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

In the Set 2 proposal, we proposed several changes to the percentage standard equations in 40 CFR 80.1405(c), including to: (1) clarify that the volume requirements used to calculate the percentage standards for cellulosic biofuel, advanced biofuel, and total renewable fuel are based on the number of “gallon-RINs”; (2) change the BBD volume requirement to be expressed in gallon-RINs; and (3) clarify, revise, or remove certain terms of the percentage standard equations. Commenters were generally supportive of these changes, although several commenters raised concerns about our proposed change to express the BBD volume requirement in gallon-RINs instead of physical gallons. After consideration of those comments, we

are finalizing the changes to the percentage standard equations as proposed with minor clerical revisions to the proposed language.\311\ We address the specific concerns raised by commenters in RTC Section 11.3.

\311\ Our changes to the percentage standard formulas are limited to the changes here and in sections IV and V of this preamble that establish SRE reallocation volumes for 2026 and 2027. We have not reopened any other aspects of the percentage standard formulas, including the factors that project exempt volumes of gasoline and diesel due to small refinery exemptions.

First, consistent with our long-standing practice, we are clarifying that the volume requirements used to calculate the percentage standards for cellulosic biofuel, advanced biofuel, and total renewable fuel (RFVCB,i, RFVAB,i, and RFVRF,i, respectively) are based on the number of “gallon- RINs” of each fuel, rather than simply “gallons” as previously specified. As described in the RFS2 Rule, we have interpreted these volume requirements as being on an energy-equivalent basis (rather than wet or physical gallons of liquid fuel) and that when the volume requirements are used to calculate the applicable percentage standards, it would be through the use of the equivalence value for RIN generation (the “Equivalence Value” approach).\312\ This energy-equivalent basis for using the volume requirements to calculate the percentage standards is expressed through the use of gallon-RINs, and thus we believe these terms should be defined as such in the regulations.

\312\ 75 FR 14709-10, 16-18 (March 26, 2010).

Second, we are changing the BBD volume requirement (RFVBBD,i) from being expressed in physical gallons to gallon-RINs, consistent with the methodology used to specify the other three renewable fuel volume requirements. Since the BBD volume requirement was first established in the RFS2 Rule, we have interpreted the statutory BBD volume requirements as being in physical gallons.\313\ Thus, while the percentage standard equations for cellulosic biofuel, advanced biofuel, and total renewable fuel were established on a gallon-RINs basis, the BBD percentage standard was established on a physical gallon basis. Because the BBD standard was assumed in the RFS2 Rule to be met exclusively with biodiesel, and biodiesel generated 1.5 RINs per gallon, we applied a 1.5 multiplier (the “BBD conversion factor”) to the BBD percentage standard equation to convert from the number of BBD physical gallons in the statutory volume requirements to the equivalent number of gallon-RINs. Since the RFS2 Rule, we have continued to use the energy-equivalent (or gallon- RIN) approach in establishing the cellulosic biofuel, advanced biofuel, and total renewable fuel volume requirement and associated percentage standards. However, the BBD volume requirement has continued to be expressed in physical gallons and then converted to a gallon-RIN equivalent in the BBD percentage standard equation by multiplying the BBD volume requirement by the BBD conversion factor (either 1.5 (from 2010-2022) or 1.6 (from 2023-2025)).

\313\ In the RFS2 rule, we stated that “we are finalizing the energy content approach to Equivalence Values for the cellulosic biofuel, advanced biofuel, and total renewable fuel standards. However, the biomass-based diesel standard is based on the volume of biodiesel. In order to align both of these approaches simultaneously, biodiesel will continue to generate 1.5 RINs per gallon as in RFS1, and the biomass-based diesel volume mandate from EISA is then adjusted upward by the same 1.5 factor.” 75 FR 14716 (March 26, 2010).

As discussed in section III of this preamble, since the promulgation of the RFS2 Rule, fuels other than biodiesel, most prominently renewable diesel, have become significant contributors to the BBD volume requirement. This increased contribution from renewable diesel to the BBD pool, along with an equivalence value of 1.7 for renewable diesel \314\--compared to an equivalence value of 1.5 for biodiesel--resulted in the average equivalence value for BBD increasing from 1.51 in 2012 to nearly 1.59 in 2022.\315\ The shifting equivalence value has led to confusion among stakeholders regarding the correct way to interpret the BBD volume requirement and a perceived lack of clarity regarding how the BBD percentage standard is calculated.

\314\ While we acknowledge that we are revising the specified equivalence value for renewable diesel from 1.7 to 1.5 in this action, our decision here to specify the BBD volume requirement in gallon-RINs rather than physical gallons is independent from our decision to revise the equivalence value for renewable diesel. In addition, we expect that many renewable diesel producers will petition for a greater equivalence value, as discussed in section VIII.A of this preamble.

\315\ For additional discussion of the BBD conversion factor, see our discussion on this topic in the Set 1 Rule in which we revised the BBD conversion factor from 1.5 to 1.6. 88 FR 44545-47 (July 12, 2023).

Acknowledging that the BBD volume requirement is now being met with a more complex mixture of fuels than we anticipated in the RFS2 Rule, we are now revising the definition of RFVBBD,i to specify that the BBD volume requirement is expressed in gallon-RINs rather than physical gallons. We believe that specifying the BBD volume requirement in gallon-RINs reduces confusion among stakeholders regarding how to interpret the BBD volume requirement and how the BBD percentage standard is calculated. We acknowledge that this is a change in our approach to the BBD volume requirement. In 2010, we believed that Congress intended the BBD volume mandate to be treated as volumes rather than in terms of gallon-RINs.\316\ However, Congress did not specify BBD volume requirements for any years after 2012. Subsequent experience implementing the RFS program has compelled us to revisit this interpretation, as well as the facts that the EPA has broad discretion to establish the BBD volume requirements after 2012 (based on a review of the implementation of the RFS program to date and the statutory factors) and the increasingly complex mix of renewable fuels that are used to meet the BBD volume requirement.

\316\ 75 FR 14710 (March 26, 2010).

We now believe that the BBD volume requirement is best read as requiring BBD volumes to be specified in gallon-RINs, consistent with the other three renewable fuel categories under the RFS program. Under CAA section 211(o)(B)(i), the tables listing the statutory volume requirements for all four categories of renewable fuel (cellulosic biofuel, BBD, advanced biofuel, and total renewable fuel) specify the units as being “in billions of gallons.” There is no indication in the statutory text that the units of the BBD volume requirement should be treated differently than the other renewable fuel categories. The reason we gave in 2010 for differentiating BBD--that we believed the BBD volume requirements set by Congress through 2012 were best interpreted as physical gallons rather than RIN-gallons--is no longer relevant since Congress did not provide BBD volume requirements for years after 2012.

In addition, we note that there is no practical effect on regulated parties by specifying the BBD volume requirement in gallon-RINs rather than physical gallons. Whether the EPA specifies the BBD volume requirement in gallon-RINs or physical gallons, ultimately the numerator in the BBD percentage standard equation--and thus the BBD percentage standard itself--would be the same. Since 2010, obligated parties have used the BBD percentage standards to determine their BBD RVOs in gallon-RINs, rather than in physical gallons. This was clear in the multiplier (initially 1.5, revised to 1.6 for 2023-2025) used in the BBD percentage standard equation, which was unique to BBD. The purpose of this multiplier was to ensure that the percentage standards

represented obligations in gallon-RINs rather than physical gallons.

Were we to still specify the BBD volume requirement in physical gallons, we would first determine the intended increase in the BBD volume requirement in RINs and then divide by 1.6 to calculate the necessary BBD volume requirement in physical gallons. This conversion would then be reversed in the numerator of the BBD percentage standard equation, where the BBD physical gallon volume requirement would be multiplied by 1.6 to convert from physical gallons back to RINs. Ultimately, the BBD volume requirement is simply an input into the BBD percentage standard equation, not a standalone or otherwise enforceable requirement itself. By specifying the BBD volume requirement in gallon- RINs in the first place, we avoid a confusing and unnecessary step in the calculation of the BBD percentage standard (i.e., the requirement with which obligated parties actually have to comply) and ensure consistency with the other three renewable fuel categories.

Consistent with this clarification, we are also revising the BBD percentage standard to remove the 1.6 conversion factor. By specifying the BBD volume requirement in gallon-RINs, the BBD conversion factor is no longer necessary to convert from physical gallons of BBD to gallon- RINs. This also eliminates the need to track the average equivalence value of BBD to adjust the BBD conversion factor in the future. For example, we recently revised from 1.5 to 1.6 in the Set 1 Rule due to increased production volumes of renewable diesel relative to biodiesel; \317\ such adjustments will no longer be necessary.

\317\ 88 FR 44545-47 (July 12, 2023).

We are also removing the terms GSi, DSi, RGSi, and RDSi from the percentage standard equations. These terms relate to the use of gasoline, diesel, and renewable fuels contained in gasoline and diesel in Alaska or a U.S. territory if the State or territory opts into the RFS program. However, if Alaska or a U.S. territory were to opt into the RFS program in the future, we would instead account for gasoline, diesel, and renewable fuel use in the State or territory under the existing Gi, Di, RGi, and RDi terms. These terms refer to the amounts of gasoline, diesel, or renewable fuel used in gasoline or diesel in the covered location, which is defined as “the contiguous 48 states, Hawaii, and any state or territory that has received an approval from the EPA to opt-in to the RFS program under Sec. 80.1443.” \318\ Thus, there is no need to have separate terms in the percentage standards just for Alaska or a U.S. territory that opts into the RFS program in the future.

\318\ 40 CFR 80.2.

Finally, we are revising the definitions of RGi and RDi (the projected amounts of renewable fuel in gasoline and diesel, respectively) to clarify that these projections are for the amounts of renewable fuel contained within the projections of Gi and Di themselves (the amounts of gasoline and diesel, respectively, projected to be used in the U.S.), rather than a projection of the absolute amount of renewable fuel contained in gasoline and diesel. While the EIA projections that the EPA uses to calculate the percentage standards have historically contained some volume of renewable fuel (e.g., ethanol in gasoline, biodiesel and renewable diesel in diesel), EIA has recently changed their STEO projection methodology to provide separate projections of petroleum- based distillate and renewable fuels blended into distillate (e.g., biodiesel and renewable diesel). Thus, were we to use these projections to calculate the percentage standards, we would use the petroleum-based distillate projection for Di and a value of zero for RDi, as the Di projection does not contain any renewable fuel.\319\ We believe this clarification makes clear how we would calculate the percentage standards under this potential future scenario.

\319\ Note that the percentage standards in this action are calculated using projections from AEO2025, which does include renewable fuels in its projections of gasoline and distillate.

In the Set 2 proposal, we proposed changes to the table of approved renewable fuel pathways in order to clarify the parameters for certain pathways. In particular, we proposed to revise references to “any” in the production process requirements of table 1 to 40 CFR 80.1426 (hereinafter “Table 1”) with more precise descriptions. These revisions are intended to more accurately describe the production processes that we evaluated when we approved these pathways as satisfying the statutory requirements for lifecycle emissions reductions. In the Set 2 proposal, we also proposed to add biogenic waste fats, oils, and greases as a feedstock for producing renewable naphtha and liquefied petroleum gas (LPG). In this action, we are finalizing many of the proposed changes with modifications based on our consideration of the public comments.

Table 1 lists generally applicable fuel pathways that have been approved for the RFS program. Fuel producers that produce fuel through a pathway (i.e., a unique combination of a fuel, feedstock, and production process) described in Table 1 may submit a registration application to the EPA.\320\ Table 1 lists an applicable RIN D code for each approved pathway based on the statutory criteria, including the type of fuel produced, the feedstock used to produce the fuel, and whether it satisfies the statutory 20 percent, 50 percent, or 60 percent lifecycle emissions reduction threshold. In section VIII.D.1 of this preamble, we are finalizing clarifications to the parameters of certain pathways in Table 1. In section VIII.D.2 of this preamble, we are finalizing the addition of pathways to Table 1 for naphtha and LPG produced from biogenic waste fats, oils, and greases. These amendments to Table 1 are summarized in Table VIII.D-1.\321\ We are finalizing these changes largely as proposed, but with certain modifications based on our consideration of the comments.

