Proposed Rule Document

2722fr01.pdf

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

Proposed Rule Document

OMB: 2060-0749

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80582

Federal Register / Vol. 87, No. 250 / Friday, December 30, 2022 / Proposed Rules
intended to improve the program’s
implementation.

ENVIRONMENTAL PROTECTION
AGENCY

DATES:

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
Environmental Protection
Agency (EPA).
ACTION: Proposed rule.
AGENCY:

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, biomassbased 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

SUMMARY:

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a North

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: a-and-r-Docket@epa.gov.
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).

NAICS a
Codes

Category
Industry
Industry
Industry
Industry
Industry
Industry
Industry
Industry
Industry
Industry
Industry
Industry
Industry
Industry
Industry

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.

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: RFS-Rulemakings@
epa.gov. 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:

Examples of potentially affected entities

112111
112210
221117
221210
221320
324110
325120
325193
325199
336110
424690
424710
424720
454319
562212

Cattle farming or ranching.
Swine, hog, and pig farming.
Biomass electric power generation.
Manufactured gas production and distribution, and distribution of renewable natural gas (RNG).
Sewage treatment plants or facilities.
Petroleum refineries.
Biogases, industrial (i.e., compressed, liquefied, solid), manufacturing.
Ethyl alcohol manufacturing.
Other basic organic chemical manufacturing.
Electric automobiles for highway use manufacturing.
Chemical and allied products merchant wholesalers.
Petroleum bulk stations and terminals.
Petroleum and petroleum products merchant wholesalers.
Other fuel dealers.
Landfills.

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

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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

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

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I. Biogas Regulatory Reform
J. Separated Food Waste Recordkeeping
Requirements
K. Definition of Ocean-Going Vessels
L. Bond Requirement for Foreign RINGenerating 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 .........................
Biomass-based diesel ................
Advanced biofuel ........................
Renewable fuel ...........................

2010–2022
2009–2012
2009–2022
2006–2022

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
• The impact of renewable fuels on
the energy security of the U.S.; 2
• The expected annual rate of future
commercial production of renewable
fuels, including advanced biofuels in
each category (cellulosic biofuel and
biomass-based diesel); 3
• 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
• 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
• 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
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.
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,
1 CAA

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,

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section 211(o)(2)(B)(ii)(I).
section 211(o)(2)(B)(ii)(II).
3 CAA section 211(o)(2)(B)(ii)(III).
4 CAA section 211(o)(2)(B)(ii)(IV).
5 CAA section 211(o)(2)(B)(ii)(V).
6 CAA section 211(o)(2)(B)(ii)(VI).
7 See, e.g., 87 FR 39600 (July 1, 2022),
establishing the 2022 BBD volume requirement.
2 CAA

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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

TABLE I.A.1–1—PROPOSED VOLUME TARGETS
[Billion RINs] a
2023
Cellulosic biofuel ..........................................................................................................................
Biomass-based diesel b ...............................................................................................................
Advanced biofuel .........................................................................................................................
Renewable fuel ............................................................................................................................
Supplemental standard ................................................................................................................

2024

0.72
2.82
5.82
20.82
0.25

1.42
2.89
6.62
21.87
n/a

2025
2.13
2.95
7.43
22.68
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
8 87

FR 39600 (July 1, 2022).

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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
9 CAA

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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.

section 211(o)(3).

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TABLE I.A.2–1—PROPOSED PERCENTAGE STANDARDS
2023
Cellulosic biofuel ..........................................................................................................................
Biomass-based diesel ..................................................................................................................
Advanced biofuel .........................................................................................................................
Renewable fuel ............................................................................................................................
Supplemental standard ................................................................................................................

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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 standardsetting 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.

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2024

0.41
2.54
3.33
11.92
0.14

0.82
2.60
3.80
12.55
n/a

2025
1.23
2.67
4.28
13.05
n/a

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.

Each of these regulatory changes is
discussed in greater detail in Section IX.

4. Other Regulatory Changes

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

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 thirdparty 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

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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.

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,

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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 lowincome populations is provided in
Section IV.E.3.
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.

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%

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Excluding Supplemental Standard:
Cost Impacts .....................................................................................................................................................
Energy Security Benefits ..................................................................................................................................
Including Supplemental Standard:
Cost Impacts .....................................................................................................................................................
Energy Security Benefits ..................................................................................................................................

28,801
623

27,835
600

29,458
634

28,492
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 pollutionreducing 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 lowcarbon 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

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

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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
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• 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?
• 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
13 84

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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
14 We refer to CAA section 211(o)(2)(B)(ii) as the
‘‘set authority.’’

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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 biomassbased diesel volume requirements in
annual rulemakings since 2013.
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:
• The impact of the production and
use of renewable fuels on the
environment; 16
• The impact of renewable fuels on
the energy security of the U.S.; 17
• The expected annual rate of future
commercial production of renewable
fuels; 18
• The impact of renewable fuels on
the infrastructure of the U.S.; 19
• 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
• 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
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.
15 In furtherance of this requirement, we have had
periodic discussions with DOE and USDA on this
proposed action.
16 CAA section 211(o)(2)(B)(ii)(I).
17 CAA section 211(o)(2)(B)(ii)(II).
18 CAA section 211(o)(2)(B)(ii)(III).
19 CAA section 211(o)(2)(B)(ii)(IV).
20 CAA section 211(o)(2)(B)(ii)(V).
21 CAA section 211(o)(2)(B)(ii)(VI).

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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.
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:
• 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);
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.
25 CAA section 211(o)(2)(B)(ii)(VI).

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• The supply of qualifying renewable
fuels to U.S. consumers (Section
III.A.5) 26;
• Soil quality (Chapter 3.4 of the
RIA) 27;
• Environmental justice (Section IV.E
and Chapter 8 of the RIA) 28;
• A comparison of costs and benefits
(Section IV.D).29;
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
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
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.
27 Soil quality is closely tied to water quality and
is also relevant to the impact of renewable fuels on
the environment more generally.
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.
29 The comparison of costs and benefits compares
our quantitative analysis of various statutory
factors, including costs, energy security, and
climate impacts.
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.’’).

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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.
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.

with our past actions in determining the
cellulosic biofuel volume.35
CAA section 211(o)(7)(D) provides
that if ‘‘the projected volume of
cellulosic biofuel production is less
than the minimum applicable volume
established under paragraph (2)(B),’’
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.

D. Authority To Establish Percentage
Standards for Multiple Future Years
2. Cellulosic Biofuel
EPA is proposing to establish
The statute requires that EPA set the
percentage standards for multiple future
applicable cellulosic biofuel
years in a single action. For years after
requirement ‘‘based on the assumption
2022, the CAA does not expressly direct
that the Administrator will not need to
EPA to continue to implement volume
issue a waiver . . . under [CAA section
requirements through percentage
211(o)](7)(D)’’ for the years in which
standards established through annual
EPA sets the applicable volume
rulemakings. Furthermore, in
requirement.33 We interpret this
establishing volumes for years after
requirement to mean that we must
2022, EPA is directed to review ‘‘the
establish the cellulosic volume
implementation of the program’’ in
requirement at a level that is achievable years during which Congress provided
and not expected to require us in the
statutory volumes.37 Thus, Congress
future to lower the applicable cellulosic provided EPA discretion as to how to
volume requirement using the cellulosic implement the volume requirements of
waiver authority under CAA section
RFS program in years 2023 and beyond.
CAA section 211(o)(3)(B)(i) provides
211(o)(7)(D).34 That is, we are setting the
that by ‘‘November 30 of each of
volume requirements such that the
calendar years 2005 through 2021, based
mandatory waiver of the cellulosic
on the estimate provided [by EIA], the
volume is not likely to be triggered in
those future years. Operating within this Administrator . . . shall determine and
publish in the Federal Register, with
limitation, we are proposing to set the
respect to the following calendar year,
cellulosic volumes for 2023, 2024, and
the renewable fuel obligation that
2025 at the projected volume available
ensures that the requirements of
in each year, respectively, consistent
paragraph (2) are met.’’ 38 The next
subparagraph (ii) provides further
31 CAA section 211(o)(2)(B)(iii).
32 87

FR 39600 (July 1, 2022).
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).
33 CAA

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35 See, e.g., 2020–2022 Rule, 87 FR 39600 (July 1,
2022).
36 CAA Section 211(o)(2)(B)(iv).
37 CAA Section 211(o)(2)(B)(ii).
38 CAA Section 211(o)(3)(b)(i).

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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.
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

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

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

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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.
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
49 87

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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

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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 multifactor 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.
This section describes the derivation
of ‘‘candidate volumes’’ based on a
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).

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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 supplyrelated 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

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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.

Figure}II.B.1-1:_Cellulosic Biofuel RINs_ Generated (2013-2020) ___ . ___
700
600

.,,
z

500

400

C
0

300
200
100

"""''... -•'"·~·······2014

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

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2015

2016

2017

2018

2019

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

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202:0.

202:1

2022
(Proj,)

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

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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 2020–May 2021)
(million)

RIN generation
(June 2021–May 2022)
(million)

526.1 ........................................................................................................................................

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

Year-over-year increase
(%)

595.1

13.1

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]
Year

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2021
2023
2024
2025

..................................
..................................
..................................
..................................

Actual .......................................................................................................................
Projection .................................................................................................................
Projection .................................................................................................................
Projection .................................................................................................................

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-

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(%)

Date type

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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.
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.
51 See Chapter 6.1.3 for a further discussion of our
estimate of CNG/LNG used as transportation fuel in
2023–2025.
52 EPA Landfill Methane Outreach Program
Landfill and Project Database; Accessed March
2022.

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N/A
13.1
13.1
13.1

Volume
(RINs)
(million)
561.8
719.3
813.9
920.9

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

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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 fossilbased 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
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
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.

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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
57 86

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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.

TABLE III.B.1.b–1—PROJECTED GENERATION OF CELLULOSIC BIOFUEL
RINS FOR ELECTRICITY DERIVED
FROM BIOGAS
[Ethanol-equivalent gallons]
Year
2023 ..................................
2024 ..................................
2025 ..................................

Volume
(million RINs)
n/a
600
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

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

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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 coprocessing of both the starch and
cellulosic components of the corn
kernel. To be eligible to generate
cellulosic RINs, facilities that are coprocessing 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

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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 coprocessing 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.
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
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).

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80595

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 ethanolequivalent 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.

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3,000
2,500
ti\!

2,000

iii
!!I· 1,500
1,000
500

2014
■ Domestic

2015

20Hi

2017

1018

2019

2020

2021

llill Domestic Renewable Diesel

Biodiesel

l!I Net Biodiesel lmport.s

Ill Net Renewable Diesel Imports

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

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effort is accompanied by new and
ongoing funding opportunities to
support sustainable aviation fuel
projects and fuel producers totaling up
to $4.3 billion.
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

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

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• Numbers are based on RIN generation data from the EPA Moderated Transaction System (EMTS). This
figure does not include fuels that did not generate RINs. This figure also does not include conventional
biodiesel and renewable diesel, which are discussed in Section III.B.4.b and DRIA Chapter 6.7.

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

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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.

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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.
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
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/cvrpauses-renewable-diesel-plans-feedstock-pricessurge-2021-08-03.

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80597

renewable diesel production is likely to
increase along with production capacity
through 2025.
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.

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Figure 111.B.2-2: Feedstocks Used to Produce Biodiesel and Renewable Diesel in the
U.S. 2014-2021

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IIIIFOG

!'.JComoil

lil!ISoybeanrnl

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

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2106

2015

2017

2018

ocanoia Oil

2019

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.

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2021

■ Grandfathered (Unkn:owT1)

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

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Sfmt 4702

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.
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

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2014

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

TABLE III.B.3–1—ESTIMATE OF FUTURE CONSUMPTION OF OTHER ADVANCED BIOFUEL
Volume
(million
RINs)

khammond on DSKJM1Z7X2PROD with PROPOSALS2

Fuel
Imported sugarcane ethanol .........
Domestic ethanol ..........................
CNG/LNG .....................................
Heating oil .....................................
Naphtha ........................................
Renewable diesel .........................

110
25
5
2
33
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
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).

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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
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
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.
71 CAA
72 CAA

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section 211(o)(2)(A)(i).
section 211(o)(1)(B)(i).

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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
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
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.
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

Continued

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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.
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).
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 noncellulosic 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.

Figure 111.B.5-1: Poolwide Ethanol Concentration Over Time

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

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2023 .................................................................................................................................................
2024 .................................................................................................................................................
2025 .................................................................................................................................................

percent was from palm oil (see page 206 of ‘‘OECD–
FAO Agricultural Outlook 2021–2030’’).

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77 ‘‘RIN supply as of 3–22–21,’’ available in the
docket.

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10.44
10.49
10.53

Projected ethanol
consumption
(million gallons)
14,590
14,640
14,669

78 ‘‘RIN supply as of 3–22–21,’’ available in the
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Projected ethanol
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Federal Register / Vol. 87, No. 250 / Friday, December 30, 2022 / Proposed Rules
C. Candidate Volumes for 2023–2025
Based on our analysis of supplyrelated 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 noncellulosic 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

80601

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.
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

2025

Liquid Cellulosic Biofuel ...............................................................................................................
CNG/LNG Derived from Biogas ..................................................................................................
eRINs ...........................................................................................................................................

0
719
0

5
814
600

10
921
1,200

Total Cellulosic Biofuel .........................................................................................................

719

1,419

2,131

2. Non-Cellulosic Advanced Biofuel

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2024

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 noncellulosic advanced biofuel, the implied
statutory requirement increased in every
year between 2009 and 2019. It
79 See definition of ‘‘cellulosic biofuel’’ at 40 CFR
part 80 Section 1401.

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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
80 87

PO 00000

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

FR 39600 (July 1, 2022).

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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
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

TABLE III.C.2–1—NON-CELLULOSIC
ADVANCED BIOFUEL CANDIDATE
VOLUMES
[Million RINs]
Year

Volume

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2023 ..................................................
2024 ..................................................
2025 ..................................................

5,100
5,200
5,300

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.
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.

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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.
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
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.

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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
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
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.

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candidate volume for conventional
renewable fuel, such as: 85
• 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
Ethanol in all blends ....................................................................................................................
Cellulosic ethanol .........................................................................................................................
Imported sugarcane ethanol ........................................................................................................
Domestic advanced ethanol ........................................................................................................
Corn ethanol ................................................................................................................................

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 noncellulosic advanced biofuel candidate

2024

14,590
0
110
25
14,455

2025

14,640
0
110
25
14,505

14,669
0
110
25
14,534

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 ......................................................................................................................
Advanced renewable diesel a ......................................................................................................
Advanced jet fuel .........................................................................................................................
Other advanced biofuel ...............................................................................................................

2,580
3,054
5
256

2,530
3,154
5
256

2,480
3,275
5
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.

volumes we have considered in this
action.

The total volumes of non-cellulosic
advanced biofuel that can be supplied
would be in excess of the candidate

TABLE III.C.3–3—EXCESS NON-CELLULOSIC ADVANCED BIOFUEL
[Million RINs]
2023

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Total supply .................................................................................................................................
Candidate volume requirement ...................................................................................................
Excess .........................................................................................................................................

2024

5,895
5,100
795

2025

5,945
5,200
745

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.

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.

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5,300
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TABLE III.C.3–4—MEETING THE CANDIDATE VOLUME FOR CONVENTIONAL RENEWABLE FUEL
[Million RINs]
2023

2024

2025

Corn ethanol ................................................................................................................................
Excess non-cellulosic advanced biofuel ......................................................................................

