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

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 2 and the energy dominance pillar of EPA's “Powering the Great American Comeback” initiative. 3 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.

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

3 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

ment 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] a Volume requirement established in Set 1 Rule 2023 2024 2025 Proposed volume requirement 2026 2027 Cellulosic biofuel 0.84 b 1.01 c 1.19 1.30 1.36 Biomass-based diesel d 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 e 20.94 21.54 22.33 24.02 24.46 a One RIN is equivalent to one ethanol-equivalent gallon of renewable fuel. Throughout this preamble, RINs are generally used to describe total volumes in each of the four renewable fuel categories, while gallons are generally used to describe volumes for individual types of biofuel ( e.g., ethanol, biodiesel, renewable diesel, etc.). b 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. c 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. d 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

acts 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 a 0.23 0.23 0.23 0.19 0.19 Conventional renewable fuel b 13.85 13.96 13.78 13.78 13.66 Total renewable fuel b 18.63 19.12 19.63 22.10 22.37 a Other advanced biofuel includes all advanced biofuels that to not qualify as cellulosic biofuel or BBD. b 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

l 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.

4 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, 5 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.

5 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

ropose 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

d 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

n 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. 6 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

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. 7 For the final rule, we intend to update our analyses using the most recent available data and projections from EIA and other sources. 8

7 EIA, “Annual Energy Outlook 2023” (AEO2023). https://www.eia.gov/outlooks/archive/aeo23.

8 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

s and completed a Biological Evaluation (BE) for the Set 1 Rule. 10 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. 11 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.

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

11 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 v. 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. 12 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.

12 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

f the program” in CAA section 211(o)(2)(B)(ii).

• The ability of the market to respond given the timing of this rulemaking (DRIA Chapter 7). 20

20 This also informs our analysis of the statutory factor “the expected annual rate of future commercial production of renewable fuels” in CAA section 211(o)(2)(B)(ii)(III).

• The supply of qualifying renewable fuels to U.S. consumers (Section III.B). 21

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

• Soil quality (DRIA Chapter 4.3). 22

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

• Ecosystem services (DRIA Chapter 4.6). 23

23 Ecosystem services broadly consist of the many life-sustaining benefits humans receive from nature, such as clean air and water, fertile soil for crop production, pollination, and flood control. Ecosystem services are discussed in DRIA Chapter 4 due to linkages to potential environmental impacts from this rule.

• A consideration of costs and benefits (Section V.H). 24

24 The consideration of costs and benefits includes our quantitative analysis of several statutory factors, including costs and monetizable impacts on energy security.

C. Statutory Conditions on Volume Requirements

As indicated above, the CAA affords the EPA Administrator flexibility to consider and weigh each of the enumerated factors

A consideration of costs and benefits (Section V.H). 24

24 The consideration of costs and benefits includes our quantitative analysis of several statutory factors, including costs and monetizable impacts on energy security.

C. Statutory Conditions on Volume Requirements

As indicated above, the CAA affords the EPA Administrator flexibility to consider and weigh each of the enumerated factors. However, the CAA contains three overarching conditions that affect our determination of the applicable volume requirements:

• A constraint in setting the applicable volume of total renewable fuel as compared to advanced biofuel, with implications for the implied volume requirement for conventional renewable fuel.

• Direction in setting the cellulosic biofuel applicable volume regarding potential future waivers.

• A floor on the applicable volume of BBD.

We discuss these conditions in further detail below.

1. Advanced Biofuel as a Percentage of Total Renewable Fuel

While the statute generally provides broad discretion in setting the applicable volume requirements for advanced biofuel and total renewable fuel, it also establishes a constraint on the relationship between these two volume requirements. CAA section 211(o)(2)(B)(iii) provides that the applicable advanced biofuel requirement must “be at least the same percentage of the applicable volume of renewable fuel as in calendar year 2022,” meaning that EPA must, at a minimum, maintain the ratio of advanced biofuel to total renewable fuel that was established for 2022 for all future years in which EPA itself sets the applicable volume requirements. In effect, this proportional requirement limits the proportion of the implied volume of conventional renewable fuel within the total renewable fuel volume for years after 2022 based on the proportion that existed for calendar year 2022.

The applicable advanced biofuel volume requirement established for 2022 was 5.63 billion gallons

ars in which EPA itself sets the applicable volume requirements. In effect, this proportional requirement limits the proportion of the implied volume of conventional renewable fuel within the total renewable fuel volume for years after 2022 based on the proportion that existed for calendar year 2022.

The applicable advanced biofuel volume requirement established for 2022 was 5.63 billion gallons. 25 The total renewable fuel volume requirement established for 2022 was 20.63 billion gallons, resulting in an implied conventional volume requirement of 15 billion gallons. Thus, advanced biofuel represented 27.3 percent of total renewable fuel for 2022, and EPA must maintain at least that percentage of the advanced biofuel volume requirement as compared to the total renewable fuel volume requirement for all subsequent years. The volume requirements we are proposing in this action for 2026 and 2027, shown in Table I.A.1-1, exceed this 27.3 percent minimum, and thus they satisfy this statutory requirement for each year.

25 87 FR 39601 (July 1, 2022).

2. Cellulosic Biofuel

CAA section 211(o)(2)(B)(iv) requires that EPA set the applicable cellulosic biofuel requirement “based on the assumption that the Administrator will not need to issue a waiver . . . under [CAA section 211(o)](7)(D)” for the years in which EPA sets the applicable volume requirement. We have historically interpreted this requirement to mean that the cellulosic biofuel volume requirement should be set at a level that is achievable such that EPA does not anticipate a need to further lower the requirement through a waiver under CAA section 211(o)(7)(D)

-billion-gallon volume requirement enumerated by statute for 2012, but it does not provide any other numerical criteria that EPA must consider. In the years since 2012, EPA has steadily increased the BBD volume requirement beyond 1.0 billion gallons to 3.35 billion gallons in 2025. In this action, we are proposing BBD volume requirements for 2026 and 2027 of 7.12 and 7.50 billion RINs respectively. 28 These numbers are not directly comparable with the BBD volume requirements in previous years, as they express the required volume of BBD in RINs rather than gallons and reflect our proposal that imported renewable fuels and renewable fuels produced from foreign feedstocks would generate fewer RINs. 29 Nevertheless, the proposed BBD volume requirements guarantee that at least 4.45 and 4.69 billion gallons of BBD would be used in 2026 and 2027 respectively, 30 far greater than 1.0-billion-gallon minimum requirement.

28 As noted in Section I.A.1 and explained further in Section X.C, we are proposing to specify the BBD volume requirement in RINs, rather than gallons, as was the case in establishing the 2025 BBD volume requirement of 3.35 billion physical gallons.

29 See Section VIII for more detail on the proposed RIN reduction for renewable fuels and renewable fuels produced from foreign feedstocks.

30 These volumes represent the lowest possible volume of BBD that could be used to meet the proposed BBD volume requirements for 2026 and 2027. These numbers are calculated by dividing the proposed BBD RIN requirements by 1.6, which is the number of RINs generated for renewable diesel if produced by a domestic renewable fuel producer using domestic feedstocks.

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

In this action, EPA is proposing applicable volume requirements and percentage standards for 2026 and 2027. We have a statutory obligation to promulgate volume requirements under CAA section 211(o)(2)(B)(ii) and are addressing that requirement in this proposed action

el producer using domestic feedstocks.

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

In this action, EPA is proposing applicable volume requirements and percentage standards for 2026 and 2027. We have a statutory obligation to promulgate volume requirements under CAA section 211(o)(2)(B)(ii) and are addressing that requirement in this proposed action. The statutory deadline for the 2026 applicable volume requirements passed on October 31, 2024. The statutory deadline for promulgating the 2027 applicable volume requirements is October 31, 2025. We are proposing this action with the intent to meet that statutory deadline for the 2027 applicable volume requirements and to fulfill our outstanding obligation to establish the 2026 applicable volume requirements ahead of the 2026 compliance year.