\320\ Note that an individual row in Table 1 can include multiple fuel pathways.

\321\ The reasons for these regulatory amendments are described in section X.D of the Set 2 proposal (90 FR 25845-49; June 17, 2025).

[GRAPHIC] [TIFF OMITTED] TR01AP26.074

In addition to requiring that renewable fuel be produced from renewable biomass and used to reduce or replace the quantity of fossil fuel in transportation fuel,\322\ the CAA also requires that qualifying biofuels meet the lifecycle emissions reduction threshold specified for the applicable category of renewable fuel.\323\ The CAA further requires the EPA to determine the lifecycle emissions for renewable fuels.\324\ We have evaluated the lifecycle emissions associated with a wide range of fuel pathways and listed those pathways that satisfy the statutory emissions reduction criteria and other statutory criteria in Table 1. To do so, we evaluate particular feedstocks that are put through particular production processes to produce particular fuels. Thus, an approved pathway in Table 1 signifies that we have determined that the specific combination of elements we evaluated--feedstock, process, and fuel--meets the applicable lifecycle emissions reduction threshold.

\322\ CAA section 211(o)(1)(J).

\323\ CAA sections 211(o)(1)(B), (D), (E); 211(o)(2)(A)(i).

\324\ CAA section 211(o)(1)(H).

For certain pathways that were promulgated in the RFS2 Rule, we believed, based on the fuel production process data available at the time, that the use of any process would result in emissions for the resulting fuel that meet the applicable lifecycle emissions reduction threshold.\325\ However, since that time, we have observed the emergence and development of fuel production processes that vary from those assumed in the original lifecycle assessments underlying the approved pathways in Table 1. These developments have resulted in processes that differ much more than we anticipated was possible in the RFS2 Rule. Indeed, some of the fuel production processes that parties are now interested in registering under “any” pathways bear little resemblance to the processes we evaluated as the basis for including a given pathway in Table 1. In some cases, the lifecycle emissions performance of such new processes may be significantly worse than the processes we analyzed in the RFS2 Rule or the notional processes we anticipated might be developed in the future. These new processes may therefore not meet the applicable statutory lifecycle emissions reduction threshold. For example, we have received petitions for thermochemical cellulosic biofuel production technologies that would use a large amount of conventional natural gas and grid electricity per unit of fuel produced, whereas our 2010 analysis assumed that this type of process would use practically zero fossil fuel or grid electricity, relying instead on combustion of char, coke, and syngas derived from the cellulosic renewable biomass feedstock for process energy.\326\

\325\ See, e.g., our discussion of “assessments of similar feedstocks sources” at 75 FR 14792-14797 (March 26, 2010).

\326\ See Table 2.4-59 of the RFS2 Rule RIA (EPA-HQ-OAR-2021- 0427-0115) (March 26, 2010).

Given the possibility that some pathways nominally fitting the description in Table 1 might not actually meet the corresponding statutory lifecycle emissions reduction requirement, we believe it is inappropriate to continue listing “any” production process under certain approved pathways in Table 1. Therefore, we are finalizing changes to clarify certain approved pathways in Table 1 by replacing the “any” terminology with more precise language that reflects the fuel production processes that we have determined satisfy the applicable lifecycle emissions reduction thresholds.

Specifically, to further clarify the scope of approved pathways in Table 1, we are replacing the term “any” with more precise language in the production technology requirements column of Rows K, L, M, P, Q, and T. Previously, Rows K and L listed the production process requirements as “Any process that converts cellulosic biomass to fuel,” Row M included “any process utilizing biogas and/or biomass as the only process energy sources which

converts cellulosic biomass to fuel,” and Rows P, Q, and T listed the production process requirements as “Any.” As discussed below, we are replacing some or all of the current language in each of these rows with a description of the production process and associated parameters that we evaluated for the corresponding lifecycle assessment and that we determined meet the applicable lifecycle emissions reduction threshold. Furthermore, we are making related changes to Row N and adding a new Row U so that the full set of previously evaluated and approved pathways are listed in Table 1. Renewable fuel production facilities that do not satisfy the production process requirements in Table 1 may petition the EPA pursuant to 40 CFR 80.1416 to request our evaluation of the lifecycle emissions associated with their fuel.

As discussed further in section VIII.D.1.h of this preamble, we are adding two provisions in the regulations at 40 CFR 80.1426(f)(1) to clarify the implementation of pathways in Table 1. First, we are adding a paragraph to clarify that the amendments to Table 1 in this action do not affect renewable fuel producers with an existing pathway registration. Second, we are adding a paragraph that specifies the criteria the EPA applies to determine whether a feedstock, fuel, or production process qualifies for an approved pathway in Table 1.

Stakeholders provided comments on these proposed changes. Some commenters were neutral and provided specific recommendations for modifying the proposed changes to Rows Q and T. One commenter was generally opposed to the changes, saying they were unnecessary, but did not provide specific reasons. Other commenters questioned the need for changes to specific rows, and in some cases these comments recommended specific alternatives. We discuss some of these specific comments and our response in the subsections below, and more detail is contained in RTC Section 11.4.1. a. Row K

Row K includes pathways for ethanol produced from certain cellulosic feedstocks to qualify for D3 RINs. We are finalizing revisions to Row K as proposed but with modifications based on consideration of comments and further review of the processes that we evaluated in prior RFS rulemakings. As proposed, we are revising Row K to specify that the approved production processes include biochemical conversion, thermochemical conversion, and dry mill processes that satisfy certain conditions. In response to comments that requested additional clarity, we are modifying the proposed text in Row K that specifies the production process requirements, and we are describing these processes in more detail in this section. Below, we describe the production processes evaluated and the associated criteria specified for each of these production processes in Row K.

Biochemical conversion refers to processes that involve the fermentation, or other biological conversion, of sugars liberated from the breakdown of cellulosic biomass. A biochemical conversion process to produce ethanol from cellulosic biomass includes the following main steps: feedstock pretreatment, hydrolysis, saccharification, fermentation, dehydration, and lignin recovery.\327\ Feedstock physical pretreatment involves reducing the feedstock's particle size by grinding, shredding, or chopping. Following physical pretreatment, the feedstock undergoes chemical pretreatment, enzymatic hydrolysis, and saccharification to break down the cellulose and hemicellulose into simple sugars such as glucose and xylose. Chemical pretreatment and hydrolysis include treating the feedstock with hot water, dilute acid, alkaline, organic solvent, ammonia, sulfur dioxide, carbon dioxide, or other chemicals to make the biomass more digestible by enzymes. Saccharification breaks down the polysaccharides into simple sugars via enzymatic or acidic methods. The resulting sugars are then fermented to ethanol with yeast, nutrients, and enzymes. Following fermentation, the mixture undergoes dehydration to remove water, carbon dioxide, and other materials. Biochemical conversion processes are unable to produce fuel from the lignin portion of cellulosic biomass feedstocks. During the processing steps described above, the lignin portion of the renewable biomass is isolated for combustion. The biochemical conversion processes we evaluated for this pathway combust the lignin onsite to provide all the thermal and electrical process energy needs for fuel production processes at the facility.

\327\ For additional information on the processes the EPA evaluated, see: 75 FR 14782 (March 26, 2010); RFS2 Rule RIA at 101- 107 and 433-435; and Tao and Aden (2009) (Docket Item No. EPA-HQ- OAR-2005-0161-0844).

We are specifying in Row K that the biochemical conversion process must use lignin from the renewable biomass feedstock (i.e., the feedstock(s) listed in Row K) to provide all thermal and electrical process energy. For example, this means that a biochemical conversion process using corn stover feedstock must combust the lignin that remains after the cellulose and hemicellulose portions of the corn stover are converted to ethanol to provide heat and power for all the fuel production processes at the facility, such that no grid electricity or other fuels are purchased to supply heat and power for these processes. We have determined that these process requirements are necessary to ensure that the pathways in Row K conform with the biochemical conversion processes that we evaluated and determined satisfy the statutory criteria for cellulosic biofuel.

Thermochemical conversion refers to processes that break down cellulosic biomass into intermediates using heat and then upgrade the intermediates to transportation fuel. A thermochemical conversion process to produce ethanol from cellulosic biomass includes the following main steps: feedstock pretreatment, gasification, syngas cleanup and conditioning, fuel synthesis, and separation.\328\ Feedstock pretreatment includes drying and particle size reduction for proper feeding into the gasifier. The biomass is gasified to syngas with an exothermic partial oxidation (directly heated) gasifier or an indirect gasifier using steam and heat transfer. The syngas cleanup and conditioning step involves removing impurities such as tar, sulfur, nitrogen oxides, alkali metals, and particulates. The syngas conditioning step includes sulfur polishing to remove trace levels of hydrogen sulfide and water-gas shift to adjust the final ratio of hydrogen to carbon monoxide. The clean syngas, comprised of carbon monoxide and hydrogen, is converted to ethanol through either a catalytic process or a fermentation process. During the alcohol separation step, ethanol, methanol, and other alcohols are separated with molecular sieves or distillation. The gasification step produces char and coke solid byproducts that are combusted to provide heat and power for the process. Unreacted gases and slipstreams of syngas from the gas conditioning through separation stages can also be combusted to provide process energy. The thermochemical conversion processes that we evaluated for this pathway combust the char, coke, and syngas onsite to provide all the thermal

and electrical process energy needs for fuel production processes at the facility.

\328\ For additional information on the processes the EPA evaluated, see: 75 FR 14782 (March 26, 2010); RFS2 Rule RIA at 107- 111 and 433-435; and Aden (2009) (Docket Item No. EPA-HQ-OAR-2005- 0161-3034).

We are specifying in Row K that the thermochemical conversion process must use char, coke, or syngas derived from the renewable biomass feedstock (i.e., the feedstock(s) listed in Row K) to provide all thermal and electrical process energy. For example, this means that a thermochemical conversion process using corn stover feedstock must combust the char, coke, or syngas byproducts from gasification of the corn stover to provide heat and power for all the fuel production processes at the facility, such that no grid electricity or other fuels are purchased to supply heat and power for these processes. We have determined that these process requirements are necessary to ensure that the pathways in Row K conform with the thermochemical conversion processes that we evaluated and determined satisfy the statutory criteria for cellulosic biofuel.

Dry mill crop residue conversion refers to the conversion of the cellulosic crop residue portion of grain ethanol feedstocks at a dry mill ethanol plant via in-situ or offline technologies. A dry mill ethanol production process to produce ethanol from cellulosic biomass includes the following main steps: grinding, pretreatment, fermentation, distillation, and dehydration.\329\ Grain feedstocks are milled into a coarse flour known as meal. The meal is pretreated (e.g., cooking, liquefaction, hydrolysis) with the addition of water and enzymes to produce a mixture called mash. The mash is fermented with the addition of yeast, nutrients, and enzymes to produce ethanol, carbon dioxide, and solids from the grain and yeast, known as fermented mash. The fermented mash is distilled to produce a mixture of ethanol and water, and a residue of non-fermentable solids known as stillage. The mixture of ethanol and water is dehydrated to produce 200-proof ethanol. Co-products from the dry mill process include distillers grains, and may also include carbon dioxide, solubles syrup, and distillers oil. Grain feedstocks often have a fiber layer on the outside of the kernel that is predominantly composed of cellulosic biomass. We have determined that this fibrous layer on the outside of grain feedstocks (i.e., barley, corn, oats, rice, rye, grain sorghum, and wheat) qualify as crop residue.\330\ While this fiber traditionally ends up in the stillage and is sold with the distillers grains as animal feed, additional ethanol can be produced by converting the kernel fiber to ethanol via in-situ or offline technologies. In-situ technologies perform the fiber and starch conversion simultaneously with minimal changes to the traditional ethanol process; these processes involve pretreatment of the stillage and the addition of specialized enzymes. Offline processes perform the fiber conversion separately from the starch conversion; these processes involve separate process trains to pretreat the stillage and then ferment the fiber portions. The dry mill crop residue conversion processes that we evaluated for this pathway use natural gas, biogas, or crop residue for all thermal process energy.

