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

There is also a small volume of renewable jet fuel that qualifies as BBD. Renewable jet fuel has qualified as a RIN-generating BBD and advanced biofuel under the RFS program since 2010 and must achieve at least a 50 percent GHG reduction in comparison to petroleum-based fuels. While relatively little renewable jet fuel was produced or imported through 2023 (20 million gallons or less per year) production volumes have been increasing in recent years, reaching approximately 110 million gallons in 2024 and approximately 290 million gallons in 2025.\122\

Tax credits for renewable jet fuel available during 2023 and 2024, often referred to as the “sustainable aviation fuel credit” or “40B credit” (also available as the 6426(k) excise tax credit), may have resulted in increasing volumes of renewable jet fuel produced from existing renewable diesel production facilities. The 45Z credit is available from 2025 through 2029 and, starting in 2026, provides up to $1.00 per gallon of renewable jet fuel, provided the relevant wage and apprenticeship requirements are met by the producer. The 45Z credit may provide continued support for renewable jet fuel production. Renewable jet fuel production from existing renewable diesel facilities, however, would likely result in a decrease in renewable diesel production, with little or no net change in their overall production of RIN-generating fuels.\123\

The vast majority of renewable jet fuel produced through 2025 was produced using the same feedstocks and very similar production technologies as renewable diesel, and in most cases are produced at the same production facilities. For example, Montana Renewables produced both renewable diesel and renewable jet fuel at their Great Falls, Montana facility in 2024,\124\ as did Phillips 66 in their Rodeo, California facility.\125\ Historically,

greater incentives have been available for renewable diesel production than for renewable jet fuel production. This has resulted in most production facilities choosing to maximize renewable diesel production, although based on the production data at the time of this writing this dynamic may be starting to change.

In the near term, we expect that because the vast majority of renewable jet fuel will be produced using the same feedstocks and at the same facilities as renewable diesel any increase in renewable jet fuel production will result in a corresponding decrease in renewable diesel production. We recognize that new technologies are being developed to produce renewable jet fuel from a wider variety of feedstocks, some of which are not suitable for use in the hydrotreating process that dominates renewable diesel production. For example, several companies are developing new technologies intended to produce renewable jet fuel from ethanol or other alcohols, through a technology often referred to as the “alcohol-to-jet” (“ATJ”) process. To date, we have not approved a generally applicable pathway for these fuels, but we have approved a facility-specific pathway for the production of renewable jet fuel from ethanol to generate D4 RINs.\126\ While ATJ has the potential to produce significant volumes of renewable jet fuel in future years, there is a high degree of uncertainty related to the production of these fuels through 2027 as commercial scale production of these fuels has been limited and no RINs have yet been generated for these fuels at the time of this writing. Production of renewable jet fuel using these emerging technologies may not negatively impact renewable diesel production to the extent that they do not compete for feedstocks.

\124\ Montana Renewables, “Products,” https://montanarenewables.com/products.

\125\ Phillips 66, “Rodeo Renewable Energy Complex,” https://www.phillips66.com/rodeo-renewable-energy-complex.

\126\ See, e.g., EPA, “Letter from EPA to LanzaJet, Inc.,” January 12, 2023.

In this action, we have not separately projected growth in renewable jet fuel production. Instead, we are considering any production of renewable jet fuel from hydrotreating lipid feedstocks in our projection of renewable diesel production. We recognize that other renewable jet fuel production technologies and production facilities are being developed and, in some cases, may produce small fuel volumes in the near term. These could enable the future production of renewable jet fuel from new facilities and feedstocks that are not expected to impact renewable diesel production. c. Other Advanced Biofuels

In addition to biodiesel, renewable diesel, and renewable jet fuel, other renewable fuels that qualify as advanced biofuel have been produced and used in the U.S. in the past and are expected to contribute to compliance with applicable RFS volume requirements in the future. These other advanced biofuels include imported sugarcane ethanol, domestically produced advanced ethanol, RNG used in CNG/LNG vehicles not produced from cellulosic biomass, and heating oil, naphtha, and co-processed renewable diesel that does not qualify as BBD.\127\

\127\ Renewable diesel produced through coprocessing vegetable oils or animal fats with petroleum cannot be categorized as BBD but remains advanced biofuel.

These biofuels have been used in much smaller quantities than biodiesel and renewable diesel in the past, and the production volumes of many of these fuels have been highly variable. Some of these “other advanced biofuels” such as naphtha and heating oil are byproducts of the production of other types of renewable fuel. Others, such as co- processed renewable diesel and sugarcane ethanol, are consistently produced or imported at volumes far below their theoretical production capacity. This variability in the technologies used to produce these fuels and their production volumes over time makes projecting the potential production or import volumes in future years challenging.

To determine the Analyzed Volumes of these other advanced biofuels in 2026 and 2027, we used the same general methodology as in the Set 2 proposal and the Set 1 Rule. We projected the supply of these other advanced biofuels using historic data on the supply of these fuels from 2015-2025. Our methodology addresses the historical variability in these categories of advanced biofuel while recognizing that consumption in more recent years is likely to provide a better basis for making future projections than consumption in earlier years. Specifically, we applied a weighting scheme to historical volumes wherein the weighting was higher for more recent years and lower for earlier years. The result of this approach is shown in Table III.A.2.c-1. Details of the derivation of these estimates can be found in RIA Chapter 5.4. As the available data varies significantly from year to year, it does not allow us to identify an upward or downward trend in the historical consumption of these other advanced biofuels. Therefore, we have used the volumes in Table III.A.2.c-1 both 2026 and 2027.

[GRAPHIC] [TIFF OMITTED] TR01AP26.041

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

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

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

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

To develop the Analyzed Volumes of conventional renewable fuel for 2026 and 2027, we focused primarily on projecting volumes of ethanol consumed via motor gasoline use across all gasoline blends with varying concentrations of ethanol (i.e., E10, E15, and E85). We also investigated potential volumes of non-advanced biodiesel and renewable diesel. a. Corn Ethanol

Ethanol made from corn starch has historically been the renewable fuel supplied in the greatest quantities basis in the past and is expected to continue to do so in 2026 and 2027.\128\ Corn starch ethanol is prohibited by CAA section 211(i)(1)(B)(i) from being an advanced biofuel regardless of its lifecycle GHG emissions performance in comparison to gasoline.

\128\ Conventional ethanol from feedstocks other than corn starch have been produced in the past, but at significantly lower volumes. Production of ethanol from grain sorghum reached 125 million gallons in 2019, representing just less than 1 percent of all conventional ethanol in that year; grain sorghum ethanol in 2024 was only 46 million gallons. Waste industrial ethanol and ethanol made from non-cellulosic portions of separated food waste have been produced more sporadically and at even lower volumes. These other sources do not materially affect our assessment of volumes of conventional ethanol that can be produced.

Total domestic corn ethanol production capacity increased dramatically between 2005 and 2010 and increased at a slower rate thereafter. As of late 2025, domestic corn ethanol production capacity exceeded 18 billion gallons.\129\ Actual production of corn ethanol in the U.S. was approximately

16.2 billion gallons in 2024 and is estimated to have reached 16.4 billion gallons in 2025.\130\

\129\ EIA, “Monthly Biofuels Capacity and Feedstocks Update,” November 28, 2025. https://www.eia.gov/biofuels/update.

\130\ EIA, “Monthly Energy Review,” Total Energy, March 2025. https://www.eia.gov/totalenergy/data/monthly/pdf/mer.pdf.

The expected annual rate of future commercial production of corn ethanol will continue to be driven primarily by gasoline demand in 2026 and 2027, as most gasoline is expected to continue to contain 10 percent ethanol during this period. Commercial production of corn ethanol is also a function of exports of ethanol and the demand for E0, E15, and E85. There is evidence that some fuel retailers sell higher volumes of E15 than E10, leveraging lower prices at the pump and marketing higher-level ethanol blends to their customers as a cheaper fuel option with only negligible effects on fuel economy (a 1-2 percent reduction compared to E10). In addition to government incentives, industry-led efforts such as Prime-the-Pump have enjoyed great success in growing markets for higher ethanol gasoline blends by providing technical and financial assistance to fuel retailers.\131\ Acknowledging the potential for growth in these fuel markets, we have incorporated projected growth in opportunities for sales of E15 and E85 blends into our assessment.

\131\ Transportation Energy Institute, “The Case of E15,” February 2018.

Despite this steady growth, there remains excess production capacity of ethanol and corn feedstock in comparison to the ethanol volumes that we estimate will be consumed domestically during 2026 and 2027, given constraints on U.S. ethanol consumption. Thus, as was the case with the Set 1 Rule, we do not expect production capacity to be a limiting factor in determining the Analyzed Volumes.

The total volume of ethanol that can be used--including ethanol produced from corn, grain sorghum, cellulosic biomass, the non- cellulosic portions of separated food waste, and sugarcane--is a function of demand for E10, E15, and E85 ethanol blends most commonly used in the U.S. and for E0. Ethanol concentration across the entire gasoline pool can exceed 10 percent only insofar as the incremental ethanol in E15 and E85 volumes more than offsets the lack of ethanol in E0 volume. As shown in Figure III.A.3.a-1, poolwide ethanol concentration increased dramatically from 2003 through 2010 and has continued to grow more slowly since 2010. As the average ethanol concentration approached and then exceeded 10 percent, the gasoline pool became saturated with E10, with a small, likely stable volume of E0 and small but gradually increasing volumes of E15 and E85. We expect this trend to continue during 2026 and 2027.

Figure III.A.3.a-1: Historical Poolwide Volumetric Ethanol Concentration [GRAPHIC] [TIFF OMITTED] TR01AP26.043

For this action, volume data from USDA's Higher Blends Infrastructure Incentive Program (HBIIP) \132\ and additional volume data acquired directly from six States with high volumes of higher- level ethanol blends (California, Kansas, Iowa, Minnesota, New York, and North Dakota) has enabled a data-driven, bottom-up approach to projecting ethanol volumes into the future that differs from the way these projections were calculated in previous years. More information on this method of projection ethanol concentration can be found in RIA Chapter 7.5.1. We introduced this new methodology in the Set 2 proposal and continue to refine it here. In the Set 1 Rule, we projected ethanol concentration in the national gasoline pool using a least-squares regression model using then-current E15 and E85 fueling station population data.\133\ This was due to lack of data and a subsequent inability to aggregate sales volumes by ethanol volume at the retail fuel station level. Now, greater availability of sales volume data from the aforementioned six States, HBIIP, and industry partners has enabled an updated and simplified methodology for producing the ethanol volume projections in this action.

\132\ USDA, “Higher Blends Infrastructure Incentive Program,” May 2023. https://www.rd.usda.gov/hbiip.

\133\ See “Renewable Fuel Standard (RFS)Program: Standards for 2023-2025 and Other Changes Regulatory Impact Analysis,” EPA-420-R- 23-015, June 2023 (“RFS Set 1 RIA”), Chapter 7.5.1.