As to the percentage standards with which obligated parties must comply, CAA section 211(o)(A)(i) and (iii) requires EPA to promulgate regulations that, regardless of the date of promulgation, contain compliance provisions applicable to refineries, blenders, distributors, and importers that ensure that the volumes in CAA section 211(o)(2)(B)—which includes volumes set by EPA after 2022—are met. As in the Set 1 Rule, EPA is also proposing to establish corresponding percentage standards in this action. 31

31 88 FR 44468, 44519-21 (July 14, 2023).

In summary, we are proposing applicable volume requirements and associated percentage standards for 2026 and 2027, as further described in Sections V and VI.

E. Considerations Related to the Timing of This Action

In this action, we are proposing applicable volume requirements for the 2026 compliance year after the statutory deadline to establish such requirements. 32 That deadline was October 31, 2024

ry, we are proposing applicable volume requirements and associated percentage standards for 2026 and 2027, as further described in Sections V and VI.

E. Considerations Related to the Timing of This Action

In this action, we are proposing applicable volume requirements for the 2026 compliance year after the statutory deadline to establish such requirements. 32 That deadline was October 31, 2024. EPA has in the past also missed statutory deadlines for promulgating RFS standards, including the 2023 and 2024 standards established in the Set 1 Rule, and the BBD volume requirements for 2014-2017, which were established under CAA section 211(o)(2)(B)(ii), the same provision under which we are proposing to establish the 2026 standards in this action. In its review of EPA's 2015 action establishing BBD volume requirements for 2014-2017, 33 the D.C. Circuit found that EPA retains authority beyond the statutory deadlines to promulgate volumes and annual standards, even those that apply retroactively, so long as EPA exercises this authority reasonably. 34 EPA had missed the statutory deadline under CAA section 211(o)(2)(B)(ii) to establish an applicable volume requirement for BBD no later than 14 months before the first year to which that volume requirement will apply for all years. The D.C. Circuit held that when EPA exercises this authority after the statutory deadline, EPA must balance the burden on obligated parties of a delayed rulemaking with the broader goal of the RFS program to increase renewable fuel use. 35 In specifically upholding the portion of that rulemaking that was late but not retroactive, the court considered whether there was sufficient lead time and adequate notice for obligated parties. 36 The court found that EPA properly balanced the relevant considerations and had provided sufficient notice to parties in establishing the applicable volume requirements for 2014-2017

ropose 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)

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. 40 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.

40 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

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). 41 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.

41 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

se, we use “biogas-derived CNG/LNG” to refer to both treated biogas and RNG when used as a transportation fuel in CNG/LNG vehicles.

41 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, 42 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

ing 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.

43 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, 44 2019, 45 2020-2022, 46 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

ble 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

oduces 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.

49 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. 50

50 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

iesel production, with little or no net change in their overall production of RIN-generating fuels. 50

50 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. 51

51 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. 52 The U.S. has also imported significant volumes of biodiesel in previous years and has been a net importer of biodiesel since 2013

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. 52 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. 53 In August 2017, the U.S. announced tariffs on biodiesel imported from Argentina and Indonesia. 54 These tariffs were subsequently confirmed in April 2018 and remain in place. 55 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. 56 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).

52 Id.

53 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.

54 82 FR 40748 (Aug. 28, 2017).

55 83 FR 18278 (April 26, 2018).

56 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

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. 57 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.

57 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. 58 These estimates of domestic production capacity strongly suggest that domestic biodiesel production capacity is unlikely to limit domestic biodiesel production through 2030.

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

b

illion gallons per year in April 2025, of which 2.6 billion gallons per year was at biodiesel facilities that generated RINs in 2024. 58 These estimates of domestic production capacity strongly suggest that domestic biodiesel production capacity is unlikely to limit domestic biodiesel production through 2030.

58 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. 59 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.

59 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

eloped 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. 60 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.

60 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

nia can generate both RINs under the RFS program and LCFS credits.

64 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 65 to approximately 4.6 billion gallons at the end of 2024. 66 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.

65 Renewable diesel capacity based on facilities registered in EMTS.

66 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. 67 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. 68 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

per year. 68 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.

67 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.

68 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. 69 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

-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.

69 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. b -1—Renewable Diesel Imports and Exports [Million gallons] Year Renewable diesel imports Renewable diesel exports Net imports 2015 120 21 99 2016 165 40 125 2017 191 37 154 2018 176 80 96 2019 267 148 119 2020 280 223 57 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

120 21 99 2016 165 40 125 2017 191 37 154 2018 176 80 96 2019 267 148 119 2020 280 223 57 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. 70 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). 71

70 USDA, “Oil Crops Yearbook,” March 2025. https://www.ers.usda.gov/data-products/oil-crops-yearbook.

71 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

ent in October 2021, before declining slightly to 39 percent in August 2024 (the most recent date for which data are available). 71

70 USDA, “Oil Crops Yearbook,” March 2025. https://www.ers.usda.gov/data-products/oil-crops-yearbook.

71 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. 72 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.

72 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

ld increase by approximately 1.5 million bushels of soybeans per day from 2024 through 2026. 73 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. 74 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. 75 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. 76

73 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.

74 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.

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

76 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

om 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. 77 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 2 e/MJ per year each year from 2023 to 2030. 78 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.

77 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.

78 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

eviously exported to the EU) from China to the U.S.

80 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.

81 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

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. 82 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.

82 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

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

he projected BBD supply for 2025.

Table III.B.2. e -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. e -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. 84 However, these biofuels have been consumed in much smaller quantities than biodiesel and renewable diesel in the past or have been highly variable.

84 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

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] a Fuel Volume Imported sugarcane ethanol 58 Domestic ethanol 28 CNG/LNG 6 Heating oil 3 Naphtha b 43 Renewable diesel c 111 Total 249 a This table does not include fuels that qualify as cellulosic biofuel or BBD. b 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. c Includes renewable diesel that is co-processed with petroleum, which does not qualify as BBD. 4

iesel c 111 Total 249 a This table does not include fuels that qualify as cellulosic biofuel or BBD. b 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. c 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)

corporated projected growth in opportunities for sales of E15 and E85 blends into our assessment.

89 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 90 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

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) 91 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. 92 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. 93 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.

91 USDA, “Higher Blends Infrastructure Incentive Program,” May 2023. https://www.rd.usda.gov/hbiip.

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

h 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

y 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

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. 97

97 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

sed 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

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

otential 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) a 2025 (Proj.) b 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 0.25 0.25 0.25 0.25 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 0.25 0.25 0.25 0.25 0.25 Total con-cellulosic advanced biofuel 7.17 8.16 9.16 10.16 11.16 12.16 13.16 a Volumes of BBD and other advanced biofuels projected to be used to meet the RFS volume requirements in the Set 1 Rule b 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

FS 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.” 98

98 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

d 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

ysis.

• 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

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

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

nding 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

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

conventional ethanol is economical to use in 10 percent blends (E10) without the presence of the RFS program. Conversely, higher-level ethanol blends are only partially economic without the RFS program. E85 is economic in some of the years before, during, and after the years 2026-2030 in the State of California; 106 thus, we assumed that E85 would be consumed in California without the RFS program. 107 While E85 is economic in New York, which offers a large E85 blending subsidy, the volume of E85 sold in New York is very small even with the RFS program in place; therefore, we ignored E85 sales in New York. Conversely E15 is not economic without the RFS program due to the high cost associated with the equipment needed to be installed at retail stations, even if these costs are partially subsidized by government funding, and the lack of octane blending value. Some volume of biodiesel is estimated to be blended based on state mandates in the absence of the RFS program, and some additional volume of both biodiesel and renewable diesel is estimated to be economical to use without the RFS program, particularly in California and Oregon due to the LCFS incentives. The volumes of CNG from biogas and imported sugarcane ethanol are projected to be consumed in California due to the economic support provided by their LCFS.

106 Our analysis indicated that E85 was also economic compared to gasoline in Oregon; however, because there are only five stations offering E85 in Oregon, we did not include E85 sold in Oregon in the No RFS Baseline.