\329\ For additional information on the processes the EPA evaluated, see: 79 FR 42145-51 (July 18, 2014).

\330\ 79 FR 42150-42151 (July 18, 2014).

We are specifying in Row K that the dry mill crop residue conversion process must use natural gas, biogas, or crop residue for all thermal process energy. Thermal process energy refers to heat energy needed for all the processes at dry mill ethanol plants that are associated with ethanol and distillers grains production. The dry mill processes that we evaluated also use grid electricity to satisfy electrical process energy needs. We have determined that these process requirements are necessary to ensure that the pathways in Row K conform with the dry mill crop residue conversion processes that we evaluated and determined satisfy the statutory criteria for cellulosic biofuel. b. Row L

Row L includes pathways for cellulosic diesel, cellulosic jet fuel, and cellulosic heating oil produced from certain cellulosic feedstocks to qualify for D7 RINs. We proposed to leave the feedstocks in Row L unchanged and revise the production process requirements from “Any process that converts cellulosic biomass to fuel,” to “Fischer- Tropsch process that converts cellulosic biomass to transportation fuel or heating oil; only includes processes that use a portion of the feedstock for over 99% of thermal and electrical process energy.” We are finalizing more substantial revisions to Row L than proposed based on consideration of comments and further review of the processes that we evaluated in prior RFS rulemakings.

One commenter stated that Row L should not be limited to Fischer- Tropsch conversion processes. Upon further review, we agree with this commenter as we have previously evaluated several other production processes (i.e., the set of production processes included in Row M) to produce cellulosic diesel from corn stover and determined that these pathways satisfy the 60 percent lifecycle emissions reduction threshold. Thus, we are finalizing a broader set of process technologies in Row L that matches the set of technologies included in Row M. To include this broader set of process technologies in Row L while ensuring the fuels produced satisfy the statutory criteria for lifecycle emissions, we are also revising the set of feedstocks included in Row L. Specifically, we are removing purpose-grown crop feedstocks from Row L and moving them to a new Row U and pairing them with a more limited set of production processes.\331\ We are moving the purpose-grown crop feedstocks because they are associated with emissions related to crop production (e.g., fertilizer application, feedstock harvesting) that are not present for the other feedstocks in Row L, which are residue and waste feedstocks. In this section, we describe the finalized pathways in Row L and the associated criteria for each of the specified production processes.

\331\ Row U is discussed in section VIII.D.1.e of this preamble.

In the RFS2 Rule and the Pathways I Rule, we evaluated biochemical and thermochemical processes that convert lignocellulosic feedstocks to hydrocarbon fuels such as renewable diesel, gasoline, and jet fuel. We found that hydrocarbon fuels produced from cellulosic feedstocks qualify for the 60 percent lifecycle emissions reduction criteria when certain criteria are satisfied. Below, we describe the production processes evaluated and the associated criteria specified for each of these production processes in Row L.

Thermochemical conversion refers to processes that break down cellulosic biomass into intermediates using heat and then upgrade the intermediates to transportation fuel. Gasification is a thermochemical process that partially combusts biomass and makes syngas intermediate. Pyrolysis is a thermochemical process that heats biomass under high temperature and pressure in the absence of oxygen and makes bio-oil intermediates. Gasification processes can convert cellulosic biomass to ethanol or hydrocarbons, whereas pyrolysis is used to produce hydrocarbons.

A gasification and upgrading process to produce hydrocarbon fuels from cellulosic biomass includes the following main steps: feedstock pretreatment, gasification, syngas cleanup and conditioning, fuel

synthesis, upgrading, and separation.\332\ Feedstock pretreatment includes drying and particle size reduction for proper feeding into the gasifier. The biomass is gasified to syngas with an exothermic partial oxidation (directly heated) gasifier or an indirect gasifier using steam and heat transfer. The syngas cleanup and conditioning step involves removing impurities such as tar, sulfur, nitrogen oxides, metals, and particulates. The syngas conditioning step includes polishing to remove hydrogen sulfide and water-gas shift to adjust the final ratio of hydrogen to carbon monoxide. A slipstream of clean syngas is sent to a pressure swing adsorption unit to provide hydrogen for downstream hydroprocessing. The cleaned and water-shifted syngas is sent to a reactor (e.g., Fischer-Tropsch) where the carbon monoxide and hydrogen are reacted over catalyst creating a synthetic crude oil (“syncrude”). The syncrude from the reactor is sent to a distillation column where it is separated into various hydrocarbon fuels such as naphtha, distillates, and wax, and the heavier compounds can be hydrocracked to maximize the production of diesel. The wax undergoes hydroprocessing to upgrade it to fuel-range-material, and diesel fuel is often finished with a hydrotreating step. The gasification step produces char and coke byproducts that are combusted to provide heat and power for the process. Unreacted gases and slipstreams of syngas from the gas conditioning through separation stages can be combusted to provide process energy. The thermochemical conversion processes that we evaluated for this pathway combust the char, coke, and syngas onsite to provide all the thermal and electrical process energy needs for fuel production processes at the facility.

\332\ For additional information on the processes the EPA evaluated, see: 75 FR 14782 (March 26, 2010); 78 FR 14208 (March 5, 2013); RFS2 Rule RIA at 101-113 and 433-435; and Davis (2009) (Docket Item No. EPA-HQ-OAR-2005-0161-3035).

A pyrolysis and upgrading process to produce hydrocarbon fuels from cellulosic biomass includes the following main steps: feedstock pretreatment, pyrolysis, upgrading, separation, and distillation.\333\ The feedstock pretreatment step includes biomass drying and size reduction and normalization. The biomass is fed to the pyrolysis reactor where it is rapidly heated in the absence of oxygen and thermally decomposed to pyrolysis vapor, water vapor, non-condensable product gases, char, coke, and ash. The pyrolysis vapor is cooled and condensed to liquid bio-oil. The bio-oil is upgraded via hydroprocessing with the addition of hydrogen to remove oxygen, sulfur, nitrogen, olefins, and metals. The upgraded bio-oil is separated into off-gas, wastewater, and stabilized oil streams. The stabilized oil is distilled into gasoline, diesel, and other hydrocarbon products. This pyrolysis step generates char, coke, and product gas that can be combusted to provide process energy. The pyrolysis and upgrading processes that we evaluated for this pathway combust the char, coke, and product gas onsite to provide all the thermal and electrical process energy needs for fuel production processes at the facility, other than the use of natural gas to produce hydrogen via steam methane reforming for the upgrading step. The pyrolysis and upgrading processes that we evaluated consume no more than 0.5 Btu of natural gas per Btu of finished fuel.

\333\ For additional information on the processes the EPA evaluated, see: 78 FR 14208-09 (March 5, 2013); RFS2 Rule RIA at 112; and Kinchin (2011) (Docket Item No. EPA-HQ-OAR-2011-0542-0007).

A biochemical conversion and upgrading process to produce hydrocarbon fuels from cellulosic biomass includes the following main steps: feedstock pretreatment, hydrolysis, and aqueous phase catalytic reforming to selectively upgrade intermediates to liquid hydrocarbon fuels.\334\ Feedstock pretreatment involves drying and size reduction by grinding, shredding, or chopping. Following pretreatment, the feedstock undergoes hydrolysis to break down the cellulose and hemicellulose into aqueous intermediates including simple sugars and platform chemicals derived from these sugars. The aqueous phase catalytic reforming step is a form of upgrading to convert sugars into hydrocarbon fuels. This form of upgrading requires hydrogen as an input and involves substantial chemical transformations and multiple reactions involving oxygen removal (e.g., dehydration, hydrogenation, hydrogenolysis) combined with carbon-to-carbon coupling (e.g., aldol condensation, ketonization, oligomerization). Biochemical conversion processes are unable to produce fuel from the lignin portion of cellulosic biomass feedstocks. During the processing steps described above, the lignin portion of the renewable biomass is isolated for combustion. The biochemical conversion and upgrading processes that we evaluated for this pathway combust the lignin onsite to provide all the thermal and electrical process energy needs for fuel production processes at the facility, other than natural gas needed to produce hydrogen for upgrading. The biochemical conversion and upgrading processes that we evaluated consume no more than 0.5 Btu of natural gas per Btu of finished fuel.

\334\ For additional information on the processes the EPA evaluated, see: 78 FR 14209-10 (March 5, 2013).

A direct biochemical conversion process to produce hydrocarbon fuels from cellulosic biomass includes the following main steps: feedstock pretreatment, hydrolysis, saccharification, fermentation with enhanced microorganisms, and lignin recovery. The process is similar to the biochemical conversion to ethanol process, with the major difference being that the fermentation step utilizes organisms enhanced through synthetic biology to produce hydrocarbons instead of ethanol. Direct biochemical conversion processes are unable to produce fuel from the lignin portion of cellulosic biomass feedstocks. During the processing steps described above, the lignin portion of the renewable biomass is isolated for combustion. The direct biochemical conversion processes we evaluated for this pathway combust the lignin onsite to provide all the thermal and electrical process energy needs for fuel production processes at the facility.

We are specifying in Row L the following feedstocks: crop residue; slash, pre-commercial thinnings, and tree residue; separated yard waste; biogenic components of separated MSW; and cellulosic components of separated food waste. We are specifying in Row L the following production processes that use lignin, char, or syngas derived from the renewable biomass feedstock to provide all the thermal and electrical process energy: gasification and upgrading; and direct biochemical conversion. We are also specifying in Row L the following production processes that use lignin, char, or syngas derived from the renewable biomass feedstock to provide all the thermal and electrical process energy other than natural gas to produce hydrogen for upgrading (maximum 0.5 Btu of natural gas per Btu of finished fuel): pyrolysis and upgrading; and biochemical conversion and upgrading. We have determined that these process requirements are necessary to ensure that the pathways in Row L conform with the processes that we evaluated and determined satisfy the statutory criteria for cellulosic biofuel.

Relative to the revisions proposed for Row L, we are finalizing a broader set of production processes and a narrower set of feedstocks. We analyzed the

lifecycle emissions associated with renewable fuel produced from corn stover and switchgrass via each of the production processes described above.\335\ We determined that when corn stover is used as feedstock, these pathways satisfy the 60 percent lifecycle emissions reduction criteria to qualify as cellulosic biofuel. However, when switchgrass is used as feedstock, not all the production processes listed in Row L would satisfy the 60 percent lifecycle emissions reduction criteria. We extended the corn stover estimates to other waste and residue feedstocks, and we extended the switchgrass estimates to other purpose- grown crop feedstocks including other energy grasses and annual cover crops. These revisions clarify the eligible pathways in Row L. As mentioned above, we are moving the purpose-grown crop feedstocks to a new Row U, which includes a narrower set of production processes.

\335\ For additional information on the EPA's analysis of the emissions associated with producing and transporting these feedstocks, see: 75 FR 14791-95 (March 26, 2010); and RFS2 Rule RIA Section 2.4.

Row M includes pathways for renewable gasoline, renewable gasoline blendstock, and co-processed cellulosic diesel, jet fuel, and heating oil produced from certain cellulosic feedstocks to qualify for D3 RINs. These pathways were originally evaluated and approved as part of the Pathways I Rule.\336\ The production process requirements listed in Row M were not described as “any” production process, but they were listed without a great deal of specificity. We are finalizing the revisions to Row M as proposed but with modifications based on consideration of comments and further review of the processes that we evaluated in prior RFS rulemakings.

\336\ 78 FR 14205-13 (March 5, 2013).

In response to comments that requested additional clarity, we are modifying the production process requirements in Row M to provide additional specificity. For example, the revisions clarify that the approved gasification and upgrading and direct biochemical conversion processes do not use any fossil fuels for process energy, whereas the pyrolysis and upgrading and biochemical conversion and upgrading processes can use up to a specific amount of natural gas to produce hydrogen for upgrading per unit of fuel produced. These revisions align the production process requirements in Row M with the production processes that we evaluated and approved in the Pathways I Rule.\337\

\337\ Id.

