Conventional ethanol from feedstocks other than corn starch have
been produced in the past, but at significantly lower volumes.
Production of ethanol from grain sorghum reached an historical high of
125 million gallons in 2019, representing just less than 1 percent of
all conventional ethanol. Waste industrial ethanol and ethanol made
from non-cellulosic portions of separated food waste have been produced
more sporadically and at even lower volumes. We have ignored these
other sources for our purposes here as they do not materially affect
our assessment of volumes of conventional ethanol that can be produced.
    Total domestic corn ethanol production capacity increased
dramatically between 2005 and 2010 and increased at a slower rate
thereafter. In 2020, production capacity had reached 17.4 billion
gallons.73 74 This production capacity was significantly
underused in 2020 because the COVID-19 pandemic depressed gasoline
demand in comparison to previous years and thus ethanol demand in the
form of E10. Actual production of denatured ethanol in the U.S. reached
just 12.82 billion gallons in 2020, compared to 14.72 billion gallons
in 2019. Denatured ethanol production partially recovered in 2021,
reaching 14.09 billion gallons.\75\
---------------------------------------------------------------------------

    \73\ ``2021 Ethanol Industry Outlook--RFA,'' available in the
docket.
    \74\ ``Ethanol production capacity--EIA April 2021,'' available
in the docket.
    \75\ ``RIN supply as of 1-31-22,'' available in the docket.
---------------------------------------------------------------------------

    The expected annual rate of future commercial production of corn
ethanol will continue to be driven primarily by gasoline demand in the
2023-2025 timeframe as most gasoline is expected to continue to contain
10 percent ethanol. Commercial production of corn ethanol is also a
function of exports of ethanol and to a smaller degree the demand for
E0, E15, and E85, and we have incorporated projected growth in
opportunities for sales of E15 and E85 into our assessment. While
production of corn ethanol could in theory be limited by production
capacity, in reality there is an excess of production capacity in
comparison to the ethanol volumes that we estimate will be consumed in
the near future given constraints on consumption as described in
Section III.B.5 below. Thus, it does not appear that production
capacity will be a limiting factor in 2023-2025 for meeting the
candidate volumes.
b. Biodiesel and Renewable Diesel
    Other than corn ethanol, the only other conventional renewable
fuels that have been used above de minimis levels in the U.S. have been
biodiesel and renewable diesel. The vast majority of those volumes were
imported, and all of it was grandfathered under 40 CFR 80.1403 and thus
was not required to meet the 20 percent GHG reduction requirement.
    Actual global production of palm oil biodiesel and renewable diesel
was about 3.7 billion gallons in 2019.\76\ The

U.S. could be an attractive market for this foreign-produced
conventional biodiesel and renewable diesel if domestic demand for
conventional renewable fuel exceeded domestic supply, i.e., the amount
of ethanol that could be consumed combined with domestic production of
conventional biodiesel and renewable diesel. While there is no RIN-
generating pathway for biodiesel or renewable diesel produced from palm
oil in the RFS program, fuels produced at grandfathered facilities from
any feedstock meeting the definition of ``renewable biomass'' may be
eligible to generate conventional renewable fuel RINs. Total foreign
production capacity at grandfathered biodiesel and renewable diesel
production facilities is over 3.6 billion gallons, suggesting that
significant volumes of grandfathered biodiesel and renewable diesel
could be imported under favorable market conditions.
---------------------------------------------------------------------------

    \76\ Total worldwide production of biodiesel and renewable
diesel was 46.8 billion liters in 2019 (see ``OECD-FAO Agricultural
Outlook 2020-2029 data for biodiesel & renewable diesel''), of which
30 percent was from palm oil (see page 206 of ``OECD-FAO
Agricultural Outlook 2021-2030'').
---------------------------------------------------------------------------

    Historical U.S. imports of conventional biodiesel and renewable
diesel have been only a small fraction of global production in the
past. Conventional biodiesel imports rose between 2012 and 2016,
reaching a high of 113 million gallons.\77\ After 2016, however, there
have been no imports of conventional biodiesel. Small refinery
exemptions granted from 2016-2018 decreased demand for renewable fuel
in the U.S. and likely had an impact on conventional biodiesel and
renewable diesel imports. Imports of conventional renewable diesel have
been similarly low, reaching a high of 87 million gallons in 2015 and
being zero since 2017.\78\ The highest imported volume of total
conventional biodiesel and renewable diesel occurred in 2016 with 160
million gallons (258 million RINs).
---------------------------------------------------------------------------

    \77\ ``RIN supply as of 3-22-21,'' available in the docket.
    \78\ ``RIN supply as of 3-22-21,'' available in the docket.
---------------------------------------------------------------------------

5. Ethanol Consumption
    Ethanol consumption in the U.S. is dominated by E10, with higher
ethanol blends such as E15 and E85 being used in much smaller
quantities. The total volume of ethanol that can be consumed, including
that produced from corn, cellulosic biomass, the non-cellulosic
portions of separated food waste, and sugarcane, is a function of these
three ethanol blends and demand for E0. The use of these different
gasoline blends is reflected in the poolwide ethanol concentration
which increased dramatically from 2003 through 2010 and thereafter
increased at a considerably slower rate.
[GRAPHIC] [TIFF OMITTED] TP30DE22.003

    As the average ethanol concentration approached and then exceeded
10.00 percent, the gasoline pool became saturated with E10, with a
small, likely stable volume of E0 and small but increasing volumes of
E15 and E85. The average ethanol concentration can exceed 10.00 percent
only insofar as the ethanol in E15 and E85 exceeds the ethanol content
of E10 and more than offsets the volume of E0. In order to project
total ethanol consumption for 2023-2025, we correlated the poolwide
average ethanol concentration shown in the figure above with the number
of retail service stations offering E15 and E85. Projections of the
number of stations offering these blends in the future then provided a
basis for a projection of the average ethanol concentration, and thus
of total ethanol volumes consumed. The results are shown below. Details
of these calculations can be found in the DRIA.

             Table III.B.5-1--Projected Ethanol Consumption
------------------------------------------------------------------------
                                                      Projected ethanol
            Year                Projected ethanol        consumption
                               concentration  (%)     (million gallons)
------------------------------------------------------------------------
2023........................                 10.44                14,590
2024........................                 10.49                14,640
2025........................                 10.53                14,669
------------------------------------------------------------------------

C. Candidate Volumes for 2023-2025

    Based on our analysis of supply-related factors as described in
Section III.B above, we developed candidate volumes for 2023-2025 which
we then subjected to the other economic and environmental analyses
required by the statute. This section describes the candidate volumes,
while Section IV summarizes the results of the additional analyses we
performed.
    We have largely framed our assessment of volumes in terms of the
component categories (cellulosic biofuel, non-cellulosic advanced
biofuel, and conventional renewable fuel) rather than in terms of the
statutory categories (cellulosic biofuel, advanced biofuel, total
renewable fuel). The statutory categories are those addressed in CAA
section 211(o)(2)(B)(i)-(iii), and cellulosic and advanced biofuel are
nested within the overall total renewable fuel category. The component
categories are the categories of renewable fuels which make up the
statutory categories but which are not nested within one another. They
possess distinct economic, environmental, technological, and other
characteristics relevant to the factors we must analyze under the
statute, making our focus on them rather than the nested categories in
the statute technically sound. Finally, an analysis of the component
categories is parsimonious as analyzing the statutory categories would
effectively require us to evaluate the difference between various
statutory categories (e.g., assessing ``the difference between volumes
of advanced biofuel and total renewable fuel'' instead of assessing
``the volume of conventional renewable fuel''), adding unnecessary
complexity and length to our analysis. In any event, were we to frame
our analysis in terms of the statutory categories, we believe that our
substantive approach and conclusions would remain materially the same.
1. Cellulosic Biofuel
    The statutory volumes for cellulosic biofuel increased rapidly,
from 100 million gallons in 2010 to 16 billion gallons in 2022 with the
largest increases in the later years. While notable on its own, it is
even more notable in comparison to the implied statutory volumes for
the other renewable fuel volumes. BBD volumes did not increase after
2012, conventional renewable fuel volumes did not increase after 2015,
and non-cellulosic advanced biofuel volume increases tapered off in
recent years with a final increment in 2022. Thus, the clear focus of
the statute by 2022 was intended to be on growth in cellulosic biofuel
volumes, which have the greatest greenhouse gas reduction threshold.
The statutory cellulosic waiver provision, while acknowledging that the
statutory cellulosic biofuel volumes may not be met, nevertheless
expressed support for the cellulosic biofuel industry in directing EPA
to establish the cellulosic biofuel volume at the projected volume
available in years when the projected volume of cellulosic biofuel
production was less than the statutory volume. This increasing emphasis
on cellulosic biofuel in the RFS program is likely due to the
expectations among proponents of cellulosic biofuel that it has
significant potential to reduce GHG emissions (cellulosic biofuels are
required to reduce GHG emissions by 60 percent relative to the gasoline
or diesel fuel they displace),\79\ that cellulosic biofuel feedstocks
could be produced or collected with relatively few negative
environmental impacts, that the feedstocks would be inexpensive,
allowing for lower cost biofuels to be produced than those produced
from feedstocks with other primary uses such as food, and that the
technological breakthroughs needed to convert cellulosic feedstocks
into biofuel were right around the corner.
---------------------------------------------------------------------------

    \79\ See definition of ``cellulosic biofuel'' at 40 CFR part 80
Section 1401.
---------------------------------------------------------------------------

    The candidate volumes discussed in this section represent the
volume of qualifying cellulosic biofuel we project will be produced or
imported into the U.S. in 2022-2025, after taking into consideration
the incentives provided by the RFS program and other available state
and federal incentives. The candidate volumes for 2022-2025 are shown
in Table III.C.1-1. Because the technical, economic, and regulatory
challenges related to cellulosic biofuel production vary significantly
between the various types of cellulosic biofuel, we have shown the
candidate volumes for liquid cellulosic biofuel, CNG/LNG derived from
biogas, and eRINs separately. Note that consistent with the proposed
regulations for eRINs in this proposed rule, the candidate volumes for
2023 do not include any generation of cellulosic RINs from eRINs.