107 Since E85 is borderline economic in California in the No RFS Baseline when we do not assume any increase in California's LCFS credit, a likely increase in the LCFS credit under the No RFS Baseline increases the certainty that E85 would be economic. Additionally, we did not consider the possibility that cellulosic ethanol, which receives a larger LCFS credit, could be used to produce E85 and may be more economic than corn ethanol.

2

s of biofuel production in 2025, which are significantly higher than the 2025 Baseline shown below that is used as a point of comparison in some of our analyses.

The 2025 volume requirements were finalized in the Set 1 Rule and the volumes we projected to be used to satisfy these requirements are shown in Table III.D.3-1. 108

108 More details on the 2025 Baseline can be found in DRIA Chapter 2.

Table III.D.3-1—2025 Baseline [Million RINs] Volume Cellulosic biofuel (D3 & D7) 1,376 Biomass-based diesel (D4) 6,881 Other advanced biofuel (D5) 290 Conventional renewable fuel (D6) 13,939 E. Volume Changes Analyzed

In general, our analysis of the impacts of the Volume Scenarios was based on the differences between the No RFS Baseline and our assessment of how the market would respond to the Low and High Volume Scenarios. Those differences are shown in Tables III.E-1 and 2. 109 Note that this approach is squarely focused on the differences in volumes between the No RFS Baseline and the Volume Scenarios; our analysis does not, in other words, assess impacts from total renewable fuel use in the U.S. As noted above, we also consider the impacts of this action relative to the 2025 Baseline for some of our analyses. The changes in renewable fuel consumption relative to the 2025 Baseline are shown in in Tables III.E-3 and 4.

109 See DRIA Chapter 2 for more details of this assessment, including a more precise breakout of those differences.

Table III.E-1—Changes in Renewable Fuel Consumption—Low Volume Scenario vs. No RFS Baseline [Million RINs] 2026 2027 2028 2029 2030 Cellulosic biofuel (D3 & D7) 716 743 772 802 834 Biomass-Based Diesel (D4) 5,255 5,600 5,981 6,297 6,658 Other Advanced Biofuel (D5) 52 52 52 52 52 Conventional Renewable Fuel (D6) 212 228 238 252 266 Table III.E-2—Changes in Renewable Fuel Consumption—High Volume Scenario vs

I.E-1—Changes in Renewable Fuel Consumption—Low Volume Scenario vs. No RFS Baseline [Million RINs] 2026 2027 2028 2029 2030 Cellulosic biofuel (D3 & D7) 716 743 772 802 834 Biomass-Based Diesel (D4) 5,255 5,600 5,981 6,297 6,658 Other Advanced Biofuel (D5) 52 52 52 52 52 Conventional Renewable Fuel (D6) 212 228 238 252 266 Table III.E-2—Changes in Renewable Fuel Consumption—High Volume Scenario vs. No RFS Baseline [Million RINs] 2026 2027 2028 2029 2030 Cellulosic biofuel (D3 & D7) 716 743 772 802 834 Biomass-Based Diesel (D4) 5,755 6,600 7,481 8,297 9,158 Other Advanced Biofuel (D5) 52 52 52 52 52 Conventional Renewable Fuel (D6) 212 228 238 252 266 Table III.E-3—Changes in Renewable Fuel Consumption—Low Volume Scenario vs 2025 Baseline [Million RINs] 2026 2027 2028 2029 2030 Cellulosic biofuel (D3 & D7) −78 −14 55 128 207 Biomass-Based Diesel (D4) 1,529 2,029 2,529 3,029 3,529 Other Advanced Biofuel (D5) −41 −41 −41 −41 −41 Conventional Renewable Fuel (D6) −156 −277 −423 −587 −767 Table III.E-4.—Changes in Renewable Fuel Consumption—High Volume Scenario vs. 2025 Baseline [Million RINs] 2026 2027 2028 2029 2030 Cellulosic biofuel (D3 & D7) −78 −14 55 128 207 Biomass-Based Diesel (D4) 2,029 3,029 4,029 5,029 6,029 Other Advanced Biofuel (D5) −41 −41 −41 −41 −41 Conventional Renewable Fuel (D6) −156 −277 −423 −587 −767 IV. Analysis of Volume Scenarios

As described in Section II.B, the statute specifies a number of factors that EPA must analyze in making a determination of the appropriate volume requirements to establish for years after 2022 (and for BBD, years after 2012). 110 In this section, we provide a summary of the analysis of a selection of factors, including climate change, energy security, costs, employment, and economic impacts for

the Volume Scenarios, along with some implications of those analyses. We provide a summary of our consideration of all factors in determining the proposed volume requirements in Section V.

110 A full description of the analysis for all factors is provided in the DRIA

the analysis of a selection of factors, including climate change, energy security, costs, employment, and economic impacts for

the Volume Scenarios, along with some implications of those analyses. We provide a summary of our consideration of all factors in determining the proposed volume requirements in Section V.

110 A full description of the analysis for all factors is provided in the DRIA.

A. Energy Security

Changes in the required volumes of renewable fuel can affect the financial and security-related risks associated with U.S. trade in crude oil and petroleum products, including both imports and exports (hereafter referred to collectively as “net petroleum imports”), which, in turn, would have a direct impact on the national energy security of the U.S. Likewise, the required volumes of renewable fuel may lead to changes in imports and exports of renewable fuels and renewable fuel feedstocks that can also impact U.S. energy security.

U.S. energy security is often defined as the continued availability of energy sources at an acceptable price. 111 Energy independence can be achieved by reducing the sensitivity or reliance of an economy to energy imports and foreign energy markets to the point where the costs of depending on foreign energy are so small that they have minimal effects on economic, military, or foreign policies. 112 A central goal of U.S. energy policy for decades has been to lower U.S. oil imports and, thus, become less reliant on foreign oil suppliers. Similarly, as described in Section VIII, we are also proposing to reduce the number of RINs generated for imported renewable fuel and renewable fuel produced from foreign feedstocks, which is intended to reduce America's reliance on such fuels in future years consistent with the statutory goals of energy security and independence.

111 IEA, “Energy Security.” https://www.iea.org/topics/energy-security.

112 Greene, David L. “Measuring Energy Security: Can the United States Achieve Oil Independence?” Energy Policy 38, no

troleum products explained, June 11, 2024. https://www.eia.gov/energyexplained/oil-and-petroleum-products/where-our-oil-comes-from-in-depth.php.

115 EIA, “U.S. Net Imports of Crude Oil and Petroleum Products,” Petroleum & Other Liquids, May 30, 2025. https://www.eia.gov/dnav/pet/hist/LeafHandler.ashx?n=pet&s=mttntus2&f=a.

116 AEO2023, Table 11—Petroleum and Other Liquids Supply and Disposition.

In recent years, however, a substantial quantity of imports of renewable fuels and renewable fuel feedstocks have been used to meet the RFS volume obligations. In particular, there has been a recent expansion of imports of BBD feedstocks since 2021, as can be seen in Figure III.B.2.d-2. This shift, which has been driven by a confluence of factors (as discussed in Section III.B.2), can have implications for the U.S.'s energy security and energy independence.

Despite the long-term shift in the U.S.'s net petroleum trade position, energy security risks remain for the U.S. There are three main reasons why energy security is still a concern. First, oil and renewable fuels and renewable fuel feedstocks are globally traded commodities. As a result, price shocks for these commodities can be transmitted globally even if a country is a net exporter of a commodity. For example, since the U.S. is a large consumer of oil, an oil price shock would raise the price of oil and oil products and could cause broad adverse effects on the economy, even though the U.S. is an overall net petroleum exporter. Second, many U.S. refineries rely significantly or exclusively on imports of heavy crude oil, which could be subject to international supply disruptions. In 2024, gross petroleum imports totaled roughly 8.4 MMBD. 117 Likewise, there has been an expansion in imported feedstocks for BBD in recent years. Third, oil exporters with a large share of global production can raise or lower the price of oil by exerting their market power through the Organization of Petroleum Exporting Countries (OPEC) to alter oil supply relative to demand

China. 121 Crude oil prices ( i.e., the WTI crude oil price) are projected to be mostly flat over 2026-2027, in the $85-86 per barrel (2022$) range. 122

118 EIA, “Crude oil prices increased in first-half 2022 and declined in second-half 2022,” Today in Energy, January 4, 2023. https://www.eia.gov/todayinenergy/detail.php?id=55079.