We are also moving “cellulosic components of annual cover crops” from Row M to Row N. As discussed in section VIII.D.1.b of this preamble, when we evaluated hydrocarbon fuels produced from switchgrass through the pyrolysis and upgrading and biochemical conversion and upgrading processes, we found that these pathways did not satisfy the 60 percent lifecycle emissions reduction criteria. We extended the switchgrass estimates to other purpose-grown crop feedstocks because they are associated with emissions related to crop production (e.g., fertilizer application, feedstock harvesting) that are not present for the other feedstocks in Row L. Thus, as discussed in section VIII.D.1.d of this preamble, to further align the pathways approved under Row M with our prior evaluations, we are moving “cellulosic components of annual cover crops” to Row N.

After these modifications, the production process requirements and feedstocks for Rows L and M are now the same. See section VIII.D.1.b of this preamble for further discussion of the production processes and feedstocks approved under Rows L and M and the reasons for the revisions in this action. d. Row N

Row N currently includes pathways for naphtha produced from switchgrass and other energy grasses through a gasification and upgrading process to qualify for D3 RINs.\338\ As discussed in section VIII.D.1.c of this preamble, we also previously determined that a wider range of hydrocarbon fuels (e.g., renewable gasoline, co-processed cellulosic diesel) produced from specific energy grasses or the cellulosic components of annual cover crops produced through a gasification and upgrading process or a direct biochemical conversion satisfies the 60 percent lifecycle emissions reduction criteria provided that specific production process requirements are met.\339\ In this action, we are moving specific feedstocks from Row M to Row N to ensure that the correct pairings of fuels, feedstocks, and production processes qualify for D3 RINs based on our prior lifecycle analyses. We are also adding fuels to Row N to ensure that the complete set of pathways that we previously determined satisfy the statutory criteria are listed in Table 1. We did not receive any comments opposing these amendments.

\338\ The current pathways in Row N were approved based on the evaluation described at 78 FR 14208 (March 5, 2013).

\339\ 78 FR 14205-13 (March 5, 2013).

Rows Q and T include pathways for renewable CNG/LNG produced from biogas. Row Q includes pathways for D3 RINs for renewable CNG/LNG produced from: biogas from landfills, municipal wastewater treatment facility digesters, agricultural digesters, and separated MSW digesters; and biogas from the cellulosic components of biomass processed in other waste digesters. The pathways in Row Q qualify for D3 RINs. Row T includes pathways for D5 RINs

for renewable CNG/LNG produced from biogas from waste digesters.\343\

\343\ For background on the EPA's evaluation of these pathways, see: 79 FR 42140-44 (July 18, 2014).

We are finalizing changes to Rows Q and T with revisions relative to what we proposed based on our consideration of the comments. In the production process requirements for Rows Q and T, we proposed to replace “Any” with “The following processes that occur in North America: CNG production from treated biogas via compression; LNG production from treated biogas via liquefaction.” Commenters stated that it could be problematic to reference the fuels (CNG/LNG) in the production process requirements, and that CNG/LNG can also be produced from biogas and RNG. Based on our consideration of these comments, we are describing the production processes as “Treatment and compression” and “Treatment and liquefaction.” Based on our consideration of comments, we are also replacing the condition that the production processes “occur in North America” with a condition that the production process “do[es] not transport RNG or renewable CNG/LNG by ocean-going vessel.” These modifications are discussed below.

Treatment and compression refers to the process of upgrading biogas to RNG and subsequent compression to produce renewable CNG for use in CNG vehicles. Treatment and liquefaction refers to the process of upgrading biogas to renewable LNG for use in LNG vehicles. Treatment begins with moisture and particulate removal from raw biogas, followed by advanced cleaning technologies that remove carbon dioxide, non- methane organic compounds and a variety of other contaminants including sulfur compounds. Treatment technologies include the use of pressure swing adsorption, water scrubbing, chemical absorption, membrane separation, or other technologies to remove additional components so the gas is suitable for injection into the natural gas commercial pipeline system. The RNG is then transported and distributed to refueling stations via the natural gas pipeline system, or potentially in a tube as compressed gas or liquefied in a tank. Final compression or liquefaction of the RNG at a refueling station depends on how the gas will be used as a vehicle fuel. Compression is the physical compression of RNG to produce renewable CNG, while liquefaction is the physical conversion of RNG into a liquid state by cooling it to low temperatures to produce renewable LNG.

As noted above, a commenter disagreed with the proposed condition limiting the processes in Rows Q and T to “processes that occur in North America.” In the Set 2 proposal, we explained that this condition was appropriate because there could be CNG/LNG transportation and distribution scenarios associated with high GHG emissions that we did not consider in the lifecycle analyses that formed the basis for Rows Q and T. We specifically discussed long-duration LNG transportation with associated boil-off emissions as a scenario that the underlying evaluation for Rows Q and T did not consider; we estimated that transporting LNG is associated with boil-off emissions of approximately 0.10 to 0.15 percent per day.\344\ Pursuant to the definition of “lifecycle greenhouse gas emissions,” \345\ we always evaluate emissions associated with transport of feedstocks and fuels in our lifecycle emissions calculations. In the case of LNG transportation in particular, the transport emissions have the potential to be dispositive in terms of meeting the statutory emissions reduction criteria to qualify for D3 or D5 RINs, so it is appropriate to condition the pathway on this basis. Thus, the proposed condition that CNG/LNG production processes “occur in North America” was intended to exclude long international transportation of LNG that could result in large boil-off or other sources of emissions that could be results in the production process (including transportation and distribution) not meeting the 50 percent or 60 percent emissions reduction threshold.

\344\ 90 FR 25848 (June 17, 2025).

\345\ “The term `lifecycle greenhouse gas emissions' . . . include[es] all stages of fuel and feedstock production and distribution, from feedstock generation or extraction through the distribution and delivery and use of the finished fuel to the ultimate consumer. . . .” CAA section 211(o)(1)(H).

However, based on our consideration of the public comments, the restriction to North America raised other questions, such as whether renewable CNG/LNG produced and used in Hawaii or other covered locations would qualify for the Row Q and T pathways.\346\ Given that our primary concern is long-duration international transportation and distribution scenarios that would likely involve marine transport of renewable CNG/LNG, we are instead finalizing a condition that the production processes under Rows Q and T, “do not transport RNG, or renewable CNG/LNG by ocean-going vessel.” \347\ We believe this change more directly addresses our primary concern of long-duration transportation scenarios. We note that renewable fuel producers seeking to transport renewable CNG/LNG on ocean-going vessels can still petition the EPA to evaluate a new pathway using the petition process specified at 40 CFR 80.1416.

\346\ Covered location is defined as “the contiguous 48 states, Hawaii, and any state or territory that has received an approval from EPA to opt-in to the RFS program.” 40 CFR 80.2.

\347\ Ocean-going vessel is defined as “vessels that are equipped with engines meeting the definition of `Category 3' in 40 CFR 1042.901.” 40 CFR 80.2.

The revisions described in this section VIII.D.1 of this preamble do not affect existing pathway registrations and we are adding language to 40 CFR 80.1426(f)(1) to clarify that a renewable fuel producer may continue to use an existing registration that was under a pathway in Table 1 that previously specified “Any” or “Any process that converts cellulosic biomass to fuel” as its production process requirement if the pathway was in the renewable fuel facility's registration that was accepted by EPA prior to the effective date of this rule. Producers with an existing pathway registration that satisfies the above criteria do not need to update or modify their registrations due to the Table 1 amendments in this action, nor will any existing pathway registrations be deactivated. Any modifications to the renewable fuel production facility's registration after the effective date of this action must meet an approved pathway.\348\ These provisions are appropriate as prior registrations were reviewed and accepted by the EPA based on our engineering judgement and interpretation of the fuel pathways in Table 1, including our consideration of the parameters of the lifecycle analyses that formed the basis for the approved pathways.

\348\ An approved pathway is defined as “a pathway listed in table 1 to Sec. 80.1426 or in a petition approved under Sec. 80.1416 that is eligible to generate RINs of a particular D code.” 40 CFR 80.2.

To provide additional clarity going forward regarding the criteria the EPA will apply to determine whether a feedstock, fuel, or production process qualifies for an approved pathway in Table 1, we are adding the following language to 40 CFR 80.1426(f)(1): “For purposes of identifying the appropriate approved pathway, the fuel must be produced, distributed, and used in a manner consistent with the pathway EPA evaluated when it determined that the pathway satisfies the applicable lifecycle emissions reduction requirement.” One commenter stated that this language was unnecessary and unhelpful, but based on our experience

implementing the RFS program we believe adding this provision to the regulations will improve program implementation and clarify how to handle situations that have arisen in the past where a production process appeared to meet the production process requirements in Table 1 but did not actually satisfy the statutory criteria. i. Conclusion

We believe the revisions to Table 1 discussed in this section will improve implementation of the RFS program in accordance with the statutory criteria. Although we have strived to describe the pathways in Table 1 in a manner that aligns with the lifecycle analysis that supports each pathway, we recognize there will likely still be some cases where it is not clear whether a particular production process qualifies for a particular pathway. Renewable fuel producers seeking to determine if their fuel fits within the bounds of a pathway listed in Table 1 can contact the EPA through the pathway screening tool for clarification.\349\ The pathway screening tool process was designed for the express purpose of providing a means for renewable fuel producers to seek input on whether a fuel fits an existing pathway in Table 1 or whether a new renewable fuel pathway petition, pursuant to 40 CFR 80.1416, is needed prior to registering to generate RINs.

\349\ EPA, “Renewable Fuel Pathway Screening Tool.” https://www.epa.gov/renewable-fuel-standard-program/forms/renewable-fuel-pathway-screening-tool.

The RFS regulations previously did not define the terms “renewable fuel producer,” “renewable fuel oil,” “renewable naphtha,” and “renewable jet fuel”; however, all these terms are used within the RFS regulations. To provide regulatory clarity, we proposed to define each of these terms in the Set 2 proposal. Commenters were generally supportive of defining these terms but suggested minor revisions to improve clarity and accuracy of the definitions. We have incorporated these suggestions into our final definitions described below.

We are defining a renewable fuel producer as “any person that owns, leases, operates, controls, or supervises a facility where renewable fuels are produced.” This definition is consistent with other definitions of regulated parties under the RFS program. We are defining renewable fuel oil as “heating oil that is renewable fuel and that meets paragraph (2) of the definition of heating oil,” renewable naphtha as “naphtha that is renewable fuel,” and renewable jet fuel as “jet fuel that is renewable fuel and that meets ASTM D1655 or ASTM D7566.” These definitions are consistent with other definitions of renewable fuels under the RFS program.

We believe these definitions will provide more clarity to both the regulated community and the public. 2. Revised Definitions

Given the complex nature of global supply chains, we are updating the definitions of foreign renewable fuel producers and importers as proposed in the Set 2 proposal. These revisions will also provide clarity to regulated parties regarding which entities qualify as foreign renewable fuel producers or importers.

Under 40 CFR 80.2, a foreign renewable fuel producer was previously defined as “a person from a foreign country or from an area outside the covered location who produces renewable fuel for use in transportation fuel, heating oil, or jet fuel for export to the covered location. Foreign ethanol producers are considered foreign renewable fuel producers.” This definition was unclear because renewable fuel produced at a facility in the United States could arguably be considered produced by a “foreign renewable fuel producer” if the corporation that produced the renewable fuel is incorporated in a foreign country. We are instead defining a foreign renewable fuel producer as “any person that owns, leases, operates, controls, or supervises a facility outside the covered location where renewable fuel is produced.” This revised definition is consistent with how foreign biogas producers and foreign RNG producers have been defined under the RFS regulations.

Further, under 40 CFR 80.2 an importer was previously defined as “any person who imports transportation fuel or renewable fuel into the covered location from an area outside of the covered location.” To provide greater clarity to the regulated community as to which entities can be considered an importer, we are revising the definition of importer to include “the importer of record or an authorized agent acting on their behalf, as well as the actual owner, the consignee, or the transferee, if the right to withdraw merchandise from a bonded warehouse has been transferred.”

