas producers, renewable electricity generators, and 
EV manufacturers (OEMs), while relying on other public and private 
efforts to address the activities of other market participants in areas 
such as charging infrastructure and electricity transmission.
    Our proposed eRIN program includes a comprehensive set of 
regulatory requirements for the biogas producers, the renewable 
electricity generators, and the OEMs. We believe that the proposed 
regulation of these three core parties is the bare minimum needed to 
ensure that the eRIN program results in the production of renewable 
electricity produced from biogas and used as transportation fuel in a 
manner consistent with the Clean Air Act. Biogas producers are the 
party best able to demonstrate that biogas was produced from qualifying 
renewable biomass. Renewable electricity generators are the party best 
able to ensure that their electricity is produced in a manner 
consistent with an EPA-approved pathway in Row Q or T in Table 1 to 40 
CFR 80.1426. OEMs, as we discuss in more detail shortly, are the party 
best able, given our programmatic goals and design criteria, to 
demonstrate the amount of renewable electricity used as transportation 
fuel in electric vehicles.
    We expect that these three parties would share, through contracts 
outside of EPA's regulatory regime, the revenue from eRINs, which we 
believe would grow the use of renewable electricity as transportation 
fuel in the coming years. OEMs are heavily invested in the success and 
proliferation of EVs in an increasingly electrified world; many OEMs 
have stated publicly their intention to electrify an ever-growing share 
of their manufactured fleets. For biogas producers and renewable 
electricity generators, the ability to acquire high-value offtake 
agreements from the increased demand for their products would send the 
requisite market signals to ensure continued growth and investment of 
renewable electricity produced from biogas as a transportation fuel, 
thereby supporting the goals of the RFS program.
    We are not proposing to directly regulate other parties in the eRIN 
generation/disposition chain. We believe inclusion of the biogas 
producers, renewable electricity generators, and OEMs in the proposed 
structure would be sufficient to ensure that renewable electricity was 
produced from qualifying biogas and used as transportation fuel. We 
also believe that regulating additional parties, e.g., charging 
infrastructure owners or transmission owners/operations, would be 
unnecessary and would impose a regulatory burden on those additional 
parties for no additional value to the program.
3. eRIN Generator
    Having identified the three core parties, it is necessary to 
designate which party, or parties, will be allowed to act as a 
generator of eRINs. While we believe it may be reasonable to designate 
any one of these parties as the eRIN generator, we are proposing for 
reasons discussed in Section VIII.G that only OEMs be eligible to 
generate eRINs.
    While EPA's regulations could specify that any or any combination 
of these parties as the eRIN generators, we are proposing that only one 
party in the chain serve as the RIN generator. We are proposing only 
one RIN generator because it would allow for us to establish a more-
focused set of regulatory requirements on the core parties in the eRINs 
generation/disposition chain that we believe would reduce program 
complexity and associated implementation burden. As discussed in more 
detail in Section VIII.G and Section IX.I, for biogas to CNG/LNG under 
the existing regulations, we have established regulatory provisions 
that allow for any party in the CNG/LNG generation/disposition chain to 
generate the RINs. In order to allow for any party to generate RINs for 
renewable CNG/LNG, we promulgated a flexible, but resource-intensive 
set of requirements based on the establishment of contracts between all 
parties in the CNG/LNG generation/disposition chain at registration and 
the creation of additional contracts, affidavits, and documentation for 
specific volumes of biogas to demonstrate that the biogas was used as 
transportation fuel. While these regulatory provisions have worked for 
the relatively low number of facilities that we have registered for 
biogas to CNG/LNG under the current regulations, we believe that it is 
not a sustainable model for eRINs which will have several times more 
biogas production facilities and hundreds of additional renewable 
electricity generation facilities than currently included in the RFS 
program. By specifying a single party (i.e., the OEM) as the eRIN 
generator in the eRINs generation/disposition chain, we can only 
require the creation and transfer of the specific information from each 
core party to the eRIN generator and provide certainty over how such 
information is reported, transferred to other parties, and reviewed by 
third parties for verification. This approach would significantly 
streamline what is required for each individual party in the eRINs 
distribution/generation chain and make the program much more 
straightforward for EPA to implement and oversee.
    Our proposed approach would establish a single point for eRIN 
generation which would enable us to ensure the validity of eRINs. As 
discussed in Section VIII.C.6, based on our experience implementing our 
current regulations for RNG under which RINs can be generated by any 
party in the RNG generation/disposition chain, we believe that 
specifying one party as the eRIN generator can help minimize program 
complexity and thereby reduce associated implementation burden for EPA 
and regulated parties. OEMs are uniquely positioned amongst the three 
parties because they are directly invested in the growth of electric 
vehicles. As discussed in DRIA Chapter 6.1.4, the fleet size and growth 
rate of electric vehicles is currently a limiting factor for increasing 
the use of renewable electricity used as renewable fuel. Therefore, to 
achieve the statutory goal of increasing renewable fuel used as 
transportation fuel in United States, it is reasonable that OEMs not 
only be a part of the eRIN generation/disposition chain as discussed 
above, but also be the RIN generator. Given the high level of 
competition among OEMs, we believe that they would have an incentive to 
use the eRIN revenue to lower the purchase price of EVs, thereby 
increasing EV sales and ultimately the penetration of renewable 
electricity into U.S. transportation fuel in support of the primary 
goal of the RFS program to increase the use of renewable fuel in 
transportation.
    Identifying OEMs as the eRIN generator would also have benefits for

[[Page 80651]]

implementation of the program. For instance, the relatively small 
number of OEMs which would need to be registered would simplify the 
program implementation, allowing it to be implemented in 2024. 
Moreover, the OEMs have the staff, resources, background, and expertise 
necessary to take on the compliance oversight responsibilities needed 
to generate eRINs. Unlike many renewable electricity generators and 
charge station owners, even the small number of small business OEMs 
have a long history of complying with EPA regulations. Finally, placing 
the OEMs as the RIN generator allows for a simpler compliance oversight 
design by ensuring that the information needed to carry out an audit to 
verify the validity of RINs is entirely at one location. Additional 
discussion of the ways in which the OEM as the eRIN generator fulfills 
the statutory goal of increasing the supply of qualifying renewable 
electricity used as transportation fuel is provided in Section VIII.G.
4. Overview of Our Proposed eRIN Program
    Having identified biogas producers, renewable electricity 
generators, and light-duty vehicle OEMs as the directly regulated 
parties in the proposed eRIN program, with OEMs being the eRIN 
generator, their roles can be more precisely defined as follows:
    Biogas producers (e.g., landfills, agricultural digesters, and 
wastewater treatment plant digesters) would produce biogas under the 
EPA-approved pathways for biogas to electricity under the RFS program. 
Renewable electricity generators would either use biogas directly 
supplied to their EGUs (e.g., a landfill or digester with an onsite 
EGU) or procure RNG (along with its assigned RIN as proposed in Section 
IX.I) from the natural gas commercial pipeline system to generate 
renewable electricity. The OEMs would determine the electricity 
consumption of their vehicles in the in-use fleet (including legacy and 
new electric vehicles), and acquire through a bilateral contract with 
the renewable electricity generators the exclusive RIN-generating 
ability for the renewable electricity generated by the renewable 
electricity generators, or ``RIN generation agreements,'' that is 
sufficient to cover their fleet's in-use electricity consumption. OEMs 
would then be able to generate the eRINs representing the lesser of the 
quantity of electricity used by their fleets and the renewable 
electricity generated from renewable electricity generator(s) under RIN 
generation agreements. In other words, the OEM could not generate RINs 
beyond the amount of renewable electricity generated by renewable 
electricity generators under their RIN generation agreements. However, 
it could only generate RINs up to the amount of electricity used by its 
fleet. Obligated parties (e.g., refiners, importers, and blenders) 
would purchase cellulosic or advanced eRINs from the OEMs to comply 
with their RVOs just as they purchase RINs from other parties today 
under the RFS program. Each party in this eRIN generation/disposition 
chain would be subject to compliance obligations as described more 
fully in Sections VIII.L through R.
    An important consideration in developing our proposed eRIN program 
was building a program we are capable of implementing in the near term, 
based on our existing implementation capabilities, thus reducing the 
amount of time needed for us and the regulated community to actualize 
the program. Significant deviation from our current capabilities (e.g., 
new information collection systems to collect large amounts of charging 
event data) would require significant additional time to develop and 
deploy such capabilities, further delaying eRIN program implementation. 
We discuss the alternative program structures that we considered in 
Section VIII.H.
5. eRIN Generation
a. OEM RIN Generation Responsibilities
    Under our proposal, OEMs would be responsible for determining the 
quantity of eRINs that they can generate based on the amount of 
renewable electricity produced from qualifying biogas used in light-
duty electric vehicles. To this end, we are proposing to require each 
OEM to submit to the EPA the quantity of light-duty electric vehicles 
they manufactured (BEVs and PHEVs) which are legally registered in a 
state in the conterminous 48 states, and thereby part of the in-use 
fleet each quarter. As part of this submittal, OEMs would be required 
to designate the quantity of both BEVs and PHEVs in their fleet along 
with technical information about the performance characteristics of 
each model in their fleet. We refer to this demonstration as the 
process of the OEM determining their fleet size and disposition for RIN 
generation. It is our understanding that OEMs already have access to 
the necessary information to support this approach, but seek comment on 
the extent to which this is the case.
    Once an OEM has determined its quarterly fleet size and 
disposition, this inventory of registered light-duty electric vehicles 
would be used to calculate the quarterly quantity of electricity used 
as transportation fuel. Using the proposed formulas and prescribed 
factors, the OEM would translate their fleet size and disposition data 
into a quantity of megawatt hours of electricity used by the fleet on a 
quarterly basis.\240\ The prescribed factors being proposed include an 
average EV efficiency value of 0.32 kWh/mi, annual eVMT for BEVs of 
7200 mi/yr, and a formula which calculates the applicable eVMT for 
PHEVs based upon the all-electric range of a given PHEV model. This set 
of prescribed factors facilitates the translation of an OEM's fleet 
size and disposition into the maximum quantity of kilowatt hours 
eligible for eRIN generation. Further explanation of this is provided 
in a memorandum to the docket \241\ and RIA Chapter 6.1.4. We request 
comment on the individual values and the appropriateness of these 
formulas and prescribed factors.
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    \240\ The proposed formulas and prescribed factors for eRIN 
generation are described in the proposed 40 CFR 80.140.
    \241\ U.S. EPA (2022), ``Examples of RIN generation under the 
proposed RFS eRIN provisions.''. Memorandum to Docket No. EPA-HQ-
OAR-2021-0427, November 22, 2022.
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    This set of data for RIN generation represents a top-down approach 
which, as discussed in Section VIII.D.2.b, would have the advantage of 
simply and easily capturing the full amount of renewable electricity 
produced from qualifying biogas used in transportation. More 
specifically, the approach captures the entire in-use fleet (i.e., both 
new electric vehicles and legacy electric vehicles without telematics 
equipment) and all vehicle charging (i.e., both public and private 
charging), thereby providing the maximum amount of and incentive for 
renewable electricity used as renewable transportation fuel under the 
RFS program. The only transportation use data needed to be collected 
and reported for the purpose of RIN generation is the OEM's fleet size 
and disposition.\242\ Consequently, this approach provides minimal 
opportunity for fraud or system gaming, a simple means for EPA to 
provide effective oversight, and would provide EPA with a predictable 
basis for projecting future renewable electricity use.
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    \242\ Additional data collection and reporting requirements are 
proposed as discussed in Section VIII.F.6. below to support 
continual updates of the prescribed factors in the formulae to 
ensure accuracy over the long term.
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    The proposed program differentiates between two types of 
electrified vehicles: full battery electric vehicles (BEVs) and plug-in 
hybrid electric vehicles (PHEVs). All BEVs, which rely

[[Page 80652]]

entirely upon electricity for all vehicle miles travelled, would be 
treated in a uniform fashion for the purposes of calculating their 
renewable electricity consumption. PHEVs, which have both an internal 
combustion engine and an electrified drivetrain, must have the 
electrical fraction of their energy consumption separated from that 
provided by fossil fuels. As described in DRIA Chapter 6.1.4.1, we are 
proposing to use the all-electric range of each unique PHEV model in 
order to determine the fraction of total vehicle miles travelled 
powered by electricity. Further disaggregation among BEVs and PHEVs may 
eventually be possible to improve the precision of RIN generation as 
more light-duty vehicle subsectors become electrified, but the 
available data does not currently allow for this.\243\ See Section 
VIII.F.6 for further discussion regarding OEM vehicle data collection 
and reporting requirements that would be used for future program 
enhancement.
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    \243\ Discussion on current disaggregation of PHEVs and BEVs 
presented in Chapter 6.1.4.1 of DRIA.
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    In order to be able to generate the calculated maximum eRINs for 
its light-duty electric vehicle fleet, we are proposing that each OEM 
would procure a sufficient quantity of renewable electricity under RIN 
generation agreements for which the OEM has the exclusive ability to 
generate RINs.\244\ We anticipate that OEMs would enter into RIN 
generation agreements with renewable electricity generators who in turn 
make the demonstration that the renewable electricity has been 
generated from qualifying renewable biogas. In determining the quantity 
of renewable electricity able to be used as transportation fuel, OEMs 
would be required to account for line losses and the typical charging 
efficiency of electric vehicles. We anticipate that in order for OEMs 
to be able to generate the maximum amount of RINs that they calculated 
using their fleet size and disposition, they would have to contract for 
24.2 percent more qualifying renewable electricity than they anticipate 
would be consumed by the fleet in any given quarter to account for line 
losses (5.3 percent \245\) and charging efficiency (85 percent \246\). 
We request comment on the values selected for line losses and vehicle 
charging efficiency. For more information on this calculation see the 
docket memorandum containing examples of RIN generation,\247\ the 
proposed regulations at 40 CFR 80.140, and DRIA Chapter 6.1.4.
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    \244\ Under our proposal, the renewable electricity could only 
be contracted and used once within the RFS program. However, as 
discussed in Section VIII.F.5.g, it could continue to be used for 
purposes outside of the RFS program under certain conditions (e.g., 
for RECs or LCFS credits).
    \245\ See DRIA Chapter 6.1.4.
    \246\ See DRIA Chapter 6.1.4.3.
    \247\ ``Examples of RIN generation under the proposed RFS eRIN 
provisions,'' available in the docket for this action.
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    We are proposing that RIN generation would occur on a one quarter 
lag from the use of the transportation fuel itself. This lag would 
provide sufficient time for the collection of the requisite fleet size 
and disposition data along with the renewable electricity generation 
data from the renewable electricity generators. Provided that this use 
and procurement data meets the qualifications outlined in the 
regulations, the OEM would be able to generate the maximum quantity of 
RINs calculated for its fleet using the revised equivalence value for 
electricity discussed in Section VIII.I. In instances where the OEM 
fails to procure an adequate quantity of renewable electricity to meet 
the maximum quantity of electricity used as transportation fuel 
calculated for its fleet, RIN generation would be limited to the 
quantity of renewable electricity procured.
b. Renewable Electricity Procurement
    Under our proposed program structure, an OEM would obtain the 
ability to generate RINs by establishing a RIN generation agreement 
with a renewable electricity generator for the total amount of 
qualifying renewable electricity produced at the renewable electricity 
generator's facility.\248\ Renewable electricity generators would 
transmit the information on the renewable electricity they generate 
under the RIN generation agreement to the OEMs, who would then use the 
information to demonstrate that the electricity used by its fleet was 
qualifying renewable fuel and to generate eRINs.
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    \248\ Under this proposal, and for purposes of this preamble, we 
call the ability to generate RINs that an OEM obtains from a 
renewable electricity generator a ``RIN generation agreement.''
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    We envision that the RIN generation agreements would not affect any 
direct purchase agreements between the renewable electricity generator 
and distributors of the renewable electricity. That is, an OEM would be 
procuring permission to generate eRINs representing the quantity of 
qualifying renewable electricity covered by the RIN generation 
agreement, but would not need to own that quantity of renewable 
electricity nor take possession of it. Furthermore, as discussed in 
Section VIII.F.5.g., we do not intend for the sale or transfer of RIN 
generation agreements by the renewable electricity generator to 
preclude them from participation in other state or local programs 
(LCFS, RECs, etc.) premised off of environmental attributes other than 
the demonstration that the electricity was produced from qualifying 
renewable biomass.
    We are also proposing that the vintage of eRINs would be the year 
that the renewable electricity was generated. For example, RINs 
generated to represent renewable electricity generated in December 
2024, would be 2024 RINs. This approach is consistent with RIN 
generation for all other renewable fuels currently under the program. 
For example, RINs generated for denatured fuel ethanol are generated as 
the vintage year of RIN that the denatured fuel ethanol was produced or 
sold, not the year in which it was used as transportation fuel.
    We are proposing to deem the net electrical output (gross 
electrical output, less balance of plant loads) of the renewable 
electricity generated by the renewable electricity generator to be 
eligible to eligible for the generation of eRINs so long as the 
renewable electricity was generated from qualifying biogas and was 
connected to the commercial transmission grid serving the conterminous 
U.S. Under our proposal, it would not matter if the facility where the 
renewable electricity generator is located also consumes electricity 
onsite, impacting the quantity of renewable electricity generation that 
gets placed on the grid. We considered limiting an renewable 
electricity generator's eligible renewable electricity for RIN 
generation to the net amount of renewable electricity production, after 
accounting for use of electricity use at the facility level, as opposed 
to the renewable electricity generator's net electricity production. 
However, in many cases a renewable electricity generator is or could be 
connected directly to a transmission grid with electricity flowing 
fungibly to and from the facility. Therefore, we could not come up with 
a reasonable means of restricting a facility's net renewable 
electricity output. We seek comment on this approach and other 
potential options.
c. Frequency of RIN Generation
    For most renewable fuels in the RFS program, RINs are generated on 
a batch basis in concert with production or sale of the renewable fuel. 
Under the existing regulations, a RIN generator may generate RINs for a 
batch of renewable fuel that represents up to one

[[Page 80653]]

calendar month's worth of production or importation. Within this 
general structure, however, each renewable fuel has adopted different 
approaches for the frequency of RIN generation based on how those 
renewable fuels are produced, distributed, and used. For example, for 
denatured fuel ethanol, ethanol producers typically generate RINs for 
each tanker truck or rail car worth of denatured fuel ethanol. For 
biogas to renewable CNG/LNG, RIN generators generate RINs on a monthly 
basis for the amount of biogas-derived renewable CNG/LNG that the RIN 
generator can demonstrate was used as transportation fuel for that 
month. For RNG specifically, the RNG is demonstrated to have been used 
as transportation fuel when a quantity of gas corresponding to the 
contracted for quantity of RNG is physically withdrawn from the 
pipeline and demonstrated through documentation to have been used as 
transportation fuel. The RIN generation procedure for biogas to 
renewable CNG/LNG is different than for denatured fuel ethanol because 
the regulations require that the RIN generator must demonstrate that a 
volume of biogas has been used as transportation fuel prior to the 
generation of RINs.
    Similarly, in the case of eRINs, as for biogas to renewable CNG/
LNG, we are proposing that before a RIN could be generated, it must 
also be connected to use as transportation fuel. However, unlike biogas 
to renewable CNG/LNG, there is no obvious time period within which this 
occurs as it is the accounting action itself which, in the context of a 
fungible electricity supply, connects the electricity generation to use 
as transportation fuel, not a physical connection. This fact allows for 
a variety of possible time periods for RIN generation. After weighing 
various options, we are proposing that OEMs would generate RINs on a 
quarterly basis. We believe that quarterly RIN generation would allow 
sufficient time for renewable electricity generators to prepare 
information related to that generation for their facilities for 
transmittal to OEMs for RIN generation.
    We considered proposing annual RIN generation, but concluded that 
it would not be appropriate. Even though we believe annual RIN 
generation could provide accurate renewable electricity generation and 
use information, we believe it is important to allow for periodic RIN 
generation throughout the year so that obligated parties could use 
publicly posted RIN generation information to develop compliance 
strategies for the RFS standards. If we only had one annual eRIN 
generation event, the number of eRINs generated would not be known 
until likely the end of February leaving only the month of March for 
obligated parties to obtain and retire the eRINs for compliance. We do 
not believe this is enough time and could cause unnecessary disruptions 
to the generation, transfer, and use of eRINs. Furthermore, annual RIN 
generation would likely delay to an unacceptable degree the flow of 
revenues among market participants, undermining the necessary 
investment needed to grow renewable electricity volumes.
    We also considered proposing monthly RIN generation. Under the 
current provisions for biogas to renewable CNG/LNG, parties that 
generate RINs for biogas do so on a monthly schedule. While we believe 
monthly eRIN generation would provide obligated parties plenty of 
information to develop adequate compliance strategies to meet their 
RVOs, we believe that renewable electricity generators and OEMs may 
have unnecessary burdens associated with this more frequent RIN 
generation. As described in the docket memorandum providing examples of 
eRIN generation, the best information regarding vehicle size and fleet 
disposition is already available on a quarterly basis. If we were to 
make RIN generation more frequent, OEMs would have to convert quarterly 
information to monthly information which may limit the information's 
precision.
    We are also proposing that OEMs would generate the RINs no later 
than 30 days after the end of the quarter. We are proposing this 30-day 
limit to help ensure that RINs are generated in a timely manner. This 
is particularly important after the fourth quarter where annual 
compliance demonstrations for obligated parties are due March 31. We 
believe it is important to provide enough time for the generation, 
transaction, and retirement of RINs, and we believe that 30 days is a 
reasonable time limit for RIN generation. This is consistent with our 
current experience with the biogas to renewable CNG/LNG pathway. Under 
the current biogas to renewable CNG/LNG pathway, most RIN generators 
generate RINs on a monthly basis after they have obtained the 
documentation needed to support RIN generation by the end of the 
following month. We believe that a shorter time period than 30 days 
would likely prove challenging for OEMs to gather all of the necessary 
information for RIN generation.
    We seek comment on our proposed approach for quarterly eRIN 
generation and our allowance for OEMs to generate eRINs 30 days after 
the end of the quarter.
d. eRIN Separation
    Under this proposed eRINs structure, OEMs would separate RINs 
generated for renewable electricity immediately after the RINs were 
generated in EMTS. This process for eRIN separation is consistent with 
the current regulatory text for how RINs are separated for renewable 
electricity.\249\ Under the existing regulations, only after a party 
designates the electricity as transportation fuel and the electricity 
is used as transportation fuel can the party separate the RINs. Because 
the OEM has designated that renewable electricity as transportation 
fuel and demonstrated that it was used as transportation fuel in its EV 
fleet, the OEM would be required to separate the RINs under the 
existing regulations. Under the proposed eRINs program, the OEM would 
only generate the eRIN after it has procured renewable electricity data 
from the renewable electricity generator and demonstrated that the 
renewable electricity was used in its EV fleet. We are therefore not 
proposing to modify the approach for eRIN separation; however, we are 
proposing to modify the regulatory text at 40 CFR 80.1429(b)(5) to 
state more clearly that the party (i.e., the OEM) that generates RINs 
for a batch of renewable electricity under the proposal must separate 
any RINs that have been assigned to that batch.
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    \249\ See 40 CFR 80.1429(b)(5).
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    We seek comment on this approach to RIN separation for eRINs. We 
also note that while we are not proposing to change the basic approach 
to how RINs are separated for renewable electricity, we are proposing 
changes to how RINs are separated for biogas and RNG under the proposed 
biogas regulatory reform provisions discussed in detail in Section 
IX.I.
e. Renewable Electricity Generator Responsibilities
    Under our proposed eRIN program, renewable electricity generators 
would be required to either be directly supplied from a biogas producer 
via a closed, private distribution system, or if the electrical 
generation was from RNG offsite from where the biogas was produced, the 
renewable electricity generator would have to retire RINs assigned to a 
volume of RNG injected into the natural gas commercial pipeline system 
as discussed in the proposed biogas regulatory reform provisions in 
Section IX.I. For renewable electricity generated from biogas supplied 
via a closed, private distribution system, the

[[Page 80654]]

proposed regulations would demonstrate at registration that their EGUs 
were directly supplied with biogas via a closed, private distribution 
system. For RNG converted to renewable electricity at an offsite EGU, 
the renewable electricity generator would retire assigned RINs to the 
RNG as described in Section IX.I, and then generate renewable 
electricity based on the amount of assigned RNG RINs retired. In both 
cases, a renewable electricity generator would identify at registration 
the OEM that entered into the RIN generation agreement for their 
renewable electricity.
    To support the amount of renewable electricity produced from 
qualifying biogas transmitted into the commercial electrical grid 
serving the conterminous U.S., renewable electricity generators would 
submit periodic reports, keep records supporting renewable electricity 
generation, and undergo an annual attest audit.
f. Conditions on Renewable Electricity RIN Generation Agreements
    We are proposing to allow light-duty OEMs to enter into RIN 
generation agreements with multiple renewable electricity generation 
facilities to ensure the procurement of enough renewable electricity to 
cover the electricity use of their light-duty electric vehicle fleet. 
By contrast, we are proposing that each renewable electricity 
generation facility would only be permitted to enter into a RIN 
generation agreement for its renewable electricity to a single OEM. We 
refer to this relationship as ``many-to-one,'' i.e., many renewable 
electricity generation facilities enter into RIN generation agreements 
with one OEM. We believe this limitation would be necessary to ensure 
we would be able to maintain oversight, reduce implementation burden, 
and avoid the double-counting of renewable electricity. If we were to 
allow unlimited contractual transfers between the renewable electricity 
generators and the OEMs, we believe it would be much more likely that 
an amount of renewable electricity would be double counted (i.e., two 
different OEMs generate RINs representing the same quantity of 
renewable electricity) because OEMs would likely be unaware that 
another OEM used that contracted renewable electricity to generate 
RINs.
    Furthermore, while we believe that, in general, OEMs would need 
multiple EGU facilities' worth of renewable electricity to cover their 
vehicle fleet's electricity use, we do not anticipate that the reverse 
would be true. That is, we do not expect that a single renewable 
electricity generator would generate so much electricity that it would 
be in a position to provide enough renewable electricity to more than 
one OEM.
    Similar to the recently finalized biointermediates program, we 
would allow renewable electricity generators to change the contracted 
OEM for a renewable electricity generation facility once per calendar 
year or more frequently subject to our approval. We would expect to 
allow a renewable electricity generator to change their contracted 
electricity for a facility in rare cases where an OEM went out of 
business or a natural disaster disrupted production for an extended 
period of time. Additionally, we expect that under our proposal OEMs 
would likely enter into a RIN generation agreement for renewable 
electricity for a period of time not less than a calendar year, and 
likely longer, in order to create certainty that the OEM could obtain 
enough renewable electricity to generate the full number of RINs for 
their fleet. Therefore, we do not believe that a renewable electricity 
generator would need to change the OEM that they have entered into a 
RIN generation agreement more frequently than once per calendar year.
    We seek comment on this proposed many-to-one limitation for 
renewable electricity generators and on any alternative approaches. 
When providing comments suggesting an alternative, commenters should 
provide information on how such an alternative would allow for proper 
verification and oversight and avoid the double-counting of 
electricity.
g. Interaction With Other Environmental Credit Programs
    The proposed eRIN regulations are designed to prevent the double 
counting of RINs under the RFS program and to ensure that renewable 
electricity for which RINs are generated is used for a single purpose--
transportation fuel within the conterminous United States. However, we 
do not intend the proposed eRIN program to limit or preclude renewable 
electricity generators from participation in other state or local 
programs (e.g., California's LCFS, state renewable portfolio standards, 
etc.) or to also claim environmental benefits under such other programs 
so long as the renewable electricity generator's participation does not 
conflict with the fundamental requirement that qualifying renewable 
fuel be used only once and for the statutorily mandated purpose. This 
is in keeping with our treatment of liquid and gaseous fuels in the RFS 
program--we allow parties to ``stack'' multiple credits for these 
fuels, so long as doing so is consistent with ensuring with the single 
use of a volume of renewable fuel for transportation within the covered 
area.
    Similarly, we are not proposing to limit the ability of renewable 
electricity generators to stack credits for renewable electricity 
generation, when and where appropriate. For instance, a renewable 
electricity generator located in a state with a renewable portfolio 
standard (RPS) that allows for renewable electricity credits (RECs) for 
biogas generated electricity may continue to generate RECs in addition 
to entering into RIN generation agreements so long as the applicable 
state's RPS does not place prohibitions on this activity. Furthermore, 
this proposal does not intend to disrupt or otherwise preclude the use 
of any other federal, state, or foreign government incentives for 
certain types of electricity generation in the form of either 
investment tax credits or production tax credits for which a renewable 
electricity generator may be eligible. However, in order to ensure that 
the statutory requirements of the RFS program are met, the qualifying 
renewable electricity may only be designated for a single use: 
transportation fuel within the conterminous United States. We believe 
that this proposed approach is necessary to ensure the integrity of the 
RFS program and to ensure that the environmental benefits associated 
with a given quantity of qualifying renewable electricity are not 
assumed to accrue more than once under the RFS program. We request 
comment on this proposed approach for the interaction of the eRIN 
program with other environmental credit programs.
h. Conditions on Electrical Generation Feedstocks
    In order to ensure that the renewable electricity for which OEMs 
contract under RIN generation agreements is actually from electricity 
generated from renewable biomass, we are proposing that renewable 
electricity generators that generate electricity onsite from raw biogas 
may only generate renewable electricity for eRIN generation if 100 
percent of the feedstock they use to generate electricity is qualifying 
biogas during any given month.
    We are proposing this limitation because raw biogas can have 
significantly different conversation rates to electricity than fossil-
based natural gas. Furthermore, these conversion rates can vary 
significantly due to the configuration and operating conditions of the 
EGUs. We acknowledge that in some instances a renewable electricity 
generator that uses raw biogas as a feedstock may wish to generate

[[Page 80655]]

electricity using a variety of feedstocks. However, in order to ensure 
that RINs are only generated for renewable electricity produced from 
qualifying biogas and to minimize program complexity, we believe it is 
most straightforward to only allow for RIN generation for renewable 
electricity generation when 100 percent of the feedstock is qualifying 
biogas. Were we to allow for the co-generation of electricity from 
qualifying biogas and non-qualifying feedstocks, we would have to 
impose additional regulatory requirements on the renewable electricity 
generator to ensure that only the portion of the electricity generation 
that came from qualifying biogas generates eRINs. These additional 
regulatory requirements would likely include additional information 
submitted at registration to determine the types of feedstocks used, 
the rates that these feeds are converted to electricity, and a detailed 
description of how the renewable electricity generator would determine 
the portion of electricity attributable to qualifying biogas. We would 
also likely need to require additional ongoing reporting and 
recordkeeping requirements to ensure that the amount of renewable 
electricity generated from qualifying biogas is accurate as well as 
require participation in the RFS QAP program to verify it. We believe 
these additional regulatory requirements would significantly increase 
the complexity of the program, which would significantly increase the 
amount of time and burden needed for renewable electricity generators 
to participate in the program, and EPA to implement and oversee the 
program.\250\
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    \250\ This proposed provision would not apply to renewable 
electricity generated offsite from RNG because we believe that 
determining the amount of renewable electricity generated from 
contracted RNG is much more straightforward. Because RNG is 
indistinguishable from fossil-based natural gas (i.e., would be 
converted to electricity at the same rates in the same facility), 
the amount of renewable electricity generated is simply the 
proportion of feed that was RNG multiplied by the volume of 
electricity generated by the facility.
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    We also do not believe this proposed restriction would impose much 
burden on most of the renewable electricity generation facilities that 
use biogas as a feedstock. We expect these facilities to be located 
away from the commercial natural gas pipeline system and as such these 
facilities tend to operate using 100 percent qualifying biogas during 
typical operation. These facilities would only tend to operate on non-
qualifying biogas during startup operations which is a small portion of 
the time.
    Nevertheless, we seek comment on methods to determine the fraction 
of qualifying biogas used when non-qualifying biogas feeds are co-
processed or whether there are ways to minimize the affected amount of 
renewable electricity.
    We are not proposing to limit the co-processing of RNG with fossil-
based natural gas because determining the amount of renewable 
electricity in this circumstance is straightforward. The renewable 
electricity generator combusting the two feedstocks would know the 
portion of the total fuel that is RNG based on the quantity of RNG it 
has purchased with attached RINs. Thus, in cases where RNG is co-
processed with fossil-based natural gas, due to the fungibility of 
these two feedstocks, the amount of renewable electricity generated is 
simply the fraction of the feedstock that is RNG multiplied by the 
amount of electricity generated by the renewable electricity generator 
over a period of time. For purposes of this proposal, the period of 
time would be on a monthly basis.
i. Biogas Producer Responsibilities
    Under our proposal, biogas producers would need to register their 
biogas production facilities (i.e., landfills or digesters) with EPA, 
submit periodic reports to EPA for the qualifying biogas they produce, 
keep records that demonstrate that they produced qualifying biogas, 
generate and transfer PTDs for biogas transfers, and undergo an annual 
attest audit. We have used similar provisions for biointermediate and 
renewable fuel producers who also convert renewable biomass into 
products that are either renewable fuels or used to produce renewable 
fuels. We discuss these proposed requirements in more detail in Section 
VIII.J-Q.
    To minimize program complexity and avoid the double-counting of 
biogas, we are also proposing provisions to govern how biogas producers 
supply biogas to renewable electricity generators. Under this proposal, 
biogas producers supplying biogas via a closed system to renewable 
electricity generators would be limited to supplying a single renewable 
electricity generator participating in the RFS program. We understand 
that in real-world applications there may often not be a perfect match 
between biogas production capacity and the quantity of biogas which can 
be consumed for electricity generation. In such instances, we want to 
allow the biogas producers to flare the excess gas or find an 
alternative productive use. However, in order to minimize program 
complexity and to safeguard against potential double counting, limiting 
the biogas producer to supplying only a single renewable electricity 
generator serves this goal by not allowing the opportunity for double-
counting in the first place. We seek comment on the proposal to place 
limitations on biogas producers that supply biogas to onsite 
electricity generation.
    In the case of biogas supplied for RNG that is later turned into 
renewable electricity at an offsite renewable electricity generation 
facility, this biogas and RNG would be covered under the proposed RNG 
provisions discussed in Section IX.I. Participation in the biogas-to-
RNG program, as we have proposed to revise it, will ensure that RNG 
that is used to generate renewable electricity is produced from 
renewable biomass and that any RINs generated for the production of RNG 
are properly retired upon use of the RNG to generate electricity.
j. Third Parties
    We use the term ``third parties'' to informally categorize those 
entities that might participate in a regulatory program but who are not 
directly regulated (e.g., they are not required to keep records or 
register with EPA). Third parties currently play a role in the RFS 
program for all types of renewable fuel in the program. For example, 
several third parties participate in the RFS in the CNG/LNG space. In 
that context, many small parties are directly involved in the 
production, distribution, and use of biogas, RNG, and CNG/LNG. Under 
our current regulations, there is no one single designated RIN 
generator--multiple parties are able to register as a RIN generator--
and third parties play a role in coordinating the various parties to 
ensure EPA's regulatory requirements are satisfied and, in many cases, 
act as a RIN generator themselves. (We note that we are proposing 
changes to the CNG/LNG regulations under RFS; see Section IX.I for 
details).
    By contrast, for our proposed eRIN program, the proposed 
regulations state that only a manufacturer of light-duty cars and 
trucks (i.e., the OEMs) may generate RINs. As discussed in Section 
VIII.F.2, the proposed program also only designates--directly 
regulates--three types of entities: biogas producers, renewable 
electricity generators, and OEMs. Under this proposal, we are not 
designating third parties, i.e., parties that do not directly 
participate in the production of biogas, RNG, or renewable electricity 
or the use of renewable electricity as transportation fuel, as a 
regulated party with responsibilities associated with eRIN generation. 
An example of a third party that might participate in the eRIN program 
is an

[[Page 80656]]

entity that assists other parties (e.g., an OEM) with securing 
contracts for renewable electricity generation.
    Based on our experience with CNG/LNG, and from stakeholders' 
experience in California's LCFS program, we recognize that third 
parties would likely serve a useful role in supporting regulated 
parties in brokering and trading biogas, RNG, renewable electricity, 
and the associated RIN generation agreements under the proposed eRIN 
program. We also believe that biogas producers, renewable electricity 
generators, and OEMs would likely contract with third parties to help 
them comply with the proposed regulatory requirements by preparing and 
submitting registration requests and periodic reports. However, 
consistent with the discussion in Section VIII.F.2, we believe that the 
direct participation of each of the three key parties is necessary in 
order to ensure that renewable electricity is produced from qualifying 
biogas and used as transportation fuel in a manner that EPA could 
reasonably implement and oversee. For example, we think it is important 
that the OEM remains the responsible party to generate the eRIN, even 
if the OEM contracts with a third party to do much or all of the work 
associated with securing contracts for renewable electricity.
    Allowing a third party to assume liability for one or more of these 
key parties would add an additional complication and removes the 
necessary information, whether it be on renewable biomass, qualifying 
biogas, renewable electricity, or transportation use, from direct EPA 
oversight. Further, we believe that our proposed approach best balances 
our design considerations to regulate only the parties that participate 
directly in the eRIN generation/disposition chain and leave it to the 
market to determine how best to engage the services of third parties.
    Although we are not proposing a direct regulatory role for third 
parties in our eRIN program, we seek comment on whether and how they 
could play such a role. We also seek comment on other ways in which 
third parties may participate in the proposed program.
6. Data Collection for Program Verification and Future Enhancement
    Our proposed eRIN program contains RIN generation equations which 
use electric vehicle fleet size and disposition data from the OEMs 
along with prescribed factors for the average EV behavior across the 
fleet population. The set of prescribed factors proposed in this 
package would allow for RIN generation at the onset of the eRIN 
program. However, the EV fleet is continuing to evolve, and we would 
expect these prescribed factors to evolve with them. In order to 
improve the precision and accuracy of eRIN generation as the fleet 
changes over time, we are proposing that OEMs submit data on vehicle 
efficiency, EV use, and charging efficiency by vehicle make and model 
for all the electrified vehicle models in service.\251\ We discuss each 
of these in more detail below. This process of updating to reflect the 
latest information would ensure that eRIN generation calculations 
remain accurate while still enabling the streamlined, efficient program 
described above in Section VIII.F.5.a. These data could also enable us 
to update the transportation fuel consumption formulas in future 
rulemaking actions to better match the characteristics of the in-use EV 
fleet as it changes over time, allowing for more accurate and precise 
eRIN generation and differentiation among OEM fleets. For example, it 
could enable additional differentiation within the BEV and PHEV 
categories.
---------------------------------------------------------------------------

    \251\ Exceptions to this requirement may be made in instances 
where the model is a legacy production and not equipped with onboard 
telematics necessary for data collection.
---------------------------------------------------------------------------

a. Vehicle Efficiency
    For the in-use efficiency of EV factor (represented as the fuel 
economy term) in the formula in the regulations as discussed in Section 
VIII.F.5 above, we used average values that were adopted from EPA 
certification testing as this was the best data available. 
Certification testing data captures the differences between vehicles 
over the typical operating conditions and therefore should provide a 
reasonable estimate. Nevertheless, certification testing data may not 
fully capture the full range of operation of EVs that may ultimately be 
important to accurately quantify the efficiency of all EVs (e.g., cold 
temperature conditions in the winter). Consequently, it would be better 
if we could base this term on actual in-use operation data of EVs, and 
as such we are proposing that the OEMs provide us with in-use vehicle 
efficiency (kWh/mi) by vehicle make and model for all the electrified 
vehicle models in service.
b. Electrified Vehicle Use
    The second key data area which we are proposing to collect from 
OEMs participating in the eRIN program relates to the frequency of EV 
use. In DRIA Chapter 6.1.4, we discuss the use of vehicle miles 
traveled on electricity (eVMT) as part of the method by which we 
calculate the amount of electricity used as transportation fuel. In 
that discussion we reference and discuss the most recent available data 
on eVMT for both BEVs and PHEVs. While we believe that the currently 
available eVMT estimates are reasonable, they are also drawn from a 
limited data set. Furthermore, in the rapidly evolving EV market 
segment, consumer driving behaviors that would impact eVMT are also 
rapidly evolving. Consequently, it is important that we have a means of 
accurately capturing and updating our eVMT term in the formulas based 
on the in-use driving behaviors of typical BEV or PHEV owners. To 
address this need, we are proposing to collect eVMT data or recorded 
charging information by make and model from OEMs participating in the 
eRIN program. These data would both help verify the proposed RIN 
generation equations as well as provide a basis for ongoing program 
improvement. We appreciate that collecting eVMT information for BEVs is 
comparatively straightforward (simply annual VMT because all miles 
traveled are on electric power) relative to PHEVs which switch between 
powertrain modes depending upon power demands and battery state of 
charge. Consequently, because of the difficulties in measuring eVMT for 
PHEVs, we are proposing to allow the submission of either eVMT or 
recorded charging information by vehicle make and model. We request 
comment on feasibility and appropriateness of this data submittal 
requirement.
c. Charging Efficiency
    In our proposed eRIN program, charging efficiency is an important 
parameter in two instances. In the first instance, charging efficiency 
is an important term in the formula that determines the quantity of 
electricity that OEMs must procure from EGUs in order to cover the 
transportation fuel demand of their fleets. Charging efficiency is 
simply a measure of the fraction of electricity lost to parasitic loads 
(heat, etc.) during the charging of the vehicle battery. We take 
account of charging efficiency to capture inefficiencies in the energy 
transfer processes and to ensure that the full amount of electricity 
used by electric vehicles is covered by qualifying renewable 
electricity.\252\ The second instance of charging efficiency is in the 
calculation of the revised equivalence

[[Page 80657]]

value for electricity in the RFS program, discussed in Section VIII.I. 
In both instances, we are proposing a value for vehicle charging 
efficiency of 85 percent based on the range of estimates in the 
literature as discussed in draft RIA Chapter 6.1.4.
---------------------------------------------------------------------------

    \252\ This is a unique issue that must be taken into 
consideration for electricity in order to represent the proper 
amount of fuel used as transportation fuel. For other renewable 
fuels, the fueling efficiency of a vehicle is essentially 100 
percent. The amount of fuel dispensed is the amount of fuel stored 
on the vehicle.
---------------------------------------------------------------------------

    We believe 85 percent is representative of the current typical 
charging situation as most charging currently occurs on private, 
domestic charging equipment which is almost universally either Level I 
or II Electric Vehicle Servicing Equipment (EVSE). However, charging 
efficiency can vary widely depending upon battery state of charge, 
ambient temperature, and the charging rate. A specific area of concern 
for which relatively little charging efficiency data is available is 
Direct Current (DC) fast chargers. Consequently, 85 percent may fail to 
remain representative if a substantial transition to DC fast charging 
occurs in the coming years. Furthermore, very few studies have been 
conducted on the effect of temperature on vehicle charging efficiency, 
and we hope that more data becomes available as EVs proliferate into 
colder climates to ensure that our charging efficiency term adequately 
captures the full range of EV charging. Given the importance of the EV 
charging efficiency in the eRIN calculation, we are proposing that 
manufacturers provide us with in-use data on the charging efficiency of 
their fleet by make and model on the various types of vehicle chargers 
and under various temperature and battery state of charge conditions.
7. Data Collection for Renewable Electricity Generators, RNG Producers, 
and Biogas Producers Emissions Verification
    In order to establish renewable fuel volumes in the RFS program for 
renewable electricity that appropriately take into consideration all 
the statutory factors pursuant to CAA 211(o)(2)(B)(ii), it is necessary 
that information regarding the environmental performance of the 
participating renewable electricity generators, RNG producers, and 
biogas producers be made available for analysis and consideration. The 
statutory language governing the Set process for RFS volumes after 2022 
directs EPA to consider a wide spectrum of factors including ``the 
impact of the production and use of renewable fuels on the environment, 
including on air quality, climate change, conversion of wetlands, 
ecosystems, wildfire habitat, water, quality, and water supply.'' \253\ 
Based upon our evaluation of the available facility data, the vast 
majority of renewable electricity generators eligible for participation 
in the RFS program are below the mandatory reporting threshold for 
biomass-fueled electricity generation facilities.\254\ Consequently, 
detailed emissions information is not required to be reported to EPA at 
this time.
---------------------------------------------------------------------------

    \253\ CAA 211(o)(2)(B)(ii)(I).
    \254\ EIA form 860, Section 6, https://www.eia.gov/electricity/data/eia860.
---------------------------------------------------------------------------

    In order to better assess the potential environmental impacts of 
renewable electricity production and use for the purpose of setting 
volumes, we are proposing that participating renewable electricity 
generators, RNG producers, and biogas producers submit air emissions 
and liquid and solid effluent production data at registration. The 
specific types of information we would require from biogas producers, 
RNG producers, and renewable electricity generators are laid out in 
proposed 40 CFR 80.150 (``Reporting''). Requiring air emissions and 
liquid and solid effluent production reporting as a condition of 
program participation for renewable electricity generators will enable 
EPA to more fully evaluate the environmental impacts of eRIN volumes 
moving forward. We request comment on the reporting of air emission and 
liquid and solid effluent information as a condition of program 
participation for renewable electricity generators, RNG producers, and 
biogas producers.

G. How the Proposed Program Structure Meets the Goals

    As discussed in Section VIII.H, EPA recognizes that there are a 
number of different approaches we could have taken to designing the 
structure of an eRIN program. However, as discussed in Sections VIII.E 
and F, we have chosen to propose a specific approach that we believe 
best achieves the goals articulated in Sections VIII.C and D. 
Specifically, the proposed approach would provide a relatively simple 
to implement but enforceable program that allows for the maximum 
incentive from the RFS program to grow the use of renewable electricity 
as transportation fuel while simultaneously enabling compliance with 
the statutory requirements. We discuss each of these aspects below in 
more detail.
1. Simplicity and Enforceability
    Foundational to our proposed eRIN program's strength and 
anticipated success is that the structure is simple (at least in 
relation to the alternatives discussed in Section VIII.H.) yet readily 
enforceable. This goal is critical given that, as discussed in DRIA 
Chapter 6.1.7, it is expected to result in a very large revenue stream, 
and therefore also provide a significant incentive for fraud that could 
then undermine the key purpose of the RFS program, increasing the use 
of renewable fuels in transportation.
    The proposed approach aligns well with the capabilities of the 
parties involved in establishing and managing the necessary contractual 
arrangements. We expect the result of this alignment to be effective 
program participation at every stage of the eRIN generation/disposition 
chain, comparatively simpler oversight, and a higher certainty of RIN 
validity. The proposal 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 renewable feedstock (i.e., 
biogas) producer, the renewable fuel producer (i.e., renewable 
electricity generator), and the party that can demonstrate its use for 
transportation (i.e., the OEM). Each party would have a set of clearly 
defined roles and responsibilities under the program. However, the 
majority of the responsibility and liability would be placed on the 
OEMs as the eRIN generator. By virtue of OEMs being relatively few in 
number, relatively large in size, having a vested business interest, 
and being already relatively experienced with our regulatory oversight, 
we believe that their role as the eRIN generator would help enable 
effective oversight to ensure the validity of the eRINs that are 
generated.
    Furthermore, the proposal takes a simple, top-down approach to the 
data needed to generate eRINs, minimizing opportunities for double-
counting and fraud, ensuring that quantities of renewable electricity 
used as transportation fuel are real, and providing confidence that 
investment for growth in renewable electricity will not be undermined. 
RINs are generated by the OEMs using only light-duty EV registrations 
as an input variable into the equation used to quantify renewable 
electricity use as a transportation fuel. This data is readily 
available and readily verifiable based on existing public data from the 
states that register the EVs and through parties that aggregate such 
data. All other inputs to the calculation are values prescribed in the 
regulations and would be updated periodically to ensure accuracy over 
time based on new data collection and reporting requirements. This 
contrasts with several of the alternative structures which would rely 
on potentially billions of data records collected from many entities in 
real time and for which both

[[Page 80658]]

incentive and opportunity would exist for fraudulent behavior. This 
top-down approach is a comparative advantage of our proposed approach 
relative to various alternatives discussed in Section VIII.H, as EPA 
and industry efforts would not need to be expended to implement complex 
data and audit systems to detect and enforce against potential fraud. 
Rather, by virtue of program design, we have minimized the potential 
likelihood of fraud occurring.
    Another important benefit of this top-down data approach would be 
the absence of the need to collect any personal information in order to 
enable eRINs to be verified. The proposed approach would not rely on 
any data from individual vehicle operation or location (other than 
vehicle registration information within the continental U.S.) nor any 
data from any individual vehicle charging events. The data used for 
eRIN generation under our proposed approach can readily be checked and 
verified not only by EPA but other interested stakeholders and would 
avoid the need to establish systems and processes to ensure that 
personal information is kept confidential.
    In addition to ensuring that renewable electricity is used as 
transportation fuel, the proposed approach would also ensure that the 
renewable electricity was produced from renewable biomass under an EPA-
approved pathway. We believe that our proposal to leverage the existing 
regulatory framework governing biogas-to-CNG/LNG pathways, as well as 
the proposed revisions to those regulations detailed in Section IX.I, 
would provide assurance that electricity is generated from qualifying 
biogas or RNG before it could be used to generate eRINs by the OEMs. By 
building off of and learning from the past implementation of the 
biogas-to-CNG/LNG pathways, we believe that we can ensure the validity 
of eRINs.
    One critical aspect of our approach is our proposal to allow OEMs 
to enter into RIN generation agreements with multiple renewable 
electricity generation facilities, but to limit each renewable 
electricity generation facility to contracting with a single OEM, as 
discussed in Section VIII.D.2. This structure for RIN generation 
agreements would make it much more straightforward for EPA and 
independent third parties to effectively audit how renewable 
electricity from qualifying biogas was used as a transportation fuel 
and would virtually eliminate the possibility that renewable 
electricity is double-counted. Our experience implementing the existing 
biogas-to-CNG/LNG provisions has necessitated that we propose a similar 
limitation on contracting for RNG as discussed in Section IX.I and for 
biointermediates as recently finalized in the 2020-2022 RFS 
rulemaking.\255\
---------------------------------------------------------------------------

    \255\ See 87 FR 39600 (July 1, 2022).
---------------------------------------------------------------------------

    In addition to this overall design structure, we believe that the 
specific regulatory requirements that we are proposing to implement the 
eRIN program as described in more detail in Sections VIII.J through 
VIII.S would enable us to ensure, at each step of the process, that the 
eRINs ultimately generated are valid. For example, the proposed 
requirement that each of these parties register with EPA in order to 
participate in the eRIN program would position us to provide direct 
oversight to ensure that (1) biogas is produced from renewable biomass, 
(2) renewable electricity is produced from qualifying biogas under an 
EPA-approved pathway, and (3) OEMs generate eRINs only from a 
sufficient quantity of renewable electricity produced from qualifying 
biogas to cover the electricity used by their fleets.
2. Incentivizing Growth in Renewable Fuels
    Consistent with our approach to growing renewable fuels and volumes 
under RFS generally, the proposed eRIN program would maximize the 
incentive to increase renewable electricity used as transportation 
fuel, and would furthermore focus on the lowest GHG renewable fuels 
(i.e., cellulosic biofuel). The eRIN program design decisions we are 
proposing in this action would, among other things, result in large 
increases in cellulosic biofuel volumes under the RFS program for 2024 
and 2025, as discussed in Section VI.A.
    First, the proposed program would readily allow for the inclusion 
of all renewable electricity used in the entire in-use light-duty EV 
fleet, both existing vehicles and new sales. By relying on top-down 
data as discussed in Section VIII.D.2, the proposal would automatically 
allow every EV registered in a state within the conterminous United 
States to count toward eRIN generation and would automatically include 
all electricity consumed in those EVs regardless of where they are 
charged within the conterminous United States. Our proposed design 
would avoid excluding any vehicles that do not have the telematic data 
necessary to support the use of bottom-up data, and any vehicle 
charging that might be excluded through a geofencing type approach as 
discussed in Section VIII.I in support of a hybrid structure. Second, 
the proposal would automatically allow inclusion of all biogas-derived 
renewable electricity generated domestically or internationally that 
can be used within the conterminous United States. This would include 
all existing biogas EGUs and any new ones that are connected to the 
commercial electric grids serving the conterminous U.S. Our proposal 
would also allow for inclusion of the gross amount of renewable 
electricity generated from biogas by the facility, enabling the maximum 
incentive for the generation of renewable electricity from qualifying 
biogas.
    Third, as discussed above, the proposed structure would minimize 
opportunities for double-counting and fraud, ensuring that volumes are 
real and providing confidence that investment for growth in volumes 
would not be undermined. Fourth, the simple design structure that 
leverages our existing structure for RNG would allow for limited 
additional implementation burden which in turn would enable the 
production of renewable electricity to begin as early as possible, on 
January 1, 2024. In contrast to other, more novel and/or data intensive 
alternatives discussed in Section VIII.H, comparatively little time 
would be needed under the proposed approach for EPA and industry to put 
in place the necessary data systems, staffing, and/or contracts 
necessary to begin eRIN generation. Finally, and importantly, we 
believe the proposal to place both renewable electricity generators and 
light-duty electric vehicle OEMs in a position to directly benefit from 
the revenue from eRIN would address three key hurdles to the growth of 
renewable electricity used as a transportation fuel under the RFS 
program: the production and capture of biogas, the generation of 
renewable electricity from qualifying biogas, and the use of that 
renewable electricity for transportation.
    Biogas producers, renewable electricity generators, and OEMs are 
all integral parties in the eRIN generation/disposition chain, and we 
anticipate that through the proposed structure a portion of the value 
of eRINs would flow through private contractual mechanisms to these 
parties as needed to support the overall growth of renewable fuel in 
the form of renewable electricity. As the eRIN generators, OEMs would 
be the parties responsible for demonstrating that renewable electricity 
is used as transportation fuel, but they would need to contract with 
renewable electricity generators (which would in turn contract with 
biogas producers) to demonstrate that the renewable electricity used as 
transportation fuel to generate the eRINs

[[Page 80659]]

came from qualifying renewable biomass. We expect that this requirement 
for the eRIN generator to demonstrate both the ``use as transportation 
fuel'' and ``from qualifying renewable biomass'' would create a market 
dynamic wherein a greater portion of the eRIN revenue would flow to 
whichever parties were most in need at any particular point in time to 
support expanded volumes of renewable electricity. For example, an OEM 
may have a fleet capable of consuming 1,000,000 megawatt hours of 
renewable electricity a year, but if they are only able to enter into 
RIN generation agreements for 600,000 megawatt hours of renewable 
electricity, they would only be able to generate RINs for sixty percent 
of their fleet. In order to generate more eRINs, the OEM would need to 
ensure that a greater portion of the value of those eRINs makes its way 
to the renewable electricity generators in order to incent greater 
electricity generation from qualifying biogas. If there were a 
constraint on production of qualifying biogas, the renewable 
electricity generator would need to direct a greater portion of the 
eRIN value to those biogas producers to incent greater production. 
Consequently, we believe all parties would have a mutual interest in 
ensuring the maximum quantity of eRINs are generated annually, and that 
as a result eRIN revenue would contractually flow to the limiting 
resource through the free market.
    The portion of the eRIN revenue flowing to renewable biogas 
producers would support eventual growth in the capture and use of 
additional quantities of biogas. The portion of the eRIN revenue 
flowing to renewable electricity generators would not only support more 
investments in such renewable electricity generators, but could also 
help reduce the cost of renewable electricity to consumers. Finally, 
the portion of the eRIN revenue retained by OEMs would help lower the 
cost of EV production and EV purchases by consumers. The vehicle market 
has always been an extremely competitive market, and with the many new 
EV offerings by virtually every vehicle manufacturer, including new 
manufacturers, we expect the EV market to be an extremely competitive 
market as well. In such a competitive market, OEMs will be forced to 
pass along revenues received from RINs to consumers in the form of 
lower EV purchase prices, charging subsidies, and other incentives or 
lose market share. This in turn would incent EV sales and thereby 
demand for the use of renewable electricity.
3. Ensuring Statutory Criteria Are Met
    The proposed program also provides assurance that the statutory 
criteria are met: that renewable electricity that is used to satisfy 
the renewable fuel volumes is both produced from renewable biomass and 
used as transportation fuel. The fundamental structure of the proposed 
program, including our decision to focus the proposed program 
requirements on the biogas producer, renewable electricity generator, 
and OEM, is designed to make those parties best positioned to 
demonstrate compliance with the statutory requirements the directly 
regulated participants.
    As discussed above, we believe that our proposal to leverage the 
regulatory framework for the biogas-to-CNG/LNG pathways would provide 
assurance that only electricity that is generated from qualifying 
biogas or RNG could be used to generate eRINs. Where our proposal 
differs from many of the alternatives is in the demonstration that the 
renewable electricity was in fact used for transportation purposes. As 
discussed above, the proposed use of a top-down data approach along 
with our choice to have the OEM be the eRIN generator ensures that 
eRINs correspond to renewable electricity that is used for 
transportation and allows little opportunity for double-counting and 
fraud, ensuring that RINs are valid and providing confidence that 
investment for growth in renewable electricity would not be undermined.
    Relatedly, while we carefully considered other options as discussed 
in Section VIII.H, our proposal to designate OEMs as the eRIN generator 
is consistent with the program design goals in Section VIII.C and meets 
the criteria laid out in Section VIII.D, including ensuring consistency 
with the statutory requirements. Clean Air Act Section 211(o)(5)(A) 
directs EPA to provide for the generation of credits under the RFS 
program by refiners, blenders, importers, and small refineries, and of 
biodiesel, but does not limit credit generation to those parties \256\ 
and provides no additional guidance relevant to the generation of RINs. 
Under the existing RFS2 program for liquid biofuels, we determined that 
it was reasonable to designate renewable fuel producers as the RIN 
generator. In the case of renewable electricity used for 
transportation, we believe it is reasonable to designate the OEMs, who 
hold one of the two pieces of information necessary to demonstrate that 
renewable electricity is a qualifying renewable fuel, as the eRIN 
generator. Furthermore, as discussed in Section VIII.F.3 we believe 
that having the OEM be the RIN generator, as opposed to the renewable 
electricity generator, will enhance our ability to track and verify the 
validity of the renewable electricity. Finally, by having the OEM be 
the sole entity that is able to generate the eRIN, we would be able to 
put in place a simple, straightforward program that allows every eRIN 
to be readily verified as meeting the statutory criteria. Unlike the 
more data and labor-intensive alternatives considered in Section 
VIII.H, the proposed approach would not afford any opportunity for 
double-counting of electricity use.
---------------------------------------------------------------------------