119 EIA, “Spot Prices,” Petroleum & Other Liquids, May 14, 2025. https://www.eia.gov/dnav/pet/pet_pri_spt_s1_d.htm.

120 Id.

121 EIA, “Short-Term Energy Outlook,” September 2024. https://www.eia.gov/outlooks/steo/archives/sep24.pdf.

122 AEO2023, Table 12—Petroleum and Other Liquids Prices.

EPA has worked with Oak Ridge National Laboratory (ORNL) to understand the energy security implications of reducing U.S. net petroleum imports and, more generally, exposure of the U.S. economy to global oil markets. ORNL has developed approaches for evaluating the social costs/impacts and energy security implications of oil imports, labeled the “oil import premium” or “oil security premium.” ORNL's methodology estimates two distinct costs/impacts of importing petroleum into the U.S., in addition to the purchase price of petroleum itself: (1) The risk of reductions in U.S. economic output and disruption to the U.S. economy caused by sudden disruptions in the supply of imported oil to the U.S. ( i.e., the macroeconomic disruption/adjustment costs); and (2) The impacts that changes in U.S. net oil imports have on overall U.S. oil demand and subsequent

changes in the world oil price ( i.e., the “demand” or “monopsony” impacts). 123

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

As has been the case for past RFS rulemakings, we consider the monopsony impacts estimated by the ORNL methodology to be a transfer payment, and thus exclude it from the estimated quantified benefits of the Volume Scenarios

price ( i.e., the “demand” or “monopsony” impacts). 123

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

As has been the case for past RFS rulemakings, we consider the monopsony impacts estimated by the ORNL methodology to be a transfer payment, and thus exclude it from the estimated quantified benefits of the Volume Scenarios. 124 Thus, we only consider the macroeconomic disruption/adjustment cost component of the net oil import premiums ( i.e., labeled “macroeconomic oil security premiums” below) estimated using ORNL's methodology.

124 See DRIA Chapter 6.4.2 for more discussion of EPA's assessment of monopsony impacts of this action. Also, for a discussion of monopsony oil security premiums, see, e.g., EPA, “Revised 2023 and Later Model Year Light Duty Vehicle GHG Emissions Standards: Regulatory Impact Analysis,” EPA-420-R-21-028, December 2021, Section 3.2.5.

For this action, EPA and ORNL have worked together to revise the U.S. oil import premiums based upon recent energy security literature and oil price projections and energy market and economic trends from AEO2023. 125 EPA and ORNL have continuously updated oil import premium estimates to account for increasing domestic shale oil production, as well as other evolving U.S. and world oil market trends, since the RFS2 Rule in 2010. We do not consider military cost impacts from reduced oil use from the Volume Scenarios due to methodological issues in quantifying these impacts. 126

125 See DRIA Chapter 6.4.2 for how the macroeconomic oil security premiums have been updated based upon a review of recent energy security literature on this topic.

126 See DRIA Chapter 6.3 for a discussion of the difficulties in quantifying military cost impacts.

To calculate the energy security benefits of the Volume Scenarios, we are using the ORNL macroeconomic oil security premiums combined with estimates of annual reductions in U.S

conomic oil security premiums have been updated based upon a review of recent energy security literature on this topic.

126 See DRIA Chapter 6.3 for a discussion of the difficulties in quantifying military cost impacts.

To calculate the energy security benefits of the Volume Scenarios, we are using the ORNL macroeconomic oil security premiums combined with estimates of annual reductions in U.S. net petroleum imports attributable to the changes in renewable fuel volumes. 127 Table IV.A-1 presents the macroeconomic oil security premiums and the total energy security benefits for the Volume Scenarios. The macroeconomic oil security premiums range from $3.65 per barrel in 2026 to $3.92 per barrel in 2030. In terms of cents per gallon, the macroeconomic oil security premiums range from 8.6 cents per gallon in 2026 to 9.3 cents per gallon in 2030.

127 See DRIA Chapter 6.4.1 for a discussion of the methodology used to estimate changes in U.S. annual net petroleum imports from the Volume Scenarios.

Table IV.A-1—Macroeconomic Oil Security Premiums and Total Undiscounted Energy Security Benefits for the Volume Scenarios a Year Macroeconomic oil security premiums (2022$/barrel of reduced imports) Total energy security benefits—Low Volume Scenario (millions 2022$) Total energy security benefits—High Volume Scenario (millions 2022$) 2026 $3.65 ($0.47-$6.89) $138 ($18-$261) $151 ($19-$284) 2027 3.73 (0.51-7.02) 150 (21-283) 176 (24-331) 2028 3.78 (0.51-7.15) 162 (22-307) 201 (27-380) 2029 3.87 (0.54-7.31) 175 (24-331) 228 (32-430) 2030 3.92 (0.51-7.46) 187 (24-357) 254 (33-484) a Top values in each cell are the mean values, while the values in parentheses define 90 percent confidence intervals. B. Costs

1. Methodology

This section provides a brief discussion of the methodology used to estimate the cost impacts for the renewable fuels expected to be used for the Volume Scenarios, as well as for the proposed volume standards, all relative to the No RFS Baseline

corporates ethanol's octane value realized by lower gasoline production costs, but also a volatility cost that accounts for ethanol's blending volatility in RVP-controlled gasoline.

• Retail infrastructure cost: in the case of higher-level ethanol blends, there is a retail cost since retail stations usually need to add equipment or use compatible materials to enable the sale of these newer fuels.

• Fuel economy cost: different fuels have different energy content, leading to different cost levels of fuel economy, which impacts the relative fossil fuel volume being displaced and the cost to the consumer.

We added these various cost components together as appropriate for each renewable fuel to reflect the cost of that fuel. We conducted a similar cost estimate for the fossil fuels being displaced since their relative cost to biofuels is used to estimate the net cost of the increased use of biofuels. Unlike for biofuels, however, we did not calculate production costs for the fossil fuels since their production costs are inherent in the wholesale price projections provided in AEO2023. 128

128 Estimating production costs for renewable fuels facilities is possible because the plants are generally single purpose production processes producing a predictable, limited array of feedstocks into products, while petroleum refineries are each configured differently and each is refining a different mix of feedstocks of varying quality and each refinery is producing a unique number and volume of products.

2. Estimated Cost Impacts

In this section, we summarize the overall results of our cost analysis based on changes in the use of renewable fuels that displace fossil fuel use for the Volume Scenarios; the costs for the proposed volume standards are

summarized in Section V.H.4)

ative to the No RFS Baseline.

Cumulative emissions impact estimates for a thirty-year analytical time period are presented in Table IV.C-1. This section of the preamble contains only a brief synopsis of the results of our analysis; a full description of the methods of analysis, models, scenarios, estimated GHG emissions impacts by year, and uncertainties considered is presented in DRIA Chapter 5.

Table IV.C-1—Cumulative Net Emissions Through 2055 for the Volume Scenarios Relative to No RFS Baseline [Millions of metric tons CO 2 e emissions] Scenario Cumulative Emissions Low Volume −672 to −339 High Volume −759 to −247 Scenarios in the climate change analysis produce annual emissions estimates for a 30-year analytical scenario duration. Additional information about analytical methods for estimating GHG emissions impacts can be found in DRIA Chapter 5; we note that the analysis for this rulemaking relies on an updated methodology for assessing climate change impacts under CAA section 211(o)(2)(B)(ii)(I), details of which can also be found in DRIA Chapter 5. We request comment on our analysis of the GHG emissions impacts of the proposed volume standards, and whether factors in addition to GHG emissions, such as other drivers of climate change and other considerations fitting within the term “climate change,” are relevant to the analysis. In addition to requesting comment on this analysis in general, including the updated methodology, we specifically request comment on the following aspects:

• The methods for evaluating crop-based fuels and waste- and byproduct-based fuels.

• The use of economic models for assessing the potential market-mediated impacts associated with crop-based fuels.