Finally, we are adding a provision in the liability provisions at 40 CFR 80.1461 that specifies that each person meeting the definition of an importer of renewable fuel under the RFS regulations is jointly and severally liable for any violations of the RFS requirements, including the new import RIN reduction provisions. The change is consistent with the liability framework for other parties participating in the RFS program and the liability framework that applies in our fuel quality program under 40 CFR part 1090. These provisions are also necessary to ensure that importers who import non-qualifying renewable fuel or renewable fuel feedstocks can be held liable. 3. New Biointermediates

In the 2020-2022 RFS Rule, we established provisions for biointermediates to be used to produce qualifying renewable fuels. At the same time, we listed in the regulations the specific biointermediates that are allowed under the RFS program.\351\ We also stated that new biointermediates would be brought into the RFS program via notice-and-comment rulemaking. In the Set 1 Rule, we added biogas as a biointermediate and in the Set 2 proposal we proposed to add two more biointermediates: activated sludge and converted oils. These new biointermediates were requested in two separate petitions for rulemaking submitted to the EPA in 2023 and 2024.\352\ We are finalizing the addition of these two new biointermediates in this action.

\351\ 87 FR 39600 (July 1, 2022).

\352\ “Agresti Energy Petition to Add Potential Biointermediates to the Regulatory Definition,” October 12, 2023; “DS Dansuk Petition for Addition of New Biointermediate Produced via a New Production Process,” November 26, 2024. Both petitions are available in the docket for this action.

First, we are adding activated sludge, which is waste sludge from a secondary wastewater treatment process involving oxygen and microorganisms. One petitioner suggested that activated

sludge could initially be used to produce renewable CNG, potentially followed by other fuels such as LNG, ethanol, biobutanol, and methanol in the future. Second, we are adding converted oils, which are glycerides such as monoglycerides and diglycerides that are produced through the glycerolysis of waste oils, fats, or greases with glycerol. Converted oils must exclusively consist of glycerides with fatty acid alkyl groups that originate from qualifying biogenic waste oils, fats, or greases during the conversion process. One petitioner suggested that converted oils could be used to produce biodiesel, renewable diesel, or jet fuel.

We are finalizing these changes as proposed. Several commenters supported the proposed changes, while one commenter expressed concern about considering activated sludge a biointermediate rather than simply as an approved feedstock. In response to this comment, we want to clarify that biogas from municipal wastewater treatment facility digesters is already an approved feedstock in Rows Q and T, and such pathways may involve the production of biogas from activated sludge at the same facility where the activated sludge is produced. Furthermore, biogas used to make a renewable fuel other than renewable CNG/LNG is also a biointermediate.\353\ In cases where the activated sludge is produced at one facility and used to produce renewable fuel at a second facility, the activated sludge would need to be a biointermediate. This is because activated sludge is produced from primary sludge, which has been substantially altered through anaerobic and aerobic treatment. Thus, by adding activated sludge as a new biointermediate, we are facilitating the production of qualifying fuel from this material.

\353\ 40 CFR 80.2.

Under the RFS program, small refineries are eligible to petition for and receive an exemption from their RFS obligations for a given compliance year. The RFS regulations do not, however, exempt these small refineries from having to submit an annual compliance report. In the Set 2 proposal, we proposed to clarify that such exempt small refineries must file an annual compliance report. Commenters were generally supportive of this change and we are finalizing this clarification as proposed.

While an exempt small refinery does not have to retire RINs to comply with an RVO, it still produces gasoline or diesel that is used as transportation fuel in the United States and thus this fuel is included in EIA's projections of nationwide fuel consumption. We use these projections as the basis for calculating the annual RFS percentage standards and, as described in the Set 1 Rule, we have recently discovered a discrepancy between the volumes of gasoline and diesel reported by obligated parties in their annual compliance reports and EIA's reported actual volumes of gasoline and diesel consumed.\354\ In order for the EPA to have a complete picture of the actual volume of gasoline and diesel that was produced by refiners--including fuel produced by exempt small refineries--that would otherwise be reported as obligated fuel in a given compliance year, it is necessary that all refiners submit an annual compliance report regardless of whether they received an exemption from their RFS obligations for the given compliance year. Having this data will improve the accuracy of our gasoline and diesel projections in future standard-setting actions and better ensure that there is not overcompliance by obligated parties. Without gasoline and diesel production volumes from exempt small refineries, we are more likely to underestimate the actual amount of gasoline and diesel expected to be used in a given compliance year. This would result in overly stringent percentage standards, and thus more RINs would need to be retired than necessary to comply with the annual volume requirements. Therefore, we are clarifying under 40 CFR 80.1441(e)(2) and 80.1442(h) that exempt small refineries and small refiners are still subject to RFS reporting requirements under 40 CFR 80.1451(a) and must submit an annual compliance report by the annual compliance reporting deadline. Such exempt small refineries will need to report their actual annual production of gasoline and diesel that would otherwise be obligated fuel.

\354\ Set 1 RIA, Chapter 1.11.

In addition, we also proposed to clarify under 40 CFR 80.1441(e)(2) and 80.1442(h) that a small refinery or small refiner that receives an exemption for a given compliance year is not exempt from having to comply with any deficit RVOs that were carried forward from the previous compliance year. Several small refinery commenters objected to this clarification and claimed that this proposed change would negate the intent behind both the deficit carryforward provision and small refinery hardship relief. We disagree with these commenters and are finalizing this clarification as proposed, consistent with our long- standing interpretation and implementation of an exemption under the SRE program. We address the specific concerns raised by commenters in RTC Section 11.6.1. 2. Compliance Report Updates

We are finalizing several changes to requirements related to compliance reports. Generally, these changes are intended to reduce burden, support implementation, and improve the quality of information submitted to the EPA under 40 CFR 80.1449, 80.1451, and 80.1452. Commenters were generally supportive of these changes.

First, we are sunsetting the reporting requirement specific to how each entity owning RINs must calculate the volume of renewable fuel (in gallons) owned at the end of each quarter and report this on a quarterly basis. The general requirements for RIN distribution specify that the number of assigned RINs owned must be less than or equal to the amount of renewable fuel owned multiplied by 2.5. However, since 2010 there have been no documented compliance issues with entities meeting the distribution requirement for assigned RINs. To reduce reporting burden, we are removing as proposed this quarterly reporting requirement under 40 CFR 80.1451 and also updating the associated requirement under 40 CFR 80.1428(a)(4).

Next, we are simplifying the “production outlook report” and its associated requirements as proposed. Renewable fuel producers were required to submit an annual “production outlook report” that previously included a monthly or annual projection in future years; we are now only requiring annual projections. Reducing this reporting requirement to annual projections will reduce burden while maintaining a minimum level of reporting needed to assess future production. We are also updating or removing other outdated language under 40 CFR 80.1449.

Additionally, producers or importers of biogas used for transportation fuel were required to report on a quarterly basis the total energy produced and supplied for use as transportation fuel, as well as where the fuel is sold for use as a transportation fuel. These quarterly reporting requirements under 40 CFR 80.1451(b)(1)(ii)(P) were similar to other existing reporting requirements under

40 CFR 80.140. We are therefore removing this separate quarterly reporting requirement as proposed to further reduce reporting burden.

Finally, we are taking steps to improve the quality of information when entities generate RINs in EMTS. Currently, each reporting party must enter a “reason code” whenever they are reporting a buy, sell, separate or retire transaction in EMTS, as described in 40 CFR 80.1452. This information is then used for implementation, compliance, and public data postings on our website. As proposed, we are now adding a “reason code” for RIN generation to directly improve implementation. For example, commenters noted long delays by the EPA in processing report corrections in EMTS and we will first use this new field to automate processing report corrections submitted by renewable fuel producers (e.g., under-generation of RINs). We will initially utilize a transition period that only requires entities submitting report corrections to complete this new element followed by full implementation starting on January 1, 2027. We will also post additional information specific to compliance assistance and technical support material on our website while gradually phasing in this new field and closely monitoring feedback towards improving implementation and automation. 3. Third-Party Auditor Registration Renewal

We are changing the frequency with which independent third-party auditors are required to renew their registrations. Previously, a third-party auditor's registration expired each year on December 31. However, we have found that there is significant burden on both the EPA and auditors to review and approve these registrations every year. We believe that it is not necessary to require auditors to renew their registrations annually and that a two-year registration period is more appropriate. This length of time still ensures that we are regularly reviewing auditor registrations, while also reducing burden on the EPA and auditors. Commenters were generally supportive of this change. Thus, we are specifying that a third-party auditor's registration will expire on December 31 every other year. 4. Engineering Review Site Visits

Under 40 CFR 80.1450(b)(2), renewable fuel production facilities are required to undergo an independent third-party engineering review prior to registration. As part of that engineering review, the independent third-party engineer is required to conduct a site visit. However, the previous regulations did not specify when such site visits need to occur. Recently, we have received some engineering reviews where the site visit was over a year old. In the Set 2 proposal, we proposed to specify that engineering review site visits must be conducted within six months prior to submitting a registration request in order to ensure that the site visit is reflective of the current operation of the facility. Several commenters expressed concern about the limited number of qualified engineers to conduct such reviews. However, we believe that it is critical that the engineering review site visit accurately reflects the current operations of the facility. We are therefore finalizing the requirement for engineering review site visits to be conducted within six months prior to submitting a registration request, as proposed. 5. Biogas Batch Period of Production

As part of the biogas regulatory reform provisions in the Set 1 Rule, a batch of biogas was specified as the volume of biogas measured for a calendar month, with the last day of the month as the production date.\355\ Stakeholders have subsequently provided feedback to the EPA that allowing biogas producers to produce batches for time periods of less than a month would improve implementation of the biogas regulations. To provide additional flexibility for biogas producers, in the Set 2 proposal we proposed to change the period of production such that a biogas batch may be “up to” a calendar month, allowing for more frequent biogas batches as indicated by the business practices of the biogas producer. This change also provides additional flexibility to RNG producers that use the biogas batches as part of their RNG RIN generation. Commenters were generally supportive of this change, and we are therefore finalizing this flexibility as proposed.

\355\ 40 CFR 80.105(j)(1) and 80.140(b)(2).

In the Set 2 proposal, we proposed to add measurement protocols to the list of approved methods for measuring the volume of RNG or treated biogas. Commenters were generally supportive of adding these methods to the regulations and suggested additional methods that could be added. We agree with commenters and have included these additional methods in the list of approved methods, as we have already accepted all these methods through alternative measurement protocols.\356\ The methods we are adding under 40 CFR 80.155(a) are the following: AGA Report No. 3; AGA Report No. 7; AGA Report No. 9; AGA Report No. 11; ASME MFC-3M; ASME MFC-5.1; ASME MFC-11; ASME MFC-12M; ASME MFC-21.2; ANSI B109.3; API MPMS 14.9; ISO 5167-1 and ISO 5167-2, ISO 5167-4, or ISO 5167-5; ISO 10790; ISO 14511; ISO 17089-1; and ISO 17089-2.

\356\ EPA, “Alternative Measurement Protocols for Biogas and Renewable Natural Gas,” https://www.epa.gov/fuels-registration-reporting-and-compliance-help/alternative-measurement-protocols-biogas-and-0.

We also proposed to add methods for the measurement of biogas and RNG samples under 40 CFR 80.155(b)(2). Commenters were generally supportive of adding these methods to the regulations and suggested additional methods that could be added. We agree with commenters and have included these additional methods in the list of approved methods. For methane, carbon dioxide, nitrogen, and oxygen, we are adding ASTM D1945, ASTM D1946, and ASTM D7833; previously, the only specified method was EPA Method 3C. For hydrogen sulfide and total sulfur, we are adding ASTM D6228 and ASTM D6968; previously the only specified method was ASTM D5504. For moisture, we are adding ASTM D1142, ASTM D5454, and ASTM D7904; previously, the only specified method was ASTM D4888. For hydrocarbon analysis, we are adding ASTM D1945, ASTM D1946, ASTM D7833, and EPA Method TO-15; previously, the only specified method was EPA Method 18.