14,455
a 545

14,505
745

14,534
716

Total ......................................................................................................................................

15,000

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.

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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 palmbased 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

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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.
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
86 40

CFR 80.1427(a)(5).
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).
87 See,

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renewable fuel—that could limit the
availability of RINs.
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 marketforcing 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

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

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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).
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
89 79

FR 49793–95 (August 15, 2013).
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.
90 The

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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,
91 87

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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.
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, caseby-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 supplyrelated 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.

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TABLE III.C.5–1—CANDIDATE VOLUME COMPONENTS DERIVED FROM SUPPLY-RELATED FACTORS
[Million RINs] a
2023

Cellulosic biofuel (D3 & D7) ........................................................................................................
Biomass-based diesel (D4) .........................................................................................................
Other advanced biofuel (D5) .......................................................................................................
Conventional renewable fuel (D6) ...............................................................................................

2024

719
5,389
256
14,455

1,419
5,689
256
14,505

2025
2,131
5,760
256
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 ..........................................................................................................................
Non-cellulosic advanced biofuel b ................................................................................................
Advanced biofuel .........................................................................................................................
Conventional renewable fuel b .....................................................................................................

719
5,100
5,819
a 15,000

1,419
5,200
6,619
15,250

2,131
5,300
7,431
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.
are implied volume requirements, not regulatory volume requirements.

b These

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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 supplyrelated 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

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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

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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
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
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.

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

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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

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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-bystate 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.

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TABLE III.D.1–1—BIOFUEL CONSUMPTION IN 2023–2025 UNDER A NO RFS BASELINE
[Million RINs]
2023

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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

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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.
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.
93 75

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2024

356
1,374
216
13,750

385
1,374
216
13,730

2025
417
1,374
216
13,693

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

TABLE III.D.3–1—FINAL 2022 VOLUME
REQUIREMENTS
Category
Cellulosic biofuel ...........................
Biomass based diesel a ................
Advanced biofuel ..........................
Total renewable fuel .....................

Volume
(billion
RINs)
0.63
2.76
5.63
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.
94 87

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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
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

80609

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
Cellulosic biofuel (D3 & D7) ........................................................................................................
Biomass-Based Diesel (D4) ........................................................................................................
Other Advanced Biofuel (D5) ......................................................................................................
Conventional Renewable Fuel (D6) ............................................................................................

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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.

95 80

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

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IV. Analysis of Candidate Volumes

2024

363
4,015
40
706

1,034
4,315
40
776

2025
1,714
4,386
40
840

that we believe would be appropriate for
2023–2025.

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

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

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)).

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A. Climate Change

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estimates as a proxy for climate change
impacts.
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 perunit 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 cropbased 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

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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

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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.
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
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 cornstarch 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.

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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-cropbased 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-toCNG 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

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Petroleum Gasoline ...............
Petroleum Diesel ....................
Corn Starch Ethanol ..............
Soybean Oil Biodiesel ............
Soybean Oil Renewable Diesel.
Used Cooking Oil Biodiesel ...
Used Cooking Oil Renewable
Diesel.
Tallow Biodiesel .....................
Tallow Renewable Diesel ......
Distillers Corn Oil Biodiesel ...
Distillers Corn Oil Renewable
Diesel.
Natural Gas CNG ...................
Landfill Gas CNG ...................
Manure Biogas CNG ..............

LCA range
84
84
38
14
26

to
to
to
to
to

98.
94.
116.
73.
87.

12 to 32.
12 to 37.
15
14
10
12

to
to
to
to

58.
81.
37.
46.

72 to 81.
9 to 70.
¥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

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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 marketmediated indirect emissions associated
with increasing the production of cropbased 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.

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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 petroleumbased 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

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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.
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 preCOVID–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 petroleumbased 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

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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,
101 Greene, D. 2010. Measuring energy security:
Can the United States achieve oil independence?
Energy Policy 38, pp. 1614–1621.
102 Ibid.
103 Ibid.
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-andpetroleum-products/images/u.s.tight_oil_
production.jpg.
106 https://www.eia.gov/energyexplained/oil-andpetroleum-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-andexports.php.

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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.
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
109 U.S. Energy Information Administration daily
spot prices, available at: https://www.eia.gov/dnav/
pet/pet_pri_spt_s1_d.htm.
110 Monopsony impacts stem from changes in the
demand for imported oil, which changes the price
of all imported oil.

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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.
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.
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.

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.
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.

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TABLE IV.B–1—MACROECONOMIC OIL SECURITY PREMIUMS AND TOTAL ENERGY SECURITY BENEFITS FOR 2023–2025 a
Macroeconomic oil
security premiums
(2021$/barrel of
reduced imports)

Year

2023 (Including the supplemental standard) .......................................................................................

$3.37
($0.88–$6.20)
$3.37
($0.88–$6.20)
$3.46
($0.89–$6.36)
$3.46
($0.83–$6.40)

2023 (Excluding the supplemental standard) ......................................................................................
2024 .....................................................................................................................................................
2025 .....................................................................................................................................................
a Top

$211
($55–$389)
$200
($52–$368)
$219
($56–$403)
$223
($53–$412)

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

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Total energy
security benefits
(millions 2021$)

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

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.

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–

TABLE IV.C.2–1—TOTAL SOCIAL COSTS
[Million 2021 dollars] a
2023 with
supplemental
standard

2023
Gasoline ...........................................................................................................

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2025
258

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TABLE IV.C.2–1—TOTAL SOCIAL COSTS—Continued
[Million 2021 dollars] a
2023 with
supplemental
standard

2023

2024

2025

Diesel ...............................................................................................................
Natural Gas ......................................................................................................

10,855
92

11,512
92

8,919
119

8,651
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]
Units
Gasoline ............................................
Diesel ................................................
Natural Gas .......................................
Gasoline and Diesel ..........................

2023 with
supplemental
standard

2023

¢/gal ..................................................
¢/gal ..................................................
¢/thousand ft3 ...................................
¢/gal ..................................................

0.18
19.6
0.30
5.7

2024

0.18
20.7
0.30
6.1

2025
0.18
16.2
0.39
4.8

0.22
15.6
0.48
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
[¢/gal]

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2023
Relative to No RFS Baseline:
Gasoline ................................................................................................................................
Diesel ....................................................................................................................................
Gasoline and Diesel .............................................................................................................
Relative to 2022 Baseline:
Gasoline ................................................................................................................................
Diesel ....................................................................................................................................
Gasoline and Diesel .............................................................................................................

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,

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the largest projected price increase is
14.9¢ 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

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2025

0.6
14.1
4.3

1.8
14.4
5.3

3.1
14.9
6.3

1.7
0.8
1.4

2.6
1.5
2.3

3.3
3.2
3.3

(USDA) which analyzed the impact of
fuel prices on the wholesale price of

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produce.113 Applying the price
correlation from the USDA study would
indicate that the 14.9¢ 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.

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

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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.

TABLE IV.D–1—FUEL COSTS OF THE CANDIDATE VOLUMES
[2021 Dollars, millions] a
Discount rate
Year
0%
2023:
Excluding Supplemental Standard .......................................................................................
Including Supplemental Standard ........................................................................................
2024 .............................................................................................................................................
2025 .............................................................................................................................................
Cumulative Discounted Costs:
Excluding Supplemental Standard .......................................................................................
Including Supplemental Standard ........................................................................................

11,199
11,856
9,295
9,100

11,199
11,856
9,025
8,578

11,199
11,856
8,687
7,948

........................
........................

28,801
29,458

27,835
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%

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2023:
Excluding Supplemental Standard .......................................................................................
Including Supplemental Standard ........................................................................................
2024 .............................................................................................................................................
2025 .............................................................................................................................................
Cumulative Discounted Benefits:
Excluding Supplemental Standard .......................................................................................
Including Supplemental Standard ........................................................................................

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.

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/comparingprices-on-groceries.
115 Due to the uncertainty related to the GHG
emission impacts of the candidate volumes

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E. Assessment of Environmental Justice
Although the statute identifies a
number of environmental factors that
we must analyze as described in Section

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200
211
219
223

200
211
213
210

200
211
205
195

........................
........................

623
634

600
611

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
(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.

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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?

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• 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 nonGHG 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
116 Mohai, P.; Pellow, D.; Roberts Timmons, J.
(2009) Environmental justice. Annual Reviews 34:
405–430. https://doi.org/10.1146/annurev-environ082508-094348.
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

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this evidence, a recent study found that
most anthropogenic sources of PM2.5,
including industrial sources, and lightand 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 nearfacility demographics of biodiesel,
renewable diesel, RNG, ethanol, and
petroleum facilities.
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
DRIA Chapter 4.1 summarizes what is
known about potential air quality
impacts of the candidate volumes
assessed for this rule. We expect that
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.
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.

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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.
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

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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 lowincome 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.

TABLE IV.E.3–1—PROPORTION OF TOTAL EXPENDITURES ON FOOD AND FUEL 127

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All consumer
units
Total expenditures .......................................................................................................................
Food expenditures .......................................................................................................................
Percent of total expenditures on food .........................................................................................
Fuel expenditures ........................................................................................................................
Percent of total expenditures on fuel ..........................................................................................
Percent Women ...........................................................................................................................
Percent Black ...............................................................................................................................
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,

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Research Triangle Park, North Carolina. Jan. 6,
2014.
127 Bureau of Labor and Statistics Consumer
Expenditure Survey, 2020. https://www.bls.gov/cex/

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$61,350
$7,316
11.9%
$1,568
2.6%
53%
13%

Lowest 20%
consumer
income
$28,782
$4,095
14.3%
$814
2.8%
65%
19%

Second-lowest
20% consumer
income
$39,846
$5,380
13.5%
$1,254
3.1%
56%
15%

tables/calendar-year/aggregate-group-share/cuincome-quintiles-before-taxes-2020.pdf.

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Federal Register / Vol. 87, No. 250 / Friday, December 30, 2022 / Proposed Rules
TABLE IV.E.3–1—PROPORTION OF TOTAL EXPENDITURES ON FOOD AND FUEL 127—Continued
All consumer
units

Percent With a High School Degree or Less ..............................................................................

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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-milliongallon 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.
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
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.
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.

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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.
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
134 86

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30%

Lowest 20%
consumer
income
49%

Second-lowest
20% consumer
income
41%

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.
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.
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.

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

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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-

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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
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.

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80619

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-milliongallon supplemental standards, one in
2022, as finalized in a prior action, and
in 2023, as we are proposing in this
action.
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
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.’’
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.

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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.
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-milliongallon supplemental standard in 2023.
As explained earlier, there are
insufficient 2015 and 2016 RINs
available to satisfy the proposed 250million-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

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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
Second, we provide significant leadtime 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 250million-gallon supplemental standard in
2023 for longer than they had notice of
the 2023 standards for renewable fuel,
advanced biofuel, and total renewable
fuel.
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 timeconsuming 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
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
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.
145 87

142 See

Section IV.F for further discussion of the
carryover RIN bank.
143 See 40 CFR 80.1427.
144 86 FR 72436 (December 21, 2021).

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FR 39600 (July 1, 2022).
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.
146 84

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

80621

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.
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]

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2023

2024

2025

0
719
0

5
814
600

10
921
1,200

Total Cellulosic Biofuel .........................................................................................................

719

1,419

2,131

149 CAA

section 211(o)(2)(B)(ii).
combinations are set forth in the statute.
See CAA section 211(o)(2)(B)(i)(I)–(III). In addition,
150 These

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the determination of the appropriate volume
requirements for BBD is treated separately in
Section VI.

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151 75
152 79

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FR 14670 (March 26, 2010).
FR 42128 (July 18, 2014).

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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.
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.
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.
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
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

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2023

2024

2025

0
719
0

3
814
600

5
921
1,200

Total Cellulosic Biofuel .........................................................................................................

719

1,417

2,126

The basis for these projections of
cellulosic biofuel production is
153 CAA

section 211(o)(1)(E).
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
154 One

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discussed in further detail in DRIA
Chapter 6.1. In this chapter we

acknowledge that there is significant
uncertainty regarding cellulosic biofuel

grain through conversion to cellulosic biofuel may
need to be replaced with additional feed.
155 See Landfill Gas Energy Project Data from
EPA’s Landfill Methane Outreach Program.

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.

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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

80623

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]
Average
growth rate
(%)

Growth rate time period

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2015–2019 .......................................................................................................
2015–2021 .......................................................................................................

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

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2023

30.4
26.3

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

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Projected production of CNG/LNG derived from
biogas
2024

955.4
896.2

1,245.8
1,131.9

2025
1,624.5
1,429.7

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

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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

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

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allow these adjustments to be made
without the need for a rulemaking
process.
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.

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2023–2025.161 High domestic
production capacity and availability of
The volume targets established by
imports indicate that volumes of nonCongress through 2022 anticipated
cellulosic advanced biofuel through
significant growth in advanced biofuel
2025 may meet or even exceed the
beyond what is needed to satisfy the
implied statutory target for 2022 (5
cellulosic standard. The statutory target billion ethanol-equivalent gallons).
for advanced biofuel in 2022 (21 billion Similarly, the feedstocks used to make
gallons) allowed for up to five billion
advanced biodiesel and renewable
gallons of non-cellulosic advanced
diesel (such as soy oil, canola oil, and
biofuel to be used towards the advanced corn oil, as well as waste oils such as
biofuel volume target, and indeed the
white grease, yellow grease, trap grease,
applicable standards for 2022 include
poultry fat, and tallow) currently exist
five billion gallons of non-cellulosic
in sufficient quantities globally to
advanced biofuel. As discussed in
supply increasing volumes. While these
Sections III.B.2 and III.B.3, we
feedstocks have many existing uses that
developed candidate volumes for nonmay require replacement with other
cellulosic advanced biofuel based on a
suitable substitutes, there is also
consideration of supply-related factors.
potential for ongoing growth in the
This process included a consideration
production of some of these feedstocks.
not only of production and import of
Higher implied volume requirements for
non-cellulosic advanced biofuels, but
non-cellulosic advanced biofuel may
also of the availability of qualifying
also have energy security benefits,
feedstocks. Based on this analysis of
increase domestic employment in the
supply-related factors, we estimated that biofuels industry, and increase income
some moderate growth after 2022 was
for biofuel feedstock producers.
Some of the factors assessed would
achievable.
support lower volumes of non-cellulosic
TABLE VI.B–1—NON-CELLULOSIC AD- advanced biofuel. For instance, as
VANCED BIOFUEL CANDIDATE VOL- described in DRIA Chapter 10, the cost
of biodiesel and renewable diesel is
UMES
significantly higher than petroleumbased diesel fuel and is expected to
Volume
Year
remain so over the next several years.
(million RINs)
Even if biodiesel and renewable diesel
2023 ..................................
5,100 blends are priced similarly to petroleum
2024 ..................................
5,200 diesel at retail after accounting for the
2025 ..................................
5,300
applicable federal and state incentives
(including the RIN value), the higher
We then analyzed these candidate
relative costs of biodiesel and renewable
volumes according to the other statutory diesel are still borne by society as a
factors.
whole. Moreover, the fact that sufficient
feedstocks exist to produce increasing
In practice the vast majority of nonquantities of advanced biodiesel and
cellulosic advanced biofuel in the RFS
renewable diesel does not mean that
program has been biodiesel and
those feedstocks are readily available or
renewable diesel, with relatively small
volumes of sugarcane ethanol and other could be diverted to biofuel production
advanced biofuels. Some of the statutory without some adverse consequences. As
factors assessed by EPA suggest that the described in DRIA Chapter 6.2, we
expect only limited quantities of fats,
targets for non-cellulosic advanced
biofuel established by Congress, or even oils, and greases and distillers corn oil
to be available for increased biodiesel
higher volumes, are still appropriate.
and renewable diesel production in
Notably, advanced biofuels have the
future years. We expect that the primary
potential to provide significant GHG
feedstock available to biodiesel and
reductions as they are required to
renewable diesel producers in
achieve at least 50 percent GHG
significant quantities through 2025 will
reductions relative to the petroleum
be soybean oil and other vegetable oils
fuels they displace.160
whose primary markets are for food.
Advanced biodiesel and renewable
Increased demand for soybean oil could
diesel together comprised 95 percent or
lead to diversion of feedstocks from
more of the total supply of nonfood and other current uses in addition
cellulosic advanced biofuel over the last to further incentivizing increased
several years. We have therefore focused
our attention on the impacts of these
161 We have also considered the potential for
increasing volumes of renewable jet fuel. Given its
fuels in determining appropriate levels
similarity to renewable diesel, for purposes of
of non-cellulosic advanced biofuel for

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B. Non-Cellulosic Advanced Biofuel

160 CAA

projecting appropriate volume requirements for
2023–2025, in most cases we consider renewable jet
fuel to be a component of renewable diesel.

section 211(o)(1)(B)(i).