Using the average sales of each gasoline-ethanol blend per retail fueling station, as well as updated station populations from DOE's Alternative Fuels Data Center (AFDC) \134\ and the California Air Resources Board (CARB) \135\ for 2021-2024, we produced projections of expected growth in station counts and throughputs out to 2027 for each gasoline-ethanol blend other than E10. In addition to a projection for each blend, E85 projections were expanded in this action relative to the Set 1 Rule. After reviewing the State-specific data, the difference between the E85 market in California compared to five other States (i.e., Kansas, Iowa, Minnesota, New York, and North Dakota) became apparent. Thus, we chose to analyze the California E85 market separately from the other States in order to more accurately project E85 in California versus the rest of the U.S. We then used these projections to estimate the total fuel volume for these gasoline- ethanol blends (E0, E15, and E85) for 2026 and 2027 using the following relation: for gasoline-ethanol blends at each concentration, the total fuel volume consumed in any given year is equal to the product of the number of retail fueling stations offering that blend for sale and the volume of that fuel blend sold at a fueling station (i.e., throughput) on average during that year. Finally, we projected E10 as the remainder of the gasoline pool, after accounting for the Analyzed Volumes of E0, E15, and E85, using the most recent version of EIA's Annual Energy Outlook to project total gasoline demand for 2026 and 2027.\136\

\134\ AFDC, “Historical Alternative Fueling Station Counts.” https://afdc.energy.gov/stations/states.

\135\ CARB, “Annual E85 Volumes,” April 11, 2025.

\136\ EIA, “Annual Energy Outlook 2025,” April 15, 2025 (“AEO2025”). https://www.eia.gov/outlooks/aeo.

Total ethanol consumption is the sum of gasoline (E0) blended with ethanol to create E10, E15, and E85.\137\ The ethanol portion of the projected total consumption for each fuel blend (i.e., total ethanol consumption) is shown in Table III.A.3.a-1. While we project that the ethanol concentration in the gasoline pool will increase in future years, total ethanol consumption is projected to decrease due to decreases in total gasoline consumption in future years.

\137\ See RIA Chapter 7.5.1 for a more comprehensive discussion of the methodology employed to produce the total ethanol consumption projection.

\138\ Less than 15 million gallons total of conventional biodiesel and renewable diesel has been produced domestically from 2014-2025. [GRAPHIC] [TIFF OMITTED] TR01AP26.044

Other than conventional ethanol, the only other conventional renewable fuels that have been used at significant levels in the U.S. in recent years have been conventional biodiesel and renewable diesel. Conventional biodiesel and renewable diesel are produced at facilities grandfathered under 40 CFR 80.1403 because there are no currently valid RIN-generating pathways for their production. Almost all conventional biodiesel and renewable diesel historically used in the U.S. has been imported.\138\ According to EMTS data, the use of conventional biodiesel and renewable diesel did grow marginally in 2024 after a period of very low volume (less than 1 million gallons per year from 2018-2022), though the overall supply remained negligible (less than 0.1 percent of total biofuel supply to the U.S.) and the total supply of conventional biodiesel and renewable diesel in 2025 was once again less than one million gallons. While some sparse generation of D6 RINs for these fuels have been observed in recent years, nearly all these RINs were retired for being designated for use in any application other than transportation fuel and therefore do not represent qualifying fuel under the RFS program. As discussed in RIA Chapter 7.7, there exists much greater potential for domestic production and use of conventional biodiesel and renewable diesel than has actually been supplied in prior years, suggesting the use of these fuels in the U.S. is largely a function of domestic demand for these fuels and the incentives available for conventional biodiesel and renewable diesel in the U.S. relative to other countries. While there exists some potential for growth in 2026 and 2027, we are not including volumes of conventional biodiesel and renewable diesel in our analyses for this final rule. c. Conventional Renewable Fuel Summary

The Analyzed Volumes of conventional renewable fuel represent the volume of these fuels we project would be supplied to the market when considering the incentives that could be available through the RFS program and other State and Federal incentives. Since the supply of ethanol is projected to be limited by the ability for the market to consume ethanol in gasoline blends, the supply of conventional ethanol in 2026 and 2027 can be estimated from the total ethanol

consumption projections from Table III.A.3.a-1 and our projections for other forms of ethanol as discussed earlier in this section. Our projected volumes of ethanol consumption are presented in Table III.A.3.c-1. We do not currently project that non-ethanol conventional renewable fuels will be supplied to the U.S. under the RFS program in 2026 and 2027. [GRAPHIC] [TIFF OMITTED] TR01AP26.045

To estimate the impacts of the Analyzed Volumes, we must identify the appropriate baseline(s). The primary baseline developed for this final rule reflects the use of renewable fuels absent this final rule or the RFS program (i.e., the alternative collection of biofuel volumes by feedstock, production process (where appropriate), and biofuel type that would be anticipated to occur in 2026 and 2027 in the absence of RFS program), and acts as the point of reference for assessing the impacts of this final rule. To this end, we have developed a “No RFS” scenario that we used as the baseline for analytical purposes (hereinafter the “No RFS Baseline”). Many of the same supply-related factors that we used to develop the Analyzed Volumes were also relevant in developing the No RFS Baseline.

We also developed a 2025 baseline that in some cases is more informative in understanding the impacts of the Analyzed Volumes relative to the status quo. 1. No RFS Baseline

Broadly speaking, the RFS program is designed to increase the use of renewable fuels in the transportation sector beyond what would occur in the absence of the program. It is appropriate, therefore, to use a scenario representing what would occur if the RFS program did not continue to exist as the baseline for estimating the costs and impacts of the Analyzed Volumes. Our No RFS Baseline is consistent with the Office of Management and Budget's Circular A-4, which says that the appropriate baseline would normally “be a `no action' baseline: what the world will be like if the proposed rule is not adopted.” \139\

\139\ Office Management and Budget, “Circular A-4,” 68 FR 58366 (October 9, 2003).

Importantly, this No RFS Baseline is not equivalent to a market scenario

wherein no renewable fuels are used at all. Prior to the RFS program, both biodiesel and ethanol were used in the transportation sector, whether due to State or local incentives, tax credits, or a price advantage over conventional petroleum-based gasoline and diesel. This same situation would exist in 2026 and 2027 in the absence of the RFS program. Federal, State, and local tax credits, incentives, and support payments would continue to be in place for these fuels, as well as State programs such as blending mandates and LCFS programs. Furthermore, now that capital investments in renewable fuels have been made and markets have been oriented towards their use, there are strong incentives in place for continuing their use even if the RFS program were to disappear. As a result, it would be improper and inaccurate to attribute all use of renewable fuel in 2026 and 2027 to the applicable standards under the RFS program.

To inform our assessment of the volume of renewable fuels that would be used in the absence of the RFS program for the years 2026 and 2027, we began by analyzing the trends in the economics for renewable fuels blending in prior years. Assessing these trends is important because the economics for blending renewable fuels changes from year to year based on renewable fuel feedstock and petroleum product prices and other factors that affect the relative economics for blending renewable fuels into petroleum-based transportation fuels. A renewable fuel facility investor and the financiers who fund their projects will review the historical (e.g., did they lose money in a previous year), current, and perceived future economics of the renewable fuel market when deciding whether to continue to operate their renewable fuel facilities, and our analysis attempted to account for these factors.

The No RFS Baseline economic analysis for 2026 and 2027 compares the projected renewable fuel cost with the projected cost for the fossil fuel it displaces. The comparison is performed at the point that the renewable fuel is blended with the fossil fuel (generally a fuel terminal) to assess whether the renewable fuel provides an economic advantage to blenders. If the renewable fuel is lower cost than the fossil fuel it displaces, it is assumed that the renewable fuel would be used absent the RFS program (within the constraints described below). The No RFS Baseline economic analysis that we conducted mirrors the fuel cost analysis described in section III.D.4 of this preamble, but there are several differences. The primary difference is that the No RFS Baseline economic analysis was conducted from the fuels industry's perspective, asking whether they would find it economically advantageous to blend renewable fuel into petroleum fuel in the absence of the RFS program. Conversely, the social cost analysis in section III.D.4 of this preamble reflects the overall fuel cost impacts on society at large.\140\ A primary example of a social cost not considered for the No RFS Baseline economic analysis is the fuel economy effect due to the lower energy density of the renewable fuel, as this cost is generally borne by consumers, not the fuels industry. Other ways that the No RFS Baseline economic analysis is different from the social cost analysis include:

\140\ See section III.D.4 of this preamble and RIA Chapter 10 for descriptions of the social cost analysis.

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

We assessed renewable fuel distribution costs to the point where it is blended into petroleum fuel, not all the way to the point of use, which is necessary for estimating the fuel economy cost.\141\

\141\ For several renewable fuels (e.g., ethanol blended as E10, biodiesel, and renewable diesel), the fuel economy cost is paid by the consumer. Because it is the fuels industry (i.e., refiners, terminals, and retailers) that decides whether to blend renewable fuels into petroleum fuels, they are only concerned about the relative cost at the point in which the renewable fuel is blended into the petroleum fuel, not the costs downstream of that blending point.

While we generally do not account for the fuel economy disadvantage of most renewable fuels for the No RFS Baseline economic analysis, the exception is E85 where the lower fuel economy of using E85 is noticeable to vehicle owners such that they demand a lower price to make up for this loss of fuel economy. As a result, retailers must price E85 lower than the primary alternative E10 to account for the lower energy content of E85 and they must consider this in their decisions to blend and sell E85.\142\

\142\ See RIA Chapter 2 for further discussion of this topic.

To estimate the relative cost of a renewable fuel compared to the fossil fuel being displaced, we considered several different cost components (i.e., production cost, distribution cost, any blending cost, retail modification costs) together to reflect the relative cost of each renewable fuel to its respective fossil fuel. We also considered any applicable Federal or State programs, incentives, or subsidies that could reduce the apparent blending cost of the renewable fuel at the terminal, including the 45Z credit. The exact amount of credit under 45Z is more variable and depends on a range of factors. However, generally speaking, the amount of credit that fuel producers are able to claim under 45Z is less than the previous $1 per gallon tax credits that biodiesel and renewable diesel producers were able to claim under 40A and 6426.\143\ In the case of higher-level ethanol blends, the retail cost associated with the equipment or use of compatible materials needed to enable the sale of these newer fuels is assumed to be reduced by 75 percent due to the HBIIP program.

\143\ See RIA Chapter 1 for a further discussion of the 45Z credit.

In addition, there are a number of State programs that create subsidies for biodiesel and renewable diesel, the largest being offered by California and Oregon through their LCFS programs.\144\ We accounted for State and local biodiesel mandates by including their mandated volume regardless of the economics. Several States offer tax credits for blending ethanol at 10 percent. Other States offer tax credits for E85, of which the largest is New York. We are not aware of any State tax credits or subsidies for E15.\145\ To account for the various State assumptions, it was necessary to model the cost of using these biofuels on a State-by-State basis.

\144\ At the time the analysis for the No RFS Baseline was completed, there was insufficient data to project the impacts of LCFS programs in New Mexico on biofuel consumption in these States in the absence of the RFS program.

\145\ In light of the fluid situation with respect to a 1-psi RVP waiver for E15 or actions to remove the 1-psi waiver for E10 in seven Midwestern States, our analysis did not specifically assume either of these potential changes. These assumptions can affect the relative cost of E15; however, adopting these assumptions would not have impacted the overall conclusions with respect to blending E15 in the absence of the RFS program.