We did not propose and are not finalizing any changes to the sulfur standards for biodiesel or renewable diesel in this action. However, we are taking this opportunity to reiterate that biodiesel and renewable diesel producers must comply with all of our regulatory requirements for diesel producers in 40 CFR part 1090 for the biodiesel and renewable diesel they produce (referred to as “nonpetroleum diesel fuel” in 40 CFR part 1090), including demonstrating homogeneity for each batch of biodiesel and renewable diesel and testing each batch for sulfur content to ensure the fuel meets the 15 ppm standard.\357\ This also

includes the requirement that all sulfur test results must be obtained by the producer before shipping biodiesel or renewable diesel from the facility. Requiring measurement before shipping provides assurance of compliance prior to the fuel being mixed and comingled in the fungible distribution system.

\357\ We have previously made clear that biodiesel producers must comply with all our regulatory requirements for diesel producers. See EPA, “Guidance for Biodiesel Producers and Biodiesel Blenders/Users,” EPA-420-B-07-019, November 2007; see also EPA “Am I required to register biodiesel? How would I do that?” April 1, 2025. https://www.epa.gov/fuels-registration-reporting-and-compliance-help/am-i-required-register-biodiesel-how-would-i-do.

To further make clear that all the above requirements apply to biodiesel and renewable diesel, we proposed to clarify the language at 40 CFR 1090.300(a), 1090.305(a), 1090.1310(b)(1), and 1090.1337(e). Commenters were generally supportive of these clarifications, and we are finalizing these changes as proposed with minor clerical revisions to the proposed language.

In 2022, we finalized changes to the way the RFS compliance and attest engagement reporting deadlines are determined.\358\ Prior to that action, the compliance and attest engagement reporting deadlines for a given compliance year were March 31 and June 1 of the subsequent year, respectively, even if the applicable RFS standards for that year had not yet been established. Any change to these deadlines required the EPA to undertake a notice-and-comment rulemaking process to revise the RFS regulations on a case-by-case basis. However, under the new provisions finalized in 2022, the annual compliance reporting deadline is the latest date of the following: \359\

\358\ 87 FR 5696 (February 2, 2022).

\359\ 40 CFR 80.1451(f)(1)(i)(A).

March 31st of the subsequent calendar year;

The next quarterly reporting deadline after the effective date of the subsequent compliance year's standards (typically 60 days after publication of the final rule in the Federal Register); or

The next quarterly reporting deadline under 40 CFR 80.1451(f)(2) after the annual compliance reporting deadline for the prior compliance year.

In December 2024, we proposed to add a new provision that would automatically extend the annual compliance reporting deadline for a given compliance year if we propose to revise an existing RFS standard for that year.\360\ Some commenters supported the certainty that this change would provide to stakeholders when EPA proposes to revise an existing RFS standard, while other commenters expressed concern that these provisions were unnecessary and could undermine RFS program integrity. On balance, we find that the benefits of the proposed new compliance date extension provisions outweigh the concerns raised by some commenters and we are finalizing the provisions as proposed. We address the specific concerns raised by commenters in RTC Section 11.9.

\360\ 89 FR 100442 (December 12, 2024).

Under this approach, the publication of a document in the Federal Register proposing to revise a renewable fuel standard in 40 CFR 80.1405(a) will automatically extend the annual compliance reporting deadline for that year to the next quarterly reporting deadline after either: (1) The effective date of the final rule that revises the existing standard (typically 60 days after publication of the final rule in the Federal Register); or (2) 60 days after the publication of a document in the Federal Register withdrawing the proposed revision. However, if we do not either finalize or withdraw the proposed revision within 12 months after the proposed rule is published, we are limiting the extension in this specific circumstance to no more than the next quarterly reporting deadline that is 12 months after the date of publication of the proposed rule.\361\ We believe that this provides sufficient time for the EPA to either finalize or withdraw the proposed revision to an existing RFS standard and do not want to indefinitely extend the compliance reporting deadline for a compliance year with already established RFS standards.

\361\ We note that under any of these scenarios, the applicable compliance reporting deadline in 40 CFR 80.1451(f)(1)(i)(A) or (B) of this section would apply if it were later than the proposed extension (e.g., the deadline would be no earlier than March 31 of the subsequent calendar year or the next quarterly reporting deadline after the annual compliance reporting deadline for the prior compliance year).

Essentially, this new provision means that the mere proposal--as opposed to a final action--by the EPA to change an existing RFS standard would change the associated compliance reporting deadline for that compliance year. This change is being made because by the time the need is evident to extend the compliance deadline, there is often inadequate time to both propose and finalize a rulemaking to do so. And even when we have undertaken rulemakings to extend compliance deadlines, these actions have required significant time and resources by EPA staff that could have been dedicated to other Agency priorities. By further automating the extension of compliance deadlines when we propose to revise an existing RFS standard, EPA staff will have more time to work on the final rulemaking to revise the existing RFS standard. This will likely result in the final rule being completed sooner than it would otherwise if the same EPA staff had to work on a separate final rule to first extend the associated compliance deadline before then revising the existing RFS standard.

As an example, under this approach, if the 2026 compliance deadline was originally established as March 31, 2027, but then we proposed to revise the 2026 cellulosic biofuel standard on November 30, 2026, the 2026 compliance reporting deadline would be automatically extended until the first quarterly reporting deadline after the effective date of the final rule establishing the revised 2026 cellulosic biofuel standard. We would not have to separately propose to extend the 2026 compliance reporting deadline in that same action, because the deadline would be automatically extended by operation of law. If we then finalized the proposed revision to the 2026 cellulosic biofuel standard on February 15, 2027, with an effective date of April 16, 2027, the 2026 compliance reporting deadline would be June 1, 2027 (i.e., the next quarterly reporting deadline after the effective date of the final rule). Alternatively, if we chose not to finalize the proposed revision to the 2026 cellulosic biofuel standard and instead published a document in the Federal Register to withdraw the proposed revision on April 30, 2027, the 2026 compliance reporting deadline would be September 1, 2027 (i.e., the next quarterly reporting deadline that is at least 60 days after publication of that document in the Federal Register). Finally, if we took no action after proposing to revise the 2026 cellulosic biofuel standard, the 2026 compliance deadline would be December 1, 2027 (i.e., the next quarterly reporting deadline that is 12 months after the date of publication of the proposed rule).

This approach will provide regulatory certainty for obligated parties by clearly establishing future compliance deadlines when we propose to change a previously established RFS standard, thereby preventing unnecessary burden on obligated parties to prepare, submit, and then possibly retract and revise compliance reports for deadlines that were later extended. This approach is consistent with our prior rules extending RFS compliance reporting deadlines in different factual

circumstances \362\ and with D.C. Circuit's decisions on this issue.\363\

\362\ 86 FR 17073 (April 1, 2021); 87 FR 5696 (February 2, 2022).

\363\ Wynnewood Refining Co., LLC, et al. v. EPA, 77 F.4th 767, 779 (D.C. Cir. 2023) (“Thus, rather than task EPA with overseeing a fixed compliance schedule, the Act gives EPA flexibility to craft and adjust a compliance regime in service of the Act's core mandate: to ensure the Act's annual renewable fuel volumes are met.”). See also ACE, 864 F.3d at 718-21; Monroe Energy, LLC v. EPA, 750 F.3d 909, 919-20 (D.C. Cir. 2014); Nat'l Petrochemical & Refiners Ass'n v. EPA, 630 F.3d 145, 154-58) (D.C. Cir. 2010).

We are finalizing revisions to align the testing frequency of pipeline-specified components for RNG with the reporting frequency for those pipeline specification components. Previously, RNG producers needed to annually sample and test their RNG to demonstrate that the RNG production facility was producing RNG that met applicable pipeline specifications,\365\ and they needed to submit these results as part of their three-year registration updates.\366\ Stakeholders have highlighted the disconnect between the annual testing requirement and the three-year reporting requirement. Since we only collect this information as part of the three-year engineering review update, we believe it appropriate to only require sampling and testing of RNG once every three years, rather than each year, and are revising 40 CFR 80.110(f)(2)(iii) to this end. We are further clarifying that such sampling and testing is required beginning with three-year engineering review updates submitted on or after January 1, 2027.

\365\ 40 CFR 80.110(f)(2)(iii).

\366\ 40 CFR 80.135(d)(6).

We are also finalizing clarifications to the regulations to reinforce that we may approve alternative test methods for testing components of RNG and that we may exempt the testing of a component that is not required under the RNG producer's applicable pipeline specifications. Specifically, we are revising 40 CFR 80.135(d)(6), which contains the information related to RNG quality that RNG producers must provide (including certificates of analysis for RNG components), to allow alternatives to the test methods for individual RNG components that are specified at 40 CFR 80.155(b). We will assess alternative test methods based on whether the requested alternative test method provides results that are reasonably accurate to the results provided by the method specified at 40 CFR 80.155(b). While under 40 CFR 80.135(d)(6)(v) RNG producers can already request alternative methods and exemption from non-specified parameters, we believe that adding further clarification will help alleviate stakeholder confusion concerning the sampling and testing requirements for RNG.

In order to streamline the alternative measurement protocol approval and registration acceptance process, we are finalizing the removal of the requirement that biogas and RNG production facilities must demonstrate that their facility is incapable of using certain specified meters in order to receive an alternative measurement protocol. After promulgation of the biogas regulatory reform provisions in the Set 1 Rule, we have received dozens of alternative measurement protocol submissions and issued guidance for the application of the criterion that a facility demonstrate that it is incapable of using the specified meters.\367\ We have determined that many of these meters are as accurate and precise as those specified in the regulations, and have also received a number of registration submissions for facilities that have demonstrated the appropriateness of using such meters.\368\ Based on our review of the alternative measurement protocol and registration submissions and the new information we have obtained in the course of this review, we believe that the first criterion whereby a facility must demonstrate that they cannot use the specified meters is not necessary to ensure the accurate and precise measurement of biogas and RNG under the RFS program.\369\ We are also removing the associated requirement that biogas producers and RNG producers demonstrate at registration that they are unable to use the meters specified.\370\

\367\ EPA, “Biogas Regulatory Reform Rule Criteria for Qualifying for an Alternative Measurement Protocol Guidance,” EPA- 420-B-24-014, March 2024.

\368\ A list of approved alternative measurement protocols can be found at: https://www.epa.gov/fuels-registration-reporting-and-compliance-help/alternative-measurement-protocols-biogas-and-0.

\369\ 40 CFR 80.155(a)(3)(i).

\370\ 40 CFR 80.135(c)(3)(iii)(A) and (d)(3)(iii)(A).

Finally, we note that due to the numerous changes to the provisions of 40 CFR 80.155(a) in this action, we are restructuring 40 CFR 80.155(a) to ensure that the measurement requirements for biogas, treated biogas, RNG, and renewable CNG/LNG are clearly enumerated. 2. Other Amendments

We are finalizing clarifications to the provisions surrounding the annual attest engagement procedures for biogas producers, RNG producers, and RNG RIN separators at 40 CFR 80.165. These changes clarify that annual attest engagements are only required for parties that engage in activities regulated under biogas regulatory reform in a given compliance year (e.g., an RNG RIN separator only needs to obtain an annual attest engagement if they separate RNG RINs in a compliance year).

We are also clarifying that any party transferring RINs assigned to a volume of RNG is deemed to also be transferring a corresponding volume of RNG for the purposes of 40 CFR part 80 (i.e., the RFS program). The original language in 40 CFR 80.125(c)(3) led to confusion among stakeholders as to whether physical volumes of RNG were required to be exchanged when transferring assigned RNG RINs. We are replacing this language with text that makes clear that when a party transfers title of an assigned RNG RIN to another party, they are deemed to have also transferred a corresponding volume of RNG to the transferee. We are also clarifying under 40 CFR 80.1460(a)(4) that, while it need not be the same volume of RNG used for RIN generation, the transferee taking title to the assigned RNG RINs must also acquire a corresponding volume of RNG.