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80625

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 noncellulosic 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

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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 longterm 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.

khammond on DSKJM1Z7X2PROD with PROPOSALS2

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
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

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come to expect that the applicable
percentage standards will include 15
billion gallons of conventional
renewable fuel, and has oriented its
operations accordingly.
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
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).

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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.
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 250million-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
164 CAA

section 211(o)(2)(A)(i).
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.
165 In

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Federal Register / Vol. 87, No. 250 / Friday, December 30, 2022 / Proposed Rules
requirement is effectively 15.25 billion
gallons rather than 15.00 billion gallons.
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.
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 250million-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
Cellulosic biofuel ..........................................................................................................................
Biomass-based diesel a ...............................................................................................................
Non-cellulosic advanced biofuel ..................................................................................................
Conventional renewable fuel .......................................................................................................
Supplemental volume requirement ..............................................................................................
a BBD

2024

0.72
2.82
5.10
15.00
0.25

1.42
2.89
5.20
15.25
0

2025
2.13
2.95
5.30
15.25
0

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
Cellulosic biofuel ..........................................................................................................................
Biomass-based diesel a ...............................................................................................................
Advanced biofuel .........................................................................................................................
Total renewable fuel ....................................................................................................................
Supplemental volume requirement ..............................................................................................

khammond on DSKJM1Z7X2PROD with PROPOSALS2

a BBD

2024

0.72
2.82
5.82
20.82
0.25

1.42
2.89
6.62
21.87
0

2025
2.13
2.95
7.43
22.68
0

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

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.

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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

khammond on DSKJM1Z7X2PROD with PROPOSALS2

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
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).

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establish the requirements and
standards for 2023–2025.

TABLE VI.F–1—POSSIBLE 2026 VOLUME REQUIREMENTS FOR COMPONENT CATEGORIES
Volume
(billion
RINs)

Category
Cellulosic biofuel .............................
Biomass-based diesel a ..................
Non-cellulosic advanced biofuel .....
Conventional renewable fuel ..........
a BBD

2.56
3.02
5.40
15.25

volumes are given in billion gallons,

TABLE VI.F–2—POSSIBLE 2026 VOLUME REQUIREMENTS FOR STATUTORY CATEGORIES
Volume
(billion
RINs)

Category
Cellulosic biofuel .............................
Biomass-based diesel a ..................
Advanced biofuel ............................
Total renewable fuel .......................
a BBD

2.56
3.02
7.96
23.21

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

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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
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.

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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.
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 ¢/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
¢/RIN.
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.
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

80629

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
(billion gallons)

Year
2023 ......................................
2024 ......................................
2025 ......................................

13,885
13,865
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
Cellulosic biofuel ..........................................................................................................................
Biomass-based diesel a ...............................................................................................................
Advanced biofuel .........................................................................................................................
Renewable fuel ............................................................................................................................
Supplemental standard ................................................................................................................

khammond on DSKJM1Z7X2PROD with PROPOSALS2

a The

2024

0.72
2.82
7.27
20.82
0.25

1.42
2.89
8.34
21.87
n/a

2025
2.13
2.95
9.19
22.68
n/a

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

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.

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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
172 See

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

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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.

TABLE VII–1—VOLUMES FOR USE IN DETERMINING THE PROPOSED APPLICABLE PERCENTAGE STANDARDS
[Billion RINs]
2023
Cellulosic biofuel ..........................................................................................................................
Biomass-based diesel a ...............................................................................................................
Advanced biofuel .........................................................................................................................
Renewable fuel ............................................................................................................................
Supplemental standard ................................................................................................................
a The

0.72
2.82
5.82
20.82
0.25

1.42
2.89
6.62
21.87
n/a

2025
2.13
2.95
7.43
22.68
n/a

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 nonrenewable 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
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2024

174 40

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

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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

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.

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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).
The projected gasoline and diesel
volumes in AEO 2022 include
projections of ethanol and biomassbased 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.

176 CAA

section 211(o)(3)(A)
for example, ‘‘EIA letter to EPA with 2020
volume projections 10–9–2019,’’ available in the
docket.
177 See,

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TABLE VII.A–1—AEO2022 GASOLINE AND DIESEL VOLUMES FOR THE CALCULATION OF PERCENTAGE STANDARDS FOR
2023–2025
Fuel category

Table

Gasoline ....................................................
Renewables blended into gasoline ...........
Diesel .........................................................
Renewables blended into diesel ...............

Table
Table
Table
Table

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).

2 ...........
2 ...........
11 .........
11 .........

Line
Total Energy Consumption/Motor Gasoline.
Energy Use & Related Statistics/Ethanol (denatured) Consumed in Motor Gasoline.
Product Supplied/by Fuel/Distillate fuel oil/of which: Diesel
Biofuels/Biodiesel + Biofuels/Other Biomass-derived Liquids.

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.
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.
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

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[Billion RINs]
Term

Description

RFVCB ............
RFVBBD ..........
RFVAB ............
RFVRF ............
G ....................
D .....................
RG ..................
RD ..................
GS ..................
RGS ................
DS ..................
RDS ................
GE ..................

Required volume of cellulosic biofuel .........................................................
Required volume of biomass-based diesela ...............................................
Required volume of advanced biofuel ........................................................
Required volume of renewable fuel ............................................................
Projected volume of gasoline ......................................................................
Projected volume of diesel ..........................................................................
Projected volume of renewables in gasoline ..............................................
Projected volume of renewables in diesel ..................................................
Projected volume of gasoline for opt-in areas ............................................
Projected volume of renewables in gasoline for opt-in areas ....................
Projected volume of diesel for opt-in areas ................................................
Projected volume of renewables in diesel for opt-in areas ........................
Projected volume of gasoline for exempt small refineries ..........................

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

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2023

for RFS Small Refinery Exemptions,’’ EPA–420–R–
22–011, June 2022.
179 We are not prejudging any small refinery
exemptions in this action; however, absent a

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2023
Supplemental

0.72
2.82
5.82
20.82
139.71
52.62
14.50
3.22
0
0
0
0
0

0
0
0
0.25
139.71
52.62
14.50
3.22
0
0
0
0
0

2024
1.42
2.89
6.62
21.87
139.46
52.47
14.50
3.22
0
0
0
0
0

2025
2.13
2.95
7.43
22.68
139.13
52.47
14.62
3.22
0
0
0
0
0

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.

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TABLE VII.C–1—VOLUMES FOR TERMS IN CALCULATION OF THE PROPOSED PERCENTAGE STANDARDS—Continued
[Billion RINs]
Term

Description

DE ..................

Projected volume of diesel for exempt small refineries ..............................

2023
Supplemental

2023
0

2024

2025
0

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
Cellulosic biofuel ..........................................................................................................................
Biomass-based diesel ..................................................................................................................
Advanced biofuel .........................................................................................................................
Renewable fuel ............................................................................................................................
Supplemental standard ................................................................................................................

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.

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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.
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
180 75

FR 14670, 14729 (March 26, 2010).

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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
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
181 79

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2024

0.41%
2.54
3.33
11.92
0.14

0.82
2.60
3.80
12.55
n/a

2025
1.23
2.67
4.28
13.05
n/a

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 nonliquid 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

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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.
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, lowGHG renewable fuels—such as
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/approvedpathways-renewable-fuel.
183 79 FR 42128 (July 18, 2014).

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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 ethanolequivalent gallons in 2021.
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.
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 RINgenerating pathways for eRINs, will be
184 Id.
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.
186 See 75 FR 14686 (March 26, 2010).

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80633

considered beyond the scope of this
rulemaking.
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.
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
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 lightduty electric vehicle is a vehicle that is both a lightduty vehicle (i.e., light-duty vehicle or light-duty
truck) and an electric vehicle (i.e., electric vehicle
or plug-in electric hybrid vehicle).

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biogas as a valid form of advanced
biofuel.
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
A. Historical Treatment of Electricity in
transfer them for the purpose of
the RFS Program
achieving the required annual volumes
1. Statutory Authority and Regulatory
of renewable fuels. Although the credit
History
system must provide ‘‘for the generation
of an appropriate amount of credits by
Congress established the RFS2
any person that refines, blends, or
program in the 2007 Energy
imports gasoline that contains a
Independence and Security Act (EISA).
quantity of renewable fuel that is greater
Among other revisions to the prior RFS1
than’’ the statutory volume, as well as
program that had been established by
for the generation of credits for biodiesel
EPAct2005, EISA defined renewable
and by small refineries,192 the statute
fuel as ‘‘fuel that is produced from
does not limit credit generation to these
renewable biomass and that is used to
parties, nor does it specify the
replace or reduce the quantity of fossil
mechanics of credit generation, transfer,
fuel present in a transportation fuel.’’ 188
or disposition.
EISA also provided a definition of
Finally, EISA required EPA to
‘‘renewable biomass,’’ enumerating the
conduct a study and issue a report to
seven categories of feedstocks that can
Congress on the feasibility of issuing
be used to produce qualifying renewable credits under the RFS program for
189
fuel under RFS2.
This statutory
renewable electricity used in electric
definition of renewable biomass
vehicles.193 In the 2010 rulemaking in
includes separated yard waste,
which EPA promulgated regulations to
separated food waste, animal waste
implement the RFS2 program, EPA
material, and crop residue, any of which
determined that electricity, as well as
could be used to produce biogas through
natural gas and propane, could meet the
190
anaerobic digestion.
Additionally, the statutory definition of renewable fuel
statutory definition of advanced biofuel and thus be eligible to generate RINs if
codified at CAA section
it was made from renewable biomass
211(o)(1)(B)(ii)(V) explicitly identifies
and if parties could ‘‘identify the
specific quantities of their product
188 CAA section 211(o)(1)(J).
which are actually used as a
189 CAA section 211(o)(1)(I).
transportation fuel.’’ 194 In the same
190 Biogas was explicitly included in EPAct2005
rulemaking, EPA established a
as a renewable fuel at CAA section
qualifying RIN-generating pathway for
211(o)(1)(C)(i)(I)(bb) and therefore was included in
the RFS1 program that applied from 2006–2009. In
biogas used as transportation fuel as an

khammond on DSKJM1Z7X2PROD with PROPOSALS2

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.

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).

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191 CAA

section 211(o)(2)(A)(i).
192 CAA section 211(o)(5).
193 Public Law 110–140, 206(b)–(c) (2007).
194 75 FR 14670, 14686 (March 26, 2010).

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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.
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.
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, noncommercial 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)
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).
196 79 FR 42128 (July 18, 2014).
197 40 CFR 80.1426(f)(10)(i).

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where the renewable electricity is
directly supplied as transportation fuel
to EVs could generate RINs.
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.
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.
198 40

CFR 80.1426(f)(11)(i).

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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.
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.
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
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.’’
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.

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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 doublecounting we did receive focused on the
fact that EPA could avoid doublecounting 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 RINgenerating pathways (e.g., Row Q or T)
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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.
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 onsite 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
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
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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
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.

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

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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.

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

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specifications, it is presumed that it will
be used as transportation fuel.
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.
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
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
208 EIA estimates that in 2020 only about 3
percent of natural gas was used for transportation,
see https://www.eia.gov/energyexplained/naturalgas/use-of-natural-gas.php.
209 See 40 CFR 80.1426(f)(11)(ii).

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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/

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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.

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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 biogasderived 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.
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
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).

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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.
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:
• 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
211 https://www.epa.gov/lmop/landfill-gas-energyproject-data.
212 https://www.epa.gov/agstar/livestockanaerobic-digester-database.
213 For years after 2015, conventional renewable
fuel remains constant at 15 billion gallons, and noncellulosic 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).
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

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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.
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
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.
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
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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 petroleumbased 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.
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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

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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.
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
217 See

further discussion in Section VIII.F.

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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

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ensuring the integrity of eRINs. To these
ends, we have drawn from experience
with existing programs such as the
current regulations governing biogasbased 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 EPAapproved 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
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 RINgenerating pathways in this action.
However, we are proposing a new set of
implementation requirements including
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.

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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

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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.
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 RINgenerating 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.
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 ‘‘topdown’’ approach as described below.
We acknowledge that both approaches
are potentially implementable. The
221 See

40 CFR 80.1426(f)(17).
e.g., 75 FR 14686, 14729 (March 26,

222 See,

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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, thirdparty 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

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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

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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 topdown 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.
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
223 We discuss the differentiation between BEVs
and PHEVs further in RIA Chapters 1 and 2.

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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
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
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.

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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 ethanolequivalent gallon of renewable fuel), can
result from either intentional or
unintentional actions.
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
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-fuelstandard-program.
226 See 40 CFR 80.1426(f)(11)(i)(F).

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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.
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.
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
227 See

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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 resourceintensive 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

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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.
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 biogasderived renewable CNG/LNG contain a
flexible, but resource-intensive set of
regulatory provisions that we believe
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.

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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
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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
229 79

FR 42128, July 18, 2014.
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
230 We

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additional eRIN pathways in the future
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accommodate them as needed.

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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
biogas to electricity under 40 CFR 80.1416 at the
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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

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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.
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 heavyduty 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.
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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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.
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 lightduty EVs would be appropriate for the
future market of medium- and heavyduty 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 lightduty and heavy-duty. How the mediumand 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
234 https://calstart.org/wp-content/uploads/2022/
07/ZIO-ZETs-June-2022-Market-Update.pdf

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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 lightduty 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 heavyduty 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

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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, offhighway 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

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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
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.

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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
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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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.
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
237 See https://www.energy.gov/oe/services/
electricity-policy-coordination-andimplementation/transmission-planning/recoveryact-0.

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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

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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

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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 thirdparty 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
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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

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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.

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F. Proposed Program Structure for LightDuty 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 nonqualifying 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

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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 contractualbased 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
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.

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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.
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, noncommercial 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 minigrid 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.
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
239 EPA’s existing regulations contain a
framework for RIN generation for electricity
distributed only via a closed, private, noncommercial 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.