                              Table III.C.1-1--Cellulosic Biofuel Candidate Volumes
                                                 [Million RINs]
----------------------------------------------------------------------------------------------------------------
                                                                       2023            2024            2025
----------------------------------------------------------------------------------------------------------------
Liquid Cellulosic Biofuel.......................................               0               5              10
CNG/LNG Derived from Biogas.....................................             719             814             921
eRINs...........................................................               0             600           1,200
                                                                 -----------------------------------------------
    Total Cellulosic Biofuel....................................             719           1,419           2,131
----------------------------------------------------------------------------------------------------------------

2. Non-Cellulosic Advanced Biofuel
    Although there are no volume targets in the statute for years after
2022, the statutory volume targets for prior years represent a useful
point of reference in the consideration of volumes that may be
appropriate for 2023-2025. For non-cellulosic advanced biofuel, the
implied statutory requirement increased in every year between 2009 and
2019. It remained at 4.5 billion gallons for three years before finally
rising to 5.0 billion gallons in 2022.
    In calculating the applicable percentage standards in the past, we
have used volumes for non-cellulosic advanced biofuel that are at least
as high as those derived from the statutory targets, and occasionally
higher. For 2022, we have set the implied volume requirement for non-
cellulosic advanced biofuel at 5.0 billion gallons, equivalent to the
implied volume target in the statute.\80\ As described in that rule, we
believe that this level can be reached, though likely not without
market adjustments that could include some diversion of soybean oil
from food and other uses to biofuel production.
---------------------------------------------------------------------------

    \80\ 87 FR 39600 (July 1, 2022).
---------------------------------------------------------------------------

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

biodiesel and renewable diesel (the two non-cellulosic advanced
biofuels projected to be available in the greatest quantities through
2025) will be limited, particularly in the U.S. While advanced biofuels
have the potential for significant GHG reductions, if pushing volume
requirements beyond the supply of low-GHG feedstocks results in an
increased use of high-GHG feedstocks in non-biofuel markets as low-GHG
feedstocks are increasingly used for biofuel production, then it would
prove counterproductive. Further, as discussed in greater detail in
Section III.C.3 below, significant volumes of non-ethanol advanced
biofuels beyond what would be needed to meet the implied non-cellulosic
advanced biofuel category are likely to also be needed to meet an
implied conventional renewable fuel volume of 15.25 billion
gallons.\81\
---------------------------------------------------------------------------

    \81\ In 2023, the candidate volume for conventional renewable
fuel would be 15.00 billion gallons, but the inclusion of the
supplemental standard of 250 million gallons makes the conventional
renewable fuel volume effectively 15.25 billion gallons. We
sometimes refer to 15.25 billion gallons in 2023 as the effective
volume requirement for conventional renewable fuel.
---------------------------------------------------------------------------

    Based on these considerations, we believe that increases in the
implied volume for non-cellulosic advanced biofuel in the 2023-2025
timeframe should be relatively small in comparison to the 500 million
RIN increase that occurred in 2022. As a result, we believe that an
annual increase of 100 million RINs as shown below would be reasonable.
We also note that this increase (100 million RINs per year) is
consistent with the projected increase in domestic soybean oil
production through 2025 if the entire volume were used to produce
biodiesel and/or renewable diesel.\82\
---------------------------------------------------------------------------

    \82\ USDA Agricultural Projections to 2031. Soybean oil
production is projected to increase from 25,535 million pounds in
2021/22 to 27,475 million pounds in 2025/2026. This represents an
average annual increase of 485 million pounds per year, which could
be used to produce approximately 65 million gallons of biodiesel or
renewable diesel. This volume of fuel could generate between 95
million and 110 million RINs, depending on the equivalence value of
the fuel produced.

   Table III.C.2-1--Non-Cellulosic Advanced Biofuel Candidate Volumes
                             [Million RINs]
------------------------------------------------------------------------
                              Year                                Volume
------------------------------------------------------------------------
2023...........................................................    5,100
2024...........................................................    5,200
2025...........................................................    5,300
------------------------------------------------------------------------

3. Conventional Renewable Fuel
    As for non-cellulosic advanced biofuel, the implied statutory
volume targets for conventional renewable fuel in prior years represent
a useful point of reference in the consideration of candidate volumes
that may be appropriate for 2023-2025. Under the statute, conventional
renewable fuel increased every year between 2009 and 2015, after which
it remained at 15 billion gallons through 2022. In calculating the
applicable percentage standards in the past, we have used 15 billion
gallons in most years between 2017 and 2022.\83\ Thus as a starting
point, consistent with our approach to setting standards in recent
years, we considered whether 15 billion gallons of conventional
renewable fuel would be appropriate for 2023-2025.
---------------------------------------------------------------------------

    \83\ While the 2020 implied volume requirement was originally
set at 15 billion gallons (85 FR 7016, February 6, 2020), we have
reduced it to the volume actually consumed due to the significant
impacts of the COVID-19 pandemic on demand for renewable fuel and
our change to the treatment of exemptions for small refineries (87
FR 39600, July 1, 2022). For 2021, as EPA did not establish
applicable standards with sufficient time to influence market
behavior, we have set the implied volume requirement for
conventional renewable fuel at the level actually consumed.
---------------------------------------------------------------------------

    However, we note that the inclusion of a supplemental volume
requirement of 250 million gallons in 2022 to address the remand of the
2016 standards effectively results in an implied conventional renewable
fuel volume requirement of 15.25 billion gallons. Since we are also
proposing to include a supplemental volume requirement of 250 million
gallons in 2023 as described in Section V, an implied volume
requirement of 15 billion gallons for conventional renewable fuel would
also effectively be 15.25 billion gallons in 2023. As discussed in the
final rule which established the applicable volume requirements for
2022, we believe that a 15.25 billion gallon implied volume requirement
for conventional renewable fuel can be met without the need for
obligated parties to use carryover RINs for compliance. The same is
true for 2023-2025; not only do we project that total ethanol
consumption in these years will be higher than it was in 2022, but we
also project that sufficient excess volumes of advanced biodiesel and
renewable diesel can be supplied in 2023-2025. Thus, we believe that a
volume of 15.25 billion gallons in 2024 and 2025 is an appropriate
candidate volume for consideration. We expect that the market will have
adjusted to providing this volume in 2022 in meeting the combination of
the conventional renewable fuel implied volume requirement and the
supplemental volume requirement, and we project that the market could
do so as well for 2023, so it would be consistent with available supply
to consider 15.25 billion gallons as a candidate volume for 2024 and
2025 as well. However, for purposes of analyzing the other
environmental and economic impacts, we treat the proposed 2023
supplemental volume requirement separately as discussed in DRIA Chapter
3.3; the candidate volumes which we subjected to the other analyses
described in Section IV do not include the impacts of the supplemental
volume requirement.\84\
---------------------------------------------------------------------------

    \84\ Although the effective implied volume requirement for
conventional renewable fuel would be 15.25 bill RINs for all years
2023-2025, in 2023 this implied volume requirement would in reality
be represented by 15.00 bill RINs for conventional renewable fuel
and 0.25 bill RINs for the supplemental standard.
---------------------------------------------------------------------------

    Additionally, in considering a candidate volume of 15.25 billion
gallons of conventional renewable fuel in 2024 and 2025, we believe
that obligated parties would seek out RINs representing new renewable
fuel consumption to comply with the supplemental volume requirement to
the extent they are able, even though the supplemental volume
requirement in 2023 could be met with carryover RINs. In past years we
have noted a preference on the part of obligated parties for using RINs
associated with new renewable fuel consumption when possible,
preserving their individual carryover RIN banks for use in the event
that future supply falls short of that needed to meet the applicable
standards. As a result, we have assumed for purposes of analyzing the
impacts of this proposed rule that no carryover RINs would be used to
meet a candidate conventional renewable volume of 15.25 billion
gallons, and this provides additional justification for the
consideration of a candidate volume of 15.25 billion gallon for
conventional renewable fuel in 2024 and 2025.
    As in past years, we do not expect that the implied conventional
renewable volume would be achievable through the consumption of ethanol
alone. As described in Section III.B.5, we estimate that ethanol
consumption will continue to fall short of 15.25 billion gallons in the
2023-2025 timeframe, even under the market influences of the RFS
program and with ongoing efforts to expand offerings of E15 and E85 at
retail service stations. Instead, there are a variety of means through
which the market could meet a 15.25 billion gallon

candidate volume for conventional renewable fuel, such as: \85\
---------------------------------------------------------------------------

    \85\ Carryover RINs also represent a legitimate compliance
approach. However, since they do not represent new supply of
renewable fuel, they are not appropriate for including in the
candidate volumes for purposes of analyzing impacts.
---------------------------------------------------------------------------

     Reductions in the consumption of E0;
     Consumption of non-ethanol advanced biofuel, such as
biodiesel and renewable diesel, in excess of the applicable advanced
biofuel standard; and
     Domestic production and/or importation of conventional
biodiesel or renewable diesel.
    As a result, our assessments from previous years remain applicable
for 2023-2025 in broad strokes: 15.25 billion gallons of conventional
renewable fuel is achievable through some collection of the avenues
listed above. We believe it is appropriate to analyze this volume of
conventional renewable fuel as part of the candidate volumes, even
though corn ethanol alone would not be sufficient to meet that volume.
    The amount of corn ethanol that could be consumed between 2023 and
2025 can be estimated from the total ethanol consumption projections
from Table III.B.5-1 and our projections for other forms of ethanol as
discussed earlier in this section.