We are clarifying that all biogas production facilities registered under the previous biogas provisions (i.e., registered under 40 CFR 80.1450(b) to generate RINs under 40 CFR 80.1426(f)(10) or (11)) do not need updated engineering reviews as part of registering for the new biogas provisions. In the Set 1 Rule, we intended to allow all previously

registered biogas production facilities that did not undergo changes as a result of the new biogas provisions to rely on their existing engineering reviews until their next three-year engineering review is due. However, after promulgation of the new biogas provisions, stakeholders noted that the language in the regulations appears to limit this allowance to only those biogas production facilities in a biogas closed distribution system. Therefore, we are revising 40 CFR 80.135(b)(2)(ii) to make it clear that all previously registered biogas production facilities can use their existing engineering review until the next one is due. We note, however, that if changes to the facility are needed that would otherwise require a new engineering review, the new engineering review must be submitted regardless of this flexibility.

We are also making two changes to the registration requirements for RNG RIN separators under 40 CFR 80.135(f). First, we are requiring that, as part of the information submitted at registration, RNG RIN separators must provide the location on the natural gas commercial pipeline system where the RNG is withdrawn, which is information we already require to be reported in periodic reports under 40 CFR 80.140(e)(1). In addition, as part of the forms and procedures established for those reports, we require that the RNG RIN separator include an EPA-issued facility registration system identification (FRS ID) number. While most withdrawal points have previously assigned FRS ID numbers, some do not. Due to how the EPA's registration system is designed, the only way to obtain those new FRS ID numbers is at the point of registration. Therefore, to aid in the timely submittal of reports, we are clarifying that RNG RIN separators must supply the withdrawal locations at registration.

Second, we are removing the limitation at 40 CFR 80.115(b) that a CNG/LNG dispensing location may only be part of one RNG RIN separator's registration at a time. Based on our experience implementing the program, it is difficult for parties to know which RNG RIN separator has registered for a particular CNG/LNG dispensing location. Under the previous framework, there was a perverse incentive for an RNG RIN separator to register for a CNG/LNG dispensing location in order to block another party from registering that location and prevent that party from separating RNG RINs for transportation fuel dispensed at that location--even though the registering party does not maintain an actual relationship to that location. Removing this restriction will allow a dispensing location to be in multiple parties' registrations, thereby avoiding the situation where one party that does not intend to actually dispense renewable CNG/LNG can block another party that does intend to dispense renewable CNG/LNG from separating RINs at that location. However, we are maintaining the limitation at 40 CFR 80.125(d)(2)(v) that only one party may actually separate RINs for a given CNG/LNG dispensing location during a calendar month. We continue to believe that this restriction is necessary to preclude double counting of RINs because it is the limitation that only one party can separate RINs for a volume dispensed at a station during a given month that avoids double-counting, not whether multiple parties reflect that station in their registration information on file with the EPA.

On June 20, 2025, the D.C. Circuit issued an opinion in CBD, a challenge by multiple petitioners to the Set 1 Rule. The majority opinion held that the EPA had reasonably considered and balanced the statutory factors to determine the required volumes of renewable fuel, with one exception concerning the consideration of climate change impacts.

CAA section 211(o)(2)(B)(ii) states that the basis for setting applicable renewable fuel volumes after 2022 under the RFS program must include, among other things, “an analysis of . . . the impact of the production and use of renewable fuels on the environment, including on . . . climate change.” Accordingly, we conducted an analysis of the potential climate change impacts of the 2023-2025 standards finalized under the Set 1 Rule. Our climate change analysis for the Set 1 Rule relied on two distinct and sequential analytical steps:

1. We conducted a broad review of lifecycle GHG emissions analyses published in peer reviewed literature and government reports for biofuels affected by the RVO standards and for the fossil fuels that those biofuels are intended to displace.\371\ This review produced ranges of published lifecycle GHG emissions estimates for each fuel type.

\371\ Studies identified and associated ranges of lifecycle GHG emissions estimates for each fuel pathway are discussed in Set 1 RIA Chapters 4.2.2.2 through 4.2.2.12 and summarized in Set 1 RIA Chapter 4.2.2.13.

2. We used a subset of the studies identified in the literature review described above to construct two scenarios illustrating a range of potential monetized GHG emissions impacts associated with the RVO standards.\372\

\372\ Ranges of lifecycle GHG emissions estimates used for monetization of potential impacts of the Set 1 volume standards and monetized impacts estimates are presented, respectively, in Set 1 RIA Chapters 4.2.3 and 4.2.4.

In CBD, the D.C. Circuit noted that, in general, the EPA used the high- and low-end estimates of GHG emissions to construct the best- and worst-case scenarios of monetized GHG emissions

impacts. However, the Court also stated that the EPA took a different approach for the category of biofuels produced from crops; specifically, that the Agency relied on just a subset of studies that did not represent the full range of GHG emissions when monetizing the impacts of crop-based biofuels. The Court then held that the EPA had failed to articulate a rational explanation for limiting the calculation of monetized impacts for crop-based biofuels to only a subset of the LCA studies identified in the EPA's literature review. The Court stated that “EPA's unexplained decision to generally rely on [ranges of GHG emissions estimates from credible publications] for every other fuel category and to disregard them for crop-based renewable fuels in favor of ranges derived from its dated 2010 study was arbitrary and capricious.” \373\ The Court raised concerns with the EPA's justification for relying on the EPA's 2010 analyses of crop- based fuels in the monetization of GHG emissions impacts and remanded these issues back to the EPA for further explanation.\374\ We intend the discussion below to fulfill our obligation to provide further explanation in response to this remand.

\373\ CBD at 173.

\374\ Analyses of crop-based fuels conducted for the RFS2 Rule are discussed in Section 2.6.1 of the RFS2 Rule RIA (EPA, “RFS2 Regulatory Impact Analysis,” EPA-420-R-10-006, February 2010). Annual estimates used in the monetization calculation were included in the docket for the RFS2 Rule (EPA-HQ-OAR-2005-0161).

First, the Court noted that the EPA had made conflicting statements in the Agency's justification for why it relied on only the 2010 analyses for crop-based fuels, as opposed to the full range of GHG emissions estimates from the literature. The Court stated that the EPA had explained that the 2010 analyses provided the only estimates of GHG emissions reported on an annual basis.\375\ However, the Court pointed out that the EPA had also stated that “[t]he majority of the land use change GHG estimates in the literature--i.e., not all of them--do not report an annual stream [of GHG emissions impacts].” \376\ Thus, the Court understood the EPA to have belied its assertion that “only” the 2010 analyses were a sufficient basis for monetizing the GHG emissions impacts of crop-based biofuels. That is, it appears the Court believed there were additional studies the Agency could have relied on for this purpose.

\375\ Annualized GHG emissions estimates were necessary to monetize the impacts of those emissions under the guidance that was in place at the time of the Set 1 rulemaking. The methodology used to monetize estimated GHG emissions impacts in the Set 1 Rule was based on the guidance provided by the February 2021 Technical Support Document: Social Cost of Carbon, Methane, and Nitrous Oxide Interim Estimates under Executive Order 13990, available to the docket in the Set 1 Rule (EPA-HQ-OAR-2021-0427-0339). That guidance provided factors expressed as dollars-per-ton of emissions in each individual year. Thus, to appropriately use the guidance on monetizing emissions impacts, it was necessary for emissions estimates to be projected for each individual year being assessed.

\376\ CBD, 141 F.4th at 174.

The EPA is clarifying here that its statement in the Set 1 RIA that “[t]he majority of the land use change GHG estimates in the literature do not report an annual stream” meant that all the land use change GHG estimates in the literature except EPA's 2010 analyses did not report annual streams of emissions. That is, for the crop-based fuels assessed in the Set 1 RIA--corn ethanol and soy biodiesel--the EPA's 2010 analyses were the only studies within the literature review which provided emissions estimates that were suitable for estimating monetized emissions impacts. No other analyses were identified in the literature review that the EPA could have used to estimate annual streams of emissions impacts.

Second, the Court stated that the EPA justified using only the Agency's 2010 analyses of crop-based fuels in the monetized impacts calculation by arguing that the full range of estimates in the literature systematically overestimates GHG emissions from land use changes. The Court then noted that “that assertion of systemic skew is contradicted by EPA's own figures showing that GHG emissions estimates drawn from the literature review were effectively identical to those included in the 2010 study for all crop-based renewable fuel--except corn-based ethanol.” \377\

\377\ CBD, 141 F.4th at 174.

We are clarifying and reinforcing here that our sole reliance on the 2010 analyses to monetize the GHG emissions impacts of crop-based fuels was because these were the only studies available that were suitable for such a calculation for the reason discussed above; the only studies within the literature review with annual emissions estimates were our 2010 analyses. We did not argue in the Set 1 Rule that estimates identified in the literature review systematically overestimated emissions from land use change, nor would we agree with such a statement in general. To the contrary, the Set 1 RIA explicitly states that the EPA did not adjudicate relative strengths or appropriateness of the various studies and that the literature review was designed to be inclusive of all published comparable estimates.\378\

\378\ See Set 1 RIA at 125 (June 2023, EPA-420-R-23-015): “Given that all LCA studies and models have particular strengths and weaknesses, as well as uncertainties and limitations, our goal for this compilation of literatures estimates is to consider the ranges of published estimates, not to adjudicate which particular studies, estimates or assumptions are most appropriate . . . Our review is intentionally broad and inclusive, and is informed by our experience conducting LCA evaluations of transportation fuels for the RFS program.”

As noted by the Court, the range of corn ethanol emissions estimates identified in the Set 1 Rule literature review (38 to 116 gCO2e/MJ) was wider than the range of emissions estimates of the studies used in the monetized impacts calculation (49 to 91 gCO2e/MJ). Relatedly, the Court raised concerns that this “unexplained discrepancy is particularly problematic for EPA because [corn ethanol] plays an outsized role in the program overall. Corn- based ethanol is by volume the largest category of renewable fuel produced in the United States--and it drives the largest aggregate portion of GHG emissions attributable to renewable fuels. If EPA improperly relied on a lower high-end emission estimate for corn-based ethanol, it lacks support for its climate conclusion that `on average [corn-based ethanol] provides some GHG reduction in comparison to gasoline.' ” \379\

\379\ CBD, 141 F.4th at 174.

As explained above, we considered all available GHG emissions estimates identified in the literature that were suitable for the monetized impacts calculation. The only studies of crop-based fuels that met these criteria were the EPA's 2010 analyses of those fuels. We also note that it is not necessarily the case that using a larger range of emissions estimates (higher and lower) would have resulted in higher and lower monetized GHG emissions impacts. Due to complexities in the timing and relative magnitude of GHG emissions associated with crop- based biofuels (e.g., there may be large pulses of emissions early in the time period analyzed followed by smaller amounts of emissions, or even negative emissions, later on in the time period analyzed), monetized impacts do not necessarily scale linearly with emissions. This is why annualized estimates are needed to monetize emissions--an annual average or net emissions estimate alone does not provide the necessary timing and magnitude information required for monetization. Additionally, while corn ethanol does represent the largest category of biofuel generating credits under the RFS program, it represented only 15 percent of the difference in total biofuel use associated with the fuel volumes that we modeled to be

attributable to the Set 1 rule, relative to a scenario in which there were no RFS standards for 2023, 2024, and 2025.\380\ Thus, while it is not possible to accurately monetize the impacts of the full range of GHG emissions estimates from the full literature review, any discrepancy is limited to a small minority (15 percent by energy content) of the total volumes of fuels assessed.

\380\ The impact on corn ethanol consumption volumes attributable to the RFS program is discussed in Set 1 RIA Chapters 2.1.1 and 3.2.