• The scenarios used in this analysis, including the analytical duration, and assumed future (post-2027) biofuel consumption levels for both the policy and baseline scenarios.

D

erve that RNG appears to be associated with the highest number of direct jobs created per unit of biofuel. However, BBD is projected to have the highest job creation impact overall, primarily due to substantially higher production increases relative to the baseline. In terms of rural employment specifically, ethanol has the highest direct and total effects per million gallons of ethanol equivalent. Relative to the No RFS Baseline and accounting for direct, indirect, and induced effects, BBD is projected to have the highest impact on agricultural employment, mainly due to substantially higher production increases relative to the baseline.

We also estimate that ethanol, BBD, and RNG are all associated with increased rural economic development, again to varying degrees. Since renewable fuels rely on agricultural feedstocks, we use the GDP impacts associated with agricultural feedstocks to infer the effects on rural economic development. We estimate that BBD and ethanol have higher impacts per million gallons of ethanol equivalent on rural economic development than does RNG. Relative to the No RFS Baseline and accounting for direct, indirect, and induced effects, BBD is projected to have the highest impact on rural economic development, largely due to substantially higher production increases relative to the baseline.

Tables IV.D-1 and 2 summarize the estimated economy-wide job impacts and rural GDP impacts (both include direct, indirect, and induced impacts) associated with the volumes of ethanol, BBD, and RNG attributable to the Low Volume Scenario and High Volume Scenario, respectively. The estimates of rural GDP impacts are actual values as opposed to discounted values, implying that they do not reflect the time value of money

summarize the estimated economy-wide job impacts and rural GDP impacts (both include direct, indirect, and induced impacts) associated with the volumes of ethanol, BBD, and RNG attributable to the Low Volume Scenario and High Volume Scenario, respectively. The estimates of rural GDP impacts are actual values as opposed to discounted values, implying that they do not reflect the time value of money.

Table IV.D-1—Economy-Wide Jobs and Rural Economic Development in the Low Volume Scenario Relative to No RFS Baseline [Number of jobs in full-time equivalents; million 2022$, undiscounted] Year RNG Jobs Rural economic development BBD Jobs Rural economic development Ethanol a Jobs Rural economic development 2026 19,504 $1,072.16 64,793 $6,840.04 5,332 $366.19 2027 20,240 1,112.59 68,931 7,276.90 5,735 393.83 2028 21,030 1,156.02 73,491 7,758.25 5,986 411.10 2029 21,847 1,200.94 77,265 8,156.68 6,338 435.29 2030 22,718 1,248.86 81,576 8,611.74 6,690 459.47 a For the corn ethanol case alone, using NREL's JEDI module for dry mill corn ethanol we were able to generate employment and income estimates under alternative scenarios and also carry out a sensitivity analysis. See DRIA Chapter 9 for more details. Table IV.D-2—Economy-Wide Jobs and Rural Economic Development in the High Volume Scenario Relative to No RFS Baseline [Number of jobs in full-time equivalents; million 2022$, undiscounted] Year RNG Jobs Rural economic development BBD Jobs Rural economic development Ethanol a Jobs Rural economic development 2026 19,504 $1,072.16 70,790 $7,473.08 5,332 $366.19 2027 20,240 1,112.59 80,905 8,540.95 5,735 393.83 2028 21,030 1,156.02 91,461 9,655.34 5,986 411.10 2029 21,847 1,200.94 101,213 10,684.78 6,338 435.29 2030 22,718 1,248.86 111,520 11,772.88 6,690 459.47 a For the corn ethanol case alone, using NREL's JEDI module for dry mill corn ethanol we were able to generate employment and income estimates under alternative scenarios and also carry out a sensitivity analysis. See DRIA Chapter 9 for more details

rn prices, we used a literature-based estimate that corn prices increase by 3 percent for every additional billion gallons of corn ethanol produced. 135 We multiplied the projected corn price by the 3 percent per-billion-gallon increase to estimate the price change per bushel. This value was then applied to the difference in corn ethanol volumes between each Volume Scenario and the No RFS Baseline. Table IV.E-1 summarizes the results of the projected impact of increased corn ethanol production on corn prices under the Volume Scenarios. 136

135 Condon, Nicole, Heather Klemick, and Ann Wolverton. “Impacts of Ethanol Policy on Corn Prices: A Review and Meta-analysis of Recent Evidence.” Food Policy 51 (January 13, 2015): 63-73. https://doi.org/10.1016/j.foodpol.2014.12.007.

136 The volume of corn ethanol is the same under the Low and High Volume Scenarios; therefore, the

results shown in Table IV.E-1 are the same for both Volume Scenarios.

Table IV.E-1—Projected Impact of Volume Scenarios on Corn Prices Relative to No RFS Baseline Units 2026 2027 2028 2029 2030 Baseline Corn Price a $/Bushel $3.97 $4.07 $4.17 $4.27 $4.30 Corn Price Increase Relative to No RFS Baseline $/Bushel 0.03 0.03 0.03 0.03 0.03 a Corn prices are from the USDA Agricultural Projections to 2034 (February 2025). Prices represent the average price for a calendar year. For corn, the price is calculated using 1/3 of the price for the first agricultural marketing year ( e.g., 2025/2026 for 2026) and 2/3 of the price for the second agricultural marketing year ( e.g., 2026/2027 for 2026). To determine the potential impact of the Volume Scenarios on soybean oil and meal prices, we calculated projected price effects for 2026-2030 relative to the No RFS Baseline. These projections assume a 35.7 percent increase in the price of a pound of soybean oil per billion gallons of biofuel produced and a 7.94 percent decrease in the price of a short ton of soybean meal per billion gallons of biofuel produced

ine $/Ton −49 −51 −53 −55 −58 a Soybean oil and meal prices are from the USDA Agricultural Projections to 2034 report. Prices represent the average price for a calendar year. For soybean oil, the price is calculated using 1/4 of the price for the first agricultural marketing year ( e.g., 2025/2026 for 2026) and 3/4 of the price for the second agricultural marketing year ( e.g., 2026/2027 for 2026). Table IV.E-3—Projected Impact of the High Volume Scenario on Soybean Oil and Meal Prices Relative to the No RFS Baseline Units 2026 2027 2028 2029 2030 Baseline Soybean Oil Price a $/Pound $0.39 $0.37 $0.37 $0.36 $0.36 Soybean Oil Price Increase Relative to No RFS Baseline $/Pound 0.29 0.31 0.34 0.37 0.40 Baseline Soybean Meal Price a $/Ton 324 331 339 347 355 Soybean Meal Price Change Relative to No RFS Baseline $/Ton −54 −62 −70 −79 −88 a Soybean oil and meal prices are from the USDA Agricultural Projections to 2034 report. Prices represent the average price for a calendar year. For soybean oil, the price is calculated using 1/4 of the price for the first agricultural marketing year ( e.g., 2025/2026 for 2026) and 3/4 of the price for the second agricultural marketing year ( e.g., 2026/2027 for 2026). In addition to estimating the price impacts on corn, soybean oil, and soybean meal, we also assessed price changes for other feed grains—grain sorghum, barley, and oats—as well as distillers grains. These commodities were included in this analysis because they have historically competed with corn in the feed market and, to a lesser extent, for planted acreage. These price changes were estimated using historical price relationships with corn, and the analysis found only minimal impacts on the other grains. 138

138 See DRIA Chapter 9 for more information.

Additionally, the impact on commodity prices described above may, in turn, have downstream effects on food prices and other products derived from these commodities

lesser extent, for planted acreage. These price changes were estimated using historical price relationships with corn, and the analysis found only minimal impacts on the other grains. 138

138 See DRIA Chapter 9 for more information.

Additionally, the impact on commodity prices described above may, in turn, have downstream effects on food prices and other products derived from these commodities. To estimate the effect on total food expenditures, we combined these projected price changes with forecasts of commodity use for food production. 139 Because commodity costs typically represent a small portion of total food prices, the anticipated effect of this action on food prices is relatively modest, as shown in Table IV.E-4.

139 Commodity use for food production estimated using USDA Agricultural Projections to 2034. See DRIA Chapter 9 for further detail on this analysis.