For most renewable fuels, the economic analysis provided consistent results, indicating that they are either economical in all years or are not economical in any year. However, this was not true for biodiesel and renewable diesel, where the results varied from year to year. Such swings in the economic attractiveness of biodiesel and renewable diesel confound efforts on the part of investors to project future returns on their investments to determine whether to continue to operate their facilities or shut down. Thus, to smooth out the swings in the economics for using biodiesel and renewable diesel and look at it the way facility operators and their investors would do in the absence of the RFS

program, we made two key assumptions. First, the economics for biodiesel and renewable diesel were modeled starting in 2009 and the trend in their use was made dependent on the relative economics in comparison to petroleum diesel over distinct four-year periods. As a result, the first four-year period modeled the costs over 2009-2012 to estimate the volume of biodiesel and renewable diesel that would be used in 2012 in the absence of the RFS program. Second, the estimated biodiesel and renewable diesel volumes were limited in the analysis to no greater volume than what occurred under the RFS program in any year, since the existence of the RFS program would be expected to create a much greater incentive for using these fuels than if the RFS program was not in place.

We also conducted an analysis for cellulosic biofuels, focusing primarily on renewable CNG/LNG and CKF ethanol. We found that renewable CNG/LNG is more expensive than fossil natural gas and, without targeted incentives and given competing demand in other sectors, would see little transportation use. However, because California, Oregon, and Washington do have State-level biofuels programs that incentivize CNG/ LNG in transportation, we assumed these programs would support some use even without the RFS program. To estimate that future level of use, we analyzed each State's program data and extrapolated trends through 2027. Additionally, CKF ethanol is eligible for additional incentives through programs such as California's LCFS program, so we expect CKF ethanol will continue to be produced at the volumes determined in this rule even in the absence of the RFS program. The No RFS Baseline for 2026 and 2027 is summarized in Table III.B.1-1.\146\ More details on the No RFS Baseline can be found in RIA Chapter 2.

\146\ See RIA Chapter 2 for a more complete description of the No RFS Baseline and its derivation.>

\147\ Since E85 is borderline economical in California in the No RFS Baseline when we do not assume any increase in California's LCFS credit, a likely increase in the LCFS credit under the No RFS Baseline increases the certainty that E85 would be economic. Additionally, we did not consider the possibility that cellulosic ethanol, which receives a larger LCFS credit, could be used to produce E85 and may be more economical than corn ethanol. [GRAPHIC] [TIFF OMITTED] TR01AP26.048

Our analysis shows that conventional ethanol is economical to use in 10 percent blends (E10) without the presence of the RFS program. Conversely, higher-level ethanol blends are only partially economical without the RFS program. E85 is economical in 2026 and 2027 in California; thus, we assumed that E85 would be consumed in California without the RFS program.\147\ Conversely, E15 is not economical without the RFS program due to the relatively low sales volumes per station and high cost associated with the equipment needed to be installed at retail stations, even if these costs are partially subsidized by government funding, and the lack of octane blending value. Some volume of biodiesel is estimated to be blended based on State mandates in the absence of the RFS program, and some additional volume of both biodiesel and renewable diesel is estimated to be economical to use without the RFS program, particularly in California and Oregon due to the LCFS incentives. The volumes of renewable CNG/LNG and imported sugarcane ethanol are projected to be consumed in States with an LCFS program due to the economic support provided by their programs. 2. 2025 Baseline

The applicable volume requirements established for one year under the RFS program do not roll over automatically to the next, nor do the volume requirements that apply in one year become the default volume requirements for the following year in the event that no volume requirements are set for that following year. Nevertheless, the volume requirements established for the previous year represent the most recent set of volume requirements that the market was required to meet and are indicative of current market conditions.

Since the previous year's volume requirements represent the starting point for any adjustments that the market may need to make to meet the next year's volume requirements, they represent another informational baseline for comparison. For this reason, in previous RFS annual standard-setting rulemakings we used previous year's standards as a baseline against which to compare the projected impacts of the volume requirements and are also doing so here in addition to the No RFS Baseline for some of the factors (e.g., the cost of this action).

In the Set 2 proposal, we estimated a 2025 baseline using the analysis performed in the Set 1 Rule. We considered using 2025 partial- year data for the 2025 Baseline in the Set 2 proposal, but we instead continued to rely on the Set 1 Rule analysis. In this final rule, we now have data from EMTS on the actual production and use of renewable fuel in the U.S. in 2025. In this final rule we have revised and updated the 2025 Baseline using this data, such that the 2025 Baseline reflects the actual production and use of biofuels in 2025 rather than the projected volumes from the Set 1 Rule. In some cases (such as the feedstocks used to produce biodiesel and renewable diesel) we have supplemented the data collected by EMTS with other data sources.

Our estimates of the actual use of qualifying biofuels in 2025 are shown in Table III.B.2-1. More details on the 2025 Baseline can be found in RIA Chapter 2.

[GRAPHIC] [TIFF OMITTED] TR01AP26.049

As described in section II.B of this preamble, the statute specifies a number of factors that the EPA must analyze in making a determination of the appropriate volume requirements to establish for years after 2022 (and for BBD, years after 2012).\149\ In this section, we provide a summary of the analysis of a selection of factors, including employment, rural economic development, energy security, climate change, costs, environmental impacts, and various other economic impacts, for the Analyzed Volumes, along with some implications of those analyses. We provide a summary of our consideration of all factors in determining the final volume requirements in section III.E of this preamble.

We received numerous comments on the analyses of statutory factors presented in the proposal. In some cases, we have updated our analyses to incorporate feedback provided by commenters (e.g., climate change, prices of agricultural commodities). Changes in methodology relative to the Set 2 proposal are described in the sections below and in the corresponding RIA Chapters. Other comments not addressed in those sections are addressed in the Response to Comment document in the docket for this rule.

It was not always possible to precisely identify the implications of the analysis of a specific factor for a specific component category of renewable fuel. For instance, while we analyzed the impact of biodiesel and renewable diesel on the cost to consumers of transportation fuel (section III.D.4 of this preamble), biodiesel and renewable diesel can be used to satisfy multiple biofuel requirements (e.g., BBD, advanced biofuel, and total renewable fuel) and this analysis therefore does not apply to a single standard in that regard. Additionally, air quality impacts are driven primarily by biofuel type (e.g., ethanol, biodiesel) rather than by biofuel category (e.g., advanced biofuel,

cellulosic biofuel), and energy security impacts are driven by the amount of fossil fuel energy displaced. In these cases, we have analyzed one or more of the standards collectively rather than individually.

Moreover, except for CAA section 211(o)(2)(ii)(III), the statute does not require that the requisite analyses be specific to each category of renewable fuel. Rather, the statute directs the EPA to analyze certain factors, without specifying how that analysis must be conducted. In addition, the statute directs the EPA to analyze the “program” and the impacts of “renewable fuels” generally, further indicating that Congress intended to provide flexibility regarding how and at what level of specificity to analyze the statutory factors.\150\

\150\ See CBD, 141 F.4th at 171 (“The text of the CAA does not require EPA to monetize or otherwise quantify all of the factors it must consider[.]”).

In this section, we summarize our estimates of the impacts (relative to the No RFS Baseline) of the Analyzed Volumes on economy- wide employment and rural economic development. These estimates include direct, indirect, and induced impacts for both job creation and rural economic development and are presented in Table III.D.1-1. More details on these analyses can be found in RIA Chapter 9.

We apply two analytical approaches common in the literature--the “rule-of-thumb” approach and, where feasible, input-output (IO) modeling. The rule-of-thumb approach uses employment and economic development impact estimates from previous studies, expressed in jobs and GDP per unit of biofuel production, and multiplies these estimated impacts by the Analyzed Volumes to arrive at employment and GDP estimates. This approach is taken to produce estimates for the impacts of the quantities of ethanol, BBD, and RNG in the Analyzed Volumes relative to the No RFS Baseline.

The IO modeling approach relies on the use of a methodology developed specifically for analysis of dry mill corn ethanol. Using the results from this IO analysis we have developed ranges of potential impacts from the projected corn ethanol volumes based on uncertainty regarding how the volumes will be provided. For example, volumes of corn ethanol associated with new production capacity would also be associated with some number of temporary construction jobs, while expanded capacity utilization at existing dry mill corn ethanol facilities would not. These ranges of potential impacts are summarized in tables in RIA Chapter 9 along with detailed explanations of the associated methodology. Similar IO modeling methods were not readily available to estimate impacts from other types of ethanol, BBD or RNG, so we have not attempted to do so.

We estimate that all three categories of renewable fuel we analyzed--ethanol, BBD, and RNG--are associated with increases in jobs to varying degrees. BBD is projected to have the highest job creation impact overall, primarily due to substantially higher projected fuel volume increases relative to the No RFS Baseline. In terms of rural employment specifically, ethanol has the highest direct and total effects per million gallons of ethanol equivalent. Relative to the No RFS Baseline and accounting for direct, indirect, and induced effects, BBD is projected to have the highest impact on agricultural employment, again primarily due to substantially higher projected fuel volume increases due to the 2026 and 2027 standards relative to the No RFS Baseline.

We also estimate that ethanol, BBD, and RNG are all associated with increased rural economic development, again to varying degrees. Since renewable fuels rely on agricultural feedstocks, we use the GDP impacts associated with agricultural feedstocks to infer the effects on rural economic development. We estimate that BBD and ethanol have higher impacts per million gallons of ethanol equivalent on rural economic development than does RNG. Relative to the No RFS Baseline and accounting for direct, indirect, and induced effects, BBD is projected to have the highest impact on rural economic development, again primarily due to substantially higher projected fuel volume increases due to the 2026 and 2027 standards relative to the No RFS Baseline.

Table III.D.1-1 summarizes the estimated economy-wide employment impacts, expressed in terms of full-time equivalent jobs, and rural economic development impacts, expressed in terms of rural GDP in 2024$ associated with the Analyzed Volumes of ethanol, BBD, and RNG.\151\

\151\ More detail on our estimates of job creation and rural economic development, including a discussion of the limitations of these estimates, can be found in RIA Chapter 9.1. [GRAPHIC] [TIFF OMITTED] TR01AP26.052

Our analysis shows that the Analyzed Volumes will have a positive impact on energy security by reducing U.S. reliance on foreign sources of energy. Monetized energy security impacts of the Analyzed Volumes are summarized in Table III.D.2-1. Energy security and methods of quantifying energy security impacts are discussed further below and in RIA Chapter 6.

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Changes in the required volumes of renewable fuels under the RFS program can significantly impact: (1) the U.S.'s trade in crude oil and petroleum products, affecting both imports and exports--collectively referred to as “net petroleum imports” and (2) the financial and energy security risks associated with this oil trade. These changes directly influence U.S. national energy security. Similarly, the Analyzed Volumes may alter imports and exports of renewable fuels and renewable fuel feedstocks, which may also affect U.S. energy security.

Energy security is defined as the continued availability of energy sources at an acceptable price.\152\ Achieving the separate but related goal of energy independence involves reducing reliance on foreign energy imports to minimize their impact on economic, military, or foreign policies.\153\ A longstanding goal of U.S. energy policy has been to decrease oil imports, thereby reducing dependency on foreign oil suppliers.

\152\ IEA, “Energy Security.” https://www.iea.org/topics/energy-security.

\153\ Greene, David L. “Measuring Energy Security: Can the United States Achieve Oil Independence?” Energy Policy 38, no. 4 (March 7, 2009): 1614-21. https://doi.org/10.1016/j.enpol.2009.01.041.

