Renewable Fuel Standard (RFS) Program: Standards for 2026 and 2027, Partial Waiver of 2025 Cellulosic Biofuel Volume Requirement, and Other Changes

Federal RegisterJun 17, 2025

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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Parts 80 and 1090

[EPA-HQ-OAR-2024-0505; FRL-11947-01-OAR]

RIN 2060-AW23

Renewable Fuel Standard (RFS) Program: Standards for 2026 and 2027, Partial Waiver of 2025 Cellulosic Biofuel Volume Requirement, and Other Changes

AGENCY:

Environmental Protection Agency (EPA).

ACTION:

Proposed rule.

SUMMARY:

Under the Clean Air Act (CAA), the Environmental Protection Agency (EPA) is required to determine the applicable volume requirements for the Renewable Fuel Standard (RFS) for years after those specified in the statute. EPA is proposing the applicable volumes and percentage standards for 2026 and 2027 for cellulosic biofuel, biomass-based diesel (BBD), advanced biofuel, and total renewable fuel. EPA is also proposing to partially waive the 2025 cellulosic biofuel volume requirement and revise the associated percentage standard due to a shortfall in cellulosic biofuel production. Finally, EPA is proposing several regulatory changes to the RFS program, including reducing the number of Renewable Identification Numbers (RINs) generated for imported renewable fuel and renewable fuel produced from foreign feedstocks and removing renewable electricity as a qualifying renewable fuel under the RFS program (eRINs).

DATES:

Comments.

Comments must be received on or before August 8, 2025.

Public Hearing.

EPA will announce information regarding the public hearing for this proposal in supplemental

Federal Register

document.

ADDRESSES:

Comments.

Submit your comments, identified by Docket ID No. EPA-HQ-OAR-2024-0505, at

http://www.regulations.gov.

Follow the online instructions for submitting comments. Once submitted, comments cannot be edited or removed from the docket. EPA may publish any comment received to its public docket. Do not submit to EPA's docket at

https://www.regulations.gov

any information you consider to be Confidential Business Information (CBI) or other information whose disclosure is restricted by statute. Multimedia submissions (audio, video, etc.) must be accompanied by a written comment. The written comment is considered the official comment and should include discussion of all points you wish to make. EPA will generally not consider comments or comment contents located outside of the primary submission (

i.e.,

on the web, cloud, or other file sharing system). Please visit

https://www.epa.gov/dockets/commenting-epa-dockets

for additional submission methods; the full EPA public comment policy; information about CBI or multimedia submissions; and general guidance on making effective comments.

EPA is specifically soliciting comment on numerous aspects of the proposed rule. To facilitate comment on those portions of the rule, EPA has indexed each comment solicitation with a unique identifier (

e.g.,

“A-1”, “A-2”, “B-1” . . .) to provide a consistent framework for effective and efficient provision of comments. Accordingly, we ask that commenters include the corresponding identifier when providing comments relevant to that comment solicitation. We ask that commenters include the identifier either in a heading or within the text of each comment, to make clear which comment solicitation is being addressed. We emphasize that we are not limiting comment to these identified areas and encourage submission of any other comments relevant to this proposed action.

FOR FURTHER INFORMATION CONTACT:

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

RFS-Rulemakings@epa.gov.

SUPPLEMENTARY INFORMATION:

Does this action apply to me?

Entities potentially affected by this action are those involved with the production, distribution, and sale of transportation fuels (

e.g.,

gasoline and diesel fuel) and renewable fuels (

e.g.,

ethanol, biodiesel, renewable diesel, and biogas). Potentially affected categories include:

Category

NAICS

codes

Examples of potentially affected entities

Industry

111110

Soybean farming.

Industry

111150

Corn farming.

Industry

112111

Cattle farming or ranching.

Industry

112210

Swine, hog, and pig farming.

Industry

211130

Natural gas liquids extraction and fractionation.

Industry

221210

Natural gas production and distribution.

Industry

324110

Petroleum refineries (including importers).

Industry

325120

Biogases, industrial (

i.e.,

compressed, liquified, solid), manufacturing.

Industry

325193

Ethyl alcohol manufacturing.

Industry

325199

Other basic organic chemical manufacturing.

Industry

424690

Chemical and allied products merchant wholesalers.

Industry

424710

Petroleum bulk stations and terminals.

Industry

424720

Petroleum and petroleum products wholesalers.

Industry

457210

Fuel dealers.

Industry

562212

Landfills.

North American Industry Classification System (NAICS).

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

FOR FURTHER INFORMATION CONTACT

section.

Preamble Acronyms and Abbreviations

Throughout this document the use of “we,” “us,” or “our” is intended to refer to EPA. We use multiple acronyms and terms in this preamble. While this list may not be exhaustive, to ease the reading of this preamble and for reference purposes, EPA defines the following terms and acronyms here:

AEO Annual Energy Outlook

AFDC Alternative Fuels Data Center

ATJ alcohol-to-jet

BBD biomass-based diesel

CAA Clean Air Act

CARB California Air Resources Board

CKF corn kernel fiber

CNG compressed natural gas

CWC cellulosic waiver credit

DOE Department of Energy

DRIA Draft Regulatory Impact Analysis

EIA Energy Information Administration

EMTS EPA Moderated Transaction System

EU European Union

FOG fats, oils, and greases

GHG greenhouse gas

LCFS Low Carbon Fuel Standard

LNG liquified natural gas

MSW municipal solid waste

OPEC Organization of Petroleum Exporting Countries

RFS Renewable Fuel Standard

RIN Renewable Identification Number

RNG renewable natural gas

RVO Renewable Volume Obligation

STP standard temperature and pressure

UCO used cooking oil

USDA United States Department of Agriculture

WTI West Texas Intermediate

Outline of This Preamble

I. Executive Summary

A. Summary of the Key Provisions of This Action

B. Impacts of This Rule

C. Policy Considerations

D. Endangered Species Act

II. Statutory Authority

A. Directive To Set Volumes Requirements

B. Statutory Factors

C. Statutory Conditions on Volume Requirements

D. Authority To Establish Volume Requirements and Percentage Standards for Multiple Years

E. Considerations Related to the Timing of This Action

F. Impact on Other Waiver Authorities

G. Severability

III. Alternative Volume Scenarios for Analysis and Baselines

A. Scope of Analysis

B. Production and Importation of Renewable Fuel

C. Volume Scenarios for 2026-2030

D. Baselines

E. Volume Changes Analyzed

IV. Analysis of Volume Scenarios

A. Energy Security

B. Costs

C. Climate Change

D. Jobs and Rural Economic Development

E. Agricultural Commodity Prices and Food Price Impacts

V. Proposed Volume Requirements for 2026 and 2027

A. Cellulosic Biofuel

B. Non-Cellulosic Advanced Biofuel

C. Biomass-Based Diesel

D. Conventional Renewable Fuel

E. Treatment of Carryover RINs

F. Summary of Proposed Volume Requirements

G. Request for Comment on Alternatives

H. Summary of the Assessed Impacts of the Proposed Volume Standards

VI. Proposed Percentage Standards for 2026 and 2027

A. Calculation of Percentage Standards

B. Treatment of Small Refinery Volumes

C. Percentage Standards

VII. Partial Waiver of the 2025 Cellulosic Biofuel Volume Requirement

A. Cellulosic Waiver Authority Statutory Background

B. Assessment of Cellulosic RINs Available for Compliance in 2025

C. Proposed Partial Waiver of the 2025 Cellulosic Biofuel Volume Requirement

D. Calculation of Proposed 2025 Cellulosic Biofuel Percentage Standard

VIII. Reduction in the Number of RINs Generated for Imported Fuels and Feedstocks

A. Introduction and Rationale

B. Legal Authority

C. Implementation

IX. Removal of Renewable Electricity From the RFS Program

A. Historical Treatment of Renewable Electricity in the RFS Program

B. Statutory Basis for Removal of Renewable Electricity From the RFS Program

C. Implementation of Proposed Removal of Renewable Electricity From the RFS Program

X. Other Changes to RFS Regulations

A. Renewable Diesel, Naphtha, and Jet Fuel Equivalence Values

B. RIN-Related Provisions

C. Percentage Standard Equations

D. Existing Renewable Fuel Pathways

E. Updates to Definitions

F. Compliance Reporting, Recordkeeping, and Registration Provisions

G. New Approved Measurement Protocols

H. Biodiesel and Renewable Diesel Requirements

I. Technical Amendments

XI. Request for Comments

A. Renewable Fuel Volumes and Analyses

B. Import RIN Reduction

C. Removal of Renewable Electricity From the RFS Program

D. Other RFS Program Amendments

E. Policy Considerations

XII. Statutory and Executive Order Reviews

A. Executive Order 12866: Regulatory Planning and Review

B. Executive Order 14192: Unleashing Prosperity Through Deregulation

C. Paperwork Reduction Act (PRA)

D. Regulatory Flexibility Act (RFA)

E. Unfunded Mandates Reform Act (UMRA)

F. Executive Order 13132: Federalism

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

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

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

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

XIII. Amendatory Instructions

XIV. Statutory Authority

I. Executive Summary

EPA initiated the RFS program in 2006 pursuant to the requirements of the Energy Policy Act of 2005 (EPAct), which were codified in CAA section 211(o). Congress subsequently amended the statutory requirements in the Energy Independence and Security Act of 2007 (EISA). The statute sets forth annual, nationally applicable volume targets for three of the four categories of renewable fuel (cellulosic biofuel, advanced biofuel, and total renewable fuel) through 2022 and for BBD through 2012. For subsequent calendar years, CAA section 211(o)(2)(B)(ii) directs EPA to determine the applicable volume targets for each of the four categories of renewable fuel in coordination with the Secretary of Energy and the Secretary of Agriculture, based on a review of the implementation of the RFS program for prior years and an analysis of specified statutory factors.

In this action, EPA is proposing the volume targets and applicable percentage standards for cellulosic biofuel, BBD, advanced biofuel, and total renewable fuel for 2026 and 2027.

We are also proposing a number of regulatory changes, including reducing the number of RINs generated for imported renewable fuel and renewable fuel produced from foreign feedstocks and removing renewable electricity as a qualifying renewable fuel under the RFS program (commonly referred to as eRINs). This preamble describes our rationale for the proposed volume requirements and regulatory changes and requests comment on the proposals and supporting rationales, including on EPA's proposed changes to the RFS program and any legitimate reliance interests that EPA should consider during this rulemaking.

EPA previously established volume requirements and applicable percentage standards for 2023-2025 on July 12, 2023 (88 FR 44468) (the “Set 1 Rule”).

The volume requirements and regulatory changes proposed in this action would strengthen the RFS program and sharpen the program's focus on a central goal of the policy: supporting domestic production of renewable fuels. Ensuring a growing

supply of domestically produced renewable fuels, particularly those produced from domestically sourced feedstocks, is a key component in meeting the statutory goals of increasing the energy independence and security of the United States. Increasing domestic production of renewable fuel also contributes to unleashing American energy production towards the goal of achieving energy dominance, consistent with the Administration's “Unleashing American Energy” Executive Order

and the energy dominance pillar of EPA's “Powering the Great American Comeback” initiative.

The proposed modifications and requirements in this action are responsive to input from key agricultural and energy stakeholders on ways to bolster the RFS program, and EPA looks forward to engaging with these and additional interested stakeholders on the proposed changes.

Executive Order 14154, “Unleashing American Energy,” January 20, 2025 (90 FR 8353; January 29, 2025).

EPA, “EPA Administrator Lee Zeldin Announces EPA's `Powering the Great American Comeback' Initiative,” February 4, 2025.

https://www.epa.gov/newsreleases/epa-administrator-lee-zeldin-announces-epas-powering-great-american-comeback.

A. Summary of the Key Provisions of This Action

1. Volume Requirements for 2026 and 2027

Based on our analysis of the factors required in the statute, and in coordination with the United States Department of Agriculture (USDA) and Department of Energy (DOE), EPA is proposing the volume requirements for 2026 and 2027, as shown in Table I.A.1-1. The proposed volumes represent significant increases from those established for 2023-2025, especially after accounting for the proposal to reduce the number of RINs generated for imported renewable fuel and renewable fuel produced from foreign feedstocks.

Table I.A.1-1—Volume Requirements for 2023-2027

[Billion RINs]

Volume requirement established in Set 1 Rule

2023

2024

2025

Proposed volume requirement

2026

2027

Cellulosic biofuel

0.84

1.01

1.19

1.30

1.36

Biomass-based diesel

4.51

4.86

5.36

7.12

7.50

Advanced biofuel

5.94

6.54

7.33

9.02

9.46

Total renewable fuel

20.94

21.54

22.33

24.02

24.46

One RIN is equivalent to one ethanol-equivalent gallon of renewable fuel. Throughout this preamble, RINs are generally used to describe total volumes in each of the four renewable fuel categories, while gallons are generally used to describe volumes for individual types of biofuel (

e.g.,

ethanol, biodiesel, renewable diesel, etc.).

EPA originally established a cellulosic biofuel volume requirement of 1.09 billion gallons for 2024 in the Set 1 Rule. EPA subsequently reduced this volume requirement to 1.01 billon RINs in a separate action.

EPA originally established a cellulosic biofuel volume requirement of 1.38 billion gallons for 2025 in the Set 1 Rule. As described in Section VII, we are proposing to reduce this volume requirement to 1.19 billion RINs in this action.

Through 2025, the BBD volume requirement was established in physical gallons rather than RINs. As described in Section X.C, we are proposing to now specify the BBD volume requirement in RINs, consistent with the other three renewable fuel categories, rather than physical gallons. For the sake of comparison, we have converted the BBD volume requirements for 2023-2025 from physical gallons to RINs using the BBD conversion factor in 40 CFR 80.1405(c) of 1.6 RINs per gallon.

The total renewable fuel volume requirement for 2023 does not include the 0.25 billion RIN supplemental standard.

In this action, we are proposing to specify the BBD volume requirement in billion RINs, rather than billion gallons as in previous RFS rules. To demonstrate the impact of this change, and to allow for easier comparison to previous RFS rules, the BBD volume requirements (in billion RINs) and the volume of BBD (in billion gallons) we project would be supplied to satisfy the volume requirements are shown in Table I.A.1-2. Finally, the quantities of renewable fuel we project would be supplied to satisfy the volume requirements, after accounting for the nested nature of the RFS volume requirements and the proposed import RIN reduction provisions, are shown in Table I.A.1-3.