                            Table III.C.3-1--Projections of Corn Ethanol Consumption
                                                [Million gallons]
----------------------------------------------------------------------------------------------------------------
                                                                       2023            2024            2025
----------------------------------------------------------------------------------------------------------------
Ethanol in all blends...........................................          14,590          14,640          14,669
Cellulosic ethanol..............................................               0               0               0
Imported sugarcane ethanol......................................             110             110             110
Domestic advanced ethanol.......................................              25              25              25
Corn ethanol....................................................          14,455          14,505          14,534
----------------------------------------------------------------------------------------------------------------

    Since corn ethanol consumption would be about 14.5 billion gallons,
there would need to be about 0.75 billion ethanol-equivalent gallons of
non-ethanol renewable fuel in order for an effective conventional
renewable fuel volume of 15.25 billion gallons to be met.
    As discussed in Section III.C.2, we project that more non-
cellulosic advanced biofuel can be made available than would be needed
to meet the non-cellulosic advanced biofuel candidate volumes shown in
Table III.C.2-1. The total volume of non-cellulosic advanced biofuel
that we project can be produced and consumed in 2023-2025 is shown
below. Details are provided in the DRIA Chapter 5.

                    Table III.C.3-2--Total Non-Cellulosic Advanced Biofuel Candidate Volumes
                                                 [Million RINs]
----------------------------------------------------------------------------------------------------------------
                                                                       2023            2024            2025
----------------------------------------------------------------------------------------------------------------
Advanced biodiesel..............................................           2,580           2,530           2,480
Advanced renewable diesel \a\...................................           3,054           3,154           3,275
Advanced jet fuel...............................................               5               5               5
Other advanced biofuel..........................................             256             256             256
                                                                 -----------------------------------------------
    Total.......................................................           5,895           5,945           6,016
----------------------------------------------------------------------------------------------------------------
\a\ Represents only biomass-based diesel with a D code of 4. Advanced renewable diesel with a D code of 5 is
  included in ``Other advanced biofuel.'' See also Table III.B.3-1.

    The total volumes of non-cellulosic advanced biofuel that can be
supplied would be in excess of the candidate volumes we have considered
in this action.

                             Table III.C.3-3--Excess Non-Cellulosic Advanced Biofuel
                                                 [Million RINs]
----------------------------------------------------------------------------------------------------------------
                                                                       2023            2024            2025
----------------------------------------------------------------------------------------------------------------
Total supply....................................................           5,895           5,945           6,016
Candidate volume requirement....................................           5,100           5,200           5,300
Excess..........................................................             795             745             716
----------------------------------------------------------------------------------------------------------------

    This excess non-cellulosic advanced biofuel would make up for the
shortfall in corn ethanol, enabling an implied conventional volume of
15.00 billion gallons in 2023 and 15.25 billion gallons in 2024 and
2025 to be met, and also enable the 250 million gallon supplemental
volume to be met.

                  Table III.C.3-4--Meeting the Candidate Volume for Conventional Renewable Fuel
                                                 [Million RINs]
----------------------------------------------------------------------------------------------------------------
                                                                       2023            2024            2025
----------------------------------------------------------------------------------------------------------------
Corn ethanol....................................................          14,455          14,505          14,534
Excess non-cellulosic advanced biofuel..........................         \a\ 545             745             716
                                                                 -----------------------------------------------
    Total.......................................................          15,000          15,250          15,250
----------------------------------------------------------------------------------------------------------------
\a\ An additional 250 million RINs of excess non-cellulosic advanced biofuel would also be available to fulfill
  the supplemental volume requirement addressing the remand of the 2016 standards.

    Based on our assessment of available supply, we do not believe that
there would be a need for conventional biodiesel or renewable diesel to
be imported in order to help meet an effective conventional renewable
fuel candidate volume of 15.25 billion gallons in the 2023-2025
timeframe. Nevertheless, such imports remain a potential source in the
event that the market did not respond to the candidate volumes in the
way that we have projected it would. As discussed in Section III.B.4.b,
total foreign production capacity for qualifying palm-based biodiesel
and renewable diesel is over 3.6 billion gallons.
4. Treatment of Carryover RINs
    In our assessment of supply-related factors, we focused on those
factors that could directly or indirectly impact the consumption of
renewable fuel in the U.S. and thereby determine the number of RINs
generated in each year that could be available for compliance with the
applicable standards in those same years. However, carryover RINs
represent another source of RINs that can be used for compliance. A
consideration of carryover RINs is also consistent with the statutory
requirement at 211(o)(2)(B)(ii) that, in the context of determining
appropriate volume requirements for years after 2022, we review the
implementation of the program in prior years. We therefore investigated
whether and to what degree carryover RINs should be considered in the
context of determining appropriate levels for the candidate volumes and
ultimately the proposed volume requirements (discussed in Section VI).
    CAA section 211(o)(5) requires that EPA establish a credit program
as part of its RFS regulations, and that the credits be valid for
obligated parties to show compliance for 12 months as of the date of
generation. EPA implemented this requirement through the use of RINs,
which are generated for the production of qualifying renewable fuels.
Obligated parties can comply by blending renewable fuels themselves, or
by purchasing the RINs that represent the renewable fuels from other
parties that perform the blending. RINs can be used to demonstrate
compliance for the year in which they are generated or the subsequent
compliance year. Obligated parties can obtain more RINs than they need
in a given compliance year, allowing them to ``carry over'' these
excess RINs for use in the subsequent compliance year, although our
regulations limit the use of these carryover RINs to 20 percent of the
obligated party's renewable volume obligation (RVO).\86\ For the bank
of carryover RINs to be preserved from one year to the next, individual
carryover RINs are used for compliance before they expire and are
essentially replaced with newer vintage RINs that are then held for use
in the next year. For example, vintage 2020 carryover RINs must be used
for compliance with 2021 compliance year obligations, or they will
expire. However, vintage 2021 RINs can then be ``banked'' for use
toward 2022 compliance.
---------------------------------------------------------------------------

    \86\ 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.\87\ A bank of carryover RINs is extremely important in
providing a liquid and well-functioning RIN market upon which success
of the entire program depends, and in providing obligated parties
compliance flexibility in the face of substantial uncertainties in the
transportation fuel marketplace.\88\ Carryover RINs enable parties
``long'' on RINs to trade them to those ``short'' on RINs instead of
forcing all obligated parties to comply through physical blending.
Carryover RINs also provide flexibility and reduce spikes in compliance
costs in the face of a variety of unforeseeable circumstances--
including weather-related damage to renewable fuel feedstocks and other
circumstances potentially affecting the production and distribution of
renewable fuel--that could limit the availability of RINs.
---------------------------------------------------------------------------

    \87\ See, e.g., 72 FR 23904 (May 1, 2007).
    \88\ See 80 FR 77482-87 (December 14, 2015), 81 FR 89754-55
(December 12, 2016), 82 FR 58493-95 (December 12, 2017), 83 FR
63708-10 (December 11, 2018), 85 FR 7016 (February 6, 2020), 87 FR
39600 (July 1, 2022).
---------------------------------------------------------------------------

    Just as the economy as a whole is able to function efficiently when
individuals and businesses prudently plan for unforeseen events by
maintaining inventories and reserve money accounts, we believe that the
RFS program is able to function when sufficient carryover RINs are held
in reserve for potential use by the RIN holders themselves, or for
possible sale to others that may not have established their own
carryover RIN reserves. Were there to be too few RINs in reserve, then
even minor disruptions causing shortfalls in renewable fuel production
or distribution, or higher than expected transportation fuel demand
(requiring greater volumes of renewable fuel to comply with the
percentage standards that apply to all volumes of transportation fuel,
including the unexpected volumes) could result in deficits and/or
noncompliance by parties without RIN reserves. Moreover, because
carryover RINs are individually and unequally held by market
participants, a non-zero but nevertheless small carryover RIN bank may
negatively impact the RIN market, even when the market overall could
satisfy the standards. In such a case, market disruptions could force
the need for a retroactive waiver of the standards, undermining the
market certainty so critical to the RFS program. For all of these
reasons, the collective carryover RIN bank provides a necessary
programmatic buffer that helps facilitate compliance by individual
obligated parties, provides for smooth overall functioning of the
program to the benefit of all market participants, and is consistent
with the statutory provision allowing for the generation and use of
credits.
    EPA can also rely on the availability of carryover RINs to support
market-forcing volumes that may not be able to be met with renewable
fuel production and use in that year, and in the context of the 2013
RFS rulemaking we noted that an abundance of carryover RINs available
in that year, together with possible increases in renewable fuel

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

    \89\ 79 FR 49793-95 (August 15, 2013).
---------------------------------------------------------------------------

a. Carryover RIN Bank Size
    After compliance with the 2019 standards, we project that there are
approximately 1.83 billion total carryover RINs available.\90\ This is
the same total number of carryover RINs that were estimated to be
available in the 2020-2022 final rule. Since we set both the 2020 and
2021 volume requirements at the actual volume of renewable fuel
consumed in those years, we project that 1.83 billion total carryover
RINs will be available for compliance with the 2022 standards
(including the 2022 supplemental standard) as well. Assuming that the
market exactly meets the 2022, 2023, and 2024 standards, this is also
the number of carryover RINs that would be available for 2023, 2024,
and 2025 (including the 2023 supplemental standard).
---------------------------------------------------------------------------