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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 EPAapproved 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

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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 resourceintensive 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

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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

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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

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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
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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.
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.
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
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.
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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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.
In order to be able to generate the
calculated maximum eRINs for its lightduty 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.
243 Discussion on current disaggregation of PHEVs
and BEVs presented in Chapter 6.1.4.1 of DRIA.
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.

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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.
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.
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
247 ‘‘Examples of RIN generation under the
proposed RFS eRIN provisions,’’ available in the
docket for this action.
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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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

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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
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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
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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.
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
249 See

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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 ‘‘manyto-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
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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

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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

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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
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
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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qualifying biogas used when nonqualifying 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 coprocessing 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 coprocessed 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
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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 biogasto-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

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

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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.
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
253 CAA

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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
254 EIA form 860, Section 6, https://www.eia.gov/
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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.
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.

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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

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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 topdown 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

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limitation on contracting for RNG as
discussed in Section IX.I and for
biointermediates as recently finalized in
the 2020–2022 RFS rulemaking.255
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
255 See

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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

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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

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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
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).

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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 doublecounting of electricity use.
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

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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

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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.
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 nontransportation purposes.258 Similarly, in
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.
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

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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.
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
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.

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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 consumptionside 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

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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 buildout, 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
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
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/presidentbiden-doe-and-dot-announce-5-billion-over-fiveyears-national-ev-charging.
261 H.R. 5376, SEC. 13404.

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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

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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.
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.
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
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.
263 ‘‘Charging at Home—Department of Energy.’’
Available: https://www.energy.gov/eere/
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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

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 topdown 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.
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,

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

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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.
3. OEM-Centered Approach Using
Telematics Data

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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.
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

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

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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, homebased 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.
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
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
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.

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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
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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.
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
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.

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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.
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
270 https://cleanfuelreward.com.
271 https://ww2.arb.ca.gov/resources/documents/
lcfs-utility-rebate-programs.
272 ‘‘A Preliminary Assessment of RIN Market
Dynamics, RIN Prices, and Their Effects,’’ available
in the docket.

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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

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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
272 ‘‘A Preliminary Assessment of RIN Market
Dynamics, RIN Prices, and Their Effects,’’ available
in the docket.

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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

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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

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

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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

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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
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
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
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.
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.

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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

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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.

TABLE VIII.I.1–1—RIN EQUIVALENCE VALUES FOR VARIOUS LIQUID RENEWABLE FUELS
Energy content
(Btu/gal)

Fuel type

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Ethanol .............................................................................................................................................................
Biodiesel ..........................................................................................................................................................
Renewable diesel ............................................................................................................................................
Butanol .............................................................................................................................................................

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.
277 See

40 CFR 80.1415.

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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.
Another point raised by several
stakeholders is that an energy contentbased 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
278 See

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1.5
1.7
1.3

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

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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.

Figure VIII.1.3-1: Illustration of the impact of point-of-measure for landfill gas used
to power electric vehicles (upper path) or as RNG for CNG/LNG vehicles (lower
path).

Cleaned
Landfill Gas

Electricity
Generation

Electricity
Transmission

Battery
Charging

Vehicle Drive
Energy

Point of Measure

Compression
and Uprating

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

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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 biogasderived 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

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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

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

80669

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.

Figure VIII.1.3-2: Illustration of the computation pathway (arrows) and energy
values used in determining the proposed revised equivalence value

Cleaned

Compression

Pipeline

Landfill Gas

and Uprating

Transport

Vehicle
Fueling

Vehicle Drive
Energy

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

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.

281 eGRID 2019 Technical Guide, prepared by Abt
Associates for U.S. EPA Clean Air Markets Division,
February 2021.

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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
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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 biogasderived renewable fuels as follows:
• 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 biogasderived renewable fuels (e.g.,
registration, reporting, and
recordkeeping requirements).
We believe that this subpart and
structure would make the biogasderived renewable fuel provisions more
accessible to all stakeholders, help
ensure compliance by making
requirements more easily identifiable,
and help future participants in biogasderived 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
282 See

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

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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 EPAaccepted 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
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
285 75

FR 76790 (December 9, 2010).

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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 nonRFS 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.
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
286 85

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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 pipelinequality 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

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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
To describe biogas-derived pipelinequality 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
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.
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.

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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.
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 nontransportation 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
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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 thirdparty 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.
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
289 See

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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 lightduty 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.
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
290 For basic registration information, see 40 CFR
1090.805.

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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.
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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

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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.
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.
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
291 See

40 CFR 80.1451(b)(1)(ii).
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.
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.
292 See

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comment on the draft reporting forms
that have been added to the docket.296
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.
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
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.
297 The PTD requirements for RFS are described
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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

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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 QAPrelated submissions. For the proposed
eRINs program, the recordkeeping
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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.

80675

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.
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:
• 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 nonrenewable 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

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.

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.

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.

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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 measurementrelated 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 thirdparty 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
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
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.

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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.
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
301 See ANSI C12.20–20, ‘‘Electricity Meters 0.2
And 0.5 Accuracy Classes,’’ available in the docket
for this action.

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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.
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 doublecounting 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
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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 doublecounting 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 doublecounted. 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 EPAapproved 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
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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.

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

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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.
b. Liability Provisions for Biogas, RNG,
Renewable Electricity, and BiogasDerived 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 biogasderived 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 biogasderived 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

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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
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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 selfidentified 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

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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 biogasderived 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 biogasderived 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

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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,

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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 domesticgenerated 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 RINgenerating foreign producer or having
the importer of the RNG generate a RIN
for the RNG. This is the same flexibility
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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 RINgenerating 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 foreignproduced renewable electricity, the

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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 RINgenerating 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
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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.
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.
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
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independence requirements for thirdparty 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 thirdparty 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 thirdparty 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 thirdparty 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 thirdparty 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
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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 thirdparty 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 thirdparty auditors could be unduly
influenced in their QAP verification
activities as a result. With regard to
companies that employ personnel who
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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.
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 thirdparty professional engineers by
requiring those engineers to comply
with similar requirements (including
the additional requirements we are
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proposing) to those that currently apply
to independent third-party auditors.
We are also proposing to improve the
RFS registration requirements for threeyear 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 thirdparty 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 thirdparty 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
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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

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January 31 deadline. Due to extenuating
circumstances, we have on a case-bycase basis allowed for site visits to occur
up to a full calendar year prior to the
deadline.
We now have concerns that thirdparty 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 thirdparty 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 threeyear 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

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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.
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
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).
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.

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

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cellulosic RINs being generated on noncellulosic feedstocks.
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 noncellulosic 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.
At the same time, there are also
features of co-processing in a digester
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.

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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 coprocessing 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
Based on the differences discussed
above, we are proposing new and
separate equations to determine
feedstock energy for when
predominantly cellulosic and nonpredominantly 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
317 Karki et al. Bioresource Technology 330 (2021)
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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 nonpredominantly 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

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

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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.
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 nonpredominantly 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 Dcode 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.

80685

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.
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.
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:

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

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.

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323 86

FR 72474 (December 21, 2021).
75 FR 14670, 14682 (March 26, 2010).
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).
324 See

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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 optsin, 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
§§ 80.1441 and 80.1442.
DEi = The total amount of diesel projected to
be exempt in year i, in gallons, per
§§ 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

Figure IX.D-1: Average Equivalence Value for BBD Containing Both Biodiesel and
Renewable Diesel
1.58
1.57
~

~
~

1.56 - - - - - - - - - - - - - - - - - - - 1.55

.!!
-~
::, 1.54

---------------#------

.2'
gi, 1.s3

f:
11.52

2012

2013

2014

2015

2016

2017

2018

2019

2020

2021

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.

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).
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

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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

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

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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.

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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).
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
331 Office of the Federal Register, National
Archives and Records Administration, ‘‘Document
Drafting Handbook,’’ August 2018 Edition (Revision
1.4), January 7, 2022.

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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 RINgenerating 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

80687

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.
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.
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

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

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332 Hydrogen Production: Natural Gas Reforming.
Department of Energy, https://www.energy.gov/
eere/fuelcells/hydrogen-production-natural-gasreforming.
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.’’
334 Argonne Greenhouse gases, Regulated
Emissions, and Energy use in Technologies
(GREET) Model, https://greet.es.anl.gov.

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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.
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

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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
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
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.
336 Clean Air Act section 211(o)(1)(H).
337 March 2010 RFS2 rule (75 FR 14670).

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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 nonmethane 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.
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 reformingwith 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.

338 EPA Landfill Methane Outreach Program
(LMOP), Basic Information about Landfill Gas,
https://www.epa.gov/lmop/basic-informationabout-landfill-gas.
339 Hydrogen Production: Natural Gas Reforming,
Department of Energy, Hydrogen and Fuel Cell
Technologies Office, https://www.energy.gov/eere/
fuelcells/hydrogen-production-natural-gasreforming.

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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.
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.
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 endusers, 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

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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.

TABLE IX.H.2–1—ELECTRICITY REQUIRED FOR HYDROGEN FUEL COMPRESSION AND PRE-COOLING FROM GREET 2021
[kWh/kg H2]
Compressor to
load gaseous
tube-trailer for
H2 delivery

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Centralized Gaseous Hydrogen Fuel Production:
Light-Duty FCEVs (700 bar H2) 343 ............................................................................................................
Medium- and Heavy-Duty FCEVs (350 bar H2) ........................................................................................
Distributed Hydrogen Fuel Production:
Light-Duty FCEVs (700 bar H2) .................................................................................................................
Medium- and Heavy-Duty FCEVs (350 bar H2) ........................................................................................

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

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hydrogen fuel production site but eliminates the
need to transport the finished hydrogen fuel to a
separate location.
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

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H2 compressor
at vehicle
refueling
station

Pre-cool
H2 for vehicle
refueling

1.30
............................

1.98
1.25

0.30
............................

N/A
............................

3.11
2.27

0.30
............................

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.
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.

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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
GREET
default
assumptions
Domestic & International Land Use Change ...................................................
Feedstock Production & Transport ..................................................................
Fuel Production ................................................................................................
Tailpipe ............................................................................................................
Lifecycle GHG Emissions ................................................................................

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

GREET using
NREL H2A
assumptions

0.0
9.2
11.4
0.0
20.5

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 gridbased 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

Liquid hydrogen fuel

0.0
9.2
25.8
0.0
34.9

GREET
default
assumptions

GREET using
NREL H2A
assumptions

0.0
10.0
39.0
0.0
49.0

0.0
10.0
53.6
0.0
63.5

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.

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
assumptions

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Domestic & International Land Use Change ...................................................................................................
Feedstock Production & Transport ..................................................................................................................
Fuel Production ................................................................................................................................................
Tailpipe ............................................................................................................................................................
Lifecycle GHG Emissions ................................................................................................................................

0.0
12.2
18.5
0.0
30.7

GREET using
NREL H2A
assumptions
0.0
12.2
20.1
0.0
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

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.
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.

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Federal Register / Vol. 87, No. 250 / Friday, December 30, 2022 / Proposed Rules
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.
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 dieselpowered vehicles using an energyequivalent 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
One consideration in assessing
hydrogen FCEV efficiency data is that
values for this relatively nascent
technology vary significantly across
government sources and the peerreviewed literature. Another
consideration is that the varied vehicle
duty cycles can yield significantly

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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
FCEVs to
conventional
vehicles

Source

California Air Resources Board (Low Carbon Fuel Standards) 348.

1.9
2.5

Argonne National Laboratory (GREET 2021 Well-to-Wheels
Calculator) 349.

1.95
2.35

National Renewable Energy Laboratory Report: Spatial and
Temporal Analysis of the Total Cost of Ownership for
Class 8 Tractors and Class 4 Parcel Delivery Trucks
(FastSIM) 350.

1.28

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1.54

Details

Heavy-Duty/Off-Road Applications (Fuels used as diesel replacement) Energy Economy Ratio (EER) Values Relative
to Diesel.
Light/Medium-Duty Applications (Fuels used as gasoline replacement) Energy Economy Ratio (EER) Values Relative
to Gasoline.
Vehicle fuel efficiency comparison between a modeled diesel passenger vehicle (3,553 btu/mile) divided by modeled hydrogen gas passenger vehicle (1,825 btu/mile).
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).
Comparison of current class 8 long haul (750 miles) modeled FCEV truck fuel efficiency (11 miles/diesel-gallon
equivalent) divided by comparable diesel truck efficiency
(8.6 mi/dge).
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.
For a conservative estimate to
illustrate this approach, we can use the
lowest vehicle efficiency factor in Table

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.
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.
348 California Code of Regulations, Title 17,
§ 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.

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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 gasolinepowered 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: gaseous
hydrogen fuel
Lifecycle GHG Emissions (GREET Default Assumptions) ..............................................
Adjusted Lifecycle GHG Emissions (Assuming Low Vehicle Efficiency Factor: 1.28) ...
Adjusted Lifecycle GHG Emissions (Assuming High Vehicle 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 RINgenerating 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.

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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
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.

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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.
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.
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.

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Centralized
SMR: liquid
hydrogen fuel

20.5
16.0
8.2

Distributed
SMR: gaseous
hydrogen fuel

30.7
24.0
12.3

49.0
38.2
19.6

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
354 See

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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 biogasderived 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 wellsuited to avoid the double counting of
RNG where RNG could be used under
the RFS program for more than one use.
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

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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:
• 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.
355 See

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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 EPAapproved 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
356 See

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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.
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 biogasderived 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
357 79

FR 42128, 42144 (July 18, 2014).

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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.
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.

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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.
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
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.

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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.
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
359 40

CFR 80.1429.

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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

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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
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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
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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
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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
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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.
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
360 RFS0601: Renewable Fuel Producer
Supplemental report.
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.

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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.
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

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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

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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
362 See

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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.
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.

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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.
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
363 See

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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.
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
364 See

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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

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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 RINgenerating 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 biogasderived 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

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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)
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

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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.
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).
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
under the control of the same person (or persons
under common control).’’
366 Questions and Answers on the Renewable
Fuel Standard Program. Page 7. https://
nepis.epa.gov/Exe/
ZyPDF.cgi?Dockey=P1001T9Z.pdf.

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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 thirdparty 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
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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.
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
367 CAA
368 40

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CFR 80.1454(d).

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(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
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.
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
369 40

CFR 80.1450(1)(vii)(B).
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.’’).
372 85 FR 7016, 7078 (Feb. 6, 2020).
373 Id. at 7062.
370 81

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producers ‘‘had no opportunity to
comment because EPA failed to mention
this new recordkeeping requirement in
the proposed rule.’’ 374
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.
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
374 RFS Power Coalition v. U.S. EPA, No. 20–1046
(D.C. Cir.), Doc. #1882940 at 38–39, filed Jan. 29,
2021.
375 We are not requesting comment on or
reopening the requirement at 40 CFR 80.1454(d).

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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

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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
376 Cal.

Code Regs. tit. 17, § 95488.
377 Cal. Code Regs. tit. 17, § 95488(b).
378 Cal. Code Regs. tit. 17, § 95488(b).
379 Cal. Code Regs. tit. 17, § 95488.8(g).

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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 chainof-custody requirements, including the
underlying records, are verified
annually by an independent third
party.382
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
380 Cal. Code Regs. tit. 17, § 95488.8(g)(1)(B)(1)
through (3).
381 Cal. Code Regs. tit. 17, § 95488.8(g)(1)(B).
382 Cal. Code Regs. tit. 17, §§ 95491.1(a)(2) and
95491.1(c)(2)(I).