Table I.A.1-2—BBD Volume Requirements for 2023-2027

Volume requirement established

in the Set 1 Rule

2023

2024

2025

Projected volume requirement

2026

2027

BBD volume requirement (billion RINs)

4.51

4.86

5.36

7.12

7.50

Projected volume of BBD (billion gallons)

2.82

3.04

3.35

5.61

5.86

Billion RINs estimated assuming the average gallon of BBD generates 1.6 RINs.

Billion gallons estimated after accounting for the projected impacts of the proposed RIN reduction for imported renewable fuel and renewable fuel produced from foreign feedstocks and the proposed revised equivalence value for renewable diesel. We project that the average number of RINs generated for BBD will be 1.27 and 1.28 RINs per gallon in 2026 and 2027, respectively. These numbers are not proposed standards and are presented for illustrative purposes only.

Table I.A.1-3—Projected Supply of Renewable Fuels To Satisfy the Volume Requirements for 2023-2027

[Billion gallons]

Projected volume in the Set 1 Rule

2023

2024

2025

Projected volume to meet the

proposed volume requirements

2026

2027

Cellulosic biofuel

0.84

1.09

1.38

1.30

1.36

Biomass-based diesel

3.71

3.85

4.24

6.83

7.16

Other advanced biofuel

0.23

0.19

Conventional renewable fuel

13.85

13.96

13.78

13.66

Total renewable fuel

18.63

19.12

19.63

22.10

22.37

Other advanced biofuel includes all advanced biofuels that to not qualify as cellulosic biofuel or BBD.

Volumes do not include the 0.25 billion RIN supplemental standard established for 2023.

As discussed above, CAA section 211(o) requires EPA to analyze a specified set of factors in making our determination of the appropriate volume requirements. Many of those factors, particularly those related to economic and environmental impacts, are difficult to analyze in the abstract. To facilitate a more robust analysis of the statutory factors, we identified a set of renewable fuel volumes to analyze prior to determining the appropriate volume requirements to establish under the statute. We began by identifying two volume scenarios and then analyzed the potential impacts of these volume scenarios on the factors listed in the statute. The derivation of these volume scenarios is discussed in Section III. Section IV discusses the analysis of the volume scenarios for the statutory factors. Section V discusses our conclusions regarding the appropriate volume requirements to propose in light of the analyses conducted. Finally, Section VI discusses the formulas and values used to calculate the proposed percentage standards.

The BBD and advanced biofuel volumes we are proposing for 2026 and 2027 reflect the significant growth observed in the production of these fuels over the past several years and build off the volumes already achieved in the marketplace in 2024. The proposed volumes reflect the projected growth in the domestic supply of feedstocks, primarily soybean oil, with smaller projected increases in other feedstocks including used cooking oil and animal fats. Our focus on the growth in domestic feedstocks when projecting the supply of BBD for 2026 and 2027 is in part due to the uncertainty in the quantity of imported fuels and feedstocks that will be available to U.S. markets given various factors, including the available supply of qualifying feedstocks and demand for these feedstocks and fuels in other countries.

The cellulosic biofuel volumes we are proposing for 2026 and 2027 are slightly lower than the volumes we finalized for 2025.

The primary reasons for the decrease in the proposed volumes are limitations on the quantities of compressed natural gas (CNG) and liquified natural gas (LNG) derived from biogas projected to be used as transportation fuel in these years. CNG/LNG derived from biogas comprise most of the qualifying cellulosic biofuel we project will be supplied through 2027. However, the proposed cellulosic biofuel volumes also include projections of cellulosic ethanol from corn kernel fiber (CKF) produced at existing corn starch ethanol production facilities.

As discussed in Section VII, we are also proposing to reduce the previously established cellulosic biofuel volume requirement for 2025 in this action.

The proposed volumes for total renewable fuel in 2026 and 2027 reflect an implied conventional biofuel volume of 15 billion gallons each year. This is consistent with the implied conventional renewable fuel volumes in the statutory tables for 2015-2022,

as well as the implied conventional biofuel volumes established for 2023-2025. We recognize that while the supply of conventional biofuel in 2026 and 2027 will likely fall short of the implied 15-billion-gallon volume, the proposed total renewable fuel volumes are still achievable through the use of additional volumes of advanced biofuel beyond the volume requirement for that category.

CAA section 211(o)(2)(B)(i).

The volume requirements that we are proposing in this action are the basis for the calculation of percentage standards applicable to producers and importers of gasoline and diesel unless they are waived in a future action using one or more of the available waiver authorities in CAA section 211(o)(7).

We believe that it is appropriate to propose volume requirements for two years instead of a longer timeframe due to the increased uncertainty of trying to project out further in the future, which increases the likelihood of needing to adjust volumes in the future. Adjustments to volume requirements create uncertainty in the RFS program and hinder the purpose of projecting future years, which is meant to provide certainty to the market. However, EPA is requesting comment on whether it would be appropriate to set standards for more than two years.

2. Partial Waiver of the 2025 Cellulosic Biofuel Volume Requirement

EPA is proposing to partially waive the 2025 cellulosic biofuel volume requirement and revise the associated percentage standard due to a shortfall in cellulosic biofuel production. As discussed in Section VII, we currently project a 0.19 billion RIN shortfall in available cellulosic biofuel in 2025. As such, we are proposing to use our CAA section 211(o)(7)(D) “cellulosic waiver authority” to reduce the 2025 cellulosic biofuel volume from 1.38 billion RINs to 1.19 billion RINs. The use of such waiver authority, if finalized, would also make cellulosic waiver credits (CWCs) available for the 2025 compliance year.

3. Reduction in the Number of RINs Generated for Imported Renewable Fuel and Renewable Fuel Produced From Foreign Feedstocks

EPA is proposing to reduce the number of RINs generated for imported renewable fuel and renewable fuel produced from foreign feedstocks. In simple terms, we are proposing regulatory changes that would mean a gallon of imported renewable fuel, or fuel produced from foreign feedstocks, would generate half the number of RINs that the same gallon of fuel would generate if produced in the U.S. from domestic feedstocks. These proposed changes, described in Section VIII, are in response to the dramatic increase in imported biofuels and feedstocks used to produce biofuels in the U.S. observed

in recent years and align with the statutory goals of bolstering national energy independence. Imported renewable fuel and renewable fuel produced from foreign feedstocks do not further energy independence and are projected to result in fewer employment and rural economic development benefits relative to renewable fuels produced in the U.S. from domestic feedstocks.

4. Removal of Renewable Electricity From the RFS Program

As described in Section IX, EPA is proposing to remove renewable electricity as a qualifying renewable fuel under the RFS program (commonly referred to as eRINs), thereby making it ineligible to generate RINs. The proposed changes would find that renewable electricity does not meet the definition of renewable fuel under CAA section 211(o)(1)(J). On this basis, we are proposing to remove the regulations related to the production and use of renewable electricity as a transportation fuel, including the regulations related to facility registration for renewable electricity producers and the provisions for generating RINs for use of renewable electricity as a transportation fuel. We are also proposing to remove the definition of “renewable electricity” and the renewable electricity pathways in Table 1 of 40 CFR 80.1426 in connection with this policy change.

5. Other Regulatory Changes

EPA is also proposing additional regulatory changes in several areas to strengthen our implementation of the RFS program. These regulatory changes are discussed in greater detail in Section X and include:

• Specifying new equivalence values for renewable diesel, naphtha, and jet fuel.

• Updating RIN generation and assignment provisions.

• Clarifying that RINs cannot be generated on pure or neat biodiesel that is used as process heat or for power generation.

• Changing the percentage standards equations, including specifying the BBD standard in RINs rather than physical gallons.

• Updating existing renewable fuel pathways and adding new ones.

• Adding definitions for terms used throughout the regulations and updating other definitions.

• Adding a joint and several liability provision applicable to importers of renewable fuel.

• Revising compliance reporting and registration provisions, including clarifying that small refineries that receive an exemption from their RFS obligations must still submit an annual compliance report.

• Clarifying certain testing requirements for biodiesel and renewable diesel.

• Other minor changes and technical corrections.

B. Impacts of This Rule

CAA section 211(o)(2)(B)(ii) requires EPA to assess several factors when determining volume requirements for calendar years after 2022. These factors are described in the introduction to this Executive Summary, and each factor is discussed in detail in the Draft Regulatory Impact Analysis (DRIA) accompanying this rule.

However, the statute does not specify how EPA must assess each factor. For two of these statutory factors—costs and energy security—we provide monetized estimates of the impacts of the proposed volume requirements. For the other statutory factors, we are either unable to quantify impacts or we provide quantitative estimated impacts that nevertheless cannot be easily monetized. Thus, we are unable to quantitatively compare all the evaluated impacts of this rulemaking.

“RFS Program Standards for 2026 and 2027: Draft Regulatory Impact Analysis,” EPA-420-D-25-001, June 2025.

EPA considered all statutory factors in developing this proposal, including factors for which we provide monetized impacts, otherwise quantified impacts, or provide a qualitative assessment of relevant impacts, and we find that the proposed volumes are appropriate under EPA's statutory authority as an outcome of balancing all relevant factors. This approach is consistent with CAA section 211(o)(2)(B)(ii), which requires the EPA Administrator to “determin[e]” volumes based on “an analysis of” the statutory factors and does not require that analysis to monetize or quantify all relevant considerations. A summary of our assessment of the impacts of this proposed rule can be found in Section V.H. Table ES-1 in the DRIA provides a list of all the impacts that we assessed, both quantitative and qualitative. Additional detail for each of the assessed factors is provided in DRIA Chapters 4 through 10. For this proposed rule, we used data and projections from the U.S. Energy Information Administration's (EIA's) Annual Energy Outlook 2023, which was the most recent version available at the time we conducted our analyses supporting this action.

For the final rule, we intend to update our analyses using the most recent available data and projections from EIA and other sources.

EIA, “Annual Energy Outlook 2023” (AEO2023).

https://www.eia.gov/outlooks/archive/aeo23.

On April 15, 2025, EIA issued “Annual Energy Outlook 2025” (AEO2025).

https://www.eia.gov/outlooks/aeo.

C. Policy Considerations

The RFS program is a critical policy tool to support the domestic production of renewable fuels. This action seeks to get the RFS program back on track by establishing renewable fuel volumes for 2027 by the statutory deadline and aligning the incentives provided by the RFS program with the statutory goals of increasing energy independence and energy security. The proposed volumes for 2026 and 2027 reflect the significant growth potential for renewable fuel production in the United States using domestic feedstocks.

EPA is requesting comment on multiple aspects of this action, including the proposed volume requirements, our technical analyses supporting those volumes, our proposal to reduce the number of RINs generated for imported renewable fuels and renewable fuels produced from foreign feedstocks, the removal of renewable electricity as a qualifying renewable fuel under RFS program, and the other proposed regulatory amendments. We also recognize that while this proposal in an important first step in getting the RFS program back on track, opportunities remain to improve the RFS program. To that end, we are requesting comment on a variety of potential changes to the RFS program that EPA could consider in future actions that would increase the program's ability to achieve the goals of EPAct and EISA. Our request for comment includes, but is not limited to:

• A general pathway for the production of renewable jet fuel from corn ethanol, including the consideration of ways to reduce emissions for this pathway such as the use of carbon capture and storage, renewable natural gas for process energy and low-carbon farming practices.

• The definition of “produced from renewable biomass.”

• Additional program amendments to ensure that imported renewable fuels are produced from qualifying feedstocks and enhance our ability to track feedstocks to their point of origin. These comments may include input on methods and data to improve our evaluation of the environmental impacts associated with imported feedstocks such as used cooking oil and tallow.

• Program enhancements to increase the use of qualifying woody-biomass to

produce renewable transportation fuel. We specifically request comment on the extent to which the renewable biomass definition in 40 CFR 80.2 aligns with current wildfire risk potential and corresponds to wildfire ignition behavior science and how to best maximize the eligibility of woody biomass residues generated at sawmills and other forest products manufacturing businesses that have not been adulterated by chemicals or other non-wood contaminants.

• An option to apply the import RIN reduction provisions to imported renewable fuel and renewable fuel produced domestically from foreign feedstock from only a subset of countries to reflect the reduced economic, energy security, and environmental benefits of imported renewable fuel and feedstock from those countries.

• Any other modifications to the RFS program designed to unleash the production of American energy.

D. Endangered Species Act

Section 7(a)(2) of the Endangered Species Act (ESA), 16 U.S.C. 1536(a)(2), requires that federal agencies such as EPA, in consultation with the U.S. Fish and Wildlife Service (USFWS) and/or the National Marine Fisheries Service (NMFS) (collectively “the Services”), ensure that any action authorized, funded, or carried out by the action agency is not likely to jeopardize the continued existence of any endangered or threatened species or result in the destruction or adverse modification of designated critical habitat for such species. Under relevant implementing regulations, the action agency is required to consult with the Services for actions that “may affect” listed species or designated critical habitat.

Consultation is not required where the action would have no effect on such species or habitat.

50 CFR 402.14.

Consistent with ESA section 7(a)(2) and relevant implementing regulations at 50 CFR part 402, EPA engaged in informal consultation with the Services and completed a Biological Evaluation (BE) for the Set 1 Rule.

Supported by the analysis in the Set 1 Rule BE, EPA determined that the Set 1 Rule was “not likely to adversely affect” listed species and their habitats. NMFS concurred with EPA's determination on July 27, 2023, and FWS concurred with EPA's determination on August 3, 2023, thereby concluding the agencies' consultation obligations.

For the rulemaking finalizing this proposed action, EPA intends to develop a biological evaluation to inform our assessment of the effects of this action, and in turn our ESA consultation obligations.

EPA, “Biological Evaluation of the Renewable Fuel Standard Set Rule and Addendum,” EPA-420-R-23-029, May 2023 (the “Set 1 Rule BE”).

The outcome of the Set 1 Rule ESA consultation is the subject of pending litigation; oral argument was held on November 1, 2024, and we are awaiting the court's decision. See

CBD

EPA, et al.,

Case No. 23-1177 (D.C. Cir.).

II. Statutory Authority

A. Directive To Set Volumes Requirements

Congress enacted the RFS program for the purpose of increasing the use of renewable fuel in transportation fuel over time. Congress specified statutory volumes for the initial years of the program, including for BBD through 2012, and for the total renewable fuel, advanced biofuel, and cellulosic biofuel through 2022, but allowed EPA to waive the statutory volumes in certain circumstances. For years after 2022, Congress provided EPA with the directive and authority to establish the applicable renewable fuel volume requirements, as described in this section.

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

We refer to CAA section 211(o)(2)(B)(ii) as the “set authority.”