    \90\ The calculations performed to estimate the size of the
carryover RIN bank can be found in the memorandum, ``Carryover RIN
Bank Calculations for 2023-2025 Proposed Rule,'' available in the
docket for this action.
---------------------------------------------------------------------------

    However, the standards we established for 2022 (including the 2022
supplemental standard) were significantly higher than the volume of
renewable fuel used in previous years, and the candidate volumes would
represent increases for 2025. While we project that the volume
requirements in 2022 and the candidate volumes for 2023-2025 could be
achieved without the use of carryover RINs, there is nevertheless some
uncertainty about how the market would choose to meet the applicable
standards. The result is that there remains some uncertainty
surrounding the ultimate number of carryover RINs that will be
available for compliance with the 2023, 2024, and 2025 standards
(including the 2023 supplemental standard). Furthermore, we note that
there have been enforcement actions in past years that have resulted in
the retirement of carryover RINs to make up for the generation and use
of invalid RINs and/or the failure to retire RINs for exported
renewable fuel. To the extent that there are enforcement actions in the
future, they could have similar results and require that obligated
parties or renewable fuel exporters settle past enforcement-related
obligations in addition to complying with the annual standards. In
light of these uncertainties, the net result could be a total carryover
RIN bank larger or smaller than 1.83 billion RINs.
b. Treatment of Carryover RINs for 2023-2025
    We evaluated the volume of carryover RINs projected to be available
and considered whether we should include any portion of them in the
determination of the candidate volumes that we analyzed or the volume
requirements that we propose for 2023-2025 (including the 2023
supplemental volume). Doing so would be equivalent to intentionally
drawing down the carryover RIN bank in setting those volume
requirements. We do not believe that this would be appropriate. In
reaching this proposed determination, we considered the functions of
the carryover RIN bank, its projected size, the uncertainties
associated with its projection, its potential impact on the production
and use of renewable fuel, the ability and need for obligated parties
to draw on it to comply with their obligations (both on an individual
basis and on a market-wide basis), and the impacts of drawing it down
on obligated parties and the fuels market more broadly. As previously
described, the bank of carryover RINs provides important and necessary
programmatic functions--including as a cost spike buffer--that will
both facilitate individual compliance and provide for smooth overall
functioning of the program. We believe that a balanced consideration of
the possible role of carryover RINs in achieving the volume
requirements, versus maintaining an adequate bank of carryover RINs for
important programmatic functions, is appropriate when EPA exercises its
discretion under its statutory authorities.
    Furthermore, as noted earlier, the advanced biofuel and total
renewable fuel standards established for 2022 are significantly higher
than the volume of renewable fuel used in previous years. As we
explained in the 2020-2022 final rule, while we believe that the market
can make sufficient renewable fuel available to meet the 2022
standards, there may be some challenges, and carryover RINs will be
available for those obligated parties who choose to use them for
compliance.\91\ In addition, in this action we are for the first time
proposing to establish volume requirements for three years
prospectively. This inherently adds uncertainty and makes it more
challenging to project with accuracy the number of carryover RINs that
will actually be available for each of these years. Given these
factors, and the uneven holding of carryover RINs among obligated
parties, we believe that further increasing the volume requirements
after 2022 with the intent to draw down the carryover RIN bank could
lead to significant deficit carryovers and non-compliance by some
obligated parties that own relatively few or no carryover RINs. We do
not believe this would be an appropriate outcome. Therefore, consistent
with the approach we have taken in recent annual rules, we are not
proposing to include carryover RINs in the candidate volumes, nor to
set the 2023, 2024, and 2025 volume requirements (including the 2023
supplemental standard) at levels that would intentionally draw down the
bank of carryover RINs.
---------------------------------------------------------------------------

    \91\ 87 FR 39600 (July 1, 2022).
---------------------------------------------------------------------------

    We are not determining that 1.83 billion RINs is a bright-line
threshold for the number of carryover RINs that provides sufficient
market liquidity and allows the carryover RIN bank to play its
important programmatic functions. As in past years, we are instead
evaluating, on a case-by-case basis, the size of the carryover RIN bank
in the context of the RFS standards and the broader transportation fuel
market at this time. Based upon this holistic, 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 is capable of achieving in 2023-2025.
Conversely, while an even larger carryover RIN bank may provide greater
assurance of market liquidity, we do not believe it would be
appropriate to set the standards at levels specifically designed to
increase the number of carryover RINs available to obligated parties.
5. Summary
    Based on our analysis of supply-related factors, we identified a
set of candidate volumes for each of the component categories which we
believe represent achievable levels of supply (domestic production and/
or import) and consumption.

                Table III.C.5-1--Candidate Volume Components Derived From Supply-Related Factors
                                               [Million RINs] \a\
----------------------------------------------------------------------------------------------------------------
                                                                       2023            2024            2025
----------------------------------------------------------------------------------------------------------------
Cellulosic biofuel (D3 & D7)....................................             719           1,419           2,131
Biomass-based diesel (D4).......................................           5,389           5,689           5,760
Other advanced biofuel (D5).....................................             256             256             256
Conventional renewable fuel (D6)................................          14,455          14,505          14,534
----------------------------------------------------------------------------------------------------------------
\a\ The D codes given for each component category are defined in 40 CFR 80.1425(g). D codes are used to identify
  the statutory categories which can be fulfilled with each component category according to 40 CFR
  80.1427(a)(2).

    These are the candidate volumes that we further analyzed according
to the other economic and environmental factors required under the
statute in CAA 211(o)(2)(B)(ii). Those additional analyses are
described in Section IV. Details of the individual biofuel types and
feedstocks that make up these candidate volumes are provided in the
DRIA. In Section VI, we discuss our proposed volumes based on a
consideration of all of the factors that we analyzed.
    Note that the volumes shown in Table III.C.5-1 represent the total
candidate volumes consumed for each component category of renewable
fuel, not the volume requirements. The volumes of non-cellulosic
advanced biofuel having a D code of 4 or 5, for instance, represent
volumes consumed in fulfillment of the BBD volume requirement, the
advanced biofuel volume requirement, and the total renewable fuel
volume requirement, including that portion of the implied volume for
conventional renewable fuel that cannot be met with ethanol. The volume
requirements that we are proposing to establish for 2023-2025, in
contrast, are based not only on an analysis of the supply-related
factors as discussed at the beginning of this Section III, but also on
a consideration of the other factors that we analyzed as required by
the statute. Below is a summary of the candidate volumes. Section VI
provides more comprehensive discussion of our consideration of all
factors leading to our determination of the proposed volume targets.

                                       Table III.C.5-2--Candidate Volumes
                                               [Million RINs] \a\
----------------------------------------------------------------------------------------------------------------
                                                                       2023            2024            2025
----------------------------------------------------------------------------------------------------------------
Cellulosic biofuel..............................................             719           1,419           2,131
Non-cellulosic advanced biofuel \b\.............................           5,100           5,200           5,300
Advanced biofuel................................................           5,819           6,619           7,431
Conventional renewable fuel \b\.................................      \a\ 15,000          15,250          15,250
                                                                 -----------------------------------------------
    Total renewable fuel........................................          20,819          21,869          22,681
----------------------------------------------------------------------------------------------------------------
\a\ Does not include the 250 million gallon supplemental volume requirement to address the 2016 remand under
  ACE.
\b\ These are implied volume requirements, not regulatory volume requirements.

D. Baselines

    In order to estimate the impacts of the candidate volumes, we must
identify an appropriate baseline. The baseline reflects the alternative
collection of biofuel volumes by feedstock, production process (where
appropriate), biofuel type, and use which would be anticipated to occur
in the absence of applicable standards, and acts as the point of
reference for assessing the impacts. To this end, we have developed a
``No RFS'' scenario that we use as the baseline for analytical
purposes. Many of the same supply-related factors that we used to
develop the candidate volumes were also relevant in developing the No
RFS baseline.
    We also considered other possible baselines that, as described
below, we are not using to assess all the impacts of the candidate
volumes. We discuss the alternative baselines here in an effort to
describe our reasoning for the public and interested stakeholders, and
because we understand there are differing, informative baselines that
could be used in this type of analysis. Ultimately, we concluded that
the No RFS scenario is the most appropriate to use.
1. No RFS Program
    Broadly speaking, the RFS program is designed to increase the use
of renewable fuels in the transportation sector beyond what would occur
in the absence of the program. It is appropriate, therefore, to use a
scenario representing what would occur if the RFS program did not exist
as the baseline for estimating the costs and impacts of the candidate
volumes. Such a ``No RFS'' baseline is consistent with the Office of
Management and Budget's Circular A-4, which says that the appropriate
baseline would normally ``be a `no action' baseline: what the world
will be like if the proposed rule is not adopted.'' In the final rule
establishing the standards for 2020-2022, we indicated that a No RFS
baseline would be preferable to using a previous year's volume
requirements as the baseline, but that we could not develop such a
baseline in the time available for that action.\92\
---------------------------------------------------------------------------

    \92\ See 87 FR 39600, 39626 (July 1, 2022). See also,
``Renewable Fuel Standard (RFS) Program: RFS Annual Rules--
Regulatory Impact Analysis'' at 50, EPA-420-R-22-008, June 2022.
---------------------------------------------------------------------------