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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 § 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 subprong (3), however, is not further
defined in the regulations.
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

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
383 CAA

section 211(o)(1)(L).
CFR 80.1407(f)(8).
385 40 CFR 80.1401.
386 75 FR 14670, 14721 (March 26, 2010).
384 40

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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

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
387 U.S.

EPA, Renewable Fuel Standards Program
(RFS2) Summary and Analysis of Comments, at 3–
198–3–200. (February 2010).

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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 nontransportation 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

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provisions provide significant flexibility
regarding the designation, distribution,
and use of distillate fuels that meet the
ULSD standards.
L. Bond Requirement for Foreign RINGenerating 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.
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.
388 72

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

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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 reproposing 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
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.
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.

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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.
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
391 See definition of ‘‘produce.’’ Oxford
Languages Dictionary. https://languages.oup.com/
google-dictionary-en.

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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 nonrenewable 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.
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, e392 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 nonrenewable natural gas) in the equivalence value for
biodiesel.

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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 nonrenewable 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

80705

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]

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Definition of ‘‘produced from
renewable biomass’’
Fuel

Feedstock

Process energy

Ethanol ............................................
Biodiesel .........................................
CNG/LNG .......................................
Hydrogen (SMR) .............................
Hydrogen (SMR) .............................
Hydrogen (Electrolysis) ..................
Hydrogen (Electrolysis) ..................
Electricity ........................................
eFuel ...............................................
eFuel ...............................................
eFuel ...............................................

Corn Starch ....................................
Soybean Oil and Methanol ............
Biogas ............................................
Biogas and Water ..........................
Biogas and Water ..........................
Water ..............................................
Water ..............................................
Biogas ............................................
Renewable Biomass CO2 ..............
Renewable Biomass CO2 ..............
Non-Renewable Biomass CO2 (Air
Capture or Fossil CO2).

Natural Gas ....................................
Natural Gas ....................................
Grid Electricity ................................
Biogas ............................................
Natural Gas ....................................
Biogas Electricity ............................
Wind/Solar Electricity .....................
Biogas ............................................
Wind/Solar Electricity .....................
Coal/Natural Gas Electricity ...........
Biogas Electricity ............................

In this rule, we are proposing to add
a definition of ‘‘produced from

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renewable biomass’’ to the regulations at
40 CFR 80.2. We propose that produced

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Energy from
renewable
biomass
(%)
100
95
100
100
65
100
0
100
0
0
100

Mass from
renewable
biomass
(%)
100
95
100
50
50
0
0
N/A
90
90
0

from renewable biomass means that the
energy in the finished fuel or

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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
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
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.
395 The fuel would also have to meet the other
requirements for qualifying as a renewable fuel,

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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.
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.
We are also proposing changes to
regulatory provisions related to coprocessed fuels to ensure that they
would be consistent with the proposed
definition of produced from renewable
biomass. The existing regulations
including being used to replace or reduce the
quantity of fossil fuel present in a transportation
fuel and meeting the GHG reduction requirements.
396 Draft Regulations for the Alternative
Definition of Produced from Renewable Biomass.
Memorandum from EPA to Docket EPA–HQ–OAR–
2021–0427.
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.

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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 coprocessed 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 coprocessed intermediate to mean a fuel or
intermediate that contains energy from
both renewable biomass and nonrenewable 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 coprocessed. 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

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do not co-process renewable biomass
with non-renewable biomass feedstocks
or have already been registered for coprocessing 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 fossilderived 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.
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
398 See

40 CFR 80.1426(f)(2).

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would need to be increased from
123,500 Btu/gallon to account for the
non-renewable portion of the coprocessed 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
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
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
399 See ‘‘Calculation of Equivalence Values for
renewable fuels under the RFS program’’ Docket
Item No. EPA–HQ–OAR–2005–0161–0046.
400 See 40 CFR 80.1426(b).

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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 socalled 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.

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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 ..............................................................................
80.2 ..............................................................................

Adding definition of business days consistent with the definition at 40 CFR 1090.80.
Clarifying the definition of renewable fuel to specify that fuel must be used in the covered
location.
Removing all references to ‘‘the Administrator’’ and replacing them with ‘‘EPA’’.
Amending the definition of certified non-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.
Clarifying that renewable naphtha may be blended to make E85.
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.
Clarifying that independent third-party auditors must review all relevant documentation
required under the RFS program when verifying elements under the QAP program.
Amending to correct cross-reference from 40 CFR part 32 to 2 CFR part 1532.
Amending to correct the list of states that are part of PADD II.
Clarifying that RCOs may add a delegate, as allowed under 1090.800(d).
Amending to add a missing word.

80.4, 80.7, 80.24, and 80.1415 through 80.1478 ........
80.1401, 80.1408, and 1090.1015 ..............................

80.1401 and 80.1453(a)(12) ........................................
80.1450(b)(1)(viii)(E) ....................................................
80.1469(c)(6) ...............................................................
1090.55(c) ....................................................................
1090.80 ........................................................................
1090.805(a)(1)(iv) ........................................................
1090.1830(a)(3) ...........................................................

X. Statutory and Executive Order
Reviews
Additional information about these
statutes and Executive Orders can be
found at https://www.epa.gov/lawsregulations/laws-and-executive-orders.

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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

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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.

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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

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

DRIA Chapter 10.
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.
402 For

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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

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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
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.
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
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.
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.

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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.
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.)

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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 0.1, 0.2, And 0.5 Accuracy
Classes, February 17, 2017.
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 14.3.1–2012, 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-edged Orifice Meters Part 1: General Equations and
Uncertainty Guidelines, 4th Edition, September 2012.
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-edged Orifice Meters Part 2: Specification and Installation Requirements, 5th Edition, March 2016.
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-edged Orifice Meters Part 3: Natural Gas Applications, 4th Edition, November 2013.
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-edged Orifice Meters Part 4—Background, Development, Implementation Procedure, and Example Calculations, 4th Edition, September 2019.
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.
APHA 2540, Solids In: Standard Methods For the Examination of
Water and Wastewater, approved 2015, revised 2020.

Standard for measuring the flow of electrical power, including physical
aspects of the meter as well as performance criteria.
Standard describing how to collect, handle, and transfer gas samples
for chemical analysis.

ASTM D3588–98(2017)e1, Standard Practice for Calculating Heat
Value, Compressibility Factor, and Relative Density of Gaseous
Fuels, approved April 1, 2017.
ASTM D4888–20, Standard Test Method for Water Vapor in Natural
Gas Using Length-of-Stain Detector Tubes, approved December 15,
2020.
406 U.S. EPA (2022). Estimation of Population
Size and Demographic Characteristics among

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Standard describing engineering equations, installation requirements,
and uncertainty estimations of square-edged orifice meters in measuring the flow of natural gas and similar fluids.

Standard describing design and installation of square-edged orifice meters for measuring flow of natural gas and similar fluids.

Standard describing applications using square-edged orifice meters for
measuring flow of natural gas and similar fluids.

Standard describing the development of equations for coefficient of discharge, including a calculation procedure, for square-edged orifice
meters measuring flow of natural gas and similar fluids.

Standard describing the calculation of flow using gas vortex meters for
measuring the flow of natural gas and similar fluids.
Standard describing how to measure the total solids, volatile solids,
and other solid properties of wastewater sludge and similar substances.
Calculation protocol for aggregate properties of gaseous fuels from
compositional measurements.
Standard specifying how to measure water vapor concentration in gaseous fuel samples

People Living Near Truck Routes in the

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Conterminous United States. Memorandum to
Docket.EPA–HQ–OAR–2019–0055.

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80711

TABLE X.I1—STANDARDS AND TEST METHODS TO BE INCORPORATED BY REFERENCE—Continued
Organization and standard or test method

Description

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 D7164–21, On-line/At-line Heating Value Determination of Gaseous Fuels by Gas Chromatography, approved April 1, 2021.
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.

Standard specifying how to measure sulfur-containing compounds in a
gaseous fuel sample.

Incorporation by reference, Oil imports,
Petroleum, Renewable fuel.

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, lowincome 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 nonGHG 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.

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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,

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Standard specifying how to use and maintain an on-line gas chromatogram for determining heating value of a gaseous fuel.
Standard specifying how to measure silicon-containing compounds in a
gaseous fuel sample.

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
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
■

2. Revise § 80.2 to read as follows:

§ 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
§ 80.1469(a) following the audit process
specified in § 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

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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 § 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 § 80.1426 or in a
petition approved under § 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’’,

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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
§ 80.1469(b) following the audit process
specified in § 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 § 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
§ 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 § 80.1426.
(ii) A process identified in a pathway
listed in a petition approved under
§ 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 § 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.

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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.

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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 § 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

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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, hemicellulose, 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 § 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
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(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 nonrenewable material and for which the
volume of renewable fuel or

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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 § 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 noncultivated 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.

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(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 § 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
§ 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
§ 80.1425(g), generated under § 80.1426,
and submitted under § 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

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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 allelectric 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

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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 § 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.

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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 § 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
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(2) For purposes of subpart M of this
part, any and all of the products
specified at § 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 nonpetroleum 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 § 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 °C and pressure = 1 atm), excluding
natural gas.
Locomotive engine means an engine
used in a locomotive as defined under
40 CFR 92.2.

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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 °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 § 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

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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 § 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 § 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,

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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

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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 § 80.1469(c) following
the audit process specified in § 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
§§ 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 °F (38 °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

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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

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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
§ 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
§ 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
§ 80.2.
Renewable Identification Number
(RIN) is a unique number generated to
represent a volume of renewable fuel
pursuant to §§ 80.1425 and 80.1426.
(1) Gallon-RIN is a RIN that represents
an individual gallon of renewable fuel
used for compliance purposes pursuant

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to § 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
§ 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 § 80.140.

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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 § 80.140(d).
RNG used as a feedstock means any
RNG used to produce renewable fuel
(including renewable electricity) under
§ 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 oceangoing 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 machineplanting of a seed or sapling, or by
coppice growth from the stump or root
of a tree that was hand- or machineplanted. Tree plantations must have
been cleared prior to December 19, 2007
and must have been actively managed
on December 19, 2007, as evidenced by

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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 abovementioned 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 thirdparty auditor to be valid. Verified RINs
includes A–RINs, B–RINs, and Q–RINs.
Wholesale purchaser-consumer
means any person that is an ultimate

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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.
■ 3. Revise § 80.3 to read as follows:
§ 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/federalregister/cfr/ibr-locations.html or email
fr.inspection@nara.gov. 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 § 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 § 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-edged Orifice Meters Part 1:
General Equations and Uncertainty
Guidelines, 4th Edition, September 2012
(‘‘API MPMS 14.3.1’’); IBR approved for
§ 80.165(a).

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(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-edged Orifice Meters Part 2:
Specification and Installation
Requirements, 5th Edition, March 2016
(‘‘API MPMS 14.3.2’’); IBR approved for
§ 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-edged Orifice Meters Part 3:
Natural Gas Applications, 4th Edition,
November 2013 (‘‘API MPMS 14.3.3’’);
IBR approved for § 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-edged Orifice Meters Part 4—
Background, Development,
Implementation Procedure, and
Example Calculations, 4th Edition,
September 2019 (‘‘API MPMS 14.3.4’’);
IBR approved for § 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 § 80.165(a).
(c) American Public Health
Association (APHA), 1015 15th Street
NW, Washington, DC 20005; (202) 777–
2742; https://www.standard
methods.org.
(1) SM 2540, Solids In: Standard
Methods For the Examination of Water
and Wastewater, approved June 10,
2020 (‘‘SM 2540’’); IBR approved for
§ 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 §§ 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 § 80.1426(f).

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(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 § 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
§ 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
§ 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 § 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 § 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 § 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 §§ 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 § 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
§ 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
§ 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 § 80.1426(f).

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§ 80.4

80719

[Amended]

4. Amend § 80.4 by removing the text
‘‘The Administrator or his authorized
representative’’ and adding, in its place,
the text ‘‘EPA’’.
■ 5. Amend § 80.7 by:
■ a. Revising paragraph (a) introductory
text;
■ b. In paragraph (b), removing the text
‘‘the Administrator, the Regional
Administrator, or their delegates’’ and
adding, in its place, the text ‘‘EPA’’; and
■ c. Revising the first sentence of
paragraph (c).
The revisions read as follows:
■

§ 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 purchaserconsumer, 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 purchaserconsumer, 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. * * *
■ 6. Revise § 80.9 to read as follows:
§ 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
§ 80.24

[Amended]

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

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80720

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

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.

khammond on DSKJM1Z7X2PROD with PROPOSALS2

§ 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 biogasderived 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

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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 § 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 § 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
§ 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 § 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.
§ 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

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part, regardless of whether the
requirements are identified in this
section.
(5) The transfer and batch segregation
limits specified in § 80.1476(g) do not
apply.
(b) Registration. The biogas producer
must register with EPA under §§ 80.145,
80.1450, and 40 CFR part 1090, subpart
I, as applicable.
(c) Reporting. The biogas producer
must submit reports to EPA under
§§ 80.150 and 80.1451, as applicable.
(d) Recordkeeping. The biogas
producer must create and maintain
records under §§ 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 § 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 § 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
§ 80.1426(f)(3)(vi) at least once per
calendar month.
(2) All sampling, testing, and
measurements must be done in
accordance with § 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
§ 80.170.
(h) Attest engagements. The biogas
producer must submit annual attest
engagement reports to EPA under
§§ 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
§ 80.180.

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VBG,p

= VBG * FEtotal

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
§ 80.1426(f)(3)(vi).
FEtotal = Sum of feedstock energies from all
feedstocks used to produce biogas, in
Btu, per § 80.1426(f)(3)(vi).

(ii) The total volume of biogas
produced must be calculated as follows:
VBG = VG * R

khammond on DSKJM1Z7X2PROD with PROPOSALS2

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 § 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 nonrenewable feedstocks, R must be
measured by a carbon-14 dating test
method, per § 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.

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§ 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 §§ 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 § 80.150.
(d) Recordkeeping. The renewable
electricity generator must create and
maintain records under § 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 § 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

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of electricity, in kWh, produced at the
renewable electricity generation facility.
(2) All measurements must be done in
accordance with § 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
§ 80.170.
(h) Attest engagements. The
renewable electricity generator must
submit annual attest engagement reports
to EPA under § 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 § 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 § 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:

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EP30DE22.008

FEP

(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.

EP30DE22.030

(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 EPAissued 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:

80721

80722

for RIN generation if biogas is the only
feedstock used to produce electricity at
the renewable electricity generation
facility during that month.

(ii) For renewable electricity
produced from RNG:

§ 80.115 Renewable electricity RIN
generators.