Table IV.E-4—Impact of Volume Scenarios on Total Food Expenditures a Units 2026 2027 2028 2029 2030 Low Volume Scenario Change in Food Expenditures Million $ $1,938 $1,802 $1,723 $1,648 $1,601 Projected Food Expenditure Increase $ per Consumer Unit $14.41 $13.40 $12.80 $12.25 $11.90 Percent Change in Food Expenditures Percent 0.14 0.13 0.13 0.12 0.12 High Volume Scenario Change in Food Expenditures Million $ $2,129 $2,141 $2,187 $2,213 $2,260 Projected Food Expenditure Increase $ per Consumer Unit $15.82 $15.92 $16.25 $16.45 $16.79 Percent Change in Food Expenditures Percent 0.16 0.16 0.16 0.16 0.17 a Data from the U.S. Bureau of Labor Statistics, Consumer Expenditures—2023, Table A. Average income and expenditures of all consumer units, 2021-23. V. Proposed Volume Requirements for 2026 and 2027

As required by CAA section 211(o)(2)(B)(ii), we have reviewed the implementation of the RFS program in prior years and have analyzed a specified set of factors. The proposed volume requirements for 2026 and 2027 (the “Proposed Volumes”) are informed by our technical analyses of the Volume Scenarios, which are summarized in Section IV

osing for 2026 and 2027 are designed to provide significant support for the continued growth in the production and use of renewable fuels. While the Proposed Volumes (expressed in billion RINs) are similar to the Low Volume Scenario and lower than the High Volume Scenario, we project that the Proposed Volumes would result in significantly higher renewable fuel production and consumption in the U.S. than either the Low or High Volume Scenario, particularly for domestic renewable fuel, due to the proposed import RIN reduction provisions. 141 Our assessment of the expected annual rate of future commercial production of renewable fuels indicates that continued growth in the production and use of renewable fuels is not only possible but expected if supported through the RFS program. Increasing the production of renewable fuels furthers the goals of the RFS program by increasing the energy independence and energy security of the U.S. Further, increasing production of renewable fuels, particularly those produced from domestic feedstocks, can have significant positive impacts on employment and economic activity in rural areas.

141 See DRIA Chapter 3 for more detail on the quantities and types of renewable fuel we project would be supplied to meet the Proposed Volumes and the Volume Scenarios.

We note that while we do not separately discuss each of the statutory factors for each component category in this section, we have analyzed all the statutory factors. However, it was not always possible to precisely identify the implications of the analysis of a specific factor for a specific component category of renewable fuel. For instance, while we analyzed the impact of biodiesel and renewable diesel on the cost to consumers of transportation fuel, biodiesel and renewable diesel can be used to satisfy multiple biofuel requirements ( e.g., BBD, advanced biofuel, and total renewable fuel) and this analysis therefore does not apply to a single standard in that regard

el. We then evaluated the Volume Scenarios using additional statutory factors. The results of these evaluations are summarized here and detailed further in the DRIA. Our analysis suggests that cellulosic biofuels offer several significant benefits, including the potential for exceptionally low lifecycle GHG emissions that meet or exceed the 60 percent GHG reduction threshold for cellulosic biofuel. 142 These benefits largely arise because the majority of feedstocks projected for use in cellulosic biofuel production are either waste materials ( e.g., CNG/LNG derived from biogas) or residues ( e.g., cellulosic diesel and heating oil from tree residue). The processing of these otherwise unused feedstocks into transportation fuel is also likely to result in increased employment and have a positive economic impact, particularly in the communities where the cellulosic biofuel production facilities are located.

142 CAA section 211(o)(1)(E).

The feedstocks currently used and expected to be used through 2027, particularly biogas used for CNG/LNG production, are not anticipated to cause substantial land use changes that could lead to negative environmental impacts. None of the cellulosic biofuel feedstocks expected to be used to produce liquid cellulosic biofuels through 2027 (including corn kernel fiber, mill residue, and separated MSW) are produced with the intention that they be used as feedstocks for cellulosic biofuel production. Because of this, using these feedstocks to produce liquid cellulosic biofuel is not expected to have significant adverse impacts related to several of the statutory factors, including the conversion of wetlands, ecosystems and wildlife habitat, soil and water quality, the price and supply of agricultural commodities, and food prices through 2027.

Cellulosic biofuels are also expected to provide significant economic development benefits. The production of these fuels supports local economies, creating jobs in biofuel facilities and related distribution networks

his rulemaking differs from past approaches, so we also request comment on the methodology used to arrive at those volumes. We also request any further data or insights that could enhance our projections for cellulosic biofuel production in 2026 and 2027.

143 See DRIA Chapter 7.1 for further information on the methodology EPA used to project the supply of cellulosic biofuel in 2026 and 2027.

B. Non-Cellulosic Advanced Biofuel

The volume targets established by Congress through 2022 anticipated volumes of advanced biofuel beyond what would be needed to satisfy the cellulosic standard. The statutory target for advanced biofuel in 2022 (21 billion gallons) allowed for up to five billion gallons of non-cellulosic advanced biofuel to be used towards the advanced biofuel volume target, with additional quantities of non-cellulosic advanced biofuel able to contribute towards meeting the total renewable fuel requirement. The applicable standards for 2022 similarly include five billion gallons of non-cellulosic advanced biofuel. In the Set 1 Rule, EPA continued to grow the implied non-cellulosic advanced biofuel category, which reached 5.95 billion gallons in 2025.

As discussed in Sections III.B.2 and 3, we developed volume scenarios for non-cellulosic advanced biofuel based on a consideration of the quantities of these fuels potentially able to be supplied to the U.S. market. This process included consideration of the supply of these fuels in 2023 and the months in 2024 for which data were available and the projected future projection and import of non-cellulosic advanced biofuels in future years. The non-cellulosic advanced biofuel volumes in the Volume Scenarios reflect significantly different growth rates for this category (500 million RINs per year vs. 1 billion RINs per year). These volume scenarios were designed to enable us to consider the likely impacts of different volume requirements for non-cellulosic advanced biofuel

biofuel volumes, are summarized in the remainder of this section, and are discussed in greater detail in the DRIA.

A key consideration in determining the proposed non-cellulosic advanced biofuel volumes is our proposal in this action to reduce the number of RINs generated for imported renewable fuels and renewable fuels produced from foreign feedstocks by 50 percent, as discussed in Section VIII. While much of the renewable fuel eligible to generate RINs under the RFS program is produced by domestic producers from domestic feedstocks—including the vast majority of all cellulosic biofuel and conventional renewable fuel—we estimate that nearly 50 percent of all non-cellulosic advanced biofuel was imported or produced from foreign feedstocks in 2024. 144 The 500 million RIN annual growth rate that forms the basis for our proposed non-cellulosic advanced biofuel volumes is approximately equal to our projection of the annual increase in the production of domestic feedstocks that can be used to produce these fuels. This approach provides a strong incentive to increase the production of domestic renewable fuels from domestic feedstocks. It also allows for domestic biofuel producers to continue to use foreign feedstocks where it is advantageous to do so, while incentivizing these producers to source increasing quantities of domestic feedstocks over time.

144 See DRIA Chapter 3.2 for more detail on EPA's estimate of domestic vs. imported biofuels and feedstocks in 2024.

To date, the vast majority of non-cellulosic advanced biofuel in the RFS program has been biodiesel and renewable diesel, with relatively small volumes of sugarcane ethanol and other advanced biofuels. While the impacts of non-cellulosic advanced biofuels on the statutory factors vary depending on the fuel type, production process, where the fuel is produced ( e.g., domestically vs. in a foreign country), and the feedstock used to produce the fuel, all advanced biofuels have the potential to provide significant GHG reductions

tively small volumes of sugarcane ethanol and other advanced biofuels. While the impacts of non-cellulosic advanced biofuels on the statutory factors vary depending on the fuel type, production process, where the fuel is produced ( e.g., domestically vs. in a foreign country), and the feedstock used to produce the fuel, all advanced biofuels have the potential to provide significant GHG reductions. These potential GHG reductions suggest that higher non-cellulosic advanced biofuel volumes than those established by Congress for 2022 (5.0 billion RINs) or established by EPA for 2025 (5.95 billion RINs) may be appropriate.