B. Statutory Factors

CAA section 211(o)(2)(B)(ii) establishes the processes, criteria, and standards for setting the applicable annual renewable fuel volumes. That provision provides that the EPA Administrator shall, in coordination with USDA and DOE,

determine the applicable volumes of each renewable fuel category, based on a review of the implementation of the program during the calendar years specified in the tables in CAA section 211(o)(2)(B)(i) and an analysis of the following factors:

In furtherance of this requirement, we will continue periodic discussions with USDA and DOE on this action.

• The impact of the production and use of renewable fuels on the environment, including on air quality, climate change, conversion of wetlands, ecosystems, wildlife habitat, water quality, and water supply;

• The impact of renewable fuels on the energy security of the United States;

• The expected annual rate of future commercial production of renewable fuels, including advanced biofuels in each category (cellulosic biofuel and biomass-based diesel);

• The impact of renewable fuels on the infrastructure of the United States, including deliverability of materials, goods, and products other than renewable fuel, and the sufficiency of infrastructure to deliver and use renewable fuel;

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

• The impact of the use of renewable fuels on other factors, including job creation, the price and supply of agricultural commodities, rural economic development, and food prices.

Congress provided EPA flexibility by enumerating factors that the Administrator must consider without mandating any particular forms of analysis or specifying how the EPA Administrator must weigh the various factors against one another. Thus, as the CAA “does not state what weight should be accorded to the relevant factors,” it “give[s] EPA considerable discretion to weigh and balance the various factors required by statute.”

These factors were analyzed in the context of the 2020-2022 RFS Rule that modified volumes under CAA section 211(o)(7)(F),

which requires EPA to comply with the processes, criteria, and standards in CAA section 211(o)(2)(B)(ii). EPA's assessment of the factors in that rule was recently upheld by the D.C. Circuit in

Sinclair

EPA.

EPA has also considered these factors in establishing the applicable volumes for 2023-2025 under CAA section 211(o)(2)(B)(ii) in the Set 1 Rule. Consistent with our past practice in evaluating the factors,

we have again determined that a holistic balancing of the factors is appropriate.

Nat'l Wildlife Fed'n

EPA,

286 F.3d 554, 570 (D.C. Cir. 2002) (analyzing factors within the Clean Water Act);

accord Riverkeeper, Inc.

U.S. EPA,

358 F.3d 174, 195 (2d Cir. 2004) (same);

BP Exploration & Oil, Inc.

EPA,

66 F.3d 784, 802 (6th Cir. 1995) (same);

See also Sinclair

EPA,

101 F.4th 871 (D.C. Cir. 2024).

NPRA

EPA,

630 F.3d 145, 164-65.

ACE,

864 F.3d at 721-22.

ACE,

864 F.3d at 721-23.

In this action, we are proposing to exercise our authority to set the applicable renewable fuel volume requirements for 2026 after the statutory deadline to promulgate such volume requirements under CAA section 211(o)(2)(B)(ii). We intend to finalize the 2026 standards prior to the beginning of the 2026 compliance year (

i.e.,

before January 1, 2026) and do not expect those standards to apply retroactively. In this proposal, we are providing obligated parties notice of the proposed 2026 standards. Under the RFS regulations, demonstrating compliance with the 2025 standards will not be required until the next quarterly reporting deadline after the 2026 standards are effective.

Additionally, obligated parties will continue to have the ability to use existing compliance flexibilities to comply with the 2026 RFS standards, such as the use of carryover RINs and carrying forward a deficit from one compliance year into the next.

40 CFR 80.1451(f)(1)(i)(A).

F. Impact on Other Waiver Authorities

While we are proposing applicable volume requirements in this action for future years that are achievable and appropriate based on our consideration of the statutory factors, we retain our legal authority to waive volumes in the future under the waiver authorities should circumstances so warrant.

For example, the general waiver authority under CAA section 211(o)(7)(A) provides that EPA may waive the volume requirements in “paragraph (2),” which provides both the statutory

applicable volume tables and EPA's set authority (the authority to set applicable volumes for years not specified in the table). Therefore, similar to our exercise of the waiver authorities to modify the statutory volumes in past annual standard-setting rulemakings, EPA has the authority to modify the applicable volumes for 2023 and beyond in future actions through the use of our waiver authorities.

See J.E.M. Ag Supply, Inc.

Pioneer Hi-Bred Intern., Inc.,

534 U.S. 124, 143-44 (2001) (holding that when two statutes are capable of coexistence and there is not clearly expressed legislative intent to the contrary, each should be regarded as effective).

We note that, as described above, CAA section 211(o)(2)(B)(iv) requires that EPA set the cellulosic biofuel volume requirements for 2023 and beyond based on the assumption that EPA will not need to waive those volume requirements under the cellulosic waiver authority. Because we are, in this action, proposing the applicable volume requirements for 2026 and 2027 under the set authority, we do not believe we could also waive those requirements using the cellulosic waiver authority in this same action in a manner that would be consistent with CAA section 211(o)(2)(B)(iv), since that waiver authority is only triggered when the projected production of cellulosic biofuel is less than the “applicable volume established under [211(o)(2)(B)].” In other words, it does not appear that EPA could use both the set authority and the cellulosic waiver authority to establish volumes at the same time in this action.

Proposing the volume requirements for 2026 and 2027 using our set authority apart from the cellulosic waiver authority has important implications for the availability of CWCs in these years. When EPA reduces cellulosic volumes under the cellulosic waiver authority, EPA is also required to make CWCs available under CAA section 211(o)(7)(D)(ii). In this rule we are proposing cellulosic biofuel volume requirements without utilizing the cellulosic waiver authority. We interpret CAA section 211(o)(7)(D)(ii) such that CWCs are only made available in years in which EPA uses the cellulosic waiver authority to reduce the cellulosic biofuel volume. Because of this, CWCs would not be available as a compliance mechanism for obligated parties in these years absent a future action to exercise the cellulosic waiver authority. Despite the absence of CWCs, we expect that obligated parties will be able to satisfy their cellulosic biofuel obligations for these years because we are proposing to establish the cellulosic biofuel volume requirement based on the quantity of cellulosic biofuel we project will used as transportation fuel in the U.S. each year.

G. Severability

We intend for the volume requirements and percentage standards for each single year covered by this rule (

i.e.,

2026 and 2027) to be severable from the volume requirements and percentage standards for the other year. Each year's volume requirements and percentage standards are supported by analyses for that year.

We intend for the revised cellulosic biofuel volume requirement and percentage standard for 2025 in Section VII to be severable from the volume requirements and percentage standards for the other years. The cellulosic biofuel volume requirement and percentage standard for 2025 is supported by the analysis for that year.

We intend for the import RIN reduction in Section VIII to be severable from the volume requirements and percentage standards for 2026 and 2027. While the regulatory amendments in Section VIII propose to modify the number of RINs generated for imported renewable fuel and renewable fuel produced from foreign feedstocks, our basis for proposing the amendments in Section VIII is independent from the volume requirements themselves. Additionally, we do not anticipate that invalidation of the import RIN reduction would jeopardize compliance with the volume requirements and percentage standards.

We also intend for the removal of renewable electricity from the RFS program in Section IX and the regulatory amendments in Section X to be severable from the volume requirements and percentage standards. These regulatory amendments are intended to improve the RFS program in general and are not part of EPA's analysis for the volume requirements and percentage standards for any specific year. Further, each of the regulatory amendments in Sections IX and X is severable from the other regulatory amendments because they all function independently of one another.

If any of the portions of the rule identified in the preceding paragraph (

i.e.,

volume requirements and percentage standards for a single year, the individual regulatory amendments) is invalidated by a reviewing court, we intend the remainder of this action to remain effective as described in the prior paragraphs. To further illustrate, if a reviewing court were to invalidate the volume requirements and percentage standards, we intend the other regulatory amendments to remain effective. Or, as another example, if a reviewing court invalidates the proposed removal of renewable electricity as a qualifying renewable fuel under the RFS program, we intend the volume requirements and percentage standards as well as other regulatory amendments to remain effective.

III. Alternative Volume Scenarios for Analysis and Baselines

In establishing volumes for 2026 and 2027, the statute requires that EPA review the implementation of the RFS program in prior years and analyze a specified set of factors (see Section II.B). Many of those factors, particularly those related to economic and environmental impacts, are difficult to analyze in the abstract; it is challenging to assess impacts without understanding the scale of the volume changes that are the driving force behind those impacts. In light of this, we have opted to develop alternative volume scenarios to analyze for each category of renewable fuel. This section describes the factors we considered when developing the volume scenarios for analysis. The analyses of the impacts of the volume scenarios are summarized in Section IV, and the volumes we are proposing based on these analyses and a review of the implementation of the RFS program to date are described in Section V. Note that neither of the volume scenarios we developed for analytical purposes include the impacts of the proposed import RIN reduction provisions described in Section VIII.

To develop the alternative volume scenarios for analysis, we first assessed two fundamental factors: (1) The potential supply of these fuels from both imports and domestic production; and (2) The ability for these fuels to be used as qualifying transportation fuel in the United States. Throughout this preamble, we use the term “supply” of renewable fuel to refer to the quantity of qualifying renewable fuel that can be used as transportation fuel, heating oil, or jet fuel in the U.S. Unless otherwise noted, all historical data on the supply of renewable fuel is based on data from the EPA Moderated Transaction System (EMTS). The projected domestic production and importation of renewable fuel and the use of renewable fuel as transportation fuel closely align with two of the explicit statutory criteria: expected annual rate of future commercial production of renewable fuel and sufficiency of infrastructure to deliver and use renewable fuels. For cellulosic biofuel and conventional renewable fuel, the volume scenarios we chose to analyze are equal to the projected volumes of these fuels we project will be used as qualifying transportation fuel in 2026 and 2027. Our projections of the use of these fuels

assumes current ongoing incentives for the production and use of these fuels provided by the RFS program and by other state and federal programs remain in place for the periods of time currently described in their respective statutes and regulations.

For non-cellulosic advanced biofuel (including BBD and other advanced biofuel), the projected supply of these fuels in future years is highly dependent on the incentives for these fuels provided by the RFS program, other state and federal incentives in the U.S., and actions by foreign countries. Unlike cellulosic biofuel and conventional renewable fuel, we do not expect that the supply of non-cellulosic advanced biofuel will be limited by the ability for the market to use these fuels as qualifying transportation fuel. Instead, we project that the available supply of non-cellulosic advanced biofuel will depend on a number of interrelated factors, including the supply of feedstocks to produce these fuels, demand for these feedstocks in non-biofuel markets, and the available incentives for the production and use of these fuels in the U.S. and other countries. Further, unlike cellulosic biofuel and conventional renewable fuel, which are primarily produced from a single feedstock (biogas and corn starch, respectively), non-cellulosic advanced biofuel can be produced from a variety of different feedstocks, and the projected impacts of the production of these fuels can vary depending on the feedstock used to produce the fuel. Considering these complexities, we have developed two different volume scenarios of non-cellulosic advanced biofuel for analysis rather that attempt to identify a single volume scenario for the projected supply of these fuels. These assessments are described in greater detail in Sections III.B and C and DRIA Chapter 6.

We acknowledge that we are adopting a slightly different approach to developing the volume scenarios for analysis in this action than we did in the Set 1 Rule, in which EPA first identified “candidate volumes” to analyze for each category of renewable fuel. These candidate volumes were based primarily on a consideration of supply-related factors, with a consideration of other relevant factors as noted in the Set 1 Rule. The approach taken in this action, in which multiple volume scenarios are analyzed, is designed to provide additional information about the potential impacts of a broader range of renewable fuel volume requirements.

The analysis of multiple scenarios allows EPA to consider different volumes scenarios for non-cellulosic advanced biofuel, where the impacts may be more heterogenous (

e.g.,

the impacts are not expected to be consistent on a per-gallon basis) across a range of potential qualifying fuels and volume requirements.

We note that the two scenarios analyzed for this action differ only in the BBD volumes. Considering different BBD volumes is of the most interest due to the high degree of uncertainty in the potential supply of this fuel through 2027 and the differences in the projected impacts between different types of BBD.

The volume scenarios we analyzed for this action, as well as the data that informed these volume scenarios, can be found in Sections III.B and C. Sections III.D and E describe the baselines we considered as points of reference for the analysis of the other statutory factors (

i.e.,

the “No RFS” baseline and the 2025 baseline) and the volume changes calculated in comparison to that baseline, respectively.

A. Scope of Analysis

In Section II.D we discuss our statutory authority to establish RFS volume requirements and percentage standards for multiple years in a single action. As discussed in that section, we are proposing to establish volume requirements and percentage standards for two years: 2026 and 2027. When developing the scenarios described in this section, however, EPA had not yet determined either the number of years for which to establish volumes in this action or the exact levels of the proposed volumes. To preserve the opportunity to consider proposing an action that would establish volumes for a greater number of years, we developed scenarios for analysis through 2030. We also assessed a range of potential fuel volumes to provide stakeholders with a more comprehensive sense for the potential impacts of different volume levels. The volume scenarios discussed in this section, as well as the results of our analysis of these scenarios discussed in Section IV, therefore consider a range of renewable fuel volumes through 2030. More information on the projected impacts of the renewable fuel volume requirements we are proposing for 2026 and 2027 can be found in Section V and the DRIA.

B. Production and Importation of Renewable Fuel

1. Cellulosic Biofuel

CAA section 211(o)(1)(E) defines cellulosic biofuel as renewable fuel derived from any cellulose, hemi-cellulose, or lignin that has lifecycle greenhouse gas (GHG) emissions that are at least 60 percent less than the baseline lifecycle GHG emissions. Since the inception of the RFS program, cellulosic biofuel production has steadily increased, reaching record levels in 2024. This growth has primarily been driven by biogas-derived CNG/LNG, although small volumes of liquid cellulosic biofuels, particularly ethanol produced from corn kernel fiber (CKF), have also played a contributing role. In this section, we discuss our analysis for projecting the production of qualifying cellulosic biofuel for 2026-2030, along with key uncertainties associated with these estimates. Additional details on our volume projections for cellulosic biofuel can be found in DRIA Chapter 7.1.

EP17JN25.001

a. CNG/LNG Derived From Biogas

Biogas-derived CNG/LNG from qualifying sources must first be collected and upgraded for vehicle use. The upgraded process varies depending on the final application but typically involves removing undesirable components and contaminants from the raw biogas. Biogas that has been upgraded and distributed through a closed distribution system, either as a biointermediate or for the production of renewable fuel, is defined as “treated biogas,” whereas biogas that has been upgraded to be suitable for injection into the commercial natural gas pipeline system and is used to produce renewable fuel is defined as “renewable natural gas” (RNG).