VRE,p

RINRNG,p
VRE * RINRNG

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:

khammond on DSKJM1Z7X2PROD with PROPOSALS2

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 § 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 § 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 § 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
§ 80.135(a)(1)(iii)(B).
(3) Renewable electricity produced
from biogas in a biogas closed
distribution system may only be used

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(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 §§ 80.145,
80.1450, and 40 CFR part 1090, subpart
I, as applicable.
(c) Reporting. The RERG must submit
reports to EPA under §§ 80.150,
80.1451, and 80.1452, as applicable.
(d) Recordkeeping. The RERG must
create and maintain records under
§§ 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 § 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 § 80.170.
(g) Attest engagements. The RERG
must submit annual attest engagement
reports to EPA under §§ 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 § 80.180.
(i) Batches. (1) A batch of RINs for
renewable electricity is the total number
of RINs generated under § 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 § 80.1425.
§ 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

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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 § 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 §§ 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 §§ 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 §§ 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 §§ 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:

E:\FR\FM\30DEP2.SGM

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EP30DE22.009

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

EP30DE22.010

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(A) Biogas used to produce RNG.
(B) RNG before blending with nonrenewable components.
(C) RNG after blending with nonrenewable 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 § 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 § 80.170.
(ii) A foreign RNG producer must
either generate RINs under § 80.140 or
enter into a contract with an RNG
importer as specified in § 80.170(e).
(2) An RNG importer must meet all
requirements that apply to an RNG
importer specified in § 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 § 80.170 and for
RIN-generating foreign renewable fuel
producers specified in § 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
§§ 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
§ 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 § 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

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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:

FEP

VRNG,p

= VRNG * FEtotal

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
§ 80.1426(f)(3)(vi).
FEtotal = Sum of feedstock energies from all
feedstocks used to produce RNG, in Btu,
per § 80.1426(f)(3)(vi).

80723

(b) Registration. The RNG RIN
separator must register with EPA under
§§ 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
§§ 80.150, 80.1451, and 80.1452, as
applicable.
(d) Recordkeeping. The RNG RIN
separator must create and maintain
records under §§ 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 § 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 § 80.165.
(g) Attest engagements. The RNG RIN
separator must submit annual attest
engagement reports to EPA under
§§ 80.175 and 80.1464 using procedures
specified in 40 CFR 1090.1800 and
1090.1805.

(ii) The total volume of RNG
produced must be calculated as follows:
VRNG = VNG * R

§ 80.130 Parties that produce biogasderived renewable fuel from biogas used as
a biointermediate or RNG used as a
feedstock.

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 § 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 § 80.1426(f)(9).

(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 § 80.1476(g) do not
apply.
(b) Registration. The renewable fuel
producer must register with EPA under
§§ 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 §§ 80.150, 80.1451, and 80.1452,
as applicable.
(d) Recordkeeping. The renewable
fuel producer must create and maintain
records under §§ 80.155 and 80.1454.

§ 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.

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§ 80.135

RINs for renewable electricity.

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(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 § 80.145.
(B) A renewable electricity generator
may only change the designated RERG
for RIN generation agreement for a

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

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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 § 80.105, if
applicable.
(ii) The RNG was produced by an
RNG producer meeting the requirements
specified in § 80.120, if applicable.
(iii) The renewable electricity was
produced from biogas or RNG by a
renewable electricity generator meeting
the requirements specified in § 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
§ 80.145 if all the following
requirements are met:
(i) The renewable electricity generator
and biogas producer each submitted a
registration request under § 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:

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
§ 80.1415(b)(6).

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(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:

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EP30DE22.012

(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 §§ 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 § 80.165.
(g) Attest engagements. The
renewable fuel producer must submit
annual attest engagement reports to EPA
under §§ 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 § 80.180.

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

+ EVQ * eVMTEv * FEEv)

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 § 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
§ 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.

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 § 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 § 80.150.
UFi = The utilization factor of the particular
PHEV, per paragraph (c)(1)(i)(B) of this
section.

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

generation facility i for batch pathway p
for quarter Q, in kWh, per paragraph
(c)(1)(ii) of this section.

(ii) Calculating RINs using quarterly
renewable electricity produced. The
volume of renewable electricity eligible
for RIN generation produced by each

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(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:

eRIN

max,Q,i,p

= ELPRo,Q,i,p
EqVRE

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
§ 80.1415(b)(6).
ELPRO,Q,i,p = The volume of renewable
electricity eligible for RIN generation
produced by renewable electricity

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§ 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 § 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 § 80.145.
(3) RNG producers must generate
RINs using the applicable requirements
for RIN generation in § 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
§ 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:

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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).

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.

(d) RIN separation. A RERG must
separate RINs generated for renewable
electricity under § 80.1429(b)(5)(i).
(e) RIN retirement. A party must retire
RINs generated for renewable electricity
if any of the conditions specified in
§ 80.1434(a) apply and must comply
with § 80.1434(b).

EP30DE22.014

(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:

(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:

EP30DE22.013

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_ (PHEVQ * eVMTPHEV * FEPHEV
ELFLEET,Q QPY

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

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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 § 80.120(j)(4)(i).
EqVRNG = The equivalence value for RNG, in
Btu per RIN, per § 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 § 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 § 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 § 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.

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(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
§ 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 § 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 § 80.1434(a)
apply and must comply with
§ 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 § 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
§ 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.
§ 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 § 80.1452.
(b) RIN generation. (1) Renewable
CNG/LNG producers must generate
RINs using the applicable requirements
for RIN generation in § 80.1426.

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(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 § 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
§ 80.1434(a) apply and must comply
with § 80.1434(b).
§ 80.145

Registration.

(a) Applicability. The following
parties must register using the
procedures specified in this section,
§ 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 § 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 § 80.100(d)(1) are deemed
registered under this subpart E, except
as follows:

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(i) If the information in the existing
registration is incorrect, the party must
update their registration as specified in
§ 80.1450(d).
(ii) If the information in the existing
registration does not meet all the
requirements in § 80.145(f), then the
party must update their registration to
meet all requirements in § 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
§ 80.1450(d)(1) before the next threeyear engineering review update is due
as specified in § 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 § 80.1450(b)(2).
(B) A three-year engineering review
update as specified in § 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 § 80.1450(b).
(4) Registration updates. (i) Except as
specified in § 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 § 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
§ 80.1450(d)(3).
(5) Registration deactivations. EPA
may deactivate the registration of a
party registered under this section as
specified in § 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

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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 § 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.

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(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
§ 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 § 80.1450(b)(1)(vii)(A), as
applicable.
(ii) Crop residue information specified
in § 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).

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(ii) [Reserved]
(11) For biogas produced in a
separated MSW digester, all the
following information:
(i) Separated MSW plan specified in
§ 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
§ 80.1450(b)(1)(viii), as applicable.
(ii) A separated yard waste plan
specified in § 80.1450(b)(1)(vii)(A), as
applicable.
(iii) Crop residues information
specified in § 80.1450(b)(1)(xv), as
applicable.
(iv) A separated food waste plan or
biogenic waste oils/fats/greases plan
specified in § 80.1450(b)(1)(vii)(B), as
applicable.
(v) If the waste digester
simultaneously converts cellulosic and
non-cellulosic feedstocks, registration
information specified in
§ 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.

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(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
§ 80.165(c), as applicable.
(5) Identification of the RERG that the
renewable electricity generator has a
RIN generation agreement as specified
in § 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 § 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
§ 80.135(a)(1).

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(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
§ 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
§ 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 § 80.165(b)(1).
(iv) A certificate of analysis from an
independent laboratory for a
representative sample of the RNG as
specified in § 80.165(b)(1).
(v) If the RNG is blended with nonrenewable 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

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blending with non-renewable natural
gas as specified in § 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 § 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 § 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 inline 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
§ 80.140(b)(7).
(9) For a foreign RNG producer, all the
following additional information:
(i) The applicable information
specified in § 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 EPAissued company and facility IDs of the
contracted importer under § 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

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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
§ 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.
§ 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.

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(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
§ 80.1451(f)(4).
(ii) Quarterly reports must be
submitted by the applicable quarterly
deadline in § 80.1451(f)(2).
(iii) Annual reports must be submitted
by the applicable annual deadline in
§ 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 § 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

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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
§ 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
§ 80.165(a).
(iv) The number of RINs retired for
the RNG under § 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

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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 § 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
§ 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 § 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 § 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 biogasderived renewable fuel, in Btu,
produced from biogas.
(2) The total volume of biogas, in Btu,
used to produce the biogas-derived

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renewable fuel as measured under
§ 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
§ 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 biogasderived 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.
§ 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 §§ 80.150,
80.175, 80.1451, and 80.1452 as follows:
(A) Copies of all reports submitted to
EPA.

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(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 §§ 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 §§ 80.160 and 80.1453.
(iv) Subpart M records. Any
applicable record required under
§ 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
§ 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 § 80.195.
(ix) Foreign parties. Any records
related to foreign parties under § 80.170.
(2) Length of time records must be
kept. The records required under this
section and § 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)

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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 § 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
§ 80.1454(j)(1).
(iv) For biogas produced from
separated municipal solid waste,
documents required under
§ 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 § 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-

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qualifying biogas volumes under
§ 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

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vehicles in the RERG’s fleet included in
RIN generation under § 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
§ 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 QAPrelated submissions.
(4) All documents supporting the
values used in the calculations in
§ 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.

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(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 § 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.

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(4) Copies of all documentation
required under § 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 § 80.170(i)(2).
(2) [Reserved]
§ 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

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information required under § 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 § 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 § 80.1453(f)(1)(vi).
(v) For biogas designated for use as
process heat under § 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
§ 80.170(e).

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(4) The name, EPA-issued company
and facility IDs, and address of the
transferee.

§ 80.170 RNG importers and foreign
biogas producers, RNG producers,
renewable electricity generators, and
RERGs.

§ 80.165 Sampling, testing, and
measurement.

(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
§ 80.170(b)(4) and (c) as part of their
registration under § 80.145.
(2) Bond posting. A foreign party that
generates RINs must meet the
requirements of § 80.1466(h).
(3) Foreign RIN owners. A foreign
party that owns RINs must meet the
requirements of § 80.1467, including
any foreign party that separates or
retires RINs under § 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.

(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 § 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 § 80.3).
(ii) API MPMS 14.12 (incorporated by
reference, see § 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 § 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 § 80.3).
(iii) Siloxanes using ASTM D8230
(incorporated by reference, see § 80.3).
(iv) Moisture using ASTM D4888
(incorporated by reference, see § 80.3).
(v) Hydrocarbon analysis using EPA
Method 18.
(vi) Heating value and relative density
using ASTM D3588 (incorporated by
reference, see § 80.3).
(vii) Additional components specified
in pipeline specifications or specified
by EPA as a condition of registration
under § 80.145 or § 80.1450.
(viii) Carbon-14 analysis using ASTM
D6866 (incorporated by reference, see
§ 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 § 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
§ 80.3).
(e) Third parties. Samples required to
be obtained under this subpart may be
collected and analyzed by third parties.

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(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 § 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

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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

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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 § 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 § 80.165.
(ii) Determine the name and EPAassigned 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

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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.

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§ 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

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submitted under §§ 80.145 and 80.1450
and all reports submitted under
§§ 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
§§ 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 § 80.1450(d)(3)(ii).
(iv) Confirm that the biogas producer
submitted all reports required under
§§ 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 § 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 § 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 § 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 § 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:

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(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 § 80.145
and all reports submitted under
§ 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
§ 80.145(b)(3). Report as a finding if the
last engineering review is outside of the
schedule specified in § 80.1450(d)(3)(ii).
(iv) Confirm that the renewable
electricity generator submitted all
reports required under § 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 § 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 § 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.

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(4) Listing of batches. The auditor
must review listings of batches as
follows:
(i) Obtain the batch reports submitted
under § 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 § 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 § 80.140(e).
(ii) Verify that the proper volume of
renewable electricity was produced
under § 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 § 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 § 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 § 80.145 and all reports submitted
under § 80.150.
(ii) Confirm that the RERG’s
registration is accurate based on the
activities reported during the
compliance period and that any

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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 §§ 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 § 80.160(a)(1)(iii).
(B) Records used to calculate the
RERG’s fleet under §§ 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
§ 80.150(d)(2)(ii).
(D) RIN generation information
submitted under § 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 § 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
§ 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
§ 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 §§ 80.145 and 80.1450
and all reports submitted under
§§ 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

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§§ 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 § 80.1450(d)(3)(ii).
(iv) Confirm that the RNG producer or
importer submitted all reports required
under §§ 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 § 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 § 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 § 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

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associated PTD and report as a finding
any exceptions.
(iii) Confirm that the PTD associated
with each batch contains all applicable
language requirements under § 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 § 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 § 80.145 and all reports submitted
under § 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
§§ 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 § 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 §§ 80.145 and 80.1450
and all reports submitted under
§§ 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.

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(iii) Confirm that the RNG RIN
separator submitted all reports required
under §§ 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
§ 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
§ 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 § 80.145 and all reports
submitted under § 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 §§ 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 §§ 80.150(h) and 80.1452.
(B) Records related to measurement
under § 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.

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§ 80.180

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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 biogasderived 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
§ 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 § 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

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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
§ 80.1472(a) and (b)(3), as applicable.
(5) Independent third-party auditors
must ensure that mass and energy
balances performed under
§ 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 § 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 § 80.165.
(2) Verify that the PTDs for biogas
transfers are consistent with the
applicable PTD requirements in
§§ 80.160 and 80.1453.
(c) Requirements for RNG producers.
In addition to the elements verified
under § 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 § 80.165.
(2) Verify that RINs were assigned
consistent with § 80.140(c).
(3) Verify that RINs were separated
and retired consistent with § 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 § 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 § 80.165(c).
(2) Verify that RIN generation
agreement is contracted consistent with
the requirements in § 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 § 80.160(c).
(5) Verify that the renewable
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RNG used to produce renewable
electricity consistent with § 80.140(e).
(e) Requirements for RERGs. The
independent third-party auditor must
verify that each input in the equations
in § 80.135 is properly calculated.
(f) Requirements for renewable fuel
producers using biogas as a
biointermediate. The independent thirdparty auditor must meet all
requirements specified in paragraph (b)
of this section and § 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
§ 80.1431(b).
§ 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
§ 80.190.
(vi) The liability provisions of
§ 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 § 80.1460, the following persons are
deemed in violation:

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(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 biogasderived 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
§ 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
§ 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 § 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

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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 § 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.

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§ 80.190

Affirmative defense provisions.

(a) Applicability. A person may
establish an affirmative defense to a
violation that person is liable for under
§ 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
§ 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
§ 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 § 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,

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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
§§ 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
§§ 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

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electricity from biogas or RNG verified
by a third-party auditor under an
approved QAP under §§ 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.
§ 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 thirdparty auditor that verified the RIN, or
EPA.
(2) Any party listed in paragraph
(a)(1) of this section must use the
procedures specified in § 80.1474(b) for
identification and treatment of PIRs and
retire any PIRs under § 80.1434(a), as
applicable.
(b) Potentially inaccurate or nonqualifying volumes of biogas-derived
renewable fuel. (1) Any party that
becomes aware of potentially inaccurate
or non-qualifying volumes of biogasderived 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
§ 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 biogasderived renewable fuel under paragraph
(a)(2) of this section, as applicable.
(3) Any notified party that generates
RINs must use the procedures specified
in § 80.1474(b) for identification and
treatment of PIRs and retire any PIRs
under § 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.

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(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 overgenerated based off the inaccurate
volumes of renewable electricity, the
RERG must retire these RINs or
replacement RINs as specified in
§ 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 overgenerated based off the double counting
of volumes of biogas or RNG, the RERG
must retire these RINs or replacement
RINs as specified in § 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
§ 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
§ 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
■

9. Revise § 80.1402 to read as follows:

§ 80.1401

Definitions.