Advanced biodiesel and renewable diesel together accounted for 95 percent or more of the total supply of non-cellulosic advanced biofuel over the last several years, and together the two fuels are expected to continue to do so through 2027 due to the limited production and import of other types of non-cellulosic advanced biofuels. 145 We have therefore focused our attention on the impacts of these fuels in relation to the statutory factors in determining appropriate levels of non-cellulosic advanced biofuel for 2026 and 2027. 146

145 See DRIA Chapters 7.2 through 7.4.

146 We have also considered the potential for increasing volumes of renewable jet fuel. Given its similarity to renewable diesel, for purposes of projecting appropriate volume requirements for 2026 and 2027, in most cases we consider renewable jet fuel to be a component of renewable diesel.

As in past RFS rulemakings, our analyses indicate that for some of the statutory factors the projected impacts of increasing consumption of biodiesel and renewable diesel are expected to be generally positive or neutral, while for other factors the impacts are expected to be generally negative

for 2026 and 2027, in most cases we consider renewable jet fuel to be a component of renewable diesel.

As in past RFS rulemakings, our analyses indicate that for some of the statutory factors the projected impacts of increasing consumption of biodiesel and renewable diesel are expected to be generally positive or neutral, while for other factors the impacts are expected to be generally negative. For other factors, the projected impacts vary significantly depending on whether the feedstock used to produce the fuel is a waste or byproduct ( e.g., used cooking oil) or an agricultural commodity ( e.g., soybean oil) and whether it is sourced domestically or imported.

All qualifying biodiesel and renewable diesel is expected to diversify the transportation fuel supply and thus have a positive impact on the energy security of the U.S. Similarly, because we project that all of the increase in the supply of biodiesel and renewable diesel through 2027 will be supplied from domestic biofuel producers using domestic feedstocks, we expect these fuels to positively impact employment and rural economic development. We

do not anticipate the availability of infrastructure to distribute or use biodiesel and renewable diesel will limit the consumption of these fuels in future years, nor do we anticipate that increasing supplies of these fuels will negatively impact the deliverability of materials, goods, and products other than renewable fuel. Together, these statutory factors suggest that higher volumes of biodiesel and renewable diesel may be appropriate in future years.

Other statutory factors suggest that lower volumes of biodiesel and renewable diesel may be appropriate. Biodiesel and renewable diesel have historically had higher costs than the diesel fuel they displace and are expected to continue to cost more into the future, primarily due to relatively high feedstock costs

higher volumes of biodiesel and renewable diesel may be appropriate in future years.

Other statutory factors suggest that lower volumes of biodiesel and renewable diesel may be appropriate. Biodiesel and renewable diesel have historically had higher costs than the diesel fuel they displace and are expected to continue to cost more into the future, primarily due to relatively high feedstock costs. These higher costs are expected to ultimately be passed through to consumers, resulting in higher costs for transportation fuel and higher costs to transport goods. 147 Biodiesel and renewable diesel produced from vegetable oils are expected to directionally result in higher prices for these oils and the crops from which they are derived ( e.g., soybeans and canola). These higher vegetable oil prices are projected to have both positive and negative impacts. Higher vegetable oil prices are expected to drive increased investment in the domestic oilseed crushing industry, resulting in increased employment and economic impact, as well as higher revenue for feedstock producers. Higher vegetable oil prices are also expected to result in higher prices for products that use them as inputs.

147 This discussion refers to societal costs. We recognize that with the incentives provided by the RFS program and other state and local programs, the price for biodiesel and renewable diesel (net available incentives) may be lower than the price of petroleum fuels. See DRIA Chapter 10 for a further discussion of our cost estimates.

Finally, the projected impacts on some of the statutory factors are expected to vary significantly depending on the feedstock used to produce the biodiesel or renewable diesel. We have generally assumed that biofuels produced from wastes or byproducts such as UCO and tallow do not drive the conversion of land to cropland, increase the intensity of farming practices, or raise agricultural commodity or food prices

not only fully consume this previously excess supply, but also result in the diversion of these feedstocks from existing markets. In turn, markets that previously used these waste and byproduct feedstocks may seek alternatives, and any impacts on cropland, GHG emissions, or other factors that result from the sourcing of these alternative feedstocks should then be attributable to biofuel production.

Increases in domestic sources of waste or byproduct feedstocks in future years are projected to be limited as much of the available feedstocks are already being used for biofuel production with smaller quantities collected for other productive uses. Significant volumes of these feedstocks may be available from foreign countries, though there is significant uncertainty in the quantities of these feedstocks that will be available to the U.S. in future years.

1. Assessment of Available Feedstocks

Biodiesel and renewable diesel produced from agricultural commodities such as soybean oil and canola oil are more likely to have negative impacts on wetlands, wildlife habitat and ecosystems, and water quality, as demand for these feedstocks can result in increased conversion of native lands to cropland. This land conversion (whether land is converted directly to produce biofuel crops or induced through higher commodity prices) generally results in GHG emissions, and therefore biofuels produced from these feedstocks are expected to have lower GHG emission benefits than biofuels produced from wastes or byproducts. Significant opportunities exist for increasing domestic production of soybean oil (which would be expected to positively impact job creation and rural economic development), as well as imported canola oil from Canada. Because the supply of these feedstocks is less dependent on imports and there are relatively fewer incentives and lower demand for biofuels produced from vegetable oils, we have greater confidence in projecting the potential supply of these feedstocks in future years

ction, relatively high tariffs on imports, and high demand in food markets respectively. Any increases to the supply of these feedstocks to biofuel producers would require diverting these feedstocks from current markets. While this is possible, we project any shifts of these vegetable oils from current markets through 2027 to be limited. Since 2015, the use of soybean oil and canola oil in the U.S. in markets other than biofuel production has remained fairly consistent despite the significant increase in the use of these oils for biofuel production. 149 This suggests that these oils have a higher value in non-biofuel markets ( e.g., food) and are unlikely to be diverted from these markets in significant quantities due to higher demand for biofuel production in the near term. While the U.S. has historically been a net exporter of soybean oil, data for the 2023/24 agricultural marketing year indicates that net exports of soybean oil were near zero 150 and therefore opportunities to divert soybean oil from export markets are very limited.

149 USDA, “Oil Crops Yearbook,” March 2025. https://www.ers.usda.gov/data-products/oil-crops-yearbook.

150 Id.

b. Animal Fats and UCO

In addition to vegetable oils, the other primary sources of feedstocks for biodiesel and renewable diesel production are animal fats (such as tallow) and UCO. In the U.S., collection and productive use of these feedstocks is well established. Most of the economically recoverable UCO and animal fats in the U.S. are currently collected and productively used, primarily for biofuel production. 151 We project that the supply of these feedstocks will continue to grow, but that the rate of growth in the availability of these feedstocks from domestic markets will be modest, growing with domestic meat production and the use of vegetable oil for food production.

151 Global Data, “UCO Supply Outlook,” August 2023

re currently collected and productively used, primarily for biofuel production. 151 We project that the supply of these feedstocks will continue to grow, but that the rate of growth in the availability of these feedstocks from domestic markets will be modest, growing with domestic meat production and the use of vegetable oil for food production.

151 Global Data, “UCO Supply Outlook,” August 2023.

In contrast, there is both significant growth potential and a high degree of uncertainty surrounding the supply of animal fats and UCO that could be imported into the U.S. and used for biofuel production. The uncertainty is associated both with the quantity of these materials that can be economically collected and competition for available feedstocks and biofuels produced from these feedstocks in other countries.