Since the beginning of the RFS2 regulatory program in 2010, the U.S. has experienced significant changes in its exposure to the global oil market, with implications for energy security. In 2010, U.S. net petroleum imports were approximately 9.4 million barrels a day (MMBD).\154\ Since then, increased domestic production of shale oil and renewable fuels have shifted the U.S. from a large net petroleum importer to a net exporter,\155\ with net exports reaching 2.4 MMBD in 2024.\156\ EIA projects continued growth in U.S. net exports of petroleum, reaching 3.3-3.8 MMBD by 2026 and 2027. Despite this shift, substantial imports of renewable fuels and feedstocks have been used to meet RFS obligations in recent years. This trend has implications for the U.S.'s energy security and independence.

\154\ EIA, “Oil imports and exports,” Oil and petroleum products explained, January 19, 2024. https://www.eia.gov/energyexplained/oil-and-petroleum-products/imports-and-exports.php.

\155\ Id.

\156\ EIA, AEO2025, Table 11--Petroleum and Other Liquids Supply and Disposition.

Even with the long-term shift in U.S.'s net petroleum trade position, energy security risks persist due to three main factors. First, even as a net exporter, the U.S. economy can be adversely affected by energy price shocks. Both crude oil and renewable fuels are globally traded commodities, making global price and supply shocks an ongoing concern even from a relatively comfortable national net trade position. Second, many U.S. refineries depend heavily on imported heavy crude oil, making them susceptible to international supply disruptions. In 2024, gross petroleum imports were about 8.4 MMBD.\157\ Likewise, the U.S. has experienced period of elevated imports of BBD feedstocks in recent years (see Figure III.A.2.b.ii-2). Third, oil exporters with a large share of global production can alter global oil prices through the Organization of Petroleum Exporting Countries (OPEC) by affecting oil supply relative to demand. These factors contribute to the vulnerability of the U.S. economy to fuel supply shocks and price spikes, despite EIA's projections of continued net petroleum exports through 2026 and 2027.

\157\ EIA, “U.S. Supply and Disposition,” Petroleum & Other Liquids, May 30, 2025. https://www.eia.gov/dnav/pet/pet_sum_snd_d_nus_mbblpd_a_cur.htm.

The EPA collaborates with Oak Ridge National Laboratory (ORNL) to assess the energy security implications of reduced net petroleum imports and exposure to global oil markets. ORNL has developed methodologies to evaluate social costs and energy security impacts of oil imports. This approach estimates two distinct impacts of importing petroleum in addition to the purchase price of petroleum itself: (1) the risk of reductions in U.S. economic output and disruption to the U.S. economy caused by sudden disruptions in the supply of imported oil to the U.S. (i.e., macroeconomic disruption/adjustment costs); and (2) the impacts that a change in U.S. net oil imports have on overall U.S. oil demand and subsequent changes in the world oil price (i.e., the “demand” or “monopsony” impacts).\158\ Consistent with previous RFS rulemakings, we consider demand impacts to be transfer payments and exclude them from estimated monetized social benefits of the Analyzed Volumes.\159\ However, the economy-wide benefits of avoiding macroeconomic disruption costs (estimated using ORNL's methodology) are societal benefits, which we label “macroeconomic oil security premiums.” For this final rule, the EPA and ORNL have developed estimates of these premiums based upon recent energy security literature and oil price projections and energy market and economic trends from AEO2025.\160\

\158\ Monopsony impacts stem from changes in the demand for imported oil, which changes the price of all imported oil.

\159\ See RIA Chapter 6.4.2 for more discussion of our assessment of monopsony impacts of this action. Also, for a discussion of monopsony oil security premiums, see, e.g., EPA, “Revised 2023 and Later Model Year Light Duty Vehicle GHG Emissions Standards: Regulatory Impact Analysis,” EPA-420-R-21-028, December 2021, Section 3.2.5.

\160\ See RIA Chapter 6.4.2 for how the macroeconomic oil security premiums have been updated based upon a review of recent energy security literature on this topic.

To calculate the energy security benefits of the Analyzed Volumes, ORNL's macroeconomic oil security premiums are combined with estimates of annual reductions in net U.S. petroleum imports due to renewable fuel volume changes.\161\ Table III.D.2-1 presents the macroeconomic oil security premiums and the total energy security benefits for the Analyzed Volumes. The average macroeconomic oil security premiums are estimated to be $3.69 per barrel in 2026 to $3.67 per barrel in 2027. Because there is uncertainty associated with these estimates, we also present confidence intervals in the table. In terms of cents per gallon, the macroeconomic oil security premiums are estimated to be 0.088[cent] per gallon in 2026 and 0.087[cent] per gallon in 2027.

\161\ See RIA Chapter 6.4.1 for a discussion of the methodology used to estimate changes in U.S. annual net petroleum imports from the Analyzed Volumes.

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CAA section 211(o)(2)(B)(ii) provides that when determining the applicable volumes of each renewable fuel category after the year 2022, the EPA shall include as part of its review “an analysis of . . . the impact of the production and use of renewable fuels on the environment, including on . . . climate change.” The statute does not define the term “climate change” and expressly provides that regulations issued pursuant to the RFS provisions shall not impact the regulatory status of any GHG under any other provision of the CAA.\162\

\162\ CAA section 211(o)(12).

Although the uncertainty inherent in our analysis does not allow us to determine whether these regulations would have a material impact on climate change, the EPA is providing the GHG emission amounts for the Analyzed Volumes for 2026 and 2027. As such, we have undertaken an assessment of the GHG emission changes of the Analyzed Volumes for 2026 and 2027 relative to the No RFS Baseline. Several commenters stated that we should consider estimates based on the Greenhouse gases, Regulated Emissions, and Energy use in Technologies (GREET) and Global Trade Analysis Project-Biofuels (GTAP-BIO) models in the climate change analysis. We agree; our climate change analysis of the Analyzed Volumes includes additional estimates based on these models, alongside estimates based on the Global Change Analysis Model (GCAM) and Global Biosphere Management Model (GLOBIOM) models presented in the proposal. More details on this analysis can be found in RIA Chapter 5.

Our analysis of the effects of the Analyzed Volumes on climate change includes three estimates of potential changes in GHG emissions. In terms of average annual CO2e emissions through 2055, these three estimates are: (1) a 1 million metric ton increase; (2) a 17 million metric ton decrease; and (3) a 31 million metric ton decrease. Two of these estimates show the potential for reductions in GHG emissions relative to the assessed No RFS Baseline, while one estimate shows a comparatively much smaller increase in GHG emissions. As illustrated by the wide range of estimates, modeling of GHG emissions impacts of biofuel use is inherently uncertain, especially over the multiple decade-long analytical timeframe used for these estimates. Additionally, while we consider the impacts on climate change as required by statute, the range of potential GHG emission reductions, when coupled with additional uncertainties involved in commonly used climate change end points, makes it difficult to quantify potential climate change impacts such as changes in global temperature. However, our assessment of the Analyzed Volumes shows the potential for net GHG emissions reductions in the majority of our estimates over that time period but does not conclude such reductions are likely to result in a material difference in commonly evaluated “climate endpoints.” In past rulemakings for the RFS program, the EPA has considered this factor by using “lifecycle GHG emissions estimates as a proxy for climate change impacts.” \163\ The analytical approach we are taking in this final rule is similar in that we are providing GHG emissions as a proxy; this factor is one of many Congress instructed the EPA to consider when setting volumes, and we have considered it in a transparent and reasonable manner.

\163\ See, e.g., 88 FR 44468, 44500 (July 12, 2023).

Scenarios included in the climate change analysis estimate cumulative GHG emissions impacts for a 30-year analytical scenario duration.\164\ Cumulative emissions impact estimates for this 30-year analytical time period are presented in Table III.D.3-1. We present three separate estimates of these emissions, two of which estimate emissions reductions associated with the Analyzed Volumes. See RIA Chapter 5 for further information.

\164\ See RIA Chapter 5.2 for the EPA's explanation regarding why the Agency has not monetized the GHG emissions impacts of this rule. [GRAPHIC] [TIFF OMITTED] TR01AP26.055

This section provides a brief discussion of the methodology used to estimate the cost impacts for the renewable fuels expected to be produced and consumed for the Analyzed Volumes and summarizes the estimated costs.

The cost analysis compared the cost of biofuels attributable to the RFS program to the cost of the fossil fuels they displace. The net estimated fuel cost impacts are social costs, excluding any subsidies and transfer payments. The fuel cost of each biofuel estimated to be consumed and of each fossil fuel being displaced as a result can be divided into various subcomponents:

Production cost: feedstock cost is usually the most prominent factor, though production processing costs are also significant for some fuels.

Distribution cost: because a given biofuel often has a different energy density than the petroleum fuel it is replacing, the distribution costs are estimated all the way to the point of use to capture the full fuel economy effect of using these fuels.

Blending value: in the case of ethanol blended as E10, there is a blending value that mostly accounts for ethanol's octane value realized by lower gasoline production costs, but also a volatility cost that accounts for ethanol's blending volatility in RVP- controlled gasoline.

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

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

We added these various cost components together as appropriate for each renewable fuel to reflect the cost of that fuel. We conducted a similar cost estimate for the fossil fuels being displaced since their relative cost to biofuels is used to estimate the net cost of the increased use of biofuels. Unlike for biofuels, however, we did not calculate production costs for the fossil fuels since their production costs are inherent in the wholesale price projections provided in AEO2025.\165\

\165\ Estimating production costs for renewable fuels facilities is possible because the plants are generally single purpose production processes producing a predictable, limited array of feedstocks into products, while petroleum refineries are each configured differently and each is refining a different mix of feedstocks of varying quality and each refinery is producing a unique number and volume of products.

As described in section III.A.2 of this preamble, the Analyzed Volumes of biodiesel and renewable diesel reflect large year-over-year increases relative to current volumes; thus, we anticipate higher biodiesel and renewable diesel prices as the industry increases production to meet the volume requirements. Higher demand for biodiesel and renewable diesel feedstocks is projected to result in higher vegetable oil prices, which have a first order impact on costs. We have considered the impact of increased demand for vegetable oils used to produce biofuels in our assessment of fuel costs and the fuel price impacts for this final rule. This represents a change from our analysis for the Set 2 proposal, which used a static vegetable oil price for our projection of fuel costs and fuel price impacts.

Our vegetable oil price projection is based on a vegetable oil modeling study for how increased vegetable oil demand for biofuel use would impact its price. Based on this study, we project that soybean oil will rise into the $0.60 per pound range, with FOG and corn oil priced somewhat lower. This is different from the analysis conducted for the Set 2 proposal, which assumed that vegetable oil prices would continue at the projected USDA price for 2026 and 2027. The higher projected BBD feedstock prices, along with lower projected crude oil prices, are the principal reasons for the higher estimated costs of this final rule compared to the cost analysis in the Set 2 proposal.