Although they are defined differently in the regulations, we use the term “RNG” to collectively refer to both treated biogas and RNG in this document. Likewise, we use “biogas-derived CNG/LNG” to refer to both treated biogas and RNG when used as a transportation fuel in CNG/LNG vehicles.

40 CFR 80.2.

To project future volumes of biogas-derived CNG/LNG, we analyzed two limiting factors: the estimated volume of RNG that could be produced or captured and the estimated amount of biogas-derived CNG/LNG that could be consumed as a transportation fuel. Our analysis indicates that consumption (

i.e.,

use as a transportation fuel), rather than production, is likely to be the primary constraint on determining volumes during 2026-2030.

To estimate consumption, we developed a projection of total CNG/LNG transportation use based on vehicle sector data, including fuel consumption rates, vehicle miles traveled, and fuel efficiency. Because biogas-derived CNG/LNG can generate RINs only when used as a transportation fuel, total CNG/LNG consumption—whether fossil- or biogas-derived—represents the upper volume limit for biogas-derived CNG/LNG RIN generation. However, full replacement of total CNG/LNG usage with biogas-derived fuel is unlikely due to infrastructure limitations, costs, and other challenges. To account for this, we applied an efficiency factor to estimate the portion of total CNG/LNG consumption that could realistically be met with biogas-derived fuel and, in turn, the number of cellulosic RINs that could be generated. Based on data from California's Low Carbon Fuel Standard (LCFS) program, we assume that even in a fully saturated market,

only 97 percent of total CNG/LNG transportation demand would be met with biogas-derived CNG/LNG. As a result, we applied a 97 percent adjustment to our total CNG/LNG consumption estimate to calculate the potential total biogas-derived CNG/LNG volume. The results of this analysis are shown in Table III.B.1.a-1 and are further described in DRIA Chapter 7.1.4.1.

We use the term “saturated market” to describe a market that consumes the maximum feasible amount of biogas-derived CNG/LNG relative to its CNG/LNG vehicle population.

Table III.B.1.

-1—Estimated Consumption of Total CNG/LNG and the Estimated Quantity of Biogas-Derived CNG/LNG

[Million ethanol-equivalent gallons]

Year

Total CNG/LNG

consumption

Total biogas-derived

CNG/LNG consumption

2026

1,210

1,174

2027

1,277

1,239

2028

1,349

1,309

2029

1,426

1,384

2030

1,509

1,464

Initial evidence of this shift towards a consumption-limited baseline is already apparent. In 2023, RNG volumes were insufficient to meet the cellulosic biofuel volume requirement established in the Set 1 Rule. This shortfall resulted in a 0.09 billion cellulosic RIN deficit carried forward from 2023 into 2024. For 2024, RNG production—and hence cellulosic RIN generation—again fell short of the required volume. This led EPA to propose a partial waiver of the 2024 cellulosic biofuel volume requirement.

Similarly, as described in Section VII, EPA currently projects a shortfall in cellulosic biofuel production for 2025 and is proposing to again partially waive the cellulosic biofuel volume requirement for 2025. Thus, while EPA is still projecting continued growth in cellulosic biofuel production, growth in cellulosic RIN generation is likely to face significant constraints for the foreseeable future, limited by the ability of fuel consumers to use RNG as a qualifying transportation fuel.

89 FR 100442 (December 12, 2024).

As a means of cross-checking this expected limitation on cellulosic RIN generation, we also projected future RNG production. To estimate this, we used an industry-wide projection methodology that has been employed in the RFS standard-setting rules since 2018. This methodology applies an industry-wide year-over-year growth rate to the current biogas production rate. Specifically, we used RIN generation data from the most recent 24 months and multiplied the observed growth rate during that period by the most recent full calendar year of data available. This growth rate was then repeatedly applied to each progressive year to project future production. This approach was previously used in the 2018,

2019,

2020-2022,

and Set 1 (2023-2025) Rules. However, unlike the 2018-2022 Rules, the Set 1 Rule relied on data from 2015-2022 rather than the previous 24 months. This adjustment was made to account for the expected impact of the COVID-19 pandemic, which was believed at the time to have negatively affected the market in 2020 and 2021. At the time of the Set 1 Rule analysis, pre-pandemic growth rates were considered a more accurate reflection of future biogas production potential, a view supported by stakeholders. However, with the benefit of post-pandemic data, we have returned to our prior methodology, basing projections on the most recent 24 months of data instead of the data from 2015-2022, as described in DRIA Chapter 7.1.4.2. Performing this analysis and comparing RNG production to the consumption of RNG-derived CNG/LNG highlights a key point: for all years from 2026-2030, projected RNG production is expected to exceed the projected consumption of RNG-derived CNG/LNG, providing further evidence that future cellulosic RIN generation is limited by the ability of fuel consumers to use RNG as a qualifying transportation fuel.

82 FR 58486 (December 12, 2017).

83 FR 63704 (December 11, 2018).

87 FR 39600 (July 1, 2022).

While RNG production is not expected to be a limiting factor in determining volumes, the future production of RNG will ultimately depend on market demand. Because of this, there is significant uncertainty overall for the production of RNG. One notable source of uncertainty is the potential for significant competing demands for RNG, such as to produce RNG-based ammonia (

e.g.,

for use as fertilizer) and to produce RNG-based hydrogen for use in various process energy applications. While the demand for these products over the 2026-2030 period is highly uncertain, substantial growth in these competing demands for RNG have the potential to further limit the available supply of RNG as a qualifying transportation fuel.

From our analysis of both RNG consumption and production, we believe that cellulosic RIN generation from biogas-derived CNG/LNG during 2026-2030 will be constrained by the total usage of CNG/LNG as transportation fuel (

i.e.,

the total amount of CNG/LNG that can be used in the fleet of CNG- and LNG-powered vehicles). Accordingly, the volumes presented in Table III.B.1.a-2 were used as the volume scenario for biogas-derived CNG/LNG during this period. That said, we recognize that there is considerable uncertainty in these volumes and that the methodology used to determine these volumes are different than what we have done in prior rules. Therefore, we request comment on our projections for cellulosic biofuel production for 2026-2030, specifically regarding our assessment of future CNG/LNG consumption. We also request any additional data or information that could further inform our projections for cellulosic biofuel production during this period.

Table III.B.1.

-2—Estimated Volume of Biogas-Derived CNG/LNG

[Million ethanol-equivalent gallons]

Year

Volume

2026

1,174

2027

1,239

2028

1,309

2029

1,384

2030

1,464

b. Ethanol From Corn Kernel Fiber

Several technologies are currently being developed to produce liquid fuels from cellulosic biomass. However, most of these technologies are unlikely to yield significant volumes of cellulosic biofuel by 2030. One notable exception is the production of ethanol from CKF, for which several companies have developed processes. Many of these processes involve co-processing of both the starch and cellulosic components of the corn kernel. However, to be eligible for generating cellulosic RINs, facilities must accurately determine the amount of ethanol produced specifically from the cellulosic portion using approved methodologies. This requires the ability to reliably and precisely calculate the ethanol derived from the cellulosic component, distinct from the starch portion of the corn kernel. In September 2022, EPA issued updated guidance on analytical methods that could be used to quantify the amount of ethanol produced when co-processing CKF and corn starch.

EPA, “Guidance on Qualifying an Analytical Method for Determining the Cellulosic Converted Fraction of Corn Kernel Fiber Co-Processed with Starch,” EPA-420-B-22-041, September 2022.

EPA has also had substantive discussions with technology providers intending to use analytical methods consistent with this guidance, as well as with owners of facilities registered as cellulosic biofuel producers using these methods. Based on information from these technology providers, EPA believes that cellulosic ethanol production from CKF could be feasible at all existing corn ethanol facilities, with minimal additional processing units or modifications. To generate cellulosic RINs for ethanol produced from CKF, a facility would need to demonstrate the converted fraction consistent with appropriate test methods. For the purposes of this analysis, we assume that 90 percent of facilities will produce cellulosic ethanol over this period due to potential facility-specific challenges that may prevent 100 percent adoption.

Additionally, while technology providers have indicated that using analytical methods consistent with EPA

guidance can demonstrate that approximately 1.5 percent of ethanol produced at existing corn ethanol facilities comes from cellulosic biomass, data submitted to EPA by renewable fuel producers generating cellulosic RINs for CKF ethanol shows that the current industry-wide average among registered facilities is closer to 1 percent. Therefore, for the purposes of this analysis, we are using a 1 percent conversion rate.

The projected production of cellulosic ethanol from CKF, as shown in Table III.B.1.b-1, is based on projections of total corn ethanol production, with a 90 percent facility participation rate and a 1 percent conversion efficiency applied.

We request comment on these projected volumes, including our projections of the percentage of ethanol producers that will generate cellulosic RINs for CKF ethanol through 2027 and the proportion of ethanol from cellulose vs. starch at these facilities.

A detailed discussion of the methodology used to project cellulosic ethanol production from CKF can be found in DRIA Chapter 7.1.5.

Table III.B.1.

-1—Projected Production of Ethanol From CKF

[Million ethanol-equivalent gallons]

Year

Volume

2026

124

2027

123

2028

122

2029

120

2030

119

c. Other Cellulosic Biofuels

We expect that commercial scale production of cellulosic biofuel in the U.S. beyond CNG/LNG derived from biogas and ethanol produced from CKF will be very limited in 2026-2030. There are several cellulosic biofuel production facilities in various stages of development, construction, and commissioning that may be capable of producing commercial scale volumes of cellulosic biofuel by 2030. These facilities primarily focus on producing cellulosic hydrocarbons from feedstocks such as separated municipal solid waste (MSW), precommercial thinnings, and tree residues, which can be blended into gasoline, diesel, and jet fuel. Since no parties have achieved consistent production of liquid cellulosic biofuel in the U.S. or consistently exported liquid cellulosic biofuel to the U.S., production and import of liquid cellulosic biofuel in 2026-2030 is highly uncertain and likely to be relatively small. For the volume scenarios we are analyzing, we have projected no production of these fuels in 2026-2030.

2. Biomass-Based Diesel

CAA section 211(o)(1)(D) defines biomass-based diesel as renewable fuel that is biodiesel and that has GHG emissions reductions of at least 50 percent from the baseline. It also excludes biodiesel that is co-processed with petroleum feedstocks. The BBD standard is nested within the advanced biofuel standard. Historically, the BBD supply under the RFS program has exceeded the BBD standard, with the additional supply used by obligated parties to meet their advanced biofuel volume requirements. Thus, the advanced biofuel standard has incentivized the use of BBD beyond just the BBD standard.

Since 2010, when the BBD volume requirement was added to the RFS program, production of BBD has generally increased annually. The volume of BBD supplied in any given year is influenced by a number of factors, including: production capacity; feedstock availability and cost; available incentives including the RFS program; the availability of imported BBD; the demand for BBD (and feedstocks used to produce BBD) in foreign markets; and several other economic factors.

Most renewable fuel that qualifies as BBD is biodiesel or renewable diesel. Both of these fuels are replacements for petroleum diesel and are produced from the same lipid-based feedstocks, a diverse category that includes animal fats, used cooking oil, and vegetable oil feedstocks. Biodiesel and renewable diesel differ in their production processes and chemical composition. Biodiesel is an oxygenated fuel that is generally produced using a transesterification process. Renewable diesel, on the other hand, is a hydrocarbon fuel that closely resembles petroleum diesel and that is generally produced by hydrotreating renewable feedstocks. From 2010-2018, the vast majority of BBD supplied to the U.S. was biodiesel. Production and imports of renewable diesel emerged in the U.S. in the early 2010s. Market share for renewable diesel began a steady upward trend in 2019, and U.S. domestic supply of these fuels has increased significantly over the past several years. The supply of biodiesel has been relatively stable since 2016 amidst the expansion of renewable diesel supply.

In 2023, the supply of renewable diesel exceeded the supply of biodiesel for the first time (see Figure III.B.2-1). Unlike biodiesel, which is often produced at relatively small facilities, renewable diesel is generally produced at large facilities. While some renewable fuel producers have built new production facilities, much of the renewable diesel produced in the U.S. uses petroleum refining infrastructure that has been converted to produce renewable diesel. Because renewable diesel is more chemically similar to petroleum, it is generally not subject to the same blending limits as biodiesel. This has allowed very large volumes of renewable diesel to be supplied to California and other states with incentives for biofuel use in addition to the incentives provided by the RFS program. In future years we expect to continue to see large increases in the supply of renewable diesel due to the advantages in the economy of scale and the ability to access markets with higher incentives, and a relatively steady supply of biodiesel from established facilities with favorable local markets.

BILLING CODE 6560-50-P

EP17JN25.002

BILLING CODE 6560-50-C

There are also small volumes of renewable jet fuel and heating oil that qualify as BBD.

Renewable jet fuel has qualified as a RIN-generating BBD and advanced biofuel under the RFS program since 2010 and must achieve at least a 50 percent reduction in GHGs in comparison to petroleum-based fuels. The technology and feedstocks that can currently be used to produce renewable jet fuel are often the same as those used to produce renewable diesel. For example, the same process that produces renewable diesel from lipids generally produces hydrocarbons in the distillation range of jet fuel that can be separated and sold as renewable jet fuel instead of being sold as renewable diesel. While relatively little renewable jet fuel has been produced since 2010—20 million gallons or less per year through 2023, increasing to approximately 110 million gallons in 2024—opportunities for increasing this category of advanced biofuel exist.

According to EMTS data renewable jet fuel supply ranged from 0-20 million gallons per year from 2014-2023 and increased to approximately 110 million gallons in 2024. Renewable jet fuel is eligible to generate RINs per 40 CFR 80.1426(a)(1)(iv), provided all other regulatory requirements are met.

A tax credit for renewable jet fuel for tax years 2023 and 2024, often referred to as the “sustainable aviation fuel credit” or “40B credit,” may have resulted in increasing volumes of renewable jet fuel produced from existing renewable diesel production facilities. Another low carbon transportation fuel tax credit, the “clean fuel production credit” or “45Z credit,” is available for tax years 2025-2027, and provides up to $1.75 per gallon of renewable jet fuel, provided the relevant wage and apprenticeship requirements are met by the producer. The 45Z credit may provide continued support for renewable jet fuel production. Renewable jet fuel production from existing renewable diesel facilities, however, would likely result in a decrease in renewable diesel production, with little or no net change in their overall production of RIN-generating fuels.

The equivalence values for renewable diesel and jet fuel are similar. As discussed in Section X.A, we are proposing to revise the renewable diesel equivalence value to be 1.6 RINs per gallon, while also proposing to establish the renewable jet fuel equivalence value to be 1.5 RINs per gallon.