    Importantly, a ``No RFS'' baseline would not be equivalent to a
market scenario wherein no biofuels were used at all. Prior to the RFS
program, both biodiesel and ethanol were used in the transportation
sector, whether due to state or local incentives, tax credits, or a
price advantage over conventional petroleum-based gasoline and diesel.
This same situation would exist in 2023-2025 in the absence of the RFS
program. Federal, state, and local tax credits, incentives, and support
payments will continue to be in place

for these fuels, as well as state programs such as blending mandates
and Low Carbon Fuel Standard (LCFS) programs. Furthermore, now that
capital investments in renewable fuels have been made and markets have
been oriented towards their use, there are strong incentives in place
for continuing their use even if the RFS program were to disappear. As
a result, it would be improper and inaccurate to attribute all use of
renewable fuel in 2023-2025 to the applicable standards under the RFS
program.
    To inform our assessment of the volume of biofuels that would be
used in the absence of the RFS program for the years 2023 through 2025,
we began by analyzing the trends in biofuel blending in prior years.
Assessing these trends is important because the economics for blending
biofuels changes from year to year based on biofuel feedstock and
petroleum product prices and other factors which affect the relative
economics for blending biofuels into petroleum-based transportation
fuels. A biofuel plant investor and the financiers who fund their
projects will review the historical, current, and perceived future
economics of the biofuel market when deciding whether to fund the
construction of biofuel plants, and our analysis attempted to account
for these factors.
    The economic analysis for 2023-2025 compares the biofuel value with
the fossil fuel it displaces, at the point that the biofuel is blended
with the fossil fuel, to assess whether the biofuel provides an
economic advantage. If the biofuel is lower cost than the fossil fuel
it displaces, it is assumed that the biofuel would be used absent the
RFS standards. The economic analysis that we conducted to assess the
volume of biofuel that would likely be produced and consumed in the
absence of the RFS program mirrors the cost analysis described in
Section IV.C, but there is one primary difference and a number of other
differences. The primary difference is that the economic analysis
relative to the No RFS baseline assesses whether the fuels industry
would find it economically advantageous to blend the biofuel into the
petroleum fuel in the absence of the RFS program, whereas the social
cost analysis reflects the overall impacts on consumers (society at
large). The primary example of a social cost not considered for the No
RFS economic analysis is the fuel economy effect due to the lower
energy density of the biofuel, as this cost is borne by consumers, not
the fuels industry. Other ways that the No RFS economic analysis is
different from the social cost analysis include:
     In the context of assessing production costs, we amortized
the capital costs at a 10 percent after-tax rate of return more typical
for industry investment instead of the 7 percent before-tax rate of
return used for social costs.
     We assessed biofuel distribution costs to the point where
it is blended into fossil fuel, not all the way to the point of use
that is necessary for estimating the fuel economy cost.
     While we generally do not account for the fuel economy
disadvantage of most biofuels for the No RFS economic analysis, the
exception is E85 where the lower fuel economy of using E85 is so
obvious to vehicle owners that they demand a lower price to make up for
this loss of fuel economy. As a result, retailers are forced to price
E85 lower than the primary alternative E10 to account for this bias and
they must consider this in their decisions to blend and sell E85. A
similar situation exists with E15, although it is not clear what the
factors are for E15 and this is discussed in more detail in the No RFS
discussion in DRIA Chapter 2.
    We added these various cost components together to reflect the cost
of each biofuel.
    We conducted a similar cost estimate for the fossil fuels being
displaced since their relative cost to biofuels is used to estimate the
net cost of using biofuels. Unlike for biofuels, we did not calculate
production costs for the fossil fuels. Instead, we projected their
production costs based solely on wholesale price projections by the
Energy Information Administration in its Annual Energy Outlook (AEO).
    We also considered any applicable federal or state programs,
incentives, or subsidies that could reduce the apparent blending cost
of the biofuel at the terminal. For instance, there are a number of
state programs that create subsidies for biodiesel and renewable diesel
fuel, the largest being offered by California and Oregon through their
LCFS programs. We accounted for state and local biodiesel mandates by
including their mandated volume regardless of the economics. Several
states offer tax credits for blending ethanol at 10 volume percent.
Other states offer tax credits for E85, of which the largest is in New
York. We are not aware of any state tax credits or subsidies for E15.
In the case of higher ethanol blends, the retail cost associated with
the equipment and/or use of compatible materials needed to enable the
sale of these newer fuels is assumed to be reduced by 50 percent due to
the Federal and/or state grant programs such as USDA's Higher Blends
Infrastructure Incentive Program (HBIIP).
    For most biofuels, the economic analysis provided consistent
results, indicating that they are either economical in all years or are
not economical in any year. However, this was not true for biodiesel
and renewable diesel, where the results varied from year to year. Such
swings in the economic attractiveness of biodiesel and renewable diesel
confound efforts on the part of investors to project future returns on
their investments. Thus, to smooth out the swings in the economics for
using biodiesel and renewable diesel and look at it the way investors
would have in the absence of the RFS program, we made two different key
assumptions. First, the economics for biodiesel and renewable diesel
were modeled starting in 2009 and the trend in its use was made
dependent on the relative economics in comparison to petroleum diesel
over a four year period. As a result, the first year modeled was
actually 2012. Second, the estimated biodiesel and renewable diesel
volumes were limited in the analysis to no greater volume than what
occurred under the RFS program in any year, since the existence of the
RFS program would be expected to create a much greater incentive for
using these biofuels than if no RFS program were in place.
    An economic analysis was also conducted for cellulosic biofuels,
including cellulosic ethanol, corn kernel fiber ethanol, and biogas.
Since the volumes of these biofuels were much smaller, a more
generalized approach was used in lieu of the detailed state-by-state
analysis conducted for corn ethanol, biodiesel, and renewable diesel
fuel.
    The No RFS baseline for 2023-2025 is summarized below in Table
III.D.1-1. A more complete description of the No RFS baseline and its
derivation is provided in DRIA Chapter 2.

                    Table III.D.1-1--Biofuel Consumption in 2023-2025 Under a No RFS Baseline
                                                 [Million RINs]
----------------------------------------------------------------------------------------------------------------
                                                                       2023            2024            2025
----------------------------------------------------------------------------------------------------------------
Cellulosic biofuel (D3 & D7)....................................             356             385             417
Biomass-based diesel (D4).......................................           1,374           1,374           1,374
Other advanced biofuel (D5).....................................             216             216             216
Conventional renewable fuel (D6)................................          13,750          13,730          13,693
----------------------------------------------------------------------------------------------------------------

    Our analysis shows that corn ethanol is economical to use up to the
E10 blendwall without the presence of the RFS program. Conversely,
higher ethanol blends would generally not be economic without the RFS
program, except for some small volume of E85 in the state of New York
which offers a large E85 blending subsidy. Some volume of biodiesel is
estimated to be blended based on state mandates in the absence of the
RFS program, and some additional volume of both biodiesel and renewable
diesel is estimated to be economical to use without the RFS program,
primarily in California due to the LCFS incentives. The volume of CNG
from biogas and imported ethanol from sugarcane are projected to be
consumed in California due to the economic support provided by their
LCFS. There would be no renewable electricity used as transportation
fuel under a No RFS baseline since we are proposing to establish the
eRIN program through this action. However, we expect that the biogas
used to produce that renewable electricity would still be produced
under a No RFS baseline as discussed in DRIA Chapter 2.1.
2. Alternative Approaches to the No RFS Baseline
    We also considered several other ways to identify a No RFS
baseline. However, we do not believe they would be appropriate as they
would be unlikely to represent the world in 2023-2025 as it would
likely be in the absence of the RFS program. For instance, the RFS
program went into effect in 2006 with a default percentage standard
specified in the statute. As 2005 represents the most recent year for
which the RFS requirements did not apply, it could be used as the
baseline in assessing costs and impacts of the candidate volumes.
However, a significant number of changes to other factors that
significantly affect the fuels sector have occurred between 2005 and
the 2023-2025 period to which this action applies, including changes in
state requirements, tax subsidies, tariffs, international supply, total
fuel demand, crude oil prices, feedstock prices, and fuel economy
standards. All of these have influenced the economical use of renewable
fuel during the intervening period, and it is infeasible to model all
these interactions. As a result, using 2005 as the baseline would lead
to a highly speculative assessment of costs and impacts that neglects
important market and regulatory realities. Therefore, we do not believe
that a 2005 baseline would be appropriate for this rulemaking.
    In the 2010 RFS2 rulemaking that created the RFS2 regulatory
program that was required by EISA, one of the baselines that we used
was the 2007 version of EIA's AEO which provided projections of
transportation fuel use, including the use of renewable fuel, out to
2030.\93\ This is the most recent version of the AEO that projected
fuel use in the absence of the statutory volume targets specified in
the Energy Independence and Security Act of 2007; all subsequent
versions of the AEO have included the current RFS program in their
projections. While the 2007 version of the AEO includes projections for
the timeframe of interest in this action, 2023-2025, it suffers from
the same drawbacks as using fuel use in 2005 as the baseline. Namely, a
significant number of other changes have occurred between 2007 when the
projections were made and the 2023-2025 period to which this action
applies. For the same reasons, then, we do not believe that the
projections in AEO 2007 would be an appropriate baseline.
---------------------------------------------------------------------------

    \93\ 75 FR 14670 (March 26, 2010).
---------------------------------------------------------------------------

3. Previous Year Volume Requirements
    The applicable volume requirements established for one year under
the RFS program do not roll over automatically to the next, nor do the
volume requirements that apply in one year become the default volume
requirements for the following year in the event that no volume
requirements are set for that following year. Nevertheless, the volume
requirements established for the previous year represent the most
recent set of volume requirements that the market was required to meet,
and the fuels industry as a whole can be expected to have adjusted its
operations accordingly. Since the previous year's volume requirements
represent the starting point for any adjustments that the market may
need to make to meet the next year's volume requirements, they
represent another informational baseline for comparison, and we have
used previous year standards as a baseline in previous annual standard-
setting rulemakings.
    The 2022 volume requirements were finalized on July 1, 2022, and
are shown in Table III.D.3-1.\94\
---------------------------------------------------------------------------

    \94\ 87 FR 39600 (July 1, 2022).