There is uncertainty in projecting soybean oil prices, the market of which is also associated with, and affected by, the markets for whole soybeans, soybean meal, and soybean oil consumed in foods, as well as the markets for other vegetable oils. To provide an upper- and lower-bound on estimated costs at higher and lower vegetable oil prices, we estimate costs based on higher (approximately $0.80 per pound) and lower (USDA projected) soybean oil prices. Modeling USDA projected soybean oil prices (approximately $0.40 per pound) for the Analyzed Volumes aims to capture the costs presuming that the agricultural market will at some point stabilize at a lower price point consistent with current USDA projections. Because of the large increase in biodiesel and renewable diesel volumes over the baseline volumes, we can attribute a cost for the price increase not just to the new incremental volume increase, but to all biodiesel and renewable diesel, including that in the baseline. Thus, the prices projected in the Analyzed Volumes case are higher than the prices projected in the No RFS Baseline case and this substantially increases the estimated cost of the RFS program. Over time, though, the market is expected to restabilize at lower prices. Consistent with previous analyses, we also estimate costs at the primary, high, and low vegetable oil price estimates relative to the 2025 Baseline.

The estimated fuel costs for the Analyzed Volumes based on the middle estimate of vegetable oil prices and relative to both the No RFS and 2025 Baselines are presented in Tables III.D.4-1 and 2.\166\ Table III.D.4-3 discounts the costs in 2027 to 2026 and adds them to the costs incurred in 2026 to provide a single cost estimate for the 2026 and 2027 standards.

\166\ More detailed information on the costs for the Analyzed Volumes is available in RIA Chapter 10.4.2.

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The biofuel costs are generally higher than the costs of the gasoline, diesel, and natural gas that they displace as evidenced by the increases in fuel costs shown in Table III.D.4-1 through 3.\167\ As described more fully in RIA Chapter 10, our assessment of costs did not yield a specific threshold value below which the incremental costs of biofuels are reasonable and above which they are not. Given the significant inherent uncertainty in both the crude oil and agricultural feedstock price forecasts, any attempt to identify such a threshold value is extremely difficult. Nevertheless, throughout section III of this preamble we consider the directional cost inferences along with the other factors that we analyzed in the context of our discussion of the Analyzed Volumes for 2026 and 2027.

\167\ Natural gas shows a cost savings despite the fact that RNG is more expensive than fossil natural gas. This is because the Analyzed Volume for cellulosic biofuel is estimated to cause a smaller RNG volume in 2026 and 2027 compared to either the No RFS Baseline or the 2025 Baseline.

The fuel cost estimates for the high and low vegetable oil prices relative to the No RFS Baseline, and fuel costs relative to the 2025 Baseline, along with a more detailed discussion of the cost analysis, are summarized in RIA Chapter 10. 5. Cost to Transport Goods

We also estimated the impact of the Analyzed Volumes on the cost to transport goods. However, we do not include these estimates in our social cost analysis because the fuel prices used to form these estimates include a number of other factors, such as RIN value and Federal incentives. Because these factors are economic transfers and are not separable from the non-transfer components of the cost to transport goods, it would not be appropriate to include the overall estimates of these impacts in our social cost estimates.

To estimate price impacts, the per-unit costs from Table III.D.4-2 are adjusted to reflect RIN price impacts and account for the 45Z credit and other market factors, and the resulting values can be thought of as retail price impacts. Consistent with our assessment of the fuels markets, we have assumed that obligated parties pass through their RIN costs to consumers and that fuel blenders reflect the RIN value of the renewable fuels in the price of the blended fuels they sell.\168\ Table III.D.5-1 summarizes the estimated impacts of the Analyzed Volumes on gasoline and diesel fuel prices at retail when the costs of each biofuel are amortized over the fossil fuel it displaces.

\168\ See RIA Chapter 10.5 for more detailed information on our estimates of the fuel price impacts of this action.

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For estimating the cost to transport goods, we focus on the impact on diesel fuel prices since trucks that transport goods are normally fueled by diesel fuel. Reviewing the data in Table III.D.5-1, the largest projected price increase is $0.223 per gallon for diesel fuel in 2027 relative to the No RFS Baseline.

The impact of fuel price increases on the price of goods overall can be estimated based on a USDA study that analyzed the impact of fuel prices on the wholesale price of produce.\169\ Applying the price correlation from the USDA study indicates that the $0.223 per gallon diesel fuel cost increase raises retail diesel fuel prices by about 6 percent, which would then increase the wholesale price of produce by about 1.5 percent. If produce being transported by a diesel truck costs $3 per pound, the increase in that product's price would be $0.045 per pound.\170\ If the estimated price impacts are averaged over the combined gasoline and diesel fuel pool, the impact on produce prices would be proportionally lower based on the lower per-gallon cost.

\169\ USDA, “How Transportation Costs Affect Fresh Fruit and Vegetable Prices,” Economic Research Report 160, November 2013.

\170\ Coupons.com, “Comparing Prices on Groceries,” May 4, 2021.

Increases in volumes attributable to the Analyzed Volumes could lead to potential increases in agricultural land conversion to produce biofuel feedstocks. Such land use changes could subsequently contribute to negative impacts to water and soil quality, water quantity, and ecosystems and wildlife habitat. This is discussed further in RIA Chapters 4.2 through 4.5. 7. Infrastructure

We evaluated the Analyzed Volumes and how they may impact the existing renewable fuels infrastructure required for product distribution. This includes whether the current infrastructure system is sufficient to accommodate the increases in the Analyzed Volumes and potential changes that could occur with increases in renewable fuel production and use. Based on our analysis, we project that the Analyzed Volumes would be compatible with existing infrastructure and that the supply of these fuels will not adversely impact the infrastructure required for product distribution. A more detailed summary of this analysis can be found in RIA Chapter 8. 8. Commodity Supply

We project that the supply of commodities used for biofuel production for the Analyzed Volumes, such as corn and soybeans, will continue to increase in future years primarily due to yield increases, consistent with historic trends. It is possible that increasing demand for biofuel feedstocks such as soybean oil will divert these feedstocks from other markets; however, we project that substitute feedstocks will be available to markets that previously used soybean oil diverted to biofuel production. See RIA Chapter 9.2 for more detail on our analysis of the impact of biofuel production on the supply of commodities. 9. Air Quality

We expect some localized increases in some emissions due to the Analyzed Volumes, particularly at locations near biofuel production and transport routes. Overall, considering end use, transport, and production, emission changes are expected to have variable impacts on ambient concentrations of emitted gases in specific locations across the U.S. Air quality impacts are discussed further in RIA Chapter 4.1. 10. Food and Commodity Prices

Our analysis indicates that the Analyzed Volumes have the potential to affect the prices of agricultural commodities and food prices. Corn price impacts are estimated using a literature-based elasticity of 3 percent per additional billion gallons of corn ethanol, applied to the difference between the Analyzed Volumes and the No RFS Baseline. Our analysis for soybean oil and meal uses a linear equilibrium displacement model from the literature, which maps biofuel demand shocks to commodity prices. Specifically, a 20 percent increase in soybean oil demand for biofuel corresponds to an 8.17 percent increase in the soybean oil price. We then quantify 2026 and 2027 price impacts for the Analyzed Volumes relative to the No RFS Baseline. We also assess grain sorghum, barley, oats, and distillers grains using historical price relationships with corn and find only small impacts. Combining these commodity price changes with forecasts of commodity use for food production suggests modest effects on total food expenditures, given that commodity costs represent a small share of retail food prices. A summary of the estimated impacts is provided in Table III.D.10-1, and further discussion can be found in RIA Chapters 9.3 and 9.4.

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In EISA, Congress set increasing targets for cellulosic biofuel, aiming to reach 16 billion gallons by 2022.\172\ After 2015, all growth in the mandated total renewable fuel volume was designated for advanced biofuels, with the majority of that growth focused on cellulosic biofuels.\173\ This indicates that Congress intended the RFS program to strongly incentivize cellulosic biofuels, placing a particular emphasis on their development after 2015. While cellulosic biofuel production has not reached the levels envisioned by Congress in 2007, we remain committed to supporting the advancement and commercialization of these fuels. As described in section III.A.1 of this preamble, the Analyzed Volume for cellulosic biofuel project growth in cellulosic biofuel production and transportation use through 2027, while accounting for potential constraints on both. We evaluated these volumes using additional statutory factors. The results of these evaluations are summarized here and detailed further in the RIA.

\172\ CAA section 211(o)(2)(B)(i)(III).

\173\ CAA section 211(o)(2)(B)(i).

Our analysis of the statutory factors, summarized here and discussed in greater detail in the RIA, shows that cellulosic biofuels have the potential to provide significant reductions in GHG emissions. We expect that in 2026 and 2027 the cellulosic biofuel supply will come mainly from three sources: renewable CNG/LNG produced from landfill biogas, renewable CNG/LNG produced from agricultural digester biogas, and CKF ethanol. Renewable CNG/LNG produced from landfill biogas and agricultural digester biogas is expected to account for the largest share of total volume. Because both fuel sources recover energy from waste materials and byproducts of existing processes, they are not expected to drive significant land-use change. As a result, we project that producing these fuels will help limit adverse impacts identified in the statutory factors, including the conversion of wetlands and other ecosystems, the loss of wildlife habitat, degradation of soil and water quality, and volatility in food prices and supply. Although we recognize potential soil and water concerns that could result from increased production of biogas from manure and agricultural digestors, the relatively small volumes of these fuels relative to landfill- sourced biogas suggests these impacts will remain minimal.

Beyond these environmental benefits, cellulosic biofuels deliver substantial economic and energy security gains. Converting otherwise unused products into transportation fuel supports jobs and generates positive economic impacts. However, the combination of growing CNG/LNG use as transportation fuel and high cellulosic RIN prices, which refiners typically recover through fuel sales, is expected to increase gasoline and diesel prices. Despite this increase, strengthening the cellulosic biofuel market advances statutory goals for energy independence and security, reduces reliance on foreign fuel sources, and supports long-term economic resilience.

In summary, our analysis of the statutory factors indicates that the benefits of increasing cellulosic biofuel volumes outweigh the potential downsides. We are finalizing cellulosic biofuel volumes for 2026 and 2027 at levels that align with projected growth in the consumption of CNG/LNG as transportation fuel in these years. These volumes, based on the most current data at the time of this action, represent a

well-informed estimate of the achievable growth in cellulosic biofuel production during this period. We believe that these volumes will continue to encourage investment in and development of cellulosic biofuels while adhering to statutory requirements, including those under CAA section 211(o)(2)(B)(iv) that the EPA set the cellulosic fuel volumes such that we do not anticipate a need to lower the requirement through a waiver under CAA section 211(o)(7)(D). To that end, because the “projected volume available” \174\ equals the analyzed volume, we are finalizing the cellulosic biofuel volumes at the analyzed level-- i.e., the level to which the EPA would reduce the cellulosic biofuel requirement if it exercised the cellulosic waiver authority--as shown in Table III.E.1-1.

\174\ CAA section 211(o)(7)(D)(i).

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The volume targets established by Congress through 2022 anticipated volumes of advanced biofuel beyond what would be needed to satisfy the cellulosic standard. The statutory target for advanced biofuel in 2022 (21 billion gallons) allowed for up to five billion gallons of non- cellulosic advanced biofuel to be used towards the advanced biofuel volume target, with additional quantities of non-cellulosic advanced biofuel able to contribute towards meeting the total renewable fuel requirement.\175\ The applicable volumes for 2022 similarly include five billion RINs of non-cellulosic advanced biofuel.\176\ In the Set 1 Rule, we continued to grow the implied non-cellulosic advanced biofuel category, which reached 5.95 billion RINs in 2025.\177\

\175\ CAA section 211(o)(2)(B)(i).