The definitions of § 80.2 apply for the
purposes of this Subpart M.
§ 80.1402

[Amended]

10. Amend § 80.1402 by, in paragraph
(f), removing the text ‘‘notwithstanding’’
and adding, in its place, the text
‘‘regardless of’’.
■ 11. Amend § 80.1405 by revising
paragraphs (a) and (c) to read as follows:
■

§ 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
Cellulosic
biofuel
standard
(%)

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Year

2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025

.....................................................................................
.....................................................................................
.....................................................................................
.....................................................................................
.....................................................................................
.....................................................................................
.....................................................................................
.....................................................................................
.....................................................................................
.....................................................................................
.....................................................................................
.....................................................................................
.....................................................................................
.....................................................................................
.....................................................................................
.....................................................................................

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Biomassbased diesel
standard
(%)

0.004
n/a
n/a
0.0005
0.019
0.069
0.128
0.173
0.159
0.230
0.32
0.33
0.35
0.41
0.82
1.23

Advanced
biofuel
standard
(%)

1.10
0.69
0.91
1.13
1.41
1.49
1.59
1.67
1.74
1.73
2.30
2.16
2.33
2.54
2.60
2.67

0.61
0.78
1.21
1.62
1.51
1.62
2.01
2.38
2.37
2.71
2.93
3.00
3.16
3.33
3.80
4.28

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Renewable
fuel
standard
(%)
8.25
8.01
9.23
9.74
9.19
9.52
10.10
10.70
10.67
10.97
10.82
11.19
11.59
11.92
12.55
13.05

Supplemental
total
renewable
fuel standard
(%)
n/a
n/a
n/a
n/a
n/a
n/a
n/a
n/a
n/a
n/a
n/a
n/a
0.14
0.14
n/a
n/a

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 optsin, 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.

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GEi = The total amount of gasoline projected
to be exempt in year i, in gallons, per
§§ 80.1441 and 80.1442.
DEi = The total amount of diesel fuel
projected to be exempt in year i, in
gallons, per §§ 80.1441 and 80.1442.

*
*
*
*
12. Amend § 80.1406 by:
a. Revising the section heading; and
b. Removing and reserving paragraph
(a).
The revision reads as follows:

■
■
■

§ 80.1406

§ 80.1407

Obligated party responsibilities.

[Amended]

13. Amend § 80.1407 by:
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’’;
■ b. In paragraphs (b) and (d), removing
the text ‘‘as defined in’’ and adding, in
its place, the text ‘‘per’’;
■ c. In paragraph (e), removing the text
‘‘MVNRLM diesel fuel at § 80.2’’ and
adding, in its place, the text ‘‘MVNRLM
diesel fuel’’; and
■ d. In paragraph (f)(5), removing the
text ‘‘48 United States and Hawaii’’ and
adding, in its place, the text ‘‘covered
location’’.
■ 14. Amend § 80.1415 by:
■ a. In paragraph (b)(2), removing the
text ‘‘(mono-alkyl ester)’’;
■ b. Revising paragraphs (b)(5) through
(7);
■ c. In paragraph (c)(1), revising the
definition of ‘‘R’’;
■ d. In paragraph (c)(2)(ii), removing the
text ‘‘derived’’ and adding, in its place,
the text ‘‘produced’’; and
■ e. In paragraph (c)(5), removing the
text ‘‘the Administrator’’ and adding, in
its place, the text ‘‘EPA’’.
The revision reads as follows:
■
■

§ 80.1415 How are equivalence values
assigned to renewable fuel?

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(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 kWhr 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.

§ 80.1416

[Amended]

15. Amend § 80.1416 by:
■ a. In paragraphs (b)(1)(vii) and
(b)(2)(vii), removing the text ‘‘The
Administrator’’ and adding, in its place,
the text ‘‘EPA’’;
■ b. In paragraph (c)(4), removing the
text ‘‘definitions in § 80.1401’’ and
adding, in its place, the text
‘‘definition’’; and
■

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c. In paragraph (d), removing the text
‘‘The Administrator’’ and adding, in its
place, the text ‘‘EPA’’.
■ 16. Amend § 80.1426 by:
■ a. Revising paragraph (a)(1)
introductory text;
■ b. In paragraph (a)(1)(iv), removing
the text ‘‘renewable’’;
■ c. Revising paragraphs (a)(4), (b)(1),
and (c)(1) and (2);
■ d. Removing and reserving paragraph
(c)(3);
■ e. In paragraph (c)(7), removing the
text ‘‘§ 80.1401’’ and adding, in its
place, the text ‘‘§ 80.2’’;
■ f. Adding a sentence to the end of
paragraph (d)(1) introductory text;
■ g. Revising paragraphs (e)(1) and
(f)(1)(i);
■ h. Moving Table 1 to § 80.1426 and
Table 2 to § 80.1426 immediately
following paragraph (f)(1) to the end of
the section;
■ 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’’;
■ 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’’;
■ k. Revising paragraph (f)(3)(v);
■ l. Removing Table 3 to § 80.1426
immediately following paragraph
(f)(3)(v);
■ m. Revising paragraph (f)(3)(vi);
■ n. Removing Table 4 to § 80.1426
immediately following paragraph
(f)(3)(vi)(A);
■ o. Revising paragraph (f)(4);
■ p. In paragraph (f)(5)(v), removing the
text ‘‘biogas-derived fuels’’ and adding,
in its place, the text ‘‘biogas-derived
renewable fuel’’;
■ 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’’;
■ r. Revising paragraphs (f)(6)
introductory text and (f)(7)(i),
(f)(7)(v)(A) and (B);
■ s. In paragraph (f)(8)(ii) introductory
text, removing the text ‘‘(mono-alkyl
esters)’’;
■ 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;
■ 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’’;
■ v. Revising paragraph (g)(2)
introductory text; and
■ w. In paragraphs (g)(3) introductory
text, (g)(5)(i) introductory text, (g)(7)

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■

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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:
§ 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 §§ 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.
*
*
*
*
*

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(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
§ 80.1415.
VS,DX = Standardized volume at 60 °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:

FEvx

VRIN,DX

-- EV* Vs* F Etotal

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 § 80.1415.
VS = Standardized volume of the batch of
renewable fuel at 60 °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.

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(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 § 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

khammond on DSKJM1Z7X2PROD with PROPOSALS2

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 § 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 § 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
§ 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 coprocessed 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 coprocessed fuel that originates from

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renewable biomass does not exceed the
fraction of chemical energy in the coprocessed 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 § 80.1415.
Vf = Standardized volume of the batch of coprocessed fuel at 60 °F, in gallons, per
paragraph (f)(8) of this section.
R = The renewable fraction of the coprocessed fuel as measured by a carbon14 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 coprocessed 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 § 80.1415.
Vf = Standardized volume of the batch of coprocessed fuel at 60 °F, in gallons, per
paragraph (f)(8) of this section.

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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 coprocessed 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:
VRIN,DX

= EqV * ERB,DX
ED

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 § 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.

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CFi = Converted fraction in annual average
Btu/lb, except as otherwise provided by
§ 80.1451(b)(1)(ii)(U), representing that
portion of feedstock i that is converted
to fuel by the producer.

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

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 coprocessed 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.

khammond on DSKJM1Z7X2PROD with PROPOSALS2

(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
§ 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 coprocessed 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 coprocessed intermediate at 60 °F, in
gallons, per paragraph (f)(8) of this
section.
R = The renewable fraction of the coprocessed 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:

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(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 coprocessed 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 coprocessed 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 coprocessed intermediate at 60 °F, in
gallons, per paragraph (f)(8) of this
section.
FER,DX = Sum of feedstock energies from
renewable biomass used to make the coprocessed 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 coprocessed 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:

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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:
vbio,DX

ERB,DX

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 coprocessed 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

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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
§ 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 § 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 § 80.3).
(B) ASTM D4442 or ASTM D4444 for
moisture content (both incorporated by
reference, see § 80.3).
*
*
*
*
*
(8) * * *
(ii) * * *
(B) The standardized volume of
biodiesel at 60 °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 § 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 § 80.3).
(B) If the renewable content of the coprocessed 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.

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(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, noncommercial 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

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80745

the volume of RNG withdrawn were
continuously measured under § 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
§ 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 § 80.165.

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(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 § 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
§ 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 § 80.1450(b)(1)(xiii)(A).

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(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 § 80.1450(b)(1)(xiii)(B) or (C), and
reporting requirements under
§ 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 § 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.
*
*
*
*
*

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§ 80.1427

[Amended]

17. Amend § 80.1427 by, in paragraph
(a)(1) introductory text, removing the
text ‘‘under § 80.1406’’.
■ 18. Amend § 80.1428 by revising
paragraphs (a)(2) through (4) and
(a)(5)(i) to read as follows:
■

§ 80.1428 General requirements for RIN
distribution.

(a) * * *
(2) Except as provided in §§ 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
§ 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
§ 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 °F, in
gallons.

*
*
*
*
19. Amend § 80.1429 by:
a. Revising paragraphs (b)(1) through
(3);
■ b. Adding paragraph (b)(4)(iii); and
■ c. Revising paragraphs (b)(5) and (6)
introductory text.
The revisions and addition read as
follows:
■
■

§ 80.1429 Requirements for separating
RINs from volumes of renewable fuel.

*
*
(b) * * *

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(1) Except as provided in paragraphs
(b)(7) and (9) of this section and
§ 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 § 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 § 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.
*
*
*
*
*
§ 80.1430

[Amended]

20. Amend § 80.1430 by, in paragraph
(e)(2), removing the text ‘‘§ 80.1468’’

■

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and adding, in its place, the text
‘‘§ 80.3’’.
■ 21. Amend § 80.1431 by:
■ a. Revising paragraphs (a)(1)(vi) and
(viii);
■ b. Adding paragraphs (a)(1)(x) and
(a)(4);
■ c. Revising paragraphs (b)
introductory text and (c) introductory
text; and
■ 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:
§ 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 § 80.140.
*
*
*
*
*
(4) If any RIN generated for a batch of
renewable fuel that had RINs
apportioned through § 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 § 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:
*
*
*
*
*
■ 22. Amend § 80.1434 by:
■ a. Revising paragraphs (a)(1) and (5);
and
■ b. Redesignating paragraph (a)(11) as
paragraph (a)(13) and adding new
paragraphs (a)(11) and (12).
The revisions and additions read as
follows:
§ 80.1434

RIN retirement.

(a) * * *
(1) Demonstrate annual compliance.
Except as specified in paragraph (b) of
this section or § 80.1456, an obligated
party required to meet the RVO under
§ 80.1407 must retire a sufficient

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number of RINs to demonstrate
compliance with an applicable RVO.
*
*
*
*
*
(5) Spillage, leakage, or disposal of
renewable fuels. Except as provided in
§ 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 § 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 § 80.140(e) must retire the
assigned RIN.
*
*
*
*
*
§ 80.1435

[Amended]

23. Amend § 80.1435 by:
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 ‘‘gallonRINs’’; and
■ 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’’.
■ 24. Amend § 80.1441 by:
■ a. Revising paragraph (a)(1);
■ b. Removing and reserving paragraph
(a)(3);
■ c. Removing paragraph (b)(3);
■ d. In paragraph (e)(1) and (2)
introductory text, removing the text ‘‘the
Administrator’’ and adding, in its place,
the text ‘‘EPA’’;
■ e. In paragraph (e)(2)(ii), removing the
text ‘‘The Administrator’’ and adding, in
its place, the text ‘‘EPA’’.
■ f. In paragraph (e)(2)(iii), removing the
text ‘‘§ 80.1401’’ wherever it appears
and adding, in its place, the text
‘‘§ 80.2’’; and
■ g. In paragraph (g), removing the text
‘‘defined under’’ and adding, in its
place, the text ‘‘specified in’’.
The revision read as follows:
■
■

§ 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 § 80.1405, and the owner or operator
of the refinery is exempt from the
requirements that apply to obligated

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parties under this subpart M for fuel
produced at the refinery if the refinery
meets the definition of ‘‘small refinery’’
in § 80.2 for calendar year 2006.
*
*
*
*
*
■ 25. Amend § 80.1442 by:
■ a. Removing and reserving paragraph
(a)(2);
■ b. Removing paragraphs (b)(4) and (5);
and
■ c. Revising paragraph (c)(1).
The revision reads as follows
§ 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 § 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.
*
*
*
*
*
§ 80.1443

[Amended]

26. Amend § 80.1443 by:
a. In paragraphs (a), (b), and (e)
introductory text, removing the text ‘‘the
Administrator’’ and adding, in its place,
the text ‘‘EPA’’; and
■ b. In paragraph (e)(2), removing the
text ‘‘as defined in § 80.1406’’.
■
■

§ 80.1449

[Amended]

27. Amend § 80.1449 by, in paragraph
(e), removing the text ‘‘the
Administrator’’ and adding, in its place,
the text ‘‘EPA’’.
■ 28. Amend § 80.1450 by:
■ a. Revising the first sentence of
paragraph (a);
■ b. Revising paragraphs (b)(1)
introductory text and (b)(1)(ii);
■ c. In paragraph (b)(1)(v) introductory
text, removing the text ‘‘as defined in
§ 80.1401’’;
■ d. Revising paragraph (b)(1)(v)(D);
■ e. In paragraph (b)(1)(v)(E) removing
the text ‘‘the Administrator’’ and
adding, in its place, the text ‘‘EPA’’.
■ f. In paragraph (b)(1)(vi), removing the
text ‘‘defined’ and adding, in its place,
the text ‘‘specified’’;
■ g. Adding paragraph (b)(1)(viii)(E);
■ h. In paragraphs (b)(1)(xi)
introductory text, (b)(1)(xi)(A), and (B),
removing the text ‘‘§ 80.1401’’ and
adding, in its place, the text ‘‘§ 80.2’’;
■ i. In paragraph (b)(1)(xii) introductory
text, removing the text ‘‘§ 80.1468’’ and
adding, in its place, the text ‘‘§ 80.3’’;
■ j. Revising paragraphs (b)(1)(xii)
introductory text and (b)(1)(xiii)(B)
introductory text;

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k. Adding paragraph (b)(1)(xiii)(C);
l. Revising paragraph (b)(1)(xv)(B);
m. Adding paragraph (b)(1)(xvii)
n. Revising the first sentence of
paragraph (b)(2) introductory text and
paragraphs (b)(2)(ii) and (iii);
■ o. Redesignating paragraphs (b)(2)(iv)
through (vi) as paragraphs (b)(2)(v)
through (vii), respectively, and adding a
new paragraph (b)(2)(iv);
■ p. Adding paragraphs (b)(2)(viii) and
(ix);
■ q. Revising paragraphs (d)(3)
introductory text, (d)(3)(ii), and (iii);
■ r. Adding paragraphs (d)(3)(v) and
(vi);
■ s. Revising paragraph (g)(10)(ii); and
■ 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:
■
■
■
■

§ 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 § 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 § 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

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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 § 80.1426(f)(11) or renewable
electricity under § 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 § 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 § 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

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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
§ 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
§ 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 § 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

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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
§ 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

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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 § 80.145, as applicable.
* * *
*
*
*
*
*
(ii) The independent third-party
engineer and its contractors and
subcontractors must meet the
independence requirements specified in
§ 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

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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