    \256\ The RIN system serves two purposes: as a general 
compliance mechanism, and as a means of implementing the statutes' 
credit provisions. EPA also established the RIN system utilizing its 
authority under CAA Sections 211(o)(2) and 301 to establish a 
compliance program which could include credit elements that extend 
beyond the specific elements required in CAA Section 211(o)(5).
---------------------------------------------------------------------------

H. Alternative eRIN Program Structures

    Section VIII.F describes our proposed eRIN program structure. We 
believe this structure would best meet the goals articulated in Section 
VIII.C, best balance the many program considerations described in 
Section VIII.D, and support the proposed program applicability outlined 
in Section VIII.E. At the same time, we acknowledge that the RFS eRIN 
program could be structured in a variety of different ways, and over 
the past several years we have heard directly from multiple 
stakeholders on this topic. Individuals, companies, and trade 
associations have suggested a wide range of alternative program 
structures designed to address many of the same program considerations, 
as well as some additional or different considerations, through other 
approaches. These alternative program structures vary in many aspects, 
including: which party is eligible/allowed to generate the eRIN; which 
parties should be regulated as part of the generation/disposition chain 
for the eRIN; what types of data are used and required as a basis for 
generating the eRIN; and how compliance with statutory and regulatory 
requirements is assured.
    In developing this proposal, we have given careful consideration to 
other potential program structures and the varying approaches that 
could be taken regarding key design elements. Below we discuss a number 
of the alternative approaches. For some of these, an assessment of the 
approach helps shed light on the reasoning for our proposing

[[Page 80660]]

the approach included in this action. For others, we seek to highlight 
some of the policy or implementation advantages we recognize in the 
alternative approaches. We describe below the main alternative eRIN 
program structures we considered. We request comment on whether and how 
any of these alternative structures could better meet the goals we have 
articulated, including satisfying the applicable statutory requirements 
and purpose, as well as whether and how they could satisfy the relevant 
program considerations. We further seek comment on whether we should 
pursue any of these alternative approaches, rather than our proposed 
approach, or variations of them.
1. Designating Renewable Electricity Generators as the Sole Entities 
Eligible To Generate eRINs
    The first alternative structure we discuss closely mirrors our 
proposed approach in Section VIII.F but would change the entity that 
generates eRINs. This alternative would regulate the same parties as 
the proposed structure (biogas producers, renewable electricity 
generators, and OEMs) but would designate the renewable electricity 
generators as the RIN generators, as opposed to OEMs. While the same 
three parties would comprise the eRIN generation/disposition chain and 
still likely share in the revenue generated by the eRIN, the regulatory 
obligations outlined in the proposed regulations for RIN generation 
would shift from the OEMs to the renewable electricity generators. 
Stakeholders who have advocated that EPA adopt this approach argue that 
renewable electricity generators play a role similar to that of liquid 
renewable fuel producers that generate RINs for fuels like ethanol 
under the RFS program. Such stakeholders argue that only a structure 
that designates the electricity generators as the sole RIN generating 
entity can ensure that entities responsible for directly increasing 
supply of renewable electricity are properly incented.
    From a program design perspective, we observe at least two 
significant drawbacks to this approach relative to designating the OEM 
as the sole entity eligible to generate RINs. The main concern we have 
with this alternative program structure is that it would be much more 
difficult to implement, oversee, and enforce than the proposed 
approach. This is primarily because we would expect a significant 
increase in the number of RIN generators under this alternative--by 
approximately a factor of fifty--many of whom would be small entities. 
Many of the electricity projects which we expect would register for the 
program would be small businesses or projects owned by municipal 
governments. These smaller entities may not have the staff, resources, 
or expertise necessary to comply with the regulatory obligations 
associated with RIN generation. Relatedly, due to the small size of the 
facilities, they may lack experience complying with EPA regulations, 
and with EPA fuels regulations specifically.\257\ We anticipate that 
the number of entities involved in RIN generation coupled with their 
relative lack of staff, resources, and experience would likely result 
in inadvertent issues concerning compliance with the applicable 
regulatory requirements resulting in the generation of invalid RINs.
---------------------------------------------------------------------------

    \257\ Many biogas EGUs are 1-10 MW in scale, and as such likely 
have little experience with regulatory compliance regimes. Of the 
378 facilities listed in the EPA Clean Air Markets Division eGRID 
database (United States, Congress, Clean Air Markets Division. eGRID 
2019 Data File), 322 are under 10 MW. Many of these facilities are 
too small to be subject to even state air permitting programs and 
therefore may not currently have a need for the type of regulatory 
compliance resources and expertise that would be needed for eRIN 
generation.
---------------------------------------------------------------------------

    We also do not believe that the renewable electricity generator 
would be ideally positioned to demonstrate that renewable electricity 
was used as transportation fuel, and crafting regulatory provisions to 
necessary for renewable electricity generators to do so would 
significantly increase the complexity of the program. As the RIN 
generator, the electricity generator would be responsible for not only 
demonstrating that the renewable electricity was made from qualifying 
biogas but also that the renewable electricity was used for 
transportation. Such a demonstration is not currently a requirement for 
most liquid renewable fuel producers under the RFS program given that 
is reasonable to assume that the dominant use of liquid renewable fuels 
is for transportation. However, it is a requirement for RIN generation 
for biogas to renewable CNG/LNG given CNG/LNG's potential use for non-
transportation purposes.\258\ Similarly, in order to demonstrate that 
only renewable electricity that was used for transportation generates 
RINs and that no double counting occurs, the renewable electricity 
generator would have to ensure that any OEM with which it has entered 
into a RIN generation agreement properly accounted not just for that 
generator's renewable electricity generation, but also the renewable 
electricity of all generators with which it has entered into 
contractual arrangements. This is because, as discussed in Section 
VIII.F.5.b, OEMs would have to enter into RIN generation agreements 
with multiple renewable electricity generators to cover their EV 
fleet's electricity use. It would be challenging for an electricity 
generator, particularly a small one, to demonstrate that an OEM has 
properly accounted for all the electricity generation from their 
various contracts.
---------------------------------------------------------------------------

    \258\ Under the regulations at 40 CFR 80.1426(f)(17)(i)(B), for 
renewable fuels other than ethanol, biodiesel, renewable gasoline, 
or certain types of renewable diesel, in order to generate RINs the 
renewable fuel producer must demonstrate that the renewable fuel was 
used as transportation fuel, heating oil, or jet fuel by either: (1) 
blending the renewable fuel into gasoline or distillate fuel to 
produce a transportation fuel, heating oil or jet fuel; (2) enter 
into a written contract for the sale of the renewable fuel which 
specifies the purchasing party shall blend the fuel into gasoline or 
distillate fuel for use as transportation fuel, heating oil, or jet 
fuel; or (3) enter into a written contract for the sale of the 
renewable fuel, which specifies that the fuel shall be used in its 
neat form as a transportation fuel, heating oil or jet fuel. Under 
the current regulations, parties that generate RINs for biogas to 
renewable CNG/LNG must show that the biogas was used as 
transportation fuel under 40 CFR 80.1426(f)(10) or (f)(11), as 
applicable.
---------------------------------------------------------------------------

    We do, however, believe that we could craft regulatory provisions 
to position the renewable electricity generator as the RIN generator. 
These provisions would likely have to impose additional requirements on 
the timing of RIN generation (i.e., RINs could only be generated after 
an OEM has allocated electricity to transportation use, then informed 
each contracted renewable electricity generator of the proportion of 
each electricity generator's electricity that was used as 
transportation fuel), require the use of the RFS QAP to ensure that RIN 
generation occurred correctly across the entire system, and put in 
place enhanced tracking requirements to ensure that renewable 
electricity was not double-counted. The complication of these 
additional regulatory provisions would necessitate more lead time for 
EPA and industry to implement the program and increase the overall 
burden of the program that would be needed to provide the same level of 
compliance assurance as the proposed approach.
    The proposed OEM structure avoids these complications by 
positioning the party best able to demonstrate that renewable 
electricity was used as transportation fuel as the party that generates 
the RIN. Under the proposed structure, an OEM would establish RIN 
generation agreements with many different renewable electricity 
generators in order to obtain the requisite quantity of renewable 
electricity to meet its fleet's renewable electricity consumption. 
Verifying the

[[Page 80661]]

validity of these RIN generation agreements and ensuring that there is 
no double-counting of the biogas electricity generation under the 
proposed approach is a relatively straightforward matter, as all of a 
renewable electricity generator's renewable electricity production 
could only be used by one OEM for eRIN generation. The relatively 
limited number of parties acting as RIN generators in our proposed 
approach is a positive with respect to program oversight and compliance 
because it makes preventing double-counting of renewable electricity a 
relatively simple and straightforward proposition to implement.
    Critically, under the proposed OEM structure, renewable electricity 
generators would merely have to engage in RIN generation agreements 
with OEMs in addition to the electricity offtake agreements they 
already engage in. This level of regulatory responsibility would seem 
to align better with the electricity generators' capabilities. They 
would still receive revenue through the contracts with the OEMs, but 
would not need to invest significantly in eRIN compliance assurance 
activities.
    We request comment on smaller electricity generators' abilities to 
facilitate RIN generation and whether only a program that positions the 
electricity generators as the RIN generating entity can accomplish the 
goal of encouraging growth in the supply of renewable electricity. We 
further request comment on the extent to which our proposed approach--
designating OEMs as the sole entities eligible to generate RINs--would 
differ in its ability to encourage such growth in renewable 
electricity, as compared to this alternative.
2. Designating Public Access Charging Stations as the Sole Entities 
Eligible To Generate eRINs
    A second alternative structure would designate public access 
charging stations for EVs as the sole type of entity that would be 
eligible to generate eRINs. Under this approach, the consumption-side 
data for the program, demonstrating that renewable electricity was used 
as transportation fuel, would come from charging data associated with 
public access charging stations. As under the proposed OEM structure, 
the public access charging stations would need to rely on contractual 
relationships with renewable electricity generators and biogas 
producers to demonstrate that renewable electricity was generated from 
qualifying biogas or RNG. Thus, while renewable electricity generators 
and biogas producers would remain part of the generation/disposition 
chain for eRINs, this structure would substitute the public access 
charging station for the OEM.
    A primary policy reason to adopt such an approach concerns the 
question of which barriers to increased growth of renewable electricity 
used for transportation could be best addressed by an eRIN program. 
There is a significant body of technical and policy analysis that 
identifies the need to expand public access EV charging infrastructure 
in order to support increased electrification of the transportation 
sector which is in turn then needed to expand the use of renewable 
electricity under the RFS program.\259\ Beyond such studies, EPA has 
heard directly from stakeholders who assert that a key barrier to 
widespread electrification of the transportation sector is the need for 
widely available access to public charging, and that some form of 
additional economic support is beneficial, or even necessary, in order 
to support the business model of public access charging stations. 
Stakeholders acknowledge that this dynamic may change over time, but 
given where the U.S. stands today in EV charger build-out, they 
maintain that additional public policy support is warranted. The Biden 
Administration has already acknowledged and acted on this need; in 
February 2022, for example, the Departments of Energy and 
Transportation announced $5 billion to be made available to build out a 
nationwide EV charging network.\260\ Furthermore, in August 2022 the 
Inflation Reduction Act included tax credits for developing charging 
station locations, with incentives for chargers built in low-income or 
rural census tracts.\261\
---------------------------------------------------------------------------

    \259\ Driving The Market For Plug-In Vehicles: Developing 
Charging Infrastructure For Consumers, UC Davis, International EV 
Policy Council, https://phev.ucdavis.edu/wp-content/uploads/Infrastructure-Policy-Guide-March-2018.pdf.
    \260\ https://www.energy.gov/articles/president-biden-doe-and-dot-announce-5-billion-over-five-years-national-ev-charging.
    \261\ H.R. 5376, SEC. 13404.
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    With respect to EPA's development of new eRIN regulations, some 
stakeholders have argued that in light of the need to directly support 
public charging infrastructure expansion, EPA should prioritize the 
need to ensure that any associated RIN revenue supports charging 
infrastructure in as direct a fashion as possible. And more 
specifically, that EPA should consider a structure designating public 
access charging stations as the sole entities eligible to generate 
eRINs, or barring that, at least ensuring that they are able to 
generate eRINs directly as part of hybrid approach (see later 
descriptions of hybrid approaches). Ensuring that charging stations can 
register to generate eRINs, stakeholders argue, provides the most 
direct form of support for expansion of charging infrastructure via the 
eRIN program. Such parties would be best positioned, they assert, to 
focus eRIN revenue on charger build-out.
    Some stakeholders, in support of this approach, also point to the 
need for additional financial support to ensure the long-term viability 
of the business model underlying public charging stations. Some of 
these stakeholders have conveyed that the combination of electricity 
capacity payments, along with relatively low charger utilization rates, 
creates a situation where the cost of charging (particularly fast 
charging) can exceed the cost of gasoline on an energy equivalent 
basis. Consequently, these stakeholders believe that without additional 
financial support, public access charging will not develop at the rate 
necessary in all parts of the country where it will be required to 
address EV charging needs and therefore be a barrier to the 
electrification of the fleet. These stakeholders argue that an eRIN 
structure that positions public access charging stations as the RIN 
generator would allow them to reduce direct costs to their customers, 
thereby reducing the total cost of EV ownership. As an additional 
result, they argue that directing eRIN revenue to public access 
charging stations would allow them to expand the geographic reach of 
their charging networks. This would increase the prevalence and 
availability of public charging infrastructure and help to relieve 
range anxiety for owners/potential owners of electrified vehicles.
    While there are other funding mechanisms in place and being 
developed for public access charge stations to support the deployment 
of EVs nationwide, EPA agrees that designating public access charging 
stations as the sole type of entity eligible to generate eRINs could 
provide a relatively direct funding mechanism for EV public charging. 
We believe this structure could be implemented at a national level, 
though it may be more complicated than the proposed structure. The 
relative ease of implementation in this case is tied directly to the 
data which we would require for eRIN generation. Because charging 
stations collect information on the quantity of electricity dispensed 
as a regular business practice, there is a readily available dataset 
which could be used as the basis for calculating electricity 
consumption and then RIN

[[Page 80662]]

generation. The availability of such a dataset, which provides a direct 
measurement of the electricity provided to a vehicle is a key advantage 
of this approach.
    While we acknowledge the benefits of an approach that provides 
access to such datasets, EPA has some concerns related to data 
verification and validation. The sheer volume of data (millions, and 
eventually billions, of individual charging events) means that 
verification of the data would necessarily need to be done by some 
combination of third party verifiers and EPA spot audits. This work 
would require substantial oversight and enforcement resources; this is 
not necessarily a barrier, but it is at least an important 
consideration as discussed in Section VIII.D. The volume of charging 
station data could provide an opportunity for and incentive for 
fraudulent behavior. We anticipate the value of the eRIN to exceed the 
cost of electricity by a substantial margin.\262\ This circumstance 
creates an incentive to inefficiently dispense electricity at the 
charge stations, redirect it for other purposes, or to otherwise 
participate in wasteful charging practices in order to generate as many 
RINs as possible. We have yet to determine if a set of protocols could 
be developed to effectively curtail this potential fraudulent behavior.
---------------------------------------------------------------------------

    \262\ With the revised equivalence value and D3 RIN prices of 
approximately $3/RIN the value of renewable electricity in the eRIN 
program would be on the order of $450/MWh.
---------------------------------------------------------------------------

    Beyond such concerns, perhaps the primary drawback to a structure 
that exclusively positions public access charging stations as the RIN 
generator is that it inherently limits the quantity of eRINs which can 
be generated to the fraction of vehicle charging which occurs at public 
charge stations. Recent estimates put the fraction of EV charging which 
occurs at public charge stations around 20 percent.\263\ If an eRIN 
program were designed so that only this portion of charging were 
eligible to generate eRINs, it would arguably limit the RFS program's 
ability to encourage increased use of renewable electricity as a 
transportation fuel.
---------------------------------------------------------------------------

    \263\ ``Charging at Home--Department of Energy.'' Available: 
https://www.energy.gov/eere/electricvehicles/charging-home.
---------------------------------------------------------------------------

    An additional consideration for the public access charging station 
only structure centers upon the types of entities that own/operate 
charging stations. Although the majority of charging stations across 
the country are owned/operated by large networks that would have the 
staff, resources, and expertise necessary to comply with the regulatory 
obligations associated with RIN generation, there are a number of 
public access charging stations owned by small businesses and 
municipalities. These smaller entities would face significant 
challenges to participation in a national eRIN program. A lack of 
participation by smaller networks or stand-alone stations would, in 
aggregate, further erode the impact of the eRIN program and potentially 
would introduce an incentive structure which only encourages 
participation from large-scale networks.
    A final consideration for the public access charging station only 
structure centers upon the mostly short- to medium-term need to build 
out the public charging infrastructure with the longer-term nature of 
the RFS program and the inability to direct where the buildout occurs. 
Unlike other federal, state, and local financial incentives, which can 
and are being put in place to target consumer public charging needs in 
particular locations and only for the duration where the need still 
exists, the financial incentive from the eRIN would not be able to do 
so. Rural and other charge locations with low use but which are 
important for consumer confidence when making an EV purchase decision 
would remain poor business in comparison to other locations with higher 
EV use. The eRIN would also continue to provide an incentive for the 
life of the program regardless of the need. Arguably, once the needed 
public access charging infrastructure was in place it could result in 
incentivizing less efficient use of resources to further support public 
access charging at the expense of private charging. While public access 
charge stations could shift the revenue from the eRIN toward lowering 
the price of electricity at public access charge stations, we believe 
that our proposed structure addresses two other, critical limitations 
to increasing the use of renewable electricity as transportation fuel--
the relatively high cost of EVs and the need for greater renewable 
electricity generation--and thus better meets the goals discussed in 
Section VIII.C. Additionally, other mechanisms exist that can and will 
be employed to support EV public access charging infrastructure.\264\ 
Nevertheless, access to public charging is currently a significant 
factor in expanding the electrification of the transportation sector, 
and therefore providing revenues from eRINs could be an important part 
of expanding that infrastructure. We therefore seek comment on 
potential structures that could support EV public access charging 
infrastructure, including hybrid structures as discussed below.
---------------------------------------------------------------------------

    \264\ EPA has observed an increase in the prevalence of CNG/LNG 
refueling infrastructure despite the RINs from CNG/LNG typically not 
being generated by the refueling stations themselves. The majority 
of value from CNG/LNG RINs has been directed towards entities 
producing RNG and towards reducing the purchase price of vehicles 
capable of utilizing CNG/LNG. The resultant increased demand and 
attractively priced, RIN subsidized fuel, have served to create 
market conditions where investment in refueling infrastructure is 
warranted.
---------------------------------------------------------------------------

3. OEM-Centered Approach Using Telematics Data
    A third alternative does not structurally differ from the proposed 
structure, but would use telematics \265\ data, rather than the 
proposed top-down aggregate approach, in order to demonstrate ``use as 
transportation fuel''. In such an approach, charging data from onboard 
vehicle telematics would be utilized rather than a top-down methodology 
to determine the quantity of renewable electricity used as 
transportation fuel. This source of data would be the most precise--
recording the actual electricity that went into the vehicle's battery 
as reflected in its state of charge. Such an approach would arguably 
help eliminate incentives for inefficient and/or fraudulent behaviors 
associated with vehicle charging and would be equally applicable to 
public and private charging. It would create an auditable stream of 
specific data that would potentially help in compliance and oversight 
efforts, and would avoid some of the uncertainty associated with top-
down estimation approaches.
---------------------------------------------------------------------------

    \265\ Telematics broadly refers to onboard vehicle data 
collection systems (GPS, onboard diagnostic systems).
---------------------------------------------------------------------------

    To implement such a system, EPA would have to establish mechanisms 
to collect, aggregate, and report the vehicle telematics data on a 
regular interval to serve as the basis for eRIN generation and allow 
for manageable oversight.\266\ The development of a mechanism to 
collect, aggregate, and report potentially billions of charging events 
would take a significant amount of time and would need to be updated 
frequently to adapt to changes in vehicle telematics information over 
time. Adopting an approach that relied on vehicle telematics as a basis 
for RIN generation could significantly delay when we could allow for 
eRIN generation as we take time to develop a mechanism to collect, 
aggregate, and report vehicle telematic information. Furthermore,

[[Page 80663]]

while all future vehicles could be designed to report the necessary 
information into some new electronic system, this would not be the case 
for much of the legacy fleet, whose electricity consumption would 
dominate at the start of the program. Additionally, the eRIN program 
may expand beyond light-duty vehicles into other transportation sectors 
in the future where telematics may or may not be a viable option. 
Although we are proposing to only allow for light-duty vehicles to 
participate in the eRIN program at this time, a lack of ubiquity and 
standardization regarding vehicle telematics curtailed our ability to 
leverage this data source at this time. We request comment on the 
potential advantages and drawbacks of leveraging vehicle telematic data 
across multiple vehicle segments to construct or improve the eRIN 
program. We further request comment on how we could reduce or mitigate 
burdens associated with program oversight and compliance (e.g., use of 
auditors) were EPA to eventually pursue an approach that relied on 
telematics data. Finally, we request comment from stakeholders who have 
participated in programs like California's LCFS, where highly detailed 
data is required, and what lessons can be applied in the development of 
EPA's eRIN program.
---------------------------------------------------------------------------

    \266\ RINs are often transacted in the RFS program in block of 
millions and even hundreds of millions of RINs, so some means of 
acquiring the data and aggregating it into manageable blocks would 
be required.
---------------------------------------------------------------------------

4. Hybrid Structures
    Consistent with the Congressional intent of the program, one of the 
main program design considerations we sought to address with our 
proposed structure was that the program be able to capture the largest 
share of renewable electricity use in transportation possible. This 
translates into the maximum number of RINs being generated from the 
eRIN program and ultimately the largest incentive for the growth of 
renewable electricity for transportation purposes. We believe that our 
proposed eRIN structure, which designates OEMs as the sole RIN 
generators, would accomplish this. However, we have also explored 
whether it is possible to maximize eRIN generation while also directing 
a portion of the program incentives to support public access charging 
stations more directly than our proposed approach might do.
    As EPA began development of new regulations on eRINs, several 
stakeholders argued that EPA should establish a regulatory structure in 
which both OEMs and public access charging stations would be eligible 
to generate eRINs. Some pointed to California's LCFS as an example of 
where such a program works today. In this notice, we refer to program 
structures where multiple parties are eligible to able to act as eRIN 
generators as ``hybrid'' approaches.'' While we have considered a wide 
range of potential hybrid structures, we discuss the primary ones in 
this section. We request comment on the benefits and drawbacks of the 
various hybrid structures presented below, whether EPA should adopt one 
of these hybrid structures, and if so how to address the issues and 
challenges they would raise.
a. Designating Both OEMs and Public Charge Stations as Entities 
Eligible To Generate eRINs
    The first type of hybrid structure we considered is one in which 
both OEMs and public access charge stations would be eligible to act as 
eRIN generators. Both entities would be required to secure contracts 
with renewable electricity generators to demonstrate procurement of the 
necessary renewable electricity from qualifying biogas and they would 
have to use unique, i.e., non-overlapping, data to demonstrate 
transportation use in order to avoid double counting.
i. California LCFS-Type Structure
    A number of stakeholders have pointed to how electricity credits 
are managed under California's Low Carbon Fuel Standard (LCFS) Program 
as a template for how EPA could implement a hybrid national program 
that includes both OEMs and public access charge stations. While it is 
not possible for EPA to directly adopt the California structure for 
eRINs under the RFS program, we gave careful consideration to whether 
we could adopt a data collection and tracking structure similar to that 
used in California that would allow both OEMs and public access charge 
stations to generate RINs.
    The first ``layer'' of LCFS credits for electrified vehicles is 
generated by the electric utility servicing the area where those 
vehicles are registered. The LCFS program then layers on top of this a 
system of providing additional LCFS credits for low-GHG electricity 
used in transportation to both vehicle manufacturers and charging 
stations, based on vehicle telematic charging data and public access 
charging data.\267\ To avoid double counting in the system--for 
example, to avoid a situation where an LCFS credit for one charging 
event is simultaneously created for both an OEM and a public charging 
company--the LCFS program relies on a ``geofencing'' system. Through 
technology-based geofencing, the locations of public charging stations 
are known with a reliable degree of precision, allowing data for 
associated charging events to be segregated from, for example, home-
based charging. Doing so allows LCFS credits to be generated by 
different entities: charging station owners receive LCFS credit for 
charging station events, for example, and an OEM might receive LCFS 
credit for certain types of home charging (provided other program 
requirements are all met). In so doing, the program is designed to 
enable direct financial support, via LCFS credits, to the owners of 
charge stations as well as to other entities like OEMs.
---------------------------------------------------------------------------

    \267\ See Section VIII.H.5.a.i for further details on these data 
requirements of the CARB LCFS program.
---------------------------------------------------------------------------

    Stakeholders have suggested that a similar approach could be used 
as part of an eRIN program to allow both OEMs and public charge 
stations to generate eRINs while providing the required demonstration 
that the renewable electricity was not double counted and was, in fact, 
used for transportation purposes.\268\
---------------------------------------------------------------------------

    \268\ Under the California LCFS program the OEMs and charge 
stations then procure and retire RECs in order to demonstrate that 
the electricity was renewable. As discussed in Section VIII.H.2., 
the RFS program cannot rely on RECs, so some means akin to our 
proposal would be required for this aspect of such a hybrid 
structure.
---------------------------------------------------------------------------

    Under the California program, charging stations collect charging 
session IDs, charging session start and end times, total time spent 
charging, total energy dispensed, charging station and plug IDs, plug 
type, maximum power output, city, state, zip code, venue type, and 
charging station activation date. All this data must then be 
synthesized and matched with vehicle telematic data from the charging 
vehicle, including the Vehicle Identification Number (VIN), the 
locational data of the vehicle, and the similarly recorded total time 
spent charging, total energy dispensed, and other charging event data. 
The charge station and vehicle telematic data must be matched against 
each other to ensure that only unique events are counted, and charging 
stations must be geofenced to differentiate between residential and 
non-residential charging stations. California structured this part of 
the program so that charging stations could earn credits for charging 
occurring at their facilities (through the use of electric vehicle 
charge station data as discussed above) and another entity (typically 
OEMs) could generate credits for charging (through the use of vehicle 
telematics data) that occurred away from charging facilities. Though 
acknowledging the data-heavy requirements and complexity of such a

[[Page 80664]]

system, particularly as it expanded to more and more homes and 
businesses nationwide, a number of the stakeholders that EPA met with 
pointed to the LCFS system as a model that EPA could adopt for a 
nationwide eRIN program.
    In assessing whether a similar model could be adopted for RFS 
programmatic purposes, a central concern is one of scale: while the 
LCFS approach may work well at the state level, EPA has concerns about 
whether it would be appropriate and possible to implement at a national 
level, given the resources available to EPA and the burden it would 
place on the many regulated entities. For example, the process of 
tabulating and crediting charging events under the RFS program would 
require that each individual charging event be recorded and then 
audited by a third party prior to generating credits. As the national 
light-duty vehicle fleet begins to be comprised of a larger share of 
electrified vehicles we will likely have tens of millions of vehicles 
charging hundreds of times each year. This would result in billions of 
individual charging events that would need to be reviewed for accuracy 
and compliance each year. This would be in addition to oversight of the 
many contracts between OEMs, charging stations, and EGUs to demonstrate 
the electricity was produced from renewable biogas.
    Moreover, given the magnitude of the eRIN value, there would be 
considerable financial incentive for parties to find ways within the 
system to improperly generate eRINs. Consequently, we do not believe 
that such an approach is currently viable and are proposing an approach 
to the eRIN program that would be both more streamlined and less data-
heavy as discussed in Section VIII.F. The stakeholders that supported 
this approach generally did not offer particular implementation 
solutions to such a complex data gathering requirement other than to 
suggest that EPA could use its resources to manage it, use computer 
algorithms to screen for potentially abnormal data, and rely on 
independent third parties to carry out much of the work involved. While 
we can and do incorporate independent third parties into the design of 
our program as discussed in Section VIII.F.5.j, leveraging third 
parties to, e.g., provide quality assurance, this does not relieve EPA 
of the obligation of promulgating the detailed regulatory framework, 
establishing the data systems and oversight mechanisms, maintaining the 
necessary infrastructure, and directly conducting any enforcement 
necessary to implement an eRIN program. We request comment on specific 
approaches EPA could use to mitigate resource and complexity concerns 
associated with this type of programmatic structure.
    Additionally, we have also heard from a number of stakeholders 
currently participating in the LCFS program that have raised concerns 
about how the program may translate into the future. Specifically, 
concerns have been voiced regarding the geofenced set-asides for 
charging stations and how these may interfere with domestic charging, 
particularly in dense urban areas.\269\ These stakeholder concerns 
contribute to our belief that it would be necessary to implement a much 
simpler system, were we to adopt a hybrid structure where both OEMs and 
public charge stations were allowed to function as RIN generators.
---------------------------------------------------------------------------

    \269\ Non-residential charging stations have an assumed minimum 
geofencing radius of 220 meters, while residential chargers may use 
a maximum geofencing radius of 110 meters. These radii are 
conservative estimates put forth by the California Air Resources 
Board to account for blocked or reflected satellite signals. This 
allows matched telematics data to be verified to ensure no double 
counting. Low Carbon Fuel Standard (LCFS) Guidance 19-03, Reporting 
for Incremental Credits for Residential Charging, https://ww2.arb.ca.gov/sites/default/files/classic/fuels/lcfs/guidance/lcfsguidance_19-03.pdf.
---------------------------------------------------------------------------

    Finally, given the complexity of this approach to implementing 
eRINs, were we to attempt to put it in place, it would likely be 
difficult to implement by January 1, 2024. Out of a desire to implement 
the eRIN program as soon as practicable in order to increase the 
penetration of renewable electricity as a transportation fuel in the 
near term, we deemed it advantageous to put in place a structure that 
could be implemented more expeditiously. Given the concerns outlined, 
we request comment on the benefit of EPA adopting a data-heavy hybrid 
approach for the eRIN program given the added complexity and potential 
delayed implementation of the eRIN program. In particular, we seek 
comment on how and why such an approach could be scaled to the national 
level.
    Some stakeholders have suggested that EPA create an eRIN program 
that would somehow incorporate broader policy tools or authorities that 
exist under the California LCFS. A number of fundamental differences 
exist between the LCFS and RFS programs, however, and those differences 
mean there will be some policy or implementation options available 
under one program that might not be available under the other. A key 
fundamental difference, for example, is that the definition of 
renewable fuel under CAA section 211(o)(1)(J) requires that it be 
produced from renewable biomass as defined in 211(o)(1)(I). Thus, only 
electricity that is produced from qualifying renewable biomass is 
eligible to generate eRINs under the RFS program. By contrast, under 
the LCFS program qualifying electricity can be produced from a broader 
range of energy sources, including wind, solar, and hydroelectric. The 
scope of what qualifies as renewable electricity for the LCFS credits 
is considerably broader than what can qualify for eRINs under current 
CAA authority.
    A second fundamental difference between EPA's RFS program and 
California's LCFS program concerns the ability to direct how parties 
receiving revenue (e.g., from LCFS credits) must be use those funds. 
Under the LCFS, utilities are required to use LCFS credit to ``benefit 
current or future'' EV owners, for example through rebate programs or 
point-of-sale incentives (e.g., California's Clean Fuel Reward).\270\ 
\271\ Some stakeholders have suggested that we should include 
provisions in our eRIN program that would allow or require EPA to 
similarly direct revenue towards specific uses. For example, some 
stakeholders have suggested that EPA establish a program that somehow 
requires eRIN revenue be used on to lower the purchase price of an EV 
or alternatively to increase the availability of public charging. The 
Clean Air Act, however, does not provide us with explicit authority, 
and we do not interpret the Clean Air Act's silence in this case as 
allowing us to direct where eRIN revenue is used. We request comment on 
this interpretation.
---------------------------------------------------------------------------

    \270\ https://cleanfuelreward.com.
    \271\ https://ww2.arb.ca.gov/resources/documents/lcfs-utility-rebate-programs.
---------------------------------------------------------------------------

    Under our proposed approach, the OEM would generate the RIN, and 
the actors in the RIN generation/disposition chain would determine how 
RIN revenue would ultimately be allocated. The market, via contractual 
negotiations among actors in the chain, would dictate, for example, how 
much of the RIN revenue the OEMs will need to share with the renewable 
electricity producer and in turn how much of the revenue will need to 
be shared with the biogas producer. We anticipate that the degree of 
competition between OEMs on the pricing of EVs will dictate in large 
part how much of the eRIN value they receive is passed on to consumers 
in the form of lower purchase prices for new vehicles or subsidized 
services (e.g., charging). Were we, in the alternative, to put in place 
an eRIN program that provided eRIN revenue to public access

[[Page 80665]]

charge stations, the degree to which that revenue would be passed on to 
consumers in the form of lower prices would similarly be a function of 
the degree to which there was competition in the marketplace between 
charge station networks. In today's marketplace there is widespread 
competition between fuel stations for gasoline and diesel fuel with 
many stations typically in close proximity to one another vying for 
consumer demand. However, significant competition among public charge 
stations is unlikely until the market matures. We have seen this 
dynamic elsewhere in retail fueling: in the still-small marketplace of 
E85 stations, for example, we have not found pricing to be driven by 
competition such that the full value of the RIN is passed along to 
consumers in the form of lower fuel prices.\272\
---------------------------------------------------------------------------

    \272\ ``A Preliminary Assessment of RIN Market Dynamics, RIN 
Prices, and Their Effects,'' available in the docket.
---------------------------------------------------------------------------

ii. OEM Structure With a Charge Station Carveout
    Given the complexities of trying to implement a California type 
structure, we looked into ways that it might be possible to streamline 
it to the extent possible. In this hybrid iteration, the OEMs would use 
the same data outlined in our proposed structure in Section VIII.F to 
establish the maximum amount of transportation fuel for which their 
fleet could potentially demonstrate RINs. The charge stations would 
separately use some form of the charge event information collected as a 
regular course of business such as that described in Section VIII.H.2 
above. Some form of adjustment would then have to be made to subtract 
the charge events that occurred at charge stations from the overall 
transportation fuel use calculated by the OEMs to ensure that no double 
counting of electricity used for transportation occurs. Known issues 
with this post-hoc reconciliation of data include: ensuring that make 
and model information is retained by the charge stations so that the 
proper subtraction can be made from an individual OEM's fleet, creating 
a workable temporal reconciliation process for the charge events so 
that RIN generation can be facilitated in a timely manner, and 
developing a methodology for predicting the rate of public charging 
such that disruptive over/under RIN generation would not occur on 
behalf of the OEMs. We request comment on the approach of OEMs as RIN 
generator with a carveout for charge stations generally, as well as on 
potential ways to address these challenges to this approach.
    There is also an issue regarding double-counting concerns which 
would exist in such a hybrid structure. In Section VIII.F.2 and H.1 we 
discussed the benefits of a many-to-one relationship for renewable 
electricity generators and OEMs, which would be abrogated by 
positioning the EGUs as the RIN generators rather than the OEMs. This 
is because a majority of renewable electricity generators are much 
smaller in their electrical generation capacity than the demanded 
quantity of electricity from an entire OEMs fleet. A similar asymmetry 
exists between renewable electricity generators and charge stations. 
Although it is true that a charge station network may well have enough 
electricity demand to require contracting with multiple renewable 
electricity generators, there will be many independently owned and 
operated public charge stations which would only require a fraction of 
the electricity production of a single renewable electricity generator 
in order to meet their charging demand. This would greatly increase the 
quantity of contracts needed to connect renewable electricity to 
transportation use; with the higher number of contracts comes an 
increased probability of overlapping claims on the same quantity of 
electricity and thus an increased probably of double counting. 
Furthermore, as discussed in Section VIII.H.2, the program would have 
substantially more RIN generating parties that would need to register 
than in our proposed structure. As we have noted previously, many of 
these charge stations are expected to be small entities that may not 
have the resources or expertise required to satisfy all the compliance 
and oversight obligations to participate in the RFS program as RIN 
generators.
b. Hybrid With Renewable Electricity Generators as RIN Generator
    The second hybrid structure to which we gave serious consideration 
would position the renewable electricity generators as the eRIN 
generators but would allow both charge stations and OEMs to participate 
in the program by demonstrating the use of electricity as 
transportation fuel. Under this structure, the renewable electricity 
generators would generate eRINs for the specific amount of renewable 
electricity that is generated and loaded onto the commercial electric 
grid serving the conterminous U.S. A party, e.g., an OEM or public 
charging station owner/operator, would separate those eRINs upon 
demonstrating that the renewable electricity was used as transportation 
fuel. This approach has the advantage of using the eRIN assigned in 
EMTS as an additional means of tracking the renewable electricity from 
generation to disposition. Additionally, because the assigned RIN could 
only be separated once, this could virtually eliminate the opportunity 
to double-counting of the renewable electricity. We would expect that 
the OEM or public charging station would use information similar to 
that required for RIN generation under the proposed approach, the 
contemplated public charging station structure discussed in Section 
VIII.H.4, or hybrid approach discussed in Section VIII.H.5.a.ii. The 
main difference in this approach would be that the renewable 
electricity generator could generate and assign the eRIN and would 
leverage the assigned RIN in EMTS to track how the volume of renewable 
electricity was used as transportation fuel. This program structure 
would be similar to the revised structure we are proposing for the 
generation, assignment, and separation of RINs for CNG/LNG produced 
from biogas. We discuss in more detail the approach proposed for RNG 
under the proposed biogas regulatory reform provisions in Section IX.I.
    Despite the improvements in program oversite that this hybrid 
structure would provide, it still has many unresolved issues and would 
essentially have the same challenges discussed in Section VIII.H.2 with 
respect to public access charging and the same challenges associated 
with sequencing RIN generation (separation under this approach) 
discussed in Section VIII.H.5.a.ii. The main challenge is that this 
would significantly increase the burden on the core party least able to 
take on that responsibility, i.e., the many small renewable electricity 
generators that would serve as eRIN generators. This could 
significantly complicate or delay the setting up of the eRIN program. 
This could also result in a significant number of renewable electricity 
generators not participating in the program which could reduce the 
number of eRINs and thereby reducing the effectiveness of an eRIN 
program at incentivizing the increased use of renewable electricity as 
transportation fuel. We request comment on means of overcoming the 
challenges presented by adopting such a hybrid structure as the basis 
of the eRIN program.
5. Renewable Electricity Credit Programs
    While most of the alternatives stakeholders have raised concern the

[[Page 80666]]

demonstration that the renewable electricity was used as transportation 
fuel, some stakeholders have also suggested an alternative for the 
demonstration that the renewable electricity was produced from 
renewable biomass. Specifically, some stakeholders have suggested to 
EPA that we consider somehow relying on or leveraging existing state 
renewable electricity credit (REC) programs in the development and 
implementation of an eRIN program. REC trading systems are a feature of 
many state-level renewable portfolio standard (RPS) programs, which set 
targets for renewable electricity use in a given area. RECs provide a 
mechanism to help track and account for electricity generated from 
renewable sources (e.g., solar, wind) as it flows onto a commercial 
electric grid. Stakeholders have pointed EPA to such RPS programs, and 
mechanisms like RECs, because the programs face a similar challenge in 
accounting for and tracking a fungible product--renewable electricity. 
Many stakeholders are familiar with how REC programs function; 
California's LCFS, for example, allows participants to use RECs to 
demonstrate supply of low carbon-intensity electricity for purposes of 
claiming LCFS credit.\273\ To avoid the double counting of electricity 
in multiple states, as parties generate LCFS credits for the renewable 
electricity that they produce, they must then retire RECs that they 
purchase.
---------------------------------------------------------------------------

    \273\ https://ww2.arb.ca.gov/sites/default/files/classic//fuels/lcfs/guidance/lcfsguidance_19-01.pdf.
---------------------------------------------------------------------------

    We recognize the similar conceptual challenges that RPS programs 
and a renewable electricity program under RFS face with respect to 
tracking/accounting mechanisms for fungible renewable electricity. And 
EPA considered whether we could, in fact, rely on REC programs for 
compliance purposes under an eRIN program. Upon investigation, however, 
it became apparent that we cannot not rely on the REC program for a 
number of reasons. First, under the Clean Air Act's definition of 
renewable fuel, only electricity that is produced from qualifying 
renewable biomass is eligible to generate eRINs. Thus, EPA's existing 
renewable electricity pathways are for biogas that is produced from 
qualifying renewable biomass. In contrast, REC programs include, and in 
fact are dominated by other forms of renewable electricity such as 
wind, solar, and hydroelectric. Such electricity does not meet the 
statutory requirement of being produced from ``renewable biomass.'' As 
a result, it would not be sufficient for us to simply rely on RECs as a 
means of demonstrating that renewable electricity was produced from 
qualifying renewable biogas under the RFS program. Although it is true 
that RECs can be generated for electricity produced from qualifying 
biogas, the generation of a REC does not by itself indicate that the 
electricity meets Clean Air Act requirements. Consequently, if we were 
to attempt to utilize REC programs in a similar fashion to the 
California LCFS program, we would still need to create additional 
regulatory requirements. These additional regulatory requirements would 
likely largely resemble those we either already have or are proposing 
in this action to ensure that CAA requirements are met, so there would 
be little value in leveraging REC generation.
    Furthermore, the lack of a centralized, national REC clearinghouse 
would complicate our relying on REC programs. An eRIN program will be 
national in scope, and the diversity that exists among different state-
level and regional REC programs with respect to structures, 
capabilities and requirements would make it difficult to rely upon RECs 
for a federal eRIN program. Again, in order to establish a national REC 
program that ensures that renewable electricity was generated using 
qualifying biogas consistent with Clean Air Act requirements, we would 
have to impose a set of regulations that would look very similar to the 
existing RFS program or our proposed approach for the eRIN program.
    Third, we cannot delegate our compliance and enforcement 
responsibilities to the state REC programs. Therefore, even if we 
somehow leverage REC programs, we would still need to have some way of 
reviewing, auditing and verifying the validity of the data on which 
eRINs would then be generated. The varied structure and limited 
geographic reach of these programs again precludes their use for eRINs.
    Finally, a key element of the existing RFS program provisions is 
that the financial incentives created by RINs for expanding the use of 
renewable fuels are incremental to the incentives created by other 
federal, state, and local programs. For example, the revenue from the 
sale of RINs for renewable fuels is in addition to revenue from 
California LCFS credits; revenue from RINs therefore helps lower the 
cost of such programs. However, if we were to leverage state REC 
programs for renewable electricity under the RFS program, we would 
likely have to require the retirement of RECs upon the generation of 
eRINs in order to prevent double counting of eRINs.\274\ This would 
negate the ability of the eRIN to further subsidize the expanded use of 
renewable electricity. We believe that the electricity producer should 
continue to benefit from the sale of the REC while also benefiting from 
revenue from the eRIN so long as the biogas used to produce the 
renewable electricity and the renewable electricity itself is not 
double counted.\275\
---------------------------------------------------------------------------

    \274\ For example, to prevent double counting of the REC, under 
the California LCFS program, any RECs are required to be retired 
upon the generation of LCFS credits.
    \275\ EPA does not permit the generation of a RIN for a volume 
of biogas used to produce renewable CNG/LNG if the same volume of 
renewable biogas has been or will be used to generate a REC. This is 
because such a practice would constitute double counting of the 
biogas as being used to both generate electricity and be compressed/
liquefied for transportation use; it is not physically possible for 
a single volume of biogas to be used in both ways. Because we have 
not registered any party to generate eRINs, we have not yet been 
confronted with a situation in which a party wishes to generate both 
a REC and a RIN based on the same volume of biogas combusted to 
generate electricity.
---------------------------------------------------------------------------

    We seek comment on how, under our proposed approach, EPA might be 
able to rely on, leverage, or otherwise incorporate REC-program 
approaches.

I. Equivalence Value for Electricity

1. Background
    The CAA establishes target volumes of renewable fuel to be attained 
in various years but does not prescribe exactly how those gallons 
should be counted across the range of potential renewable fuel types. 
For instance, the statute permits biogas to qualify as a renewable fuel 
for purposes of compliance with the applicable standards, but biogas 
cannot be easily measured in volumes in the same way that liquid 
renewable fuels can. Instead, the statute directs EPA to determine the 
appropriate basis for how credits for volumes of renewable fuels would 
be granted. To this end, in the 2007 final rule which established the 
RFS1 program, we established ``equivalence values'' unique to each 
biofuel that determine how many RINs can be generated for each physical 
gallon and how each gallon counts towards meeting the applicable 
standards.\276\
---------------------------------------------------------------------------

    \276\ 72 FR 23918 (May 1, 2007). We are not revisiting or 
seeking comment on the question of our statutory authority to set 
equivalence values or the basis we're using (i.e., ethanol 
equivalent), which were established in the 2007 rule. Rather, we are 
only requesting comment on changing the equivalence value for 
electricity.
---------------------------------------------------------------------------

    In the 2007 rule, we assessed several ways of determining 
equivalence values. Since one goal of the RFS program was reduction of 
GHG emissions, we considered use of lifecycle GHG scores, meaning that 
biofuels with lower

[[Page 80667]]

lifecycle GHG emissions could be given higher value. However, we 
determined that there was too much uncertainty at that time in the 
available information and modeling tools, and we anticipated a need to 
update the equivalence values periodically as the science evolved. 
Ultimately, we determined that, in light of the statute's requirement 
that qualifying renewable fuel be ``used to replace or reduce the 
quantity of fossil fuel present in a transportation fuel,'' volumetric 
energy content was the appropriate basis for equivalence values, 
stating that ``fossil fuels such as gasoline or diesel are only 
replaced or reduced to the degree that the energy they contain is 
replaced or reduced.''
    We also noted in the 2007 rule that denatured fuel ethanol was 
likely to be the predominant biofuel expected to be used to meet the 
statutory volume targets under the RFS1 program. Thus, in an effort to 
establish a simple and stable program, we opted to use the energy 
content of renewable fuels as the basis of equivalence values and to 
designate denatured fuel ethanol as the baseline gallon of renewable 
fuel. Under this structure, credits for renewable fuels under the RFS 
program have been determined based on their energy content relative to 
denatured fuel ethanol; specifically, equivalence values are based on 
the ratio of a given biofuel's volumetric energy content relative to 
the volumetric energy content of denatured fuel ethanol. The 
regulations specify the equivalence values for a number of renewable 
fuels that we expected would be used.\277\ Table VIII.G.1-1 shows the 
energy content and equivalence values (statutory gallons, or RINs) for 
several liquid renewable fuels.
---------------------------------------------------------------------------

    \277\ See 40 CFR 80.1415.

  Table VIII.I.1-1--RIN Equivalence Values for Various Liquid Renewable
                                  Fuels
------------------------------------------------------------------------
                                       Energy content      Equivalence
              Fuel type                   (Btu/gal)           value
------------------------------------------------------------------------
Ethanol.............................            77,000               1.0
Biodiesel...........................           115,000               1.5
Renewable diesel....................           130,000               1.7
Butanol.............................           100,000               1.3
------------------------------------------------------------------------

    For renewable fuels that the regulations do not provide an 
equivalence value, the regulations provide a formula for calculating 
the equivalence value.
    The use of denatured fuel ethanol as the baseline gallon of 
renewable fuel for the RFS program provides a convenient and 
straightforward way to determine the equivalence value for all 
biofuels, including non-liquid biofuels. That is, 77,000 Btu of any 
biofuel can generate 1 RIN for purposes of compliance with the 
applicable standards under the RFS program. For renewable natural gas 
with an energy density of 1,000 Btu per cubic foot, one gallon of 
ethanol is equivalent to 77 cubic feet. This same basis applies to 
electricity by dividing 77,000 Btu per gallon by 3,412 Btu per kWh to 
arrive at an equivalence value of 22.6 kWh per statutory gallon.
    While the energy content-based equivalence values provide the same 
credit value for each fuel on an energy equivalent basis, they then 
also provide different values on a volumetric basis. Thus, they have a 
first order impact on the revenue renewable fuel producers receive from 
RINs. For example, at a D6 RIN value of $1.00, a gallon of corn ethanol 
receives $1.00 whereas a gallon of conventional biodiesel receives 
$1.50. At a D3 RIN value of $3.00, a gallon of cellulosic ethanol 
receives $3.00, whereas a gallon of cellulosic renewable diesel 
receives $5.10.
2. Rationale for Revision
    As discussed in Section VIII.A above, the 2016 REGS proposal 
requested comment on several eRIN-related topics, including the 
equivalence value for electricity used as transportation fuel. The 
preponderance of commenters argued that EPA should revise the 
equivalence value to allow for the generation of more eRINs for a given 
quantity of renewable electricity, which would provide greater value 
for that renewable electricity.\278\ A common argument was that a given 
quantity of biogas used to produce renewable electricity would receive 
less credit in the RFS program (fewer RINs) than if it were used as 
RNG, due the energy loss in the conversion from gas to electricity. 
Despite the addition of eRINs to the RFS program, commenters believed 
the result might still be little generation of eRINs given the far 
greater incentive for the use of the biogas as RNG if the basis for 
equivalence values (i.e., energy content of the fuel) remained 
unchanged.
---------------------------------------------------------------------------

    \278\ See docket EPA-HQ-OAR-2016-0041.
---------------------------------------------------------------------------

    Another point raised by several stakeholders is that an energy 
content-based equivalence value does not take into account the much 
greater efficiency of the electric vehicles themselves. Energy content-
based equivalence values may work well when comparing fuels that are 
all combusted in internal combustion engines, but they argued that this 
does not treat electricity appropriately given its much greater end-use 
efficiency. Here, the comments suggested refocusing credits on the 
energy efficiency of electricity generation, vehicle powertrains, or 
some combination of the two.
    Other stakeholders have asked us to address the ``point of 
measure'' (POM) issue that concerns the energy losses associated with 
electricity generation. In other words, depending on where one measures 
the energy in the eRIN generation/disposition chain, the resulting RIN 
generation is considerably different. Specifically, if one measures the 
energy at the point where the biogas feedstock is produced, more than 
three times the RIN revenue is provided than if one measures the energy 
after that same biogas is used to produce renewable electricity, even 
though there is no difference in the electrical energy produced or the 
distance an electric vehicle can travel using this energy.
    Modifying the basis for equivalence values in one or more of these 
ways could address the issues raised by stakeholders and would provide 
greater credit value for eRINs and consequently a greater incentive for 
EV and renewable electricity growth.
3. Proposed Equivalence Value for Renewable Electricity
    We are proposing to change the equivalence value for renewable 
electricity to account for system inefficiencies in both the RNG (CNG/
LNG vehicle fueling) and electricity (EV charging) supply chains to 
ensure approximately equivalent RIN generation between the two for a 
given amount of biogas. In doing so, the

[[Page 80668]]

equivalence value for RNG is not being altered. The proposed approach 
seeks to establish and maintain equivalence values for renewable 
electricity and RNG, respectively, that are consistent with the 
statutory goal of displacing petroleum-based fuels in the 
transportation sector. This approach also seeks to establish an 
equivalence value for renewable electricity that is consistent with the 
existing structure of the RFS program in which equivalence values are 
determined based on the energy content of the fuel, rather than 
attempting to account for vehicle efficiency. Relative to the existing 
equivalence value for renewable electricity this proposed change would 
allow for a greater number of RINs to be generated for renewable 
electricity. The information used to calculate the proposed equivalence 
value for renewable electricity is discussed in greater detail in DRIA 
Chapter 6.1.4.
    The POM issue is a key starting point for understanding the need to 
revise the equivalence value for renewable electricity. In general, 
parties generate RINs based on the quantity of renewable fuel supplied 
at the POM and the applicable equivalence value. Figure VIII.I.3-1 
illustrates how one unit of landfill-derived RNG energy flows through 
the supply chain to fuel either an electric vehicle (upper path) or a 
CNG/LNG vehicle (lower path), where each circle's area approximates the 
fraction of useful energy that remains after each step. The boxes 
around the fourth circle indicate the POM where the energy is 
transferred to the vehicle, either at a RNG refueling station or an EV 
charger.
[GRAPHIC] [TIFF OMITTED] TP30DE22.004

    As the diagram makes clear, this POM produces a very different 
measure of fuel energy for electricity than for RNG. In the case of 
electricity, the initial conversion of the biogas's chemical energy to 
mechanical energy occurs upstream of the POM in the EGU, and this step 
results in a significant loss of useful energy. In the case of RNG, in 
contrast, there is no upstream conversion and, while energy losses 
occur, they essentially all occur when the chemical energy in the fuel 
is converted to drive energy on board the vehicle after the POM. The 
net result of this difference is that the number of available RINs for 
EV charging is heavily discounted relative to the RNG pathway for the 
same biogas input. Thus, the existing POM significantly disadvantages 
renewable electricity relative to RNG used as renewable CNG/LNG, 
because while both supply chains experience energy losses prior to 
powering a vehicle, the relatively inefficient combustion of RNG occurs 
prior to the POM for electricity, but after the POM for direct use in a 
CNG/LNG vehicle.
    We believe this existing approach arbitrarily penalizes the use of 
biogas-derived renewable electricity and are therefore proposing to 
revise the equivalence value. Our proposed revision does not change or 
add POMs, but rather considers key steps or processes along the energy 
supply chains that significantly affect the amount of useful energy 
delivered to the transportation application. For the renewable 
electricity pathway this includes generation, transmission, and EV 
battery charging, and for the RNG pathway, compression and pipeline 
transport of the fuel. Essentially, we summed up the energy losses 
between the two POMs and incorporated those into the proposed 
electricity equivalence value in order to put them on more equitable 
footing. Figure VIII.I.3-2 summarizes this approach by overlaying 
arrows and values onto the previous diagram indicating the flow of our 
computation.
    In determining the proposed revised equivalence value, we first 
analyzed the efficiencies and losses associated with biogas used in 
CNG/LNG vehicles using information from an Argonne National Labs 
analysis of landfill gas

[[Page 80669]]

pathways \279\ and from EIA's published values on natural gas 
consumption and delivery.\280\ Production and delivery of biogas 
upgraded to RNG and used as renewable CNG/LNG includes collection of 
the biogas, purification to produce RNG, and compression processes to 
transfer it onto a pipeline and into a vehicle tank. Accounting for the 
range of data available, this analysis indicates a central estimate of 
96,100 BTU of input energy is required to deliver 1 RIN (77,000 Btu) of 
RNG to the vehicle.
---------------------------------------------------------------------------

    \279\ M. Mintz, J. Han, M. Wang, and C. Saricks, ``Well-to-
Wheels Analysis of Landfill Gas-Based Pathways and Their Addition to 
the GREET Model'', Center for Transportation Research, Energy 
Systems Division, Argonne National Laboratory. 2010. Report ANL/ESD/
10-3.
    \280\ U.S. Natural Gas Consumption by End Use, U.S. Department 
of Energy, Energy Information Administration. June 2021.
---------------------------------------------------------------------------

    We then analyzed the efficiencies and losses associated with 
converting 96,100 BTU of biogas energy into electricity for delivery to 
an EV. Starting with the assumption that the electrical generation unit 
(EGU) would draw the raw biogas (same assumption for the 96,100 BTU as 
input for RNG), we applied a factor of 28.8 percent for EGU thermal 
efficiency and 5.3 percent for transmission line losses based on 
information in EPA's eGRID database.\281\ A literature review on EV 
charging efficiencies is presented in DRIA Chapter 6.1.4.4, and 
suggests a charging efficiency range of 80-90 percent for common EV 
charging configurations. Overall, we derive a central estimate of 
22,300 BTU of electrical energy delivery to the vehicle battery in 
correspondence to 1 RIN of biogas energy delivery to a CNG/LNG vehicle. 
Dividing this value by 3,412 Btu/kWh to convert to kilowatt-hours 
produces an equivalence value of 6.5 kWh per RIN. We propose that this 
revised equivalence value for renewable electricity produced from 
biogas would replace the value of 22.6 kWh per RIN that is currently in 
the regulations. A more detailed discussion of the derivation of the 
6.5 kWh equivalence value is available in DRIA Chapter 6.1.4.4.
---------------------------------------------------------------------------

    \281\ eGRID 2019 Technical Guide, prepared by Abt Associates for 
U.S. EPA Clean Air Markets Division, February 2021.
[GRAPHIC] [TIFF OMITTED] TP30DE22.005

    In addition to our proposed approach, we also considered the 
alternative approaches suggested in comments on the REGS rule. One 
potential alternative considered was to change the POM for electricity 
such that it occurs prior to electricity generation (placing the POM 
box in Figure VIII.I.3-2 around or just after the first circle). This 
would allow for the same number of RINs to be generated for biogas 
whether it is used in CNG/LNG vehicle or in generating renewable 
electricity without increasing the equivalence value for electricity. 
However, there are several downsides to changing the POM for 
electricity. First, allowing RIN generation for electricity on the 
basis of the biogas used to produce the electricity could create 
difficulty in matching RIN generation (which would be done on the basis 
of biogas production) and use of the fuel as transportation fuel (which 
would be a measure of electricity used to charge an EV). Second, in 
years for which the use of electricity as transportation fuel is the 
limiting factor for RIN generation, using biogas consumption for 
electricity generation as the basis for RIN generation would favor less 
efficient electricity generators, as these parties would combust higher 
quantities of biogas (and thus generate more RINs) for the same 
quantity of electricity used as transportation fuel.
    We also considered an equivalence value based on the efficiency of 
an electric vehicle relative to a vehicle with an internal combustion 
engine. Conceptually this approach would seek to give a similar number 
of RINs to renewable fuels that transport a vehicle the same distance. 
For example, this approach would seek to provide a similar quantity of 
RINs for fuel that powers a vehicle for 100 miles, whether that fuel 
was RNG or electricity. By taking into account the much higher

[[Page 80670]]

efficiency of an electric motor relative to an internal combustion 
engine, this approach would offset the disadvantage of measuring 
renewable electricity after biogas has been combusted. This approach, 
however, would be a significant departure from the existing structure 
of the RFS program, which currently does not take vehicle efficiency 
into account when determining the number of RINs generated per gallon 
of renewable fuel. The same number of RINs are generated for biofuels 
used in all vehicles, whether those vehicles are relatively efficient 
or inefficient. Further, accounting for the efficiency of a vehicle in 
the equivalence value of a fuel would introduce significant complexity 
into an already complex eRIN program. To do so we would either need to 
determine a single equivalence value that reflects an average of the 
wide variety of electric vehicle efficiencies, or alternatively, use 
different equivalence values for different vehicles or categories of 
vehicles.
    While we are not proposing to use this approach to determine the 
equivalence value for electricity, we note that equivalence values 
suggested by others using such an approach are similar to our proposed 
value. For example, the International Council on Clean Technologies, in 
their comments on the REGS rule, suggested a value of 5.24 kWh per RIN. 
The California LCFS program uses a different structure for credit 
generation that provides an energy equivalence ratio multiplier to 
account for the higher efficiency of electric vehicles. Applying 
California's multiplier for light-duty vehicles (3.4) to the existing 
RFS equivalence value of 22.4 kWh per RIN produces an equivalence value 
of 6.6 kWh per RIN.
    We request comment on our proposed approach to revising the 
equivalence value for electricity. Additionally, we request comment on 
the threshold issues of whether to change the equivalence value for 
electricity in the first instance and, if so, what approach should be 
used and what the new equivalence value should be. We invite commenters 
to submit any relevant data that would help inform the equivalence 
value for electricity.