In this rule we have not separately projected growth in renewable jet fuel production, but we recognize that some of the projected growth in renewable diesel production may instead be renewable jet fuel from the same production facilities. Other renewable jet fuel production technologies and production facilities (discussed briefly in Section III.B.2.b) also being developed could enable the future production of renewable jet fuel from new facilities and feedstocks that are not expected to impact renewable diesel production.

The remainder of this section provides historical data on biodiesel and renewable diesel production and production capacity, briefly discusses potential feedstock limitations for

biodiesel and renewable diesel production in future years, and summarizes our assessment of the rate of production and use of qualifying BBD for 2026-2030, along with some of the uncertainties associated with those volumes.

Further details on these volume projections can be found in DRIA Chapter 7.2.

a. Biodiesel

For most of the history of the RFS program, the largest volume of BBD and advanced biofuel supplied in the program each year have been from biodiesel. Domestic biodiesel production increased from approximately 1.3 billion gallons in 2014 to approximately 1.8 billion gallons in 2018. Since 2018, domestic biodiesel production decreased slightly, to approximately 1.7 billion gallons in 2024.

The U.S. has also imported significant volumes of biodiesel in previous years and has been a net importer of biodiesel since 2013. Biodiesel imports reached a peak in 2016, with the majority of the imported biodiesel coming from Argentina.

In August 2017, the U.S. announced tariffs on biodiesel imported from Argentina and Indonesia.

These tariffs were subsequently confirmed in April 2018 and remain in place.

Biodiesel imports started dropping in 2017 but have increased again in recent years, reaching approximately 500 million gallons in 2023 and reduced to 420 million gallons in 2024.

More generally, overall biodiesel supply in the U.S. has remained between 1.6 and 1.8 billion gallons since 2016 (see Figure III.B.2-1).

Id.

In 2016 and 2017, 67 percent of all biodiesel imports were from Argentina. EIA, “U.S. Imports by Country of Origin—Biodiesel,” Petroleum & Other Liquids, April 30, 2025.

https://www.eia.gov/dnav/pet/pet_move_impcus_a2_nus_EPOORDB_im0_mbbl_a.htm.

82 FR 40748 (Aug. 28, 2017).

83 FR 18278 (April 26, 2018).

EIA, “U.S. Imports of Biodiesel,” Petroleum & Other Liquids, April 30, 2025.

https://www.eia.gov/dnav/pet/hist/LeafHandler.ashx?n=pet&s=m_epoordb_im0_nus-z00_mbbl&f=a.

Available data suggests that there is significant unused biodiesel production capacity in the U.S., and thus domestic biodiesel production could grow without the need to invest in additional production capacity. Data reported by EIA shows that domestic biodiesel production capacity in November 2024 was approximately 2.00 billion gallons per year, roughly 0.3 billion gallons more than was utilized.

According to this data, annual average biodiesel production capacity grew relatively slowly from about 2.1 billion gallons in 2012 to a peak of approximately 2.6 billion gallons in 2019. EIA reports that domestic biodiesel production capacity was approximately 2.5 billion gallons as recently as October 2021. This facility capacity data is collected by EIA in monthly surveys, which suggests that this capacity represents the production at facilities that are currently producing some volume of biodiesel and likely does not include facilities that are inactive or have closed, as these facilities are far less likely to complete a monthly survey.

EIA, “U.S. Biodiesel Production Capacity,” Petroleum & Other Liquids, April 30, 2025.

https://www.eia.gov/dnav/pet/hist/LeafHandler.ashx?n=PET&s=M_EPOORDB_8BDPC_NUS_MMGL&f=M.

EPA separately collects facility capacity information through the RFS program facility registration process. This data includes both facilities that are currently producing biodiesel and those that are inactive. EPA's data shows a total domestic biodiesel production capacity of 2.9 billion gallons per year in April 2025, of which 2.6 billion gallons per year was at biodiesel facilities that generated RINs in 2024.

These estimates of domestic production capacity strongly suggest that domestic biodiesel production capacity is unlikely to limit domestic biodiesel production through 2030.

See “BBD Registered Facility Capacity,” available in the docket for this action.

b. Renewable Diesel and Renewable Jet Fuel

Renewable diesel and renewable jet fuel are currently produced using the same feedstocks and very similar production technologies, and in most cases are produced at the same production facilities. For example, Montana Renewables produced both renewable diesel and renewable jet fuel at their Great Falls, Montana facility in 2024.

Historically, greater incentives have been available for renewable diesel production than for renewable jet fuel production, which has meant that in practice most production facilities chose to maximize renewable diesel production. In this section we have focused on renewable diesel production, but we acknowledge that an increasing portion of this fuel may be used as renewable jet fuel in future years.

Montana Renewables, “Products.”

https://montanarenewables.com/products.

In the near term, we expect that any increase in renewable jet fuel production will result in a corresponding decrease in renewable diesel production. We recognize that new technologies are being developed to produce renewable jet fuel from a wider variety of feedstocks, some of which are not suitable for use in the hydrotreating process that dominates renewable diesel production. For example, several companies are developing new technologies intended to produce renewable jet fuel from ethanol or other alcohols, through a technology often referred to as the “alcohol-to-jet” (or “ATJ”) process. To date EPA has not approved a generally applicable pathway for these fuels, but we have approved a facility specific pathway for the production of renewable jet fuel from ethanol to generate BBD RINs.

While ATJ has the potential to produce significant volumes of renewable jet fuel in future years, there is a high degree of uncertainty related to the production of these fuels through 2030 as commercial scale production of these fuels has been limited and no RINs have yet been generated for these fuels. Production of renewable jet fuel using these emerging technologies may not negatively impact renewable diesel production to the extent that they do not compete for feedstocks. Through 2027, however, we expect that only relatively modest volumes of fuels might be produced through these emerging technologies. We request comment on the potential production volume of such renewable jet fuel through 2027 and any technical and economic data that would help inform our understanding of the potential impacts of the production of renewable jet fuel through the ATJ process on the statutory factors.

See EPA, “Letter from EPA to LanzaJet, Inc.,” January 12, 2023.

Renewable diesel has historically been produced and imported in smaller quantities than biodiesel, as shown in Figure III.B.2-1. In recent years, however, domestic production of renewable diesel has increased significantly. Renewable diesel production facilities generally have higher capital costs and production costs relative to biodiesel, which likely accounts for the historically higher volumes of biodiesel production relative to renewable diesel production prior to 2023. The higher cost of renewable diesel production can largely be offset through the benefits of economies of scale, since renewable diesel facilities tend to be much larger than biodiesel production facilities.

For example, according to EMTS data, in 2024, there were 23 renewable diesel facilities that produced an average of 157 million gallons of renewable diesel per facility, compared to 71 biodiesel facilities that

produced an average of 29 million gallons of biodiesel per facility.

See DRIA Chapter 10 for more detail on our assessment of the cost to produce biodiesel and renewable diesel.

See “Analysis of BBD RIN Generation by Facility Size,” available in the docket for this action.

More importantly, because renewable diesel more closely resembles petroleum diesel than biodiesel (both renewable diesel and petroleum diesel are hydrocarbons while biodiesel is a methyl-ester), renewable diesel can be blended at much higher concentrations with diesel than biodiesel (it is for this reason that renewable diesel is sometimes referred to as a “drop-in” fuel). This allows renewable diesel to more easily be blended into diesel at higher rates and enables renewable diesel producers to sell greater volumes of renewable diesel in California, benefiting from the LCFS credits in California in addition to RFS incentives and the federal tax credit.

The greater ability for renewable diesel to generate credits under California's LCFS program provides a significant advantage over biodiesel. Biodiesel blends in California containing 6-20 percent biodiesel require the use of an additive to comply with California's Alternative Diesel Fuels Regulations, making the use of higher-level biodiesel blends more challenging in California.

The Washington and Oregon programs modeled from the California LCFS have generally mirrored this incentive structure, and the emerging New Mexico program may do so as well. If additional States were to adopt clean fuels programs using a similar structure, these programs could provide an additional advantage to renewable diesel production relative to biodiesel production in the U.S.

For example, when LCFS credits are worth $100/metric ton, blending renewable diesel into California generates LCFS credits worth approximately $0.25 to $0.90 per gallon (assuming carbon intensities of 70 and 20 gCO

e/MJ respectively). Renewable fuel producers that sell qualifying renewable fuel in California can generate both RINs under the RFS program and LCFS credits.

CARB, “Frequently Asked Questions on the Alternative Diesel Fuels Regulation,” November 2017. In 2021, nearly all renewable diesel consumed in the U.S. was consumed in California. Together renewable diesel and biodiesel represented approximately 65-70 percent of all diesel fuel consumed in California in the second half of 2024.

Total domestic renewable diesel production capacity has increased significantly in recent years from approximately 280 million gallons in 2017

to approximately 4.6 billion gallons at the end of 2024.

Additionally, a number of parties have announced plans to build new renewable diesel production capacity with the potential to begin production in future years. This new capacity includes new renewable diesel production facilities, expansions of existing renewable diesel production facilities, and the conversion of units at petroleum refineries to produce renewable diesel.

Renewable diesel capacity based on facilities registered in EMTS.

EIA, “U.S. Total Biofuels Operable Production Capacity,” Petroleum & Other Liquids, April 30, 2025.

https://www.eia.gov/dnav/pet/pet_pnp_capbio_dcu_nus_m.htm.

EIA currently projects that renewable diesel production capacity will continue to expand and could reach nearly 6 billion gallons by the end of 2025.

A recent report published by the National Renewable Energy Laboratory found that by 2028 the domestic production capacity for renewable diesel and renewable jet fuel through the hydrotreating process alone could increase to 9.6 billion gallons per year.

In previous years, domestic renewable diesel production has increased in concert with increases in domestic production capacity, with renewable diesel facilities generally operating at high utilization rates. In future years we expect that competition for affordable qualifying feedstocks may result in renewable diesel and biodiesel facilities operating below their production capacity. Competition for qualifying feedstocks could also result in reductions in overall biodiesel production if larger renewable diesel facilities are able to out-compete smaller biodiesel producers for feedstock. Further, even if these facilities operate at levels close to their production capacity, demand for renewable diesel and renewable jet fuel in other countries may impact the quantity of these fuels available to U.S. markets.

EIA, “Domestic renewable diesel capacity could more than double through 2025,” Today in Energy, February 2, 2023.

https://www.eia.gov/todayinenergy/detail.php?id=55399.

Calderon, Oscar Rosales, Ling Tao, Zia Abdullah, Michael Talmadge, Anelia Milbrandt, Sharon Smolinski, Kristi Moriarty, et al. “Sustainable Aviation Fuel State-of-Industry Report: Hydroprocessed Esters and Fatty Acids Pathway,” National Renewable Energy Laboratory NREL/TP-5100-87803, July 30, 2024.

https://doi.org/10.2172/2426563.

In addition to domestic production of renewable diesel, the U.S. has also imported renewable diesel, with nearly all of it produced from fats, oils, and greases (FOG) and imported from Singapore.

In more recent years, the U.S. has also exported increasing volumes of renewable diesel. In 2022-2024, renewable diesel exports exceeded renewable diesel imports based on data collected through EMTS (see Table III.B.2.b-1). This situation, wherein significant volumes of renewable diesel are both imported and exported, is likely the result of a number of factors, including the design of the biodiesel tax credit (which is available to renewable diesel that is either produced or used in the U.S. and thus eligible for exported volumes as well), the varying structures of incentives for renewable diesel (with the level of incentives varying depending on the feedstocks used to produce the renewable diesel varying as well as by country), and logistical considerations (renewable diesel may be imported and exported from different parts of the country). Starting in 2025, the 45Z credit, which consolidates and replaces the previous $1 per gallon credit for blending biodiesel and renewable diesel into diesel fuel under 40A, also provides a production credit for alternative fuels and sustainable aviation fuel. Since the new 45Z credit is only available for fuel produced in the United States, it may result in significantly decreased renewable fuel imports and may in turn also decrease renewable fuel exports as domestic producers seek to satisfy demand previously met by imported renewable fuels.

EIA, “U.S. Imports by Country of Origin—Renewable Diesel Fuel,” Petroleum & Other Liquids, April 30, 2025.

https://www.eia.gov/dnav/pet/pet_move_impcus_a2_nus_EPOORDO_im0_mbbl_a.htm.

Table III.B.2.

-1—Renewable Diesel Imports and Exports

[Million gallons]

Year

Renewable

diesel imports

Renewable

diesel exports

Net imports

2015

120

2016

165

125

2017

191

154

2018

176

2019

267

148

119

2020

280

223

2021

262

241

121

2022

311

326

−15

2023

361

414

−53

2024

430

581

−151

c. Domestic BBD Feedstocks

When considering the potential production and import of biodiesel and renewable diesel in future years and the likely impacts of renewable diesel production, the availability of feedstocks is a key consideration. Currently, biodiesel and renewable diesel in the U.S. are produced from a number of different feedstocks, including FOG, distillers corn oil, and virgin vegetable oils such as soybean oil and canola oil.

EP17JN25.003

Use of soybean oil to produce biodiesel grew from approximately 10 percent of all domestic soybean oil production in the 2009/2010 agricultural marketing year to 48 percent in the 2023/2024 agricultural marketing year.

In the intervening years, the total increase in domestic soybean oil production and the increase in the quantity of soybean oil used to produce biodiesel and renewable diesel were similar, indicating that the increase in oil production was likely driven by the increasing demand for biofuel. However, as the production of renewable diesel has increased in recent years it appears that demand for soybean oil is growing faster than demand for soybean meal. Notably, the percentage of the soybean value that came from the soybean oil (rather than the meal and hulls) had been relatively stable and averaged approximately 33 percent from 2016-2020. The percentage of the soybean value that came from the soybean oil increased significantly starting in 2021, however, reaching a high of 53 percent in October 2021, before declining slightly to 39 percent in August 2024 (the most recent date for which data are available).

USDA, “Oil Crops Yearbook,” March 2025.

https://www.ers.usda.gov/data-products/oil-crops-yearbook.

Id.

Through 2020, most of the renewable diesel produced in the U.S. was made from FOG and distillers corn oil, with smaller volumes produced from soybean oil.

While some biodiesel production facilities are unable to use FOG and distillers corn oil without additional capital investment, renewable diesel production facilities are generally able to use them. Additionally, through 2024 the vast majority of renewable diesel consumed in the U.S. is used in

California due to the combined value of RFS and LCFS incentives (together with the blenders' tax credit). Under California's LCFS program, renewable diesel produced from FOG and distillers corn oil receive more credits than renewable diesel produced from soybean oil and canola oil.