             Table III.D.3-1--Final 2022 Volume Requirements
------------------------------------------------------------------------
                                                                 Volume
                           Category                             (billion
                                                                 RINs)
------------------------------------------------------------------------
Cellulosic biofuel...........................................       0.63
Biomass based diesel \a\.....................................       2.76
Advanced biofuel.............................................       5.63
Total renewable fuel.........................................      20.63
------------------------------------------------------------------------
\a\ The BBD volumes are in physical gallons (rather than RINs).

    In the final rule that established these volume requirements, we
discussed the fact that the preferable baseline would have been a No
RFS baseline, but that it could not be developed in the time available.
For this proposed rule for 2023-2025, we again believe that the No RFS
baseline is preferable and should be used since it is now available. As
a result, we have not used the 2022 volume requirements as a baseline
to estimate all of the impacts of the candidate volumes for 2023-2025.
However, as an additional informational case, we have estimated the
costs alone with respect to the 2022 volume requirements in order to
allow comparison to the analysis and results presented in recent annual
rules. For this purpose, we needed to estimate a mix of biofuels and
associated feedstocks that would represent a reasonable way that the
market will respond to the finalized 2022 volume requirements. This
assessment is provided in the DRIA in Chapter 2.

4. Previous Year Actual Consumption
    In most annual standard-setting rules, we have used the previous
year's volume requirements as the baseline against which the impacts of
the next year's volume requirements would be assessed. In the final
rule establishing the volume requirements and percentage standards for
2021 and 2022, however, we instead used the actual consumption in 2020
as a baseline for the purposes of estimating the impacts of those
standards. We did this because the previous year's (2020) volume
requirements were revised in that same action to represent actual
consumption in that year. That approach was also consistent with the
approach we took in the rulemaking which established the volume
requirements for 2014, 2015, and 2016.\95\ In that rule, the impacts of
the volume requirements for 2015 were compared to the actual volumes
consumed in 2014, and the impacts of the volume requirements for 2016
were compared to the actual volumes consumed in 2015.\96\
---------------------------------------------------------------------------

    \95\ 80 FR 77420 (December 14, 2015).
    \96\ The 2015 volumes were based on actual consumption data for
January-September and a projection for October-December.
---------------------------------------------------------------------------

    We acknowledge that actual consumption in a previous year would
have the advantage that the mix of biofuel types and associated
feedstocks are known and would not need to be estimated as would be
required when using the previous year's volume requirements as a
baseline. However, we have not used the previous year's actual
consumption as a baseline in this action because, as explained earlier,
we believe that the No RFS baseline is superior. Moreover, the use of
actual consumption from a previous year has the drawback that the
resulting comparison would conflate the impacts of the program with
whatever unique market circumstances existed in that previous year.

E. Volume Changes Analyzed

    In general, our analysis of the economic and environmental impacts
of the candidate volumes derived and discussed above was based on the
differences between our assessment of how the market would respond to
those candidate volumes (summarized in Table III.C.4-1) and the No RFS
baseline (summarized in Table III.D.1-1). Those differences are shown
below. Details of this assessment, including a more precise breakout of
those differences, can be found in DRIA Chapter 2. Note that this
approach is squarely focused on the differences in volumes between the
No RFS baseline and the candidate volumes; our analysis does not, in
other words, assess impacts from total biofuel use in the United
States.

 Table III.E-1--Changes in Biofuel Consumption in the Transportation Sector in Comparison to the No RFS Baseline
                                                 [Million RINs]
----------------------------------------------------------------------------------------------------------------
                                                                       2023            2024            2025
----------------------------------------------------------------------------------------------------------------
Cellulosic biofuel (D3 & D7)....................................             363           1,034           1,714
Biomass-Based Diesel (D4).......................................           4,015           4,315           4,386
Other Advanced Biofuel (D5).....................................              40              40              40
Conventional Renewable Fuel (D6)................................             706             776             840
----------------------------------------------------------------------------------------------------------------

    Note that the change in cellulosic biofuel shown in the table above
for 2024 and 2025 is primarily due to the increased use of biogas for
electricity. Moreover, these values represent changes in the use of
cellulosic biofuel in the transportation sector, not changes in the
production of cellulosic biofuel. For renewable electricity in
particular, we project that there will be no change in production in
the 2023-2025 timeframe as a result of the standards we set. Instead,
renewable electricity that is already generated will shift from general
distribution on the grid to use as a transportation fuel. As described
in more detail in DRIA Chapter 3, we took this distinction into account
in our analysis of the impacts of the candidate volumes.

IV. Analysis of Candidate Volumes

    As described in Section II.B, the statute specifies a number of
factors that EPA must analyze in making a determination of the
appropriate volume requirements to establish for years after 2022 (and
for BBD, years after 2012). A full description of the analysis for all
factors is provided in the DRIA. In this section we provide a summary
of the analysis of a selection of factors for the candidate volumes
derived from supply-related factors as described in the previous
section (see Table III.C.5-2 for the candidate volumes, and Table
III.E-1 for the corresponding volume changes in comparison to the No
RFS baseline), along with some implications of those analyses. In
Section VI we provide our consideration of all factors in determining
the volume requirement that we believe would be appropriate for 2023-
2025.

A. Climate Change

    CAA section 211(o)(2)(B)(ii) states that the basis for setting
applicable renewable fuel volumes after 2022 must include, among other
things, ``an analysis of . . . the impact of the production and use of
renewable fuels on the environment, including on . . . climate
change.'' While the statute requires that EPA base its determinations,
in part, on an analysis of the climate change impact of renewable
fuels, it does not require a specific type of analysis. The CAA
requires evaluation of lifecycle greenhouse gas (GHG) emissions as part
of the RFS program,\97\ and GHG emissions contribute to climate
change,\98\ so we believe it is reasonable to use lifecycle GHG
emissions

estimates as a proxy for climate change impacts.
---------------------------------------------------------------------------

    \97\ See CAA section 211(o)(1)(H) (empowering the Administrator
to determine lifecycle greenhouse gas emissions) and CAA section
211(o)(2)(A)(i) (requiring the Administrator to ``ensure that
transportation fuel sold or introduced into commerce in the United
States . . . contains . . . renewable fuel . . . [that] achieves at
least a 20 percent reduction in lifecycle greenhouse gas emissions
compared to baseline lifecycle greenhouse gas emissions.,'' where
the 20 percent reduction threshold applies to renewable fuel
``produced from new facilities that commence construction after
December 19, 2007.'').
    \98\ Extensive additional information on climate change is
available in other EPA documents, as well as in the technical and
scientific information supporting them. See 74 FR 66496 (December
15, 2009) (finding under CAA section 202(a) that elevated
concentrations of six key well-mixed GHGs may reasonably be
anticipated to endanger the public health and welfare of current and
future generations); 81 FR 54421 (August 15, 2016) (making a similar
finding under CAA section 231(a)(2)(A)).
---------------------------------------------------------------------------