J. Regulatory Structure and Implementation Dates

1. Structure of the Regulations
    Due to the comprehensive nature of the proposed eRIN provisions, we 
believe that it makes sense to create 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 proposing to create a new subpart E in 
40 CFR part 80. This new subpart would include provisions not only for 
biogas and RNG used to produce renewable electricity, but also for 
other biogas-derived renewable fuels including biogas used in CNG/LNG 
vehicles and cases where biogas is used as a biointermediate. Existing 
provisions for these fuels under subpart M would be moved into the new 
subpart E.
    Based on our general approach adopted in the Fuels Regulatory 
Streamlining Rule,\282\ we are proposing to structure the new subpart 
for biogas-derived renewable fuels as follows:
---------------------------------------------------------------------------

    \282\ See 85 FR 78415-78416 (December 4, 2020).
---------------------------------------------------------------------------

     Identify general provisions (e.g., implementation dates, 
definitions, etc.);
     Articulate the general requirements that apply to parties 
regulated under the subpart (e.g., biogas producers, renewable 
electricity generators, and renewable electricity RIN (eRIN) 
generators); and then
     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 would 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.
2. Implementation Dates
    As described in Section VIII.E.4, we are proposing to allow for 
eRIN generation to begin January 1, 2024. In order to accommodate eRIN 
generation on January 1, 2024, we are proposing to begin implementation 
of the eRINs provisions as soon as the rule is effective (anticipated 
to be 60 days after publication of the final rule in the Federal 
Register). This means that we would begin accepting registration 
submissions for parties that elect to participate in the proposed eRINs 
program beginning 60 days after publication of the final rule in the 
Federal Register. However, while we would begin accepting registration 
upon the effective date of the final rule, for the reasons described in 
Section VIII.E.4, we believe that the generation of eRINs cannot 
reasonably begin at this time.
    We recognize that due to the large number of parties that may want 
to register to produce biogas and renewable electricity to generate 
RINs for renewable electricity used for transportation, these parties 
may have difficulty in arranging for third-party engineering reviews, 
preparing registration submissions, and having EPA process and accept 
those registration materials prior to January 1, 2024. For instance, 
based on EPA's Landfill Methane Outreach Program (LMOP) data, we 
believe there are currently somewhere between 400 and 600 landfills in 
the U.S. that may be capable of registering in order to use the biogas 
they produce for the purpose of eRIN generation.\283\ Additionally, 
according to EPA's AgSTAR data, we believe there are somewhere between 
100-200 agricultural digester-to-renewable electricity generation 
projects.\284\ We believe it is possible that some facilities that are 
able to produce qualifying biogas or renewable electricity may not be 
able to complete all the necessary steps that would allow EPA to accept 
that registration before January 1, 2024. If we do not provide 
flexibility for the delayed generation of eRINs, we would limit the 
near-term generation of eRINs to only those parties that submitted 
their registrations first, despite other parties producing qualifying 
biogas and renewable electricity. We believe this would ultimately 
create an unlevel playing field whereby only some, typically larger, 
renewable electricity generators would be able to start generating 
eRINs on January 1, 2024, while others would not. We believe that 
larger renewable electricity generators would be unfairly advantaged 
because they would be more able to pay a premium for third-party 
engineers to conduct site visits and hire consultants to prepare and 
submit registration materials. This would additionally make our 
estimation of eRIN generation during the first year of the program 
difficult and undermine certainty in the proposed volumes.
---------------------------------------------------------------------------

    \283\ For more basic information on landfill gas energy projects 
included in the LMOP data, see https://www.epa.gov/lmop/basic-information-about-landfill-gas.
    \284\ For more information on agricultural digester to 
electricity projects included in AgSTAR data, see https://www.epa.gov/agstar/livestock-anaerobic-digester-database.
---------------------------------------------------------------------------

    To address this potential scenario, we are proposing a temporary 
flexibility with regard to the acceptance of registrations related to 
eRINs. Under the current RFS regulations, we do not allow a party to 
generate RINs until after EPA has accepted its registration. Applying 
this to the start of eRINs would mean that in order for an eRIN to be 
generated, all three core parties (i.e., the biogas producer supplying 
the biogas, the renewable electricity generator generating the 
renewable

[[Page 80671]]

electricity, and the light-duty OEM generating the eRIN) must complete 
registration by January 1, 2024. Given the challenges associated with 
this at the program startup we are proposing that OEMs would be 
permitted to generate eRINs for renewable electricity produced from 
qualifying biogas produced from January 1, 2024 through April 30, 2024, 
without the associated biogas producers and renewable electricity 
generators having an EPA-accepted registration so long as all of the 
following conditions are met:
     The biogas producer submitted a registration request with 
a third-party engineering review report to EPA no later than December 
31, 2023.
     The renewable electricity generator submitted a 
registration request with a third-party engineering review report to 
EPA no later than December 31, 2023.
     Neither the biogas producer nor renewable electricity 
generator substantially alters their facilities after the third-party 
engineering review site visit.
     The biogas was produced after the third-party engineering 
review site visit.
     The renewable electricity generator contracted with the 
eRIN generator for the RIN generation allowance from their renewable 
electricity prior to January 1, 2024.
     The renewable electricity was generated between January 1, 
2024, and March 31, 2024.
     The biogas producer, renewable electricity generator, and 
eRIN generator meet all applicable requirements under the RFS program 
for the biogas, renewable electricity, and RINs.
     EPA accepts the registrations for the biogas producer and/
or the renewable electricity generator by April 30, 2024.
    Under this proposal, parties would essentially have until the first 
quarterly RIN generation deadline in 2024 for EPA to accept their 
registration submission. Under this proposal, this would be 30 days 
after the end of the first quarter in 2024, or April 30, 2024. We 
believe this is enough time for EPA to reasonably approve all timely 
registration submissions. We have adopted flexibilities to address 
similar concerns in the past. For example, in 2010 we provided 
flexibilities for delayed RIN generation while EPA transitioned from 
RFS1 to RFS2 and when EPA was in the process of approving new 
pathways.\285\
---------------------------------------------------------------------------

    \285\ 75 FR 76790 (December 9, 2010).
---------------------------------------------------------------------------

    We note that if EPA does not accept registration materials needed 
for the generation of eRINs from a biogas producer or renewable 
electricity generator by April 30, 2024, the OEM would not be able to 
generate RINs. We also note that parties that do not meet the 
conditions of this proposal would still be able to register to generate 
eRINs, but their biogas or renewable electricity would not be able to 
take advantage of this proposed flexibility. Instead, OEMs could rely 
on the biogas or renewable electricity for eRIN generation only after 
EPA has accepted the registrations for the biogas producer and/or 
renewable electricity generator.
    We seek comment on our proposal to begin implementation on the 
effective date of the rule and begin eRIN generation for renewable 
electricity produced from qualifying biogas on January 1, 2024. We also 
seek comment on our proposal to allow RIN generation for the first 
quarter of 2024 under certain circumstances to provide more time for 
parties and EPA to process registration submissions related to eRINs. 
We are particularly interested in whether EPA should provide more time 
for parties to submit and EPA to accept eRIN related registration 
submissions.

K. Definitions

    We are proposing definitions of the various regulated parties, 
their facilities, and the products related to the production of biogas-
derived renewable fuels. We are also proposing to define other terms as 
necessary for clarity and consistency. We are also proposing to move 
and consolidate all defined terms for the RFS program from 40 CFR 
80.1401 to 40 CFR 80.2. We are doing this because we moved all of the 
non-RFS fuel quality regulations from 40 CFR part 80 to 40 CFR part 
1090 as part of our Fuels Regulatory Streamlining Rule.\286\ As such, 
it is no longer necessary to have a separate definitions section for 40 
CFR subpart M, as only requirements related to the RFS program are 
housed in 40 CFR part 80. We are not proposing to change the meaning of 
the terms moved from 40 CFR 80.1401 to 40 CFR 80.2, but are simply 
relocate them to consolidate the definitions that apply to RFS in a 
single location. For these relocated terms, we are not proposing to 
amend their meaning and any comments on the relocated terms will be 
considered beyond the scope of this rulemaking. We are proposing to add 
any newly defined terms under this proposal to 40 CFR 80.2.
---------------------------------------------------------------------------

    \286\ 85 FR 78417-78420 (December 4, 2020).
---------------------------------------------------------------------------

    For parties regulated under the proposed eRIN and biogas regulatory 
reform provisions (the latter discussed in Section IX.I), we are 
proposing several new terms to specify which persons and parties are 
subject to the proposed regulatory requirements in a manner that is 
consistent with our approach under our other fuel quality and RFS 
regulations. For example, we are proposing that a biogas producer would 
be any person who owns, leases, operates, controls, or supervises a 
biogas production facility, and a biogas production facility would be 
any facility where biogas is produced from renewable biomass that 
qualifies under the RFS program. We propose the same framework for RNG 
producers and renewable electricity generators. We are proposing to 
define the eRIN generator, i.e., a light-duty OEM, as any OEM of light-
duty vehicles or light-duty trucks who generates RINs for renewable 
electricity.
    Under the existing 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 
proposing specific definitions for biogas-derived renewable fuel, 
biogas (or raw biogas), biomethane, and renewable natural gas (RNG). 
These new terms would apply to the proposed eRINs program as well as 
the biogas regulatory reform provisions discussed in Section IX.I.
    Because ``biogas'' is often used to broadly mean any renewable fuel 
used in the transportation sector that has its origins in biogas, we 
are proposing a more descriptive and inclusive term of ``biogas-derived 
renewable fuel.'' Under this proposal, biogas-derived renewable fuels 
would include renewable CNG, renewable LNG, renewable electricity, or 
any other renewable fuel that is produced from biogas or its pipeline-
quality derivative RNG now or in the future.
    Under this proposal, we would define biogas (sometimes referred to 
as raw biogas) as a mixture of biomethane, inert gases, and impurities 
that is produced through the anaerobic digestion of organic matter 
prior to any treatment to remove inert gases and impurities or adding 
non-biogas components. We have proposed to update this definition to 
make more explicit that this definition refers to the biogas collected 
at landfills or through a digester before that biogas is either 
upgraded to produce RNG or is used to make a

[[Page 80672]]

biogas-derived renewable fuel, which was intended but not stated in the 
previous definition.
    We are proposing to define biomethane as exclusively methane 
produced from renewable biomass (as defined in 40 CFR 80.1401). We 
believe a separate definition for biomethane is important because 
biomethane (exclusive of impurities, inert gases often found with 
biomethane in biogas) is what renewable electricity and eRIN generation 
is based on. In order to ensure the appropriate measurement of 
biomethane for RIN generation for RNG, we have issued guidance under 
the existing regulations that cover cases where non-renewable 
components are added to biogas.\287\
---------------------------------------------------------------------------

    \287\ 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.
---------------------------------------------------------------------------

    To describe biogas-derived pipeline-quality gas, we are proposing 
to adopt a term now in common use, renewable natural gas or RNG. Under 
this proposal, in order to meet the definition of RNG, the product 
would need to meet 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.
     The gas must be designated for use to produce a biogas-
derived renewable fuel.
    We are proposing that RNG must contain at least 90 percent 
biomethane content because we believe this is 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 do, however, seek comment on whether a different 
biomethane content would be more appropriate.
    EPA's existing 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.\288\ We are proposing to 
codify this guidance in our regulations as part of the proposed 
definition of RNG. As a result, registration submissions for RNG under 
the RFS program would require the submission of these pipeline 
specifications and we are proposing a definition of RNG that would 
require gas to meet those pipeline specifications.
---------------------------------------------------------------------------

    \288\ 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 also proposing that RNG be defined such that it only meets 
the definition if the gas is designated for use to produce a biogas-
derived renewable fuel under the RFS program. We are proposing 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. We believe such an 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.
    We have incorporated the use of these new proposed definitions in 
both the new 40 CFR part 80, subpart E proposed regulations for biogas 
derived renewable fuels, and 40 CFR part 80, subpart M where 
applicable. We seek comment on these proposed definitions and on 
whether there are other terms that we should define. If suggesting a 
newly defined term, commenters should also provide a suggested 
definition for that term.

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

    We are proposing compliance provisions necessary to ensure that the 
production, distribution, and use of biogas, renewable electricity, and 
eRINs are consistent with Clean Air Act requirements under the RFS 
program. These proposed compliance provisions include registration, 
reporting, PTDs, and recordkeeping requirements. We discuss each of 
these compliance provisions below.
1. Registration
    Under the RFS program, we require biointermediate and renewable 
fuel producers 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 initially 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 RINs.
    To that end, we are proposing that biogas producers, renewable 
electricity generators, eRIN generators, and RNG producers would be 
required to register with EPA prior to participation in the RFS 
program. Under this proposal, biogas producers, RNG producers, and 
renewable electricity generators would have to submit information that 
demonstrates that their facilities are capable of producing biogas, 
RNG, or renewable electricity from renewable biomass under an EPA-
approved pathway. This information would include the feedstocks that 
the producer or generator intends to use, the process through which the 
feedstock is converted into biogas, RNG, or electricity, and any other 
information necessary for EPA to determine whether biogas, RNG, or 
electricity were produced in a manner consistent with Clean Air Act and 
EPA's regulatory requirements. Such information is necessary to ensure 
that eRINs are generated only for renewable electricity generated from 
qualifying biogas. Biogas producers, RNG producers, and renewable 
electricity generators would also have to 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, RNG, or renewable electricity to help identify 
potential fraud. Like biointermediate production and renewable fuel 
production facilities, we are proposing that biogas production, RNG 
production,\289\ and renewable electricity facilities 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, RNG, or renewable electricity consistent 
with Clean Air Act and EPA regulatory requirements.
---------------------------------------------------------------------------

    \289\ See 40 CFR 80.1450(b)(2).
---------------------------------------------------------------------------

    Under this proposal, like other RIN generators, OEMs that want to 
generate eRINs would have to register with EPA under the RFS program to 
be able to generate and transact RINs in EMTS and to submit required 
periodic reports. We

[[Page 80673]]

are also proposing that, in addition to basic registration information 
for the company required of all registrants under EPA's fuel 
programs,\290\ OEMs would have to submit information to EPA for their 
anticipated light-duty electric vehicle fleet size and disposition. 
This information is needed to serve as a baseline for total potential 
eRIN generation and would be used by EPA and third parties to evaluate 
whether OEMs generate an appropriate amount of eRINs based on the 
amount of renewable electricity that an OEM can demonstrate was used in 
its light-duty electric vehicle fleet as discussed in Section VIII.F.5. 
OEMs would update their light-duty electric vehicle fleet size and 
disposition information via the quarterly reporting requirements 
discussed in Section VIII.N.2.
---------------------------------------------------------------------------

    \290\ For basic registration information, see 40 CFR 1090.805.
---------------------------------------------------------------------------

    We are also proposing that biogas producers, renewable electricity 
generators, and OEMs 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. As discussed in Section VIII.F, biogas producers that 
directly supply a renewable electricity generation facility with biogas 
through a private, closed pipeline would need to associate with that 
renewable electricity generation facility via their registration with 
EPA and must supply their biogas to the associated renewable 
electricity generation facility. Similarly, for each renewable 
electricity generation facility, renewable electricity generators would 
have to associate with the OEM to which they have established their RIN 
generation agreement. We are proposing that this be monitored via 
registration because our registration system is currently set up to 
track these kinds of relationships. Similarly, for renewable 
electricity generators, we propose to track the association related to 
the transfer of RIN generation agreement to OEMs via the registration 
process.
    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 
VIII.L.2) would have to 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 
would have to register in accordance with existing requirements under 
40 CFR parts 1090 and 80 using forms and procedures specified by EPA. 
We are not proposing changes to this existing requirement.
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 
biogas-derived renewable CNG/LNG in 40 CFR 80.1451. We are proposing 
similar reporting requirements for biogas producers, renewable 
electricity generators, eRIN generators, and RNG producers.
    For biogas producers, we are proposing quarterly batch reports that 
would 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 would break 
down each batch by D-code, by digester, and by designated use of the 
biogas. The designated use of the biogas includes whether the biogas 
would be used to make renewable CNG/LNG via a closed, private pipeline 
system; RNG; on-site renewable electricity; or other use as a 
biointermediate. This information is necessary for us 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. We need the information at the digester level for each biogas 
facility because we have determined, based on our current 
registrations, that some biogas production facilities have multiple 
digesters that produce biogas using different D-codes for different end 
uses. Without reported data at this level, it would be difficult if not 
impossible for third-party auditors and EPA to conduct effective audits 
of the facility. Additionally, Biogas producers will enter these 
quarterly batch reports directly into EMTS and transfer each batch to a 
renewable electricity generator in EMTS. This improved electronic 
reporting process is intended to improve the quality of information, 
enable better information sharing between parties, including third-
party auditors, and define a structured reporting process.
    For renewable electricity generators, we are proposing quarterly 
reports to support the amount of renewable electricity generated from 
qualifying biogas. Under these quarterly reports, renewable electricity 
generators would report the amount and energy content of biogas or RNG 
used to produce renewable electricity and the quantity of renewable 
electricity generated and placed onto the commercial electric grid 
serving the conterminous U.S. Renewable electricity generators would 
break down the quantity of renewable electricity generated by month, by 
EGU, and D-code. Renewable electricity generators would also need to 
identify which electricity is attributed to their designated OEM. For 
RNG co-processed with natural gas, we would require that renewable 
electricity generators report the amount of natural gas feed used to 
help ensure that eRINs are not generated for non-renewable electricity. 
Similar to the biogas reports, these reporting requirements are 
necessary to demonstrate the amount of renewable electricity produced 
from qualifying biogas, to describe the amount of renewable electricity 
placed on the commercial electric grid serving the contiguous U.S., and 
to help track which quantities of renewable electricity were supplied 
to eRIN generators. Similar to the reporting procedure for biogas 
producers, renewable electricity generators will enter these batch 
reports into EMTS and transfer the batch information to the OEM in 
EMTS. A batch of renewable electricity entered into EMTS would be 
directly connected to a corresponding amount of biogas batches within 
the renewable electricity generator's EMTS holdings. This process will 
ensure the batch information has been properly reported and transferred 
between parties. The reports would also serve as the basis for third-
party verification and EPA audits to help ensure the validity of eRINs.
    Under our proposal, OEMs that participate in the program as eRIN 
generators would be subject to all applicable reporting requirements 
for RIN generators under the current program. These requirements would

[[Page 80674]]

include the RIN generation reports,\291\ RIN transaction reports,\292\ 
and the RIN activity reports.\293\ Prior to the generation of any RINs, 
OEMs would also be required to receive the corresponding transfer of 
the renewable electricity batches in EMTS demonstrating the renewable 
electricity batch was transferred and reporting requirements were 
completed. As the RIN generator, the OEMs would also be responsible for 
generating RINs in EMTS as well as separating and transacting the 
RINs.\294\ These reporting requirements are necessary to allow for the 
generation of eRINs and are required of any party that generate RINs 
under the RFS program.
---------------------------------------------------------------------------

    \291\ See 40 CFR 80.1451(b)(1)(ii).
    \292\ See 40 CFR 80.1451(b)(2) and (c)(1).
    \293\ See 40 CFR 80.1451(b)(3) and (c)(2).
    \294\ Requirements related to the generation, separation, and 
transaction of RINs in EMTS are described at 40 CFR 80.1452.
---------------------------------------------------------------------------

    In addition to the reporting needed to administer the generation, 
separation, and transaction of RINs, we are proposing two additional 
reporting requirements for OEMs that generate eRINs. First, OEMs would 
be required to report quarterly their light-duty EV fleet size and 
disposition. Because we expect these data to change quarterly and the 
data serve as the basis for eRIN generation, it is necessary for OEMs 
to update this information to ensure that the appropriate number of 
eRINs are generated for each OEM's light-duty electric vehicle fleet. 
Furthermore, these reports would serve as the basis for compliance 
oversight by EPA and third parties. The quarterly fleet size and 
disposition reports would include the actual fleet totals and 
characteristics for their fleet by make, model, year, and trim.\295\ We 
are proposing that the reported fleet characteristics would include the 
eVMT, efficiency, and charging efficiency. This information is needed 
to demonstrate that the appropriate amount of renewable electricity 
from qualifying biogas was used as transportation fuel in the OEM's 
light-duty electric vehicle fleet and, as discussed in Section 
VIII.F.6, help refine the assumed values for eRIN generation over time.
---------------------------------------------------------------------------

    \295\ For purposes of this preamble, a vehicle's trim refers to 
the different versions of a model that an OEM produces in a given 
year. Sometimes, OEMs manufacture a vehicle model that includes 
different trims for an ICE, PHEV, and EV version of the same model.
---------------------------------------------------------------------------

    We note that we are also proposing new reporting requirements for 
RNG producers. These reporting requirements are described in more 
detail in Section IX.
    In addition to seeking comment on these reporting provisions, we 
also seek comment on the draft reporting forms that have been added to 
the docket.\296\
---------------------------------------------------------------------------

    \296\ ``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.
---------------------------------------------------------------------------

3. Product Transfer Documents (PTDs)
    We are proposing product transfer documents (PTDs) for transfers of 
title for biogas and for transfers of data regarding the generation of 
renewable electricity between renewable electricity generators and 
OEMs. We have historically used PTDs to create a record trail that 
demonstrates the movement of product 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.\297\ PTDs are important for 
biogas and eRINs as they are necessary to document that qualifying 
biogas was transferred between biogas producers and renewable 
electricity generators and to ensure that eRIN generators receive 
necessary information concerning the amount of renewable electricity 
placed onto the commercial electric grid serving the contiguous U.S. 
for transportation use. EPA and third parties would also review PTDs to 
help verify the eRINs were validly generated.
---------------------------------------------------------------------------

    \297\ The PTD requirements for RFS are described at 40 CFR 
80.1453.
---------------------------------------------------------------------------

    For biogas transfers to renewable electricity generators, we are 
proposing that PTDs accompany transfers of title for biogas from biogas 
producers to renewable electricity generators. These PTDs would include 
information related to the transferer and transferee, a designation 
that the biogas is intended for use to produce renewable electricity, 
the amount of biogas being transferred, and the date that title of the 
biogas was transferred. These proposed 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.
    We note that under this proposal, no PTDs would be necessary when 
biogas is transferred between a biogas production facility and a co-
located renewable electricity generation facility as long as the same 
party maintains title of the biogas and owns and operates both 
facilities. We also note that these PTDs would not be required in cases 
where title to RNG is being transferred between RNG producers and 
renewable electricity generators. This is because, as discussed in 
Section IX.I, RINs are generated upon the production of RNG, and the 
transfer of those RINs then serves the function that the PTD would 
otherwise serve. The proposed generation of RINs for RNG and associated 
PTD requirements are discussed in Section IX.I, which addresses our 
proposed biogas regulatory reform.
    For transfers of information related to the generation of renewable 
electricity, we are proposing that renewable electricity generators 
would create and transfer PTDs quarterly to OEMs for the amount of 
renewable electricity introduced onto the commercial electric grid 
serving the contiguous U.S. for the quarter. These proposed PTDs would 
include similar information to other PTDs required under the RFS 
program and the proposed biogas PTDs described above. This would 
include information regarding the transferer and transferee of the 
information related to the generation of renewable electricity, the 
amount of renewable electricity introduced onto the commercial electric 
grid serving the contiguous U.S., and a statement certifying that the 
renewable electricity was introduced onto the commercial electric grid 
serving the contiguous U.S. We are proposing these PTDs be transferred 
quarterly to align with the proposed RIN generation procedures in 
Section VIII.L.3.
    We note that all other applicable PTD requirements under 40 CFR 
part 80 would apply. For example, after OEMs have generated and 
separated RINs for renewable electricity, the OEMs would still need to 
transfer PTDs for the separated RINs when they sell those RINs to other 
parties. We seek comment on the proposed PTD requirements for biogas 
and renewable electricity.
4. Recordkeeping
    We are proposing recordkeeping requirements for biogas producers, 
renewable electricity generators, and eRIN generating OEMs. 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 proposing to continue to require 
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

[[Page 80675]]

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. Specific to eRINs, we are proposing 
that biogas producers keep PTDs to support the fact that the biogas was 
transferred to renewable electricity generators.
    For renewable electricity generators, we are proposing 
recordkeeping requirements consistent with other parties that produce 
renewable fuels under the RFS program. Similar to the proposed 
requirements for biogas producers, this would include information and 
documentation needed to support that the renewable electricity was 
produced from qualifying biogas or RNG, copies of all registration 
information, copies of all reports, and copies related to the 
measurement of renewable electricity transmitted onto the commercial 
electric grid serving the contiguous U.S. Renewable electricity 
generators that use RNG to produce renewable electricity would also 
have to maintain records related to separating RINs from the RNG as 
discussed in more detail in Section IX.I.
    For OEMs, we are proposing recordkeeping requirements consistent 
with those of other RIN generators under the current RFS program. These 
records would include information received from the renewable 
electricity generator related to the amount of renewable electricity 
introduced onto the commercial electric grid serving the contiguous 
U.S., copies of contracts between the renewable electricity generator 
and the OEM to support the use of the renewable electricity generator's 
renewable electricity for RIN generation, and copies of all RIN 
generation records and reports. We would also require that OEMs keep 
copies of all calculations for RIN generation as well as any EMTS-
related records for the generation and transaction of RINs. These 
records are needed to help ensure that eRINs are generated only for 
renewable electricity derived from qualifying biogas and used as 
transportation fuel.
    Under the RFS program, parties that participate in the RFS QAP must 
maintain records related to their participation in the RFS QAP program 
which includes copies of contracts between the regulated party and the 
QAP auditor, copies of any records related to verification activities 
under the RFS QAP, and copies of any QAP-related submissions. For the 
proposed eRINs program, the recordkeeping requirements would similarly 
apply to parties in the eRINs generation/disposition chain that 
participate in the RFS QAP program. We describe in more detail how we 
propose the RFS QAP would work for eRINs in Section VIII.P.
    We believe these proposed recordkeeping requirements for parties 
regulated under the proposed eRINs program are necessary to ensure 
proper program implementation and oversight. We seek comment on these 
proposed recordkeeping requirements and whether any additional 
recordkeeping requirements should be imposed as part of the proposed 
program.

M. Testing and Measurement Requirements

    We are proposing to specify testing and measurement procedures for 
biogas, RNG, and renewable electricity. 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 generated more renewable electricity, and thus RINs, 
than would be appropriate. By establishing clear and consistent testing 
and measurement requirements, we can ensure the validity of RINs and a 
level playing field for RIN generators. We separately discuss the 
testing and measurement considerations for biogas and RNG and renewable 
electricity below.
1. Testing and Measurement Requirements for Biogas and RNG
    For the measurement of biogas and RNG, we are proposing to 
incorporate currently published guidance into the regulations.\298\ 
Under this guidance, for RIN generation purposes, we specified that 
parties should use in-line gas chromatography (GC) meters that provide 
continuous readings to measure the energy content in BTUs of the biogas 
after treatment to remove inert gases (e.g., nitrogen and carbon 
dioxide) and other contaminants (e.g., hydrogen sulfides, total sulfur 
and siloxanes) and before the biogas or RNG is injected into a 
commercial distribution pipeline. Also under the guidance, we allow for 
parties to submit for EPA-approval as part of a registration submission 
an alternative sampling protocol that would properly measure the energy 
content of the biogas after treatment. Biogas and RNG producers would 
submit as part of their registrations whether they were using in-line 
GC meters or an alternative sampling protocol. We would not require 
parties with already-approved alternative sampling protocols to 
resubmit those approvals under this proposal.
---------------------------------------------------------------------------

    \298\ ``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.
---------------------------------------------------------------------------

    Similarly, we are also incorporating into the proposed regulations 
the existing guidance related to analytical testing for the 
registration of biogas and RNG for use in the production of a biogas-
derived renewable fuel.\299\ Under the current guidance, any party 
registering to produce renewable CNG or renewable LNG from biogas 
injected into a commercial pipeline must describe the technology being 
used to treat the biogas to get the biogas to pipeline quality prior to 
blending with non-renewable fuel streams, and must demonstrate that 
this technology is successful by submitting a certificate of analysis 
(COA) from an independent laboratory. Specifically, the party that 
registers must supply the following at registration:
---------------------------------------------------------------------------

    \299\ ``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.
---------------------------------------------------------------------------

     A COA for a representative sample of the raw biogas 
produced at the digester or landfill;
     A COA for a representative sample of the ``cleaned up'' 
biogas after treatment;
     A COA for a representative sample of the biogas after 
blending with non-renewable gas (if the biogas is blended with non-
renewable gas prior to injection into a pipeline);
     Specifications for the commercial distribution pipeline 
into which the RNG will be injected;
     Summary table with the results of the three COAs and the 
pipeline specifications (converted to the same units); and
     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.
    The COAs must report 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 specifying specific standards that must be used when 
measuring biogas properties. These

[[Page 80676]]

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. We are seeking comment on the proposed standards 
as well as any additional standards that would ensure biogas properties 
are accurately measured. 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). We allow parties that cannot obtain the COAs to make an 
alternative demonstration for biogas and RNG quality during the 
registration process if they can demonstrate that the alternative 
demonstration is similarly robust to independent laboratory analysis.
    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 proposing to 
codify the recordkeeping requirements for the testing and measurement 
of biogas and RNG as well as the requirement that third parties verify 
this information mentioned in the guidance.\300\
---------------------------------------------------------------------------

    \300\ ``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 specifying additional measurement requirements for RNG 
that is trucked to a gas pipeline interconnect. In this situation, we 
are proposing that 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 generated from biomethane.
    We do not believe these proposed requirements would impose any 
additional burden on currently registered parties as the proposed 
requirements are in line with existing guidance and we believe all 
current registrants for biogas have indicated that they comply through 
their registrations. We seek comment on this proposed inclusion of the 
current biogas guidance into the regulations.
2. Metering Requirements for Renewable Electricity
    For the measurement of renewable electricity transmitted to the 
grid, we are proposing that facilities use revenue grade meters that 
meet the requirements of ANSI C12.20-15.\301\ Under the NTTAA, we are 
required to specify industry standards when appropriate, and we believe 
this standard is appropriate considering our need to ensure consistent, 
quality measurement of renewable electricity for RIN generation. Under 
this proposal, we would ask that third-party engineers verify that 
meters at renewable electricity facilities meet ANSI C12.20-15 as part 
of third-party engineering reviews. We are also proposing that the 
facilities keep records of the calibration and maintenance of meters 
that would also be part of 3-year registration updates and RFS QAP 
verification.
---------------------------------------------------------------------------

    \301\ See ANSI C12.20-20, ``Electricity Meters 0.2 And 0.5 
Accuracy Classes,'' available in the docket for this action.
---------------------------------------------------------------------------

    We recognize that many current electricity projects may not have 
revenue grade meters and that it may take time for these renewable 
electricity generators to install compliant meters. Therefore, we seek 
comment on whether there are alternative metering standards for 
renewable electricity or whether we should provide an alternative 
approval process if the renewable electricity generator can demonstrate 
that the alternative measurement method is as valid as ANSI C12.20-15. 
We also seek comment on whether we should temporarily allow alternative 
measurement methods for a period to let renewable electricity 
generators have enough time to install revenue grade meters and, if so, 
what temporary alternative measurement methods should be allowed.

N. RFS Quality Assurance Program (QAP)

    We are proposing changes to the RFS QAP provisions to allow for 
verification of eRINs. The RFS QAP provides for auditing of 
biointermediate and renewable fuel production facilities by independent 
third-party auditors who review feedstock, process, and RIN generation 
elements to determine if renewable fuel production and RIN generation 
is consistent with EPA requirements. Once having gone through this 
process, the RINs generated are considered to be QAP verified (often 
referred to as a Q-RIN). The current RFS QAP provisions do not include 
the specific elements that we believe would be necessary to verify the 
entire eRIN generation/disposition chain.
    Under this proposal, the biogas production, renewable electricity 
generation, and eRIN generation would all need to be verified to 
generate a verified eRIN (i.e., Q-RIN). This would mean that the QAP 
auditor would have to have a pathway specific plan approved for all 
three parties in the eRINs production chain. As with the similar case 
of biointermediates where multiple parties are in the chain, the same 
QAP auditor would be required to conduct verification of all three 
facilities in order for the eRIN to be Q-RINs. We believe that this is 
necessary to provide the level of assurance that is expected from the 
RFS QAP. If we allowed the eRIN generator to generate Q-RINs without 
also verifying the biogas production and renewable electricity 
generation, it could undermine the level of compliance assurance 
provided by the QAP process.
    We are not proposing mandatory participation in the RFS QAP for 
parties that participate in the proposed eRINs program. We do not 
believe that such a requirement is necessary due to the nature of the 
proposed eRINs regulatory program. We note that this contrasts with the 
recently finalized biointermediates program.\302\ For the 
biointermediates program, we expressed significant concerns over the 
double generation of RINs from a biointermediate, which is often 
indistinguishable from renewable fuel, and a renewable fuel. In such 
cases, a party could generate a RIN for the biointermediate and a 
separate party could generate a RIN for a renewable fuel made from the 
biointermediate. We also had concerns with biointermediates being 
adulterated with non-qualifying feedstocks in route to the renewable 
fuel production facility. Therefore, on balance we believed that 
mandatory QAP participation was necessary to mitigate these concerns.
---------------------------------------------------------------------------

    \302\ 87 FR 39600 (July 1, 2022).
---------------------------------------------------------------------------

    We do not have the same concerns with the proposed eRINs program. 
As discussed in Section VIII.P.1.d, we have two main concerns regarding 
the generation of invalid eRINs: the double-counting of the biogas or 
RNG (e.g., one party generates a RIN for the biogas for use as 
renewable CNG and then another party claims the same volume of biogas 
was used to make renewable electricity) and the double-counting of 
renewable electricity to generate multiple eRINs (e.g., one party 
claims an amount of renewable electricity through one set of data to 
generate eRINs and another party

[[Page 80677]]

claims the same amount of renewable electricity through a different set 
of data to generate additional eRINs). For the biogas and RNG that 
would be used to produce renewable electricity, we believe the proposed 
biogas regulatory reform provisions discussed in Section IX.I would 
address most of our double-counting and double-RIN generation concerns. 
Tracking the movement and use of RNG through assigned RINs in EMTS 
limits the ability to double-count the volume of RNG. We note, however, 
that should we decline to finalize the proposed provisions for biogas 
regulatory reform discussed in Section IX.I, we would consider it 
necessary to require mandatory QAP participation for eRIN participants 
as a mechanism to help oversee the program and avoid the double-
counting of the biogas or RNG.
    Regarding the double-counting of renewable electricity, we believe 
that the proposed conditions on RIN generation discussed in Section 
VIII.F.5 would virtually eliminate the possibility that renewable 
electricity is double-counted. The proposed many-to-one structure only 
allows the RIN generation allowance from a renewable electricity 
generator to go to a single OEM. OEMs, in turn, could only generate 
RINs for registered EVs in service that they manufactured. This should 
virtually eliminate the possibility that the renewable electricity is 
double counted. Furthermore, unlike biointermediates, the renewable 
electricity is already in its final form, so we do not have concerns 
that the renewable electricity would fail to be generated consistent 
with an EPA-approved pathway from qualifying biogas.
    As is currently the case for RINs generated from biogas to 
renewable CNG/LNG, we do, however, believe that obligated parties and 
other RIN market participants would want most eRINs to be verified 
under the RFS QAP. While the RFS QAP provides additional assurance to 
obligated parties that the verified RINs (Q-RINs) are likely valid, 
consistent with the current regulations, obligated parties must still 
replace invalid Q-RINs. The regulations do allow for obligated parties 
to establish an affirmative defense against civil violations under 40 
CFR 80.1473 as long as all elements needed to establish such a defense 
are met. We believe this is due to the relatively high value of 
cellulosic RINs and the difficulty in procuring replacement cellulosic 
RINs should they turn out to be invalid.
    Under the proposed changes to the RFS QAP for eRINs, biogas 
production verification would remain substantially the same as what is 
currently required for biogas and RNG used to produce renewable CNG/
LNG. The QAP Provider would be required to perform a site visit to the 
biogas production facility (e.g., the landfill, agricultural digester, 
waste digester, etc.) and the upgrading facility for the biogas that 
turned it into RNG, if applicable. Auditors would verify that biogas 
came from qualifying renewable biomass, and any specific requirements 
related to the specific type of digester used to produce the biogas 
(e.g., ensuring that separated municipal solid waste (MSW) met the 
requirements of an approved separated MSW plan under 40 CFR 
80.1426(f)(5)(ii)(B)). As is currently required, auditors would also 
conduct quarterly desktop audits of registration, reports, and 
recordkeeping information for consistency and conformance with 
applicable regulatory requirements.
    As with existing regulatory requirements for other fuels, the QAP 
auditor would be required to make site visits to the renewable 
electricity generation facility to verify that necessary equipment is 
present and that the registered capacity is accurate. The auditor would 
also verify that only qualifying biogas was used to produce renewable 
electricity. As is also currently required for RFS QAP participants, 
auditors would have to conduct quarterly desk audits of the renewable 
electricity generation facility. In addition to the typical 
registration, reporting, and recordkeeping review, auditors would also 
review PTDs from the biogas producer and renewable electricity 
generator to the OEMs to verify that the correct amounts of biogas and 
RIN generation allowances were transferred between the three regulated 
parties.
    Finally, desk audits would be required for the eRIN generator 
(i.e., OEM) to verify that RINs were generated accurately. We would not 
require a site visit of the OEM's vehicle manufacturing facilities as 
we do not believe that would be necessary for the verification of 
eRINs. As part of the quarterly desk audits, auditors would verify that 
the OEM only generated RINs from the lesser of the total renewable 
electricity represented by their RIN generation allowances or the 
renewable electricity used in the OEM's electric vehicle fleet based on 
vehicle registration records.
    Although we are not proposing mandatory QAP participation for 
eRINs, we seek comment on whether we should require it. We also seek 
comment on the proposed changes to the RFS QAP to accommodate the 
verification of eRINs.

O. Compliance and Enforcement Provisions and Attest Engagements

    We are proposing compliance and enforcement provisions for eRINs 
and other 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 against non-compliance, and the proposed 
compliance and enforcement provisions for eRINs and other biogas-
derived renewable fuels would serve the same purposes. We discuss the 
specific proposed 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 proposing provisions that establish prohibited actions relating 
to the generation of RINs from biogas-derived renewable fuels; how 
biogas producers, RNG producers, renewable electricity generators, and 
RIN generators for renewable electricity and RNG would be held liable 
when RINs from biogas-derived renewable fuels are determined to be 
invalid; how biogas producers, RNG producers, and renewable electricity 
generators may establish affirmative defenses; and 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 existing 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, violate 
any requirement of the subchapter.\303\ For the renewable electricity 
program we are proposing to adopt 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, would be

[[Page 80678]]

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.
---------------------------------------------------------------------------

    \303\ See 85 FR 29034, 29075 (May 14, 2020); 40 CFR 1090.1700.
---------------------------------------------------------------------------

b. Liability Provisions for Biogas, RNG, Renewable Electricity, and 
Biogas-Derived RIN Generators
    We are proposing 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 proposing that when biogas, RNG, renewable electricity, or RINs 
from a biogas-derived renewable fuel are found to be in violation of 
regulatory requirements, the biogas producer, RNG producer, renewable 
electricity generator, and person that generated RINs from a biogas-
derived renewable fuel would all be liable. Under this proposed 
approach, 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 represent a determination by EPA that the subsequent feedstocks and 
processes used 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, renewable electricity, and RINs generated from biogas-
derived renewable fuel rests with all parties in the generation/
disposition chain.
    As noted above, this approach 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. In this case, 
if, for example, a biogas producer were to use feedstocks that do not 
meet the definition of a renewable biomass, then the biogas producer, 
renewable electricity generator, and RIN generator could all be liable 
for the violation.
    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. Typically, EPA would notify the 
party of the compliance issue and provide an opportunity for the party 
to remedy the issue within 30 days before EPA deactivates the party's 
registration. 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 the eRINs proposal, these provisions for administrative 
action would apply like they do currently under the RFS program. We 
would intend to deactivate registrations in cases where parties in the 
eRIN generation/disposition 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 eRIN generation/disposition chain (i.e., a biogas 
producer, renewable electricity generator, or OEM) would result in the 
prohibition of the generation of eRINs from any affected biogas, 
renewable electricity, or transportation use from the party whose 
registration was deactivated. Similarly, if EPA has approved a QAP plan 
for the OEM to generate a verified eRIN, if EPA revokes the QAP plan, 
the OEM would not be able to generate verified eRINs. We note that 
these administrative actions would be in addition to any civil 
penalties. We believe that in combination with the proposed prohibited 
actions, liabilities, and provisions for dealing with invalid eRINs, 
regulated parties in the eRINs disposition/generation chain would have 
a strong incentive to comply with the proposed eRINs regulatory 
requirement. We are not proposing to amend the existing provisions that 
allow for EPA to take administrative action to deactivate registrations 
or revoke QAP plans under the RFS program in this action, and we would 
consider any comments received as beyond the scope of this action.
c. Affirmative Defenses
    We are proposing that biogas producers, RNG producers, and 
renewable electricity generators may establish affirmative defenses to 
certain violations if the biogas producer, RNG producer, or renewable 
electricity generator 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. Under this proposal, we would 
allow biogas producers to establish an affirmative defense so long as 
all the following were 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, renewable electricity, 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 the 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; and
     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 and renewable electricity generators, we are 
proposing analogous requirements to establish an affirmative defense 
except that, instead of relating to biogas producer, the elements would 
relate to the RNG producer or renewable electricity

[[Page 80679]]

generator. We believe these elements to establish an affirmative 
defense would allow RNG producers and renewable electricity generators 
to avoid liability only in cases where they could not reasonably be 
expected to know that a violation took place; for example, if an OEM 
over-generated RINs for the volume of renewable electricity covered by 
a RIN generation agreement.
    Under the RFS program, the RIN generator is always responsible for 
the validity of the RIN, and we are therefore not proposing to allow 
OEMs that generate eRINs the ability to establish an affirmative 
defense. We expect OEMs that generate eRINs, like all RIN generators 
under the RFS program, to diligently ensure that other parties that are 
part of the eRIN generation/distribution chain are meeting their 
regulatory requirements. Similarly, when the RNG producer generates a 
RIN for RNG used to make renewable CNG/LNG, the RNG producer would not 
be able to establish an affirmative defense.
    We seek comment on these proposed affirmative defenses for biogas 
producers, RNG producers, and renewable electricity generators.
d. Invalid Biogas-Derived RINs
    We are proposing provisions similar to the existing RFS regulations 
to address the treatment of invalid biogas-derived RINs. If a biogas-
derived RIN is identified to be potentially invalid by the RIN 
generator, an independent third-party auditor, or the EPA, certain 
notifications and remedial actions would be required to address the 
potentially invalid biogas-derived 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 proposing provisions that require biogas and RNG 
producers to notify renewable electricity generators if they become 
aware that inaccurate amounts of biogas or RNG were transferred to the 
renewable electricity generator. Similarly, the provisions require 
renewable electricity generators to notify OEM eRIN generators if they 
become aware that inaccurate amounts of renewable electricity were 
transferred to the biogas-derived electricity RIN generators. Finally, 
renewable electricity generators, OEM eRIN generators, and any other 
persons 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 renewable electricity 
generators, or of renewable electricity generators taking credit for 
the same volumes of renewable electricity sold to multiple OEM eRIN 
generators. These provisions are necessary to help prevent the 
generation of invalid RINs by ensuring that parties in the eRINs 
generation/disposition chain are informing all affected parties of 
issues when they arise.
2. Attest Engagements
    We are proposing 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 this proposal. Specifically, we are 
proposing that biogas producers, RNG producers, renewable electricity 
generators, and OEMs 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 would be an important 
component of third-party oversight of the proposed eRINs program.
    Under this proposal, attest engagements for biogas and RNG 
producers, renewable electricity generators, and OEMs would consist of 
an audit of underlying records, reports, and registration information 
(including the third-party engineering review report) for biogas 
production, RNG producers, renewable electricity generation, and RIN 
generation as applicable. These proposed attest engagements would 
follow the same general requirements for other attest engagements under 
EPA's other fuel programs. For example, an independent auditor (i.e., a 
CPA without any interest in the audited party) would 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.
    We believe attest engagements are appropriate for parties involved 
in the generation of eRINs as they would serve to maintain consistency 
across the three regulated parties and serve as valuable third-party 
oversight. We seek comment on requiring attest engagements for biogas 
and RNG producers, renewable electricity generators, and OEMs involved 
in the proposed eRINs program.

P. Foreign Producers

    Under the RFS program, RINs may be generated for foreign-produced 
renewable fuels that are imported for use in the covered location 
either by RIN-generating foreign producers or by the importers of the 
renewable fuel. Currently, we have registered several landfills in 
Canada that produce biogas that is upgraded to RNG and injected onto 
the commercial pipeline system. This Canadian RNG is compressed to make 
renewable CNG/LNG that is used as transportation fuel in the covered 
location, and domestic RIN generators generate RINs for the Canadian 
RNG after the they have demonstrated that the RNG was used as 
transportation fuel in the form of renewable CNG/LNG. We are proposing 
similar provisions for eRINs. In the case of eRINs, we are proposing 
that OEMs would be able to generate eRINs for foreign-generated 
renewable electricity and domestic-generated renewable electricity 
produced from foreign-produced RNG.
1. Foreign-Produced RNG to Renewable Electricity
    We are proposing to allow for the use of foreign-produced biogas to 
produce renewable electricity that could in turn be used to generate 
eRINs if an OEM could demonstrate that the renewable electricity was 
used as transportation fuel in the contiguous U.S. Foreign produced 
biogas would be eligible to participate in the eRIN program so long as 
it is produced consistent with an approved pathway and applicable 
requirements and either upgraded to RNG and injected onto a commercial 
pipeline system that serves the covered location, or is used to produce 
renewable electricity at a renewable electricity generation facility 
(either domestic or foreign) that transmits electricity into the 
commercial electric grid serving the conterminous U.S.
    A foreign RNG producer would have the flexibility of either being a 
RIN-generating foreign producer or having the importer of the RNG 
generate a RIN for the RNG. This is the same flexibility that we 
currently provide other

[[Page 80680]]

imported renewable fuels, and we believe the same approach is 
appropriate for RNG. If the foreign RNG producer chooses to generate 
RINs, the foreign RNG producer would have to meet all the additional 
requirements applicable to RIN-generating foreign producers described 
in 40 CFR 80.1466, which include committing the RIN-generating foreign 
producer to U.S. jurisdiction and the posting of a bond commensurate 
with the number of RINs generated. We note that in the case where a 
foreign party takes title to an assigned RNG RIN, under the current 
regulations that party would have to comply with the additional 
requirements for foreign RIN owners specified at 40 CFR 80.1467. These 
additional requirements for foreign RIN owners include similar 
commitments to those we impose on RIN-generating foreign producers, and 
we are not proposing to modify these requirements.
    In the case where the RNG importer generates the RINs for imported 
RNG, the importer would have to meet all applicable requirements for 
the generation of RINs from an imported renewable fuel under 40 CFR 
80.1426. In both cases, as discussed in more detail in Section IX.I, 
the RIN generated for the foreign produced RNG would need to be 
assigned to the specific volume of RNG injected onto the commercial 
pipeline system and would need to be separated and retired by the 
renewable electricity generator when the RNG was used to produce 
renewable electricity.
2. Foreign-Generated Renewable Electricity
    We are proposing to allow for the inclusion of foreign-generated 
renewable electricity for the generation of eRINs. Under this proposal, 
the foreign-generated renewable electricity would have to be 
transmitted on the commercial electric grid serving the contiguous U.S. 
We believe the same principles discussed in Section VIII.E.3.a that 
make it appropriate to assume that renewable electricity transmitted 
via the commercial electric grid serving the contiguous U.S. is used as 
transportation fuel within the U.S. would also apply if the electricity 
is transmitted on the same grid but is generated in Canada or Mexico.
    Foreign electricity generators and foreign biogas producers would 
have to meet the same proposed regulatory requirements that domestic 
biogas producers and renewable electricity generators would have to 
meet. We are also proposing that in order to have eRINs generated for 
the foreign-produced renewable electricity, the foreign renewable 
electricity generator and the foreign biogas producer that supplied the 
biogas would have to meet the additional requirements for foreign 
renewable fuel producers at 40 CFR 80.1466. This approach is identical 
to the treatment of non-RIN generating foreign producers under the 
existing program for imported liquid renewable fuels.
3. Foreign OEMs
    Under this proposal, similar to the treatment of foreign renewable 
fuel producers, OEMs that are based outside of the U.S. could either 
register as a foreign RIN generator or register a domestic subsidiary 
as the eRIN generator for their continental U.S. light-duty EV fleet. 
If the OEM registers as a foreign RIN generator, the OEM would have to 
comply with the applicable requirements for RIN-generating foreign 
renewable fuel producers. For foreign OEMs, this would include posting 
a bond for the amount of eRINs they generate and committing to U.S. 
jurisdiction for purposes of compliance with the RFS program 
requirements and enforcement. These requirements are necessary to 
ensure that EPA is able to enforce against the foreign OEM in the event 
that the OEM generates invalid RINs or otherwise fails to meet 
requirements under the RFS program.
    If the foreign OEM registers a domestic subsidiary to be the eRIN 
generator, the domestic subsidiary would not need to post a bond or 
commit to U.S. jurisdiction. We note, that due to the parent company 
liability provision at 40 CFR 80.1461, the foreign parent OEM company 
would still be subject to liability for violations of the RFS 
regulations. We seek comment on this approach.