In December 2022, EPA approved generally applicable pathways for renewable diesel produced from canola oil (87 FR 73956; December 2, 2022). Use of canola oil to produce renewable diesel for consumption in the U.S. was therefore rare before 2023, but has gradually become more common in recent years.

Available volumes of FOG (including used cooking oil and animal fats) and distillers corn oil from domestic sources are expected to continue to increase in future years, but these increases are expected to be limited. FOG are the byproducts of other activities (

e.g.,

food production and rendering operations), and production of FOG is not responsive to increasing demand for biofuel production. Because the production of FOG is generally not responsive to increased demand and most of the available domestic FOG is currently used for biofuel production or in other industries, we expect the availability of FOG to increase slowly, consistent with the observed trend in recent years. Similarly, distillers corn oil is a byproduct of ethanol production. Since we do not anticipate significant growth in ethanol production in future years (see Section III.B.4), we do not project significant increases in the production of distillers corn oil for biofuel production, as most ethanol production facilities currently produce distillers corn oil. Therefore, if renewable diesel production in future years increases rapidly as suggested by the large production capacity announcements, it will likely require increased use of vegetable oils such as soybean oil and canola oil, either from new production or diverted from other markets, or increased use of imported feedstocks.

Greater volumes of soybean oil are projected to be produced from new or expanded soybean crushing facilities through 2030. Several parties have announced plans to expand existing soybean crushing capacity or build new soybean crushing facilities. Public announcements of new and expanded soybean crushing capacity suggest that domestic soybean crush capacity could increase by approximately 1.5 million bushels of soybeans per day from 2024 through 2026.

An increase in the domestic crush capacity of this magnitude would result in an increase in domestic soybean oil production sufficient to produce approximately 750 million additional gallons of BBD per year and suggests a 250 million gallon per year annual increase in soybean oil production through 2026.

Similarly, an assessment of potential BBD feedstocks in future years prepared for the National Oilseed Processors Association by S&P Global estimated that increases in domestic soybean oil production could support the production of an additional 1 billion gallons of BBD from 2023 to 2027.

Most of the publicly announced expansion in soybean crush capacity is scheduled to occur in the next few years, through 2027. Recent data suggests that the domestic soybean crushing industry is capable of continuing to add significant capacity in future years, but that any investment in domestic soybean crushing is highly dependent on demand for soybean oil (and soybean meal) from biofuel producers and other markets.

Futrell, Crystal, “US Soybean Crush Capacity on the Rise,” World-Grain.com, January 5, 2024.

https://www.world-grain.com/articles/19463-us-soybean-crush-capacity-on-the-rise.

This estimate assumes a soybean oil yield of 11 lbs per bushel of soybeans and 1 gallon of BBD per 7.75 lbs of soybean oil.

S&P Global, “Availability of Feedstocks for Biofuel Use—Key Highlights,” July 2024.

See DRIA Chapter 7.2 for a further discussion of this topic.

If domestic crushing of soybeans increases at the expense of soybean exports, domestic vegetable oil production could increase without the need for increasing domestic soybean acreage. Alternatively, increased demand for soybeans from new or expanded crushing facilities could be met through increased soybean production in the U.S. Increased demand for BBD feedstock could also be met through diversion of increasing volumes of qualifying feedstocks (

e.g.,

soybean oil and canola oil) from existing markets to produce renewable diesel. Were this diversion to occur, non-qualifying feedstocks (

e.g.,

palm oil or other virgin vegetable oils) could be used in larger quantities in place of soybean and canola oil in food and oleochemical markets. Diverting feedstocks from existing uses would be projected to result in higher prices for these feedstocks, as biofuel producers would have to outbid the current users of these feedstocks.

d. Imported BBD Feedstocks

In addition to processing domestic feedstocks such as distillers corn oil and soybean oil, a number of domestic BBD producers produce BBD from imported feedstocks. In recent years, and as multiple stakeholders have noted to EPA, the market has seen a significant increase in the quantity of imported BBD feedstocks. Imports of feedstocks that are often considered wastes or by-products of other industries, such as used cooking oil and tallow, have seen the greatest increase in recent years. Figure III.B.2.d-1 shows total imports of common BBD feedstocks through 2024. Figure III.B.2.d-2 shows the total volumes of domestic BBD produced from domestic feedstocks, domestic BBD produced from imported feedstocks, and imported BBD.

BILLING CODE 6560-50-P

EP17JN25.004

EP17JN25.005

There are several factors that have likely contributed to the recent increases in imports of certain BBD feedstocks to the U.S. Three key factors contributing to the increase in imported feedstocks are increasing domestic demand for these feedstocks, increasing available supply of these feedstocks in other countries, and the structure of

incentive programs for biofuels in the U.S. relative to other countries' polices. As noted in Section III.B.2.b, the production capacity for renewable diesel and renewable jet fuel has increased rapidly and is expected to continue to grow in future years. As the total production capacity for these fuels has grown, the demand for feedstocks for renewable fuel production has grown along with the production capacity. While some of this demand has been met by the increasing production of domestic feedstocks, domestic feedstock production has not grown as quickly as has the production capacity for renewable diesel and renewable jet fuel. Renewable diesel and renewable jet fuel producers have thus turned to imports to source the feedstocks needed to support increased BBD production.

At the same time domestic demand for these feedstocks has been increasing, the supply available to import from other countries has also been increasing. For example, we project that production of canola oil will increase in future years due to expanding canola crushing capacity in Canada.

Similar to the investments in soybean crushing in the U.S., a number of companies have announced investment in additional canola crushing capacity in Canada, and some of these projects are already under construction. Increasing canola oil production in Canada could provide an opportunity for domestic renewable diesel producers to import canola oil for biofuel production. We note that these parties will face competition for this feedstock from Canadian biofuel producers as well as food and other non-biofuel markets. For example, in 2023, Canada began implementing their Clean Fuels Requirements, requiring that the carbon intensity of transportation fuel decrease by 1.5 gCO

e/MJ per year each year from 2023 to 2030.

These regulations are expected to increase demand for biofuels and biofuel feedstocks in Canada, and therefore also impact the quantities of canola oil and other feedstocks available for export to the U.S.

Some of the projected expansion in soybean crushing capacity discussed in Section III.B.2.c is from facilities also capable of crushing canola and other oilseeds. Domestic production of canola is limited, however, and the majority of canola oil supplied to biofuel producers through 2027 is expected to be imported from Canada.

Government of Canada, “What are the Clean Fuel Regulations?” July 7, 2022.

https://www.canada.ca/en/environment-climate-change/services/managing-pollution/energy-production/fuel-regulations/clean-fuel-regulations/about.html.

The incentives available in foreign countries to encourage the production and use of BBD are also changing. In response to the increase in the prices of energy and agricultural commodities caused by the Russian invasion of Ukraine in February 2022, a number of countries, including Croatia, Czech Republic, Finland, Latvia, Poland, and Sweden, temporarily reduced biofuel mandates and/or the penalties for not fulfilling the mandates.

The reduction in demand from these countries resulted in an increase in the available feedstock supply to the U.S.

USDA, “Biofuel Mandates in the EU by Member State—2024,” June 27, 2024.

At the same time, the European Union (EU) in recent years took actions to discourage the importation of used cooking oil (UCO) and biodiesel produced from UCO from China, which had previously been supplied in significant volumes. On December 20, 2023, the EU announced an anti-dumping investigation on biodiesel imported from China.

This investigation resulted in provisional duties on biodiesel from China sold in the EU, which were announced in July 2024.

The anti-dumping investigation and resulting fiscal duties on biodiesel imported from China from the EU opened up an opportunity for increased exports of UCO (the primary feedstock used to produce biodiesel in China previously exported to the EU) from China to the U.S.

European Commission, “European Commission to Examine Allegations of Unfairly Traded Biodiesel from China,” December 20, 2023.

https://policy.trade.ec.europa.eu/news/european-commission-examine-allegations-unfairly-traded-biodiesel-china-2023-12-20_en.

Reuters, “EU to Set Tariffs on Chinese Biodiesel in Anti-Dumping Probe,” July 19, 2024.

https://www.reuters.com/business/energy/eu-set-tariffs-chinese-biodiesel-imports-anti-dumping-probe-2024-07-19.

Finally, incentive programs for biofuels in the U.S. have contributed to the recent observed increases in biofuel feedstock imports. State low carbon fuel standards or clean fuels programs, such as California's LCFS, provide greater incentives for fuels with lower carbon intensities. In general, fuels produced from wastes or by-products such as UCO or tallow have lower carbon intensity values under these programs and thus generate greater credits relative to virgin vegetable oils such as soybean oil and canola oil. In recent years additional States such as Oregon, Washington, and New Mexico have adopted programs that similarly provide higher incentives for fuels with lower carbon intensity.

While these State programs do not explicitly favor imported fuels and/or feedstocks over domestic fuels and feedstocks, most of the available waste and by-product feedstocks such as UCO and tallow available in the U.S. are already being used for biofuel production. The nature of these programs has likely played a role in biofuel producers seeking to import UCO and tallow from foreign countries rather than increasing their use of domestic soybean oil to maximize their generation of credits under these programs.

Changes to the RFS program have also contributed to the observed increase in feedstock imports. In December 2022, EPA approved generally applicable pathways for certain fuels, including renewable diesel, that are produced from qualifying canola oil.

The ability for renewable diesel producers to generate RINs for renewable diesel produced from canola oil created a new demand for canola oil in the U.S.

87 FR 73956 (December 2, 2022).

Together, the trends and policy factors described above collectively contributed to increasing imports of BBD feedstocks since 2021. We discuss the impact of these dynamics, and a proposed response to them in the RFS program, in Section VIII.

e. Summary

BBD (including biodiesel, renewable diesel, and renewable jet fuel) has been the fastest growing category of renewable fuel in the RFS program since 2021, with nearly all of the growth coming from renewable diesel. While the domestic supply of BBD feedstocks continues to grow, in recent years imported BBD and BBD produced from imported feedstocks have accounted for an increasing share of the total supply of BBD. BBD production capacity currently exceeds actual production and imports of these fuels by a significant margin, and ongoing investment is expected to result in significantly higher production capacity in future years, particularly for renewable diesel and renewable jet fuel. Further, because of the high blending rates for BBD in general and renewable diesel in particular, the use of BBD in the U.S. is unlikely to be constrained by limitations related to the ability to distribute these fuels or consume them in existing and future diesel engines.

In the absence of constraints related to the production capacity and the ability for the market to distribute and use BBD, the factors most likely to have the largest impact on the quantity of BBD required under the RFS program—in light of our analysis of the statutory factors—is the availability of affordable qualifying feedstocks, competition for those feedstocks for other uses, and competition for them abroad. The

sources of the feedstocks used to produce BBD also indirectly impact other factors, as the environmental and economic impacts of supplying additional volumes of BBD to the U.S. differ depending on the feedstocks used to produce the BBD and the likely alternative use of those feedstocks. For example, the projected economic and environmental impacts of increasing BBD production vary depending on whether the feedstock used to produce the BBD was UCO that would not otherwise have been collected, soybean oil from additional production and processing of soybeans, or the diversion of feedstocks or biofuels that would otherwise have been used in other countries.

In developing the volume scenarios for analysis in this action, we have therefore not attempted to identify the absolute maximum quantity of BBD that could be produced utilizing all potentially available production capacity and used in the U.S. Instead, we have developed two volume scenarios that reflect different growth rates for the quantity of BBD used in the U.S. based on our projections of the potential growth in available feedstocks. Both scenarios start with an updated projection of the supply of BBD to the U.S. which reflects the expected market conditions for 2025 based on the most recent available data at the time these scenarios were developed.

The low growth scenario increases the supply of BBD by 500 million RINs each year, a quantity approximately equal to our projection of the potential for growth in waste and byproduct feedstocks such as UCO and tallow, primarily from foreign sources. The high growth scenario increases the supply of BBD by 1 billion RINs each year, a quantity approximately equal to our projection of the potential growth for waste and byproduct feedstocks (primarily imported) and potential growth in virgin vegetable oil production that could be available to biofuel producers from the U.S. and Canada. These two scenarios are summarized in Table III.B.2.e-1 (in billion RINs) and III.B.e-2 (in billion gallons). More detail on the development of these scenarios can be found in DRIA Chapters 3 and 6.

Note that the quantity of BBD expected to be supplied in 2025 based on the available data (7.91 billion RINs) is significantly higher than the quantity of BBD projected to be used in 2025 in the Set 1 Rule (6.88 billion RINs). See DRIA Chapter 7.2 for more detail on the projected BBD supply for 2025.

Table III.B.2.

-1—BBD Volume Scenarios

[Billion RINs]

Scenario

2025

2026

2027

2028

2029

2030

Low Growth

7.91

8.41

8.91

9.41

9.91

10.41

High Growth

7.91

8.91

9.91

10.91

11.91

12.91

Table III.B.2.

-2—BBD Volume Scenarios

[Billion gallons]

Scenario

2025

2026

2027

2028

2029

2030

Low Growth

5.08

5.39

5.70

6.01

6.33

6.64

High Growth

5.08

5.70

6.33

6.95

7.58

8.20

3. Other Advanced Biofuel

In addition to BBD, other renewable fuels that qualify as advanced biofuel have been consumed in the U.S. in the past and are expected to contribute to compliance with applicable RFS volume requirements in the future. These other advanced biofuels include imported sugarcane ethanol, domestically produced advanced ethanol, RNG used in CNG/LNG vehicles not produced from cellulosic biomass, and heating oil, naphtha, and renewable diesel that does not qualify as BBD.

However, these biofuels have been consumed in much smaller quantities than biodiesel and renewable diesel in the past or have been highly variable.

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

To estimate the volumes of these other advanced biofuels that may be available in 2026-2030, we used the same general methodology as in the Set 1 Rule, which EPA originally presented in the Set 1 Rule. We projected the supply of these other advanced biofuels by including data on the supply of these fuels from 2023 (the most recent data available at the time the volume scenarios were defined). This methodology addresses the historical variability in these categories of advanced biofuel while recognizing that consumption in more recent years is likely to provide a better basis for making future projections than consumption in earlier years. Specifically, we applied a weighting scheme to historical volumes wherein the weighting was higher for more recent years and lower for earlier years. The result of this approach is shown in Table III.B.3-1. Details of the derivation of these estimates can be found in RIA Chapter 5.4. As the available data varies significantly from year to year, it does not allow us to identify an upward or downward trend in the historical consumption of these other advanced biofuels. Therefore, we have used the volumes in Table III.B.3-1 for all years in the volume scenarios for analysis (

i.e.,

2026-2030).