    To support the GHG emission reduction goals of EISA, Congress
required that biofuels used to meet the RFS obligations achieve certain
GHG reductions based on a lifecycle analysis (LCA). To qualify as a
renewable fuel under the RFS program, a fuel must be produced from
approved feedstocks and have lifecycle GHG emissions that are at least
20 percent less than the baseline petroleum-based gasoline and diesel
fuels. The CAA defines lifecycle emissions in section 211(o)(1)(H) to
include the aggregate quantity of significant direct and indirect
emissions associated with all stages of fuel production and use.
Advanced biofuels and biomass-based diesel are required to have
lifecycle GHG emissions that are at least 50 percent less than the
baseline fuels, while cellulosic biofuel is required to have lifecycle
emissions at least 60 percent less than the baseline fuels. Congress
also allowed for facilities that existed or were under construction
when EISA was passed to be grandfathered into the RFS program and
exempt from the lifecycle GHG emission reduction requirements.
    In the March 2010 RFS2 rule (75 FR 14670) and in subsequent agency
actions, EPA estimated the lifecycle GHG emissions from different
biofuel production pathways; that is, the emissions associated with the
production and use of a biofuel, including indirect emissions, on a
per-unit energy basis. Since the existing LCA methodology was developed
for the March 2010 RFS2 rule, there has been more research on the
lifecycle GHG emissions associated with transportation fuels in general
and crop-based biofuels in particular. New models have been developed
to evaluate biofuels and more models--developed for other purposes--
have been modified to evaluate the GHG emissions associated with
biofuel production and use. There has also been rapid growth in
available data on land use, farming practices, crude oil extraction and
many other relevant factors. While our existing LCA estimates for the
RFS program remain within the range of more recent estimates, we
acknowledge that the biofuel GHG modeling framework EPA has previously
relied upon is old, and that an updated framework is needed. In this
rulemaking, EPA is not proposing to reopen the related aspects of the
2010 RFS2 rule or any prior EPA lifecycle greenhouse gas analyses,
methodologies, or actions. That is beyond the scope of this rulemaking.
However, EPA has initiated work to develop a revised modeling framework
of the GHG impacts associated with biofuels. We intend to present the
results of a model comparison exercise in the final rulemaking as an
initial step in this update to our modeling framework. As an interim
step in the process, for this proposed rule, we present biofuel LCA
estimates from the range of published values from the scientific/
technical literature.
    Our assessment of the climate change impacts of the candidate
volumes relies on an extrapolation of lifecycle GHG analyses. As we did
in the 2020-2022 RVO rulemaking, this approach involves multiplying
lifecycle emissions of individual fuels by the change in the candidate
volumes of that fuel to quantify the GHG impacts. We repeat this
process for each fuel (e.g., corn ethanol, soybean biodiesel, landfill
biogas CNG) to estimate the overall GHG impacts of the candidate
volumes. In the 2020-2022 RVO rulemaking, we applied the LCA estimates
that we developed in the March 2010 RFS2 rule (75 FR 14670) and in
subsequent agency actions. In this rulemaking, we are updating our
approach to use a range of LCA estimates that are in the literature.
Instead of providing one estimate of the GHG impacts of each candidate
volume, we provide a high and low estimate of the potential GHG
impacts, which is inclusive of the values we estimated in the 2010 RFS
final rule and subsequent agency actions. We then use this range of
values for considering the GHG impacts of the candidate renewable fuel
volumes that change relative to the No RFS baseline described and
developed in Section III.
    As described in more detail in the DRIA, to develop the new range
of LCA values, we conducted a high-level review of relevant literature
for the biofuel pathways (combination of biofuel type, feedstock, and
production process) that would be most likely to satisfy the candidate
renewable fuel volumes. Our literature review was broad and includes
studies that estimate the lifecycle GHG emissions associated with the
relevant biofuel pathways and the petroleum-based fuels they replace.
Our compilation includes journal articles, major reports and studies
that inform biofuel-related policies. We included studies that were
published after the March 2010 RFS2 rule, as that rule considered the
available science at the time. In cases where there were multiple
studies that include updates to the same general model and approach, we
included only the most recent study. However, we include a subset of
older estimates that are still used for particular regulatory programs
or that continue to be widely cited for other reasons. We focused on
estimates of the average type of each fuel produced in the United
States.\99\ For example, for corn ethanol, we focused on estimates for
average corn ethanol production from natural gas-fired dry mill
facilities, as that is the predominant mode of corn ethanol production
in the United States.\100\ Some of the studies included estimate
lifecycle GHG emissions whereas others only estimate land use change
GHG emissions. For purposes of developing a quantitative range of
estimates of the overall GHG impacts of the candidate volumes in the
DRIA, we relied only on the available LCA estimates; however, our
qualitative discussion includes a review of the literature that covers
only land use change estimates.
---------------------------------------------------------------------------

    \99\ We note that lifecycle GHG emissions are also influenced by
the use of advanced technologies and improved production practices.
For example, corn ethanol produced with the adoption of advanced
technologies or climate smart agricultural practices can lower LCA
emissions. Corn ethanol facilities produce a highly concentrated
stream of CO2 that lends itself to carbon capture and
sequestration (CCS). CCS is being deployed at ethanol plants and has
the potential to reduce emissions for corn-starch ethanol,
especially if mills with CCS use renewable sources of electricity
and other advanced technologies to lower their need for thermal
energy. Climate smart farming practices are being widely adopted at
the feedstock production stage and can lower the GHG intensity of
biofuels. For example, reducing tillage, planting cover crops
between rotations, and improving nutrient use efficiency can build
soil organic carbon stocks and reduce nitrous oxide emissions.
    \100\ Lee, U., et al. (2021). ``Retrospective analysis of the US
corn ethanol industry for 2005-2019: implications for greenhouse gas
emission reductions.'' Biofuels, Bioproducts and Biorefining.
---------------------------------------------------------------------------

    The range of values in the literature for different types of
renewable fuels varies considerably, particularly for crop-based
biofuels. The ranges of estimates for non-crop based biofuel pathways
are narrower relative to the crop-based pathways (See Table IV.A-1).
Based on our literature review we can also make some general
observations about what contributes to lower and higher GHG estimates.
For crop-based biofuels, higher GHG estimates tend to be associated
with assessments that show greater land use change emissions, assumed
higher levels of energy and fertilizer use for feedstock production,
and more intensive energy use for biofuel production. Lower GHG
emissions are generally characterized by improvements in technology
over time lower land use change emissions (e.g., estimates that include
more intensive use of existing agricultural land through double-
cropping and other practices that increase yield without bringing more
land into production), widespread

adoption of agricultural practices intended to maintain soil carbon
(e.g., cover crops), and the trend toward more efficient biofuel
production practices. Consistent with our prior estimates, our
literature compilation also suggests that biofuels produced from
byproducts and wastes tend to have lower lifecycle GHG emissions than
crop-based biofuels. For example, the GHG estimates for renewable
diesel produced from used cooking oil are significantly lower than
those for renewable diesel produced from soybean oil. For these non-
crop-based pathways, different approaches of accounting for co-products
can have a large effect on results, as well as whether pre-existing
markets for these feedstocks will be backfilled. An important factor
dictating the GHG emissions associated with biogas-to-CNG pathways
include the extent of methane leakage during the collection,
processing, and transport of renewable natural gas.

 Table IV.A-1--Lifecycle GHG Emissions Ranges Based on Literature Review
                               [gCO2e/MJ]
------------------------------------------------------------------------
                 Pathway                             LCA range
------------------------------------------------------------------------
Petroleum Gasoline.......................  84 to 98.
Petroleum Diesel.........................  84 to 94.
Corn Starch Ethanol......................  38 to 116.
Soybean Oil Biodiesel....................  14 to 73.
Soybean Oil Renewable Diesel.............  26 to 87.
Used Cooking Oil Biodiesel...............  12 to 32.
Used Cooking Oil Renewable Diesel........  12 to 37.
Tallow Biodiesel.........................  15 to 58.
Tallow Renewable Diesel..................  14 to 81.
Distillers Corn Oil Biodiesel............  10 to 37.
Distillers Corn Oil Renewable Diesel.....  12 to 46.
Natural Gas CNG..........................  72 to 81.
Landfill Gas CNG.........................  9 to 70.
Manure Biogas CNG........................  -533 to 44.
------------------------------------------------------------------------

    Our compilation of the current literature reveals a wide range of
estimates of the lifecycle GHG emissions associated with renewable
fuels. The range of estimates is particularly wide for fuels derived
from crop-based feedstocks due to variation in land use change GHG
estimates. There is also a wide range of estimates for tallow renewable
diesel depending on whether or not the studies allocate GHG emissions
from meat production to the tallow or treat it as a byproduct.
Estimates for landfill gas and manure biogas CNG vary substantially
based on assumptions about methane emissions in the baseline scenario.
Given the ongoing uncertainty associated with the science of analyzing
biofuel GHG effects, our current assessment of the GHG impacts does not
support significantly raising or lowering the candidate volumes derived
from the supply-related factors discussed in Section III.
    For the final rule, we intend to advance our understanding of the
lifecycle GHG emissions associated with changes in crop-based biofuel
consumption, including through new modeling of biofuel lifecycle GHG
impacts and a comparison of available models for biofuel GHG analysis.
In the DRIA we discuss models that have been used since 2010 to
estimate biofuel GHG emissions, including the market-mediated indirect
emissions associated with increasing the production of crop-based
fuels. We intend to run similar scenarios through some of these models
and to compare the results. For example, we intend to align the amount
of U.S. biofuel consumption in a reference scenario and use the models
to estimate the GHG emissions associated with scenarios that include an
increased volume of corn ethanol and separately an increased volume of
soybean oil biodiesel. We also intend to compare key input assumptions
used in the models, and time permitting, align some of these
assumptions.
    We believe the model comparison exercise will provide valuable
information about the capabilities of these models, and the effects of
model choice and key input assumptions on biofuel lifecycle GHG
estimates. While this model comparison exercise can provide helpful
information for the final rule, we recognize that crop-based biofuel
lifecycle GHG emissions are inherently uncertain to a large degree.
Thus, we do not expect this exercise to produce a single robust
estimate of the GHG impacts associated with the volume requirements
that will be established with the final rule. However, we do expect
this model comparison exercise to advance our understanding for the
final rule, by more precisely locating the reasons that model estimates
differ, and by identifying future priorities for updating and aligning
particular assumptions across the models.
    We invite comment on the range of lifecycle GHG emissions impacts
of the biofuels considered as part of this proposed rulemaking, and
input on the proposed approach, or other potential approaches, for
conducting a model comparison exercise for the final rule. We invite
comment on the scope of this review as well as comment on the specific
studies included in the review. We also invite comment on how this
information may be used to inform the final rule. Given the different
types of modeling frameworks currently available, we also invite
comments on the appropriateness of these different approaches for
conducting lifecycle GHG emissions analysis and whether model results
can or should be weighted if we choose a multi-model approach to
assessing GHG emissions for purposes of RFS volumes assessment. Since
models treat time differently (e.g., different time steps, static
versus dynamic models), we invite comment on the most appropriate way
to handle the GHG impacts of biofuels over time. As we undertake this
expanded examination of the changes in GHG emissions attributable to
biofuels and the RFS program, we solicit input on how we should refine
our analysis by revising or incorporating various effects such as land
use change, the effectiveness of conservation programs targeted at soil
sequestration of carbon, international leakage (e.g., effects of
potentially backfilling vegetable oil feedstocks with palm oil),
facility-level variability in GHG emissions, and others. We also
request comment on how we can incorporate new research that examines
the effectiveness of the RFS program in mitigating GHG emissions.