\176\ 87 FR 39600, 39624 (July 1, 2022).

\177\ 88 FR 44468, 44518 (July 12, 2023).

The non-cellulosic advanced biofuel volumes in this action reflect growth rates based on analysis of feedstock availability and production capacity potential. In this action, we are finalizing volume requirements that reflect 4.2 and 4.4 billion RIN increases in the projected supply of non-cellulosic advanced biofuel for 2026 and 2027, respectively. These increases are relative to the volume of non- cellulosic advanced biofuel supplied to the U.S. in 2025 based on available data. Our decision to finalize these volumes is based on our assessment of the impacts of non-cellulosic advanced biofuels (primarily biodiesel and renewable diesel) on the statutory factors. Our assessment of the statutory factors, and how these assessments support the final non-cellulosic advanced biofuel volumes, are summarized in the remainder of this section and are discussed in greater detail in the RIA. Section V.E.3 of this preamble discusses our consideration of what portion of the non-cellulosic advanced biofuel volume should be restricted to BBD.

To date, the vast majority of non-cellulosic advanced biofuel in the RFS program has been biodiesel and renewable diesel, with relatively small volumes of sugarcane ethanol and other advanced biofuels. Advanced biodiesel and renewable diesel together accounted for 95 percent, or more, of the total supply of non-cellulosic advanced biofuel over the last several years, and this trend is expected to continue through 2027 due to the limited production and import of other types of non-cellulosic advanced biofuels.\178\ We therefore focused our attention on the impacts of these fuels in relation to the statutory factors in determining appropriate levels of non-cellulosic advanced biofuel for 2026 and 2027.\179\

\178\ See RIA Chapters 7.2 through 7.4.

\179\ We have also considered the potential for increasing volumes of renewable jet fuel. Given its similarity to renewable diesel, for purposes of projecting appropriate volume requirements for 2026 and 2027, in most cases we consider renewable jet fuel to be a component of renewable diesel.

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

With respect to GHG emission reductions, while there remains considerable uncertainty as to the GHG emission impacts of non- cellulosic advanced biofuels (particularly biofuel produced from crop- based feedstocks) our assessment suggests these fuels have the potential to provide net GHG emission reductions. Regardless of the potential resulting impacts to climate change from the reduction in GHG emissions due to this program, as Congress intended to emphasize lower GHG-emitting fuels within the RFS program, the potential GHG reductions suggest that higher non-cellulosic advanced biofuel volumes than those established by Congress for 2022 (5.0 billion RINs) or established by the EPA for 2025 (5.95 billion RINs) may be appropriate.

All qualifying biodiesel and renewable diesel is expected to diversify the transportation fuel supply and thus have a positive impact on the energy security of the U.S. Similarly, because we project that a greater percentage of the increase in the supply of biodiesel and renewable diesel through 2027 will be supplied from domestic biofuel producers using domestic feedstocks, we expect these fuels to positively impact employment and rural economic development. We do not anticipate the availability of infrastructure to distribute or use biodiesel and renewable diesel will limit the consumption of these fuels in future years, nor do we anticipate that increasing supplies of these fuels will negatively impact the deliverability of materials, goods, and products other than renewable fuel. Together, these statutory factors further support higher volumes of biodiesel and renewable diesel in future years.

Other statutory factors suggest that lower volumes of biodiesel and renewable diesel may be appropriate. Biodiesel and renewable diesel have historically had higher costs than the diesel fuel they displace and are expected to continue to cost more into the future, primarily due to relatively high feedstock costs. These higher costs are expected to ultimately be passed through to consumers, resulting in higher costs for transportation fuel and higher costs to transport goods.\180\

\180\ This discussion refers to societal costs. We recognize that with the incentives provided by the RFS program and other State and local programs, the price for biodiesel and renewable diesel (net available incentives) may be lower than the price of petroleum fuels. See RIA Chapter 10 for a further discussion of our cost estimates.

Biodiesel and renewable diesel produced from vegetable oils are also expected to result in higher prices for these oils and the crops from which they are derived (e.g., soybeans and canola). These higher vegetable oil prices are projected to have both positive and negative impacts. Higher vegetable oil prices are expected to drive increased investment in the domestic oilseed crushing industry, resulting in increased employment and economic impact, as well as higher revenue for feedstock producers. This projected increased investment in domestic oilseed crushing capacity would reduce domestic oilseed producers reliance on export markets, as it would increase the capacity for processing oilseed domestically. Higher vegetable oil prices are, however, expected to result in higher prices for products that use them as inputs (e.g., food and feed).

Notably, the projected impacts on some of the statutory factors are expected to vary depending on the feedstock used to produce biodiesel or renewable diesel. We have generally assumed that biofuels produced from FOG feedstocks such as UCO and tallow do not drive the conversion of land to cropland, increase the intensity of farming practices, or raise agricultural commodity or food prices.\181\ Because of this assumption, biofuels produced from FOG are also generally expected to result in greater GHG emission reductions. However, commodities such as UCO and tallow now command prices comparable to those of crop-derived vegetable oils in some cases which makes forecasting which feedstocks will be economically preferable more difficult than in previous years.

\181\ This is particularly true if the feedstocks used to produce these biofuels would otherwise be landfilled or not productively used. It is not the case, however, that all feedstocks assumed to be wastes or byproducts would otherwise be landfilled or not productively used. For example, UCO and animal fats such as tallow have historically had a variety of productive uses, include use as animal feed and use as a feedstock to produce soaps, detergents, and other oleochemicals. Historically, such demands have been outstripped significantly by product supply, leading to unproductive disposal of excess supply in the absence of a productive use opportunity. However, increasing levels of demand for these feedstocks for biofuel production could not only fully consume this previously excess supply, but also result in the diversion of these feedstocks from existing markets. In turn, markets that previously used these waste and byproduct feedstocks may seek alternatives, and any impacts on cropland, GHG emissions, or other factors that result from the sourcing of these alternative feedstocks should then be attributable to biofuel production.

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

Biodiesel and renewable diesel produced from domestic agricultural commodities such as soybean oil and canola oil are more likely to have negative impacts on wetlands, wildlife habitat and ecosystems, and water quality, as demand for these feedstocks can result in increased conversion of native lands to cropland. This land conversion (whether land is converted directly to produce biofuel crops or induced through higher commodity prices) generally results in GHG emissions, and therefore biofuels produced from these feedstocks may have lifecycle GHG emission greater than biofuels produced from wastes or byproducts.\182\ Significant opportunities exist for increasing domestic production of soybean oil (which would be expected to positively impact job creation and rural economic development), as well as imported canola oil from Canada. Generally, agricultural feedstocks grown in North America are eligible for lower incentives in foreign biofuel programs compared to waste feedstocks. Consequently, we have greater confidence in projecting the potential supply of these feedstocks available for domestic renewable fuel production in future years.

\182\ However, the land use impacts with respect to GHG emissions may be outweighed by additional transportation GHG emissions especially if obtained from international sources.

Our analysis of the Analyzed Volumes indicated likely differences in impacts on the statutory factors between growth in the supply of biodiesel and renewable diesel produced from FOG feedstocks such as UCO and tallow (the marginal supplies of which are primarily sourced from foreign countries) and those produced from virgin vegetable oils (the marginal supplies of which are primarily sourced from the U.S. and Canada). Thus, the availability and likely use of these feedstocks for biofuel production and use in the U.S. is a key factor in our consideration of the Analyzed Volumes of non-cellulosic advanced biofuel. As discussed in section III.A.2 of this preamble and RIA Chapter 7, there is relatively less uncertainty in the projected availability of marginal quantities of vegetable oils than there is in the projected availability of marginal quantities of FOG. The higher uncertainty in the projected availability of the waste and byproduct feedstocks is not only a function of the quantity of these feedstocks that can be collected globally, but also of demand for these feedstocks for biofuel production, other productive uses in other countries, and highly dynamic trading environments. Due to the relatively high uncertainty in the available supply of FOG and the structure of the 45Z credit (which is not available to imported biofuels nor, starting in 2026, biofuels produced from feedstocks originating outside of North America), we project that biofuels produced from domestic feedstocks are more likely to be used in significant quantities in future years than imported biofuels and feedstocks, particularly imported feedstocks originating outside North America.

We have also considered how the increased production of domestic biodiesel and renewable diesel relates to the statutory factors. As is typically the case, not all factors are affected positively or negatively in a uniform fashion by increasing or decreasing domestic biodiesel and renewable diesel production. However, there are several statutory factors that have the potential to be positively impacted in a material way by increasing domestic production of these fuels, including employment and rural economic development and energy security impacts. Energy security is bolstered through a further displacement of fossil fuels by increasing volumes of renewable fuel, a large and increasing fraction of which will be produced from domestic feedstocks as we move forward and changes in trade dynamics and tax incentives (45Z) work through renewable fuel markets.

Employment and rural economic development can be affected very positively by increasing the domestic production of biodiesel and renewable

diesel by more fully utilizing the production assets which have been underutilized or ceased production in recent years. Our analysis indicates that significantly higher domestic production of biodiesel and renewable diesel from existing facilities is possible given the low utilization rates in 2025 compared to previous years and historical precedent and that the industry has been able to achieve utilization rates greater than 90% in past years.\183\

\183\ See further discussion in RIA Chapter 7.2.

Increasing the domestic production of non-cellulosic advanced biofuels would have several positive effects for employment and rural economic development. Direct effects of increased production would be increased employment as additional workers would be required to restart or expand production and increased economic activity for the rural communities wherein these renewable production facilities are often located. Increasing domestic production of biodiesel and renewable diesel is also expected to result in increased investment in domestic oilseed crushing to supply feedstocks for biofuel production. These investments would decrease the reliance of domestic soybean producers on export markets and further benefit rural economic development and employment. A few second order positive impacts may include: increased demand for feedstock produced in rural communities, expansion of associated input and service sector employment related to biofuel and feedstock production, and potential for either new or expanded biofuel production capacity in rural communities. In totality, our analysis of the statutory factors suggests that higher non-cellulosic advanced biofuel volumes intended to realize higher and historically-precedented capacity utilization rates are appropriate.

Based on our analyses of all the statutory factors, we are finalizing volumes for 2026 and 2027 that reflect the Analyzed Volumes of non-cellulosic advanced biofuel. These volumes were calculated projecting a 90 percent utilization rate of existing biodiesel and renewable diesel production capacity (with some growth from 2026 to 2027) and the projected production and import of other advanced biofuels. These volumes reflect our consideration of the impacts of these fuels on the statutory factors, including the potential increases in employment and economic impacts for renewable fuel producers, feedstocks producers and processors, and the rural communities in which these facilities are located. These volumes also reflect our consideration of the impact of these fuels on fuel prices and climate change, although the potential impacts on climate change are more uncertain, as discussed previously. The final non-cellulosic advanced biofuel volume requirements also reflect our assessment of the available supply of feedstocks used to produce these fuels (including the uncertainties associated with these projections), the projected high costs for these fuels relative to the petroleum fuel they displace, and the potential negative impacts associated with increasing demand for vegetable oils or diverting feedstocks from existing uses to biofuel production.