Table III.B.3-1—Estimate of Annual Consumption of Other Advanced (D5) Biofuel

[Million RINs]

Fuel

Volume

Imported sugarcane ethanol

Domestic ethanol

CNG/LNG

Heating oil

Naphtha

Renewable diesel

111

Total

249

This table does not include fuels that qualify as cellulosic biofuel or BBD.

While renewable naphtha is generally a co-product of renewable diesel production, the supply of renewable naphtha has not increased in line with the observed increases in renewable diesel production.

Includes renewable diesel that is co-processed with petroleum, which does not qualify as BBD.

4. Conventional Renewable Fuel

Conventional renewable fuel includes any renewable fuel that is made from renewable biomass as defined in 40 CFR 80.1401, does not qualify as advanced biofuel (including cellulosic biofuel and BBD), and meets one of the following criteria:

• Is demonstrated to achieve a minimum 20 percent reduction in lifecycle GHG emissions in comparison to the gasoline or diesel which it displaces; or

• Is exempt (“grandfathered”) from the 20 percent minimum GHG reduction requirement due to having been produced in a facility or facility expansion that commenced construction on or before December 19, 2007, as described in 40 CFR 80.1403 and pursuant to CAA section 211(o)(2)(A)(i).

Under the statute, there is no volume requirement for conventional renewable fuel. Instead, conventional renewable fuel may fill that portion of the total renewable fuel volume requirement that is not required to be advanced biofuel. In some cases, this portion of the total renewable fuel requirement that can be met with conventional renewable fuel is referred to as an “implied” volume requirement. However, obligated parties are not required to comply with it per se, since any portion of it can be met with advanced biofuel volumes exceeding what is needed to meet the advanced biofuel volume requirement.

To project volumes of conventional renewable fuel for 2026-2030, we focused primarily on projecting volumes of corn ethanol consumed via motor gasoline use across all gasoline blends with varying concentrations of ethanol (

i.e.,

E10, E15, E85). We also investigated potential volumes of non-advanced biodiesel and renewable diesel.

a. Corn Ethanol

Ethanol made from corn starch has dominated the renewable fuels market on a volume basis in the past and is expected to continue to do so for the years addressed by this rulemaking.

Corn starch ethanol is prohibited by CAA section 211(i)(1)(B)(i) from being an advanced biofuel regardless of its lifecycle GHG emissions performance in comparison to gasoline.

Conventional ethanol from feedstocks other than corn starch have been produced in the past, but at significantly lower volumes. Production of ethanol from grain sorghum reached 125 million gallons in 2019, representing just less than 1 percent of all conventional ethanol in that year; grain sorghum ethanol in 2024 was only 46 million gallons. Waste industrial ethanol and ethanol made from non-cellulosic portions of separated food waste have been produced more sporadically and at even lower volumes. These other sources do not materially affect our assessment of volumes of conventional ethanol that can be produced.

Total domestic corn ethanol production capacity increased dramatically between 2005 and 2010 and increased at a slower rate thereafter. As of early 2024, domestic corn ethanol production capacity exceeded 18 billion gallons.

86 87

Actual production of corn ethanol in the U.S. was approximately 16.2 billion gallons in 2024, up from approximately 15.6 billion gallons in 2023.

Renewable Fuels Association, “2024 Ethanol Industry Outlook,” February 19, 2024.

EIA, “U.S. Fuel Ethanol Plant Production Capacity,” Petroleum & Other Liquids, August 15, 2024.

https://www.eia.gov/petroleum/ethanolcapacity.

EIA, “Monthly Energy Review,” Total Energy, March 2025.

https://www.eia.gov/totalenergy/data/monthly/archive/00352503.pdf.

The expected annual rate of future commercial production of corn ethanol will continue to be driven primarily by gasoline demand in 2026-2030, as most gasoline is expected to continue to contain 10 percent ethanol during this period. Commercial production of corn ethanol is also a function of exports of ethanol and the demand for E0, E15, and E85. There is evidence that some fuel retailers sell higher volumes of E15 than E10, leveraging lower prices at the pump and marketing higher-level ethanol blends to their customers as a cheaper fuel option with only negligible effects on fuel economy (a 1-2 percent reduction compared to E10). In addition to government incentives, industry-led efforts such as Prime-the-Pump have enjoyed great success in growing markets for higher ethanol gasoline blends by providing technical and financial assistance to fuel retailers.

Acknowledging the potential for growth in these fuel markets, we have incorporated projected growth in opportunities for sales of E15 and E85 blends into our assessment.

Transportation Energy Institute, “The Case of E15,” February 2018.

Despite this steady growth, there remains excess of production capacity of ethanol and corn feedstock in comparison to the ethanol volumes that we estimate will be consumed domestically during 2026-2030, given constraints on U.S. ethanol consumption as described in Section III.B.5. Thus, as was the case with the Set 1 Rule, we do not expect production capacity to be a limiting factor for meeting the volume scenarios analyzed in this action.

b. Biodiesel and Renewable Diesel

Other than corn ethanol, the only other conventional renewable fuels that have been used at significant levels in the U.S. in recent years have been conventional biodiesel and renewable diesel. Conventional biodiesel and renewable diesel are produced at facilities grandfathered under 40 CFR 80.1403 because there are no currently valid RIN-generating pathways for their production. Almost all conventional biodiesel and renewable diesel historically used in the U.S. was imported, with the only exceptions being less than 15 million gallons per year produced domestically between 2014 and 2024. The use of conventional biodiesel and renewable diesel did grow marginally in 2024 after a period of very low volume (less than 1 million gallons per year from 2018-2022), though the overall supply remained negligible (less than 0.1 percent of total biofuel supply

to the U.S.). While some sparse generation of D6 RINs

for these fuels have been observed in recent years, nearly all these RINs were retired for being designated for use in any application other than transportation fuel and therefore do not represent qualifying fuel under the RFS program. As discussed in DRIA Chapter 7.7, there exists much greater potential for domestic production and use of conventional biodiesel and renewable diesel than has actually been supplied in prior years, suggesting the use of these fuels in the U.S. is largely a function of domestic demand versus other markets. While there exists some potential for growth across the period covered by this proposed rule, we are not projecting any increased volumes of these fuels will be used in 2026-2030.

The D codes given for each component category are defined in 40 CFR 80.1425(g). D codes are used to identify the statutory categories that can be fulfilled with each component category according to 40 CFR 80.1427(a)(2). D6 RINs satisfy only the “renewable fuel” category.

5. Ethanol Consumption

Ethanol consumption in the U.S. is dominated by E10, with higher-level ethanol blends such as E15 and E85 being used in much smaller quantities. The total volume of ethanol that can be consumed—including ethanol produced from corn, grain sorghum, cellulosic biomass, the non-cellulosic portions of separated food waste, and sugarcane—is a function of demand for these three ethanol blends and for E0. The distribution of consumption for these different gasoline blends is best reflected by measuring the observed poolwide ethanol concentration. Ethanol concentration across the entire gasoline pool can exceed 10 percent only insofar as the incremental ethanol in E15 and E85 volumes more than offsets the lack of ethanol in E0 volume. Poolwide ethanol concentration increased dramatically from 2003 through 2010 and has continued to grow more slowly since 2010. As the average ethanol concentration approached and then exceeded 10 percent, the gasoline pool became saturated with E10, with a small, likely stable volume of E0 and small but gradually increasing volumes of E15 and E85. We expect this trend to continue during 2026-2030.

EP17JN25.006

For this action, new volume data from USDA's Higher Blends Infrastructure Incentive Program (HBIIP)

and additional volume data acquired directly from six States with high volumes of higher-level ethanol blends (California, Kansas, Iowa, Minnesota, New York, and North Dakota) has enabled a data-driven, bottom-up approach to projecting ethanol volumes into the future that differs from the way these projections were calculated in previous years.

In the Set 1 Rule, we projected ethanol concentration in the national gasoline pool using a least-squares regression model using then-current E15 and E85 fueling station population data.

This was due to lack of data and a subsequent inability to aggregate sales volumes by ethanol volume at the retail fuel station level. Now, greater availability of sales volume data from the six aforementioned States, HBIIP, and industry partners has enabled an updated and simplified methodology for producing the ethanol volume projections in this action.

USDA, “Higher Blends Infrastructure Incentive Program,” May 2023.

https://www.rd.usda.gov/hbiip.

See DRIA Chapter 7.5.1 for more information on our projections of ethanol concentration in the gasoline pool.

See “Renewable Fuel Standard (RFS) Program: Standards for 2023-2025 and Other Changes Regulatory Impact Analysis,” EPA-420-R-23-015, June 2023 (“RFS Set 1 RIA”), Chapter 7.5.1.

Using the average sales of each gasoline-ethanol blend per retail fueling station, as well as updated station populations from DOE's Alternative Fuels Data Center (AFDC)

and the California Air Resources Board (CARB)

for 2021-2023, we produced

forecasts of expected growth in station counts and throughputs out to 2030 for each gasoline-ethanol blend other than E10. We then used these forecasts to project the total fuel volume for these gasoline-ethanol blends (E0, E15, and E85) for 2026-2030 using the following relation: for gasoline-ethanol blends at each concentration, the total fuel volume consumed in any given year is equal to the product of the number of retail fueling stations offering that blend for sale and the volume of that fuel blend sold at a fueling station (

i.e.,

throughput) on average during that year. Finally, we projected E10 as the remainder of the gasoline pool, after accounting for the projected volumes of E0, E15, and E85.

AFDC, “Historical Alternative Fueling Station Counts.”

https://afdc.energy.gov/stations/states.

CARB, “Annual E85 Volumes,” April 11, 2025.

Total ethanol consumption is the sum of ethanol blended with gasoline (E0) to create E10, E15, and E85.

The ethanol portion of the projected total consumption for each fuel blend (

i.e.,

total ethanol consumption) is shown in Table III.B.5-1. While we project that the ethanol concentration in the gasoline pool will increase in future years, total ethanol consumption is projected to decrease due to decreases in total gasoline consumption in future years.

See DRIA Chapter 7.5.1 for a more comprehensive discussion of the methodology employed to produce the total ethanol consumption projection.

Table III.B.5-1—Projected Ethanol Concentration and Consumption

Year

Projected ethanol

concentration

(%)

Projected ethanol consumption

(million gallons)

2026

10.54

13,993

2027

10.58

13,871

2028

10.60

13,724

2029

10.67

13,558

2030

10.71

13,377

C. Volume Scenarios for 2026-2030

Based on the analyses described in Section III.B, we developed two different volume scenarios for 2026-2030 that we then used to analyze the expected impacts of the statutory factors. This section describes the volume scenarios, while Section IV summarizes the results of the analyses we performed. The volumes we are proposing in this action based on the analysis of the statutory factors are described in Section V.

Both of the volume scenarios developed for this action represent growth in the advanced biofuel and total renewable fuel categories relative to the volume of these fuels we expect to be supplied in 2025. Further, both scenarios are identical in the quantities of cellulosic biofuel, advanced biofuel other than BBD, and conventional renewable fuel we project will be supplied. Where the scenarios differ is in the quantity of BBD we project will be supplied in each year. Throughout this action we refer to these two scenarios as the Low Volume Scenario and the High Volume Scenario (or collectively, “the Volume Scenarios”), though we note that even the Low Volume Scenario represents an annual growth rate of 500 million RINs per year of BBD.

In developing the Volume Scenarios, we have considered the implied volumes for each component category of renewable fuel (cellulosic biofuel, non-cellulosic advanced biofuel, and conventional renewable fuel) in the statutory tables through 2022. While these volumes are not binding on the volume requirements in future years, they do provide an indication of statutory intent. We also considered the statutory intent of the RFS program to increase renewable fuel volumes over time, along with other factors enumerated in the statute to inform the proposed volumes.

Given the nested nature of the statutory renewable fuel categories, we have largely framed our assessment of volumes in terms of the component categories rather than in terms of the statutory categories (cellulosic biofuel, advanced biofuel, total renewable fuel). The statutory categories are those addressed in CAA section 211(o)(2)(B)(i)-(iii), and cellulosic and advanced biofuel are nested within the overall total renewable fuel category. The component categories are the categories of renewable fuels that make up the statutory categories, but which are not nested within one another. They possess distinct economic, environmental, technological, and other characteristics relevant to the factors we must analyze under the statute, making our focus on them rather than the nested categories in the statute technically sound. Finally, an analysis of the component categories is equivalent to analyzing the statutory categories, since doing so would effectively require us to evaluate the difference between various statutory categories (

e.g.,

assessing “the difference between volumes of advanced biofuel and total renewable fuel” instead of assessing “the volume of conventional renewable fuel”), adding unnecessary complexity to our analysis. In any event, were we to frame our analysis in terms of the statutory categories, we believe that our substantive approach and conclusions would remain materially the same.

1. Cellulosic Biofuel

In determining the cellulosic biofuel volume scenario, we started by considering the statutory volume targets for 2010-2022. The statutory volumes for cellulosic biofuel increased rapidly, from 100 million gallons in 2010 to 16 billion gallons in 2022 with the largest increases in the later years. While notable on its own, it is even more notable in comparison to the implied statutory volumes for the other renewable fuel volumes. Statutory BBD volumes did not increase after 2012, implied conventional renewable fuel volumes did not increase after 2015, and non-cellulosic advanced biofuel volume increases tapered off in recent years with a final increment in 2022. Thus, the clear focus of the statute, and CAA section 211(o)(1)(E) in particular, by 2022 was on growth in cellulosic biofuel volumes, which have the greatest GHG reduction threshold requirement in the statute.

Cf.

CAA section 211(o)(1)(B)(i), (D), (2)(A)(i). See also definition of “cellulosic biofuel” in 40 CFR 80.2.

This increasing emphasis in the statute on cellulosic biofuel over time is likely due to some or all of the following factors:

• Expectations that cellulosic biofuel has significant potential to reduce GHG emissions (cellulosic biofuels are required to reduce GHG emissions by 60

percent relative to the gasoline or diesel fuel they displace);

• That cellulosic biofuel feedstocks could be produced or collected with relatively few negative environmental impacts;

• That the feedstocks would be comparable or cheaper in cost relative to other fuel feedstocks, allowing for lower cost biofuels to be produced than those produced from feedstocks without other primary uses such as food; and

• That the technological breakthroughs needed to convert cellulosic feedstocks into biofuel were likely imminent.

As discussed in Section II.C, CAA section 211(o)(2)(B)(iv) requires that EPA determine the cellulosic biofuel volume requirement such that EPA will not need to waive the volumes under CAA section 211(o)(7)(D).