The global supply of animal fats is expected to increase with global meat consumption. Global meat production increased 53 percent from 2000 to 2021 and is expected to continue to increase in future years. 152 Like other biodiesel and renewable diesel feedstocks, animal fats have historically been used in other markets such as for oleochemical production and livestock feed. We project that strong incentives for biofuels produced from animal fats in the U.S. (from both state and federal incentive programs) will result in increasing quantities of these feedstocks being used for biofuel production. Thus, we project that the available supply of animal fats to biofuel producers will increase in future years due to both increasing animal fat production (as a byproduct of increasing meat production) and the diversion of animal fats for existing uses to biofuel production. We note, however, that the environmental benefits associated with biofuels produced from diverting animal fats (or any feedstock) diverted from existing markets are likely less than the environmental benefits associated with biofuels produced from feedstocks that would not otherwise be productively used

sing meat production) and the diversion of animal fats for existing uses to biofuel production. We note, however, that the environmental benefits associated with biofuels produced from diverting animal fats (or any feedstock) diverted from existing markets are likely less than the environmental benefits associated with biofuels produced from feedstocks that would not otherwise be productively used. 153

152 Food and Agriculture Organization of the United Nations, “World Food and Agriculture—Statistical Yearbook 2023,” 2023. https://doi.org/10.4060/cc8166en.

153 When feedstocks are diverted from existing uses, the markets that previously used these feedstocks generally seek alternative feedstocks. Potential alternatives could include petroleum-based feedstocks or palm oil. Increased use of these feedstocks in non-biofuel markets could reduce or negate the intended environmental benefits from increased biofuel production.

The global supply of UCO is primarily a function of UCO collection rates, which are themselves a function of the total quantity of vegetable oils used in food production and the infrastructure in place to collect and productively use UCO. UCO collection rates vary significantly by country, from virtually nothing in many countries to approximately 2.5 pounds per capita in the U.S. 154 Demand for UCO as a feedstock for biofuel production in recent years has resulted in a rapid increase in the global collection of UCO, from approximately 2.3 billion gallons in 2018 to approximately 3.7 billion gallons in 2022. 155 A recent study projected that the increase in global UCO collection from 2022 to 2027 could range from 1.4 billion gallons (based on projected increases in population and GDP) to 6.1 billion gallons (based on increasing collection rates in countries that currently have some UCO collection infrastructure in place)

imately 2.3 billion gallons in 2018 to approximately 3.7 billion gallons in 2022. 155 A recent study projected that the increase in global UCO collection from 2022 to 2027 could range from 1.4 billion gallons (based on projected increases in population and GDP) to 6.1 billion gallons (based on increasing collection rates in countries that currently have some UCO collection infrastructure in place). 156 The study noted that even greater UCO collection is possible by 2027 with economic incentives sufficient to encourage the collection of UCO in countries where it is currently not being collected. 157

154 Global Data, “UCO Supply Outlook,” August 2023.

155 Id.

156 Id.

157 Id.

In addition to the uncertainty related to the global collection of animal fats and UCO, there is also significant uncertainty related to the markets where these feedstocks and biofuels produced from them will be used. Because biodiesel and renewable diesel generally cost more to produce than the petroleum fuels they displace, demand for these fuels is primarily driven by the incentives available to the producers and/or blenders of these fuels. Many countries around the world offer incentives or have imposed mandates for the use of biodiesel and renewable diesel. These incentives vary significantly from country to country, both in magnitude and in structure. For example, some countries provide the same incentive for all gallons of qualifying biofuel, while other countries provide increasing incentives for biofuels that provide greater GHG reductions, such as the waste feedstock derived fuels.

Because incentives are often greatest for animal fats and UCO feedstocks and biofuels produced from them, the market for these fuels is subject to greater volatility based on changes in biofuel policies than are vegetable oils and biofuels produced from vegetable oils

ntries provide increasing incentives for biofuels that provide greater GHG reductions, such as the waste feedstock derived fuels.

Because incentives are often greatest for animal fats and UCO feedstocks and biofuels produced from them, the market for these fuels is subject to greater volatility based on changes in biofuel policies than are vegetable oils and biofuels produced from vegetable oils. For example, in California's LCFS program, biofuels produced from animal fats and UCO generally have a lower carbon intensity and thus generate more credits than biofuels produced from vegetable oils such as soybean oil and canola oil. The EU's RED II places no restrictions on the crediting of biofuels produced from animal fats and UCO while the crediting of biofuels produced from food and feed crops is limited to a maximum of 7 percent of the consumption in the road and rail transport sector in each member state. 158 Because biofuels and biofuel feedstocks are globally traded commodities, the incentives available for the production and use of these

biofuels can and historically have had a significant impact on where these products are used. A greater or smaller portion of the available global supply of animal fats and UCO could be available to U.S. biofuel producers depending on whether the incentives available to biofuel producers are higher or lower than those offered by other countries.

158 European Commission, “Renewable Energy—Recast to 2030 (RED II).”

Recent changes in the trade flows of UCO from China illustrate the changing nature of incentive programs and the impact these changes can have on the supply of biofuel feedstocks. From 2018-2023, exports of UCO from China increased significantly, from approximately 0.6 million metric tons in 2018 to about 2.1 million metric tons in 2023

ean Commission, “Renewable Energy—Recast to 2030 (RED II).”

Recent changes in the trade flows of UCO from China illustrate the changing nature of incentive programs and the impact these changes can have on the supply of biofuel feedstocks. From 2018-2023, exports of UCO from China increased significantly, from approximately 0.6 million metric tons in 2018 to about 2.1 million metric tons in 2023. From 2018-2022, the primary destination of these exports was Europe, accounting for approximately 60 percent of all exports of UCO from China, while less than 1 percent of all exports of UCO from China were exported to the U.S. 159 In 2023, however, the market dynamics changed significantly. Exports of UCO from China to Europe fell to just 23 percent of total exports, while exports to the U.S. increased to 41 percent. 160 The decline in European UCO imports was due to a combination of factors, including reduced demand for biodiesel and renewable diesel in some EU member states and concerns that imported UCO from China may include palm oil. These concerns resulted in decreased demand for UCO sourced from China in the EU and simultaneous increased demand for this feedstock in the U.S. There is potential for increased consumption of these fuels and feedstocks domestically in China in future years, should the government, for example, choose to increase incentives for the production and use of renewable jet fuel. The unpredictable nature of changes to biofuel incentives in both the U.S. and other countries in future years, combined with the potentially significant impact of these changes, makes it very difficult to predict the supply of these feedstocks to U.S. biofuel producers with a high degree of certainty.

159 UN Comtrade Database, Trade Data, HS Code 1518.

160 Id.

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d use of renewable jet fuel. The unpredictable nature of changes to biofuel incentives in both the U.S. and other countries in future years, combined with the potentially significant impact of these changes, makes it very difficult to predict the supply of these feedstocks to U.S. biofuel producers with a high degree of certainty.

159 UN Comtrade Database, Trade Data, HS Code 1518.

160 Id.

2. Proposed Non-Cellulosic Advanced Biofuel Volumes

Based on our analyses of all the statutory factors, we are proposing volumes for 2026 and 2027 that reflect 500 million RIN annual increases in the projected supply of non-cellulosic advanced biofuel relative to the projected supply of these fuels in 2025. These volumes reflect our consideration of the impacts of these fuels on the statutory factors, including the potential increases in employment and economic impacts associated with the increased production of these fuels (particularly those produced from domestic feedstocks) and the potential for GHG reductions that may result from their use. The proposed non-cellulosic advanced biofuel volumes also reflect our consideration of the projected potential increases in biodiesel and renewable diesel production and supply based primarily on our assessment of the supply of feedstocks used to produce these fuels (including the uncertainties associated with these projections), the projected high costs for these fuels relative to the petroleum fuel they displace, and the potential negative impacts associated with increasing demand for vegetable oils or diverting feedstocks from existing uses to biofuel production.

We project that the feedstocks needed to produce the proposed non-cellulosic advanced biofuel volumes could be supplied from domestic sources and therefore are not dependent on increases in the quantity of imported feedstocks in future years

mpact of the proposed import RIN reduction.

We recognize that there are potential negative impacts likely to result from non-cellulosic advanced biofuel volume requirements that are too high or too low. If we establish volume requirements for these fuels that are too low, the market will likely supply lower volumes of these fuels to the U.S. than could be achieved with higher volume requirements. This could negatively impact biofuel producers a

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