We project that the feedstocks needed to produce the final non- cellulosic advanced biofuel volume requirements could be supplied primarily, if not exclusively from domestic sources and imports from Canada and Mexico. Trade dynamics and changes to the 45Z credit increase the likelihood that the increase in the supply of non- cellulosic advanced biofuels through 2027 will be supplied by domestic biofuel producers using North American feedstocks. Through 2027, we project that imported renewable fuels and imported feedstocks from countries other than Canada and Mexico may continue to contribute towards the total supply of non-cellulosic advanced biofuels, but that the relative share of these fuels will decrease in future years as domestic supplies (and the supply of feedstocks from Canada and Mexico) increase in response to the incentives provided by tax and trade policy.

We recognize that there are potential negative impacts likely to result from non-cellulosic advanced biofuel volume requirements that are too high or too low. If we establish volume requirements for these fuels that are too low, the market will likely supply lower volumes of these fuels to the U.S. than could be achieved with higher volume requirements. This could negatively impact biofuel producers and result in lower employment, economic impacts, and GHG emission reductions than could be achieved with higher volume requirements. Conversely, if we establish volume requirements for these fuels that are too high, the costs of these fuels would be expected to rise, increasing the prices of food, fuel, and other goods for consumers. It is also possible that the market would be unable to supply higher volumes, requiring the EPA to reduce the volume requirements in the future, undermining the market stability the RFS program is designed to provide.

Non-cellulosic advanced biofuel is again expected to fill some of the total renewable fuel volume requirement in excess of the advanced biofuel requirement. Consistent with the approach taken in the Set 1 Rule, and as discussed in greater detail in section III.E.4 of this preamble, we are finalizing volume requirements in this action that reflect an implied conventional renewable fuel requirement of 15 billion gallons in each year. Since we project that the quantity of conventional renewable fuel available in these years will be limited, significant volumes of non-ethanol biofuels will be needed to meet the conventional renewable fuel volume requirement of 15 billion gallons.

We project that the most likely source of non-ethanol biofuel will be biodiesel and renewable diesel that qualifies as advanced biofuel. Biodiesel and renewable diesel cannot be used to satisfy the projected shortfall in conventional renewable fuel if we already require the use of these fuels to meet the non-cellulosic advanced biofuel volume requirement. Therefore, the final renewable fuel volumes we are establishing for 2026 and 2027 reflect non-cellulosic advanced biofuel volumes equal to the analyzed volumes of these fuels less the volume projected to be needed to meet the shortfall in the conventional renewable fuel volume requirement. The final non-cellulosic advanced biofuel volumes for 2026 and 2027 are summarized in Table III.E.2-1.

[GRAPHIC] [TIFF OMITTED] TR01AP26.062

Because BBD makes up for the vast majority of non-cellulosic advanced biofuel, we did not separately assess the impacts of BBD on the statutory factors from those of non-cellulosic advanced biofuels. Our analysis of the impacts of the Analysis Volumes for BBD can be found in section III.E.2 of this preamble. In determining the appropriate BBD volumes for 2026 and 2027, our primary consideration is how much of the non-cellulosic advanced biofuel volume to reserve exclusively for BBD based on our review of the implementation of the RFS program to date and our analysis of the statutory factors. This approach is consistent with the approach we have taken to establishing the BBD volume requirements in previous years.

In previous RFS rulemakings, we have adopted an approach of increasing the BBD volume requirement in concert with the change, if any, in the implied non-cellulosic advanced biofuel volume requirement.\184\ This approach provides ongoing support for BBD producers, while maintaining an opportunity for other advanced biofuels to compete for market share. In reviewing the implementation of the RFS program to date, we determined that this approach successfully balanced a desire to provide support for BBD producers with an increasing guaranteed market, while at the same time maintaining an opportunity for other advanced biofuels to compete within the advanced biofuel category. Our assessment of the impacts of BBD on the statutory factors is discussed further in the RIA.

\184\ See, e.g., 88 FR 44516-17 (July 12, 2023).

As in recent years, we believe that excess volumes of BBD beyond the BBD volume requirements will be used to satisfy the advanced biofuel volume requirement within which the BBD volume requirement is nested. Historically, the BBD standard has not independently driven the use of BBD in the market. This is due to the nested nature of the standards and the competitiveness of BBD relative to other advanced biofuels. Moreover, BBD use can also be driven by the implied conventional renewable fuel volume requirement as an alternative to using increasing volumes of corn ethanol in higher-level ethanol blends such as E15 and E85. We believe these trends will continue through 2027.

We also believe it is important to maintain space for other advanced biofuels to participate within the advanced biofuel standard of the RFS program. Although the BBD industry has matured over the past decade, the production of advanced biofuels other than biodiesel and renewable diesel continues to be relatively low and uncertain. Maintaining this space for other advanced biofuels can in the long-term facilitate increased commercialization and use of other advanced biofuels, which may have superior environmental benefits, avoid concerns with food prices and supply, and have lower costs relative to BBD. Furthermore, rather than only supporting BBD, the 45Z credit may support the production and use of North American non-BBD advanced biofuels as well. Despite the potential impacts of the 45Z credit, we do not think increasing the size of this space is necessary through 2027 given that only small quantities of these other advanced biofuels have been used in recent years relative to the space we have provided for them in those years.

The final BBD volumes represent significant growth from the volumes established in the Set 1 Rule. At the same time, these volumes preserve an opportunity for non-cellulosic advanced biofuels other than BBD to compete for market share within the advanced biofuel category. We are finalizing BBD volumes that maintain a 600 million RIN opportunity for non-cellulosic advanced biofuels other than BBD, which is approximately equal to the opportunity for these fuels from 2023-2025. The final BBD volumes are shown in Table III.E.3-1.\185\

\185\ Note that, unlike in previous years, the BBD volume requirement is expressed in RINs rather than physical gallons. As discussed in section VIII.C of this preamble, we are making this change to better align the BBD requirement with the requirements for the other three categories of renewable fuel, which are expressed in RINs rather than gallons. [GRAPHIC] [TIFF OMITTED] TR01AP26.063

Although Congress had intended cellulosic biofuel to become the most widely used renewable fuel by 2022,\186\ conventional renewable fuel has continued to account for the majority of renewable fuel supply since the RFS program began in 2005. The favorable economics of blending corn ethanol at 10 percent into gasoline, even without the incentives created by the RFS program, caused it to quickly saturate the gasoline supply shortly after the RFS program began.

\186\ CAA section 211(o)(2)(B)(i).

The implied statutory volume target for conventional renewable fuel rose annually between 2009 and 2015 until it reached 15 billion gallons, where it remained through 2022.\187\ We have maintained the implied statutory volume target for conventional renewable fuel at 15 billion gallons since 2022, including in the Set 1 Rule.\188\

\187\ Id.

\188\ 88 FR 44517-18 (July 12, 2023).

As discussed in section III.A.3.a of this preamble, constraints on ethanol consumption have prevented the volume of ethanol used in transportation fuel from reaching 15 billion gallons, even with the incentives provided by the RFS program and after accounting for the projected increase in the availability of higher-level ethanol blends such as E15 and E85. Such higher-level ethanol blends are an avenue through which higher volumes of renewable fuel can be used in the transportation sector to reduce GHG emissions and improve energy security over time. Incentives created by the implied conventional renewable fuel volume requirement contribute to the economic attractiveness of these fuels. However, we expect the constraints that currently limit adoption of these blends, and ethanol consumption as a whole, to continue to exist through 2027. The difficulty in reaching 15 billion gallons with ethanol is compounded by the fact that gasoline demand for 2026 and 2027 is expected to continue to decline slightly relative to gasoline demand in 2025.

We do not believe that constraints on ethanol consumption should be the single determining factor in the appropriate level of conventional renewable fuel to establish for 2026 and 2027. The implied volume requirement for conventional renewable fuel is not a requirement for ethanol, nor even for conventional renewable fuel. Instead, conventional renewable fuel is the portion of total renewable fuel that is not required to be advanced biofuel. The implied volume requirement for conventional renewable fuel can be satisfied by any approved renewable fuel. Examples of non-ethanol renewable fuels that regularly contribute to this volume include conventional biodiesel and renewable diesel, as well as advanced biodiesel and renewable diesel beyond what is required by the advanced biofuel volume requirement. For these reasons, we are establishing the appropriate level of conventional renewable fuel on a broader basis than just the amount of conventional ethanol likely to be consumed each year.

While this segment of the RFS program creates opportunities for all approved renewable fuels to contribute, our analyses of several of the statutory factors, described in more detail in the RIA, also highlights the importance of ongoing support for corn ethanol generally and for an implied conventional renewable fuel volume requirement that helps to incentivize the domestic consumption of corn ethanol. Moreover, sustained and predictable support of higher-level ethanol blends through consistent implied conventional renewable fuel volume requirements helps provide some longer-term incentives for the market to invest in the infrastructure necessary to expand the availability of higher-level ethanol blends. The benefits of this approach include potential increases in employment and economic impact, most notably for corn farmers, but also positive impacts on ethanol producers and related ethanol blending and distribution activities. The rural economies surrounding these industries also benefit from strong demand for ethanol. Increased demand for higher-level ethanol blends could also increase employment and economic impact more broadly if retail station owners respond to the incentives created by the RFS program and other Federal actions by investing in infrastructure necessary to increase the availability of higher-level ethanol blends at their stations. In addition, the consumption of renewable fuels, including domestically produced ethanol, reduces our reliance on foreign sources of petroleum imports and increases the energy security status of the U.S. as noted in section III.D.2 of this preamble.

We are projecting that total ethanol consumption will remain steady in 2026 and 2027 despite the increase in consumption of E15 and E85, as discussed in section III.A.3.a of this preamble. At the same time, we are projecting that sufficient BBD and other non-ethanol advanced biofuels will be available in 2026 and 2027 to compensate for this reduction in ethanol consumption and to enable an implied volume requirement for conventional renewable fuel of 15 billion gallons to be met. We are thus establishing the implied conventional renewable fuel volume requirement for 2026 and 2027 at the Analyzed Volumes of 15 billion gallons of conventional biofuel. [GRAPHIC] [TIFF OMITTED] TR01AP26.064

Sections III.E.1 through 4 of this preamble summarize our holistic balancing of the statutory factors to determine the appropriate volumes for each of the component categories of renewable fuel. After determining the appropriate volumes for each component category, we calculated the volumes for each of the four statutory renewable fuel categories. These volumes for 2026 and 2027 are shown in Table III.E.5- 1.

[GRAPHIC] [TIFF OMITTED] TR01AP26.065

In balancing the factors to arrive at these volumes, we have recognized that the cost of achieving them is significant, and that these costs are not offset by benefits that we are able to monetize. Nevertheless, we believe that these volumes represent a reasonable balancing of the statutory factors, including those for which we were unable to provide monetized estimates. In establishing the RFS program, Congress established ambitious renewable fuel volume requirements recognizing that the production and use of renewable fuel was often more costly than using petroleum-based fuels.\189\ The waiver authorities provided by Congress authorized reductions of the statutory volumes only when achieving these volumes would cause severe economic harm.\190\ Further, while Congress required that the EPA evaluate the impact of the use of renewable fuels on the cost to consumers of transportation fuel and the cost to transport goods, Congress did not require that the consideration of these costs outweigh the consideration of the other statutory factors.\191\ Indeed, the D.C. Circuit found that “[n]othing in the Act or precedent supports a freestanding requirement that EPA balance the quantifiable costs and benefits of the volumes it sets, let alone that EPA may implement the RFS Program only insofar as its benefits--quantified or not--outweigh its costs.” \192\

\189\ The D.C. Circuit has observed that “Congress in the RFS Program `made a policy choice to accept higher fuel prices' in exchange for the benefits of energy security and reduced GHG emissions.” CBD, 141 F.4th at 171 (quoting Sinclair, 101 F.4th at 889).