The RFS regulations specify an “aggregate compliance” approach for demonstrating that planted crops and crop residue from the U.S. comply with the “renewable biomass” requirements that address lands from which qualifying feedstocks may be harvested.\381\ In the RFS2 Rule, we established a baseline number of acres for U.S. agricultural land in 2007 (the year of EISA's enactment) and determined that as long as this baseline number of acres is not exceeded, it is unlikely, based on our assessment of historical trends and economic considerations, that new land outside of the 2007 baseline is being devoted to crop production for renewable fuel production. The regulations specify, therefore, that renewable fuel producers using planted crops or crop residue from the U.S. as feedstock in renewable fuel production need not undertake individual recordkeeping and reporting related to documenting that their feedstocks come from qualifying lands, unless the EPA determines through one of its annual evaluations that the 2007 baseline acreage of 402 million acres of agricultural land has been exceeded. The RFS regulations require the EPA to make an annual finding concerning whether the 2007 baseline amount of U.S. agricultural land has been exceeded in a given year. If the baseline is found to have been exceeded, then producers using U.S. planted crops and crop residue as feedstocks for renewable fuel production would be required to comply with individual recordkeeping and reporting requirements to verify that their feedstocks are renewable biomass.

\381\ 40 CFR 80.1454(g). We established the “aggregate compliance” approach in the 2010 RFS2 rule and has applied it for the U.S. in annual RFS rulemakings since then. 75 FR 14701-04 (March 26, 2010). In this final rule, we have not reexamined or reopened this policy, including the regulations at 40 CFR 80.1454(g) and 80.1457. Similarly, as further explained below, we have applied this approach for Canada since our approval of Canada's petition to use aggregate compliance in 2011. In this final rule, we have also not reexamined or reopened our decision on that petition. Any comments we received on these issues are beyond the scope of this rulemaking.

USDA provided the EPA with data from the discontinued Grassland Reserve Program (GRP) and Wetlands Reserve Program (WRP) as well as the Agricultural Land Easements (ACEP-ALE) and the Wetlands Reserve Easements (ACEP-WRE) programs. Based on data from reduced cropland based on historic programs, WRE and GRP, estimated cropland reached approximately 372.4 million acres in 2024 and thus did not exceed the 2007 baseline acreage of 402 million acres.\382\ We will continue to monitor total agricultural land annually to determine if national agricultural land acreage increases above this 2007 national aggregate baseline, as specified in the RFS2 Rule.\383\

\382\ For additional analysis and the underlying USDA data, see “Assessment of Domestic Aggregate Compliance Approach 2024,” available in the docket for this action.

\383\ 75 FR 14701 (March 26, 2010).

The information collection activities in this rule have been submitted for approval to the Office of Management and Budget (OMB) under the PRA. The Information Collection Request (ICR) document that the EPA prepared has been assigned EPA ICR number 7804.02, OMB Control Number 2060-0767. You can find a copy of the ICR in the docket for this rule, and it is briefly summarized here. The information collection requirements are not enforceable until OMB approves them.

The volume standards and associated percentage standards for 2026 and 2027 do not add to the burdens already estimated under existing, approved ICRs for the RFS program. This final rule creates reporting for RIN generators to identify a generation protocol code. We anticipate the increase in burden related to this code to be very small because the parties already provide reports for the RFS program, generally. General recordkeeping and reporting for the RFS

program is contained in the Renewable Fuel Standard program ICR, OMB Control Number 2060-0725 (extended pending OMB decision).

Respondents/affected entities: Renewable fuel producers, obligated parties, RIN owners, third party auditors (attest engagements), QAP auditors.

Respondent's obligation to respond: Mandatory, under 40 CFR part 80.

Estimated number of respondents: 3,689.

Frequency of response: Quarterly, annual, on occasion/as needed.

Total estimated burden: 11,483 hours (per year). Burden is defined at 5 CFR 1320.3(b).

Total estimated cost: $24,512 (per year), includes $0 annualized capital or operation & maintenance costs.

An agency may not conduct or sponsor, and a person is not required to respond to, a collection of information unless it displays a currently valid OMB control number. The OMB control numbers for the EPA's regulations in 40 CFR are listed in 40 CFR part 9. When OMB approves this ICR, the Agency will announce that approval in the Federal Register and publish a technical amendment to 40 CFR part 9 to display the OMB control number for the approved information collection activities contained in this final rule.

I certify that this action will not have a significant economic impact on a substantial number of small entities under the RFA.

With respect to the amendments to the RFS regulations, this action makes minor corrections and modifications to those regulations. As such, we do not anticipate that there will be any significant adverse economic impact on directly regulated small entities as a result of these revisions.

The small entities directly regulated by the annual percentage standards associated with the RFS volumes are small refiners that produce gasoline or diesel fuel, which are defined at 13 CFR 121.201. We believe that there are currently 6 refiners (owning 7 refineries) producing gasoline and/or diesel that meet the definition of small entity by having 1,500 employees or fewer. To evaluate the impacts of the 2026 and 2027 volume requirements on small entities, we have conducted a screening analysis to assess whether we should make a finding that this action will not have a significant economic impact on a substantial number of small entities.\388\

\388\ RIA Chapter 11.

This action does not change the compliance flexibilities currently offered to small entities under the RFS program and currently available information shows that the impact on small entities from implementation of this rule will not be significant. We have reviewed and assessed the available information, which shows that obligated parties, in general on a nationwide scale, are able to recover the cost of acquiring the RINs necessary for compliance with the RFS standards through higher sales prices of the petroleum products they sell than would be expected in the absence of the RFS program.\389\ This is true whether they acquire RINs by purchasing renewable fuels with attached RINs or purchasing separated RINs. The costs of the RFS program are thus being passed on to consumers in a highly competitive marketplace. Even if we were to assume that the cost of acquiring RINs was not recovered by obligated parties, a cost-to-sales ratio test shows that the costs to small entities of the RFS standards established in this action are less than 1 percent of the value of their sales.\390\

\389\ For a further discussion of the ability of obligated parties to recover the cost of RINs, see, e.g., EPA, “Denial of Petitions for Rulemaking to Change the RFS Point of Obligation,” EPA-420-R-17-008, November 2017. See also Gerveni, Maria, Todd Hubbs, Scott H. Irwin, and James H. Stock. “The Biofuels Blueprint: Understanding the U.S. Renewable Fuel Standard,” January 12, 2026. See also CBD at 188, finding that the EPA properly considered RIN cost passthrough in setting the volume requirements in the Set 1 Rule, and acknowledging the “central premise” that “refineries are able to pass RIN costs along to consumers” as generally true.

\390\ A cost-to-sales ratio of 1 percent represents a typical agency threshold for determining the significance of the economic impact on small entities. “Final Guidance for EPA Rulewriters: Regulatory Flexibility Act as amended by the Small Business Regulatory Enforcement Fairness Act,” November 2006.

While the screening analysis described above supports a certification that this rule will not have a significant economic impact on small refiners, we continue to believe that it is more appropriate to consider the 2026 and 2027 standards as a part of our ongoing implementation of the overall RFS program. When considered this way, the impacts of the RFS program as a whole on small entities were addressed in the RFS2 Rule, which was the rule that implemented the entire program as required by EISA 2007.\391\ As such, the Small Business Regulatory Enforcement Fairness Act (SBREFA) panel process that took place prior to the 2010 rule was also for the entire RFS program and looked at impacts on small refiners through the full implementation of the statutory volume targets.

\391\ 75 FR 14670 (March 26, 2010).

For the SBREFA process for the RFS2 Rule, we analyzed the potential impacts of the RFS regulations on small entities. As a part of this analysis, we convened a Small Business Advocacy Review Panel (SBAR Panel, or “the Panel”). During the Panel process, we gathered information and recommendations from Small Entity Representatives (SERs) on how to reduce the impact of the rule on small entities, and those comments are detailed in the Final Panel Report.\392\ We also conducted an analysis of the potential impacts of the RFS program on all refiners, including small refiners, and found that the program would not have a significant economic impact on a substantial number of small entities.\393\ For small refiners subject to the RFS program, the analysis included a cost-to-sales ratio test, a ratio of the estimated annualized compliance costs to the value of sales per company. From this test, we estimated that all directly regulated small entities would have compliance costs that are less than one percent of their sales over the full implementation of the statutory volume targets.\394\ Furthermore, the EPA conducted a section 610 review of the RFS program in May 2020, in which the Agency was required to determine whether the RFS program should continue without change or should be rescinded or amended, consistent with the stated objectives of the CAA, to minimize any significant economic impact of the rule upon a substantial number of small entities.\395\ Following a review of relevant evidence, the EPA did not identify any such potential changes that would reduce burden on a substantial number of small entities in a manner consistent with the stated objectives of the CAA or EISA and concluded that no changes to the RFS program were warranted.\396\

\392\ EPA, “Final Report of the Small Business Advocacy Review Panel on EPA's Planned Proposed Rule Regulation of Fuels and Fuel Additives: Renewable Fuel Standard Program,” September 8, 2008, Docket Item No. EPA-HQ-OAR-2005-0161-0457.

\393\ 75 FR 14858-62 (March 26, 2010).

\394\ 75 FR 14862 (March 26, 2010).

\395\ EPA, “Results of EPA's Section 610 Review of the Final Rule for Regulation of Fuels and Fuel Additives: Changes to Renewable Fuel Standard Program,” May 2020, Docket Item No. EPA-HQ- OAR-2019-0168-0022.

\396\ Id.

We have determined that this final rule will not impose any additional requirements on small entities beyond those already analyzed, since the impacts of this rule are not greater or fundamentally different than those already considered in the analysis for

the RFS2 final rule assuming full implementation of the statutory volume targets. While in this action we are establishing volumes through our Set authority rather than reducing the statutory volumes through our waiver authorities (as was the case through 2022), the magnitude of the cellulosic biofuel, advanced biofuel, and total renewable fuel volume requirements established in this action nonetheless remain significantly below the statutory volume targets analyzed in the RFS2 Rule.\397\ Compared to the burden that would be imposed under the volumes that we assessed in the analysis for the RFS2 Rule (i.e., the volumes specified in the CAA), the volume requirements in this rule reduce burden on small entities. Regarding the BBD standard, it is a nested standard within the advanced biofuel category, and as discussed in section III of this preamble, the BBD volume requirements for 2026 and 2027 are below the volume of BBD that is anticipated to be produced and used to satisfy the advanced biofuel and total renewable fuel requirements. In other words, the volume of BBD actually used in 2026 and 2027 will be driven not by the 2026 and 2027 BBD standards, but rather by the 2026 and 2027 advanced biofuel and total renewable fuel standards. The net result of the standards being promulgated in this action is a reduction in burden as compared to implementation of the statutory volume targets assumed in the RFS2 Rule analysis.

\397\ The statutory volume targets analyzed in the RFS2 Rule were 16 billion gallons of cellulosic biofuel, 21 billion gallons of advanced biofuel, and 36 billion gallons of total renewable fuel.

Furthermore, to the degree that small entities may be impacted by this action, these impacts are mitigated by the existing compliance flexibilities in the RFS program that are available to small entities, which we are not changing in this rule. These flexibilities include being able to comply through RIN trading rather than renewable fuel blending, 20 percent RIN rollover allowance (up to 20 percent of an obligated party's RVO can be met using previous-year RINs), and deficit carry-forward (the ability to carry over a deficit from a given year into the following year, provided that the deficit is satisfied together with the next year's RVO). Additionally, as required by CAA section 211(o)(9)(B), the RFS regulations include a hardship relief provision that allows for a small refinery to petition for an extension of its small refinery exemption at any time based on a showing that the refinery is experiencing a “disproportionate economic hardship.” \398\ The RFS regulations provide the same relief to small refiners that are not eligible for small refinery relief.\399\ In the RFS2 Rule, we discussed other potential small entity flexibilities that had been suggested by the SBAR Panel or through comments, but we did not adopt them, in part because we had serious concerns regarding our legal authority to do so.\400\

\398\ 40 CFR 80.1441(e)(2).

\399\ 40 CFR 80.1442(h).

\400\ 75 FR 14858-62 (March 26, 2010).

In sum, this rule will not change the compliance flexibilities currently offered to small entities under the RFS program and available information shows that the impact on small entities from implementation of this rule will not be significant. We have therefore concluded that this action will not have any significant adverse economic impact on directly regulated small entities.