IX. Other Changes to Regulations

A. RFS Third-Party Oversight Enhancement

    Independent third-party auditors and professional engineers play 
critical roles in ensuring the integrity of the RFS program. The 
independent third-party professional 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. Given EPA's recent 
promulgation of a program allowing renewable fuel to be produced from 
biointermediates,\304\ we expect there will be an expansion in the 
scope and number of regulated entities under the RFS program, making 
third-party verifications even more critical.
---------------------------------------------------------------------------

    \304\ 87 FR 39600 (July 1, 2022).
---------------------------------------------------------------------------

    We proposed changes to third-party verifications and submissions in 
the 2016 Renewables Enhancement Growth and Support (REGS) rule; \305\ 
however, those proposed changes were not finalized. We are now re-
proposing (i.e., proposing anew) some, but not all of those changes in 
order to receive further comment and public input. Given the length of 
time since the 2016 proposal, we believe that the proposed changes 
would benefit from a review of implementation of the program in the 
intervening years and from renewed consideration by the public. Any 
comments that were previously submitted on the 2016 REGS rulemaking 
must be resubmitted to the docket for this action. We will not consider 
any comments submitted on the 2016 rulemaking that are not resubmitted 
in response to this re-proposal.
---------------------------------------------------------------------------

    \305\ 81 FR 80828 (November 16, 2016).
---------------------------------------------------------------------------

    As we explained in 2016, the 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 
professional engineers may not be mitigating unlawful and fraudulent 
activities in the RFS program to the extent needed for a successful 
program, we are proposing to strengthen requirements that apply to 
these entities. Specifically, we are proposing to modify the 
requirements for the independent third-party auditors that use approved 
QAPs to audit renewable fuel production to verify that RINs were 
validly generated by the producer. The purpose of these modifications 
would be to strengthen the independence requirements for QAP providers 
that protect against conflicts of interest. We are also proposing 
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 registration, including updates.
    The changes to the regulations that we are proposing to make fall 
into six areas. First, we are proposing to strengthen the

[[Page 80681]]

independence requirements for third-party professional engineers by 
requiring those engineers to comply with similar requirements, 
including the additional requirements we are proposing, to those that 
currently apply to independent third-party auditors.
    Second, we are proposing 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. Currently, the third-party engineer signs 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 proposing that third-party professional engineers 
provide documents and 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 proposing that the required three-year engineering 
review updates are conducted by a third-party engineer while the 
facility being reviewed is operating to produce renewable fuel. We 
believe that the efficacy of a third-party engineer's review of a 
facility 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 
would 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 proposing that a third-party engineer employed by an 
independent third-party auditor who is involved in a specified activity 
performed by the auditor could not be employed by the regulated party, 
currently or previously, within 12 months from when the regulated party 
hired the independent third-party to provide the specified activities. 
We received comments to the REGS proposed rule that due to a limited 
number of RFS experts to perform both engineering and auditing 
activities, a prohibition on providing ``cross services'' between third 
parties would be unworkable. Instead, we are proposing in this 
rulemaking a narrower and shorter limitation on third parties, 
consistent with other EPA programs such as the conventional fuels 
program, to help ensure independence between third parties and 
regulated parties.
    Sixth, we are proposing prohibited acts and liability provisions 
applicable to third-party professional engineers to reduce the 
potential of a conflict of interest with the renewable fuel producer. 
The purpose of these requirements would be to help the 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 professional engineers 
maintain a proper level of independence from the renewable fuel 
producer.
    Taken together, we believe these six proposed requirements would 
help avoid RIN fraud by strengthening third-party verification of 
renewable fuel producers' registration information. Additional 
information on third-party auditors and professional 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 
proposing language that clarifies the current prohibition against an 
appearance of a conflict of interest to include:
     Acting impartially when performing all auditing 
activities.
     Disallowing a person employed by an independent third-
party auditor who is involved in a specified activity performed by the 
auditor to be employed by the regulated party, currently or previously, 
within 12 months from when the regulated party hired the independent 
third-party to provide the specified activities.
    These provisions would be intended to prevent third-party auditors 
from seeking or obtaining employment from producers for which the 
auditors are 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. With regard to companies 
that employ personnel who previously worked for or otherwise engaged in 
consulting services with a producer, those companies would meet the 
independence criteria when such personnel do not participate on, 
manage, or advise the audit teams. Additionally, employees of these 
companies would not be prohibited from accepting future employment with 
a producer as long as they were not involved in performing or managing 
the audit.
    In the RFS QAP final rule, we stated that we continued to be 
concerned that allowing an auditor to also perform engineering reviews 
and attest engagements would tie the auditor's financial interests too 
closely with the renewable fuel producer being audited and could create 
incentives for auditors to fail to report potentially invalid 
RINs.\306\ However, we did not want to exclude potential third-party 
auditors that had significant knowledge of the RFS program and 
renewable fuel production facilities from participating in the QAP 
program. Therefore, the final rule prohibited third-party auditors from 
continuing to provide annual attest engagements and QAP implementation 
to the same audited renewable fuel producer but allowed third-party 
auditors to continue to conduct engineering reviews. We received 
significant comments to the REGS proposed rule that proposed to 
preclude third parties from performing engineering reviews and 
providing QAP services to the same producers. As a result, we are not 
re-proposing this prohibition.
---------------------------------------------------------------------------

    \306\ 79 FR 42078 (July 18, 2014).
---------------------------------------------------------------------------

2. Third-Party Professional Engineers
    Engineering reviews from independent third-party professional 
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 
professional engineers, affiliates, and renewable fuel producers are 
analogous to third-party auditors and renewable fuel producers. As a 
result, we are proposing to strengthen the independence requirements 
for third-party professional engineers by requiring those engineers to 
comply with similar requirements (including the additional requirements 
we are

[[Page 80682]]

proposing) to those that currently apply to independent third-party 
auditors.
    We are also proposing to improve the RFS registration requirements 
for three-year engineering review updates by requiring site visits to 
take place when the facility is producing renewable fuel. Comments 
received to this requirement in the REGS proposed rule noted that a 
facility would be required to generate fuel but not RINs if EPA 
required the engineering review site visit for a facility's initial 
registration. However, by the three-year engineering review, facilities 
should reasonably be able to coordinate with third-party engineers to 
ensure they are operational for the engineering review. This would 
provide the regulated community and the 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 professional engineers. 
Some of these engineers are using templates that make it difficult for 
the 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 proposing that the engineering review submission include 
evidence of a site visit while the facility is producing renewable 
fuel(s) that it is registered to produce. We also propose to 
incorporate the 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 would explain that in order to verify the 
applicable registration information, the third-party auditor must 
independently evaluate and confirm the information and cannot rely on 
representations made by the renewable fuel producer. We also propose to 
require the third-party engineer to electronically certify that the 
third-party meets the independence requirements whenever the third-
party submits engineering reviews or engineering review updates to EPA. 
Currently, the third-party engineer signs 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 would help provide greater assurance 
that third-party professional 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 proposing prohibited activities for third-party 
professionals failing to properly conduct an engineering review, or 
failing to disclose to the EPA any financial, professional, business, 
or other interest with parties for whom the third-party professional 
engineer provides services for under the RFS registration requirements. 
The EPA staff that review RFS registrations have concerns that third-
party professional engineers may be acting, independently or through an 
affiliate, as consultants and agents for the same renewable fuel 
producer, or that, directly or through an affiliate, they may have a 
financial interest in the renewable fuel producer, may not 
appropriately conduct engineering reviews, or may not meet the 
requirements for independence to qualify as a third-party. We believe 
that making third-party professional engineers more accountable for 
properly conducting engineering reviews under the regulations and 
requiring that they interact more directly with the EPA would help our 
ability to identify potential conflicts of interests and bring 
enforcement actions against third-party professional engineers should 
an issue arise.

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

    We are proposing to require 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. Under the existing regulations, renewable fuel producers are 
required to have a third-party engineer conduct an updated engineering 
review three years after initial registration. The regulations state 
that the three-year engineering review reports are due by January 31 
after the first year of registration. However, the regulations do not 
specify when the third-party engineer has to conduct the site visit. We 
have received several inquiries by 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 noted 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.
    We now 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 proposing that the site visit occur 
no sooner than July 1 of the preceding calendar year. We believe that 
this amount of time would 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 note that this seven-month period would be greater than the 
originally provided 120-day period under prior EPA guidance. We believe 
more time is warranted as the number of facilities that require three-
year updates has increased. We seek comment on this proposed deadline 
and whether more or less time is warranted to balance the efficacy of 
the third-party site visit with ensuring enough time for renewal fuel 
producers to satisfy their three-year registration update requirements.
    We are also proposing to specify which batches of RINs should be 
included in the VRIN calculation portion of the three-year 
registration update. Under this proposal, 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 
appropriate 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 vary 
significantly across third-party engineers and we want to ensure that 
this portion of the engineering review update is conducted 
consistently. We seek comment on this proposed change.

C. RIN Apportionment in Anaerobic Digesters

    In the Pathways II rule, we updated RIN-generating pathways using 
biogas as a feedstock to allow D3 RINs to be generated for renewable 
compressed natural gas (CNG) and renewable liquefied natural gas (LNG) 
produced from biogas from digester types that

[[Page 80683]]

process only predominately cellulosic \307\ 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.\308\ We also created a 
renewable CNG/LNG pathway to allow for D5 RINs to be generated for 
biogas produced from other waste digesters; \309\ this pathway must be 
used if the feedstock being processed in a digester is not 
predominantly cellulosic. If a party wishes to simultaneously convert 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, the regulations at 40 CFR 80.1450(b)(1)(xiii)(B) requires 
parties to calculate and submit to EPA as part of their registration 
materials the cellulosic converted fraction, i.e., the portion of a 
cellulosic feedstock that is converted into renewable fuel. The 
cellulosic converted fraction calculation is based on measurements of 
cellulose, and these measurements must be obtained using a method that 
would produce 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, with any degree of accuracy, the 
cellulosic content of the feedstock at the time of registration.
---------------------------------------------------------------------------

    \307\ A predominately cellulosic feedstock is a feedstock with 
an adjusted cellulosic content, as defined in 40 CFR 80.1401, of 
greater than 75 percent.
    \308\ EPA's regulations also allow D3 RINS to be generated for 
renewable CNG/LNG produced from biogas from landfills.
    \309\ See Table 1 to 40 CFR 80.1426; 79 FR 42168 (July 18, 
2014).
---------------------------------------------------------------------------

    Since the Pathways II rule was finalized, we have had numerous 
inquiries from stakeholders about 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.\310\ 
This processing condition is desirable for stakeholders because 
simultaneous conversion in a single digester can lead to higher biogas 
yields than processing in separate digesters \311\ with less capital 
investment. Some stakeholders have asked whether EPA would consider the 
separated food waste in these instances to be a predominantly 
cellulosic feedstock, which would allow producers to obtain D3 RINs for 
all biogas produced from the digester. However, in the Pathways II 
rule, we did not find that separated food waste necessarily meets the 
predominantly cellulosic criteria,\312\ and we continue to believe it 
generally does not have an adjusted cellulosic content greater than 75 
percent. Therefore, biogas-derived renewable fuels produced from biogas 
produced from mixed feedstocks that include separated food waste are 
not eligible to generate 100 percent D3 RINs and are subject to the 
registration requirements in 40 CFR 80.1450(b)(1)(xiii)(B), which 
includes testing to determine the cellulosic content of the feedstocks. 
Other inquiries have sought clarification about whether it is possible 
to apportion the predominantly cellulosic feedstock as D3 and the 
separated food waste as D5 without needing to test the cellulosic 
composition of individual or mixed feedstocks. Proposed solutions by 
stakeholders focused on determining the cellulosic biogas converted 
fraction from processing just the predominantly cellulosic feedstock, 
for example by assuming that the predominantly cellulosic feedstock 
produces the same amount of methane when it is processed alone (based 
on a biochemical methane potential test) as when it is processed in an 
anaerobic digester with other feedstocks. However, this approach is not 
allowed under the existing regulations in 40 CFR 
80.1450(b)(1)(xiii)(B)(3), since the existing regulations require the 
cellulosic converted fraction to be based on chemical testing for 
cellulosic content, without any allowance for testing predominantly 
cellulosic feedstocks separately in lieu of chemical testing of 
cellulosic content. However, even if such chemical testing was 
undergone for registration, we believe the existing approach in the 
regulations may not be acceptable due to the variability of the food 
waste feedstock composition which makes it likely that any converted 
fraction submitted for the purpose of registration is not 
representative of the actual composition of the feedstock used to 
produce biogas. This lack of accuracy could lead to cellulosic RINs 
being generated on non-cellulosic feedstocks.
---------------------------------------------------------------------------

    \310\ 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.
    \311\ Karki et al. Bioresource Technology 330 (2021) 125001. 
DOI: 10.1016/j.biortech.2021.125001.
    \312\ 79 FR 42140 (July 18, 2014).
---------------------------------------------------------------------------

    EPA's existing 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. Currently, these requirements apply to all situations 
in which predominantly cellulosic \313\ and non-cellulosic feedstocks 
are simultaneously converted to produce a single type of fuel.\314\ 
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 case of feedstocks co-processed in a 
digester, we have determined that a number of the existing requirements 
are unnecessary or otherwise inappropriate. For example, chemical data 
showing the cellulosic content of the mixed feedstocks is not necessary 
because the feedstocks can be measured separately before they are mixed 
(and measurement may not be needed if the separate feedstocks have 
already been determined to be predominantly cellulosic or non-
cellulosic). Additionally, the regulatory apportionment equations use 
dry mass, which is less accurate for biogas than volatile solids, which 
is the value typically used in the digester industry.\315\ The 
apportionment equations also include an energy component, which, as 
noted by a commenter in a previous rulemaking, can underweight biogas 
from feedstocks with lower energy content.\316\ Finally, even if 
cellulosic testing were conducted on select batches of feedstock, the 
highly heterogeneous composition of separated food waste raises the 
likelihood that sampling would not be representative, which could cause 
D3 RINs to be generated when the fuel is not derived from cellulosic 
biomass.
---------------------------------------------------------------------------

    \313\ For feedstocks that have been determined to be 
predominantly cellulosic, see 79 FR 42140 (July 18, 2014).
    \314\ 40 CFR 80.1426(f)(3)(vi).
    \315\ Dry mass, also referred to as total solids in the digester 
industry, includes ash, which consists of salts that are is left 
over after combusting the total solids. Due to the lack of organic 
matter, ash is generally considered to not contribute to methane 
production. The volatile solids term excludes the ash content, so it 
is generally regarded as a more accurate measure of the substance 
that is capable of producing methane.
    \316\ See comment submitted by Fulcrum BioEnergy, Inc., Docket 
Item No. EPA-HQ-OAR-2021-0324-0434.
---------------------------------------------------------------------------

    At the same time, there are also features of co-processing in a 
digester

[[Page 80684]]

that make it reasonable to consider a different regulatory approach to 
RIN apportionment. The feedstocks in question are generated as 
physically separate streams, so that mass, moisture content, and 
methane production potential of each feedstock can be determined before 
mixing. This possibility of measuring physically separated feedstocks 
individually is not contemplated by the current 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 in the food waste, which means that chemical analysis of the 
cellulosic content of the food waste feedstock and digestate is not 
required. In addition to the feedstocks being physically separate, 
mixing of typical feedstocks in anaerobic digestion does not lead to a 
decrease in biogas production relative to when they are processed 
together, reducing the risk of D3 RINs being generated from non-
cellulosic feedstock.\317\
---------------------------------------------------------------------------

    \317\ Karki et al. Bioresource Technology 330 (2021) 125001. 
DOI: 10.1016/j.biortech.2021.125001.
---------------------------------------------------------------------------

    Based on the differences discussed above, we are proposing new and 
separate equations to determine feedstock energy for when predominantly 
cellulosic and non-predominantly cellulosic feedstocks are 
simultaneously converted in anaerobic digesters. The cellulosic 
feedstock energy equation is similar to the equation in 40 CFR 
80.1426(f)(3)(vi), with a few modifications. The proposed equation uses 
a volatile solids measurement since non-volatile solids do not 
generally produce biogas, making this equation more accurate than the 
one in 40 CFR 80.1426(f)(3)(vi). We are also specifying that the 
feedstock energy used in the equation should be the energy content of 
biogas instead of the feedstock to avoid disproportionate RIN 
generation for higher energy feedstock and so that the equation that 
results is the energy content of the biogas which is used as the 
feedstock to the renewable fuel pathway. The non-predominantly 
cellulosic feedstock energy equation sets the non-predominantly 
cellulosic feedstock energy to be the difference between total biogas 
produced and cellulosic biogas as calculated by the cellulosic 
feedstock apportionment equation. We believe these updated equations 
would 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 proposing 
biogas producers keep records of feedstocks necessary to recompute 
apportionment calculations.
    To support this proposed apportionment, we are proposing separate 
registration requirements to determine the converted fraction of the 
predominantly cellulosic feedstock used in an anerobic digester when it 
is simultaneously converted with a non-predominantly cellulosic 
feedstock. Instead of chemical data supporting a cellulosic converted 
fraction as required under the existing regulations, we are proposing 
that a facility producing biogas from anaerobic digestion be required 
at registration to 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;
     A description including any calculations demonstrating how 
the data were used to determine the cellulosic converted fraction; and
     The cellulosic converted fraction that will be used in the 
RIN apportionment.
    Operational data used to determine the cellulosic converted 
fraction would 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 proposing a requirement that the registrant identify 
the conditions in its registration under which the facility would need 
to operate to properly apportion RINs. In specifying those processing 
conditions, we are proposing a requirement that parties 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 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.
    We are not proposing to require registrants to submit data on 
whether their converted fraction determined from processing a single 
feedstock applies when processing multiple feedstocks because evidence 
from literature shows that cellulosic converted fractions generally do 
not decrease, and in some cases increase, when adding additional 
feedstocks such as food waste under identical processing 
conditions.\318\ Our approach thus conservatively assumes that the 
cellulosic converted fraction is the same when processing a single 
feedstock and multiple feedstocks, which we believe would result in 
digester operators using a conservative estimate of the biogas produced 
from cellulosic feedstock when simultaneously processing it with non-
cellulosic feedstock. The evidence from literature allows us to 
simplify the registration process while still providing us with the 
assurance that RINs are generated with the appropriate D-code.
---------------------------------------------------------------------------

    \318\ Karki et al. Bioresource Technology 330 (2021) 125001. 
DOI: 10.1016/j.biortech.2021.125001.
---------------------------------------------------------------------------

    Instead of providing operational data, we are also proposing to 
allow registrants an alternative 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 
proposing 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.\319\ 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,

[[Page 80685]]

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.\320\ Given 
the limited types of feedstocks, the limited number of digesters 
evaluated in this study, and the different goals behind the 
recommendations,\321\ 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.\322\ We welcome comments suggesting other default values of 
converted fractions based on other data sources, such as operational 
data. Comments presenting alternative converted fraction values should 
also contain information about the underlying data, discussion of why 
the underlying data is representative (for example, by describing the 
process by which data was selected) and how the converted fraction was 
derived from operational data, and a list of operational conditions on 
which the data was based.
---------------------------------------------------------------------------

    \319\ 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.
    \320\ Holliger et al. (2017) Frontiers in Energy Research, 5, 
12. DOI: 10.3389/fenrg.2017.00012.
    \321\ When designing a digester and gas treatment system, one 
would like to maximize the amount of fuel or energy and using a 
slight overestimate of biogas production is less of a problem than 
in the RFS program, where overestimating cellulosic production of 
biogas would lead to invalidly generated RINs.
    \322\ See memo ``Calculation of cellulosic converted fraction 
values from biochemical methane potential,'' available in the docket 
for this action.
---------------------------------------------------------------------------

    We are proposing that the requirements discussed in this subsection 
only apply for processes using biogas from anaerobic digestion that 
simultaneously convert multiple feedstocks where at least one is not 
predominantly cellulosic. We are seeking comment on whether the 
proposed approach should be more limited, for example, to digesters 
processing separated food waste, or whether some aspects of these 
proposed changes could be applied more broadly, for example, to all 
simultaneous conversion of renewable feedstocks where one or more does 
not meet the minimum 75 percent cellulosic content requirement and when 
the feedstocks are produced separately and can be separately measured. 
Commenters should provide examples of how expanding or restricting the 
use of these proposed changes beyond pathways for the production of 
renewable CNG/LNG or renewable electricity from biogas produced in 
anaerobic digesters would be beneficial or problematic, using examples 
of specific production pathways and processes.
    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 as renewable electricity. We are proposing that the 
different D-codes be tracked through product transfer documents from 
biogas producers, RNG producers, and renewable electricity generators 
as well as reporting of D-code information into EMTS. Under this 
proposed approach, biogas producers would 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.I) and renewable 
electricity (as discussed in Section VIII) would use this proportion to 
calculate the appropriate number of D3 and D5 RINs.

D. BBD Conversion Factor for Percentage Standard

    In the proposal for the 2020-2022 standards, we proposed a change 
to the conversion factor used in the calculation of applicable 
percentage standards for BBD.\323\ We did not finalize that proposed 
change in the final rulemaking which established the applicable 
standards for 2020-2022. We are now reproposing that change for 
implementation for compliance years 2023 and beyond, and are including 
data from 2021 in the proposed determination of the appropriate revised 
conversion factor.
---------------------------------------------------------------------------

    \323\ 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.\324\ 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.
---------------------------------------------------------------------------

    \324\ See 75 FR 14670, 14682 (March 26, 2010).
---------------------------------------------------------------------------

    The formula for calculating the applicable percentage standards for 
BBD 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 for biodiesel, 1.5, as discussed in the 
2007 RFS1 final rule.\325\ The resulting formula \326\ (incorporating 
the recent modification to the definitions of GEi and 
DEi) \327\ is shown below:
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    \325\ See 72 FR 23900, 23921 at Table III.B.4-1 (May 1, 2007).
    \326\ See 40 CFR 80.1405(c).
    \327\ See 85 FR 7016 (February 6, 2020).
    [GRAPHIC] [TIFF OMITTED] TP30DE22.006
    
---------------------------------------------------------------------------
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

[[Page 80686]]

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 percent standard formula for 
BBD was first promulgated, advanced renewable diesel production has 
grown. Most renewable diesel has an Equivalence Value of 1.7, and its 
growing presence in the BBD pool means that the average Equivalence 
Value of BBD has also grown.\328\
---------------------------------------------------------------------------

    \328\ Under 40 CFR 80.1415(b)(4), renewable diesel with a lower 
heating value of at least 123,500 Btu/gallon is assigned an 
Equivalence Value of 1.7. A minority of renewable diesel has a lower 
heating value below 123,500 BTU/gallon and is therefore assigned an 
Equivalence Value of 1.5 or 1.6 based on applications submitted 
under 40 CFR 80.1415(c)(2).
[GRAPHIC] [TIFF OMITTED] TP30DE22.007

    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 2 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 Equivalence Value 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 as discussed 
in DRIA Chapter 5.2. Based on the data shown in Figure IX.D-1, we 
believe that the factor used in the formula for calculating the 
percentage standard for BBD should be at least 1.57. We are therefore 
proposing to replace the factor of 1.5 in the percentage standard 
formula for BBD with a factor of 1.57.\329\ For the final rule, we will 
consider additional data that may be available and may adjust this 
factor as appropriate. Note that we are not proposing to change any 
other aspect of the percentage standard formula for BBD.
---------------------------------------------------------------------------

    \329\ While we are proposing to revise the factor of 1.5 in the 
percentage standard formula for BBD, we would include 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 proposing minor edits for 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 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 and if the renewable fuel producer 
has not met all other applicable requirements, including registration, 
reporting, and recordkeeping requirements.\330\ Our 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 the EPA. In light of this approach, we have 
determined that a more straightforward approach would be to allow, 
rather than require, RINs to be generated for qualifying renewable 
fuel. Thus, we are proposing that 40 CFR 80.1426(a)(1), (a)(2) and (b) 
state that RINs ``may only'' be generated if certain requirements are 
met. We are also proposing to remove

[[Page 80687]]

the provisions for small volume renewable fuel producers at 40 CFR 
80.1426(c)(2) and (c)(3) as well as 40 CFR 80.1455 because those 
provisions are no longer necessary. If any renewable fuel producer, 
regardless of size, has the flexibility to choose to generate RINs, 
then there is no longer a need to provide flexibility for small 
producers because they would only choose to generate RINs if it were 
economically beneficial to do so. We seek comment on our proposal to 
modify the RIN generation provisions to allow rather than require RIN 
generation.
---------------------------------------------------------------------------

    \330\ 40 CFR 80.1426(a)(1)(iii).
---------------------------------------------------------------------------

F. Changes to Tables in 40 CFR 80.1426

    We are proposing 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).\331\ As they currently exist in the CFR, these tables 
are 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 means that they should 
be located at the very end of 40 CFR 80.1426. Currently, however, 
Tables 1 and 2 are located after 40 CFR 80.1426(f)(1)(vi), Table 3 is 
located in 40 CFR 80.1426(f)(3)(v), and Table 4 is located in 40 CFR 
80.1426(f)(3)(vi)(A).
---------------------------------------------------------------------------

    \331\ 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 proposing to move 
Tables 1 and 2 to the end of 40 CFR 80.1426, consistent with their 
current designation. Since we are not proposing to change 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) would remain accurate and valid. In contrast, for Tables 
3 and 4, we are proposing to create new provisions within the 
regulations into which we would move and consolidate the formulas in 
these tables. Specifically, we would move and consolidate the five 
formulas currently in Table 3 into 40 CFR 80.1426(f)(3)(v), and would 
move and consolidate the five formulas currently in Table 4 into 40 CFR 
80.1426(f)(3)(vi)(A). The formulas themselves would effectively 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 proposed change.
    We seek comment on our proposal to move Tables 1 and 2 to the end 
of 40 CFR 80.1426 and to retain their current designations (``Table 1 
to 40 CFR 80.1426'' and ``Table 2 to 40 CFR 80.1426''), to move and 
consolidate the formulas currently within Tables 3 and 4 into 
paragraphs 40 CFR 80.1426(f)(3)(v) and (vi)(A), respectively, and on 
whether any additional clarification or revisions are necessary to 
implement these moves. We reiterate that we are not proposing to revise 
or otherwise reopen the contents of Table 1 or Table 2 as part of this 
move, or to revise or otherwise reopen the formulas that are currently 
in Table 3 and Table 4, other than to move and consolidate them.

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

    We are proposing amendments to 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 our 
implementing regulations already limit RIN generation to renewable fuel 
produced for use in the United States, and these amendments are 
intended to address any perceived confusion on the part of 
stakeholders. The amendments specify that RINs cannot be generated on 
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 
our proposal reinforces that generating RINs for fuel not produced for 
use in the covered location is a prohibited activity. We seek comment 
on our proposed amendments to reiterate that parties cannot generate 
RINs for renewable fuel unless it was produced for use in the covered 
location.

H. Seeking Public Comment on Hydrogen Fuel Lifecycle Analysis

1. Background and Purpose
    EPA has received multiple petitions pursuant to 40 CFR 80.1416 
requesting cellulosic biofuel (D-code 3) RIN eligibility for new fuel 
pathways that use renewable natural gas (RNG) produced from biogas from 
anaerobic digesters or landfills as a feedstock to produce hydrogen 
fuel for use in fuel cell electric vehicles (FCEVs). The pathway 
petitions received to date have focused on the use of steam methane 
reforming (SMR), a process that reacts natural gas or RNG with high-
pressure steam to produce hydrogen fuel.\332\ Approximately 95 percent 
of hydrogen produced in the United States today is produced using SMR. 
The large majority of SMR facilities use natural gas feedstock, though 
there are variations of this process and differences in efficiencies 
across facilities. Although most hydrogen fuel is currently used in 
industrial processes such as petroleum refining and fertilizer 
production, there is interest in using hydrogen as a transportation 
fuel in light-duty, medium- and heavy-duty, and non-road vehicles.
---------------------------------------------------------------------------

    \332\ Hydrogen Production: Natural Gas Reforming. Department of 
Energy, https://www.energy.gov/eere/fuelcells/hydrogen-production-natural-gas-reforming.
---------------------------------------------------------------------------

    In this section we are presenting estimates of lifecycle GHG 
emissions associated with the feedstock sourcing, production, 
transport, and use of hydrogen fuel produced from RNG through an SMR 
process for use as a transportation fuel. Clean Air Act section 
211(o)(1)(B) defines advanced biofuel, of which cellulosic biofuel 
\333\ is a subset, as ``renewable fuel, other than ethanol derived from 
corn starch, that has lifecycle greenhouse gas emissions, as determined 
by the Administrator, after notice and opportunity for comment, that 
are at least 50 percent less than the baseline lifecycle greenhouse gas 
emissions.'' Thus, for a fuel to qualify as a cellulosic or advanced 
biofuel and be eligible to generate D-code 3 or D-code 5 RINs 
respectively, the public must have notice of and an opportunity to 
comment on EPA's lifecycle GHG assessment of that fuel. We are 
therefore requesting public comment on use of the lifecycle GHG 
estimates in this section and related topics in support of evaluating 
and resolving the pathway petitions for hydrogen fuel before the 
agency.
---------------------------------------------------------------------------

    \333\ Cellulosic biofuel is defined in Clean Air Act section 
211(o)(1)(E) as ``renewable fuel derived from any cellulose, 
hemicellulose, or lignin that is derived from renewable biomass and 
that has lifecycle greenhouse gas emissions, as determined by the 
Administrator, that are at least 60 percent less than the baseline 
lifecycle greenhouse gas emissions.''
---------------------------------------------------------------------------

    The estimates summarized below are from Argonne National 
Laboratory's Greenhouse gases, Regulated Emissions, and Energy use in 
Technologies (GREET) \334\ model for hydrogen fuel produced from RNG 
through an average SMR process. We present GREET results here since it 
is a publicly available data source developed by a U.S. Department

[[Page 80688]]

of Energy laboratory that are similar to the pathway petitions EPA has 
received. EPA has often used GREET as one of the data sources for our 
lifecycle analysis assumptions in the past. The predeveloped pathways 
in GREET were similar in scope to the petitions that were submitted to 
EPA under claims of confidential business information, therefore 
presenting the GREET data allows for public comment without disclosing 
data that was claimed as confidential business information.
---------------------------------------------------------------------------

    \334\ Argonne Greenhouse gases, Regulated Emissions, and Energy 
use in Technologies (GREET) Model, https://greet.es.anl.gov.
---------------------------------------------------------------------------

    Based on the data and information we have received from petitioners 
to date, the lifecycle GHG emissions associated with hydrogen produced 
from RNG via SMR vary significantly based on the configuration of 
individual hydrogen production facilities and how hydrogen from 
individual facilities gets distributed to end users. While SMR 
production of hydrogen is well established, hydrogen use as a 
transportation fuel introduces new areas of significant variation and 
uncertainty that would be more difficult to address in a generalized 
lifecycle GHG analysis of hydrogen fuel (e.g., whether hydrogen fuel is 
produced on-site or at larger centralized SMR facilities, or whether 
hydrogen fuel is compressed or liquified). Given these variations in a 
relatively nascent transportation fuel market and the lack of real-
world data, we believe it is prudent as a first step towards approving 
hydrogen fuel pathways to take into account the GHG emissions 
associated with a specific facility's production and distribution of 
hydrogen fuel at this time. EPA's evaluation of individual petitions 
will be based on the petitioner's energy and mass balance data and, as 
we are requesting comment on here, the GHG emissions associated with 
the petitioners' fuel production processes and combined with data from 
GREET on emissions upstream from biogas sourcing as well as downstream 
associated with the distribution and use of the finished biofuel. Our 
intent is to use this combination of GREET data and pathway petition 
data to determine whether the fuel produced at an individual facility 
satisfies the CAA renewable fuel GHG reduction requirements. Due to the 
large number of possible configurations for producing transportation 
fuel from hydrogen, and varying energy requirements for producing 
gaseous and liquid hydrogen, we do not intend to promulgate a generally 
applicable pathway for hydrogen fuel to Table 1 to 40 CFR 80.1426 at 
this time.\335\
---------------------------------------------------------------------------

    \335\ We anticipate that some refineries would wish to use 
hydrogen produced from RNG via SMR as a feedstock for producing 
other renewable fuels. We intend for the lifecycle GHG analysis for 
hydrogen in Section 9.H.2 to inform the broader evaluation of such 
renewable fuels produced at refineries.
---------------------------------------------------------------------------

    In this section, we also discuss and seek comment on key and novel 
aspects of using hydrogen fuel under the RFS program, including 
compression and pre-cooling of the hydrogen fuel, hydrogen fuel cell 
electric vehicle efficiency, and the global warming potential of 
fugitive hydrogen. We request comment on these topics, as they all have 
a potential impact on the lifecycle GHG emissions.
    There are additional considerations beyond the lifecycle GHG 
emissions that may need to be resolved before RINs can be generated for 
hydrogen. These include registration, recordkeeping, and reporting 
requirements, product transfer documents, the party that would generate 
the RINs, the equivalence value that determines the number of RINs 
generated for a given quantity of hydrogen, and the definition of 
``produced from renewable biomass'' that is discussed in Section IX.M. 
Following the notice and opportunity for public comment provided here, 
we believe we would be in a position to act on facility-specific 
hydrogen fuel pathway petitions submitted pursuant to 40 CFR 80.1416, 
in situations where no additional regulatory changes are needed to 
accommodate the generation of RINs for hydrogen fuel.
2. Hydrogen Fuel Steam Methane Reforming (SMR) Lifecycle Analysis
    Evaluation of the lifecycle GHG emissions associated with hydrogen 
fuel under the RFS program must consider ``the aggregate quantity of 
greenhouse gas emissions (including direct emissions and significant 
indirect emissions such as significant emissions from land use 
changes), as determined by the Administrator, related to the full fuel 
lifecycle, including all stages of fuel and feedstock production and 
distribution, from feedstock generation or extraction through the 
distribution and delivery and use of the finished fuel to the ultimate 
consumer,'' not merely the hydrogen fuel production step.\336\
---------------------------------------------------------------------------

    \336\ Clean Air Act section 211(o)(1)(H).
---------------------------------------------------------------------------

    In this analysis, we are considering hydrogen fuel produced in an 
SMR from RNG sourced from landfill biogas. The feedstock is biogas from 
landfills which we have previously evaluated as part of the RFS2 final 
rule lifecycle determination.\337\ Therefore no new renewable feedstock 
production modeling is required. No direct or indirect land use change 
emissions were attributed to landfill biogas as a feedstock. Landfill 
biogas is a natural byproduct of the decomposition of organic material 
in landfills. It is composed of roughly 50 percent methane (the primary 
component of natural gas), 50 percent carbon dioxide (CO2), 
and a small amount of non-methane organic compounds.\338\ The landfill 
biogas is captured and upgraded to RNG to increase the concentration of 
methane and remove CO2 along with other impurities. The 
upgraded pipeline specification RNG is then injected into a common 
carrier pipeline to transport the gas that is functionally identical to 
fossil natural gas towards facilities that can use the feedstock. In 
this case the pipeline transports the RNG to an SMR located offsite in 
order to produce hydrogen fuel.
---------------------------------------------------------------------------

    \337\ March 2010 RFS2 rule (75 FR 14670).
    \338\ EPA Landfill Methane Outreach Program (LMOP), Basic 
Information about Landfill Gas, https://www.epa.gov/lmop/basic-information-about-landfill-gas.
---------------------------------------------------------------------------

    While we describe a few variations of SMR processes below, 
consisting of different sizes, production capacities, and primary 
energy sources, these all share similarities in that they convert the 
RNG into hydrogen by subjecting it to high pressure and temperatures in 
the presence of a catalyst using energy supplied to the system to 
release and bond the embedded hydrogen molecules together found in the 
RNG and supplied water.\339\ This two-step process includes the 
namesake steam-methane reforming reaction and a subsequent water-gas 
shift reaction that releases additional hydrogen from the water in the 
process. This process relies on RNG, fossil natural gas, or electricity 
to supply the energy for the steam methane reforming- with the most 
common energy source being fossil natural gas for larger and more 
centralized facilities. Natural gas or RNG can be used in SMRs for both 
the feedstock and also as the process energy to drive the reactions. 
While some of the hydrogen molecules are stripped from water in the 
process, there is no energy in the finished fuel that originates from 
the water molecules. The energy in the finished hydrogen fuel comes 
from both the feedstock and process energy used as inputs to the SMR, 
which relates to the ``produced from renewable biomass'' topic as 
discussed in Section IX.M.
---------------------------------------------------------------------------

    \339\ Hydrogen Production: Natural Gas Reforming, Department of 
Energy, Hydrogen and Fuel Cell Technologies Office, https://www.energy.gov/eere/fuelcells/hydrogen-production-natural-gas-reforming.

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

[[Page 80689]]

    Once hydrogen fuel is produced in the SMR, it must be specially 
stored and transported for its end use as a transportation fuel. 
Hydrogen fuel differs from conventional liquid fuels due to the 
significant amount of energy required for concentration, 
transportation, and storage of the fuel. While hydrogen fuel is 
typically produced in a gaseous form, it requires compression at high 
pressure to maintain a reasonable storage or transportation volume and 
requires significant energy to perform that compression. Liquefaction 
of the hydrogen fuel to below -423 degrees Fahrenheit is another option 
for further reducing the volume and allowing for easier transportation 
of greater amounts of hydrogen fuel over long distances using cryogenic 
tanker trucks compared to gaseous tube trailers, but this comes at an 
even greater energy cost than gaseous hydrogen fuel compression.\340\ 
Once delivered to a refueling station, hydrogen fuel is commonly 
gasified and pre-cooled to enable faster refueling of vehicles. These 
steps require energy, usually from electrically driven compressors. 
Argonne's GREET evaluates both the centralized and distributed \341\ 
hydrogen fuel production and distribution scenarios.
---------------------------------------------------------------------------

    \340\ Liquid Hydrogen Delivery. Department of Energy, https://www.energy.gov/eere/fuelcells/liquid-hydrogen-delivery.
    \341\ Centralized production refers to producing hydrogen fuel 
from larger facilities that can increase production efficiency but 
requires distribution through a network of gaseous or liquified 
hydrogen tube trailer or pipeline deliveries to hydrogen refueling 
stations. Distributed hydrogen fuel production refers to producing 
hydrogen fuel at the point of end-use such as at the refueling 
stations themselves. This is generally expected to have lower 
production efficiencies and requires the hydrogen fuel production 
inputs (e.g., natural gas, electricity, water) to come to the 
distributed hydrogen fuel production site but eliminates the need to 
transport the finished hydrogen fuel to a separate location.
---------------------------------------------------------------------------

    The GREET model contains various pathway analyses for hydrogen 
produced through an SMR process. We present the following lifecycle 
estimates based on results from GREET that represent average hydrogen 
production scenarios using landfill biogas as the feedstock based on 
data from industry average SMR facilities. The steps include feedstock 
production, feedstock transportation, hydrogen fuel production, 
transportation of the finished fuel, and dispensing to vehicles at a 
hydrogen refueling station. We present three different scenarios below 
from GREET that most closely represent the various pathway petitions 
using an SMR that the agency has received. Facility specific GHG 
estimates would vary slightly from these GREET pathways based on 
factors such as process efficiency, energy inputs, and transport 
distances, among others.
    All scenarios assume the feedstock is RNG sourced from landfill 
biogas.\342\ GREET assumes electricity is used to upgrade and process 
the landfill biogas and approximately two percent of the methane is 
assumed to become fugitive during this process. The resulting upgraded 
RNG is compressed and injected into a common carrier natural gas 
pipeline for transportation to the SMR facility to be converted to 
hydrogen fuel.
---------------------------------------------------------------------------

    \342\ While GREET's assumptions here use landfill biogas, EPA 
stated in the RFS Pathways II and Technical Amendments to the RFS 2 
Standards final rule (79 FR 42128) that GHG lifecycle emissions for 
biogas generated at MSW landfills reasonably represent biogas from 
municipal wastewater treatment facility digesters, agricultural 
digesters, separated MSW digesters, and waste digesters as well. We 
would therefore use this proposed lifecycle assessment to represent 
any of those feedstocks as they have already been evaluated and 
approved in Table 1 to 40 CFR 80.1426. Biogas from waste digesters 
that does not meet the regulatory criteria as cellulosic feedstock 
used to generate hydrogen fuel would only be able to qualify for 
advanced (D5) or conventional biofuel (D6) RINs.
---------------------------------------------------------------------------

    The first two scenarios presented below represent lifecycle GHG 
emissions for large centralized SMR facilities that are meant to 
produce hydrogen in one location and transport it to hydrogen refueling 
stations for end-users, similar in concept to how petroleum refineries 
produce gasoline and transport the resulting fuel to gas stations. The 
first scenario represents gasifying the hydrogen fuel and the second 
scenario represents liquefaction of the hydrogen fuel, which as 
described above incurs a greater energy and GHG emissions burden 
compared to gasification. In both scenarios, the SMR process is assumed 
to use fossil natural gas for converting the RNG feedstock into 
hydrogen fuel and export excess steam for other industrial processes. 
GREET assumes natural gas as the energy input into the process. 
Therefore, when considering the SMR system as a whole, 59.4 percent of 
the energy comes from RNG as the feedstock and 40.6 percent of the 
energy comes from the fossil natural gas used to drive the process. The 
system has an overall average energy efficiency ratio of 71.9 percent, 
meaning it takes approximately 1.4 million Btu (mmBtu) of total natural 
gas (RNG and fossil natural gas) to produce 1.0 mmBtu of hydrogen fuel.
    For compression and pre-cooling of hydrogen in all scenarios, the 
energy source is assumed to be electricity from the average U.S. 
electrical grid. Table IX.H.2-1 provides examples of the amount of 
electricity that GREET assumes for various steps of the finished 
hydrogen fuel transportation, delivery, and vehicle fueling process. We 
recognize that these values can vary based on factors such as fuel 
volumes delivered, transportation distance, and residence time of the 
hydrogen fuel that requires cooling, among others. The hydrogen fuel is 
assumed to be used in hydrogen fuel cell electric vehicles and 
therefore has no associated tailpipe GHG emissions.
---------------------------------------------------------------------------

    \343\ Hydrogen fuel needs to be compressed to high pressures to 
reduce its volume for onboard storage tanks in vehicles. As light-
duty vehicles are more space limited, they typically refill using 
gaseous hydrogen fuel compressed to 700 bar or approximately 10,000 
psi. Heavy-duty vehicles can carry larger tanks and typically refill 
using hydrogen fuel compressed to 350 bar or approximately 5,000 
psi. More energy is needed to achieve higher levels of compression.

       Table IX.H.2-1--Electricity Required for Hydrogen Fuel Compression and Pre-Cooling From GREET 2021
                                                   [kWh/kg H2]
----------------------------------------------------------------------------------------------------------------
                                                                              H2 compressor at
                                                              Compressor to        vehicle      Pre-cool  H2 for
                                                              load gaseous        refueling          vehicle
                                                            tube-trailer for       station          refueling
                                                               H2 delivery
----------------------------------------------------------------------------------------------------------------
Centralized Gaseous Hydrogen Fuel Production:
    Light-Duty FCEVs (700 bar H2) \343\...................              1.30              1.98              0.30
    Medium- and Heavy-Duty FCEVs (350 bar H2).............  ................              1.25  ................
Distributed Hydrogen Fuel Production:
    Light-Duty FCEVs (700 bar H2).........................               N/A              3.11              0.30
    Medium- and Heavy-Duty FCEVs (350 bar H2).............  ................              2.27  ................
----------------------------------------------------------------------------------------------------------------


[[Page 80690]]

    In addition to the GREET default assumptions supported by industry 
data, we also present GREET results that make use of assumptions from 
NREL's Hydrogen Analysis (H2A) model in the table below. NREL assumes a 
similar 72.0 percent conversion efficiency for centralized steam 
methane reforming. H2A also assumes that a small percentage 
(approximately 1.2 percent) of the total energy to produce the hydrogen 
in centralized SMR comes from grid electricity, unlike the default 
GREET assumptions. We present both the default GREET results and those 
from GREET using NREL H2A assumptions in Table IX.H.2-2 below to show a 
range of values from the model.

Table IX.H.2-2--Lifecycle GHG Emissions for Producing Gaseous and Liquid Hydrogen From Centralized Steam Methane
    Reforming (SMR) Using Landfill Gas as Feedstock and Natural Gas as the Predominant Process Energy Source
                                              [kgCO2e/mmBtu] \344\
----------------------------------------------------------------------------------------------------------------
                                                       Gaseous hydrogen fuel           Liquid hydrogen fuel
                                                 ---------------------------------------------------------------
                                                                    GREET using                     GREET using
                                                  GREET  default     NREL H2A     GREET  default     NREL H2A
                                                    assumptions     assumptions     assumptions     assumptions
----------------------------------------------------------------------------------------------------------------
Domestic & International Land Use Change........             0.0             0.0             0.0             0.0
Feedstock Production & Transport................             9.2             9.2            10.0            10.0
Fuel Production.................................            11.4            25.8            39.0            53.6
Tailpipe........................................             0.0             0.0             0.0             0.0
Lifecycle GHG Emissions.........................            20.5            34.9            49.0            63.5
----------------------------------------------------------------------------------------------------------------

    The third scenario shown below in Table IX.H.2-3 represents 
lifecycle GHG emissions for producing gaseous hydrogen fuel using a 
smaller-scale SMR for distribution directly at a refueling station 
(also referred to as distributed production or forecourt natural gas 
reforming). This configuration would be analogous to a gas station that 
produces its own gasoline onsite. This scenario still assumes the 
feedstock is renewable natural gas sourced from landfill biogas and it 
arrives at the distributed SMR via natural gas pipeline. The SMR 
process is assumed to use a mixture of grid-based electricity and 
fossil natural gas for converting the RNG feedstock into hydrogen fuel. 
GREET assumes the system has an overall average efficiency ratio of 
74.2 percent while NREL's H2A model assumes the process is 71.4 percent 
efficient. The gaseous hydrogen is compressed and pre-cooled to allow 
for fast vehicle refueling, using electricity from average U.S. 
electrical grid as the energy source. As with the other scenarios, the 
hydrogen fuel is assumed to be used in hydrogen fuel cell electric 
vehicles and results in no tailpipe GHG emissions.
---------------------------------------------------------------------------

    \344\ Results are presented from Argonne Greenhouse gases, 
Regulated Emissions, and Energy use in Technologies (GREET) Model 
where the model is set to use landfill gas as the source of natural 
gas for methane feedstock in the SMR process. GREET's default 
assumptions represent process energy to be 100 percent natural gas. 
To review the complete spreadsheet assumptions, see 
``GREET1_2021rev1--Hydrogen Central SMR Scenarios.xlsm'' and 
``GREET1_2021rev1--Hydrogen Central SMR Scenarios--H2A 
Assumptions.xlsm'' in the docket.

 Table IX.H.2-3--Lifecycle GHG Emissions for Producing Gaseous Hydrogen
  From Distributed Steam Methane Reforming (SMR) Using Landfill Gas as
  Feedstock and Natural Gas and Grid Electricity as the Process Energy
                                 Sources
                          [kgCO2e/mmBtu] \345\
------------------------------------------------------------------------
                                             Gaseous hydrogen fuel
                                     -----------------------------------
                                        GREET default   GREET using NREL
                                         assumptions     H2A assumptions
------------------------------------------------------------------------
Domestic & International Land Use                  0.0               0.0
 Change.............................
Feedstock Production & Transport....              12.2              12.2
Fuel Production.....................              18.5              20.1
Tailpipe............................               0.0               0.0
Lifecycle GHG Emissions.............              30.7              32.3
------------------------------------------------------------------------

    We request comment on the lifecycle GHG estimates presented for 
hydrogen fuel produced from an SMR process based on information from 
the GREET model. We also invite comment on our intent to combine GREET 
data with information from pathway petitions submitted pursuant to 40 
CFR 80.1416, with adjustments to account for aspects of each facility 
and how they plan to distribute hydrogen to end users. This would allow 
us to determine whether proposed pathways satisfy CAA lifecycle GHG 
emission reduction requirements for RFS-qualifying renewable fuels on a 
facility-specific basis. Based on the data presented here, hydrogen 
fuel produced from RNG in an SMR may qualify for either advanced (D-
code 5) RINs or cellulosic (D-code 3) RINs when compared against the

[[Page 80691]]

petroleum baseline fuel.\346\ However, EPA is not determining whether 
hydrogen fuel produced from RNG in an SMR meets any particular GHG 
reduction threshold at this time and we intend to evaluate petitions 
for hydrogen fuel and determine RIN eligibility on a case-by-case 
basis, in the context of specific proposed pathways.
---------------------------------------------------------------------------

    \345\ Results are presented from Argonne Greenhouse gases, 
Regulated Emissions, and Energy use in Technologies (GREET) Model 
where the model is set to use landfill gas as the source of natural 
gas for methane feedstock in the SMR process. To review the complete 
spreadsheet assumptions, see ``GREET1_2021rev1--Hydrogen Distributed 
SMR Scenarios.xlsm'' and ``GREET1_2021rev1--Hydrogen Distributed SMR 
Scenarios--H2A Assumptions.xlsm'' in the docket.
    \346\ While it may be reasonable to compare hydrogen fuel 
against either petroleum gasoline or diesel, as we expect most 
hydrogen fuel will be used in medium- and heavy-duty fuel cell 
electric vehicles, we have opted to compare hydrogen fuel against a 
diesel fuel baseline as the predominant fuel used currently for 
those vehicles.
---------------------------------------------------------------------------

3. Hydrogen Fuel Cell Electric Vehicle Efficiency
    Similar to battery electric vehicles (BEVs), fuel cell electric 
vehicles (FCEVs) rely on electric motors in their drivetrains, which 
more efficiently convert fuel into useful work than internal combustion 
engines. FCEVs can drive approximately 1.5-2.5 times as far using 
gaseous hydrogen compared to conventional gasoline- or diesel-powered 
vehicles using an energy-equivalent amount of fuel. While the LCA 
estimates above from GREET are based on the energy content of hydrogen 
fuel and do not consider vehicle efficiency, it may be appropriate to 
calculate lifecycle GHG emissions for hydrogen fuel used in FCEVs by 
accounting for this increased vehicle fuel efficiency for hydrogen 
compared to conventional fuels such as diesel or gasoline. This would 
require the identification of an appropriate value or values to account 
for this significant difference in relative vehicle powertrain fuel 
efficiency in our lifecycle GHG calculations.\347\
---------------------------------------------------------------------------

    \347\ We similarly accounted for the relative increase in per 
mmBtu efficiency use of fuel for battery electric vehicle 
drivetrains as part of the RFS Pathways II and Technical Amendments 
to the RFS 2 Standards proposed rule (78 FR 36042). For that 
lifecycle GHG analysis, accounting for EV efficiency was considered 
but ultimately not deemed necessary to include for a pathway of 
renewable electricity from landfill gas due to the GHG percent 
reduction threshold already exceeding the 60 percent cellulosic 
biofuel target before considering vehicle efficiency.
---------------------------------------------------------------------------

    One consideration in assessing hydrogen FCEV efficiency data is 
that values for this relatively nascent technology vary significantly 
across government sources and the peer-reviewed literature. Another 
consideration is that the varied vehicle duty cycles can yield 
significantly different vehicle fuel efficiencies relative to 
conventional gasoline and diesel vehicles (e.g., passenger vehicles 
compared to long-haul truck freight delivery). Though not meant to be 
comprehensive, we present various examples of this kind of data below 
in Table IX.H.3-1. As the data comes presented in various formats, we 
have conformed the sources below to the same metric for better 
comparison using the Energy Economy Ratios (EERs) developed by the 
California Air Resources Board for the California Low Carbon Fuel 
Standard, which provide a relative ratio for efficiency between two 
vehicle powertrain/fuel technology combinations. A higher EER value 
represents a greater relative efficiency of hydrogen FCEVs compared to 
either gasoline or diesel equivalent technologies.

  Table IX.H.3-1--Example Fuel Cell Electric Vehicle Efficiency Factors
------------------------------------------------------------------------
                                Relative vehicle
                                 fuel efficiency
                                factors comparing
            Source                  FCEVs to              Details
                                  conventional
                                    vehicles
------------------------------------------------------------------------
California Air Resources                      1.9  Heavy-Duty/Off-Road
 Board (Low Carbon Fuel                             Applications (Fuels
 Standards) \348\.                                  used as diesel
                                                    replacement) Energy
                                                    Economy Ratio (EER)
                                                    Values Relative to
                                                    Diesel.
                                              2.5  Light/Medium-Duty
                                                    Applications (Fuels
                                                    used as gasoline
                                                    replacement) Energy
                                                    Economy Ratio (EER)
                                                    Values Relative to
                                                    Gasoline.
Argonne National Laboratory                  1.95  Vehicle fuel
 (GREET 2021 Well-to-Wheels                         efficiency
 Calculator) \349\.                                 comparison between a
                                                    modeled diesel
                                                    passenger vehicle
                                                    (3,553 btu/mile)
                                                    divided by modeled
                                                    hydrogen gas
                                                    passenger vehicle
                                                    (1,825 btu/mile).
                                             2.35  Vehicle fuel
                                                    efficiency
                                                    comparison between a
                                                    modeled gasoline
                                                    passenger vehicle
                                                    (4,289 btu/mile)
                                                    divided by modeled
                                                    hydrogen gas
                                                    passenger vehicle
                                                    (1,825 btu/mile).
National Renewable Energy                    1.28  Comparison of current
 Laboratory Report: Spatial                         class 8 long haul
 and Temporal Analysis of the                       (750 miles) modeled
 Total Cost of Ownership for                        FCEV truck fuel
 Class 8 Tractors and Class 4                       efficiency (11 miles/
 Parcel Delivery Trucks                             diesel-gallon
 (FastSIM) \350\.                                   equivalent) divided
                                                    by comparable diesel
                                                    truck efficiency
                                                    (8.6 mi/dge).
                                             1.54  Comparison of current
                                                    class 4 parcel
                                                    delivery modeled
                                                    FCEV truck fuel
                                                    efficiency (15.6
                                                    miles/diesel-gallon
                                                    equivalent) divided
                                                    by comparable diesel
                                                    truck efficiency
                                                    (10.1 mi/dge).
------------------------------------------------------------------------

    We can account for the relative efficiency of hydrogen FCEVs and 
the use of hydrogen fuel by combining the LCA estimates we present from 
GREET above in Section IX.H.2 that represent GHGs based on the energy 
content of the fuel, with the relative vehicle efficiency factors in 
Table IX.H.3-1. By dividing the lifecycle GHG emissions of the fuel by 
the relative vehicle fuel efficiency, we obtain new lifecycle GHG 
values, adjusted to represent the relative efficiency of the vehicle 
compared to either a gasoline or diesel vehicle using the same amount 
of fuel energy.
---------------------------------------------------------------------------

    \348\ California Code of Regulations, Title 17, Sec.  95486.1--
Generating and Calculating Credits and Deficits Using Fuel Pathways, 
Table 5. EER Values for Fuels Used in Light- and Medium-Duty, and 
Heavy-Duty Applications.
    \349\ Argonne National Lab (2022) GREET WTW Calculator and 
Sample Results from GREET 1 2021, https://greet.es.anl.gov/tools.
    \350\ Hunter, C. et al. Spatial and Temporal Analysis of the 
Total Cost of Ownership for Class 8 Tractors and Class 4 Parcel 
Delivery Trucks. (2021). NREL/TP-5400-71796, https://www.osti.gov/servlets/purl/1821615 doi:10.2172/1821615. Values taken from 
Appendix H: EPA Regulatory Cycle Fuel Economy, Figure H1.
---------------------------------------------------------------------------

    For a conservative estimate to illustrate this approach, we can use 
the lowest vehicle efficiency factor in Table

[[Page 80692]]

IX.H.3-1, a value that represent Class 8 long-haul trucks from a recent 
NREL study of 1.28, meaning that it would be expected that FCEV Class 8 
long-haul trucks would be approximately 1.28 times more efficient with 
an equal amount of hydrogen fuel energy compared to a similar diesel 
engine truck running on an energy-equivalent amount of diesel fuel. 
Representing the highest efficiency value in Table IX.H.3-1, California 
Air Resources Board provides a value of 2.5 that represents light- and 
medium-duty FCEVs that replace similar gasoline-powered vehicles both 
using an energy-equivalent amount of fuel. Table IX.H.3-2 shows both 
the unadjusted and newly adjusted lifecycle GHG values assuming a low 
vehicle efficiency factor of 1.28 and a high vehicle efficiency factor 
of 2.5.

    Table IX.H.3-2--Lifecycle GHG Emissions for Producing Hydrogen Using SMR With Landfill Gas Feedstock, and
  Adjusted GHG Emissions Accounting for FCEV Fuel Efficiency, Assuming Low and High Vehicle Efficiency Factors
                                                 [kgCO2e/mmBtu]
----------------------------------------------------------------------------------------------------------------
                                                            Centralized SMR:  Centralized SMR:  Distributed SMR:
                                                            gaseous hydrogen   liquid hydrogen  gaseous hydrogen
                                                                  fuel              fuel              fuel
----------------------------------------------------------------------------------------------------------------
Lifecycle GHG Emissions (GREET Default Assumptions).......              20.5              30.7              49.0
Adjusted Lifecycle GHG Emissions (Assuming Low Vehicle                  16.0              24.0              38.2
 Efficiency Factor: 1.28).................................
Adjusted Lifecycle GHG Emissions (Assuming High Vehicle                  8.2              12.3              19.6
 Efficiency Factor: 2.5)..................................
----------------------------------------------------------------------------------------------------------------

    We seek public comment on whether it is appropriate to account for 
the relative vehicle/powertrain efficiency of hydrogen FCEVs compared 
to conventional gasoline and diesel vehicles for the purpose of 
lifecycle GHG analysis of hydrogen as a RIN-generating fuel under the 
RFS program. Furthermore, we seek additional data associated with the 
relative efficiency of FCEVs compared to conventional vehicles and 
whether it would be appropriate to make a single average assumption 
across all vehicle types or if we should define and differentiate 
different vehicle groupings.
4. Global Warming Potential of Hydrogen
    A Global Warming Potential (GWP) is a quantified measure of the 
globally averaged relative radiative forcing impacts of a particular 
GHG relative to carbon dioxide. Although hydrogen is not considered a 
direct greenhouse gas and the IPCC and UNFCCC have not identified and 
established a GWP associated with hydrogen,\351\ we are aware of 
literature suggesting there are indirect radiative effects caused by 
the presence of emitted hydrogen in the troposphere.\352\ While the LCA 
values above from GREET do not include a GWP for hydrogen, limited 
literature suggests that hydrogen released to the troposphere may 
affect ozone concentrations and prolong the lifetime of resident 
methane.\353\ Due to its extremely small molecular size, it is expected 
there would be leakage of gaseous hydrogen during production, 
transportation, storage, and dispensing into vehicles. We seek data on 
the leakage and venting rates of hydrogen throughout its production, 
storage, distribution, and use. We also seek comment on additional data 
and sources of information related to the global warming potential of 
hydrogen to consider in evaluating the lifecycle GHG emissions of 
hydrogen as a transportation fuel under the RFS program.
---------------------------------------------------------------------------

    \351\ Framework Convention on Climate Change; January 31, 2014; 
Report of the Conference of the Parties at its nineteenth session; 
held in Warsaw from 11 to 23 November 2013; Addendum; Part two: 
Action taken by the Conference of the Parties at its nineteenth 
session; Decision 24/CP.19; Revision of the UNFCCC reporting 
guidelines on annual inventories for Parties included in Annex I to 
the Convention; p. 2. (UNFCCC 2014). Available at: http://unfccc.int/resource/docs/2013/cop19/eng/10a03.pdf.
    \352\ Derwent, R., et al. (2006). Global environmental impacts 
of the hydrogen economy. International Journal of Nuclear Hydrogen 
Production and Applications, 1(1), 57. https://doi.org/10.1504/IJNHPA.2006.009869.
    \353\ Forster, Piers, et al. (2018). Changes in Atmospheric 
Constituents and in Radiative Forcing. IPCC. p. 106. https://www.ipcc.ch/site/assets/uploads/2018/02/ar4-wg1-chapter2-1.pdf.
---------------------------------------------------------------------------

    Hydrogen is an evolving source of transportation fuel, and we seek 
to use the best available data and modeling information as we evaluate 
the RFS pathway petitions we have before us. We invite comment on the 
issues discussed above in the context of evaluating the lifecycle GHG 
emissions of hydrogen fuel from renewable biogas as a feedstock in 
support of resolving the pathway petitions before the agency. EPA is 
not addressing the question of whether hydrogen fuel produced from RNG 
in an SMR meets any GHG reduction threshold at this time and intends to 
evaluate petitions for hydrogen fuel as well as determine RIN 
eligibility on a case-by-case basis, in the context of facility-
specific pathway petitions.