\190\ See generally CAA section 211(o)(7)(A).

\191\ See CAA section 211(o)(2)(B)(ii).

\192\ CBD at 172.

While the general approach we are taking to organize our analysis of the statutory factors is consistent with our approach in the Set 1 Rule, which was upheld by the D.C. Circuit in CBD, we acknowledge that our balancing of the statutory factors in this rule differs in certain respects from previous rules.\193\ In the Set 1 Rule, we emphasized the potential for significant GHG emission reductions, alongside the projected energy security benefits and support for increasing the annual rate of future commercial production of renewable fuels, job creation, and rural economic development, in justifying renewable fuel volume requirements with high costs.\194\ In this action we continue to consider all the statutory factors, but, in contrast to previous rules, we are placing less emphasis on the potential impact of this rule on climate change while retaining the general practice of using lifecycle GHG emission reduction estimates as a proxy for this analysis. As explained previously, the ranges of potential GHG emission reductions vary widely from substantial net reductions to very slight net increases. This variability, when coupled with the additional uncertainties involved in commonly used climate change end points, makes it difficult to quantify potential climate change impacts such as changes in global temperature. The potential for net GHG emission reductions is sufficient to consider the climate change factor Congress specified as a relevant environmental consideration, particularly in light of Congress' use of GHG emission reduction thresholds in defining renewable fuels. On the other hand, we have placed greater emphasis on the impact of this rule on other statutory criteria: energy security, job creation, and rural economic development, and have maintained our intent to increase the annual rate of future commercial production of renewable fuels. As a result, we have generally sought to establish volumes that support the domestic production of renewable fuels from domestic feedstocks. This is most apparent in our approach to determining the appropriate volumes for non-cellulosic advanced biofuel. In previous RFS rules our determination of the final volume requirements for non-cellulosic advanced biofuel was based on estimates of the quantity of feedstocks available without diverting feedstock from non-biofuel markets or use in other countries. In this action, the final volume requirements reflect the domestic production capacity for non-cellulosic advanced biofuel, consistent with the policy goal of supporting increased domestic production of these fuels as explained in section III.A of this preamble.

\193\ See FDA v. Wages & White Lion Invs., L.L.C., 604 U.S. 542, 569-570 (2025).

\194\ Additionally, the EPA promulgated the 2020-2022 Rule under its authority in CAA section 211(o)(7)(F), which directs the EPA to conduct the statutory factor analysis under CAA section 211(o)(2)(B)(ii). 87 FR 39600 (July 1, 2022). The D.C. Circuit similarly upheld the EPA's analysis there. See Sinclair v. EPA, 101 F.4th 871, 887 (2024).

In our assessment of supply-related factors in section III.A of this preamble, we focused on those factors that could directly or indirectly impact the use of renewable fuel in the U.S. and thereby determine the potential number of RINs generated in each year that could be available for compliance with the applicable standards in those same years. However, carryover RINs represent another source of RINs that can be used for compliance. We therefore investigated whether and to what degree carryover RINs should be considered in the context of determining appropriate levels for the final volume requirements.

CAA section 211(o)(5) requires that the EPA establish a credit program as part of its RFS regulations, and that the credits be valid for obligated parties to show compliance for 12 months as of the date of generation. We implemented this requirement through the use of RINs, which are generated for the production of qualifying renewable fuels. Obligated parties can comply by blending renewable fuels into the transportation fuel supply themselves, or by purchasing RINs that represent the renewable fuels that other parties have blended into the supply. RINs can be used to demonstrate compliance for the year in which they are generated or the subsequent compliance year. Obligated parties can obtain more RINs than they need in a given compliance year, allowing them to “carry over” these excess RINs for use in the subsequent compliance year, although the RFS regulations limit the use of these carryover RINs to 20 percent of the obligated party's RVO.\195\ For the collective supply of carryover RINs to be preserved from one year to the next,

individual carryover RINs are used for compliance before they expire and are essentially replaced with newer vintage RINs that are then held for use in the next year. For example, vintage 2025 carryover RINs must be used for compliance with 2026 compliance year obligations, or they will expire. However, using 2025 vintage RINs to meet 2026 compliance obligations reduces the need to use vintage 2026 RINs, which can then be saved for use toward 2027 compliance.

\195\ 40 CFR 80.1427(a)(5).

As noted in past RFS annual rules, carryover RINs are a foundational element of the design and implementation of the RFS program.\196\ Carryover RINs play an important role in providing a liquid and well-functioning RIN market upon which success of the entire program depends, and in providing obligated parties compliance flexibility in the face of substantial uncertainties in the transportation fuel marketplace.\197\ Carryover RINs enable parties “long” on RINs to trade them to those “short” on RINs, instead of forcing all obligated parties to comply through physical blending. Carryover RINs also provide flexibility and reduce spikes in compliance costs in the face of a variety of unforeseeable circumstances-- including weather-related damage to renewable fuel feedstocks and other circumstances potentially affecting the production and distribution of renewable fuel--that could limit the availability of RINs.

\196\ See, e.g., 72 FR 23904 (May 1, 2007).

\197\ See 80 FR 77482-87 (December 14, 2015), 81 FR 89754-55 (December 12, 2016), 82 FR 58493-95 (December 12, 2017), 83 FR 63708-10 (December 11, 2018), 85 FR 7016 (February 6, 2020), 87 FR 39600 (July 1, 2022), 88 FR 44468 (July 12, 2023).

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

Carryover RINs have also provided flexibility when we have considered the need to use our waiver authorities to lower volumes. For example, in the context of the 2013 RFS rulemaking we noted that an abundance of carryover RINs available in that year, together with possible increases in renewable fuel production and import, justified maintaining the advanced and total renewable fuel volume requirements for that year at the levels specified in the statute.\198\

\198\ 79 FR 49793-95 (August 15, 2013).

The projected number of available carryover RINs after compliance with the 2024 standards (i.e., the number of carryover RINs available for compliance with the 2025 standards) is summarized in Table III.F.1- 1.\199\ This is the most recent year for which complete RFS compliance data was available at the time of this action.

\199\ The calculations performed to project the number of available carryover RINs can be found in RIA Chapter 1.8. [GRAPHIC] [TIFF OMITTED] TR01AP26.066

Assuming that the market exactly meets the 2025 standards with new RIN generation, these are also the number of carryover RINs that would be available for 2026 and 2027. However, there remains considerable uncertainty surrounding the ultimate number of the carryover RINs that will be available for compliance with the 2026 and 2027 standards for several reasons, including the granting of small refinery exemptions (projected to total 990 million RINs in 2025, as discussed in section IV of this preamble), higher or lower than expected transportation fuel

demand (requiring greater or lower volumes of renewable fuel to comply with the percentage standards that apply to all volumes of transportation fuel), and the impact of 2025 RFS compliance on the availability of carryover RINs. While we project that the volume requirements in 2025-2027 could be achieved without the use of carryover RINs, there is nevertheless some uncertainty about how the market will choose to meet the applicable standards. The result is that there remains some uncertainty surrounding the ultimate number of carryover RINs that will be available for compliance with the 2026 and 2027 standards.

In addition, we note that there have been enforcement actions in past years that have resulted in the retirement of carryover RINs to make up for the generation and use of invalid RINs and/or the failure to retire RINs for exported renewable fuel. To the extent that there are enforcement actions in the future, they could have similar results and require that obligated parties or renewable fuel exporters settle past enforcement-related obligations in addition to complying with the annual standards. In light of these uncertainties, the number of carryover RINs that will be available for compliance with the 2026 and 2027 standards could be larger or smaller than the number projected in Table III.F.1-1. 2. Treatment of Carryover RINs for 2026 and 2027

We evaluated the number of carryover RINs projected to be available and considered whether we should include any portion of them in the determination of the volume requirements that we are establishing for 2026 and 2027. Doing so would be equivalent to intentionally drawing down the number of available carryover RINs in setting those volume requirements. As part of this consideration, we note that, as further discussed in section IV of this preamble, we are reallocating a portion of the exempted RVOs for the 2023-2025 compliance years to the 2026 and 2027 compliance years, which we intend to be met with carryover RINs attributable to the 2023-2025 exemptions. These reallocated obligations, which total over 2 billion RINs, represent over 50 percent of the number of currently available carryover RINs. Thus, absent the impact of other factors (e.g., higher or lower than expected transportation fuel demand), we would expect that compliance with the SRE reallocated volumes will result in a significant decrease in the number of available carryover RINs over the course of the 2026 and 2027 compliance years.

After due consideration, we do not believe that it would be appropriate to establish final volume requirements that would intentionally draw down the projected number of available carryover RINs any further than will already be required by the SRE reallocation volumes. In reaching this determination, we considered the functions of carryover RINs, the projected number available, the uncertainties associated with this projection, the potential impact of carryover RINs on the production and use of renewable fuel, the ability and need for obligated parties to draw on carryover RINs to comply with their obligations (both on an individual basis and on a market-wide basis), and the impacts of drawing down the number of available carryover RINs on obligated parties and the fuels market more broadly. As previously described, carryover RINs provide important and necessary programmatic functions--including as a cost spike buffer--that will both facilitate individual compliance and provide for smooth overall functioning of the program. We believe that a balanced consideration of the possible role of carryover RINs in achieving the volume requirements, versus maintaining an adequate number of carryover RINs for important programmatic functions, is appropriate when we exercise our discretion under our statutory authorities.

Furthermore, in this action we are prospectively establishing volume requirements for multiple years. This inherently adds uncertainty and makes it more challenging to project with accuracy the number of carryover RINs that will be available for each of these years. Given these factors, and the uneven holding of carryover RINs among obligated parties, we believe that further increasing the volume requirements for 2026 and 2027 with the intent to draw down the number of available carryover RINs could lead to significant deficit carryforwards and noncompliance by some obligated parties. We do not believe this would be a desirable outcome. Therefore, consistent with the approach we have taken in recent annual rules, we are not establishing the 2026 and 2027 volume requirements at levels that will intentionally draw down the projected number of available carryover RINs beyond what will already be required by the SRE reallocation volumes for 2026 and 2027.

We are not determining that the number of carryover RINs projected in Table III.F.1-1 is a bright-line threshold for the number of carryover RINs that provides sufficient market liquidity and allows carryover RINs to play their important programmatic functions. As in past years, we are instead evaluating, on a rule-by-rule basis, the number of available carryover RINs in the context of the RFS standards and the broader transportation fuel market. Based upon this holistic, case-by-case evaluation, we are concluding that it would be inappropriate to intentionally reduce the number of carryover RINs by establishing higher volumes than what we anticipate the market can achieve in 2026 and 2027. Conversely, while a larger number of available carryover RINs may provide greater assurance of market liquidity, we do not believe it would be appropriate to set the standards at levels specifically designed (i.e., low) to increase the number of carryover RINs available to obligated parties.