The cellulosic biofuel volumes are the same for both the Low and High Volume Scenarios and represent the projected amount of qualifying biofuel expected to be used as transportation fuel in the U.S. for 2026-2030, accounting for incentives provided by the RFS program and other state and federal programs. The cellulosic biofuel volume scenario for 2026-2030 is shown in Table III.C.1-1. Because the technical, economic, and regulatory challenges related to cellulosic biofuel production vary significantly between the various types of cellulosic biofuel, we have shown the volumes for ethanol from corn kernel fiber and CNG/LNG derived from biogas separately.

Table III.C.1-1—Cellulosic Biofuel Volume Scenario

[Million RINs]

2026

2027

2028

2029

2030

RNG use as CNG/LNG

1,174

1,239

1,309

1,384

1,464

Ethanol from CKF

124

123

122

120

119

Total cellulosic biofuel

1,298

1,362

1,431

1,504

1,583

2. Non-Cellulosic Advanced Biofuel

Although there are no volume targets in the statute for years after 2022, the statutory volume targets for prior years represent a useful point of reference in the consideration of volumes that may be appropriate for 2026-2030. For non-cellulosic advanced biofuel, the implied statutory requirement in CAA section 211(o)(2)(B) increased in every year between 2009 and 2019. It then remained at 4.5 billion gallons for three years before finally rising to 5.0 billion gallons in 2022. In the Set 1 Rule, EPA further increased the implied volume of non-cellulosic advanced biofuel over the course of three years to a total of 5.95 billion RINs in 2025. However, the market has outperformed these standards to date primarily through higher than anticipated imports of non-cellulosic advanced biofuels and their feedstocks. In recognition of this, the volumes for non-cellulosic advanced biofuel in the Volume Scenarios are higher than the non-cellulosic biofuel volumes in the Set 1 Rule, starting with an updated projection of supply for 2025.

For 2026-2030, we anticipate that a key factor in the growth in the production of advanced biodiesel and renewable diesel (the two non-cellulosic advanced biofuels projected to be available in the greatest quantities through 2030) will be the availability of feedstocks as discussed in Section III.B.2. In light of the significant uncertainties related to the supply of qualifying feedstock in these years, we developed two scenarios for the potential supply of advanced biodiesel and renewable diesel: a low growth scenario and a high growth scenario. These two volume scenarios, when combined with our projection of the available supply of other advanced biofuels discussed in Section III.B.3, are the bases for the two non-cellulosic advanced biofuel volume scenarios that differentiate the Low Volume Scenario from the High Volume Scenario.

Table III.C.2-1—Total Non-Cellulosic Advanced Biofuel Volume Scenarios

[Billion RINs]

2025

(Set 1)

2025

(Proj.)

2026

2027

2028

2029

2030

Low Volume Scenario

BBD

6.88

7.91

8.41

8.91

9.41

9.91

10.41

Other advanced biofuel

0.29

0.25

Total con-cellulosic advanced biofuel

7.17

8.16

8.66

9.16

9.66

10.16

10.66

High Volume Scenario

BBD

6.88

7.91

8.91

9.91

10.91

11.91

12.91

Other advanced biofuel

0.29

0.25

Total con-cellulosic advanced biofuel

7.17

8.16

9.16

10.16

11.16

12.16

13.16

Volumes of BBD and other advanced biofuels projected to be used to meet the RFS volume requirements in the Set 1 Rule

Volumes of BBD and other advanced biofuels projected to be used in 2025 based on data available through May 2024.

3. Conventional Renewable Fuel

The conventional renewable fuel volume scenario represents the volume of these fuels we project would be supplied to the market when considering the incentives that could be available through the RFS program and other state and national incentives. Since the supply of ethanol is projected to be limited by the ability for the market to consume ethanol in gasoline blends, the supply of conventional ethanol from 2026-2030 can be estimated from the total ethanol consumption projections from Table III.B.5-1 and our projections for other forms of ethanol as discussed earlier in this section. Our projected volumes of ethanol consumption are presented in Table III.C.3-1. We do not currently project that non-ethanol conventional renewable fuels will be supplied to the U.S. under the RFS program in 2026-2030.

Table III.C.3-1—Ethanol Consumption Volume Scenario

[Million gallons]

2026

2027

2028

2029

2030

Cellulosic ethanol

126

125

124

122

120

Imported sugarcane ethanol

Domestic advanced ethanol

Conventional ethanol

13,781

13,660

13,514

13,350

13,170

Total ethanol consumption

13,993

13,871

13,724

13,558

13,377

4. Summary

Many of the factors we are statutorily obligated to analyze under CAA section 211(o)(2)(B)(ii) when setting volume standards for the RFS program are difficult to analyze in the abstract, particularly those related to economic and environmental impacts. For this reason, we opted to develop volume scenarios to analyze for each category of renewable fuel, which are summarized in Tables III.C.4-1 and 2. Note that neither of these volume scenarios include the impacts of the proposed import RIN reduction provisions described in Section VIII.

Table III.C.4-1—Low Volume Scenario

[Million RINs]

2026

2027

2028

2029

2030

Cellulosic biofuel (D3 & D7)

1,298

1,362

1,431

1,504

1,583

Biomass-based diesel (D4)

8,410

8,910

9,410

9,910

10,410

Other advanced biofuel (D5)

249

Conventional renewable fuel (D6)

13,783

13,662

13,516

13,352

13,172

Table III.C.4-2—High Volume Scenario

[Million RINs]

2026

2027

2028

2029

2030

Cellulosic biofuel (D3 & D7)

1,298

1,362

1,431

1,504

1,583

Biomass-based diesel (D4)

8,910

9,910

10,910

11,910

12,910

Other advanced biofuel (D5)

249

Conventional renewable fuel (D6)

13,783

13,662

13,516

13,352

13,172

To inform the volumes we are proposing for 2026 and 2027, we analyzed these volume scenarios according to the factors required under the statute in CAA section 211(o)(2)(B)(ii). A summary of several of these analyses is described in Section IV and discussed in greater detail in the DRIA. Details of the individual biofuel types and feedstocks that make up these volume scenarios are provided in the DRIA Chapter 3. In Section V, we discuss the proposed volume requirements based on a consideration of all the factors that we analyzed.

D. Baselines

To estimate the impacts of the Volume Scenarios, we must identify an appropriate baseline(s). The baseline reflects the use of renewable fuels absent the proposed action or RFS program (

i.e.,

the alternative collection of biofuel volumes by feedstock, production process (where appropriate), biofuel type, and use that would be anticipated to occur after 2025 in the absence of proposed standards), and acts as the point of reference for assessing the impacts. To this end, we have developed a “No RFS” scenario that we used as the baseline for analytical purposes (hereafter the “No RFS Baseline”), which reflects a world without the RFS program. Many of the same supply-related factors that we used to develop the Volume Scenarios were also relevant in developing the No RFS Baseline.

We also consider a 2025 baseline that in some cases may be more informative in understanding the impacts of the Volume Scenarios relative to the status quo. We further discuss alternative baselines to describe our reasoning for the public and interested stakeholders, and because we understand there are differing, informative baselines that could be used in this type of analysis.

1. No RFS Baseline

Broadly speaking, the RFS program is designed to increase the use of renewable fuels in the transportation sector beyond what would occur in the absence of the program. It is

appropriate, therefore, to use a scenario representing what would occur if the RFS program did not continue to exist as the baseline for estimating the costs and impacts of the Volume Scenarios. Such a “No RFS” baseline is consistent with the Office of Management and Budget's Circular A-4, which says that the appropriate baseline would normally “be a `no action' baseline: what the world will be like if the proposed rule is not adopted.”

Office Management and Budget, “Circular A-4,” September 17, 2003.

Importantly, a “No RFS” baseline would not be equivalent to a market scenario wherein no renewable fuels were used at all. Prior to the RFS program, both biodiesel and ethanol were used in the transportation sector, whether due to state or local incentives, tax credits, or a price advantage over conventional petroleum-based gasoline and diesel. This same situation would exist in 2026-20230 in the absence of the RFS program. Federal, State, and local tax credits, incentives, and support payments will continue to be in place for these fuels, as well as State programs such as blending mandates and LCFS programs. Furthermore, now that capital investments in renewable fuels have been made and markets have been oriented towards their use, there are strong incentives in place for continuing their use even if the RFS program were to disappear. As a result, it would be improper and inaccurate to attribute all use of renewable fuel in 2026-2030 to the applicable standards under the RFS program.

To inform our assessment of the volume of renewable fuels that would be used in the absence of the RFS program for the years 2026-2030, we began by analyzing the trends in the economics for renewable fuels blending in prior years. Assessing these trends is important because the economics for blending renewable fuels changes from year to year based on renewable fuel feedstock and petroleum product prices and other factors that affect the relative economics for blending renewable fuels into petroleum-based transportation fuels. A renewable fuel facility investor and the financiers who fund their projects will review the historical (

e.g.,

did they lose money in a previous year), current, and perceived future economics of the renewable fuel market when deciding whether to continue to operate their renewable fuel facilities, and our analysis attempted to account for these factors.

The No RFS Baseline economic analysis for 2026-2030 compares the projected renewable fuel cost with the projected cost for the fossil fuel it displaces, at the point that the renewable fuel is blended with the fossil fuel, to assess whether the renewable fuel provides an economic advantage to blenders. The comparison is performed at the point that the renewable fuel is blended with the fossil fuel to assess whether the renewable fuel provides an economic advantage to blenders. If the renewable fuel is lower cost than the fossil fuel it displaces, it is assumed that the renewable fuel would be used absent the RFS program (within the constraints described below). The No RFS Baseline economic analysis that we conducted mirrors the cost analysis described in Section IV.C, but there are several differences. The primary difference is that the No RFS Baseline economic analysis was conducted from the fuels industry's perspective, whether they would find it economically advantageous to blend renewable fuel into petroleum fuel in the absence of the RFS program. Conversely, the social cost analysis reflects the overall cost impacts on society at large.

A primary example of a social cost not considered for the No RFS Baseline economic analysis is the fuel economy effect due to the lower energy density of the renewable fuel, as this cost is generally borne by consumers, not the fuels industry. Other ways that the No RFS Baseline economic analysis is different from the social cost analysis include:

See Section IV.C and DRIA Chapter 10 for descriptions of the social cost analysis.

• In the context of assessing production costs, we amortized the capital costs at a higher rate of return more typical for industry investment instead of the rate of return used for social costs.

• We assessed renewable fuel distribution costs to the point where it is blended into petroleum fuel, not all the way to the point of use, which is necessary for estimating the fuel economy cost.

100

For several renewable fuels (

e.g.,

ethanol blended as E10, biodiesel, and renewable diesel), the fuel economy cost is paid by the consumer. Because it is the fuels industry (

i.e.,

refiners, terminals, and retailers) that decides whether to blend renewable fuels into petroleum fuels, they are only concerned about the relative cost at the point in which the renewable fuel is blended into the petroleum fuel, not the costs downstream of that blending point.

• While we generally do not account for the fuel economy disadvantage of most renewable fuels for the No RFS Baseline economic analysis, the exception is E85 where the lower fuel economy of using E85 is so obvious to vehicle owners that they demand a lower price to make up for this loss of fuel economy. As a result, retailers must price E85 lower than the primary alternative E10 to account for this bias and they must consider this in their decisions to blend and sell E85.

101

See DRIA Chapter 2 for further discussion of this topic.

To estimate the relative cost of a renewable fuel compared to the fossil fuel being displaced, we considered several different cost components (

i.e.,

production cost, distribution cost, any blending cost, retail cost) together to reflect the relative cost of each renewable fuel to its respective fossil fuel. We also considered any applicable federal or state programs, incentives, or subsidies that could reduce the apparent blending cost of the renewable fuel at the terminal, including the 45Z credit. The exact amount of credit under 45Z is more variable and depends on a range of factors. However, generally speaking, the amount of credit that fuel producers are able to claim under 45Z is less than the previous $1 per gallon credit that biodiesel and renewable diesel producers were able to claim under 40A.

102

In the case of higher ethanol blends, the retail cost associated with the equipment or use of compatible materials needed to enable the sale of these newer fuels is assumed to be reduced by 50 percent due to the HBIIP program.

102

See DRIA Chapter 1 for a further discussion of the 45Z tax credit.

In addition, there are a number of State programs that create subsidies for biodiesel and renewable diesel fuel, the largest being offered by California and Oregon through their LCFS programs.

103

We accounted for State and local biodiesel mandates by including their mandated volume regardless of the economics. Several States offer tax credits for blending ethanol at 10 percent. Other States offer tax credits for E85, of which the largest is New York. We are not aware of any State tax credits or subsidies for E15.

104

To account for the various State assumptions, it was necessary to model the cost of using these biofuels on a State-by-State basis.

103

At the time the analysis for the No RFS Baseline was completed, there was insufficient data to project the impacts of LCFS programs in New Mexico on biofuel consumption in these states in the absence of the RFS program.

104

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

For most renewable fuels, the economic analysis provided consistent results, indicating that they are either

economical in all years or are not economical in any year. However, this was not true for biodiesel and renewable diesel, where the results varied from year to year. Such swings in the economic attractiveness of biodiesel and renewable diesel confound efforts on the part of investors to project future returns on their investments to determine whether to continue to operate their facilities, or shutdown. Thus, to smooth out the swings in the economics for using biodiesel and renewable diesel and look at it the way facility operators and their investors would have in the absence of the RFS program, we made two key assumptions. First, the economics for biodiesel and renewable diesel were modeled starting in 2009 and the trend in its use was made dependent on the relative economics in comparison to petroleum diesel over distinct four-year periods. As a result, the first four-year period modeled the costs over 2009-2012 to estimate the volume of biodiesel and renewable diesel that would be used in 2012 in the absence of the RFS program. Second, the estimated biodiesel and renewable diesel volumes were limited in the analysis to no greater volume than what occurred under the RFS program in any year, since the existence of the RFS program would be expected to create a much greater incentive for using these fuels than if the RFS program was not in place.

We also conducted an economic analysis for cellulosic biofuels, including cellulosic ethanol, corn kernel fiber ethanol, and biogas. Since the volumes of these biofuels were much smaller, a more generalized approach was used in lieu of the detailed state-by-state analysis conducted for corn ethanol, biodiesel, and renewable diesel fuel.

The No RFS Baseline for 2026-2030 is summarized in Table III.D.1-1.

105

See DRIA Chapter 2 for a more complete description of the No RFS Baseline and its derivation.

Table III.D.1-1—No RFS Baseline

[Million RINs]

2026

2027

2028

2029

2030

Cellulosic biofuel (D3 & D7)

582

619

659

702

749

Biomass-based diesel (D4)

3,156

3,310

3,429

3,614

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