I. Biogas Regulatory Reform

1. Background
    In Section VIII.A, we explain in detail the current regulatory 
provisions for biogas to renewable CNG/LNG. We also describe in Section 
VIII.D our reasons for concluding that the current regulatory 
provisions for biogas to renewable CNG/LNG are not an appropriate model 
for the design of the proposed eRINs program. We explain that 
challenges associated with implementing the existing program for biogas 
to renewable CNG/LNG largely arise from flexibility in the current 
regulations that allow for any party in the biogas production, 
distribution, and use chain (and even those outside of it) to generate 
RINs. This situation is particularly complex in the case where biogas 
is upgraded to RNG and then injected into the commercial pipeline 
system because there are potentially dozens of parties that would need 
to enter into contractual relationships for the movement, storage, and 
use of the RNG; and the RIN generator must demonstrate both at 
registration and prior to generating a RIN that each party in the chain 
produced, distributed, and/or used the RNG in a manner consistent with 
its use as transportation fuel.
    Since promulgation of the existing regulatory provisions for biogas 
to renewable CNG/LNG in the RFS Pathways II rule,\354\ many parties 
have asked EPA to accept registrations under the existing pathways for 
the generation of RINs for renewable electricity produced from biogas, 
and to approve pathways to allow the use of biogas as a biointermediate 
to produce various types of fuels (e.g., steam methane

[[Page 80693]]

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 use of advanced and cellulosic renewable fuels. While we 
recognize the opportunity to increase the availability of advanced and 
cellulosic biogas-derived renewable fuels in support of the statutory 
goals, we also note that allowing biogas or contracted RNG to be used 
as an input to produce a fuel other than renewable CNG/LNG entails 
adding yet further layers of complexity to a system that is already 
complex to implement and oversee. We therefore believe that the 
existing regulatory requirements for renewable CNG/LNG must first be 
modified to ensure that biogas is not double-counted in a situation 
where biogas may have multiple uses. We do not believe that the current 
regulatory program is well-suited to avoid the double counting of RNG 
where RNG could be used under the RFS program for more than one use.
---------------------------------------------------------------------------

    \354\ See 79 FR 42128 (July 18, 2014).
---------------------------------------------------------------------------

    As clarification, biogas is the product from anaerobic digesters 
and landfills before any purification has occurred. After purification, 
the biogas becomes RNG. Both biogas and RNG can be compressed or 
liquified to produce renewable CNG or renewable LNG, respectively. 
Under our proposal, the biogas producer is the party that produces the 
biogas and the RNG producer is the party that upgrades the biogas into 
RNG and injects the RNG into the natural gas commercial pipeline 
system.
    The potential expanded use of RNG to renewable electricity, coupled 
with the potential use of RNG as a biointermediate to produce renewable 
fuels, could make the program impracticable to oversee within the 
current regulatory structure. Since biogas may have multiple uses, we 
believe it would be crucial to take steps to minimize the potential for 
generating invalid or fraudulent RINs, including the double counting of 
RINs, should we accept registrations for the use of renewable 
electricity and/or approve additional pathways to allow the use of 
biogas as a biointermediate. We believe such measures are necessary 
because EPA would potentially be tracking and overseeing increased 
volumes of biogas, and as highlighted in Section VIII.D.4, 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 on a commercial pipeline 
system). 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. We also have concerns that the existing program's complexity 
would not be well-suited to cover the potentially hundreds of 
additional biogas and RNG production facilities that would come online 
as a result of the proposed eRINs program and allowing biogas and RNG 
to be used as a biointermediate.
    Therefore, in order to better facilitate the potential expanded use 
of biogas and RNG for renewable electricity and other biointermediates, 
and to reduce the burden associated with implementing the current 
biogas to renewable CNG/LNG program, we are proposing to modify the 
existing compliance and enforcement provisions for biogas to renewable 
CNG/LNG. The proposed changes would provide a more comprehensive, yet 
streamlined, tracking and oversight program for biogas and RNG. We 
recently finalized regulations for other biointermediates.\355\ At that 
time, we deferred taking action to address the use of biogas or RNG as 
a biointermediate so that we could comprehensively address the unique 
aspects of biogas for a variety of potential uses, including to produce 
renewable electricity for the purpose of generating eRINs, in a future 
rulemaking. This proposal, if finalized, would allow 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. The key elements of the biogas regulatory reforms we are now 
proposing include the following:
---------------------------------------------------------------------------

    \355\ See 87 FR 39635-39651 (July 1, 2022).
---------------------------------------------------------------------------

     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 
onto a commercial pipeline;
     A requirement that only 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 chain; and
     Specific provisions to address when biogas or RNG is used 
as renewable electricity or as a biointermediate.
    We discuss each of these proposed key elements in more detail 
below. Furthermore, we are also proposing to remove regulatory 
provisions that would no longer be necessary should we finalize the 
proposed biogas regulatory reforms. For example, should EPA finalize 
this proposal, much of the documentation currently required to be 
submitted to EPA at registration would no longer be necessary to 
submit, including much of the documentation currently required to 
demonstrate the contractual relationships between each party in the 
biogas production and distribution chain. We note, however, that under 
our proposal the registration of biogas production facilities (e.g., 
landfills and agricultural digesters) would still be maintained because 
those requirements are necessary to ensure that the biogas was produced 
from renewable biomass under an EPA-approved pathway consistent with 
the Clean Air Act.
    We are not proposing to revisit or reopen the pathways for biogas 
established in the RFS Pathways II rule. We are also not proposing any 
additional pathways for biogas in this action. 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.
2. Biogas Under a Closed Distribution System
    There are two approaches to generating RINs from biogas to 
renewable CNG/LNG under the existing regulations: (1) biogas in a 
closed, private, non-commercial distribution system that is compressed 
to renewable CNG/LNG, and (2) biogas upgraded to RNG, injected onto a 
commercial pipeline system, and then compressed to renewable CNG/
LNG.\356\ The focus of this proposed regulatory reform deals with RNG 
injected onto the natural gas commercial pipeline system. We are 
proposing only minor modifications to the existing regulatory 
provisions for biogas used to produce a renewable fuel when the biogas 
is produced, made into a renewable fuel, and used as transportation 
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

[[Page 80694]]

an extended production, distribution, and use chain. As such, the focus 
of the proposed biogas regulatory reform provisions is centered on the 
movement of biogas that is upgraded to RNG and then injected onto the 
natural gas commercial pipeline system for later use as transportation 
fuel.
---------------------------------------------------------------------------

    \356\ See 40 CFR 80.1426(f)(10) and (11).
---------------------------------------------------------------------------

    We are proposing that parties that generate RINs for biogas to 
renewable CNG/LNG via a closed distribution system would continue to 
operate under similar regulatory provisions to those currently in 
place. However, we note that to help ensure consistency in the 
regulatory requirements for all biogas-derived renewable fuels, we are 
proposing to move the provisions for biogas to renewable CNG/LNG via a 
closed distribution system into the newly proposed 40 CFR subpart E. It 
is not our intention to make significant changes to these regulatory 
requirements. However, we nevertheless seek comment on whether and how 
to streamline the regulatory requirements for biogas to renewable CNG/
LNG via a closed distribution system.
    We also note that under this proposal, to the extent that 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 would have to separately register with EPA, as 
discussed in Section VIII.L.1. We are proposing this requirement to 
ensure that biogas producers are treated consistently throughout the 
program and to help us identify how parties are related in the biogas 
production, distribution, and use 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.
3. RNG Producer as the RIN Generator
    We are proposing that RNG producers would be the sole RIN 
generators, and that they would generate RINs for RNG they produce and 
inject into a commercial pipeline. Under the existing regulations, we 
allow for any party to generate RINs from biogas-derived renewable 
fuels, even parties that are not part of the biogas production or 
distribution 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.\357\ 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 potential expansion in the use of 
biogas as a biointermediate, we now believe that it is important to 
designate a RIN generator.
---------------------------------------------------------------------------

    \357\ 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 the proposed 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 would effectively be tracked in EMTS from RNG 
injection through withdrawal for transportation use via the assignment 
and separation of RINs, as discussed in more detail in Section IX.I.4 
below. This approach significantly reduces double counting concerns 
since a specific volume of RNG would have corresponding RINs assigned 
to it, and by specifying that the RINs could 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 would 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 injected into the 
commercial pipeline system.
    We also considered designating other parties as the RIN generator. 
For example, we considered designating the party that produces or uses 
the renewable CNG as the RIN generator. However, if we proposed such an 
approach, then we would largely forgo any tracking benefits provided by 
following transfers of the assigned RIN for a volume of RNG because the 
RNG would have already traversed the entirety of the natural gas 
commercial pipeline system before the RIN was generated and assigned. 
This approach would not remedy the issue that would arise under the 
existing program with regard to double counting and tracking; i.e., the 
RNG would have to be tracked via a complicated series of contractual 
relationships instead of electronically and the downstream party and 
EPA acting in its oversight capacity would have to go to great lengths 
to ensure that the RNG was not multiple counted before the RIN was 
generated.
    We recognize that this proposed change could affect a number of 
parties that are currently registered to generate RINs for biogas to 
renewable CNG/LNG; however, we think this step is necessary to 
implement the other proposed changes discussed below that would greatly 
simplify the program while improving our ability to effectively oversee 
it. Furthermore, by making the RNG producer the RIN generator, we can 
greatly improve our ability to track the movement of the RNG via RINs 
assigned at the point of injection as discussed in Section IX.I.4.
    We seek comment on our proposal to designate the RNG producer as 
the RIN generator for RNG injected into a commercial pipeline system. 
We also seek comment on whether we should consider designating a 
different party as the RIN generator.
4. Assignment, Separation, Retirement, and Expiration of RNG RINs
    Under this proposal, we are proposing to revise the regulations to 
specify how parties would assign, separate, and retire RINs generated 
for RNG. Under the current biogas to renewable CNG/LNG regulations, 
RINs are generated after any party in the CNG/LNG generation/
disposition chain demonstrates that a specific amount of RNG was used 
as transportation fuel.
    For RIN assignment, we are proposing that the RNG producer or RNG 
importer, i.e., the RIN generator, 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 
same volume of RNG as the volume moves through the natural gas 
commercial pipeline system.\358\ The purpose of this proposed 
requirement is to ensure that the RIN, as tracked through EMTS, would 
follow the transfer of title of the RNG as the RNG moves through the 
natural gas commercial pipeline system.
---------------------------------------------------------------------------

    \358\ 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 proposing that only the party that 
demonstrates that the RNG was actually used as transportation fuel 
would be eligible to separate the RINs generated for the RNG from the 
RNG itself. For example, the party that compresses the RNG into 
renewable CNG or renewable LNG and demonstrates that the renewable CNG/
LNG is used as

[[Page 80695]]

transportation fuel would be eligible to separate the RINs from the 
RNG. This is a different approach than currently taken under the 
existing regulations. At present, the party that generates the RINs 
from a volume of biogas immediately separates any RINs generated for 
that biogas 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 RNG's distribution chain, which necessitates tracking via 
contractual relationships, as discussed above, and forgoes any tracking 
capabilities of EMTS that could be leveraged by tracking assigned RINs 
for volumes of RNG as the RNG moves through the commercial pipeline 
system. Our proposed changes would allow for RINs assigned to a given 
volume of RNG to be tracked via EMTS as the RNG moves through the 
commercial pipeline system from injecting to withdrawal. Similarly, we 
are also proposing to clarify that the existing provisions that require 
obligated parties to separate assigned RINs when they take title to any 
assigned RINs would 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 to renewable CNG/LNG, we believe that having the 
party that has the documentation needed to demonstrate that the RNG was 
used as transportation fuel as renewable CNG or renewable LNG is the 
party best positioned to separate the RIN because they are also the 
party best positioned to demonstrate that the RNG is used as 
transportation fuel in the form of renewable CNG/LNG. This is analogous 
to the provisions that require parties blending denatured fuel ethanol 
(DFE) into gasoline to separate any assigned RINs for the denatured 
fuel ethanol at fuel terminals (i.e., the point at which we believe it 
is reasonable to assume that the DFE will be used as transportation 
fuel).\359\ Similarly, we believe that once a party has turned RNG into 
renewable CNG or renewable LNG, we can reasonably assume that the 
renewable CNG or renewable LNG would be used as transportation fuel.
---------------------------------------------------------------------------

    \359\ 40 CFR 80.1429.
---------------------------------------------------------------------------

    To address the potential issue of double counting an RNG RIN where 
a party claims the RNG is used as renewable CNG/LNG and as renewable 
electricity, we are proposing that renewable electricity generators 
that use RNG to generate renewable electricity under the proposed eRINs 
program would have to retire the assigned RINs for the RNG they use to 
generate renewable electricity. As described in Section VIII.F.5.e, the 
renewable electricity generator would then transfer the RIN generation 
allotment for the renewable electricity generated from the RNG to the 
OEM for the subsequent generation of eRINs. Similarly, for RNG used as 
a biointermediate, we are proposing to require that the party that uses 
the RNG as a biointermediate retire the assigned RIN for the RNG used 
as a biointermediate, and then generate a separate RIN using the 
procedures for RIN generation for the new renewable fuel.
    Under our proposal, RNG RINs would 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 before the annual compliance deadline for the 
compliance year following the year in which that RNG RIN was generated, 
the RNG RIN would expire after the subsequent year's compliance 
deadline has passed. For example, if a RIN is generated for RNG 
injected into the natural gas commercial pipeline in 2024, then that 
RNG RIN would 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, to produce 
renewable electricity, or as a biointermediate, then the RNG RIN would 
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 are merely 
highlighting how the proposed biogas regulatory reform provisions would 
operate under the existing provisions. We also note that that this 
provision would 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 would 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 would help encourage parties to use RNG as 
transportation fuel under the RFS before the RIN expires.
    The benefits of this proposed approach to both EPA and the 
regulated community are manifold. First, this approach would 
significantly increase the ability for the title to RNG to be tracked 
and overseen because the transfer of title to RNG would follow the 
assigned RIN and would be reported in EMTS. EPA and third parties would 
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. EPA's 
proposed approach would greatly simplify the auditing process for both 
EPA and third parties allowing for increased program oversight.
    Second, the proposed approach for RNG RINs would allow us to 
streamline the registration, reporting, and recordkeeping requirements 
for RNG and RNG RINs by utilizing EMTS for tracking. This would create 
a number of efficiencies. With regard to registration, it would 
eliminate the need for parties to submit contracts at registration. The 
requisite contractual chains can potentially involve dozens of parties 
and hundreds of CNG/LNG dispensers or CNG/LNG vehicle fleets. Each 
contract can be several hundred pages in length, and changing 
relationships between the parties involved often results in the need 
for RIN-generating parties to frequently update their registration 
information. The proposed approach would eliminate these 
inefficiencies. For reporting, since the RNG and RNG RINs would be 
tracked in EMTS, we would no longer need to 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, under the proposed 
approach, EMTS would electronically provide real-time data concerning 
how a given volume of RNG is transferred and ultimately used. This 
would eliminate the need for the existing provisions that require RIN 
generators to obtain documents from every party in the chain in the 
form of additional contracts, affidavits, or real-time electronic data. 
These proposed registration, reporting, and recordkeeping requirements 
would significantly streamline program implementation for EPA and 
reduce the compliance burden on regulated parties.

[[Page 80696]]

    Third, our proposed approach minimizes the potential for a given 
volume of RNG to be counted more than once. To date, we have not had to 
address double counting because we have only accepted registrations for 
converting RNG to renewable CNG/LNG. However, if we finalize the 
proposed eRINs program and/or allow for the use of biogas as a 
biointermediate, then double counting would be a concern since RNG 
could have multiple uses within the RFS program, including converting 
RNG to renewable CNG/LNG, using RNG to generate renewable electricity 
under the proposed eRINs program, or using RNG as a biointermediate to 
produce a renewable fuel other than renewable CNG/LNG or renewable 
electricity.
    We believe our proposed approach mitigates the risk of counting a 
given volume of RNG more than once because we are proposing to clearly 
specify the point in the process when RNG RINs may be generated (i.e., 
at the point where RNG is injected into the commercial pipeline system) 
and the point in the process when RNG RINs may be separated (i.e., when 
the RNG is demonstrated to be used as a transportation fuel). Because 
the RNG may only be injected into the pipeline once and because an 
assigned RNG RIN may only be separated once, this specificity 
significantly reduces 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.
5. Proposed Regulatory Provisions for Biogas Regulatory Reform
    To assist in the implementation of the treatment of RNG RINs under 
this proposal, we are proposing to require that specific parties in the 
RNG disposition/generation chain participate in the RFS program and 
meet certain regulatory requirements. Under this biogas regulatory 
reform proposal, we are proposing specific regulatory requirements for 
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); and
     The party that demonstrates that the RNG was used as 
transportation fuel in the form of renewable CNG/LNG, used to generate 
renewable electricity, or used as a biointermediate to produce a 
renewable fuel other than renewable CNG/LNG or electricity (the RNG RIN 
separator).
    Like the eRINs proposal described in Section VIII.F, regulatory 
requirements for each of these key parties is necessary to ensure that 
the biogas is produced and converted to RNG consistent with CAA and 
regulatory requirements, and the RNG is used as transportation fuel 
consistent with Clean Air Act and regulatory requirements. Specifying 
the requirements applicable to each party would enable us 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. 
Below, we discuss the specific regulatory requirements we are proposing 
for each party in the RNG disposition/generation chain.
a. Proposed Requirements for Biogas Producers
    Under the biogas regulatory reform proposal, biogas producers would 
be required to comply with the same proposed regulatory requirements 
described in Section VIII.F and Section VIII.L because it is our intent 
to regulate all biogas producers in the same manner regardless of how 
their biogas may be used under the RFS program. In summary, biogas 
producers would need to register as described in Section VIII.L.1, 
submit reports as described in Section VIII.L.2, keep records as 
described in Section VIII.L.4, comply with PTD requirements for biogas 
as described in Section VIII.L.3, and undergo an annual attest 
engagement as described in Section VIII.O.2. The information we are 
proposing to collect from biogas producers is modelled off of what we 
currently collect from RIN generators as it relates to biogas 
production, with the key difference in our proposed approach versus the 
current regulatory approach being that, under our proposed approach, 
the biogas producers are responsible for complying with the 
requirements related to biogas production, as opposed to these 
requirements being placed on RIN generators.
b. Proposed Requirements for RNG Producers
    We are proposing that RNG producers would register as described in 
Section VIII.L.1. Specifically, RNG producers would demonstrate at 
registration the RNG production capacity of their facility, how their 
facility is connected to the natural gas commercial pipeline system, 
and how they would meet the applicable sampling, testing, and 
measurement requirements to ensure that RNG meets applicable pipeline 
specifications as described in Section VIII.L.1. Like other RIN 
generators, RNG producers would be required to undergo an initial 
third-party engineer review as well as three-year registration updates 
which would include a new third-party engineer review.
    We are also proposing that RNG producers would be required to 
submit quarterly reports on the amount of RNG they produced and 
injected into the natural gas commercial pipeline system. These reports 
would include information related to the volume and energy content of 
the injected RNG. We note that these proposed reports are intended to 
replace existing reporting requirements that RIN generators for biogas 
to renewable CNG/LNG must submit on a quarterly basis.\360\ We are 
proposing to remove the existing regulatory requirements related to 
demonstrating that contracts or affidavits were obtained from parties 
in the RNG distribution chain, since this tracking would now be done 
via EMTS, as described in Section IX.I.4. We believe this would greatly 
simplify the quarterly reporting requirements related to RNG when 
compared to the existing biogas to renewable CNG/LNG regulatory 
provisions.
---------------------------------------------------------------------------

    \360\ RFS0601: Renewable Fuel Producer Supplemental report.
---------------------------------------------------------------------------

    As part of this biogas regulatory reform proposal, we are proposing 
recordkeeping requirements related to RNG production, injection, and 
RIN generation. For RNG production, RNG producers would be required to 
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 would be 
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.\361\ For RNG RIN generation, RNG producers 
would be required to 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 Clean Air Act requirements and applicable 
regulatory requirements, and that the appropriate number of RINs were

[[Page 80697]]

generated for the RNG injected into the natural gas commercial pipeline 
system. Since we are proposing to track the movement of assigned RNG 
RINs in EMTS, we would no longer require that the RIN generator (i.e., 
RNG producer under this proposed 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 would no longer be needed since EMTS would memorialize 
the necessary information pertaining to the transfer of the assigned 
RINs.
---------------------------------------------------------------------------

    \361\ 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 proposing that transfers of title for RNG would be 
accompanied by PTDs, consistent with transfers of title of renewable 
fuels elsewhere under the RFS program. Like PTDs for renewable fuels, 
the proposed PTDs for RNG would include the name and address 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 proposing that RNG 
producers would 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) would also apply to transfers of title for the RINs assigned 
to the RNG. We do not believe any changes to the RIN PTD provisions are 
necessary, but we seek comment on whether any additional RIN PTD 
language is needed concerning transfers of assigned RNG RINs.
    We are proposing that RNG producers undergo an annual attest 
engagement like other RIN generators under 40 CFR 80.1464(b). We are 
also proposing additional procedures that are specific to the 
production and injection of RNG into the natural gas commercial 
pipeline system. These proposed attest engagement provisions would 
verify that records related to the appropriate measurement of RNG 
injection is consistent with the measurement requirements for RNG 
described in Section VIII.O.2, and would verify that pipeline injection 
statements match the amount of RNG reported by RNG producers in 
quarterly reports is consistent. Attest auditors would also confirm 
that the correct number of RINs were generated in EMTS compared to the 
underlying records. The purpose of these proposed attest engagement 
procedures for RNG producers is to help ensure that RNG RINs were 
validly generated consistent with EPA's regulatory requirements for 
RNG. We note that the annual attest engagement procedures for EPA's 
fuels program would apply to RNG producers like other parties required 
to undergo an annual attest engagement under EPA's fuels program (e.g., 
obligated parties and renewable fuel producers). For example, RNG 
producers would have to identify in their registration information 
their independent attest auditor, and the independent attest auditor 
would electronically submit the annual attest engagement report 
directly to EPA using forms and procedures prescribed by EPA. We seek 
comment on the proposed annual attest engagement provisions for RNG 
producers.
c. Proposed Requirements for Parties That Own and Transact RNG RINs
    We are proposing 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) would have to 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, used to generate renewable electricity, or used as a 
biointermediate to produce renewable fuel would be allowed to separate 
the RNG RIN. In other words, parties that simply transact assigned RNG 
RINs would not be allowed to separate RINs, and we would intend to 
design EMTS to prevent them from doing so. As described in more detail 
in Section IX.I.4, this provision is necessary to ensure that RNG is 
used as transportation fuel consistent with the Clean Air Act and 
applicable regulatory requirements.
    With the exception of the limitation on RNG RIN separation, we note 
that we are not otherwise proposing to modify the requirements for 
parties that own and transact RNG RINs; we are simply highlighting how 
parties that solely own and transact RNG RINs would operate in the 
context of the proposed biogas regulations. As such, we will treat any 
comments on the current regulatory requirements for parties that own 
and transact RINs as beyond the scope of this action.
d. Proposed Requirements for RNG RIN Separators
    Because parties that separate RNG RINs (``RNG RIN separators'') are 
key to ensuring that RNG is used as transportation fuel, we are 
proposing additional requirements for RNG RIN separators to ensure that 
RNG RINs are separated only when allowed. We would expect that the RNG 
RIN separators would be parties that operate compression equipment to 
turn RNG into renewable CNG/LNG, dispensers that dispense renewable 
CNG/LNG into CNG/LNG vehicles, or parties that operate CNG/LNG vehicle 
fleets; however, under our proposal, we would allow only the party that 
has the documentation to demonstrate that the RNG was used as 
transportation fuel in the form of renewable CNG/LNG.
    We are proposing that RNG RIN separators would be required to 
register with EPA prior to RNG RIN separation, submit periodic reports 
to EPA on RNG RIN separation activities, maintain records, and undergo 
an annual attest audit. These requirements would apply to any party 
that separates RINs from RNG but would not include those parties that 
retire RNG RINs for renewable electricity generation (i.e., renewable 
electricity generators) and for using biogas as a biointermediate. We 
also note that, because RNG RIN separators would also own the RINs they 
are separating and would be able to transact them, the RNG RIN 
separator would be subject to all other regulatory requirements that 
apply to owning RINs under the RFS program generally. This includes 
additional reporting, recordkeeping, PTD, and annual attest engagement 
requirements. We are not intending to repropose the current regulatory 
requirements for RIN owners under the RFS program; instead, we are 
merely highlighting that these requirements would apply to RNG RIN 
separators. Accordingly, we will treat any comments received on the 
regulatory requirements for RNG RIN separators as beyond the scope of 
this action.
    The proposed registration requirements for RNG RIN separators would 
include provision of all the company information currently required 
from any party that registers under EPA's fuels program, which includes 
the RFS program.\362\ Additionally, in the case of RNG to renewable 
CNG/LNG, we are proposing that RNG RIN separators would describe at 
registration their capabilities to compress RNG into renewable CNG/LNG 
(i.e., convert RNG into renewable CNG/LNG) and their distribution and 
dispensing capabilities. The purpose of this requirement is to ensure 
that the RNG RIN separator can convert RNG into renewable CNG/LNG to be 
used as transportation fuel consistent with the Clean Air Act and 
applicable regulatory requirements. We note that we currently collect 
such information from the RIN generator under the current biogas to 
renewable CNG/LNG regulations; however, under this proposal, such 
information would instead come directly from the RNG RIN

[[Page 80698]]

separator--the party we believe is best positioned to demonstrate that 
the RNG was converted to renewable CNG/LNG and used as transportation 
fuel. For renewable electricity generators and parties that use biogas 
as a biointermediate, the registration requirements for renewable 
electricity generators described in Section VIII and the requirements 
for renewable fuel producers under 40 CFR 80.1450 would convey such 
information.
---------------------------------------------------------------------------

    \362\ See 40 CFR 1090.800 and 1090.805.
---------------------------------------------------------------------------

    We are not proposing to require a third-party engineering review 
for RNG RIN separators. We believe that RNG compression technology and 
verifying CNG/LNG dispensers is straightforward and that a third-party 
engineering review would be unnecessarily burdensome. We note that if a 
party is required to undergo a third-party engineering review because 
of a different activity, e.g., renewable electricity generation, that 
party would still need to undergo a third-party engineering review, if 
required. We seek comment on whether we should require that RNG RIN 
separators undergo a third-party engineering review as part of their 
registration requirements.
    For periodic reporting, we are proposing that RNG RIN separators 
submit quarterly reports related to their RNG RIN separation 
activities. For RNG to renewable CNG/LNG, these reports would denote 
which facilities/dispensers converted RNG to renewable CNG/LNG and 
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 would 
also serve as the basis for attest auditors and EPA to verify RNG RIN 
separation activities. We are also proposing to utilize these periodic 
reports to update the dispensing locations associated with the RNG RIN 
separator, and we are proposing to require that RNG RIN separators 
update their CNG/LNG dispensers quarterly. This would eliminate the 
need for such information to be included in RIN generators' 
registration information, as required by existing regulations. We seek 
comment on the proposed quarterly reporting requirements and whether 
any additional reports are needed to help ensure that RNG is converted 
to renewable CNG/LNG or used as transportation fuel.
    Under this proposal, RNG RIN separators would also be required to 
submit additional information related to the separation transaction in 
EMTS. Under the current regulations, we have established a series of 
codes to identify the reason that a RIN is separated, consistent with 
the regulatory requirements that allow for RIN separation.\363\ To 
implement the proposed requirements for eRINs and biogas regulatory 
reform, we would require 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, for use to generate renewable electricity, or for 
use as a biointermediate. These proposed changes to EMTS would help 
track the use of RNG under the RFS program, which we believe will 
improve program oversight. We seek comment on whether any additional 
functionality in EMTS would be needed to ensure that RNG RINs are 
properly separated.
---------------------------------------------------------------------------

    \363\ See 40 CFR 80.1429.
---------------------------------------------------------------------------

    We are also proposing that RNG RIN separators would have to 
maintain records related to their RNG RIN separation activities. For 
RNG to renewable CNG/LNG, this would include 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 are currently maintained by the RIN generator and 
under this proposal would instead be maintained by the RNG RIN 
generator. We believe such 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. We seek comment on 
whether there are any additional recordkeeping requirements necessary 
for RNG RIN separators.
    We are proposing specific annual attest engagement procedures to 
verify RNG RIN separation, and we note that these proposed annual 
attest engagement procedures would be in addition to those currently 
required for RINs separated under 40 CFR 80.1464. Specifically, we are 
proposing that an independent attest auditor 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 would be required to be flagged in the 
annual attest engagement report. These proposed annual attest 
engagement provisions are necessary to ensure that RNG RINs would only 
be separated when consistent with applicable regulations. We note that 
the annual attest engagement procedures for EPA's fuels program would 
also apply to RNG RIN separators.\364\ For example, an RNG RIN 
separator would have to identify in their registration information 
their independent attest auditor, and the independent attest auditor 
would electronically submit the annual attest engagement report 
directly to EPA using forms and procedures prescribed by EPA.
---------------------------------------------------------------------------

    \364\ See 40 CFR 80.1464 and 1090.1800.
---------------------------------------------------------------------------

6. RFS QAP Under Biogas Regulatory Reform
    Similar to the proposed eRINs program, we are not proposing to 
require that biogas producers and RNG producers participate in the RFS 
QAP. As we noted in Sections VIII.N and IX.I.4, we believe our proposed 
biogas regulatory reforms would address the issues of double counting 
of RNG use (e.g., a party claims an amount of RNG as renewable CNG/LNG 
and as renewable electricity), such that a requirement that biogas 
producers and RNG producers participate in the RFS QAP is not 
necessary. We note, however, that should we not finalize the proposed 
biogas regulatory reform provisions, we intend to require that all 
participants in both the eRINs and RNG disposition/generation chain 
participate in the RFS QAP program to help avoid the generation of 
fraudulent and invalid RINs, including ensuring that RNG is not double 
counted.
    While we are not proposing to require RFS QAP participation, under 
this proposal, in order to generate a Q-RIN for RNG, both the biogas 
producer and the RNG producer would be required to be audited by the 
same independent third-party auditor. We believe that the existing RFS 
QAP regulatory requirements sufficiently cover the production of biogas 
and RNG because almost all RINs generated for biogas and RNG under the 
current program are verified by an independent third-party auditor; 
therefore, we are not proposing any changes to the RFS QAP provisions 
for biogas and RNG producers. However, we note that, under our 
proposal, the parties that transact the assigned RNG RIN and the RNG 
RIN separator would not need to be included as part of the RFS QAP. 
This approach

[[Page 80699]]

is consistent with the current regulatory treatment of RINs generated 
for ethanol and biodiesel, and we are not proposing to modify how the 
RFS QAP considers RIN separations in this action. We note that, as 
described in Section IX.I.5.d, we are requiring that RNG RIN separators 
undergo annual attest engagements, which we believe should provide 
sufficient third-party oversight.
7. RNG Used as Renewable Electricity or a Biointermediate
    We are proposing provisions to address situations in which RNG is 
used to make renewable electricity or RNG is used as a biointermediate. 
Specifically, we are proposing that renewable electricity generators 
and renewable fuel producers would be required to retire the RINs 
assigned to a given volume of RNG prior to using that volume to either 
generate renewable electricity or produce renewable fuel. For renewable 
electricity, as described in Section VIII.F.5, the renewable 
electricity generator could then generate renewable electricity covered 
by a RIN generation agreement and transfer the data for the renewable 
electricity generated under the RIN generation agreement to the light-
duty OEM, which could then generate eRINs for the amount of renewable 
electricity used by its fleet. In cases where RNG is used as a 
biointermediate to produce a different renewable fuel, the applicable 
RIN generation procedures would vary depending on what fuel is made 
from the RNG.
    We believe our proposed approach would allow for multiple uses of 
RNG without imposing strict limits on the number of parties that 
produce or distribute RNG. By assigning RINs to the RNG injected into 
the commercial pipeline and using EMTS to track the transfer of the 
assigned RINs between parties that produced the RNG and use the RNG, we 
believe we can provide flexibility in the use of RNG while maintaining 
adequate oversight. We believe requiring retirement of the RNG RIN 
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 retired.
    We seek comment on the proposed approach to require the retirement 
of assigned RINs when a party uses RNG to make renewable electricity or 
uses RNG as a biointermediate.
8. RNG Imports and Exports
    For imported RNG, we are proposing to maintain the existing 
regulatory structure whereby either the importer of the RNG or the 
foreign RNG producer may generate the RINs. Under the RFS program, 
either the foreign renewable fuel producer may generate RINs (provided 
certain additional requirements are met) or the importer of the 
renewable fuel may generate RINs. Under the existing program, 
approximately 10 percent of all D3 RINs are generated from imported 
Canadian biogas and, to date, RINs for foreign biogas have only been 
generated by an importer. Under this proposal, we would maintain the 
flexibility that either the foreign renewable fuel producer (in this 
case, the foreign RNG producer) may generate the RIN or an importer may 
generate the RIN. The sole difference between the proposal and the 
existing regulations would be that instead of any foreign party in the 
biogas production and distribution chain, only a foreign RNG producer 
may be a RIN-generating foreign producer consistent with the approach 
outlined for domestic biogas production described above. In the case 
where a foreign RNG producer generates a RIN, the foreign RNG producer 
would be required to satisfy the additional regulatory requirements for 
RIN-generating foreign producers at 40 CFR 80.1466 (i.e., submit to 
U.S. jurisdiction, comply with inspection requirements, and post a 
bond).
    Based on existing registrations for foreign biogas, we do not 
believe that any changes to existing registrants would be necessary 
because RNG importers have already served as the RIN generator in all 
current registrations for Canadian RNG. We seek comment on our proposed 
approach to dealing with imported biogas used to make biogas-derived 
renewable fuel. We also note that we describe in more detail how 
foreign RNG and foreign renewable electricity would be treated under 
the proposed eRINs program in Section VIII.P.
    For exported biogas, RNG, and renewable CNG and renewable LNG, we 
are not proposing to treat those exports any differently than other 
exported renewable fuels under the current regulations. 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 
proposal, since a RIN would be generated for RNG at the point of 
injection into a commercial pipeline system, any party that exports the 
RNG outside of the covered location would incur an exporter RVO under 
40 CFR 80.1430 and would be required to satisfy that RVO by retiring 
the appropriate number and type(s) of RINs. We seek comment on this 
proposed approach to handling exports of RNG and whether any additional 
regulatory provisions for RNG exports are necessary.
9. Implementation Date
    We recognize that the proposed biogas regulatory reforms would 
necessitate a transition period for parties that are already generating 
RINs for biogas under the existing provisions. To allow for this 
transition, we are proposing an implementation date of January 1, 2024, 
for the biogas regulatory reforms. Beginning on January 1, 2024, all 
RNG introduced into the commercial pipeline system would be subject to 
the RIN generation, assignment, and separation provisions as discussed 
in Section XI.I.4. Until that time, RINs for the biogas to renewable 
CNG/LNG pathway must be generated using the existing regulatory 
provisions. Since most affected parties are currently registered with 
EPA (e.g., the biogas production facilities and parties that transact 
RNG RINs), we believe this is a sufficient amount of time for parties 
to update their registrations to meet the new regulatory requirements. 
We seek comment on whether additional time is necessary for this 
transition.
    We also recognize that there may be a significant volume of stored 
RNG that parties are intending to use as renewable CNG/LNG under the 
existing regulations, and that parties may not be able to use all of 
that volume prior to January 1, 2024. Therefore, we are proposing to 
allow parties to use all stored biogas in accordance with existing 
regulations to generate RINs prior to January 1, 2025. We believe this 
would provide enough time for parties with stored biogas to utilize 
their existing inventories and to begin complying with the new 
regulations. We seek comment on whether the January 1, 2025 deadline 
provides sufficient time for parties to use stored RNG produced under 
the existing regulations.
10. Biogas/RNG Storage Prior to Registration
    We are proposing to address situations in which biogas or RNG is 
produced and stored prior to EPA's acceptance of a biogas or RNG 
producer's registration submission. Specifically, we are proposing that 
biogas or RNG may be stored on site (i.e., at a storage facility co-
located at the biogas or RNG production facility \365\)

[[Page 80700]]

prior to EPA's acceptance of a registration submission, provided that 
certain conditions are met, as discussed below. In order to ensure 
equal treatment of all parties, we are also proposing that these 
storage provisions would also apply to all other biointermediates and 
renewable fuels.
---------------------------------------------------------------------------

    \365\ ``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).''
---------------------------------------------------------------------------

    Under the RFS1 program, we issued guidance \366\ stating that 
parties may assign RINs for renewable fuels that had left the renewable 
fuel production facility because the RFS1 regulations required that 
RINs be assigned to renewable fuels at the point of production and did 
not specifically define what ``point of production'' meant. This was 
acceptable for the RFS1 program 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 definition 
of renewable fuel under the RFS1 program).
---------------------------------------------------------------------------

    \366\ 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, we have not allowed 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 (i.e., the 
renewable fuel has left the renewable fuel production facility). The 
reason we have not allowed this is because EPA may determine that the 
fuel was not produced consistently with EPA's regulatory requirements 
and therefore, not be eligible for RIN generation. However, we have 
allowed parties to generate RINs for biogas and RNG that was produced 
prior to EPA acceptance of the RIN generator's registration 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 have allowed biogas/RNG to 
be stored prior to registration in large part due to the length of time 
it has taken EPA to review and accept registrations for biogas to 
renewable CNG/LNG as a result of the existing registration 
requirements.
    As explained in Section IX.I.4, under this proposal we would no 
longer require that biogas and RNG producers demonstrate that there are 
contracts between each party in the biogas/RNG production, 
distribution, and use chains in order to demonstrate transportation 
use. Therefore, we believe it is no longer necessary 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.
    We would, however, continue to allow for the storage onsite of 
biogas/RNG, as well as all renewable fuels and biointermediates, 
produced prior to EPA acceptance of a registration submission if 
certain conditions are met. Specifically, we would allow for storage 
onsite if 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; and
     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 storage 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; so long as the producer does not modify their facility, 
the biogas and RNG produced at these facilities should be able to be 
utilized to generate RINs. These products would have to be produced in 
accordance with the applicable regulatory requirements. We are 
proposing that the biogas or RNG producer must maintain custody of the 
product because once the product has left their custody, the potential 
ability of the producer to remedy issues with the product is greatly 
diminished; this could also result in other parties downstream becoming 
liable for the product not meeting applicable regulatory requirements. 
After EPA has accepted the biogas or RNG producer's registration, the 
stored products could then be used to produce renewable fuel or for the 
generation of RINs, as applicable.
    For renewable electricity, we are proposing that renewable 
electricity placed on the commercial electric grid serving the 
contiguous U.S. prior to EPA's acceptance of a renewable electricity 
generator's registration does not meet these requirements and may not 
be stored for purposes of RIN generation because we are not aware of a 
case where the renewable electricity generator could store the 
renewable electricity on site. We seek comment on all aspects of 
allowing biogas, RNG, biointermediates, and renewable fuels to be 
stored prior to registration.

J. Separated Food Waste Recordkeeping Requirements

    Under the Clean Air Act, qualifying renewable fuel must be produced 
from renewable biomass.\367\ To ensure that RIN-generating renewable 
fuels satisfy this requirement, EPA's 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.'' \368\ In addition to the generally applicable 
requirements, EPA's 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.
---------------------------------------------------------------------------

    \367\ CAA section 211(o)(1)(J).
    \368\ 40 CFR 80.1454(d).
---------------------------------------------------------------------------

    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

[[Page 80701]]

(2) a separated food waste plan.\369\ 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 the provision to 
submit the location of every facility from which separated food waste 
is collected as a registration requirement and to simply rely on the 
corresponding recordkeeping requirement; \370\ at that time, we noted 
that renewable fuel producers are also required to retain this 
information under the recordkeeping requirements under 40 CFR 
80.1454.\371\
---------------------------------------------------------------------------

    \369\ 40 CFR 80.1450(1)(vii)(B).
    \370\ 81 FR 80828, 80902-03 (November, 16, 2016).
    \371\ 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.'').
---------------------------------------------------------------------------

    EPA finalized the proposed removal of the requirement to provide 
the location of every facility from which separated food waste is 
collected as part of the information required for registration in 
2020.\372\ We 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.'' \373\ To 
emphasize that this requirement remains 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(s) from which the separated food waste stream is 
collected.
---------------------------------------------------------------------------

    \372\ 85 FR 7016, 7078 (Feb. 6, 2020).
    \373\ Id. at 7062.
---------------------------------------------------------------------------

    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.'' \374\
---------------------------------------------------------------------------

    \374\ RFS Power Coalition v. U.S. EPA, No. 20-1046 (D.C. Cir.), 
Doc. #1882940 at 38-39, filed Jan. 29, 2021.
---------------------------------------------------------------------------

    Although we emphasize that the requirement for 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 has 
existed at 40 CFR 80.1454(d) since 2010, we are also aware there are 
parties that may have suggestions for how to better apply this 
requirement specifically to separated food waste feedstocks. We are 
therefore requesting comment on the separated food waste-specific 
recordkeeping requirement in 40 CFR 80.1454(j)(1)(ii).\375\ In 
particular, we seek comment on how renewable fuel producers using 
separated food waste as feedstocks can 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 are sufficient to verify that the feedstocks meet the 
definition of renewable biomass.
---------------------------------------------------------------------------

    \375\ We are not requesting comment on or reopening the 
requirement at 40 CFR 80.1454(d).
---------------------------------------------------------------------------

    EPA has also been engaged in conversations with third party 
feedstock suppliers, independent auditors, and renewable fuel producers 
on this topic. Based on these conversations, we are proposing a 
specific, optional approach to satisfying the applicable recordkeeping 
requirement on which we are requesting comment, in addition to the 
general request for comment on approaches above.
    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 supplier. While the current 
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 proposing an option to allow 
independent auditors to verify records held by the feedstock supplier 
by leveraging the biointermediates provisions of the RFS program. While 
most of our conversations to date have addressed this issue in the 
context of used cooking oil collection, we believe this proposed option 
could also be useful for and apply adequately well to third-party 
collectors of separated yard waste, separated food waste, and separated 
municipal solid waste.
    We are proposing an option under which, in lieu of renewable fuel 
producers needing to hold the records demonstrating the locations from 
which the feedstocks were collected, feedstock suppliers could 
voluntarily comply with the parts of the biointermediates provision 
relevant to demonstrating that the feedstock used to produce renewable 
fuel is renewable biomass. If a renewable fuel producer and feedstock 
supplier opt into this alternative requirement, then the following 
requirements would need to be met (as described in the proposed 40 CFR 
80.1479): the feedstock supplier would need to register with the EPA 
and must keep all applicable records of feedstock collection; both the 
renewable fuel producer and feedstock supplier would need to 
participate in the QAP program using the same QAP provider; and product 
transfer documents would need to be supplied for feedstocks after 
leaving the feedstock supplier that include the volume, date, location 
at time of transfer, and transferor and transferee information. The 
feedstock suppliers and the renewable fuel producers that process those 
feedstocks would also be subject to the same liability provisions that 
apply to biointermediate producers and renewable fuel producers that 
process biointermediates.
    Since the feedstock suppliers are not substantially altering the 
feedstock before transferring the feedstock, we believe fewer 
requirements would be necessary than for biointermediates to provide 
sufficient oversight of the feedstock and renewable fuel production 
process. Specifically, we are proposing that the feedstock supplier 
would not need to supply an engineering review, separated food waste 
plans, separated yard waste plans, or separated MSW plans as a part of 
registration. However, the renewable fuel producer will still need to 
supply these documents as part of their registration. Title transfer 
PTDs and transfer limits would also not be required. In addition, the 
feedstock would not be considered a biointermediate, so the feedstock 
supplier could sell feedstock to a biointermediate producer which could 
sell a biointermediate to a renewable fuel facility. In this situation, 
all three

[[Page 80702]]

entities (feedstock supplier, biointermediate production facility and 
renewable fuel production facility) would need to use the same QAP 
provider.
    We have designed this proposed option to be consistent with the 
California Air Resources Board's (CARB) approach for verification of 
similar feedstocks under their low carbon fuel standard (LCFS) program, 
given that many producers participate in both LCFS and RFS. Under 
CARB's LCFS program, multiple parties may serve as ``joint applicants'' 
to demonstrate that LCFS credits were validly created for fuels 
produced from ``specified source feedstocks'' like used cooking oil and 
animal fats.\376\ Under CARB's LCFS program, applying as joint 
applicants allows each entity to maintain control of confidential data 
for the portions of the LCFS pathway they submit.\377\ However, in 
order to ensure that LCFS credits are valid, CARB's LCFS program 
requires that ``(1) [e]ach joint applicant is subject to all 
requirements for pathway application, attestations, validation and 
verification, recordkeeping, pursuant to this subarticle, for the 
portion of the pathway they control[; and] (2) [a] single entity 
designated to submit data on behalf of multiple entities within a 
pathway does not relieve any other entity in the pathway from 
responsibility for ensuring that the data submitted on its behalf is 
accurate.'' \378\ CARB's LCFS requirements then set up a structure 
similar to our proposal whereby the party must either maintain (1) 
``delivery records that show shipments of feedstock type and quantity 
directly from the point of origin to the fuel production facility'' or 
(2) ``information from material balance or energy balance systems that 
control and record the assignment of input characteristics to output 
quantities at relevant points along the feedstock supply chain between 
the point of origin and the fuel production facility.'' \379\ Under the 
second option, joint applicants under CARB's LCFS program must 
collectively maintain records of the type and quantity of feedstock 
obtained from each supplier, including feedstock transaction records, 
feedstock transfer documents, weighbridge tickets, bills of lading or 
other documentation for all incoming and outgoing feedstocks; maintain 
records used for material balance and energy balance calculations; and 
ensure CARB staff and verifier access to audit feedstock suppliers to 
demonstrate proper accounting of attributes and conformance with 
certified CI data.\380\ CARB's LFCS regulations note that different 
entities may assume responsibility for different portions of the chain-
of-custody, but that all entities must meet the chain of custody 
requirements collectively.\381\ The chain-of-custody requirements, 
including the underlying records, are verified annually by an 
independent third party.\382\
---------------------------------------------------------------------------

    \376\ Cal. Code Regs. tit. 17, Sec.  95488.
    \377\ Cal. Code Regs. tit. 17, Sec.  95488(b).
    \378\ Cal. Code Regs. tit. 17, Sec.  95488(b).
    \379\ Cal. Code Regs. tit. 17, Sec.  95488.8(g).
    \380\ Cal. Code Regs. tit. 17, Sec.  95488.8(g)(1)(B)(1) through 
(3).
    \381\ Cal. Code Regs. tit. 17, Sec.  95488.8(g)(1)(B).
    \382\ Cal. Code Regs. tit. 17, Sec. Sec.  95491.1(a)(2) and 
95491.1(c)(2)(I).
---------------------------------------------------------------------------

    As noted above, we have designed our proposed option to be 
consistent with the LCFS approach, taking into consideration the unique 
statutory and regulatory structure of the RFS program. Under our 
proposal, we would essentially allow renewable producers the same 
choice as LCFS credit generators: either the renewable fuel producer 
would have to maintain records from the point of origin (e.g., 
restaurants) demonstrating that the feedstock is renewable biomass, or 
the feedstock suppliers would maintain the records for the feedstock 
from the point of origin and have the QAP auditors verify the chain-of-
custody. We would not require that underlying records be transmitted 
between the feedstock supplier and the renewable fuel producer, but 
rather that the feedstock supplier and the renewable fuel producer 
would collectively have to demonstrate the chain-of-custody for the 
feedstock back to the origin of the renewable biomass. Under our 
proposal, the QAP auditors would verify the chain of custody, which is 
similar to CARB's annual verification process.
    We believe that by allowing renewable fuel producers to opt into 
these limited additional requirements, more renewable fuel can be 
produced under the RFS program. We are requesting comments on this 
proposal and are specifically interested in the perspective of 
renewable fuel producers, independent auditors, and feedstock suppliers 
about how this alternative recordkeeping requirement would fit within 
their current business practices.

K. Definition of Ocean-Going Vessels

    We are proposing to amend the definition of ``fuel used in ocean-
going vessels'' to ensure that obligated parties are including diesel 
fuel in their RVOs in a consistent manner and as required by the CAA. 
Fuel used in ocean-going vessels is explicitly excluded from the CAA's 
definition of ``transportation fuel,'' \383\ and does not need to be 
included in RVO calculations.\384\ Our regulations define 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.'' \385\ The term ``ocean-going 
vessels'' referenced in sub-prong (3), however, is not further defined 
in the regulations.
---------------------------------------------------------------------------

    \383\ CAA section 211(o)(1)(L).
    \384\ 40 CFR 80.1407(f)(8).
    \385\ 40 CFR 80.1401.
---------------------------------------------------------------------------

    In the preamble promulgating the RFS2 regulations, we stated:

    With respect to fuels for use in ocean-going vessels, [the 
Energy Independence and Security Act (EISA)] specifies that 
`transportation fuels' do not include such fuels. We are 
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). Thus, fuel for use in ocean-going 
vessels, or that an obligated party can verify as having been used 
in an ocean-going vessel, will be excluded from the renewable fuel 
standards.\386\
---------------------------------------------------------------------------

    \386\ 75 FR 14670, 14721 (March 26, 2010).

    This statement made clear that vessels powered by C3 marine engines 
are ocean-going vessels and that fuel supplied to those vessels do not 
need to be included in obligated parties' RVO calculations. The 
reference to ``and some Category (C2) marine engines'' is further 
explained in the Response to Comments document accompanying the final 
---------------------------------------------------------------------------
RFS2 regulations, where we stated:

    With respect to the comments that EPA should not allow the term 
``ocean-going vessel'' to include Category 2 engines, we note that 
Category 1 and Category 2 engines/vessels are generally subject to 
the NRLM diesel fuel standards. Since NRLM diesel fuel would not be 
considered part of ``fuels for use in ocean-going vessels'', this 
means that the vast majority of fuel used by Category 1 and Category 
2 engines would be considered part of ``transportation fuels''. 
However, our recent rulemaking to establish new standards for 
Category 3 engines included a provision that would effectively allow 
Category 1 and 2 auxiliary engines installed on Category 3 vessels 
(i.e., those vessels powered by Category 3 engines) to utilize fuels 
other than NRLM. This allowance is to reduce the burden that could 
potentially be caused by requiring that these Category 1 and 2

[[Page 80703]]

auxiliary engines burn 15 ppm diesel fuel--which could result in a 
Category 3 vessel needing to carry three different types of fuel 
onboard. Thus, to the extent that these engines use residual fuel or 
ECA marine fuel, their fuel would also not be considered 
``transportation fuels''.\387\
---------------------------------------------------------------------------

    \387\ U.S. EPA, Renewable Fuel Standards Program (RFS2) Summary 
and Analysis of Comments, at 3-198-3-200. (February 2010).

    In other words, the reference to ``and some Category (C2) marine 
engines'' in the preamble to the final RFS2 rule refers to auxiliary 
engines equipped on vessels that are primarily powered by C3 marine 
engines.
    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 are proposing 
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.'' 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 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. 
Auxiliary engines are often used for purposes other than propulsion. 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 are also proposing to modify 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 and the 
flexibilities to certify diesel fuel for multiple purposes as allowed 
under Fuels Regulatory Streamlining. Specifically, we are proposing to 
remove the restriction that fuel that meets the requirements of MVNRLM 
diesel fuel cannot be ECA marine fuel as this exclusion in the 
definitions conflicts with the designation provisions in 40 CFR part 
1090. We note that we are not proposing to change the treatment of 
certified NTDF under the RFS program in this action.
    Under the current definitions for MVNRLM diesel fuel and ECA marine 
fuel, the definitions exclude 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 must include the designated MVNRLM diesel 
fuel in their RVO calculations even if the fuel is designated and used 
as ECA marine fuel.
    On February 6, 2020, EPA promulgated regulations to allow refiners 
and importers to exclude certified non-transportation 15 ppm distillate 
fuel or certified NTDF from their RVO calculations if certain 
conditions were met. The definition of certified NTDF includes 15 ppm 
fuel that is designated as ECA marine fuel. Since the NTDF regulations 
allow parties to exclude ECA marine fuel that is also certified NTDF 
from their RVO compliance calculations, we are also 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.
    Under EPA's fuel quality regulations in 40 CFR part 1090, we allow 
diesel fuel manufacturers to apply multiple designations to a batch of 
diesel fuel so long as all applicable regulatory requirements are met 
for each designation. A party downstream of the diesel fuel 
manufacturer may then determine how that batch of diesel fuel is 
ultimately used consistent with market demand. For example, a diesel 
fuel manufacturer can designate a diesel fuel batch that meets the ULSD 
standards as ULSD, ECA marine fuel, and heating oil, and then a 
terminal operator may use such fuel for any of those uses so long as 
all applicable regulatory requirements are met.
    Under the certified NTDF provisions, in order for diesel fuel to be 
considered certified NTDF and thus eligible for exclusion from an 
obligated party's RVO, the diesel fuel must have been certified as 
meeting the ULSD standards, designated as certified NTDF, designated 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), and 
not been designated as ULSD or 15 ppm MVNRLM diesel fuel.
    This means that regardless of whether a diesel fuel manufacturer 
designates a batch of fuel for a non-transportation use, if a diesel 
fuel manufacturer designates the batch as ULSD or MVNRLM diesel fuel, 
the batch must be included in their RVOs. Together, these provisions 
provide significant flexibility regarding the designation, 
distribution, and use of distillate fuels that meet the ULSD standards.

L. Bond Requirement for Foreign RIN-Generating Renewable Fuel Producers

    The current bond requirement applicable to foreign RIN-generating 
renewable fuel producers and Foreign RIN owners was developed in the 
RFS 1 rule \388\ 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. 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 in the past twelve months, RINs in all 
categories have consistently sold above $1.00 per RIN.\389\ The 
increased value of RINs makes a bond requirement of $0.01 per RIN 
insufficient to deter potential noncompliance nor is it 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 believe it is necessary to 
raise the bond requirement to more accurately reflect the current value 
of RINs so that bonds can serve their intended purposes. We are 
proposing raising the bond requirement from $0.01 per RIN to $0.30 per 
RIN, and we are seeking comment on whether this increase is significant 
enough for the bond to serve its intended purposes.
---------------------------------------------------------------------------

    \388\ 72 FR 24007 (May 1, 2007).
    \389\ See RFS pricing data available at: https://www.epa.gov/fuels-registration-reporting-and-compliance-help/rin-trades-and-price-information.
---------------------------------------------------------------------------

    The existing regulation at 40 CFR 80.1466(h) allows either direct 
payment to the U.S. Treasury in the calculated amount of a bond or the 
posting of a surety bond to fulfill the foreign bond requirement. EPA 
cannot easily process direct payments to the U.S. Treasury made by 
check, nor can EPA easily refund such payments to the payor. Therefore, 
EPA proposes to remove direct payment to the U.S. Treasury as an 
option. We seek comment on how this change affects RIN-generating 
foreign producers and foreign RIN owners and if there are other options 
that would provide adequate security, accountability, and ease of use 
for the EPA, RIN-generating foreign producers, and foreign RIN owners.