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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 § 80.1469 and notified all
appropriate parties of all potentially
invalid RINs as described in
§ 80.1471(d).
*
*
*
*
*
■ 29. Amend § 80.1451 by:
■ a. In paragraph (a) introductory text,
removing the text ‘‘described in
§ 80.1406’’ and ‘‘described in
§ 80.1430’’;
■ b. Revising paragraph (a)(1)(iii);
■ c. In paragraph (a)(1)(vi), removing the
text ‘‘defined’’ and adding, in its place,
the text ‘‘specified’’;
■ d. Revising paragraphs (a)(1)(viii) and
(ix);
■ e. In paragraph (a)(1)(xiii), removing
the text ‘‘the Administrator’’ and
adding, in its place, the text ‘‘EPA’’;
■ f. Revising paragraphs (a)(1)(xvi),
(xvii), and (xviii);
■ g. In paragraph (b)(1)(ii)(O), removing
the text ‘‘as defined in § 80.1401’’;
■ h. In paragraph (b)(1)(ii)(T), removing
the text ‘‘§ 80.1468’’ and adding, in its
place, the text ‘‘§ 80.3’’;
■ i. Revising paragraph (b)(1)(ii)(U)
introductory text;

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j. Redesignating paragraph
(b)(1)(ii)(W) as paragraph (b)(1)(ii)(X)
and adding a new paragraph
(b)(1)(ii)(W);
■ k. In newly redesignated paragraph
(b)(1)(ii)(X), removing the text ‘‘the
Administrator’’ and adding, in its place,
the text ‘‘that EPA’’;
■ l. In paragraph (c)(1)(iii)(K), removing
the text ‘‘the Administrator’’ and
adding, in its place, the text ‘‘EPA’’;
■ m. In paragraphs (c)(2)(i)(J) and (L),
removing the text ‘‘as defined in’’ and
adding, in its place, the text ‘‘under’’;
■ n. In paragraph (c)(2)(i)(R), removing
the text ‘‘the Administrator’’ and
adding, in its place, the text ‘‘EPA’’;
■ o. In paragraphs (c)(2)(ii)(D)(8) and
(10), removing the text ‘‘as defined in’’
and adding, in its place, the text
‘‘under’’;
■ p. Revising paragraph (c)(2)(ii)(D)(14);
■ q. In paragraph (c)(2)(ii)(I), removing
the text ‘‘the Administrator’’ and
adding, in its place, the text ‘‘EPA’’;
■ r. In paragraph (e) introductory text,
remove the text ‘‘as defined in § 80.1401
who’’ and adding, in its place, the text
‘‘that’’;
■ s. Adding paragraph (f)(4);
■ t. In paragraph (g)(1)(ii)(Q), removing
the text ‘‘the Administrator’’ and
adding, in its place, the text ‘‘that EPA’’;
■ u. In paragraphs (g)(2)(xi) and (h)(2),
removing the text ‘‘the Administrator’’
and adding, in its place, the text ‘‘EPA’’;
■ v. In paragraph (j)(1)(xvi), removing
the text ‘‘the Administrator’’ and
adding, in its place, the text ‘‘that EPA’’;
and
■ w. In paragraph (k), removing the text
‘‘the Administrator’’ and adding, in its
place, the text ‘‘EPA’’.
The revisions and additions read as
follows:
■

§ 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-byfacility 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

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that are invalid as specified in
§ 80.1431(a).
(xvii) The total prior-year RINs by
renewable fuel category retired for
compliance that are invalid as specified
in § 80.1431(a).
(xviii) A list of all RINs that were
retired for compliance in the reporting
period and are invalid as specified in
§ 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
§ 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 °F, in gallons.
(ii) The renewable fraction of the coprocessed fuel or intermediate, as a
percentage.
(iii) The test method used to measure
the renewable fraction under
§ 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 °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) * * *

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(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.
*
*
*
*
*
§ 80.1452

[Amended]

30. Amend § 80.1452 by:
a. In paragraph (b)(14), removing the
text ‘‘as defined in § 80.1401’’;
■ b. In paragraph (b)(18), removing the
text ‘‘the Administrator’’ and adding, in
its place, the text ‘‘that EPA’’; and
■ c. In paragraphs (c)(14) and (d),
removing the text ‘‘the Administrator’’
and adding, in its place, the text ‘‘EPA’’.
■ 31. Amend § 80.1453 by:
■ a. Revising paragraph (a) introductory
text;
■ b. Adding paragraph (a)(11)(i)(D);
■ c. Revising paragraphs (a)(12)
introductory text and (a)(12)(v);
■ d. Adding paragraph (a)(12)(viii);
■ e. In paragraphs (d) and (f)(1)(vi),
removing the text ‘‘§ 80.1401’’ and
adding, in its place, the text ‘‘§ 80.2’’;
and
■ f. Adding paragraph (f)(1)(vii).
The revisions and additions read as
follows:
■
■

§ 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

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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 § 80.160.
*
*
*
*
*
■ 32. Amend § 80.1454 by:
■ a. In paragraph (a) introductory text,
removing the text ‘‘(as described at
§ 80.1406)’’ and ‘‘(as described at
§ 80.1430)’’;
■ b. In paragraph (b) introductory text,
removing the text ‘‘as defined in
§ 80.1401’’;
■ c. Revising paragraphs (b)(3)(ix) and
(xii);
■ d. In paragraph (b)(8), removing the
text ‘‘§ 80.1401’’ and adding, in its
place, the text ‘‘§ 80.2’’;
■ e. In paragraphs (c)(1) introductory
text, (c)(1)(iii), and (c)(2) introductory
text, removing the text ‘‘(as defined in
§ 80.1401)’’;
■ f. Adding paragraphs (c)(2)(vii) and
(c)(3);
■ g. Revising paragraph (d) introductory
text;
■ h. Redesignating paragraphs (d)(1)
through (4) as paragraphs (d)(2) through
(5), respectively, and adding a new
paragraph (d)(1);
■ i. In newly redesignated paragraph
(d)(2)(ii), removing the text ‘‘(d)(1)(i)’’
and adding, in its place, the text
‘‘(d)(2)(i)’’;
■ 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)’’;
■ k. Revising newly redesignated
paragraph (d)(5);

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l. Adding paragraph (d)(6);
m. In paragraphs (h)(3)(iv) and (v),
removing the text ‘‘as defined in
§ 80.1401’’;
■ n. Removing paragraphs (h)(6)(vi) and
(vii);
■ o. Revising paragraph (j) introductory
text;
■ p. In paragraphs (j)(1)(iii) and
(j)(2)(iv), removing the text ‘‘the
Administrator’’ and adding, in its place,
the text ‘‘EPA’’;
■ q. Revising paragraph (k) introductory
text;
■ r. In paragraph (k)(2)(v), removing the
text ‘‘the Administrator’’ and adding, in
its place, the text ‘‘EPA’’;
■ s. Revising paragraph (l) introductory
text;
■ t. In paragraphs (l)(4) and (m)(11),
removing the text ‘‘the Administrator’’
and adding, in its place, the text ‘‘EPA’’;
■ u. In paragraph (t), removing the text
‘‘the Administrator or the
Administrator’s authorized
representative’’ and adding, in its place,
the text ‘‘EPA’’; and
■ v. In paragraph (v), removing the text
‘‘the Administrator’’ and adding, in its
place, the text ‘‘EPA’’.
The revisions and additions read as
follows:
■
■

§ 80.1454 What are the recordkeeping
requirements under the RFS program?

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*
*
*
*
(b) * * *
(3) * * *
(ix) All facility-determined values
used in the calculations under
§ 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 § 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
§ 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

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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 § 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 § 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 § 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 § 80.1426(f)(10) or (11), or that
uses process heat from biogas to
produce renewable fuel under
§ 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

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§ 80.1426(f)(10), § 80.1426(f)(11), or for
use of biogas for process heat to make
renewable fuel as relied upon in
§ 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 § 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 § 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 § 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 § 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
§ 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 § 80.1426(f)(13) were used for
producing ethanol at the renewable fuel
production facility and for no other
purpose. The renewable fuel producer

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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 § 80.3), biogas-derived renewable
fuel or renewable electricity shall keep
all of the following additional records:
*
*
*
*
*
§ 80.1455
■

[Removed and Reserved]

33. Remove and reserve § 80.1455.

§ 80.1457

[Amended]

34. Amend § 80.1457 by, in paragraph
(b)(8), removing the text ‘‘the
Administrator’’ and adding, in its place,
the text ‘‘that EPA’’.
■ 35. Add § 80.1458 to read as follows:
■

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§ 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
§ 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 § 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 § 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.

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(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
§ 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 §§ 80.1426 and 80.1452 after EPA
activates the registration under
§ 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
§ 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
§ 80.145 does not meet the requirements
of this section and may not be stored.
■ 36. Amend § 80.1460 by:
■ a. In paragraphs (c)(2) and (3),
removing the text ‘‘(as defined in
§ 80.1401)’’;
■ b. In paragraph (g), removing the text
‘‘§ 80.1401’’ and adding, in its place, the
text ‘‘§ 80.2’’;
■ c. Revising paragraph (h)(3); and
■ d. Adding paragraph (l).
The revision and addition read as
follows:
§ 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
§ 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
§ 80.1429.
*
*
*
*
*
(l) Independent third-party engineer
violations. No person shall do any of the
following:

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(1) Fail to identify any incorrect
information submitted by any party as
specified in § 80.1450(b)(2).
(2) Fail to meet any requirement
related to engineering reviews as
specified in § 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 § 80.1450.
(4) Fail to meet any requirement
related to the independent third-party
engineering review requirements in
§ 80.1450(b)(2) or (d)(1).
■ 37. Amend § 80.1461 by adding
paragraph (f) to read as follows:
§ 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.
■ 38. Amend § 80.1464 by:
■ a. In the introductory paragraph,
removing the text ‘‘§§ 80.1465 and
80.1466’’ and adding, in its place, the
text ‘‘§ 80.1466’’;
■ b. In paragraph (a) introductory text,
removing the text ‘‘(as described at
§ 80.1406(a))’’ and ‘‘(as described at
§ 80.1430)’’;
■ c. Revising paragraph (a)(3)(ii);
■ d. In paragraph (b)(1)(iii), removing
the text ‘‘a pathway in Table 1 to
§ 80.1426’’ and adding, in its place, the
text ‘‘an approved pathway’’;
■ e. In paragraph (b)(1)(v)(B), removing
the text ‘‘in § 80.1401’’; and
■ f. Revising paragraphs (b)(3)(ii) and
(c)(3)(ii).
The revisions read as follows:
§ 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

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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.
*
*
*
*
*
■ 39. Amend § 80.1466 by:
■ a. In paragraph (d)(2)(ii), removing the
text ‘‘The Administrator’’ and adding, in
its place, the text ‘‘EPA’’;
■ b. In paragraph (f)(1)(viii), removing
the text ‘‘working’’ and adding, in its
place, the text ‘‘business’’;
■ c. Revising paragraphs (h)(1) and (2);
■ d. In paragraph (k)(4)(i), removing the
text ‘‘The Administrator’’ and adding, in
its place, the text ‘‘EPA’’;
■ e. In paragraph (o)(1), removing the
text ‘‘the Administrator’’ wherever it
appears and adding, in its place, the text
‘‘EPA’’; and
■ 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:
§ 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

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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 gallonRINs 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.

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 RINgenerating 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
§ 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.
*
*
*
*
*
■ 40. Amend § 80.1467 by:
■ a. In paragraph (c)(1)(viii), removing
the text ‘‘working’’ and adding, in its
place, the text ‘‘business’’;
■ b. Revising paragraphs (e)(1) and (2);
and
■ 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:
§ 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

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[Removed and Reserved]

41. Remove and reserve § 80.1468.
42. Amend § 80.1469 by:
a. In paragraph (a)(1)(i)(A), removing
the text ‘‘as defined in § 80.1401’’;
■ b. In paragraphs (a)(1)(i)(F) and
(a)(2)(i)(B), removing the text ‘‘as
permitted under Table 1 to § 80.1426 or
a petition approved through § 80.1416’’
and adding, in its place, the text ‘‘from
the approved pathway’’;
■ c. In paragraph (b)(1)(i), removing the
text ‘‘as defined in § 80.1401’’;
■ d. In paragraphs (b)(1)(vi) and
(b)(2)(ii), removing the text ‘‘as
permitted under Table 1 to § 80.1426 or
a petition approved through § 80.1416’’
and adding, in its place, the text ‘‘from
the approved pathway’’;
■ e. In paragraph (c)(1)(i), removing the
text ‘‘as defined in § 80.1401’’;
■ f. Revising paragraphs (c)(4)
introductory text;
■ g. In paragraph (c)(4)(i), removing the
text ‘‘§ 80.1429(b)(4)’’ and adding, in its
place, the text ‘‘§ 80.1429(b)’’;
■ h. Adding paragraph (c)(6);
■ i. Revising paragraph (d); and
■ 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:
■
■
■

§ 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

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§ 80.1450, reporting information under
§ 80.1451, and recordkeeping
information under § 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.
*
*
*
*
*
■ 43. Amend § 80.1471 by:
■ a. Revising paragraph (b) introductory
text and (b)(1);
■ b. In paragraph (b)(2), removing the
text ‘‘as defined in § 80.1406’’;
■ c. Revising paragraphs (b)(4) through
(6); and
■ d. Adding paragraphs (b)(8) through
(13).
The revisions and additions read as
follows:
§ 80.1471

Requirements for QAP auditors.

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*
*
*
*
(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 thirdparty auditor’s contractors and
subcontractors.
(6) The independent third-party
auditor and its contractors and
subcontractors must not have performed
an attest engagement under § 80.1464
for the audited party in the same
calendar year as a QAP audit conducted
pursuant to § 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
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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 thirdparty audit (including the verification
activities) pursuant to § 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.
*
*
*
*
*

■

§ 80.1473

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

[Amended]

44. Amend § 80.1473 by, in
paragraphs (c)(1), (d)(1), and (e)(1),
removing the text ‘‘defined’’ and adding,
in its place, the text ‘‘specified’’.

■

§ 80.1474

[Amended]

45. Amend § 80.1474 by, in paragraph
(g), removing the text ‘‘the
Administrator’’ and adding, in its place,
the text ‘‘EPA’’.

■

§ 80.1478

46. Amend § 80.1478 by, in paragraph
(g)(1), removing the text ‘‘the
Administrator’’ wherever it appears and
adding, in its place, the text ‘‘EPA’’.

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§ 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 § 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 thirdparty 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 § 80.1476(e).
(2) Instead of verifying RINs with a
site visit every 200 days as specified in
§ 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
§ 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
§ 80.1454.
(f) Liability. The feedstock supplier
and renewable fuel producer are liable
for violations as specified in
§ 80.1461(e).

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
49. Amend § 1090.55 by revising
paragraph (c) to read as follows:

■

[Amended]

■

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(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.

50. Amend § 1090.80 by:
■ a. In the definition of ‘‘PADD’’,
revising entry II in the table; and
■ b. In the definition of ‘‘Ultra lowsulfur diesel’’, removing the text ‘‘Ultra
■

low-sulfur diesel’’ and adding, in its
place, the text ‘‘Ultra-low-sulfur diesel’’.
The revision reads as follows:
§ 1090.80

Definitions.

PADD * * *
PADD

Regional description

State or territory

*
II .............................

*
*
Midwest ..................................................

*
*
*
*
Illinois, Indiana, Iowa, Kansas, Kentucky, Michigan, Minnesota, Missouri, Nebraska, North Dakota, Ohio, Oklahoma, South Dakota, Tennessee, Wisconsin.

§ 1090.805

Subpart I—Registration
51. Amend § 1090.805 by revising
paragraph (a)(1)(iv) to read as follows:

■

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
§ 1090.1830

[Amended]

52. Amend § 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]

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