[[Page 80704]]

M. Definition of Produced From Renewable Biomass

    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.'' 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). In 
the 2020-2022 RFS Annual Rule, 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 this rule, we are re-
proposing the definition of ``produced from renewable biomass'' that 
was in the 2020-2022 RFS Annual Rule, as well as seeking comment on 
alternative definitions or ways that renewable fuel producers could 
demonstrate that the fuel they produce meets this statutory 
requirement.\390\
---------------------------------------------------------------------------

    \390\ Any comments submitted on this matter in the 2020-2022 RVO 
action must be re-submitted to the docket for this rule to be 
considered. Any comments that are not re-submitted to the docket for 
this action will not be considered.
---------------------------------------------------------------------------

    As described in the 2020-2022 RFS Annual Rule, we believe a 
definition of ``produced from renewable biomass'' is needed 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 would reduce confusion on this 
issue. In particular, we want to 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.
    In comments on the proposed definition of ``produced from renewable 
biomass'' in the 2020-2022 RFS Annual Rule commenters identified two 
primary ways that renewable fuels could meet this statutory 
requirement. Some commenters supported the proposed definition wherein 
the energy in the finished fuel is derived from renewable biomass. 
Other commenters suggested an alternative in which a fuel would be 
deemed to have been produced from renewable biomass if the mass or 
molecules in the fuel were from renewable biomass.
    The CAA does not define the term ``produced from renewable 
biomass,'' and we believe that this phrase allows for multiple 
interpretations, including that renewable fuels must contain energy 
from renewable biomass or that they must contain mass from renewable 
biomass. The case for defining produced from renewable biomass as 
containing energy from renewable biomass is primarily based on the fact 
that the fundamental purpose of transportation fuel is to provide 
motive energy to vehicles and engines. Thus, the source of the energy 
in the finished fuel should be the criterion for determining whether 
that fuel was produced from qualifying renewable biomass. It is also 
consistent with the statutory definition that renewable fuel must ``be 
used to replace or reduce the quantity of fossil fuel present in a 
transportation fuel.'' Fuel that derives its energy from fossil fuel (a 
subset of non-renewable feedstocks) is replacing one form of fossil 
fuel for another, not reducing the quantity of fossil fuel present in a 
transportation fuel.
    Conversely, the case for defining produced from renewable biomass 
as containing mass from renewable biomass is based on the term 
``produced'' and the fact that fuels must also reduce lifecycle GHG 
emission to qualify as a renewable fuel under the RFS program. As 
provided in comments on EPA's proposed definition in the 2020-2022 RFS 
Annual Rule, the definition of ``produced'' is to ``make or manufacture 
from components or raw materials.'' \391\ According to this definition 
it is the components or raw materials (i.e., the mass that comprise a 
fuel) that determine from what it is produced. Commenters also noted 
that to qualify as a renewable fuel the fuel must reduce lifecycle GHG 
emissions by at least 20 percent. These parties claim that the 
lifecycle GHG emission requirement effectively addresses the sources of 
energy used to produce renewable fuels and prevents the qualification 
of fuels that rely on excessive amounts of non-renewable energy sources 
that would increase GHG emissions in the transportation sector.
---------------------------------------------------------------------------

    \391\ See definition of ``produce.'' Oxford Languages 
Dictionary. https://languages.oup.com/google-dictionary-en.
---------------------------------------------------------------------------

    To inform our consideration of these two potential definitions of 
produced from renewable biomass, we also considered how various fuels 
would be impacted by applying one or the other. The vast majority of 
renewable fuel pathways that are currently approved under the RFS 
program would continue to qualify as renewable fuels under either 
definition of produced from renewable biomass. The majority of these 
fuels, such as ethanol, biodiesel, CNG/LNG, etc. contain little or no 
energy or mass from non-renewable biomass. Further, for fuels such as 
denatured ethanol or biodiesel that do contain energy or mass from non-
renewable biomass we have generally accounted for the non-renewable 
portion of the fuel in the number of RINs generated per gallon of fuel 
produced.\392\ However, the application of the ``produced from 
renewable biomass'' requirement is less clear for some newer fuel 
technologies that are being developed by stakeholders.
---------------------------------------------------------------------------

    \392\ The renewable content of a renewable fuel is also 
addressed in the calculation of its Equivalence Value under 40 CFR 
80.1415. In the specific case of ethanol, the denaturant that is 
added to ethanol is considered to be renewable despite the fact that 
it is not produced from renewable biomass in order to maintain 
consistency with the program's original expectations. This issue is 
discussed in the 2007 rulemaking which established the RFS program. 
72 FR 23920 (May 1, 2007). Similarly, we have accounted for the 
methanol used to produce biodiesel (which is generally produced from 
non-renewable natural gas) in the equivalence value for biodiesel.
---------------------------------------------------------------------------

    For some emerging renewable fuel production technologies, these two 
different definitions of produced from renewable biomass produce very 
different results. Two examples that illustrate the importance of this 
definition are hydrogen produced from biogas and e-fuels (fuels made 
from CO2, water, and electricity). For a fuel production 
process where hydrogen is produced from biogas from a qualifying source 
(e.g., from a landfill or agricultural digester) and biogas is used as 
both the feedstock and energy source to produce hydrogen in a steam 
methane reformer (SMR), all of the energy in the hydrogen comes from 
renewable biomass. Conversely, because half of the mass of hydrogen 
produced through the SMR process are from water, which does not meet 
the statutory definition of renewable biomass, only half of the mass is 
from renewable biomass.
    The implications for e-fuels are even more significant, as the 
definition of produced from renewable biomass would determine not how 
many RINs could be generated, but whether the fuels qualified as 
renewable fuel at all. For e-fuels produced using CO2 from 
qualifying renewable biomass, such as that produced when fermenting 
corn starch to ethanol, and wind or solar electricity providing the 
energy, none of the energy in the finished fuel is from renewable 
biomass despite the fact that most of the mass in the fuel is from 
renewable biomass. Theoretically, e-

[[Page 80705]]

fuels produced using CO2 from qualifying biomass and 
electricity generated using natural gas or coal could also qualify as a 
renewable fuel if the definition of produced form renewable biomass 
required that the mass of the fuel come from renewable biomass, but it 
is very unlikely that such fuels would meet the GHG reduction threshold 
to qualify as renewable fuel. For e-fuels produced using CO2 
from sources other than renewable biomass, such as CO2 
captured from the air or a coal power plant, and electricity generated 
using qualifying biogas, all of the energy in the fuel is from 
renewable biomass but none of the mass of the fuel is from renewable 
biomass.
    As the examples listed here demonstrate, under either 
interpretation of what it means for a fuel to be produced from 
renewable biomass there are situations where a fuel would only be 
partially produced from renewable biomass. These are cases where some 
of the energy or the mass in the finished fuel is from renewable 
biomass and the remainder is not. In comments on the 2020-2022 RFS 
Annual Rule NPRM several parties raised concerns that our proposed 
definition of produced from renewable biomass would disqualify fuels 
from being considered renewable fuel, and thus eligible to generate 
RINs, if even a portion of the fuel was not produced from renewable 
biomass. These commenters often noted that such a strict interpretation 
would disqualify fuels such as biodiesel and renewable diesel that 
contain some non-renewable content. This was not the intent of the 
definition of produced from renewable biomass that we proposed in that 
action, nor our intent in this re-proposal. While we do not believe 
that fuel producers should be able to generate RINs for the portion of 
the finished fuel that is not derived from renewable biomass, we are 
not proposing to completely disqualify fuels that contain any portion 
of non-renewable biomass. Rather, such fuels are subject to equations 
in the regulations for the RFS program that determine the portion of 
the fuel that is produced from renewable biomass and can only generate 
RINs for this portion of the fuel. We note that as part of this 
proposal to define ``produced from renewable biomass'' we are also 
proposing new regulations for determining the renewable content of 
fuels that are produced from both renewable biomass and feedstocks that 
are not renewable biomass, fuels that contain process energy that is 
not derived from renewable biomass, and fuels that are produced through 
multiple pathways with different D codes. These new regulations are 
discussed in greater detail at the end of this section.
    Further examples of how different fuel types would qualify under 
the two potential definitions, including fuels that are produced from 
both renewable and non-renewable biomass, are shown in Table IX.M-1. In 
this table the term feedstock is used to refer to the source or sources 
of the mass in the finished fuel. The energy in the finished fuel could 
come exclusively from the feedstock (if the process of converting the 
feedstock is exothermic) or could come from both the feedstock and the 
process energy (if the process of converting the feedstock is 
endothermic). Ethanol and biodiesel are examples of fuels where all of 
the energy in the fuel comes from the feedstock. In these cases, the 
source of the process energy has no impact on whether a fuel is 
produced from renewable biomass, but the source of the process energy 
does impact the lifecycle GHG emissions of the fuel. Hydrogen produced 
through an SMR process is an example where some of the energy in the 
fuel comes from the process energy. In situations where some of the 
energy in the fuel comes from the process energy whether the process 
energy is renewable biomass or not impacts the degree to which the 
finished fuel is produced from renewable biomass if we define produced 
from renewable biomass based on the energy in the finished fuel. For 
example, because a portion of the energy in hydrogen produced using an 
SMR process comes from the process energy, hydrogen produced using this 
process would generate a greater number of RINs if the process energy 
is from qualifying biogas (renewable biomass) than if the process 
energy is from natural gas (not renewable biomass). We note that the 
fuels and values in this table are only illustrative and do not 
represent determinations as to the eligibility of a fuel or the 
percentage of a fuel that would be produced from renewable biomass 
under these respective definitions.

 Table IX.M-1--Renewable Content of Various Fuels Under Different Definitions of Produced From Renewable Biomass
                                             [Illustrative examples]
----------------------------------------------------------------------------------------------------------------
                                                                                   Definition of ``produced from
                                                                                        renewable biomass''
                                                                                 -------------------------------
               Fuel                       Feedstock            Process energy       Energy from      Mass from
                                                                                     renewable       renewable
                                                                                    biomass (%)     biomass (%)
----------------------------------------------------------------------------------------------------------------
Ethanol...........................  Corn Starch..........  Natural Gas..........             100             100
Biodiesel.........................  Soybean Oil and        Natural Gas..........              95              95
                                     Methanol.
CNG/LNG...........................  Biogas...............  Grid Electricity.....             100             100
Hydrogen (SMR)....................  Biogas and Water.....  Biogas...............             100              50
Hydrogen (SMR)....................  Biogas and Water.....  Natural Gas..........              65              50
Hydrogen (Electrolysis)...........  Water................  Biogas Electricity...             100               0
Hydrogen (Electrolysis)...........  Water................  Wind/Solar                          0               0
                                                            Electricity.
Electricity.......................  Biogas...............  Biogas...............             100             N/A
eFuel.............................  Renewable Biomass CO2  Wind/Solar                          0              90
                                                            Electricity.
eFuel.............................  Renewable Biomass CO2  Coal/Natural Gas                    0              90
                                                            Electricity.
eFuel.............................  Non-Renewable Biomass  Biogas Electricity...             100               0
                                     CO2 (Air Capture or
                                     Fossil CO2).
----------------------------------------------------------------------------------------------------------------

    In this rule, we are proposing to add a definition of ``produced 
from renewable biomass'' to the regulations at 40 CFR 80.2. We propose 
that produced from renewable biomass means that the energy in the 
finished fuel or

[[Page 80706]]

biointermediate must come from renewable biomass.\393\ We recognize 
that this is not the only potentially reasonable definition of produced 
from renewable biomass, and that the choice of this definition could 
have a significant impact on the development of some fuel production 
technologies with the potential to significantly reduce GHG emissions 
from the transportation sector. We are therefore requesting comment on 
an alternative definition: that produced from renewable biomass would 
mean that the mass of the finished fuel or biointermediate must come 
from renewable biomass. We note that one potential challenge with this 
definition is that electricity, for which we are proposing regulations 
to enable the generation of RINs when the electricity is generated from 
qualifying biogas or renewable natural gas and used as transportation 
fuel, contains no mass from the biogas or renewable natural gas. We 
therefore seek comment on how electricity, which EPA determined in 2010 
could meet the statutory definition of renewable fuel, would be treated 
in the RFS program if this alternative definition were finalized.\394\
---------------------------------------------------------------------------

    \393\ Because biointermediates, like renewable fuels, must be 
produced from renewable biomass to qualify in the RFS program we are 
proposing that the definition of produced from renewable biomass 
apply to both finished fuels and biointermediates.
    \394\ See Section VIII.A.1 for a further discussion of this 
topic.
---------------------------------------------------------------------------

    In response to the proposed definition of produced from renewable 
biomass in the 2020-2022 RFS Annual Rule we also received comments 
saying that EPA should interpret this phrase as broadly as possible. 
Parties making these comments generally argued that EPA should seek to 
leverage the incentives provided by the RFS program to reduce GHG 
emissions to the greatest extent possible, and that a broad definition 
of produced from renewable biomass would best achieve this aim. Several 
of these parties also stated that given the existence of multiple 
potentially reasonable interpretations of this phrase EPA should allow 
any fuel that can demonstrate that it is produced from renewable 
biomass under any reasonable interpretation to be eligible to generate 
RINs under the RFS program. We are therefore requesting comment on an 
approach that would allow fuels to qualify as renewable fuel under the 
RFS program if producers can demonstrate that either the molecules 
contained in the fuel or the energy in the fuel was sourced from 
renewable biomass.\395\
---------------------------------------------------------------------------

    \395\ The fuel would also have to meet the other requirements 
for qualifying as a renewable fuel, including being used to replace 
or reduce the quantity of fossil fuel present in a transportation 
fuel and meeting the GHG reduction requirements.
---------------------------------------------------------------------------

    We are also including an alternative set of draft regulations in a 
technical memorandum \396\ that would be consistent with defining 
produced from renewable biomass such that the mass in the finished fuel 
or biointermediate must come from renewable biomass. We would intend to 
adopt these alternative proposed regulations if we finalized this 
alternative definition of produced from renewable biomass. Were we to 
finalize a definition of produced from renewable biomass allowing fuels 
to qualify under the RFS program if the producer could demonstrate that 
either the mass or the energy in the fuel are sourced from renewable 
biomass, we anticipate that we would finalize regulations consistent 
with the proposed regulatory changes, but we would also include the 
unique elements from the alternative regulations.
---------------------------------------------------------------------------

    \396\ Draft Regulations for the Alternative Definition of 
Produced from Renewable Biomass. Memorandum from EPA to Docket EPA-
HQ-OAR-2021-0427.
---------------------------------------------------------------------------

    Consistent with the proposed definition of produced from renewable 
biomass (that the energy in the finished fuel or biointermediate must 
come from renewable biomass), we are proposing modifications to the 
existing regulatory previsions in 40 CFR 80.1426(f)(3) for determining 
the number of RINs that can be generated for fuels produced from 
multiple pathways with different D codes. These proposed changes would 
ensure that the RINs of different D codes are generated proportional to 
the energy in the fuel that came from the corresponding pathways.\397\ 
For example, if a renewable fuel producer simultaneously converted 
waste sugary beverages (i.e., separated food waste qualifying for D5 
RINs) with corn starch (i.e., feedstock qualifying for D6 RINs) to 
produce ethanol via fermentation, these proposed changes would base RIN 
generation by pathway on the relative proportion of energy in the final 
fuel attributed to the feedstocks by D code. If 10 percent of the 
energy in the ethanol came from separated food waste, then 10 percent 
of the RINs would be generated under the D5 pathway.
---------------------------------------------------------------------------

    \397\ We believe this change addresses a comment on 2020-2022 
RFS rule that suggested that the current RIN apportionment equations 
biased higher energy density feedstocks. See Docket Item No. EPA-HQ-
OAR-2021-0324-0434.
---------------------------------------------------------------------------

    We are also proposing changes to regulatory provisions related to 
co-processed fuels to ensure that they would be consistent with the 
proposed definition of produced from renewable biomass. The existing 
regulations contain the following definition in 40 CFR 80.1401:

    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.

    This definition states that the feedstocks used to produce a fuel 
determine whether the fuel is co-processed or not, which in turn 
determines whether the fuel producers must generate fewer RINs than 
they otherwise would if the fuel had not been produced from co-
processing to account for the feedstock that does not qualify as 
renewable biomass. As with the definition of produced from renewable 
biomass, this definition for co-processed may be reasonable for many of 
the existing pathways, where nearly all of the energy and molecules in 
the fuel come from the feedstocks. However, with the narrow focus on 
the feedstocks used to produce a fuel this definition of co-processed 
does not reflect the fact that for other potential pathways such as 
hydrogen and e-fuels a portion of the energy in the fuel comes from the 
process energy. Thus, to be consistent with our proposed definition of 
produced from renewable biomass, we are also proposing to change the 
definition of co-processed to a definition of co-processed fuel or co-
processed intermediate to mean a fuel or intermediate that contains 
energy from both renewable biomass and non-renewable biomass.
    We are also proposing new regulatory provisions and modifications 
to the existing regulatory provisions in 80.1426(f)(4) for determining 
the number of RINs that can be generated for fuels that are co-
processed that would be consistent with the proposed revision to the 
definition of co-processed. These proposed changes would provide 
greater clarity on the required methods for determining the number of 
RINs that can be generated for co-processed fuels. The proposed changes 
also add a new formula for cases where a portion of the energy in the 
fuel comes from the process energy, rather than from the feedstocks. We 
are also proposing to update the registration requirements in 
80.1450(b)(1)(xviii) and recordkeeping requirements in 
80.1454(b)(3)(ix) to ensure that the equations used for determining the 
number of RINs are used appropriately and that sufficient records exist 
for oversight and enforcement.
    We note that under this proposal, we believe that most producers 
would be largely unaffected because they either

[[Page 80707]]

do not co-process renewable biomass with non-renewable biomass 
feedstocks or have already been registered for co-processing and would 
continue to use their currently registered method of determining the 
number of RINs to be generated from a co-processed fuel. However, under 
this proposal, we believe that renewable diesel produced via 
hydrotreating would be affected because some of the energy in the fuel 
comes from hydrogen, which in many cases is produced from natural gas. 
Under the proposed approach, they would generate RINs based on the 
portion of the energy in the renewable diesel that is from renewable 
biomass.
    Recognizing that this would be a change from current RIN generation 
procedures, we seek comment on potential ways to address this 
situation. One option is to maintain the proposal (which would result 
in renewable diesel producers using hydrogen produced from natural gas 
generating slightly fewer RINs than under the current regulations) and, 
in a future action, allow for parties to replace the hydrogen with 
renewable hydrogen (i.e., hydrogen produced from biogas that is 
produced from renewable biomass) for RIN generation. Some parties have 
discussed the possibility of using renewable hydrogen as a substitute 
for the fossil-derived hydrogen for the generation of advanced or 
cellulosic RINs based on the energy in the renewable diesel produced 
from the renewable hydrogen. We believe that the existing regulations 
do not currently accommodate the generation of such RINs in part 
because the RIN generation procedure for renewable diesel is to assume 
that 100 percent of the renewable diesel came from the non-hydrogen 
feedstocks.\398\ This proposal would allow parties that wished to 
replace fossil-derived with renewable hydrogen the opportunity to 
generate additional RINs proportional to the amount of energy in the 
renewable diesel that came from renewable hydrogen.
---------------------------------------------------------------------------

    \398\ See 40 CFR 80.1426(f)(2).
---------------------------------------------------------------------------

    Another option would be to adjust the equivalence value for RIN 
generation for renewable diesel to account for the fact that a portion 
of the energy in the fuel was not produced from renewable biomass. We 
could do this in two ways. First, we could increase the minimum level 
of energy per gallon needed to qualify for the existing equivalence 
value for renewable diesel (1.7) to account for the non-renewable 
portion of the co-processed fuel. Under this option, the minimum amount 
of energy per gallon needed to qualify for the 1.7 RINs per gallon 
equivalence value would need to be increased from 123,500 Btu/gallon to 
account for the non-renewable portion of the co-processed renewable 
diesel. Alternatively, we could lower the equivalence value itself from 
1.7 RINs per gallon to 1.6 RINs per gallon to accommodate the non-
renewable portion of the co-processed fuel, and adjust the minimum 
quantity of BTUs per gallon necessary to qualify for this equivalence 
value accordingly. The second option is similar to the approach we took 
with biodiesel to deal with the fact that some of the energy in 
biodiesel is a result of non-renewable methanol to produce the 
biodiesel.\399\
---------------------------------------------------------------------------

    \399\ See ``Calculation of Equivalence Values for renewable 
fuels under the RFS program'' Docket Item No. EPA-HQ-OAR-2005-0161-
0046.
---------------------------------------------------------------------------

    We request comment on these proposed regulatory changes, as well as 
the draft regulations for the alternative proposed definition of 
produced from renewable biomass.

N. Limiting RIN Separation Amounts

    We are proposing to limit the assignment to and separation of RINs 
for a gallon of renewable fuel (including RNG) to the equivalence value 
of the renewable fuel. Under the current RFS regulations, parties are 
allowed to assign and separate RINs to a volume of renewable fuel up to 
2.5 RINs per gallon.\400\
---------------------------------------------------------------------------

    \400\ See 40 CFR 80.1426(b).
---------------------------------------------------------------------------

    This proposed change is necessary for the proposed biogas 
regulatory reform provisions to ensure that only the RINs generated for 
and assigned to the specific volume of RNG injected into the natural 
gas commercial pipeline system are separated after the RNG has been 
used as transportation fuel. Without this proposed change, it would be 
possible for parties to assign additional RINs to the volume of RNG, 
which may be inadvertently or improperly separated by downstream 
parties. This issue arises from how RINs are transacted in EMTS. By 
default, EMTS separates RINs in a RIN-owner's account on a first in, 
first out basis; i.e., when a party separates RINs, it separates the 
first RINs received in their account, not necessarily the RINs that 
were generated from the specific volume of renewable fuel. Each party 
that transacted the inadvertently separated RIN would have a potential 
violation which would be unnecessarily burdensome on industry. We did 
not foresee this occurrence when we originally promulgated the 
regulations and set up EMTS, but now recognize it as an issue. An 
alternative to limiting RIN assignment and separation to the 
equivalence value of the fuel would be to redesign EMTS which would 
take significant resources and time and likely disrupt current RIN 
transaction processes by industry. Such an effort would also likely 
delay the implementation date of the biogas regulatory reform 
provisions and consequently the eRINs proposal.
    We also believe this change could help bring transparency to RIN 
assignment and separation practices for other renewable fuels. We are 
aware of practices where renewable fuel producers, in coordination with 
an obligated party, use the separation provisions of 40 CFR 
80.1429(b)(2) to separate RINs assigned to volumes of renewable fuel so 
that a renewable fuel producer can obtain both the separated RINs and 
RIN-less renewable fuels and then later assign RINs from other 
producers to the fuel or sell the fuel without RINs. This process, 
sometimes called ``RIN-flashing,'' can lead to parties that transact 
RINs or fuel to be less aware of who made the fuel or generated the 
RINs. One of the regulatory mechanisms that parties use to move these 
separated RINs is the ability to assign more RINs to a volume of 
renewable fuel than were able to be generated for the fuel using the 
equivalence value. Again, we did not foresee parties using the 
regulations in this manner when we promulgated them and the process of 
``RIN-flashing,'' which undermines the ability of parties to ascertain 
the origin and validity of fuels and RINs, is contrary to our intent. 
By setting the separation limit to the equivalence value, parties would 
not be able to move excess separated RINs with a volume of renewable 
fuel and would be disincentivized from engaging in so-called RIN-
flashing.
    Imposing the proposed limitation of RIN assignment and separation 
to be based on the equivalence value of the renewable fuel would also 
help EPA implement the RFS program because we could establish a single 
set of rules that apply to all RINs instead of having separate sets of 
rules that apply to RNG RINs and to non-RNG RINs. This would also 
facilitate EPA to implement the proposed eRINs program and biogas 
regulatory reform provisions in the proposed timeframes.
    We understand that this change would likely require parties that 
currently transact RINs to make adjustments to their RIN assignment and 
separation practices. As such, we are proposing that this change would 
go into effect on January 1, 2024. We seek comment on our proposal to 
limit separations to the equivalence value of the renewable fuel.

[[Page 80708]]

O. Technical Amendments

    We are proposing to make 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 IX.O-1.

 Table IX.O-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, 80.24, and         Removing all references to ``the
 80.1415 through 80.1478.       Administrator'' and replacing them with
                                ``EPA''.
80.1401, 80.1408, and          Amending the definition of certified non-
 1090.1015.                     transportation distillate fuel (NTDF) at
                                40 CFR 80.1401 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.
80.1401 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.
------------------------------------------------------------------------

X. 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

    This action is an economically significant regulatory action that 
was submitted to the Office of Management and Budget (OMB) for review. 
Any changes made in response to OMB recommendations have been 
documented in the docket. EPA prepared an analysis of potential costs 
and benefits associated with this action. This analysis is presented in 
the DRIA, available in the docket for this action.

B. Paperwork Reduction Act (PRA)

    The information collection activities in this proposed rule have 
been submitted for approval to the Office of Management and Budget 
(OMB) under the PRA. The Information Collection Request (ICR) document 
that EPA prepared has been assigned EPA ICR number 2722.01. You can 
find a copy of the ICR in the docket for this rule, and it is briefly 
summarized here.
    We are proposing compliance provisions necessary to ensure that the 
production, distribution, and use of biogas, renewable electricity, and 
RINs are consistent with Clean Air Act requirements under the RFS 
program. These proposed compliance provisions include registration, 
reporting, product transfer documents (PTDs), and recordkeeping 
requirements. The information requirements are under 40 CFR part 80, 
subpart M, 40 CFR part 1090, and proposed subpart E. Interested parties 
may wish to review the following related ICRs: Fuels Regulatory 
Streamlining (Final Rule), OMB Control Number 2060-0731, expires 
January 31, 2024, and Renewable Fuel Standard (RFS) Program (Renewal), 
OMB Control Number 2060-0725, submitted for renewal on August 31, 2022, 
and pending OMB approval.
    Respondents/affected entities: Biogas producers; renewable energy 
generators; renewable electricity RIN generators (RERGs); renewable 
natural gas (RNG) producers; RNG importers; producers of biogas-derived 
renewable fuel in a closed distribution system; RNG RIN separators; and 
third parties; including third party engineers, attest auditors, QAP 
providers.
    Respondent's obligation to respond: Mandatory, under 40 CFR parts 
80 and 1090.
    Estimated number of respondents: 10,454.
    Frequency of response: On occasion, monthly, quarterly, or 
annually.
    Total estimated burden: 181,794 hours (per year). Burden is defined 
at 5 CFR 1320.3(b).
    Total estimated cost: $22,422,240, all purchased services, and 
which includes $0 annualized capital or operation & maintenance costs.
    An agency may not conduct or sponsor, and a person is not required 
to respond to, a collection of information unless it displays a 
currently valid OMB control number. The OMB control numbers for the 
EPA's regulations in 40 CFR are listed in 40 CFR part 9.
    Submit your comments on the Agency's need for this information, the 
accuracy of the provided burden estimates and any suggested methods for 
minimizing respondent burden to the EPA using the docket identified at 
the beginning of this rule. The EPA will respond to any ICR-related 
comments in the final rule. You may also send your ICR-related comments 
to OMB's Office of Information and Regulatory Affairs using the 
interface at www.reginfo.gov/public/do/PRAMain. Find this particular 
information collection by selecting ``Currently under Review--Open for 
Public Comments'' or by using the search function. OMB must receive 
comments no later than February 28, 2023.

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.
    With respect to eRIN regulatory program discussed in Section VIII, 
participation in the proposed renewable electricity program would be 
purely voluntary. We do not believe that a small biogas producer, 
renewable electricity generator, or light-duty OEM would choose to take 
advantage of the proposed eRIN program unless there is

[[Page 80709]]

sufficient economic incentive for them to do so. No party would be 
compelled to produce or use biogas or renewable electricity, and as 
such, any costs associated with these provisions would also be purely 
voluntary. Also, the proposed eRIN program would create new 
opportunities for small entities that may be able to build smaller 
operations or develop previously uneconomical projects. These entities 
would likely not be able to otherwise participate in the RFS program. 
With respect to the other amendments to the RFS regulations, this 
action proposes to make corrections and modifications to those 
regulations that would make compliance more straightforward. As such, 
we do not anticipate that there would be any significant adverse 
economic impact on directly regulated small entities as a result of the 
proposed provisions.
    The small entities directly regulated by the annual percentage 
standards associated with the RFS volumes are small refiners that 
produce gasoline or diesel fuel, which are defined at 13 CFR 121.201. 
To evaluate the impacts of the volume requirements on small entities, 
we have conducted a screening analysis \401\ 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.\402\ This is true 
whether they acquire RINs by purchasing renewable fuels with attached 
RINs or purchase separated RINs. The costs of the RFS program are thus 
being passed on to consumers in the highly competitive marketplace.
---------------------------------------------------------------------------

    \401\ See DRIA Chapter 10.
    \402\ For a further discussion of the ability of obligated 
parties--including small refiners--to recover the cost of RINs, see 
``April 2022 Denial of Petitions for RFS Small Refinery Exemption,'' 
EPA-420-R-22-005, April 2022 and ``June 2022 Denial of Petitions for 
RFS Small Refinery Exemption,'' EPA-420-R-22-011, June 2022.
---------------------------------------------------------------------------

    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 small entities can take advantage of. 
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 SBREFA panel or through 
comments, but we did not adopt them, in part because we had serious 
concerns regarding our authority to do so.
    In sum, this proposed rule would 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 would contain 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 the proposed rule are discussed in Section IV and in 
the DRIA.
    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, 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 an 
economically significant regulatory action as defined by Executive 
Order 12866, and the EPA believes that the environmental health or 
safety risk addressed by this action may have a disproportionate effect 
on children.
    Children are more susceptible than adults to many air pollutants 
because of differences in physiology, higher per body weight breathing 
rates and consumption, rapid development of the brain and bodily 
systems, and 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.
    Infants and children breathe at much higher rates per body weight 
than adults, with infants under one year of age having a breathing rate 
up to five times that of adults.\403\ In addition, children breathe 
through their mouths more than adults and their nasal passages are less 
effective at removing pollutants, which leads to a higher deposition 
fraction in their lungs.\404\
---------------------------------------------------------------------------

    \403\ U.S. Environmental Protection Agency. (2009). 
Metabolically-derived ventilation rates: A revised approach based 
upon oxygen consumption rates. Washington, DC: Office of Research 
and Development. EPA/600/R-06/129F. http://cfpub.epa.gov/ncea/cfm/recordisplay.cfm?deid=202543.
    \404\ Foos, B.; Marty, M.; Schwartz, J.; Bennet, W.; Moya, J.; 
Jarabek, A.M.; Salmon, A.G. (2008) Focusing on children's inhalation 
dosimetry and health effects for risk assessment: An introduction. J 
Toxicol Environ Health 71A: 149-165.
---------------------------------------------------------------------------

    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.\405\ Exposure at a young age to these carcinogens could lead to 
a higher risk of developing cancer later in life.
---------------------------------------------------------------------------

    \405\ 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. 
In addition, to the extent increased use of renewable diesel resulting 
from this rule reduces end-use emissions, there may be public

[[Page 80710]]

health benefits for children, particularly those who live or go to 
school near roads. Analysis conducted by EPA indicates that millions of 
Americans live within a few hundred yards of a truck route.\406\ 
However, emissions data for vehicles running on renewable diesel fuel 
are too limited at present to draw any conclusions about potential air 
quality impacts.
---------------------------------------------------------------------------

    \406\ U.S. EPA (2022). Estimation of Population Size and 
Demographic Characteristics among People Living Near Truck Routes in 
the Conterminous United States. Memorandum to Docket.EPA-HQ-OAR-
2019-0055.
---------------------------------------------------------------------------

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 proposes 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) & 
Incorporation by Reference

    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 National Standards 
Institute (ANSI), American Petroleum Institute (API), American Public 
Health Association (APHA), and ASTM International (ASTM). A detailed 
discussion of these test methods and standards can be found in Section 
VIII. The standards and test methods may be obtained through the ANSI 
website (www.ansi.org) or by calling ANSI at (212) 642-4980, the API 
website (www.api.org) or by calling API at (202) 682-8000, the APHA 
website (www.standardmethods.org) or by calling APHA at (202) 777-2742, 
and the ASTM website (www.astm.org) or by calling ASTM at (877) 909-
2786. ANSI, API, APHA, and ASTM routinely update many of their 
reference documents. If an updated version of any of reference 
documents included in this proposal is published, we will consider 
referencing that updated version in the final rule. (In addition to the 
standards and test methods listed below, ASTM D975, ASTM D1250, ASTM 
D4442, ASTM D4444, ASTM D6751, ASTM D6866, and ASTM E870 are also 
referenced in the regulatory text of this proposed rule. They were 
approved for IBR for the sections referenced as of July 1, 2022, and no 
changes are being proposed. ASTM E711 is also referenced in the 
regulatory text of this proposed rule. It was approved for IBR for the 
section referenced as of July 1, 2010, and no changes are being 
proposed.)

 Table X.I1--Standards and Test Methods To Be Incorporated by Reference
------------------------------------------------------------------------
   Organization and standard or test
                 method                            Description
------------------------------------------------------------------------
ANSI C12.20-2015, Electricity Meters     Standard for measuring the flow
 0.1, 0.2, And 0.5 Accuracy Classes,      of electrical power, including
 February 17, 2017.                       physical aspects of the meter
                                          as well as performance
                                          criteria.
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, April 2016.
API MPMS 14.3.1-2012, Manual of          Standard describing engineering
 Petroleum Measurement Standards          equations, installation
 Chapter 14--Natural Gas Fluids           requirements, and uncertainty
 Measurement Section 3--Orifice           estimations of square-edged
 Metering of Natural Gas and Other        orifice meters in measuring
 Related Hydrocarbon Fluids-Concentric,   the flow of natural gas and
 Square-edged Orifice Meters Part 1:      similar fluids.
 General Equations and Uncertainty
 Guidelines, 4th Edition, September
 2012.
API MPMS 14.3.2-2016, Manual of          Standard describing design and
 Petroleum Measurement Standards          installation of square-edged
 Chapter 14--Natural Gas Fluids           orifice meters for measuring
 Measurement Section 3--Orifice           flow of natural gas and
 Metering of Natural Gas and Other        similar fluids.
 Related Hydrocarbon Fluids-Concentric,
 Square-edged Orifice Meters Part 2:
 Specification and Installation
 Requirements, 5th Edition, March 2016.
API MPMS 14.3.3-2021, Manual of          Standard describing
 Petroleum Measurement Standards          applications using square-
 Chapter 14--Natural Gas Fluids           edged orifice meters for
 Measurement Section 3--Orifice           measuring flow of natural gas
 Metering of Natural Gas and Other        and similar fluids.
 Related Hydrocarbon Fluids-Concentric,
 Square-edged Orifice Meters Part 3:
 Natural Gas Applications, 4th Edition,
 November 2013.
API MPMS 14.3.4-2019, Manual of          Standard describing the
 Petroleum Measurement Standards          development of equations for
 Chapter 14--Natural Gas Fluids           coefficient of discharge,
 Measurement Section 3--Orifice           including a calculation
 Metering of Natural Gas and Other        procedure, for square-edged
 Related Hydrocarbon Fluids-Concentric,   orifice meters measuring flow
 Square-edged Orifice Meters Part 4--     of natural gas and similar
 Background, Development,                 fluids.
 Implementation Procedure, and Example
 Calculations, 4th Edition, September
 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 2540, Solids In: Standard Methods   Standard describing how to
 For the Examination of Water and         measure the total solids,
 Wastewater, approved 2015, revised       volatile solids, and other
 2020.                                    solid properties of wastewater
                                          sludge and similar substances.
ASTM D3588-98(2017)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

[[Page 80711]]

 
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 D7164-21, On-line/At-line Heating   Standard specifying how to use
 Value Determination of Gaseous Fuels     and maintain an on-line gas
 by Gas Chromatography, approved April    chromatogram for determining
 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.
------------------------------------------------------------------------

J. Executive Order 12898: Federal Actions To Address Environmental 
Justice in Minority Populations, and Low-Income Populations

    EPA believes that this action does not have disproportionately high 
and adverse human health or environmental effects on minority 
populations, low-income populations and/or indigenous peoples, as 
specified in Executive Order 12898 (59 FR 7629, February 16, 1994). 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 DRIA Chapter 9.
    This proposed rule would reduce GHG emissions, which would benefit 
minority populations, low-income populations, and indigenous 
populations. The manner in which the market responds to the provisions 
in this proposed rule could also have non-GHG impacts. Replacing 
petroleum fuels with renewable fuels will 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.

XI. 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 proposes to amend 40 
CFR parts 80 and 1090 as follows:

PART 80--REGULATION OF FUELS AND FUEL ADDITIVES

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

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

Subpart A--General Provisions

0
2. 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.
    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.
    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'',

[[Page 80712]]

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: http://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.
    Audited party means a party that pays for or receives services from 
an independent third party under this part.
    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.
    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 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.  80.3).
    Biodiesel distillation bottoms means the heavier product from 
distillation at a biodiesel production facility that does not meet the 
definition of biodiesel.
    Biogas or raw biogas means a mixture of biomethane, inert gases, 
and impurities that is produced through the anaerobic digestion of 
renewable biomass prior to any treatment to remove inert gases and 
impurities or adding non-biogas components.
    Biogas closed distribution system means the infrastructure 
contained between when biogas is produced, used to produce a biogas-
derived renewable fuel, and when the biogas-derived renewable fuel is 
used as transportation fuel within a discrete location or series of 
locations that does not include placement of 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, renewable 
electricity, 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 that a renewable fuel 
producer uses to produce a renewable fuel other than renewable CNG/LNG 
or renewable electricity.
    Biointermediate means any feedstock material that is intended for 
use to produce renewable fuel and meets all of 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 or renewable electricity.
    (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.
    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

[[Page 80713]]

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 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).
    Charging efficiency means the average fraction of energy stored in 
an EV's or PHEV's battery relative to the energy obtained from the 
electricity distribution system.
    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.
    Conterminous electricity distribution system means the major and 
minor alternating current (AC) power grids that supply electricity to 
or within the covered location (excluding Hawaii).
    Continuous measurement means the automated measurement of specified 
parameters of biogas, natural gas, or electricity as follows:
    (1) For in-line GC meters, automated measurement must occur at 
least once every 15 minutes.
    (2) For flow meters, automated measurement must occur at least once 
every 6 seconds.
    (3) For all other meters, automated measurement must occur at least 
once every 2 seconds.
    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 or CG means any gasoline that has been 
certified under 40 CFR 1090.1000(b) and is not RFG.
    Co-processed cellulosic diesel is any renewable fuel that meets the 
definition of cellulosic biofuel 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) 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.
    Co-processed fuel or co-processed intermediate means a fuel or 
intermediate that was partially produced from renewable biomass by any 
of the following:
    (1) The simultaneous processing of renewable biomass with non-
renewable feedstock in the same unit.
    (2) The use of heat or electricity that is not from renewable 
biomass and is converted to energy in the fuel or intermediate.
    (3) The commingling of renewable fuel or biointermediate with non-
renewable material and for which the volume of renewable fuel or 
biointermediate cannot be separately measured during the production 
process.
    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.
    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.
    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.

[[Page 80714]]

    (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) and 
(2) 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 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.
    Electrical vehicle miles traveled (eVMT) means the average annual 
vehicle miles travelled for an EV or average annual miles traveled in 
the all-electric mode of a PHEV.
    Electric generating unit (EGU) means a combustion unit that 
produces electricity.
    Electric vehicle (EV) has the meaning given in 40 CFR 86.1803-01.
    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 subpart:
    (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 or 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 or a biointermediate 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).
    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.

[[Page 80715]]

    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 electricity generator means any person who owns, 
leases, operates, controls, or supervises a renewable electricity 
generation facility outside of the United States.
    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.
    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 subpart 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 or BOB has the meaning 
given in 40 CFR 1090.80.
    Gasoline treated as blendstock or 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 60 degrees Fahrenheit and 1 atmosphere of 
pressure, 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.
    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.
    LDV/T has the meaning given in 40 CFR 86.1803-01.
    Light-duty truck has the meaning given in 40 CFR 86.1803-01.
    Light-duty vehicle has the meaning given in 40 CFR 86.1803-01.
    Liquefied petroleum gas or 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.
    Model has the meaning given in 40 CFR 86.1803-01.
    Model year has the meaning given in 40 CFR 86.1803-01.
    Motor vehicle has the meaning given in Section 216(2) of the Clean 
Air Act (42 U.S.C. 7550(2)).
    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 Sec.  
80.1450(b)(1)(v)(C).
    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

[[Page 80716]]

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.  80.3) 
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 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 primarily (i.e., >=75%) 
propelled by engines meeting the definition of ``Category 3'' in 40 CFR 
1042.901.
    Original equipment manufacturer (OEM) has the meaning given in 40 
CFR 86.1803-01.
    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.
    Plug-in hybrid electric vehicle (PHEV) has the meaning given in 40 
CFR 86.1803-01.
    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.
    Produced from renewable biomass means that the energy in the 
finished fuel or biointermediate comes from renewable biomass.
    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 or 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

[[Page 80717]]

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 or 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 or 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 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 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 and is covered under a RIN generation agreement under 
Sec.  80.135.
    Renewable electricity data mean the information that describes the 
monthly renewable electricity generation for a renewable electricity 
generation facility covered by a RIN generation agreement.
    Renewable electricity generation facility means any facility where 
renewable electricity is produced.
    Renewable electricity generator means any person who owns, leases, 
operates, controls, or supervises a renewable electricity generation 
facility.
    Renewable electricity RIN generator (RERG) means any OEM of 
electric and plug-in hybrid electric LDV/Ts registered to generate RINs 
for renewable electricity.
    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 subpart.
    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 or 
RNG that goes through the process of liquefaction in which it is cooled 
below its boiling point for use as transportation fuel, and which 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 contains at least 90 percent biomethane content.
    (3) It meets the specifications for the natural gas commercial 
pipeline system submitted and accepted by EPA under Sec.  80.145(f)(6).
    (4) It is used or will be used in the covered location as 
transportation fuel or to produce a renewable fuel.
    RERG's fleet means the RERG's electric and plug-in hybrid electric 
LDV/T fleet.
    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 generation agreement means the exclusive, bilateral, contracted 
ability of a RERG to generate RINs for all of the renewable electricity 
generated at a renewable electricity generation facility.
    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.  80.140.

[[Page 80718]]

    RNG producer means any person who owns, leases, operates, controls, 
or supervises an RNG production facility.
    RNG production facility means a location where biogas is upgraded 
to RNG.
    RNG RIN separator means any person registered to separate RINs for 
RNG under Sec.  80.140(d).
    RNG used as a feedstock means any RNG used to produce renewable 
fuel (including renewable electricity) under Sec.  80.140.
    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 (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 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.
    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 biogas that has undergone treatment to remove 
inert gases or impurities and is used in a biogas closed distribution 
system.
    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.
    Vehicle fuel economy means the average kWh consumed per mile by an 
EV or PHEV when operating in all electric mode.
    Verification status means a description of whether biogas, 
renewable electricity, 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. Revise Sec.  80.3 to read as follows:


Sec.  80.3  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 National Standards Institute (ANSI), 25 West 43rd 
Street, 4th Floor, New York, NY 10036; (212) 642-4980; www.ansi.org.
    (1) ANSI C12.20-2015, Electricity Meters 0.1, 0.2, And 0.5 Accuracy 
Classes, February 17, 2017 (ANSI C12.20); IBR approved for Sec.  
80.165(c).
    (2) [Reserved]
    (b) American Petroleum Institute (API), 200 Massachusetts Avenue 
NW, Suite 1100, Washington, DC 20001-5571; (202) 682-8000; www.api.org.
    (1) API MPMS 14.1-2016, Manual of Petroleum Measurement Standards 
Chapter 14--Natural Gas Fluids Measurement Section 1--Collecting and 
Handling of Natural Gas Samples for Custody Transfer, 7th Edition, 
April 2016 (``API MPMS 14.1''); IBR approved for Sec.  80.165(b).
    (2) API MPMS 14.3.1-2012, Manual of Petroleum Measurement Standards 
Chapter 14--Natural Gas Fluids Measurement Section 3--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, September 2012 (``API MPMS 
14.3.1''); IBR approved for Sec.  80.165(a).

[[Page 80719]]

    (3) API MPMS 14.3.2-2016, Manual of Petroleum Measurement Standards 
Chapter 14--Natural Gas Fluids Measurement Section 3--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.  80.165(a).
    (4) API MPMS 14.3.3-2021, Manual of Petroleum Measurement Standards 
Chapter 14--Natural Gas Fluids Measurement Section 3--Orifice Metering 
of Natural Gas and Other Related Hydrocarbon Fluids-Concentric, 
Square[hyphen]edged Orifice Meters Part 3: Natural Gas Applications, 
4th Edition, November 2013 (``API MPMS 14.3.3''); IBR approved for 
Sec.  80.165(a).
    (5) API MPMS 14.3.4-2019, Manual of Petroleum Measurement Standards 
Chapter 14--Natural Gas Fluids Measurement Section 3--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, 
September 2019 (``API MPMS 14.3.4''); IBR approved for Sec.  80.165(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.  80.165(a).
    (c) American Public Health Association (APHA), 1015 15th Street NW, 
Washington, DC 20005; (202) 777-2742; https://www.standardmethods.org.
    (1) SM 2540, Solids In: Standard Methods For the Examination of 
Water and Wastewater, approved June 10, 2020 (``SM 2540''); IBR 
approved for Sec.  80.165(d).
    (2) [Reserved]
    (d) 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(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.  
80.165(b).
    (4) 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).
    (5) 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).
    (6) 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.  80.165(b).
    (7) ASTM D5504-20, Standard Test Method for Determination of Sulfur 
Compounds in Natural Gas and Gaseous Fuels by Gas Chromatography and 
Chemiluminescence, approved November 1, 2020 (``ASTM D5504''); IBR 
approved for Sec.  80.165(b).
    (8) 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.
    (9) 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.  80.165(b); 80.1426(f); 80.1430(e).
    (10) ASTM D7164-21, On-line/At-line Heating Value Determination of 
Gaseous Fuels by Gas Chromatography, approved April 1, 2021 (``ASTM 
D7164''); IBR approved for Sec.  80.165(a).
    (11) 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.  80.165(b).
    (12) ASTM E711-87 (R2004), 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).
    (13) 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).


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 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.  80.9 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.

Subpart B--Controls and Prohibitions


Sec.  80.24  [Amended]

0
7. Amend Sec.  80.24 by, in paragraph (b), removing the text ``the 
Administrator'' and adding, in its place, the text ``EPA''.
0
8. Add subpart E, consisting of Sec. Sec.  80.100 through 80.195, to 
read as follows:

[[Page 80720]]

Subpart E--Biogas-Derived Renewable Fuel

Sec.
80.100 Scope and application.
80.105 Biogas producers.
80.110 Renewable electricity generators.
80.115 Renewable electricity RIN generators.
80.120 RNG producers, RNG importers, and biogas closed distribution 
system RIN generators.
80.125 RNG RIN separators.
80.130 Parties that produce renewable fuel from biogas used as a 
biointermediate or RNG used as a feedstock.
80.135 RINs for renewable electricity.
80.140 RINs for RNG.
80.142 RINs for renewable CNG/LNG from a biogas closed distribution 
system.
80.145 Registration.
80.150 Reporting.
80.155 Recordkeeping.
80.160 Product transfer documents.
80.165 Sampling, testing, and measurement.
80.170 RNG importers and foreign biogas producers, RNG producers, 
renewable electricity generators, and RERGs.
80.175 Attest engagements.
80.180 Quality assurance program.
80.185 Prohibited acts and liability provisions.
80.190 Affirmative defense provisions.
80.195 Potentially invalid RINs.


Sec.  80.100  Scope and application.

    (a) Applicability. (1) The provisions of this subpart E apply to 
all biogas, renewable electricity, and RNG used to produce a biogas-
derived renewable fuel, and RINs generated for a biogas-derived 
renewable fuel.
    (2) This subpart also specifies requirements for any person that 
engages in activities associated with the production, distribution, 
transfer, or use of biogas, renewable electricity, RNG, 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. (1) RERGs must only generate RINs for 
renewable electricity used in vehicles in the RERG's fleet that are 
registered in a state in the covered location (excluding Hawaii).
    (2) Only renewable electricity that is used as transportation fuel 
in the covered location (excluding Hawaii) is eligible for the 
generation of RINs for renewable electricity. Renewable electricity is 
deemed to be eligible for use as transportation fuel in the covered 
location if the renewable electricity is introduced into the 
conterminous electricity distribution system that serves the covered 
location (excluding Hawaii).
    (3) 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 January 1, 2024, unless otherwise specified. 
Parties required to register under Sec.  80.145 may register with EPA 
beginning on the effective date of the final rule.
    (2) Generation of RINs for renewable electricity. RERGs must only 
generate RINs for renewable electricity produced from biogas or RNG 
produced on or after January 1, 2024.
    (3) Generation of RINs for RNG. RNG producers must generate RINs 
for RNG produced on or after January 1, 2024, as specified in Sec.  
80.140.
    (4) Generation of RINs for renewable CNG/LNG. (i) For biogas or RNG 
produced on or before December 31, 2023, biogas closed distribution 
system RIN generators must generate RINs for renewable CNG/LNG as 
specified in Sec.  80.1426(f)(10) and (11), as applicable.
    (ii) For biogas produced on or after January 1, 2024, biogas closed 
distribution system RIN generators must generate RINs for renewable 
CNG/LNG as specified in Sec.  80.142.
    (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 January 1, 2024.


Sec.  80.105  Biogas producers.

    (a) General requirements. (1) Any biogas producer that produces 
biogas for use to produce RNG, renewable electricity, 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.
    (5) The transfer and batch segregation limits specified in Sec.  
80.1476(g) do not apply.
    (b) Registration. The biogas producer must register with EPA under 
Sec. Sec.  80.145, 80.1450, and 40 CFR part 1090, subpart I, as 
applicable.
    (c) Reporting. The biogas producer must submit reports to EPA under 
Sec. Sec.  80.150 and 80.1451, as applicable.
    (d) Recordkeeping. The biogas producer must create and maintain 
records under Sec. Sec.  80.155 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.  80.160.
    (f) Sampling, testing, and measurement. (1)(i) A biogas producer 
must continuously measure the volume of biogas, in Btu, prior to 
transferring biogas outside of the biogas production facility.
    (ii) A biogas producer must continuously measure the volume of 
biogas, in Btu, from each digester subject to Sec.  80.1426(f)(3)(vi) 
prior to mixing with any other biogas.
    (iii) A biogas producer with separate digesters at a biogas 
production facility that produces biogas qualified to be used to 
produce biogas-derived renewable fuel eligible to generate RINs 
multiple D codes must continuously measure the volume of biogas, in 
Btu, at all the following:
    (A) At the output of each digester.
    (B) As each mixture of biogas from multiple digesters leaves the 
facility.
    (iv) A biogas producer must measure total solids and volatile 
solids for a representative sample of each cellulosic feedstock for 
each digester subject to Sec.  80.1426(f)(3)(vi) at least once per 
calendar month.
    (2) All sampling, testing, and measurements must be done in 
accordance with Sec.  80.165.
    (g) Foreign biogas producer requirements. A foreign biogas producer 
must meet all requirements that apply to a biogas producer under this 
part, as well as the additional requirements for foreign biogas 
producers specified in Sec.  80.170.
    (h) Attest engagements. The biogas producer must submit annual 
attest engagement reports to EPA under Sec. Sec.  80.175 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.  80.180.

[[Page 80721]]

    (j) Batches. (1) A batch of biogas is the total volume of biogas 
produced at a biogas production facility under a single batch pathway 
for the calendar month, in Btu, as determined under paragraph (j)(3) of 
this section.
    (2) 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.).
    (3)(i) The batch volume of biogas for each batch pathway must be 
calculated as follows:
[GRAPHIC] [TIFF OMITTED] TP30DE22.030

Where:

VBG,p = The batch volume of biogas for batch pathway p, 
in Btu.
VBG = The total volume of biogas produced, in Btu, per 
paragraph (j)(3)(ii) of this section.
FEp = Sum of feedstock energies from all feedstocks used 
to produce biogas under batch pathway p, in Btu, per Sec.  
80.1426(f)(3)(vi).
FEtotal = Sum of feedstock energies from all feedstocks 
used to produce biogas, in Btu, per Sec.  80.1426(f)(3)(vi).

    (ii) The total volume of biogas produced must be calculated as 
follows:

VBG = VG * R

Where:

VBG = The total volume of biogas produced, in Btu.
VG = The total volume of gas produced at the biogas 
production facility for the calendar month, in Btu, as measured 
under Sec.  80.165.
R = The renewable fraction of the gas produced at the biogas 
production facility for the calendar month. For gas produced only 
from renewable feedstocks, R is equal to 1. For 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).

    (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) Production of renewable electricity via a biogas closed 
distribution system.
    (iii) As a biointermediate via a biogas closed distribution system.
    (iv) Production of RNG.
    (2) For each biogas production facility that produces biogas in a 
biogas closed distribution system used to produce renewable 
electricity:
    (i) The biogas producer must only supply biogas to a single 
renewable electricity generation facility.
    (ii) The biogas producer must not inject biogas into a natural gas 
commercial pipeline system.
    (3) 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 to a single renewable fuel production 
facility.
    (4) If the biogas producer operates a municipal wastewater 
treatment facility digester, the biogas producer must not introduce any 
feedstocks into the digester that do not contain at least 75% average 
adjusted cellulosic content.


Sec.  80.110  Renewable electricity generators.

    (a) General requirements. (1) Any renewable electricity generator 
that produces renewable electricity must comply with the requirements 
of this section.
    (2) The renewable electricity generator must also comply with all 
other applicable requirements of this part and 40 CFR part 1090.
    (3) If the renewable electricity generator meets the definition of 
more than one type of regulated party under this part or 40 CFR part 
1090, the renewable electricity generator must comply with the 
requirements applicable to each of those types of regulated parties.
    (4) The renewable electricity generator must comply with all 
applicable requirements of this part, regardless of whether the 
requirements are identified in this section.
    (b) Registration. The renewable electricity generator must register 
with EPA under Sec. Sec.  80.145, 80.1450, and 40 CFR part 1090, 
subpart I, as applicable.
    (c) Reporting. The renewable electricity generator must submit 
reports to EPA under Sec.  80.150.
    (d) Recordkeeping. The renewable electricity generator must create 
and maintain records under Sec.  80.155.
    (e) PTDs. On each occasion when the renewable electricity generator 
transfers renewable electricity generation data to a RERG, the 
transferor must provide to the transferee PTDs under Sec.  80.160.
    (f) Measurement. (1)(i) A renewable electricity generator must 
continuously measure the volume of natural gas, in Btu, withdrawn from 
the natural gas commercial pipeline system.
    (ii) A renewable electricity generator must continuously measure 
the volume of electricity, in kWh, produced at the renewable 
electricity generation facility.
    (2) All measurements must be done in accordance with Sec.  80.165.
    (g) Foreign renewable electricity generator requirements. A foreign 
renewable electricity generator must meet all requirements that apply 
to a renewable electricity generator under this part, as well as the 
additional requirements for foreign renewable electricity generators 
specified in Sec.  80.170.
    (h) Attest engagements. The renewable electricity generator must 
submit annual attest engagement reports to EPA under Sec.  80.175 using 
procedures specified in 40 CFR 1090.1800 and 1090.1805.
    (i) QAP. Prior to the generation of Q-RINs for renewable 
electricity, the renewable electricity generator must meet all 
applicable requirements specified in Sec.  80.180.
    (j) Retirement of RINs for RNG. A renewable electricity generator 
that produces renewable electricity from RNG must retire RINs for RNG 
as specified in Sec.  80.140.
    (k) Batches. (1) A batch of renewable electricity is the total 
volume of renewable electricity produced at a renewable electricity 
generation facility under a single batch pathway for the calendar 
month, in kWh, as determined under paragraph (k)(3) of this section.
    (2) The renewable electricity generator must assign a number (the 
``batch number'') to each batch of renewable electricity 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.).
    (3) The batch volume of renewable electricity for each batch 
pathway must be calculated as follows:
    (i) For renewable electricity produced from biogas:
    [GRAPHIC] [TIFF OMITTED] TP30DE22.008
    
Where:

VRE,p = The batch volume of renewable electricity for 
batch pathway p, in kWh.
VRE = The total volume of renewable electricity produced, 
in kWh, per paragraph (k)(3)(iii) of this section.
VBG,p = The total volume of biogas used to produce 
renewable electricity under

[[Page 80722]]

batch pathway p, in Btu, per Sec.  80.105(j)(3)(i).
VBG = The total volume of biogas used to produce 
renewable electricity, in Btu, per Sec.  80.105(j)(3)(ii).

    (ii) For renewable electricity produced from RNG:
    [GRAPHIC] [TIFF OMITTED] TP30DE22.009
    
Where:

VRE,p = The batch volume of renewable electricity for 
batch pathway p, in kWh.
VRE = The total volume of renewable electricity produced, 
in kWh, per paragraph (k)(3)(iii) of this section.
RINRNG,p = The total number of RINs for RNG that were 
retired by the renewable electricity generator corresponding to the 
volume of RNG used to produce renewable electricity under batch 
pathway p.
RINRNG = The total number of RINs for RNG that were 
retired by the renewable electricity generator corresponding to the 
volume of RNG used to produce renewable electricity.

    (iii) The total volume of renewable electricity produced must be 
calculated as follows:

[GRAPHIC] [TIFF OMITTED] TP30DE22.010

Where:

VRE = The total volume of renewable electricity produced, 
in kWh.
VE = The total volume of electricity produced at the 
renewable electricity generation facility for the calendar month, in 
kWh, as measured under Sec.  80.165.
VEGU = The total volume of electricity used by EGUs at 
the renewable electricity generation facility for the calendar 
month, in kWh.
FERNG = The total higher heating value of the RNG used to 
produce electricity, in Btu. For purposes of this equation, 
FER is equal to the number of RINs retired for RNG under 
Sec.  80.140(e) for the calendar month multiplied by 85,200 Btu.
FEFS = The total higher heating value of the feedstocks 
used to produce electricity, in Btu, as measured under Sec.  80.165.

    (l) Limitations. (1) For each renewable electricity generation 
facility, the renewable electricity generator must only produce 
renewable electricity from one of the following:
    (i) Biogas in a biogas closed distribution system.
    (ii) RNG.
    (2) For each renewable electricity generation facility, the 
renewable electricity generator must only enter into a RIN generation 
agreement with a single RERG, except as specified in Sec.  
80.135(a)(1)(iii)(B).
    (3) Renewable electricity produced from biogas in a biogas closed 
distribution system may only be used for RIN generation if biogas is 
the only feedstock used to produce electricity at the renewable 
electricity generation facility during that month.


Sec.  80.115  Renewable electricity RIN generators.

    (a) General requirements. (1) Any RERG must comply with the 
requirements of this section.
    (2) The RERG must also comply with all other applicable 
requirements of this part and 40 CFR part 1090.
    (3) If the RERG meets the definition of more than one type of 
regulated party under this part or 40 CFR 1090, the RERG must comply 
with the requirements applicable to each of those types of regulated 
parties.
    (4) The RERG must comply with all applicable requirements of this 
part, regardless of whether they are identified in this section.
    (b) Registration. The RERG must register with EPA under Sec. Sec.  
80.145, 80.1450, and 40 CFR part 1090, subpart I, as applicable.
    (c) Reporting. The RERG must submit reports to EPA under Sec. Sec.  
80.150, 80.1451, and 80.1452, as applicable.
    (d) Recordkeeping. The RERG must create and maintain records under 
Sec. Sec.  80.155 and 80.1454.
    (e) PTDs. On each occasion when the RERG transfers RINs to another 
party, the transferor must provide to the transferee PTDs under Sec.  
80.1453.
    (f) Foreign RERG requirements. A foreign RERG must meet all 
requirements that apply to a RERG under this part, as well as the 
additional requirements for foreign RERGs specified in Sec.  80.170.
    (g) Attest engagements. The RERG must submit annual attest 
engagement reports to EPA under Sec. Sec.  80.175 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 renewable 
electricity, the RERG must meet all applicable requirements specified 
in Sec.  80.180.
    (i) Batches. (1) A batch of RINs for renewable electricity is the 
total number of RINs generated under Sec.  80.135 for a renewable 
electricity generation facility under a single batch pathway for the 
quarter.
    (2) The RERG must assign a number (the ``batch number'') to each 
batch of RINs as specified in Sec.  80.1425.


Sec.  80.120  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.  80.145, 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.  80.150, 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.  80.155 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.  80.160 and 80.1453, as 
applicable.
    (f) Sampling, testing, and measurement. (1)(i) An RNG producer must 
continuously measure the volume of RNG, in Btu, 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 continuously measure the 
volume of RNG, in Btu, 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:

[[Page 80723]]

    (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 but does not produce RNG must 
continuously measure the volume of biogas, in Btu, after such upgrading 
has been conducted.
    (2) All sampling, testing, and measurements must be done in 
accordance with Sec.  80.165.
    (g) Foreign RNG producer, RNG importer, and foreign biogas closed 
distribution system RIN generator requirements. (1)(i) A foreign RNG 
producer must meet all requirements that apply to an RNG producer under 
this part, as well as the additional requirements for foreign RNG 
producers specified in Sec.  80.170.
    (ii) A foreign RNG producer must either generate RINs under Sec.  
80.140 or enter into a contract with an RNG importer as specified in 
Sec.  80.170(e).
    (2) An RNG importer must meet all requirements that apply to an RNG 
importer specified in Sec.  80.170(i).
    (3) A foreign biogas closed distribution system RIN generator must 
meet all 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.  80.170 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.  80.175 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.  80.180.
    (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, 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)(i) The batch volume of RNG for each batch pathway must be 
calculated as follows:
[GRAPHIC] [TIFF OMITTED] TP30DE22.011

Where:

VRNG,p = The batch volume of RNG for batch pathway p, in 
Btu.
VRNG = The total volume of RNG produced, in Btu, per 
paragraph (j)(4)(ii) of this section.
FEp = Sum of feedstock energies from all feedstocks used 
to produce RNG under batch pathway p, in Btu, per Sec.  
80.1426(f)(3)(vi).
FEtotal = Sum of feedstock energies from all feedstocks 
used to produce RNG, in Btu, per Sec.  80.1426(f)(3)(vi).

    (ii) The total volume of RNG produced must be calculated as 
follows:

VRNG = VNG * R

Where:

VRNG = The total volume of RNG produced, in Btu.
VNG = The total volume of natural gas produced at the RNG 
production facility for the calendar month, in Btu, as measured 
under Sec.  80.165.
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.  80.125  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. The RNG RIN separator must register with EPA 
under Sec. Sec.  80.145, 80.1450, and 40 CFR part 1090, subpart I, as 
applicable.
    (c) Reporting. The RNG RIN separator must submit reports to EPA 
under Sec. Sec.  80.150, 80.1451, and 80.1452, as applicable.
    (d) Recordkeeping. The RNG RIN separator must create and maintain 
records under Sec. Sec.  80.155 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) An RNG RIN separator must continuously measure 
the volume of natural gas, in Btu, withdrawn from the natural gas 
commercial pipeline system.
    (2) All measurements must be done in accordance with Sec.  80.165.
    (g) Attest engagements. The RNG RIN separator must submit annual 
attest engagement reports to EPA under Sec. Sec.  80.175 and 80.1464 
using procedures specified in 40 CFR 1090.1800 and 1090.1805.


Sec.  80.130  Parties that produce biogas-derived renewable fuel from 
biogas used as a biointermediate or RNG used as a feedstock.

    (a) General requirements. (1) Any renewable fuel producer that uses 
biogas as a biointermediate or RNG as a feedstock to produce a biogas-
derived renewable fuel 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.  80.145, 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.  80.150, 80.1451, and 80.1452, as applicable.
    (d) Recordkeeping. The renewable fuel producer must create and 
maintain records under Sec. Sec.  80.155 and 80.1454.

[[Page 80724]]

    (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.  80.160 and 80.1453.
    (f) Measurement. (1) A renewable fuel producer must continuously 
measure the volume of biogas or natural gas, in Btu, withdrawn from the 
natural gas commercial pipeline system, as applicable.
    (2) All measurements must be done in accordance with Sec.  80.165.
    (g) Attest engagements. The renewable fuel producer must submit 
annual attest engagement reports to EPA under Sec. Sec.  80.175 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.  80.180.


Sec.  80.135  RINs for renewable electricity.

    (a) General RIN generation provisions--(1) RIN generation 
agreements. (i) Only a RERG may generate RINs for renewable 
electricity.
    (ii) A RERG must only generate RINs for renewable electricity 
represented by a RIN generation agreement obtained from a registered 
renewable electricity generator.
    (iii)(A) Except as specified in paragraph (a)(1)(iii)(B) of this 
section, for each renewable electricity generation facility, a 
renewable electricity generator must contract the RIN generation 
agreement to only one RERG and identify the RERG in the renewable 
electricity generator's registration information submitted under Sec.  
80.145.
    (B) A renewable electricity generator may only change the 
designated RERG for RIN generation agreement for a renewable 
electricity generation facility once per calendar year unless EPA, in 
its sole discretion, allows the renewable electricity generator to 
change the designated RERG more frequently.
    (iv) A RERG may have RIN generation agreements from multiple 
renewable electricity generation facilities and from multiple renewable 
electricity generators.
    (v) A RERG must not transfer any RIN generation agreement to any 
other party.
    (2) RIN generation timing. (i) A RERG must only generate RINs 
quarterly.
    (ii) A RERG must generate RINs no later than 30 days after the end 
of the quarter for which they are generating the RINs.
    (iii) The generation year for RINs generated for renewable 
electricity is the calendar year in which the renewable electricity was 
generated.
    (3) Renewable electricity allocation. A RERG may allocate renewable 
electricity data for the generation of RINs in any manner as long all 
the following conditions are met:
    (i) The total number of RINs generated does not exceed the total 
number of RINs determined under paragraph (c)(1) of this section.
    (ii) The number of RINs generated under each batch pathway for a 
particular renewable electricity generation facility does not exceed 
the number of RINs determined under paragraph (c)(2) of this section.
    (iii) Any unallocated renewable electricity for one quarter may not 
be used for RIN generation in another quarter.
    (b) Requirements for renewable electricity from biogas or RNG. (1) 
Except as specified in paragraph (b)(2) of this section, RINs for 
renewable electricity produced from biogas or RNG may only be generated 
if all the following requirements are met:
    (i) The biogas was produced by a biogas producer meeting the 
requirements specified in Sec.  80.105, if applicable.
    (ii) The RNG was produced by an RNG producer meeting the 
requirements specified in Sec.  80.120, if applicable.
    (iii) The renewable electricity was produced from biogas or RNG by 
a renewable electricity generator meeting the requirements specified in 
Sec.  80.110.
    (2) A RERG may generate RINs for renewable electricity regardless 
of whether the renewable electricity generator, biogas producer, or 
both have had their registration(s) accepted under Sec.  80.145 if all 
the following requirements are met:
    (i) The renewable electricity generator and biogas producer each 
submitted a registration request under Sec.  80.145 with a third-party 
engineering review report to EPA on or before December 31, 2023.
    (ii) Neither the biogas producer nor renewable electricity 
generator substantially alters their facilities after the third-party 
engineering review site visit.
    (iii) The biogas was produced after the third-party engineering 
review site visit.
    (iv) The renewable electricity generator entered into a RIN 
generation agreement with the RERG on or before December 31, 2023.
    (v) The renewable electricity was produced between January 1, 2024, 
and April 30, 2024.
    (vi) The biogas producer, renewable electricity generator, and RERG 
meet all applicable requirements under this subpart for the biogas, 
renewable electricity, and RINs.
    (vii) EPA accepts the registrations for the biogas producer and 
renewable electricity generator on or before April 30, 2024.
    (c) RIN generation equations. (1) The total number of RINs a RERG 
is eligible to generate for each quarter must be calculated as follows:
[GRAPHIC] [TIFF OMITTED] TP30DE22.012

Where:

eRINQ = The total number of RINs the RERG is eligible to 
generate for quarter Q.
MIN = A minimization function that takes the lesser of the two 
subsequent values in parentheses.
ELFLEET,Q = The total volume of electricity that was used 
by the RERG's fleet for quarter Q, in kWh, per paragraph (c)(1)(i) 
of this section.
ELPRO,Q = The total volume of renewable electricity 
eligible for RIN generation produced by all renewable electricity 
generation facilities for which the RERG has obtained RIN generation 
agreements for quarter Q, in kWh, per paragraph (c)(1)(ii) of this 
section.
EqVRE = The equivalence value for renewable electricity, 
in kWh per RIN, per Sec.  80.1415(b)(6).

    (i) Calculating RINs using the RERG's fleet. The total volume of 
electricity that was used in the RERG's fleet for each quarter must be 
calculated as follows:

[[Page 80725]]

[GRAPHIC] [TIFF OMITTED] TP30DE22.013

Where:

ELFLEET,Q = The total volume of electricity that was used 
in the RERG's fleet for quarter Q, in kWh.
PHEVQ = The number of PHEVs in the RERG's fleet for 
quarter Q, as reported to EPA under Sec.  80.150.
eVMTPHEV = The estimated annual distance traveled in the 
all-electric mode of an average PHEV in the RERG's fleet, in miles 
per year, per paragraph (c)(1)(i)(A) of this section.
FEPHEV = The vehicle fuel economy for an average PHEV, in 
kWh per mile. For purposes of this equation, FEPHEV is 
equal to 0.32.
EVQ = The number of EVs in the RERG's fleet for quarter 
Q, as reported to EPA under Sec.  80.150.
eVMTEV = The estimated annual distance traveled for an 
average EV, in miles per year. For purposes of this equation, 
eVMTEV is equal to 7,200.
FEEV = The vehicle fuel economy for an average EV, in kWh 
per mile. For purposes of this equation, FEEV is equal to 
0.32.
QPY = The number of quarters per year. For purposes of this 
equation, QPY is equal to 4.

    (A) The estimated annual distance traveled in the all-electric mode 
of an average PHEV in the RERG's fleet must be calculated as follows:
[GRAPHIC] [TIFF OMITTED] TP30DE22.014

Where:

eVMTPHEV = The estimated annual distance traveled in the 
all-electric mode of an average PHEV in the RERG's fleet, in miles 
per year.
VMTPHEV = The estimated annual distance traveled for an 
average PHEV, in miles per year. For purposes of this equation, 
VMTPHEV equals 11,500.
nP = The number of PHEV groups with distinct make, model, model 
year, and trim in the RERG's fleet, as reported to EPA under Sec.  
80.150.
ni,Q = The number of PHEVs of a particular make, model, 
model year, and trim in the RERG's fleet designated with i (the 
``particular PHEV'') for quarter Q, as reported to EPA under Sec.  
80.150.
UFi = The utilization factor of the particular PHEV, per 
paragraph (c)(1)(i)(B) of this section.

    (B) The utilization factor of a particular PHEV must be calculated 
as follows:
    (1) Determine the all-electric range of the PHEV as specified in 40 
CFR 600.210-12(a)(4).
    (2)(i) If the all-electric range of the PHEV is less than or equal 
to 10 miles, then UFi equals 0.
    (ii) If the all-electric range of the PHEV is greater than or equal 
to 100 miles, then UFi equals 0.867.
    (iii) If the all-electric range of the PHEV is greater than 10 
miles and less than 100 miles, then UFi must be calculated 
as follows:

UFi = 0.379 * ln(REV,i)-0.878

Where:

UFi = The utilization factor of the PHEV.
REV,i = The all-electric range of the PHEV, in miles, per 
40 CFR 600.210-12(a)(4).

    (ii) Calculating RINs using quarterly renewable electricity 
produced. The volume of renewable electricity eligible for RIN 
generation produced by each renewable electricity generation facility 
for which the RERG has obtained a RIN generation agreement for each 
batch pathway for each quarter must be calculated as follows:

ELPRO,Q,i,p = PROQ,i,p * (1-LossLINE) * CE

Where:

ELPRO,Q,i,p = The volume of renewable electricity 
eligible for RIN generation produced by renewable electricity 
generation facility i for batch pathway p for quarter Q, in kWh.
PROQ,i,p = The volume of renewable electricity produced 
by renewable electricity generation facility i for batch pathway p 
for quarter Q, in kWh.
LossLINE = The assumed fraction of renewable electricity 
loss from the transmission of the renewable electricity expressed as 
a proportion. For purposes of this equation, LossLINE 
equals 0.053.
CE = The assumed fraction of renewable electricity retained during 
the charging of the EV or PHEV expressed as a proportion. For 
purposes of this equation, CE equals 0.85.

    (2) For each quarter, the maximum number of RINs a RERG is eligible 
to generate under each batch pathway for a particular renewable 
electricity facility must be calculated as follows:

[GRAPHIC] [TIFF OMITTED] TP30DE22.015

Where:

eRINmax,Q,i,p = The maximum number of RINs that a RERG is 
eligible to generate under batch pathway p for renewable electricity 
facility i for quarter Q.
EqVRE = The equivalence value for renewable electricity, 
in kWh per RIN, per Sec.  80.1415(b)(6).
ELPRO,Q,i,p = The volume of renewable electricity 
eligible for RIN generation produced by renewable electricity 
generation facility i for batch pathway p for quarter Q, in kWh, per 
paragraph (c)(1)(ii) of this section.

    (d) RIN separation. A RERG must separate RINs generated for 
renewable electricity under Sec.  80.1429(b)(5)(i).
    (e) RIN retirement. A party must retire RINs generated for 
renewable electricity if any of the conditions specified in Sec.  
80.1434(a) apply and must comply with Sec.  80.1434(b).


Sec.  80.140  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) RINs for RNG must be transacted 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.  
80.145.
    (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.  80.165 to determine the heating value of RNG for the generation 
of RINs.
    (6) The number of RINs generated for a batch of RNG under each 
batch pathway must be calculated as follows:

[[Page 80726]]

[GRAPHIC] [TIFF OMITTED] TP30DE22.016

Where:

RINRNG,p = The number of RINs generated for an RNG batch 
under batch pathway p, in gallon-RINs.
VRNG,p = The batch volume of RNG for batch pathway p, in 
Btu, per Sec.  80.120(j)(4)(i).
EqVRNG = The equivalence value for RNG, in Btu 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, must not be greater than the lesser of the 
total loading or unloading volume measurement for the month, in Btu, as 
required under Sec.  80.165(a)(1).
    (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) No party may assign any other RIN to a volume of RNG except as 
specified in paragraph (c)(1) of this section.
    (3) Each party that transfers title of a volume of RNG to another 
party must transfer title of any assigned RINs for the volume of RNG to 
the transferee.
    (d) RIN separation. (1) A party must only separate a RIN from RNG 
if all the following requirements are met:
    (i) The party withdrew the RNG from the natural gas commercial 
pipeline system.
    (ii) The party produced or oversaw the production of the renewable 
CNG/LNG from the RNG.
    (iii) The party measured the volume of RNG used to produce the 
renewable CNG/LNG using the procedures specified in Sec.  80.165.
    (iv) The party has the following documentation demonstrating that 
the volume of renewable CNG/LNG was used as transportation fuel:
    (A) If the party 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 party is relying on documentation from a downstream 
party, all the following:
    (1) A written contract with the downstream party for the sale or 
use of the renewable CNG/LNG as transportation fuel.
    (2) Records from the downstream party demonstrating the date, 
location, and volume of renewable CNG/LNG sold or used as 
transportation fuel.
    (3) An affidavit from the downstream party confirming that the 
volume of renewable CNG/LNG was used as transportation fuel and for no 
other purpose.
    (v) The volume of RNG was only used to produce renewable CNG/LNG 
that is used as transportation fuel and for no other purpose.
    (vi) No other party used the information in paragraphs (d)(1)(i) 
through (v) of this section to separate RINs for the RNG.
    (2) 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.
    (3) A party must only separate a number of RINs equal to the total 
volume of RNG (where the Btu are converted to gallon-RINs using the 
conversion specified in Sec.  80.1415(b)(5)) that the party 
demonstrates are used as renewable CNG/LNG under paragraph (d)(1) 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) 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 would expire under Sec.  80.1428(c) and must 
retire the expired, assigned RINs by March 31 of the subsequent year. 
For example, if an RNG producer assigns RINs for RNG in 2024, the RINs 
expire if they are not separated under paragraph (d) of this section by 
December 31, 2025, and must be retired by March 31, 2026.
    (3) Any party that uses RNG as a feedstock or as process heat under 
Sec.  80.1426(f)(12) or (13) must retire any assigned RINs for the 
volume of RNG within 5 business days of such use of the RNG.


Sec.  80.142  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) RINs must be transacted as specified in Sec.  80.1452.
    (b) RIN generation. (1) Renewable CNG/LNG producers must generate 
RINs using the applicable requirements for RIN generation in Sec.  
80.1426.
    (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.  80.145  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) Renewable electricity generators.
    (3) RERGs.
    (4) RNG producers.
    (5) Biogas closed distribution system RIN generators.
    (6) RNG RIN separators.
    (7) Renewable fuel producers using biogas as a biointermediate or 
RNG as a feedstock.
    (b) General registration requirements--(1) New registrants. (i) 
Except as allowed under Sec.  80.135(b)(2), 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. Parties registered to 
produce renewable CNG/LNG under an approved pathway before the 
effective date in Sec.  80.100(d)(1) are deemed registered under this 
subpart E, except as follows:

[[Page 80727]]

    (i) If the information in the existing registration is incorrect, 
the party must update their registration as specified in Sec.  
80.1450(d).
    (ii) If the information in the existing registration does not meet 
all the requirements in Sec.  80.145(f), then the party must update 
their registration to meet all requirements in Sec.  80.145(f) by 
November 1, 2024.
    (iii)(A) Except as specified in paragraph (b)(2)(iii)(B) of this 
section, the party's three-year engineering review updates must include 
all of the information required in paragraphs (c) through (h) of this 
section, as applicable.
    (B) A biogas closed distribution system RIN generator 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).
    (3) Engineering reviews. (i) A biogas producer, renewable 
electricity generator, or RNG producer under paragraph (c), (d), or (f) 
of this section, respectively, must undergo all the following:
    (A) A third-party engineering review as specified in Sec.  
80.1450(b)(2).
    (B) A three-year engineering review update as specified in Sec.  
80.1450(d)(3).
    (ii) Third-party engineering reviews 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).
    (4) Registration updates. (i) Except as specified in Sec.  
80.1450(d)(2), 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) or 
(2), as applicable.
    (C) A change of ownership is submitted under 40 CFR 1090.820.
    (ii) Information specified in paragraphs (d)(4)(ii) and (i) of this 
section must be updated according to the schedule 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 
paragraphs (b) and (i) of this section, a biogas producer must submit 
all the following information for each biogas production facility:
    (1) All applicable company and facility information under 40 CFR 
1090.805.
    (2) Information to establish the biogas production capacity for the 
biogas production facility, in Btu, including 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 
biogas production facility, if available.
    (ii) Documents demonstrating the biogas production facility's 
nameplate capacity.
    (iii) Information describing the biogas production facility's 
electricity production for each of the last three calendar years prior 
to the registration submission, if available.
    (3) A description of how the biogas will be used (e.g., RNG, 
renewable CNG/LNG, or renewable electricity).
    (4) Information related to biogas measurement as follows:
    (i) A description of how biogas will be measured under Sec.  
80.165(a), including the specific standards that the meters are 
operated under.
    (ii) A description of the biogas production process, including a 
process flow diagram that includes metering type(s) and location(s).
    (iii) If the biogas producer is unable to continuously measure 
biogas, the biogas producer may request the approval by EPA of an 
alternative sampling protocol as long as the biogas producer 
demonstrates that the alternative sampling protocol properly measures 
the heating value of the biogas, as applicable.
    (5) 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 the physical process from biogas 
production to dispensing of renewable CNG/LNG as transportation fuel, 
including major equipment (e.g., tanks, pipelines, flares, separation 
equipment, compressors, and dispensing infrastructure).
    (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 that is expected to use the 
CNG/LNG as transportation fuel.
    (6) For biogas in a biogas closed distribution system used to 
produce renewable electricity, all the following additional 
information:
    (i) Identifying information for the renewable electricity generator 
that the biogas producer will supply.
    (ii) A process flow diagram of the physical process from biogas 
production to entering the renewable electricity generation facility, 
including major equipment (e.g., feedstock retrieval, tanks, pipelines, 
flares, separation equipment, and compressors).
    (iii) A description of the physical process from biogas production 
to entering the renewable electricity generation facility, including 
the biogas closed distribution system and explaining how the biogas is 
introduced into a biogas closed distribution system connected to the 
renewable electricity generation facility.
    (7) For biogas used as a biointermediate, all the following 
additional information:
    (i) All information specified in Sec.  80.1450(b)(1)(ii)(B).
    (ii) [Reserved]
    (8) 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.
    (9) 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).
    (10) For biogas produced in a municipal wastewater treatment plant 
digester, all the following information:
    (i) 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 80728]]

    (ii) [Reserved]
    (11) 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).
    (12) For biogas produced in other waste digesters, all the 
following information:
    (i) A separated MSW plan specified in Sec.  80.1450(b)(1)(viii), as 
applicable.
    (ii) A separated yard waste plan specified in Sec.  
80.1450(b)(1)(vii)(A), as applicable.
    (iii) Crop residues information specified in Sec.  
80.1450(b)(1)(xv), as applicable.
    (iv) A separated food waste plan or biogenic waste oils/fats/
greases plan specified in Sec.  80.1450(b)(1)(vii)(B), as applicable.
    (v) If the waste digester simultaneously converts cellulosic and 
non-cellulosic feedstocks, registration information specified in Sec.  
80.1450(b)(1)(xiii)(C).
    (vi) 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).
    (d) Renewable electricity generator. In addition to the information 
required under paragraphs (b) and (i) of this section, a renewable 
electricity generator must submit all the following information for 
each renewable electricity generation facility:
    (1) All applicable company and facility information under 40 CFR 
1090.805.
    (2) A description whether the renewable electricity generation 
facility will be using biogas or RNG to generate renewable electricity 
and, if using biogas, a description of their relationship to each 
biogas producer.
    (3) Information to establish the renewable electricity generation 
facility's renewable electricity generation capacity, including all 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 
renewable electricity generation facility, if available.
    (ii) Documents demonstrating the renewable electricity generation 
facility's nameplate capacity.
    (iii) Information describing the renewable electricity generation 
facility's electricity production for each of the last three calendar 
years prior to the registration submission, if available.
    (iv) The construction date of the renewable electricity generation 
facility.
    (4) Information related to each the renewable electricity 
generation facility's design, as follows:
    (i) A diagram of the physical layout of the renewable electricity 
generation facility that identifies and assigns a unique identifier for 
each EGU and shows all connections to the biogas production facility 
and the conterminous electricity distribution system.
    (ii) A description of the type, rating, electricity production 
capacity, manufacturer, and electrical consumption capacity of each EGU 
at the renewable electricity generation facility.
    (iii) A description, including any applicable equations, that 
identifies the measurement locations on the diagram specified in 
paragraph (d)(4)(i) of the section and identifies other documentation 
that will be used to determine the volume, in kWh, and D code 
eligibility of renewable electricity.
    (iv) A demonstration that the renewable electricity generation 
facility has installed measurement capabilities that meet the 
requirements of Sec.  80.165(c), as applicable.
    (5) Identification of the RERG that the renewable electricity 
generator has a RIN generation agreement as specified in Sec.  80.135, 
if available.
    (6) The information specified in paragraph (i) of this section.
    (e) RERG. In addition to the information required under paragraph 
(b) of this section, a RERG must submit all the following information:
    (1) All applicable company information under 40 CFR 1090.805.
    (2) A description of the qualifying pathways.
    (3) A description of the RERG's fleet by make, model, model year, 
and trim, representing the fleet at the time of registration, including 
all the following information for each vehicle:
    (i) Whether the vehicle is an EV or PHEV.
    (ii) For PHEVs, the all-electric range of the vehicle, in miles, as 
determined under Sec.  80.135(c)(1)(i)(B)(1).
    (iii) The total number of vehicles registered in a state in the 
covered location (excluding Hawaii).
    (4) A description of the relationship to each renewable electricity 
generator from which the RERG has a RIN generation agreement under 
Sec.  80.135(a)(1).
    (f) RNG producer. In addition to the information required under 
paragraphs (b) and (i) of this section, an RNG producer must submit all 
the following information for each RNG production facility:
    (1) All applicable company and facility information under 40 CFR 
1090.805.
    (2) All applicable information in Sec.  80.1450(b)(5)(ii).
    (3) Annual volume totals of the RNG produced, in Btu, at the RNG 
production facility for each of the last three calendar years.
    (4) The natural gas commercial pipeline system name, location, and 
pipeline interconnect specifications into which the RNG will be 
injected.
    (5) Information related to biogas and RNG measurement, as follows:
    (i) A description of how biogas and RNG will be continuously 
measured.
    (ii) Metering type(s) and location(s) must be included as part of 
the process flow diagram submitted under Sec.  80.1450(b)(1)(i).
    (iii) If the RNG producer is unable to continuously measure biogas, 
the RNG producer may request the approval by EPA of an alternative 
sampling protocol as long as the RNG producer demonstrates that the 
alternative sampling protocol properly measures the heating value of 
the biogas or RNG, as applicable.
    (6) For RNG, information related to the RNG quality, including all 
the following:
    (i) 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).
    (ii) Documentation of any waiver provided by the natural gas 
commercial pipeline system for any parameter of the RNG that does not 
meet the pipeline specifications.
    (iii) A certificate of analysis from an independent laboratory for 
a representative sample of the raw biogas produced at the biogas 
production facility as specified in Sec.  80.165(b)(1).
    (iv) A certificate of analysis from an independent laboratory for a 
representative sample of the RNG as specified in Sec.  80.165(b)(1).
    (v) If the RNG is blended with non-renewable natural gas 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

[[Page 80729]]

blending with non-renewable natural gas as specified in Sec.  
80.165(b)(1).
    (vi) A summary table with the results of the certificates of 
analysis under paragraphs (f)(4)(iii) through (v) of this section and 
the pipeline specifications under paragraph (f)(4)(i) of this section 
converted to the same units.
    (vii) Certificates of analysis, including the major and minor gas 
components specified in Sec.  80.165(b)(1).
    (viii) EPA may approve an RNG producer's request of an alternative 
analysis in lieu of the certificates of analysis required under 
paragraphs (f)(4)(iii) through (v) 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 parameters required by the pipeline 
specification.
    (ix) A sampling protocol meeting the requirements in Sec.  
80.165(b)(1) that accurately represents the average composition of the 
biogas.
    (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 Sec.  80.140(b)(7).
    (9) For a foreign RNG producer, all the following additional 
information:
    (i) The applicable information specified in Sec.  80.170.
    (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.  80.170(e).
    (g) RNG RIN separator. In addition to the information required 
under paragraph (b) of this section, an RNG RIN separator must submit 
all the following information:
    (1) Information specified in 40 CFR 1090.805.
    (2) An initial 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.
    (3) Description of process and equipment used to compress RNG into 
renewable CNG/LNG.
    (h) Renewable fuel producer using biogas as a biointermediate or 
RNG as a feedstock. In addition to the information required under 
paragraph (b) of this section, a renewable fuel producer using biogas 
as a biointermediate or RNG as a feedstock must submit all the 
following:
    (1) All applicable information in Sec.  80.1450(b).
    (2) For biogas, documentation demonstrating a direct connection 
between the biogas producer and the renewable fuel production facility.
    (i) Emissions-related information. (1) The following parties must 
submit all the information specified in paragraph (i)(2) of this 
section for each pollutant specified in paragraph (i)(3) of this 
section, if available.
    (i) Biogas producers, for each landfill or digester at the biogas 
production facility.
    (ii) Renewable electricity generators, for each EGU at the 
renewable electricity generation facility.
    (iii) RNG producers, for each RNG production facility.
    (2)(i) The annual emission rate of each pollutant and a description 
of how the emission rate was measured or determined.
    (ii) The regulatory level (e.g., federal, state, local) and 
citation of the most stringent emission standard for each pollutant.
    (iii) The emission rate or emission reduction specified by the most 
stringent emission standard for each pollutant.
    (iv) Copies of National Pollutant Discharge Elimination System 
Forms 2A, 2B, and 2C.
    (3)(i) Air pollutants. (A) Carbon dioxide.
    (B) Carbon monoxide.
    (C) Methane.
    (D) Nitrous oxides.
    (E) PM2.5.
    (F) PM10.
    (G) Sulfur dioxide.
    (ii) Water pollutants. (A) Solid effluent.
    (B) Liquid effluent.
    (C) All pollutants that the party is required to monitor under any 
National Pollutant Discharge Elimination System permit.


Sec.  80.150  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).
    (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 designated use of the biogas (e.g., biointermediate, 
renewable electricity, renewable CNG/LNG, or RNG).
    (5) The volume of the batch supplied to the downstream party, in 
Btu and scf, as measured under Sec.  80.165(a).
    (6) The associated pathway information, including D code, 
production process, and feedstock information.
    (7) The EPA-issued company and facility IDs for the RNG producer, 
renewable electricity generator, biogas closed distribution system RIN 
generator, or renewable fuel producer that received the batch of the 
biogas.
    (c) Renewable electricity generators. A renewable electricity 
generator must submit monthly reports to EPA containing all the 
following information for each batch of renewable electricity:
    (1) Batch number.
    (2) Production date (end date of the calendar month).
    (3) Description of each batch or portion of a batch of biogas used 
to

[[Page 80730]]

produce the batch of renewable electricity batch, including all the 
following information:
    (i) The biogas batch number.
    (ii) The EPA-issued company and facility IDs for the biogas 
producer that produced the biogas.
    (iii) The volume of biogas used as feedstock, in Btu, as measured 
under Sec.  80.165(a).
    (iv) The associated D code of the biogas.
    (v) The verification status of the biogas.
    (vi) The date or period that the biogas was transferred.
    (4) Description of each batch or portion of a batch of RNG used to 
produce the batch of renewable electricity batch, including all the 
following information:
    (i) The RNG batch number.
    (ii) The EPA-issued company and facility IDs for the RNG producer 
that produced the RNG.
    (iii) The volume of natural gas used as feedstock, in Btu, as 
measured under Sec.  80.165(a).
    (iv) The number of RINs retired for the RNG under Sec.  80.140(e).
    (v) The associated D code of the RNG.
    (vi) The verification status of the RNG.
    (vii) The date or period that the RNG was transferred.
    (5) Total volume of electricity, in kWh, produced at the renewable 
electricity generation facility.
    (6) Total volume of electricity, in kWh, used by EGUs at the 
renewable electricity generation facility.
    (7) The EPA-issued company and facility IDs for each RERG that 
received the renewable electricity data representing the batch.
    (8) Total volume of renewable electricity, in kWh, described in the 
renewable electricity data transferred to each RERG.
    (d) RERGs. A RERG must submit quarterly reports to EPA containing 
all the following information:
    (1) Volume of renewable electricity, in kWh, used to generate RINs 
for renewable electricity, including all the following information:
    (i) The EPA-issued company and facility IDs for each renewable 
electricity generator and each renewable electricity generation 
facility.
    (ii) For each renewable electricity generation facility, the volume 
of renewable electricity, in kWh, used to generate RINs for renewable 
electricity by D code and verification status.
    (2) For quarterly RIN generation, a description of the RERG's fleet 
by make, model, model year, and trim, representing the fleet at the 
start of the quarter, including all the following information for each 
vehicle:
    (i) Whether each vehicle is an EV or PHEV.
    (ii) For PHEVs, the all-electric range of the vehicle, in miles, as 
determined under Sec.  80.135(c)(1)(i)(B)(1).
    (iii) The total number of vehicles registered in a state in the 
covered location (excluding Hawaii).
    (3) For future adjustment of the RIN generation parameters, a 
description of the RERG's fleet by make, model, model year, and trim, 
representing the fleet at the start of the quarter, including all the 
following information for each vehicle for which the OEM received 
vehicle telematic data during the quarter:
    (i) The total number of vehicles registered in a state in the 
covered location (excluding Hawaii).
    (ii) Vehicle fuel economy, in kWh per mile.
    (iii) Charging efficiency, as a percentage.
    (iv) One of the following:
    (A) eVMT, in average all-electric miles per vehicle.
    (B) Average quarterly charging information, in kWh.
    (4) All applicable information in Sec.  80.1451(b)(1)(ii), (2), and 
(3).
    (e) 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, produced and injected into the 
natural gas commercial pipeline system as measured under Sec.  80.165.
    (ii) [Reserved]
    (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 volume of the batch, in Btu and scf, as measured under 
Sec.  80.165(a).
    (v) The associated pathway information, including D code, 
production process, and feedstock information.
    (vi) The EPA-issued company and facility IDs for the RNG importer 
that will generate RINs for the batch.
    (f) Biogas closed distribution system RIN generators. A biogas 
closed distribution system RIN generator must submit quarterly reports 
to EPA containing all the following information:
    (1) The type and volume of biogas-derived renewable fuel, in Btu, 
produced from biogas.
    (2) The total volume of biogas, in Btu, used to produce the biogas-
derived renewable fuel as measured under Sec.  80.165.
    (3) The name(s) and location(s) of where the biogas-derived 
renewable fuel is used or sold for use as transportation fuel.
    (4) The volume of biogas-derived renewable fuel, in Btu, 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).
    (g) RNG RIN separators. An RNG RIN separator must submit quarterly 
reports to EPA containing all the following information:
    (1) Name and location of the natural gas commercial pipeline system 
where the RNG was withdrawn.
    (2) Volume of RNG, in Btu, withdrawn from the natural gas 
commercial pipeline system during the reporting period by location.
    (3) Volume of renewable CNG/LNG, in Btu, produced during the 
reporting period.
    (4) The locations where renewable CNG/LNG was dispensed as 
transportation fuel.
    (5) The volume of renewable CNG/LNG, in Btu, dispensed as 
transportation fuel at each location.
    (h) Retirement of RINs for RNG. A party that retires RINs for RNG 
used as a feedstock 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, 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 to produce renewable electricity or as a 
feedstock.
    (4) For each facility, the volume of renewable electricity, in kWh, 
or biogas-derived renewable fuel, in Btu, produced from the withdrawn 
RNG.
    (5) The number of RINs for RNG retired during the reporting period 
by D code and verification status.


Sec.  80.155  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 Sec. Sec.  80.150, 80.175, 80.1451, and 
80.1452 as follows:
    (A) Copies of all reports submitted to EPA.

[[Page 80731]]

    (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 
Sec. Sec.  80.145, 80.170, and 80.1450 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 Sec. Sec.  
80.160 and 80.1453.
    (iv) Subpart M records. Any applicable record required under Sec.  
80.1454.
    (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, testing, and measurement results relied upon 
under Sec.  80.165, including any results and maintenance 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 related to potentially 
invalid RINs under Sec.  80.195.
    (ix) Foreign parties. Any records related to foreign parties under 
Sec.  80.170.
    (2) Length of time records must be kept. The records required under 
this section and Sec.  80.160 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 renewable electricity 
generator, RNG producer, or renewable fuel producer.
    (2) Documents supporting the volume of biogas, in Btu and scf, 
produced for each batch.
    (3) Documents supporting the composition and cleanup of biogas 
produced for each batch.
    (4) Documentation supporting the use of each process heat source 
and supporting the amount of each source used in the production process 
for each batch.
    (5) In addition to any applicable recordkeeping requirement for the 
use of renewable biomass to produce biogas under Sec.  80.1454, 
information and documentation showing that the biogas came from 
renewable biomass.
    (i) For agricultural digesters, a quarterly affidavit signed by the 
RCO or 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.
    (ii) For municipal wastewater treatment 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.
    (iii) For biogas produced from separated yard waste, separated food 
waste, or biogenic waste oils/fats/greases, documents required under 
Sec.  80.1454(j)(1).
    (iv) For biogas produced from separated municipal solid waste, 
documents required under Sec.  80.1454(j)(2).
    (6) For biogas produced in digesters simultaneously converting 
cellulosic and non-cellulosic feedstock, all the following:
    (i) Documents for each delivery of feedstock to the biogas 
production facility, demonstrating the mass of each feedstock 
delivered, type of feedstock delivered, and name of feedstock supplier.
    (ii) Process operational data for the types of data specified at 
registration under Sec.  80.1450(b)(1)(xiii)(C)(4) or (5), as 
applicable.
    (iii) Documents for each batch demonstrating volatile solids and 
total solids measurements of feedstocks.
    (7) Copies of all records and notifications related to the 
identification of potentially inaccurate or non-qualifying biogas 
volumes under Sec.  80.195(b).
    (c) Renewable electricity generators. In addition to the records 
required under paragraph (a) of this section, a renewable electricity 
generator must keep all the following records:
    (1) Contracts, PTDs, affidavits required under this part, and all 
other commercial documents with any biogas producer, RNG producer, RIN 
owner, or RERG, as applicable.
    (2) Documents supporting the volume of biogas or natural gas 
(including both RNG and non-renewable natural gas), in Btu and scf, 
used to produce electricity in monthly increments received from any 
source.
    (3) Documents supporting the monthly volume of electricity, in kWh, 
produced from biogas or natural gas (including both RNG and non-
renewable natural gas).
    (4) Documents supporting the process heat source for production 
process and the amount of each source used in the production process in 
a given month.
    (5) Records related to continuous measurement, including types of 
equipment used, metering process, maintenance and calibration records, 
and documents supporting adjustments related to error correction.
    (6) Documents supporting the volume of electricity, in kWh, used by 
EGUs at the renewable electricity generation facility.
    (7) Documents supporting RIN retirements for RNG used to produce 
renewable electricity.
    (8) Information and documents supporting that the renewable 
electricity was produced from biogas or RNG.
    (9) Information and documents related to participation in any QAP 
program, including contracts between the renewable electricity 
generator and the QAP provider, records related to verification 
activities under the QAP, and copies of any QAP-related submissions.
    (10) Copies of any applicable air permits over the past 5 years 
issued by EPA, a state, a local air pollution control agency, or a 
foreign governmental agency that governs the renewable electricity 
generation facility.
    (d) RERGs. In addition to the records required under paragraph (a) 
of this section, a RERG 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 the renewable 
electricity.
    (iv) Documents demonstrating the make, model, model year, and trim 
of all

[[Page 80732]]

vehicles in the RERG's fleet included in RIN generation under Sec.  
80.135.
    (v) Documentation of any calculation relied upon for RIN 
generation.
    (vi) Documentation describing how the RERG allocated renewable 
electricity used to generate RINs by facility, D code, and verification 
status.
    (vii) Contracts, PTDs, affidavits, agreements required under this 
part, and all other commercial documents with any renewable electricity 
generator.
    (viii) Copies of renewable electricity data received from any 
renewable electricity generator.
    (2) All documents specified in Sec.  80.1454(b), as applicable.
    (3) Information and documentation related to participation in any 
QAP program, including contracts between the RERG and the QAP provider, 
records related to verification activities under the QAP, and copies of 
any QAP-related submissions.
    (4) All documents supporting the values used in the calculations in 
Sec.  80.135(c)(1)(i).
    (e) 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 raw biogas, in Btu and scf, respectively, received at 
each RNG production facility.
    (vi) Volume of RNG, in Btu and scf, produced at each RNG production 
facility.
    (vii) Pipeline injection statements describing the volume of RNG, 
in Btu and scf, 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) Process heat source for production process.
    (7) Records related to continuous measurement, including types of 
equipment used, metering process, maintenance and calibration records, 
and documents supporting adjustments related to error correction.
    (8) 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.
    (9) 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 Sec.  
80.140(b)(7).
    (10) Summaries comparing raw biogas to treated biogas, including 
from certificates of analysis from independent laboratories and from 
meters on site.
    (11) Documents supporting the amount of methane and other gases 
released into the atmosphere at the facility.
    (f) 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.
    (g) 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, withdrawn 
from the natural gas commercial distribution system.
    (2) Documentation demonstrating that RNG withdrawn from the natural 
gas commercial distribution system was used to produce renewable CNG/
LNG.
    (3) Documentation indicating the volume of renewable CNG/LNG, in 
Btu, dispensed as transportation fuel from each dispensing location.
    (4) Copies of all documentation required under Sec.  
80.140(d)(1)(iv), as applicable.
    (h) 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) Documentation supporting the volume of biogas, in Btu and scf, 
that was used as a biointermediate from each biointermediate production 
facility.
    (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, withdrawn 
from the natural gas commercial distribution system.
    (ii) Documentation supporting the retirement of RINs for RNG used 
as a feedstock (e.g., contracts, purchase orders, invoices).
    (j) RNG importers and non-RIN generating foreign RNG producers. In 
addition to the records required under paragraph (a) of this section, 
an RNG importer or non-RIN generating foreign RNG producer must keep 
all the following records:
    (1) Copies of all reports submitted under Sec.  80.170(i)(2).
    (2) [Reserved]


Sec.  80.160  Product transfer documents.

    (a) General requirements--(1) PTD contents. On each occasion when 
any person transfers title of any biogas, renewable electricity data, 
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 for biogas and RNG and kWh for renewable 
electricity data) 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

[[Page 80733]]

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 as renewable electricity, ``This 
volume of biogas is designated and intended for use to produce 
renewable electricity.''
    (ii) 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.''
    (iii) For biogas designated for use to produce RNG, ``This volume 
of biogas is designated and intended for use to produce renewable 
natural gas.''
    (iv) For biogas designated for use as a biointermediate, the 
applicable language found at Sec.  80.1453(f)(1)(vi).
    (v) For biogas designated for use as process heat under Sec.  
80.1426(f)(12), ``This volume of biogas is designated and intended for 
use as process heat.''
    (c) PTD requirements for custodial transfers of RNG. Whenever 
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)(1) 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. Whenever custody 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)(1) 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.  80.170(e).
    (4) The name, EPA-issued company and facility IDs, and address of 
the transferee.


Sec.  80.165  Sampling, testing, and measurement.

    (a) Biogas and RNG continuous measurement. Any party required to 
continuously measure the volume of biogas or RNG under this subpart 
must use all the following:
    (1) In-line GC meters compliant with ASTM D7164 (incorporated by 
reference, see Sec.  80.3), 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.  80.3).
    (ii) API MPMS 14.12 (incorporated by reference, see Sec.  80.3).
    (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.  80.3).
    (2) Perform all the following measurements on each representative 
sample:
    (i) Methane, carbon dioxide, nitrogen, and oxygen using EPA Method 
3C.
    (ii) Hydrogen sulfide and total sulfur using ASTM D5504 
(incorporated by reference, see Sec.  80.3).
    (iii) Siloxanes using ASTM D8230 (incorporated by reference, see 
Sec.  80.3).
    (iv) Moisture using ASTM D4888 (incorporated by reference, see 
Sec.  80.3).
    (v) Hydrocarbon analysis using EPA Method 18.
    (vi) Heating value and relative density using ASTM D3588 
(incorporated by reference, see Sec.  80.3).
    (vii) Additional components specified in pipeline specifications or 
specified by EPA as a condition of registration under Sec.  80.145 or 
Sec.  80.1450.
    (viii) Carbon-14 analysis using ASTM D6866 (incorporated by 
reference, see Sec.  80.3).
    (c) Renewable electricity. Any party required to continuously 
measure the volume of renewable electricity under this subpart must use 
ANSI C12.20 (incorporated by reference, see Sec.  80.3).
    (d) Digester feedstock. Any party required to measure total solids 
and volatile solids of a digester feedstock under this subpart must use 
Part G of SM 2540 (incorporated by reference, see Sec.  80.3).
    (e) Third parties. Samples required to be obtained under this 
subpart may be collected and analyzed by third parties.


Sec.  80.170  RNG importers and foreign biogas producers, RNG 
producers, renewable electricity generators, and RERGs.

    (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 Sec.  80.170(b)(4) and (c) as part of their registration 
under Sec.  80.145.
    (2) Bond posting. A foreign party that generates RINs must meet the 
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.  80.140.
    (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.

[[Page 80734]]

    (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.  80.155.
    (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 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.
    (g) 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 (c)(1) 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.
    (h) 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 80.170, 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.''
    (i) 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, injected into the natural 
gas commercial pipeline system as specified in Sec.  80.165.
    (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

[[Page 80735]]

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 (h) of this section.
    (ii) The name of the foreign non-RIN generating RNG producer, 
containing the information specified in paragraph (h) 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, 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 (i)(1) and 
(2) of this section for five years from the date of creation.


Sec.  80.175  Attest engagements.

    (a) General provisions. (1) The following parties must arrange for 
annual attestation engagement using agreed-upon procedures:
    (i) Biogas producers.
    (ii) Renewable electricity generators.
    (iii) RERGs.
    (iv) RNG producers.
    (v) RNG importers.
    (vi) Biogas closed distribution system RIN generators.
    (vii) RNG RIN separators.
    (viii) 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, renewable 
electricity generation 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 the biogas producer's registration information 
submitted under Sec. Sec.  80.145 and 80.1450 and all reports submitted 
under Sec. Sec.  80.150 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) Report the date of the last engineering review conducted 
under Sec. Sec.  80.145(b)(3) and 80.1450(b), as applicable. 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.  80.150 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 as follows:
    (i) Obtain records related to measurement under Sec.  
80.155(a)(1)(vi).
    (ii) Identify and report the name of the method(s) used for 
measuring the volume of biogas, in Btu and in scf, and report as a 
finding any method that is not specified in Sec.  80.165 or the biogas 
producer's registration.
    (iii) Identify whether maintenance and calibration records were 
kept and report as a finding if no records were obtained.
    (3) Listing of batches. The auditor must review listings of batches 
as follows:
    (i) Obtain the batch reports submitted under Sec.  80.150.
    (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 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.  80.160 and report as a 
finding any exceptions.
    (c) General procedures for renewable electricity generators. An 
attest auditor must conduct annual attestation audits for renewable 
electricity generators using the following procedures:
    (1) Registration and EPA reports. The auditor must review 
registration and EPA reports as follows:
    (i) Obtain copies of the renewable electricity generator's 
registration information submitted under Sec.  80.145 and all reports 
submitted under Sec.  80.150.
    (ii) For each renewable electricity generation 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) Report the date of the last engineering review conducted 
under Sec.  80.145(b)(3). 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 renewable electricity generator submitted all 
reports required under Sec.  80.150 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 or RNG received as follows:
    (i) Obtain copies of records documenting the source and volume of 
biogas or RNG, in Btu and scf, received by the renewable electricity 
generator. Report the number of parties the renewable electricity 
generator received biogas or RNG from and the total volume of biogas or 
RNG, in Btu and scf, received separately from each party.
    (ii) Obtain copies of records showing the volume of biogas or RNG, 
in Btu and scf, used to produce renewable electricity. Report as a 
finding the total volume of biogas or RNG, in Btu and scf, used to 
produce renewable electricity.
    (iii) Obtain copies of records showing whether non-renewable 
feedstocks were used to produce renewable electricity. Report as a 
finding if any RINs were generated for electricity produced from the 
non-renewable feedstocks.
    (3) Measurement method review. The auditor must review measurement 
methods as follows:
    (i) Obtain records related to measurement under Sec.  
80.155(a)(1)(vi).
    (ii) Identify and report the name of the method(s) used for 
measuring the volume of renewable electricity, in kWh, and report as a 
finding any method that is not specified in Sec.  80.165 or the 
renewable electricity generator's registration.
    (iii) Identify whether maintenance and calibration records were 
kept and report as a finding if no records were obtained.

[[Page 80736]]

    (4) Listing of batches. The auditor must review listings of batches 
as follows:
    (i) Obtain the batch reports submitted under Sec.  80.150.
    (ii) Compare the reported volume for each batch to the measured 
volume and report as a finding any exceptions.
    (5) Testing of renewable electricity data transfers. The auditor 
must review renewable electricity data transfers as follows:
    (i) Obtain the associated PTD for each batch of renewable 
electricity 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 kWh, 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.  80.160 and report as a 
finding any exceptions.
    (5) Renewable electricity batches from RNG. If RNG was used to 
produce renewable electricity, the auditor must review renewable 
electricity batches as follows:
    (i) Obtain copies of records demonstrating the number and types of 
RINs retired for RNG under Sec.  80.140(e).
    (ii) Verify that the proper volume of renewable electricity was 
produced under Sec.  80.110(k)(3) for each batch as follows:
    (A) Calculate the total volume of renewable electricity the 
renewable electricity generator is eligible to produce for the month 
using the equations in Sec.  80.110(k)(3). Compare this value to the 
batch report and report as a finding any difference.
    (B) Calculate the maximum volume of renewable electricity the 
renewable electricity generator is eligible to produce for the month 
using the equations in Sec.  80.110(k)(3). Compare this value to the 
batch report and report as a finding if the maximum volume of renewable 
electricity was less than the volume of renewable electricity produced.
    (d) General procedures for RERGs. An attest auditor must conduct 
annual attestation audits for RERGs using the following procedures:
    (1) Registration and EPA reports. The auditor must review 
registration and EPA reports as follows:
    (i) Obtain copies of the RERG's registration information submitted 
under Sec.  80.145 and all reports submitted under Sec.  80.150.
    (ii) Confirm that the RERG'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 RERG submitted all reports required under 
Sec. Sec.  80.150 and 80.1451 for activities performed during the 
compliance period and report as a finding any exceptions.
    (2) Renewable electricity RIN generation. The auditor must perform 
the following procedures for quarterly RIN generation:
    (i) Obtain copies of all the following:
    (A) PTDs containing the renewable electricity data provided to the 
RERG under Sec.  80.160(a)(1)(iii).
    (B) Records used to calculate the RERG's fleet under Sec. Sec.  
80.150(d)(2)(i) and (iii).
    (C) Records used to calculate the electric range of PHEVs by make, 
model, model year, and trim under Sec.  80.150(d)(2)(ii).
    (D) RIN generation information submitted under Sec.  80.1452.
    (ii) Using the values obtained in paragraph (d)(2)(i) of this 
section, verify that the proper number of RINs were generated under 
Sec.  80.135 for each batch as follows:
    (A) Calculate the total number of RINs the RERG is eligible to 
generate for the quarter using the equations in Sec.  80.135(c)(1). 
Compare this value to the number of RINs the RERG generated for the 
quarter and report as a finding any difference.
    (B) Calculate the maximum number of RINs the RERG is eligible to 
generate for the quarter using the equations in Sec.  80.135(c)(2). 
Compare this value to the number of RINs the RERG generated for the 
quarter and report as a finding if the maximum number of RINs was less 
than the number of RINs generated.
    (e) 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 the RNG producer or importer's registration 
information submitted under Sec. Sec.  80.145 and 80.1450 and all 
reports submitted under Sec. Sec.  80.150 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) Report the date of the last engineering review conducted 
under Sec. Sec.  80.145(b)(3) and 80.1450(b), as applicable. 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.  80.150 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 records documenting the source and volume of 
biogas, in Btu and scf, received by the RNG producer. Report the number 
of parties the RNG producer received biogas from and the total volume 
received separately from each party.
    (ii) Obtain copies of records showing the volume of biogas, in Btu 
and scf, used to produce RNG. Report the total volume of biogas used to 
produce RNG, in Btu and scf, and report as a finding if the volume of 
RNG is greater than the volume of biogas.
    (iii) Obtain copies of records showing whether non-renewable 
components were blended into RNG. 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 as follows:
    (i) Obtain records related to measurement under Sec.  
80.155(a)(1)(vi).
    (ii) Identify and report the name of the method(s) used for 
measuring the volume of RNG, in Btu and in scf, and report as a finding 
any method that is not specified in Sec.  80.165 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.  80.150.
    (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 pipeline specifications.
    (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

[[Page 80737]]

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.  80.160 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.
    (f) 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 the biogas closed distribution system RIN 
generator's registration information submitted under Sec.  80.145 and 
all reports submitted under Sec.  80.150.
    (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.  80.150 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.
    (g) 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 the RNG RIN separator's registration 
information submitted under Sec. Sec.  80.145 and 80.1450 and all 
reports submitted under Sec. Sec.  80.150 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.  80.150 and 80.1451 for activities performed 
during the 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 records required under Sec.  80.155(g).
    (ii) Compare the volume of RNG, in Btu, withdrawn from the natural 
gas commercial distribution system to the reported volume of RNG, in 
Btu, used to produce the renewable CNG/LNG.
    (iii) Compare the volume of CNG/LNG sold or used as transportation 
fuel to the reported volume of CNG/LNG separated from RINs.
    (iv) Report as a finding if the volume of CNG/LNG sold or used as 
transportation fuel does not match the volume of CNG/LNG separated from 
RINs.
    (3) RIN owner. The auditor must complete all requirements specified 
in Sec.  80.1464(c).
    (h) 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 the renewable fuel producer's registration 
information submitted under Sec.  80.145 and all reports submitted 
under Sec.  80.150.
    (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.  80.150 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.  80.150(h) and 
80.1452.
    (B) Records related to measurement under Sec.  80.155(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.  80.180  Quality assurance program.

    (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 electricity produced in a biogas closed 
distribution system, the biogas producer, the renewable electricity 
generator, and the RERG.
    (iii) For renewable electricity produced from RNG, the renewable 
electricity generator and the RERG.
    (iv) For renewable CNG/LNG produced from RNG, the biogas producer 
and the RNG producer.
    (v) 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.
    (vi) 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.
    (vii) 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) and (g) through (h).
    (3) QAPs approved by EPA to verify RINs generated under this 
subpart must meet the requirements in Sec.  80.1469(c) through (f), as 
applicable.
    (4) Independent third-party auditors must conduct quality assurance 
audits at biogas production facilities, RNG production facilities, 
renewable electricity generation facilities, renewable fuel production 
facilities, and

[[Page 80738]]

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(a) and (b)(3), as applicable.
    (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 producers. In addition to the elements 
verified under Sec.  80.1469(c) through (f), the independent third-
party auditor must do all the following at each biogas production 
facility:
    (1) Verify that the measurement of biogas is consistent with the 
requirements in Sec.  80.165.
    (2) Verify that the PTDs for biogas transfers are consistent with 
the applicable PTD requirements in Sec. Sec.  80.160 and 80.1453.
    (c) Requirements for RNG producers. In addition to the elements 
verified under Sec.  80.1469(c) through (f), the independent third-
party auditor must do all the following at each RNG production 
facility:
    (1) Verify that the sampling, testing, and measurement of RNG is 
consistent with the requirements in Sec.  80.165.
    (2) Verify that RINs were assigned consistent with Sec.  80.140(c).
    (3) Verify that RINs were separated and retired consistent with 
Sec.  80.140(d) and (e), respectively.
    (4) Verify that the RNG was injected into a natural gas commercial 
pipeline system.
    (5) 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 electricity generators. In addition 
to the elements verified under Sec.  80.1469(c) through (f), the 
independent third-party auditor must do all the following at each 
renewable electricity generation facility:
    (1) Verify that the measurement of renewable electricity is 
consistent with the requirements in Sec.  80.165(c).
    (2) Verify that RIN generation agreement is contracted consistent 
with the requirements in Sec.  80.135(a)(1).
    (3) Verify that the renewable electricity was only produced from 
biogas or RNG consistent with an approved pathway.
    (4) Verify that the renewable electricity data is consistent with 
the volume specified on the PTD to the RERG under Sec.  80.160(c).
    (5) Verify that the renewable electricity generator retired RINs 
for RNG used to produce renewable electricity consistent with Sec.  
80.140(e).
    (e) Requirements for RERGs. The independent third-party auditor 
must verify that each input in the equations in Sec.  80.135 is 
properly calculated.
    (f) Requirements for renewable fuel producers using biogas as a 
biointermediate. The independent third-party auditor must meet all 
requirements specified in paragraph (b) of this section and Sec.  
80.1477.
    (g) 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.  80.185  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.
    (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 (5) of this 
section is liable for any violation of any prohibition under 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.  80.190.
    (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 or RNG 
produced from the biogas to produce a biointermediate.
    (iv) Any person that used the biogas, RNG produced from the biogas, 
or biointermediate produced from the biogas or RNG 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.
    (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 biointermediate producer that used the RNG to produce a 
biointermediate.
    (iv) Any person that used the RNG or biointermediate produced from 
the RNG to produce a biogas-derived renewable fuel.
    (v) Any person that generated a RIN from a biogas-derived renewable 
fuel produced from the RNG or biointermediate produced from the RNG.
    (4) Renewable electricity liability. When renewable electricity 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) Any biogas producer that produced the biogas used to generate 
the renewable electricity.
    (ii) Any RNG producer that produced RNG used to produce renewable 
electricity.
    (iii) The renewable electricity generator that generated the 
renewable electricity.
    (iv) Any RERG that generated a RIN from the renewable electricity.
    (5) RINs generated for renewable electricity liability. When RINs 
generated for renewable electricity are 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) Any biogas producer that produced the biogas used to generate 
the renewable electricity for which the RINs were generated.
    (ii) Any RNG producer that produced RNG used to produce renewable

[[Page 80739]]

electricity for which the RINs were generated.
    (iii) Any renewable electricity generator that generated the 
renewable electricity for which the RINs were generated.
    (iv) The RERG that generated the RIN.
    (6) Third-party liability. Any party allowed under Sec.  80.165(e) 
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.  80.190  Affirmative defense provisions.

    (a) Applicability. A person may establish an affirmative defense to 
a violation that person is liable for under Sec.  80.185(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.  80.185(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.  80.185(b)(1) and (3).
    (4) A person that is a renewable electricity generator may not 
establish an affirmative defense under this section for a violation 
that the renewable electricity generator is liable for under Sec.  
80.185(b)(1) and (4).
    (b) General elements. A person may only establish an affirmative 
defense under this section if the person meets all of 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, 
RNG, renewable electricity, or RINs were 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 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 QAP 
that includes, at a minimum, a periodic sampling and testing 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.  80.180 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 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 QAP 
that includes, at a minimum, a periodic sampling and testing 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.  80.180 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.
    (e) Renewable electricity generator elements. In addition to the 
elements in paragraph (b) of this section, a renewable electricity 
generator must also meet all the following requirements to establish an 
affirmative defense:
    (1) The renewable electricity generator conducted or arranged to be 
conducted a QAP that includes, at a minimum, a periodic sampling and 
testing program adequately designed to ensure that the biogas or RNG 
used to generate their renewable electricity meets the applicable 
requirements to produce biogas or RNG under this part.
    (2) The renewable electricity generator only generated renewable 
electricity from biogas or RNG verified by a third-party auditor under 
an approved QAP under Sec. Sec.  80.180 and 80.1469.
    (3) The PTDs for the biogas or RNG used to produce their renewable 
electricity indicate that the biogas or RNG was in compliance with the 
applicable requirements.


Sec.  80.195  Potentially invalid RINs.

    (a) Identification and treatment of potentially invalid RINs 
(PIRs). (1) Any RIN can be identified as a PIR by the RIN generator, an 
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), as 
applicable.
    (b) Potentially inaccurate or non-qualifying volumes of biogas-
derived renewable fuel. (1) Any party that becomes aware of potentially 
inaccurate or non-qualifying volumes of biogas-derived renewable fuel 
must notify the next party in the production chain within 5 business 
days.
    (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.  80.180, the party must notify the independent third-party 
auditor within 5 business days.
    (iii) Non-RIN generating foreign RNG producers must follow 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 inaccurate or non-qualifying 
volumes of biogas-derived renewable fuel under paragraph (b)(1) of this 
section must correct affected volumes of biogas-derived renewable fuel 
under paragraph (a)(2) of this section, as applicable.
    (3) Any notified party that generates RINs 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), as applicable.
    (c) Potentially inaccurate volumes of renewable electricity. (1) 
When a renewable electricity generator becomes aware of inaccurate 
quantities of renewable electricity produced and transferred to the 
RERG, the renewable electricity generator must notify EPA and the RERG 
within 5 business days of initial discovery.

[[Page 80740]]

    (2) The RERG must then calculate any impacts to the number of RINs 
generated for the volume of impacted renewable electricity. The RERG 
must then notify EPA and the independent third-party auditor, if any, 
within 5 business days of initial notification.
    (3) For any number of RINs over-generated based off the inaccurate 
volumes of renewable electricity, the RERG must retire these RINs or 
replacement RINs as specified in Sec.  80.1434(a)(9).
    (d) Potential double counting of volumes of biogas or RNG. (1) When 
a renewable electricity generator, RERG, or any other party becomes 
aware of a biogas or RNG producer taking credit for the same volume of 
biogas or RNG sold to multiple renewable electricity generators, or of 
a renewable electricity generator taking credit for the same volume of 
renewable electricity sold to multiple RERGs, they must notify EPA 
within 5 business days of initial discovery.
    (2) The RERG must then calculate any impacts to the number of RINs 
generated for the volume of impacted renewable electricity. The RERG 
must then notify EPA and the independent third-party auditor, if any, 
within 5 business days of initial notification.
    (3) For any number of RINs over-generated based off the double 
counting of volumes of biogas or RNG, the RERG must retire these RINs 
or replacement RINs as specified in Sec.  80.1434(a)(9).
    (e) Failure to take corrective action. Any person who fails to meet 
a requirement under paragraphs (b), (c), or (d) 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.
    (f) 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.
    (g) 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
9. Revise Sec.  80.1402 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
10. Amend Sec.  80.1402 by, in paragraph (f), removing the text 
``notwithstanding'' and adding, in its place, the text ``regardless 
of''.
0
11. 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
2022............................            0.35            2.33            3.16           11.59            0.14
2023............................            0.41            2.54            3.33           11.92            0.14
2024............................            0.82            2.60            3.80           12.55             n/a
2025............................            1.23            2.67            4.28           13.05             n/a
----------------------------------------------------------------------------------------------------------------

* * * * *
    (c) EPA will calculate the annual renewable fuel percentage 
standards using the following equations:

[[Page 80741]]

[GRAPHIC] [TIFF OMITTED] TP30DE22.017

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
12. 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
13. 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
14. Amend Sec.  80.1415 by:
0
a. In paragraph (b)(2), removing the text ``(mono-alkyl ester)'';
0
b. Revising paragraphs (b)(5) through (7);
0
c. In paragraph (c)(1), revising the definition of ``R'';
0
d. In paragraph (c)(2)(ii), removing the text ``derived'' and adding, 
in its place, the text ``produced''; and
0
e. In paragraph (c)(5), removing the text ``the Administrator'' and 
adding, in its place, the text ``EPA''.
    The revision reads as follows:


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

* * * * *
    (b) * * *
    (5) 77,000 Btu (lower heating value) of renewable CNG/LNG or RNG 
shall represent one gallon of renewable fuel with an equivalence value 
of 1.0.
    (6)(i) For renewable electricity produced from biogas or RNG, 6.5 
kW-hr of electricity shall represent one gallon of renewable fuel with 
an equivalence value of 1.0.
    (ii) For renewable electricity produced from renewable biomass 
other than biogas or RNG, 22.6 kW-hr of electricity 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. Except for renewable 
electricity, a producer or importer may also submit an application for 
an alternative equivalence value pursuant to paragraph (c) of this 
section if the renewable fuel is listed in this paragraph (b), but the 
producer or importer has reason to believe that a different equivalence 
value than that listed in this paragraph (b) is warranted.
    (c) * * *
    (1) * * *

R = Renewable content of the renewable fuel. This is a measure of 
the portion of a renewable fuel that came from renewable biomass, 
expressed as a fraction, on an energy basis. For co-processed fuel, 
R is equal to 1.0.
* * * * *


Sec.  80.1416  [Amended]

0
15. 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

[[Page 80742]]

0
c. In paragraph (d), removing the text ``The Administrator'' and 
adding, in its place, the text ``EPA''.
0
16. 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 (a)(4), (b)(1), and (c)(1) and (2);
0
d. Removing and reserving paragraph (c)(3);
0
e. In paragraph (c)(7), removing the text ``Sec.  80.1401'' and adding, 
in its place, the text ``Sec.  80.2'';
0
f. Adding a sentence to the end of paragraph (d)(1) introductory text;
0
g. Revising paragraphs (e)(1) and (f)(1)(i);
0
h. 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
i. 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
j. 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
k. Revising paragraph (f)(3)(v);
0
l. Removing Table 3 to Sec.  80.1426 immediately following paragraph 
(f)(3)(v);
0
m. Revising paragraph (f)(3)(vi);
0
n. Removing Table 4 to Sec.  80.1426 immediately following paragraph 
(f)(3)(vi)(A);
0
o. Revising paragraph (f)(4);
0
p. In paragraph (f)(5)(v), removing the text ``biogas-derived fuels'' 
and adding, in its place, the text ``biogas-derived renewable fuel'';
0
q. 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
r. Revising paragraphs (f)(6) introductory text and (f)(7)(i), 
(f)(7)(v)(A) and (B);
0
s. In paragraph (f)(8)(ii) introductory text, removing the text 
``(mono-alkyl esters)'';
0
t. Revising paragraphs (f)(8)(ii)(B), (f)(9)(i) and (ii), (f)(10) 
through (13), (f)(15), (f)(17), and (g)(1)(i) introductory text;
0
u. 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
v. Revising paragraph (g)(2) introductory text; and
0
w. 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 of the following 
occur:
* * * * *
    (4) For co-processed fuel, RINs may only be generated for the 
portion of fuel that is produced from renewable biomass, as calculated 
under paragraph (f)(4) of this section.
    (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.
* * * * *
    (d) * * *
    (1) * * * Biogas producers, RNG producers, and RERGs must use the 
definition of batch for biogas, RNG, and renewable electricity in 
Sec. Sec.  80.105(j), 80.120(j), and 80.110(k), 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 = EVDX * 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.
EVDX = 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] TP30DE22.018

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.
EV = 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 = Sum of feedstock energies from all feedstocks 
whose pathways have been assigned a D code of X, in Btu, per 
paragraphs (f)(3)(vi)(B) through (D) of this section.
FEtotal = Sum of feedstock energies from all feedstocks, 
in Btu, per paragraphs (f)(3)(vi)(B) through (D) 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.
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.

[[Page 80743]]

CFi = Converted fraction in annual average Btu/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 from advanced 
feedstocks, the feedstock energy value for advanced feedstocks must be 
calculated as follows:

FED5 = FEBG-FED3/7

Where:

FED5 = Sum of feedstock energies from all feedstocks 
whose pathways have been assigned a D code of 5, in Btu. If the 
result of this equation is negative, then FE5 equals 0.
FEBG = Biogas energy in higher heating value produced by 
the digester, in Btu, as measured under Sec.  80.165(a).
FED3/7 = Sum of feedstock energies from all feedstocks 
whose pathways have been assigned a D code of 3 or 7, in Btu, per 
paragraph (f)(3)(vi)(D) of this section.

    (D) For biogas produced from anaerobic digestion from cellulosic 
feedstocks, the feedstock energy value for each cellulosic feedstock 
must be calculated as follows:

FED3/7,i = Mi * TSi * VSi * 
CFi

Where:

FED3/7,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 3 or 7, in Btu.
Mi = Mass of feedstock i, in pounds, measured on a daily 
or per-batch basis.
TSi = Total solids of feedstock i, as a mass fraction, in 
pounds total solids per pound feedstock, per Sec.  80.165(d), 
measured on a daily or per-batch basis.
VSi = Volatile solids of feedstock i, as a mass fraction, 
in pounds volatile solids per pound total solids, per Sec.  
80.165(d), measured on a daily or per-batch basis.
CFi = Converted fraction in annual average Btu/lb, 
representing the portion of feedstock i that is converted to 
biomethane from the cellulosic feedstock by the producer. If the 
anaerobic digester was operated outside of the applicable operating 
conditions specified in Sec.  80.1450(b)(1)(xiii)(C)(4) or (5), 
CFi for that batch equals 0.

    (4) Co-processed fuel and intermediate. (i) For a batch of co-
processed fuel (excluding biodiesel, RNG, and renewable electricity), 
the RIN generator must determine the number of gallon-RINs (i.e., 
VRIN) that may be generated using one of the following 
approaches:
    (A) Approach A. (1) This approach must only be used for a process 
that meets all the following requirements:
    (i) The renewable fuel is produced under approved pathways with a 
single D code.
    (ii) The fraction of carbon in the co-processed fuel that 
originates from renewable biomass does not exceed the fraction of 
chemical energy in the co-processed fuel that originates from renewable 
biomass.
    (2) VRIN must be calculated as follows:

VRIN = EqV * Vf * R

Where:

VRIN = RIN volume, in gallons, for use in determining the 
number of gallon-RINs generated for the batch of renewable fuel.
EqV = Equivalence value of the renewable fuel, per Sec.  80.1415.
Vf = Standardized volume of the batch of co-processed 
fuel at 60 [deg]F, in gallons, per paragraph (f)(8) of this section.
R = The renewable fraction of the co-processed fuel as measured by a 
carbon-14 dating test method, per paragraph (f)(9) of this section.

    (B) Approach B. (1) This approach must only be used for a process 
that meets all the following requirements:
    (i) The process does not meet the requirements of Approach A in 
paragraph (f)(4)(i)(A) of this section.
    (ii) Neither heat nor electricity is converted to chemical energy 
in the co-processed fuel.
    (iii) The fraction of chemical energy in the co-processed fuel that 
comes from renewable biomass is equal to or greater than the fraction 
of chemical energy in the feedstocks that comes from renewable biomass.
    (iv) If the renewable fuel produced is eligible to generate both 
D3/D7 RINs and D4/D5/D6 RINs, the fraction of chemical energy in the 
co-processed fuel eligible to generate D3/D7 RINs that comes from 
renewable biomass is equal to or greater than the fraction of chemical 
energy in the feedstocks qualified to be used to produce renewable fuel 
eligible to generate D3/D7 RINs that comes from renewable biomass.
    (v) If the renewable fuel produced is eligible to generate both D4/
D5 RINs and D6 RINs, the fraction of chemical energy in the co-
processed fuel eligible to generate D4/D5 RINs that comes from 
renewable biomass is equal to or greater than the fraction of chemical 
energy in the feedstocks qualified to be used to produce renewable fuel 
eligible to generate D4/D5 RINs that comes from renewable biomass.
    (2) VRIN must be calculated as follows:

VRIN,DX = EqV * Vf * FER,DX/
(FER + FENR)

Where:

VRIN,DX = RIN volume, in gallons, for use in determining 
the number of gallon-RINs generated for the batch of renewable fuel 
with D code of X.
EqV = Equivalence value of the renewable fuel, per Sec.  80.1415.
Vf = Standardized volume of the batch of co-processed 
fuel at 60 [deg]F, in gallons, per paragraph (f)(8) of this section.
FER,DX = Sum of feedstock energies from renewable biomass 
(including the renewable portion of a biointermediate) used to make 
the co-processed fuel that qualify be used to produce renewable fuel 
with D code of X, in Btu, per paragraph (f)(4)(i)(B)(3) of this 
section.
FER = Sum of feedstock energies from all renewable 
biomass (including the renewable portion of a biointermediate) used 
to make the co-processed fuel, in Btu, per paragraph (f)(4)(i)(B)(3) 
of this section.
FENR = Sum of feedstock energies from all non-renewable 
feedstocks (including the non-renewable portion of a 
biointermediate) used to make the co-processed fuel, in Btu, per 
paragraph (f)(4)(i)(B)(3).

    (3) The feedstock energy value for each feedstock must be 
calculated as follows:

FEi = Mi * (1-mi) * Ei

Where:

FEi = Feedstock energy of feedstock i, in Btu.
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.
Ei = Energy content of feedstock i, in annual average 
Btu/lb, per paragraph (f)(7) of this section.

    (C) Approach C. (1) This approach must only be used for a process 
that meets all the following requirements:
    (i) The process does not meet the requirements of Approach A or B 
in paragraphs (f)(4)(i)(A) and (B) of this section.
    (ii) Heat or electricity is converted to energy in the co-processed 
fuel.
    (2) VRIN must be calculated as follows:
    [GRAPHIC] [TIFF OMITTED] TP30DE22.019
    
Where:

VRIN,DX = RIN volume, in gallons, for use in determining 
the number of gallon-RINs generated for the batch of renewable fuel 
with D code of X.
EqV = Equivalence value of the renewable fuel, per Sec.  80.1415.
ERB,DX = The chemical energy in the batch of co-processed 
fuel that came from chemical energy in renewable biomass qualified 
to be used to produce renewable fuel with D code of X, in Btu, per 
paragraph (f)(4)(i)(C)(3) of this section.
ED = The energy density of the renewable fuel, in Btu per gallon.

    (3) ERB,DX must be calculated as follows:

ERB,DX = Efeedstock,DX-Eexo,DX-Eother,DX + Eendo,DX

Where:

ERB,DX = The chemical energy in the batch of co-processed 
fuel that came from chemical energy in renewable biomass qualified 
to be used to produce renewable fuel with D code of X, in Btu.

[[Page 80744]]

Efeedstock,DX = The total chemical energy from renewable 
biomass qualified to be used to produce renewable fuel with D code 
of X used to produce the batch of co-processed fuel, in Btu, per 
paragraph (f)(7) of this section.
Eexo,DX = The total chemical energy from renewable 
biomass qualified to be used to produce renewable fuel with D code 
of X that is converted to heat during the production of the batch of 
co-processed fuel, in Btu.
Eother,DX = The total chemical energy from renewable 
biomass qualified to be used to produce renewable fuel with D code 
of X that is converted to other products and wastes during the 
production of the batch of co-processed fuel, in Btu.
Eendo,DX = The total heat or electricity from renewable 
biomass qualified to be used to produce renewable fuel with D code 
of X that is converted to chemical energy in the renewable fuel, 
other products, and wastes during the production of the batch of co-
processed fuel, in Btu. This amount must be proportional to the 
total amount of heat or electricity that comes from renewable 
biomass.

    (D) Approach D. EPA may approve a different approach if the RIN 
generator demonstrates that the process does not meet the requirements 
of Approach A, B, or C in paragraphs (f)(4)(i)(A) through (C) of this 
section, as specified in Sec.  80.1450(b)(1)(xvii)(D).
    (ii) For a batch of co-processed intermediate, the biointermediate 
producer must determine the volume of biointermediate (i.e., 
Vbio) qualified to be used to produce renewable fuel for 
which RINs may be generated using one of the following approaches:
    (A) Approach A. (1) This approach must only be used for a process 
that meets all the following requirements:
    (i) The biointermediate is produced under approved pathways with a 
single D code.
    (ii) The fraction of carbon in the co-processed intermediate that 
originates from renewable biomass does not exceed the fraction of 
chemical energy in the co-processed intermediate that originates from 
renewable biomass.
    (2) Vbio must be calculated as follows:

Vbio = Vi * R

Where:

Vbio = Volume of biointermediate, in gallons, qualified 
to be used to produce renewable fuel for which RINs may be 
generated.
Vi = Standardized volume of the batch of co-processed 
intermediate at 60 [deg]F, in gallons, per paragraph (f)(8) of this 
section.
R = The renewable fraction of the co-processed intermediate as 
measured by a carbon-14 dating test method, per paragraph (f)(9) of 
this section.

    (B) Approach B. (1) This approach must only be used for a process 
that meets all the following requirements:
    (i) The process does not meet the requirements of Approach A in 
paragraph (f)(4)(ii)(A) of this section.
    (ii) Neither heat nor electricity is converted to chemical energy 
in the co-processed intermediate.
    (iii) The fraction of chemical energy in the co-processed 
intermediate that comes from renewable biomass is equal to or greater 
than the fraction of chemical energy in the feedstocks that comes from 
renewable biomass.
    (iv) If the biointermediate produced qualifies to be used to 
produce renewable fuel eligible to generate both D3/D7 RINs and D4/D5/
D6 RINs, the fraction of chemical energy in the co-processed 
intermediate qualified to be used to produce renewable fuel eligible to 
generate D3/D7 RINs that comes from renewable biomass is equal to or 
greater than the fraction of chemical energy in the feedstocks 
qualified to be used to produce renewable fuel eligible to generate D3/
D7 RINs that comes from renewable biomass.
    (v) If the biointermediate produced qualifies to generate both D4/
D5 RINs and D6 RINs, the fraction of chemical energy in the co-
processed intermediate qualified to be used to produce renewable fuel 
eligible to generate D4/D5 RINs that comes from renewable biomass is 
equal to or greater than the fraction of chemical energy in the 
feedstocks qualified to be used to produce renewable fuel eligible to 
generate D4/D5 RINs that comes from renewable biomass.
    (2) Vbio,DX must be calculated as follows:

Vbio,DX = Vi * FER,DX/(FER 
+ FENR)

Where:

Vbio,DX = Volume of biointermediate, in gallons, 
qualified to be used to produce renewable fuel for which RINs with D 
code of X may be generated.
Vi = Standardized volume of the batch of co-processed 
intermediate at 60 [deg]F, in gallons, per paragraph (f)(8) of this 
section.
FER,DX = Sum of feedstock energies from renewable biomass 
used to make the co-processed intermediate that qualify be used to 
produce renewable fuel with D code of X, in Btu, per paragraph 
(f)(4)(ii)(B)(3) of this section.
FER = Sum of feedstock energies from all renewable 
biomass used to make the co-processed intermediate, in Btu, per 
paragraph (f)(4)(ii)(B)(3) of this section.
FENR = Sum of feedstock energies from all non-renewable 
feedstocks used to make the co-processed intermediate, in Btu, per 
paragraph (f)(4)(ii)(B)(3).

    (3) The feedstock energy value for each feedstock must be 
calculated as follows:

FEi = Mi * (1-mi) * Ei

Where:

FEi = Feedstock energy of feedstock i, in Btu.
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.
Ei = Energy content of feedstock i, in annual average 
Btu/lb, per paragraph (f)(7) of this section.

    (C) Approach C. (1) This approach must only be used for a process 
that meets all the following requirements:
    (i) The process does not meet the requirements of Approach A or B 
in paragraphs (f)(4)(ii)(A) and (B) of this section.
    (ii) Heat or electricity is converted to energy in the co-processed 
intermediate.
    (2) Vbio,DX must be calculated as follows:
    [GRAPHIC] [TIFF OMITTED] TP30DE22.020
    
Where:

Vbio,DX = Volume of biointermediate, in gallons, 
qualified to be used to produce renewable fuel for which RINs with D 
code of X may be generated.
ERB,DX = The chemical energy in the batch of co-processed 
intermediate that came from chemical energy in renewable biomass 
qualified to be used to produce renewable fuel with D code of X, in 
Btu, per paragraph (f)(4)(ii)(C)(3) of this section.
ED = The energy density of the biointermediate, in Btu per gallon.

    (3) ERB,DX must be calculated as follows:

ERB,DX = Efeedstock,DX-Eexo,DX-Eother,DX + Eendo,DX

Where:

ERB,DX = The chemical energy in the batch of co-processed 
intermediate that came from chemical energy in renewable biomass 
qualified to be used to produce renewable fuel with D code of X, in 
Btu.
Efeedstock,DX = The total chemical energy from renewable 
biomass qualified to be used to produce renewable fuel with D code 
of X used to produce the batch of co-processed intermediate, in Btu, 
per paragraph (f)(7) of this section.
Eexo,DX = The total chemical energy from renewable 
biomass qualified to be used to produce renewable fuel with D code 
of X that is converted to heat during the production of the batch of 
co-processed intermediate, in Btu.
Eother,DX = The total chemical energy from renewable 
biomass qualified to be used to produce renewable fuel with D code 
of X that is converted to other products and wastes during the 
production of the batch of co-processed intermediate, in Btu.
Eendo,DX = The total heat or electricity from renewable 
biomass qualified to be used to produce renewable fuel with D code 
of X that is converted to chemical energy in the renewable fuel, 
other products, and wastes during the production of the batch of co-
processed intermediate, in

[[Page 80745]]

Btu. This amount must be proportional to the total amount of heat or 
electricity that comes from renewable biomass.

    (D) Approach D. EPA may approve a different approach if the 
biointermediate producer demonstrates that the process does not meet 
the requirements of Approach A, B, or C in paragraphs (f)(4)(ii)(A) 
through (C) of this section, as specified in Sec.  
80.1450(b)(1)(xvii)(D).
* * * * *
    (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.
* * * * *
    (7) * * *
    (i) For purposes of paragraphs (f)(3)(vi), (f)(4)(i)(B), and 
(f)(4)(ii)(B) of this section, producers must specify the value for E, 
the energy content of the feedstock components, used in the calculation 
of the feedstock energy value FE.
* * * * *
    (v) * * *
    (A) ASTM E870 or ASTM E711 for gross calorific value (both 
incorporated by reference, see Sec.  80.3).
    (B) ASTM D4442 or ASTM D4444 for moisture content (both 
incorporated by reference, see Sec.  80.3).
* * * * *
    (8) * * *
    (ii) * * *
    (B) The standardized volume of biodiesel at 60 [deg]F, in gallons, 
as calculated from the use of the American Petroleum Institute Refined 
Products Table 6B, as referenced in ASTM D1250 (incorporated by 
reference, see Sec.  80.3).
    (9) * * *
    (i) Parties required under this part to use a radiocarbon dating 
test method for determination of the renewable fraction of a co-
processed fuel or intermediate must use one of the following methods:
    (A) Method B of ASTM D6866 (incorporated by reference, see Sec.  
80.3).
    (B) If the renewable content of the co-processed fuel or 
intermediate is 10% or greater, Method C of ASTM D6866.
    (C) An alternative test method as approved by EPA that meets all 
the following requirements:
    (1) The laboratory meets the requirements related to usage of 
enriched C-14, as specified in Section 1.4 of ASTM D6866.
    (2) The result is rounded according to Section 13.4 of ASTM D6866.
    (3) The uncertainty of the method is less than 0.5%.
    (ii) Any party required to test for carbon-14 under this subpart 
must keep representative samples for at least 30 days after testing is 
complete.
    (A) For liquid samples, at least 330 ml must be retained.
    (B) For gaseous samples, at least one gallon at standard 
temperature and pressure must be retained.
* * * * *
    (10) RINs for renewable CNG/LNG produced from biogas that is only 
distributed via a closed, private, non-commercial system may only be 
generated if all the following requirements are met:
    (i) The renewable CNG/LNG was produced from renewable biomass and 
qualifies to generate RINs under an approved pathway.
    (ii) The RIN generator has entered into a written contract for the 
sale or use of a specific quantity of renewable CNG/LNG for use as 
transportation fuel, or has obtained affidavits from all parties 
selling or using the renewable CNG/LNG as transportation fuel.
    (iii) The renewable CNG/LNG was used as transportation fuel and for 
no other purpose.
    (iv) The biogas was introduced into the closed, private, non-
commercial system no later than December 31, 2023, and the renewable 
CNG/LNG was used as transportation fuel no later than December 31, 
2024.
    (11)(i) 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 to generate RINs 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 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 were continuously measured under 
Sec.  80.165.
    (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, 2023, and the renewable CNG/LNG was used as 
transportation fuel no later than December 31, 2024.
    (ii) On or after January 1, 2024, RINs may only be generated for 
RNG introduced into a natural gas commercial pipeline system for use as 
transportation fuel as specified in subpart E of this part.
    (iii) If non-renewable components are blended into biogas or RNG, 
RINs may only be generated on the biomethane content of the biogas or 
RNG prior to blending.
    (12) For purposes of Table 1 of this section, process heat produced 
from combustion of biogas or RNG at a renewable fuel production 
facility is considered produced from renewable biomass 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 commercial distribution 
system and the volume of biogas used as process heat were continuously 
measured under Sec.  80.165.
    (ii) For RNG injected into a commercial distribution system on or 
before December 31, 2023:
    (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 commercial 
distribution 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 commercial distribution 
system and the volume of RNG withdrawn were continuously measured under 
Sec.  80.165.

[[Page 80746]]

    (E) The commercial distribution 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 January 1, 2024, the 
renewable fuel producer must retire RINs for RNG as specified in Sec.  
80.140.
    (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:
    (i) The quantity of electricity used at the site that is purchased 
from the electricity distribution system must be continuously measured 
and recorded.
    (ii) All electricity used on-site that is not purchased from the 
electricity distribution system must be produced on-site from biogas 
from landfills or waste digesters.
    (iii) For biogas transported to the renewable fuel production 
facility via a biogas closed distribution system, the requirements in 
paragraph (f)(12)(i) of this section must be met.
    (iv) For RNG injected into a commercial distribution system on or 
before December 31, 2023, the requirements in paragraph (f)(12)(ii) of 
this section must be met. For RNG injected into a natural gas 
commercial pipeline system on or after January 1, 2024, the renewable 
fuel producer must retire RINs for RNG as specified in Sec.  80.140.
    (v) The biogas or RNG used at the renewable fuel production 
facility is not considered produced from renewable biomass 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 electricity, 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.  80.3) is considered 
renewable fuel and the producer or importer may generate RINs for such 
fuel only if all of 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
17. Amend Sec.  80.1427 by, in paragraph (a)(1) introductory text, 
removing the text ``under Sec.  80.1406''.
0
18. Amend Sec.  80.1428 by revising paragraphs (a)(2) through (4) and 
(a)(5)(i) to read as follows:


Sec.  80.1428  General requirements for RIN distribution.

    (a) * * *
    (2) Except as provided in Sec. Sec.  80.1429 and 80.140(d), no 
person can separate a RIN that has been assigned to a volume of 
renewable fuel or RNG pursuant to Sec.  80.1426(e).
    (3) An assigned RIN cannot be transferred to another person without 
simultaneously transferring a volume of renewable fuel or RNG to that 
same person.
    (4) Assigned gallon-RINs with a K code of 1 can be transferred to 
another person based on the following:
    (i) On or before December 31, 2023, for purposes of this section, 
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. For RNG, the transferer of assigned 
RINs with RNG must transfer RINs under Sec.  80.140(c).
    (ii) On or after January 1, 2024, for purposes of this section, the 
transferee must transfer assigned gallon-RINs equal to the equivalence 
value multiplied by the quantity of the renewable fuel or RNG 
transferred to the transferor.
    (5)(i) On or before December 31, 2023, for purposes of this 
section, on each of the dates listed in paragraph (a)(5)(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 = Total volume of renewable fuel owned on date d, 
standardized to 60 [deg]F, in gallons.
* * * * *
0
19. Amend Sec.  80.1429 by:
0
a. Revising paragraphs (b)(1) through (3);
0
b. Adding paragraph (b)(4)(iii); and
0
c. Revising paragraphs (b)(5) and (6) introductory text.
    The revisions and addition read as follows:


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

* * * * *
    (b) * * *

[[Page 80747]]

    (1) Except as provided in paragraphs (b)(7) and (9) of this section 
and Sec.  80.140(d)(2), an obligated party must separate any RINs that 
have been assigned to a volume of renewable fuel if that party owns 
that volume.
    (2) Except as provided in paragraph (b)(6) of this section, any 
party that owns a volume of renewable fuel must separate any RINs that 
have been assigned to that volume once the volume is blended with 
gasoline or fossil-based diesel to produce a transportation fuel, 
heating oil, or jet fuel.
    (i) On or before December 31, 2023, a party may separate up to 2.5 
RINs per gallon of blended renewable fuel.
    (ii) On or after January 1, 2024, a party must separate RINs in the 
amount equal to the equivalence value multiplied by the quantity of the 
renewable fuel or RNG of the gallon-RINs with a K code of 1.
    (3) Any exporter of renewable fuel must separate any RINs that have 
been assigned to the exported renewable fuel volume.
    (i) On or before December 31, 2023, an exporter of renewable fuel 
may separate up to 2.5 RINs per gallon of exported renewable fuel.
    (ii) On or after January 1, 2024, an exporter of renewable fuel 
must separate RINs in the amount equal to the equivalence value 
multiplied by the quantity of the renewable fuel or RNG of the gallon-
RINs with a K code of 1.
    (4) * * *
    (iii) Renewable fuel producers of biodiesel may not separate RINs 
under paragraph (b)(4)(i) of this section.
    (5)(i) Any party that generates RINs for a batch of renewable 
electricity under Sec.  80.135 must separate any RINs that have been 
assigned to that batch.
    (ii) Any party that generates RINs for a batch of renewable CNG/LNG 
must separate any RINs that have been assigned to that batch if the 
party demonstrates that the renewable CNG/LNG was used as 
transportation fuel.
    (iii) Only a party that demonstrates that RNG was used as a biogas-
derived renewable fuel under Sec.  80.140(d)(1) may separate the RINs 
that have been assigned to the RNG.
    (6) RINs assigned to a volume of biodiesel can only be separated 
from that volume pursuant to paragraph (b)(2) of this section if such 
biodiesel is blended into diesel fuel at a concentration of 20 volume 
percent biodiesel or less.
* * * * *


Sec.  80.1430  [Amended]

0
20. Amend Sec.  80.1430 by, in paragraph (e)(2), removing the text 
``Sec.  80.1468'' and adding, in its place, the text ``Sec.  80.3''.
0
21. Amend Sec.  80.1431 by:
0
a. Revising paragraphs (a)(1)(vi) and (viii);
0
b. Adding paragraphs (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 meet the definition of renewable fuel.
* * * * *
    (viii) Was generated for fuel that was not used in the covered 
location.
* * * * *
    (x) Was inappropriately separated under Sec.  80.140.
* * * * *
    (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 of the following conditions and requirements are satisfied and 
the renewable fuel producer or importer who improperly generated the 
RINs demonstrates that the conditions and requirements are satisfied 
through the reporting and recordkeeping requirements set forth below, 
that:
* * * * *
0
22. 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 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.  80.140(e) must retire the assigned RIN.
* * * * *


Sec.  80.1435  [Amended]

0
23. 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
24. 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 read 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

[[Page 80748]]

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
25. 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
26. 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
27. Amend Sec.  80.1449 by, in paragraph (e), removing the text ``the 
Administrator'' and adding, in its place, the text ``EPA''.
0
28. 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)(D);
0
e. In paragraph (b)(1)(v)(E) removing the text ``the Administrator'' 
and adding, in its place, the text ``EPA''.
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.  80.3'';
0
j. Revising paragraphs (b)(1)(xii) introductory text and 
(b)(1)(xiii)(B) introductory text;
0
k. Adding paragraph (b)(1)(xiii)(C);
0
l. Revising paragraph (b)(1)(xv)(B);
0
m. Adding paragraph (b)(1)(xvii)
0
n. Revising the first sentence of paragraph (b)(2) introductory text 
and paragraphs (b)(2)(ii) and (iii);
0
o. Redesignating paragraphs (b)(2)(iv) through (vi) as paragraphs 
(b)(2)(v) through (vii), respectively, and adding a new paragraph 
(b)(2)(iv);
0
p. Adding paragraphs (b)(2)(viii) and (ix);
0
q. Revising paragraphs (d)(3) introductory text, (d)(3)(ii), and (iii);
0
r. Adding paragraphs (d)(3)(v) and (vi);
0
s. Revising paragraph (g)(10)(ii); and
0
t. 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) * * *
    (D) For purposes of this section, for all facilities producing 
renewable electricity or other renewable fuel from biogas, submit all 
relevant information in Sec.  80.1426(f)(10) or (11), including all the 
following:
    (1) On or before December 31, 2023, for facilities producing 
renewable CNG/LNG as specified in Sec.  80.1426(f)(10):
    (i) Copies of all contracts or affidavits, as applicable, that 
follow the track of the biogas, renewable CNG/LNG, or renewable 
electricity (i.e., from the biogas producer to the party that processes 
it into renewable fuel, and finally to the end user that will actually 
use the renewable electricity or renewable CNG/LNG as transportation 
fuel.
    (ii) Specific quantity, heat content, and percent efficiency of 
transfer, as applicable, and any conversion factors, for the renewable 
fuel derived from biogas.
    (2) On or before December 31, 2023, for facilities producing RNG as 
specified in Sec.  80.1426(f)(11) or renewable electricity under Sec.  
80.1426(f)(10) or (11):
    (i) Copies of all contracts or affidavits, as applicable, that 
follow the track of the biogas, renewable CNG/LNG, or renewable 
electricity (i.e., from the biogas producer to the party that processes 
it into renewable fuel, and finally to the end user that will actually 
use the renewable electricity or renewable CNG/LNG as transportation 
fuel).
    (ii) Specific quantity, heat content, and percent efficiency of 
transfer, as applicable, and any conversion factors, for the renewable 
fuel derived from biogas.
* * * * *
    (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.
* * * * *
    (xii) For a producer or importer of 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.  80.3), biogas, or renewable electricity, all the 
following:
* * * * *
    (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:
* * * * *
    (C) A renewable fuel producer seeking to generate D code 3 or D 
code 7 RINs or a biointermediate producer seeking to

[[Page 80749]]

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 provide items (1) 
through (4) or specify a value and limited conditions in (5):
    (1) A cellulosic Converted Fraction (CF) for each cellulosic 
feedstock that will be used for generating RINs under Sec.  
80.1426(f)(3)(vi)(D), in Btu/lb, rounded to the nearest whole number.
    (2) Data supporting the cellulosic CF from each cellulosic 
feedstock. Data must be derived from processing of cellulosic 
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 has 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 including any calculations demonstrating how the 
data were used to determine the cellulosic CF.
    (4) A list of ranges of processing conditions, including 
temperature, solids residence time, and hydraulic residence time, for 
which the cellulosic CF is accurate and for which the facility must 
maintain to generate RINs and a description of how such processing 
conditions will be measured by the facility. RINs generated from 
facilities operating outside of these conditions will be invalid 
pursuant Sec.  80.1431(a)(1)(ix).
    (5) Registering parties choosing at least one of the converted 
fraction values below in lieu of providing data specified in paragraphs 
(b)(1)(xiii)(C)(1) through (4) of this section must only use biogas 
from anaerobic digesters that continuously operate above 95 degrees 
Fahrenheit with hydraulic and solids residence times greater than 20 
days. RINs generated from facilities operating outside of the listed 
conditions will be invalid pursuant Sec.  80.1431(a)(1)(ix).
    (i) Swine manure: 1,742 Btu/lb.
    (ii) Bovine manure: 1,869 Btu/lb.
    (iii) Chicken manure: 2,700 Btu/lb.
    (iv) Municipal wastewater treatment sludge: 3,131 Btu/lb.
* * * * *
    (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.
* * * * *
    (xvii) A RIN generator or biointermediate producer that generates 
RINs for a co-processed fuel or produces a co-processed intermediate 
under Sec.  80.1426(f)(4) must provide all the following information 
for each facility:
    (A) Whether Approach A, B, C, or D will be used to generate RINs.
    (B) For Approaches A, B, and C, a description of the process and 
any supporting data describing how the process meets the applicable 
requirements of the approach.
    (C) For Approach C, all the following information:
    (1) A description of how the renewable fuel or biointermediate 
producer will determine the values used in all equations for Approach 
C, including additional information used to determine those values, and 
an explanation of why this approach is either accurate or provides a 
conservative estimate of the amount of renewable fuel produced.
    (2) A list of the meters or other measurement locations that will 
be used to determine the values for Approach C, including any methods 
or standards used for each meter or measurement, and a process flow 
diagram showing their locations.
    (3) A list of assumptions underlying the calculation of the values 
for Approach C and an explanation of why each assumption is accurate or 
provides a conservative estimate of the amount of renewable fuel 
produced, including a literature review and testing, as applicable.
    (4) Any additional supporting information needed to evaluate 
whether Approach C accurately or conservatively estimates the amount of 
renewable fuel as requested by EPA.
    (D) For Approach D, all the following information:
    (1) A description and any supporting data describing why the 
process cannot meet the requirements specified for Approaches A, B, and 
C.
    (2) A description of how the renewable fuel or biointermediate 
producer will determine the volume of renewable fuel produced, 
including relevant equations, and an explanation of why this approach 
is either accurate or provides a conservative estimate of the volume of 
renewable fuel produced.
    (3) A list of the meters or other measurement locations that will 
be used to determine the values in paragraph (b)(1)(xvii)(D)(2) of this 
section, including any methods or standards used for each meter or 
measurement, and a process flow diagram showing their locations.
    (4) A list of assumptions underlying the calculation of the volume 
of renewable fuel produced and an explanation of why each assumption is 
accurate or provides a conservative estimate of the amount of renewable 
fuel produced, including a literature review and testing, as 
applicable.
    (5) Any additional supporting information needed to evaluate 
whether Approach D accurately or conservatively estimates the amount of 
renewable fuel as requested by EPA.
    (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.  80.145, as applicable. * * *
* * * * *
    (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), (7) through (10), (12), and (13).
    (iii) 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.''
    (iv)(A) 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

[[Page 80750]]

during the site visit, and certify that all process unit connections 
are in place and functioning based on the site visit.
    (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.
    (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.
    (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.
* * * * *
    (viii) 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.
    (ix) Reports required under paragraph (b)(2) of this section 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:
* * * * *
    (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 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, 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 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. The representative 
sample must be selected in accordance with the sample size guidelines 
set forth at 40 CFR 1090.1805 and 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.
* * * * *
    (v) Independent third-party engineers must conduct on-site visits 
required under this paragraph of this section no sooner than July 1 of 
the calendar year prior to the applicable January 31 deadline.
    (vi) The site visit must occur when the renewable fuel production 
facility is producing renewable fuel or when the biointermediate 
production facility is producing biointermediates.
* * * * *
    (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
29. 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.  80.3'';
0
i. Revising paragraph (b)(1)(ii)(U) introductory text;
0
j. Redesignating paragraph (b)(1)(ii)(W) as paragraph (b)(1)(ii)(X) and 
adding a new paragraph (b)(1)(ii)(W);
0
k. In newly redesignated paragraph (b)(1)(ii)(X), removing the text 
``the Administrator'' and adding, in its place, the text ``that EPA'';
0
l. In paragraph (c)(1)(iii)(K), removing the text ``the Administrator'' 
and adding, in its place, the text ``EPA'';
0
m. In paragraphs (c)(2)(i)(J) and (L), removing the text ``as defined 
in'' and adding, in its place, the text ``under'';
0
n. In paragraph (c)(2)(i)(R), removing the text ``the Administrator'' 
and adding, in its place, the text ``EPA'';
0
o. In paragraphs (c)(2)(ii)(D)(8) and (10), removing the text ``as 
defined in'' and adding, in its place, the text ``under'';
0
p. Revising paragraph (c)(2)(ii)(D)(14);
0
q. In paragraph (c)(2)(ii)(I), removing the text ``the Administrator'' 
and adding, in its place, the text ``EPA'';
0
r. In paragraph (e) introductory text, remove the text ``as defined in 
Sec.  80.1401 who'' and adding, in its place, the text ``that'';
0
s. Adding paragraph (f)(4);
0
t. In paragraph (g)(1)(ii)(Q), removing the text ``the Administrator'' 
and adding, in its place, the text ``that EPA'';
0
u. In paragraphs (g)(2)(xi) and (h)(2), removing the text ``the 
Administrator'' and adding, in its place, the text ``EPA'';
0
v. In paragraph (j)(1)(xvi), removing the text ``the Administrator'' 
and adding, in its place, the text ``that EPA''; and
0
w. 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

[[Page 80751]]

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 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 of the 
following:
* * * * *
    (W) Renewable fuel and biointermediate producers that produce co-
processed fuel or intermediate under Sec.  80.1426(f)(4) must report 
the following information, as applicable:
    (1) For Approach A, the following information by batch:
    (i) The standardized volume of the batch of co-processed fuel or 
intermediate at 60 [deg]F, in gallons.
    (ii) The renewable fraction of the co-processed fuel or 
intermediate, as a percentage.
    (iii) The test method used to measure the renewable fraction under 
Sec.  80.1426(f)(9).
    (2) For Approach B, the following information by batch:
    (i) The standardized volume of the batch of co-processed fuel or 
intermediate at 60 [deg]F, in gallons.
    (ii) The mass of each feedstock, in pounds.
    (iii) The average moisture content of each feedstock, as a mass 
fraction.
    (iv) The energy content of each feedstock, in Btu/lb.
    (3) For Approach C, the following information by batch:
    (i) The energy density of the renewable fuel or biointermediate, in 
Btu per gallon.
    (ii) Each input used to calculate ERB,DX, in Btu.
    (4) For Approach D, all the information specified at registration 
to be reported, by batch.
* * * * *
    (c) * * *
    (2) * * *
    (ii) * * *
    (D) * * *
    (14) For compliance periods ending on or before December 31, 2023, 
the volume of renewable fuel (in gallons) owned at the end of the 
quarter.
* * * * *
    (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.
* * * * *


Sec.  80.1452  [Amended]

0
30. 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
31. Amend Sec.  80.1453 by:
0
a. Revising paragraph (a) introductory text;
0
b. Adding paragraph (a)(11)(i)(D);
0
c. Revising paragraphs (a)(12) introductory text and (a)(12)(v);
0
d. Adding paragraph (a)(12)(viii);
0
e. 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
f. 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 of the following information, as 
applicable:
* * * * *
    (11) * * *
    (i) * * *
    (D) Beginning January 1, 2024, the identifying information for a 
RIN must also include the assigned equivalence value of the renewable 
fuel along with the following statement: ``These assigned RINs may only 
be separated up to the amount of the assigned equivalence value on a 
per-gallon basis''.
* * * * *
    (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.  80.160.
* * * * *
0
32. 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 paragraphs (c)(1) introductory text, (c)(1)(iii), and (c)(2) 
introductory text, removing the text ``(as defined in Sec.  80.1401)'';
0
f. Adding paragraphs (c)(2)(vii) and (c)(3);
0
g. Revising paragraph (d) introductory text;
0
h. Redesignating paragraphs (d)(1) through (4) as paragraphs (d)(2) 
through (5), respectively, and adding a new paragraph (d)(1);
0
i. In newly redesignated paragraph (d)(2)(ii), removing the text 
``(d)(1)(i)'' and adding, in its place, the text ``(d)(2)(i)'';
0
j. 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
k. Revising newly redesignated paragraph (d)(5);

[[Page 80752]]

0
l. Adding paragraph (d)(6);
0
m. In paragraphs (h)(3)(iv) and (v), removing the text ``as defined in 
Sec.  80.1401'';
0
n. Removing paragraphs (h)(6)(vi) and (vii);
0
o. Revising paragraph (j) introductory text;
0
p. In paragraphs (j)(1)(iii) and (j)(2)(iv), removing the text ``the 
Administrator'' and adding, in its place, the text ``EPA'';
0
q. Revising paragraph (k) introductory text;
0
r. In paragraph (k)(2)(v), removing the text ``the Administrator'' and 
adding, in its place, the text ``EPA'';
0
s. Revising paragraph (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''.
    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 supplier 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 supplier 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) Additional requirements for producers of renewable CNG/LNG, 
biogas and electricity in pathways involving grain sorghum as 
feedstock, and renewable fuel that uses process heat from biogas. (1) 
Renewable CNG/LNG. A renewable fuel producer that generates RINs for 
renewable CNG/LNG under Sec.  80.1426(f)(10) or (11), or that uses 
process heat from biogas to produce renewable fuel under Sec.  
80.1426(f)(12), must keep all the following additional records:
    (i) Documentation recording the sale of renewable CNG/LNG for use 
as transportation fuel relied upon in Sec.  80.1426(f)(10), Sec.  
80.1426(f)(11), or for use of biogas for process heat to make renewable 
fuel as relied upon in Sec.  80.1426(f)(12) and the transfer of title 
of the biogas, or renewable CNG/LNG from the point of biogas production 
to the facility which sells or uses the fuel for transportation 
purposes.
    (ii) Documents demonstrating the volume, energy content, and 
applicable D code of biogas or renewable CNG/LNG relied upon under 
Sec.  80.1426(f)(10) that was delivered to the facility which sells or 
uses the fuel for transportation purposes.
    (iii) Documents demonstrating the volume, energy content, and 
applicable D code of biogas or renewable CNG/LNG relied upon under 
Sec.  80.1426(f)(11) or (12), as applicable, that was placed into the 
commercial distribution system.
    (iv) Documents demonstrating the volume and energy content of 
biogas relied upon under Sec.  80.1426(f)(12) at the point of 
distribution.
    (v) Affidavits, EPA-approved documentation, or data from a real-
time electronic monitoring system, confirming that the amount of the 
biogas or renewable CNG/LNG relied upon under Sec.  80.1426(f)(10) and 
(11) was used as transportation fuel and for no other purpose. The RIN 
generator must obtain affidavits, or monitoring system data under this 
paragraph (k), for each quarter.
    (vi) A copy of the biogas producer's Compliance Certification 
required under Title V of the Clean Air Act.
    (vii) Any other records as requested by EPA.
    (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 of 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

[[Page 80753]]

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.  80.3), biogas-
derived renewable fuel or renewable electricity shall keep all of the 
following additional records:
* * * * *


Sec.  80.1455  [Removed and Reserved]

0
33. Remove and reserve Sec.  80.1455.


Sec.  80.1457  [Amended]

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


Sec.  80.1458  Storage of renewable fuel and 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 of the requirements in 
this section are met.
    (2) 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 of the 
requirements in this section are met.
    (b) Storage requirements. In order for a renewable fuel producer or 
biointermediate producer to store renewable fuel or biointermediate 
under this section, the producer must do the following:
    (1) Produce the stored renewable fuel or stored biointermediate 
after an independent third-party engineer has conducted an engineering 
review for the renewable fuel production or biointermediate production 
facility under Sec.  80.1450(b)(2).
    (2) Produce the stored renewable fuel or stored 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 stored renewable fuel or stored biointermediate at 
the facility that produced the renewable fuel or biointermediate.
    (5) Maintain custody and title to the stored renewable fuel or 
stored biointermediate until EPA accepts the renewable fuel or 
biointermediate producer's registration under Sec.  80.1450(b).
    (c) RIN generation. (1) A RIN generator may only generate RINs for 
stored renewable fuel or renewable fuel produced from stored 
biointermediate if the RIN generator generates the RINs under 
Sec. Sec.  80.1426 and 80.1452 after EPA activates the 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 or 
renewable fuel produced from stored biointermediate is the year that 
the renewable fuel was produced.
    (d) Limitations. (1) RNG injected into a commercial distribution 
system prior to EPA acceptance of a renewable fuel producer's 
registration under Sec.  80.1450(b) does not meet the requirements of 
this section and may not be stored.
    (2) Renewable electricity produced and placed on a transmission 
grid prior to EPA activation of a renewable electricity generator's 
registration under Sec.  80.145 does not meet the requirements of this 
section and may not be stored.
0
36. Amend Sec.  80.1460 by:
0
a. In paragraphs (c)(2) and (3), removing the text ``(as defined in 
Sec.  80.1401)'';
0
b. In paragraph (g), removing the text ``Sec.  80.1401'' and adding, in 
its place, the text ``Sec.  80.2'';
0
c. Revising paragraph (h)(3); and
0
d. Adding paragraph (l).
    The revision and addition read as follows:


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

* * * * *
    (h) * * *
    (3)(i) On or before December 31, 2023, separate more than 2.5 RINs 
per gallon of renewable fuel that has a valid qualifying separation 
event pursuant to Sec.  80.1429.
    (ii) On or after January 1, 2024, separate more RINs per gallon 
than the equivalence value assigned to the renewable fuel that has a 
valid qualifying separation event pursuant to Sec.  80.1429.
* * * * *
    (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
37. 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.
0
38. Amend Sec.  80.1464 by:
0
a. In the introductory paragraph, removing the text ``Sec. Sec.  
80.1465 and 80.1466'' and adding, in its place, the text ``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. Revising paragraph (a)(3)(ii);
0
d. 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
e. In paragraph (b)(1)(v)(B), removing the text ``in Sec.  80.1401''; 
and
0
f. Revising paragraphs (b)(3)(ii) and (c)(3)(ii).
    The revisions read as follows:


Sec.  80.1464  What are the attest engagement requirements under the 
RFS program?

    (a) * * *
    (3) * * *
    (ii) Obtain the database, spreadsheet, or other documentation used 
to generate the information in the RIN activity reports; compare the 
RIN transaction samples reviewed under paragraph (a)(2) of this section 
with the corresponding entries in the database or spreadsheet and 
report as a finding any discrepancies; compute the total number of 
current-year and prior-year RINs owned at the start and end of each

[[Page 80754]]

quarter; and state whether this information agrees with the party's 
reports to EPA.
* * * * *
    (b) * * *
    (3) * * *
    (ii) Obtain the database, spreadsheet, or other documentation used 
to generate the information in the RIN activity reports; compare the 
RIN transaction samples reviewed under paragraph (b)(2) of this section 
with the corresponding entries in the database or spreadsheet and 
report as a finding any discrepancies; report the total number of each 
RIN generated during each quarter and compute and report the total 
number of current-year and prior-year RINs owned at the start and end 
of each quarter; and state whether this information agrees with the 
party's reports to EPA.
* * * * *
    (c) * * *
    (2) * * *
    (ii) Obtain the database, spreadsheet, or other documentation used 
to generate the information in the RIN activity reports; compare the 
RIN transaction samples reviewed under paragraph (c)(1) of this section 
with the corresponding entries in the database or spreadsheet and 
report as a finding any discrepancies; compute the total number of 
current-year and prior-year RINs owned at the start and end of each 
quarter; and state whether this information agrees with the party's 
reports to EPA.
* * * * *
0
39. 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 * $0.30

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
40. 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 * $ 0.30

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 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
41. Remove and reserve Sec.  80.1468.
0
42. 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 (b)(1)(i), removing the text ``as defined in Sec.  
80.1401'';
0
d. 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
e. In paragraph (c)(1)(i), removing the text ``as defined in Sec.  
80.1401'';
0
f. Revising paragraphs (c)(4) introductory text;
0
g. 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
h. Adding paragraph (c)(6);
0
i. Revising paragraph (d); and
0
j. In paragraph (e)(1), removing the text ``the Administrator'' and 
adding, in its place, the text ``EPA''.
    The addition and revision 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

[[Page 80755]]

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 a RIN-generating approved pathway, which must contain elements 
specific to particular feedstocks, production processes, and fuel 
types, as applicable.
* * * * *
0
43. Amend Sec.  80.1471 by:
0
a. Revising paragraph (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 (13).
    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 for the audited party in the same calendar year 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 conducted past research, development, 
design, or construction, or consulting regarding such activities for 
the audited party within the last year. For purposes of this 
requirement, consulting does not include performing or participating in 
verification activities pursuant to this section.
    (11) The independent third-party auditor and its contractors and 
subcontractors must not provide other business or consulting services 
to the audited party, including advice or assistance to implement the 
findings or recommendations in an audit report, for a period of at 
least one year following cessation of QAP services for the audited 
party.
    (12) 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 
do not accept future employment with the owner or operator of the 
audited party for a period of at least 12 months. For purposes of this 
requirement, employment does not include performing or participating in 
the third-party audit (including the verification activities) pursuant 
to Sec.  80.1472.
    (13) 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
44. 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
45. 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
46. 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
47. 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 waste, 
separated MSW, or biogenic waste oils/fats/greases and uses a third-
party feedstock supplier to supply these feedstocks may comply with the 
alternative recordkeeping requirements of this section.
    (b) Registration of the feedstock supplier. The feedstock supplier 
must register under 40 CFR 1090.805.
    (c) QAP participation. (1) The feedstock supplier and renewable 
fuel producer must have an approved QAP as specified in Sec.  
80.1476(e).
    (2) Instead of verifying RINs with a site visit 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 
supplier'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 supplier 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.
    (f) Liability. The feedstock supplier 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
48. 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
49. Amend Sec.  1090.55 by revising paragraph (c) to read as follows:


Sec.  1090.55  Requirements for independent parties.

* * * * *

[[Page 80756]]

    (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
50. Amend Sec.  1090.80 by:
0
a. In the definition of ``PADD'', revising entry II in the table; and
0
b. In the definition of ``Ultra low-sulfur diesel'', removing the text 
``Ultra low-sulfur diesel'' and adding, in its place, the text ``Ultra-
low-sulfur diesel''.
    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
51. 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
52. Amend Sec.  1090.1830 by, in paragraph (a)(3), adding the text 
``all'' after the text ``submitted''.

[FR Doc. 2022-26499 Filed 12-29-22; 8:45 am]
BILLING CODE 6560-50-P