B. Energy Security

    Another factor that we are required under the statute to analyze is
energy security. Changes in the required volumes of renewable fuel can
affect the financial and strategic risks associated with imports of
petroleum, which in turn would have a direct impact on national energy
security.
    The candidate volumes for the years 2023-2025 would represent
increases in comparison to previous years and, also, increases in
comparison to a No RFS baseline. Increasing the use of renewable fuels
in the U.S. displaces domestic consumption of petroleum-based fuels,
which results in a reduction in U.S. imports of petroleum and
petroleum-based fuels. A reduction of U.S. petroleum imports reduces
both financial and strategic risks caused by potential sudden
disruptions in the supply of imported petroleum to the U.S., thus
increasing U.S. energy security.
    Energy independence and energy security are distinct but related

concepts.\101\ The goal of U.S. energy independence is the elimination
of all U.S. imports of petroleum and other foreign sources of
energy.\102\ U.S. energy security is broadly defined as the continued
availability of energy sources at an acceptable price.\103\ Most
discussions of U.S. energy security revolve around the topic of the
economic costs of U.S. dependence on oil imports.
---------------------------------------------------------------------------

    \101\ Greene, D. 2010. Measuring energy security: Can the United
States achieve oil independence? Energy Policy 38, pp. 1614-1621.
    \102\ Ibid.
    \103\ Ibid.
---------------------------------------------------------------------------

    The U.S.'s oil consumption had been gradually increasing in recent
years (2015-2019) before dropping dramatically as a result of the
COVID-19 pandemic in 2020.\104\ Domestic oil consumption in 2022
returned to pre-COVID-19 levels and is expected to be relatively steady
during the timeframe of this proposed rule, 2023-2025. The U.S. has
increased its production of oil, particularly ``tight'' (i.e., shale)
oil, over the last decade.\105\ Mainly as a result of this increase,
the U.S. became a net exporter of crude oil and petroleum-based
products in 2020 and is now projected to be a net exporter of crude oil
and petroleum-based products during the time frame of this proposed
rule, 2023-2025.\106\ \107\ This is a significant reversal of the
U.S.'s net export position since the U.S. had been a substantial net
importer of crude oil and petroleum-based products starting in the
early 1950s.\108\
---------------------------------------------------------------------------

    \104\ U.S. Energy Information Administration. 2022. Total
Energy. Monthly Energy Review. Table 3.1. Petroleum Overview. March.
    \105\ https://www.eia.gov/energyexplained/oil-and-petroleum-products/images/u.s.tight_oil_production.jpg.
    \106\ https://www.eia.gov/energyexplained/oil-and-petroleum-products/imports-and-exports.php.
    \107\ U.S. Energy Information Administration. 2022. Annual
Energy Outlook 2022. Reference Case. Table A11. Petroleum and Other
Liquids Supply and Disposition.
    \108\ See EIA https://www.eia.gov/energyexplained/oil-and-petroleum-products/imports-and-exports.php.
---------------------------------------------------------------------------

    More recently, in the beginning of 2022, world oil prices have
risen fairly rapidly. For example, as of January 3, 2022, the West
Texas Intermediate (WTI) crude oil price was roughly $76 per barrel.
The WTI oil price increased to roughly $124 per barrel on March 8th,
2022, a 63 percent increase.\109\ High and volatile oil prices in 2022
are a result of a combination of several factors: supply not rising
fast enough to meet rebounding world oil demand from increased economic
activity as COVID-19 recedes, reduced supply from some leading oil-
producing nations, and geopolitical events/conflicts (i.e., war in
Ukraine). It is not clear to what extent the current oil price
volatility will continue, increase, or be transitory in the 2023-2025
period addressed by this proposed rule.
---------------------------------------------------------------------------

    \109\ U.S. Energy Information Administration daily spot prices,
available at: https://www.eia.gov/dnav/pet/pet_pri_spt_s1_d.htm.
---------------------------------------------------------------------------

    Although the U.S. is projected to be a net exporter of crude oil
and petroleum-based products over the 2023-2025 timeframe, energy
security remains a concern. U.S. refineries still rely on significant
imports of heavy crude oil from potentially unstable regions of the
world. Also, oil exporters with a large share of global production have
the ability to raise or lower the price of oil by exerting their market
power through the Organization of Petroleum Exporting Countries (OPEC)
to alter oil supply relative to demand. These factors contribute to the
vulnerability of the U.S. economy to episodic oil supply shocks and
price spikes, even when the U.S. is projected to be an overall net
exporter of crude oil and petroleum-based products.
    In order to understand the energy security implications of reducing
U.S. oil imports, EPA has worked with Oak Ridge National Laboratory
(ORNL), which has developed approaches for evaluating the social costs/
impacts and energy security implications of oil use, labeled the oil
import or oil security premium. ORNL's methodology estimates two
distinct costs/impacts of importing petroleum into the U.S., in
addition to the purchase price of petroleum itself: first, the risk of
reductions in U.S. economic output and disruption to the U.S. economy
caused by sudden disruptions in the supply of imported oil to the U.S.
(i.e., the macroeconomic disruption/adjustment costs); and secondly,
the impacts that changes in U.S. oil imports have on overall U.S. oil
demand and subsequent changes in the world oil price (i.e., the
``demand'' or ``monopsony'' impacts).\110\
---------------------------------------------------------------------------

    \110\ Monopsony impacts stem from changes in the demand for
imported oil, which changes the price of all imported oil.
---------------------------------------------------------------------------

    For this proposed rule, as has been the case for past EPA
rulemakings under the RFS program, we consider the monopsony component
estimated by the ORNL methodology to be a transfer payment, and thus
exclude it from the estimated quantified benefits of the candidate
volumes.\111\ Thus, we only consider the macroeconomic disruption/
adjustment cost component of oil import premiums (i.e., labeled
macroeconomic oil security premiums below), estimated using ORNL's
methodology.
---------------------------------------------------------------------------

    \111\ See the DRIA for more discussion of EPA's assessment of
monopsony impacts of this proposed rule. Also, see the previous EPA
GHG vehicle rule for a discussion of monopsony oil security
premiums, e.g., Section 3.2.5, Oil Security Premiums Used for this
Rule, RIA, Revised 2023 and Later Model Year Light-Duty Vehicle GHG
Emissions Standards, December 2021, EPA-420-F-21-077.
---------------------------------------------------------------------------

    For this proposed rule, EPA and ORNL have worked together to revise
the oil import premiums based upon recent energy security literature
and the most recently available oil price projections and energy market
and economic trends from EIA's 2022 Annual Energy Outlook.\112\ We do
not consider military cost impacts from reduced oil use from the
candidate volumes due to methodological issues in quantifying these
impacts. A discussion of the difficulties in quantifying military cost
impacts is in the DRIA accompanying this proposal.
---------------------------------------------------------------------------

    \112\ See DRIA Chapter 5.4.2 for how the macroeconomic oil
security premiums have been updated based upon a review of recent
energy security literature on this topic.
---------------------------------------------------------------------------

    To calculate the energy security benefits of the candidate volumes,
we are using the ORNL macroeconomic oil security premiums combined with
estimates of annual reductions in aggregate U.S. crude oil imports/
petroleum product imports as a result of the candidate volumes. A
discussion of the methodology used to estimate changes in U.S. annual
crude oil imports/U.S. petroleum product imports from the candidate
volumes is provided in the DRIA. Table IV.B-1 below presents the
macroeconomic oil security premiums and the total energy security
benefits for the candidate volumes for 2023-2025.

   Table IV.B-1--Macroeconomic Oil Security Premiums and Total Energy
                   Security Benefits for 2023-2025 \a\
------------------------------------------------------------------------
                                 Macroeconomic oil
                                 security premiums       Total energy
             Year                 (2021$/barrel of    security benefits
                                  reduced imports)     (millions 2021$)
------------------------------------------------------------------------
2023 (Including the                           $3.37                 $211
 supplemental standard).......        ($0.88-$6.20)           ($55-$389)
2023 (Excluding the                           $3.37                 $200
 supplemental standard).......        ($0.88-$6.20)           ($52-$368)
2024..........................                $3.46                 $219
                                      ($0.89-$6.36)           ($56-$403)
2025..........................                $3.46                 $223
                                      ($0.83-$6.40)           ($53-$412)
------------------------------------------------------------------------
\a\ Top values in each cell are the mean values, while the values in
  parentheses define 90 percent confidence intervals.

C. Costs

    We assessed the cost impacts for the renewable fuels expected to be
used for the candidate volumes relative to a No RFS baseline, described
in Section III.C.1. Table III.E-1 provides a summary of the volume
changes that we project would occur if the candidate volumes were to be
established as applicable volume requirements for 2023-2025, and it is
these volume changes relative to the No RFS baseline which we analyzed
for costs.
1. Methodology
    This section provides a brief discussion of the methodology used to
estimate the costs of the candidate volume changes over the years of
2023-2025. A more detailed discussion of how we estimated the renewable
fuel costs, as well as the fossil fuel costs being displaced, is
contained in DRIA Chapter 9.
    The cost analysis compares the cost of an increase in biofuel to
the cost of the fossil fuel it displaces. There are various components
to the cost of each biofuel:
     Production cost, of which the biofuel feedstock usually is
the prominent factor
     Distribution cost. Because the biofuel often has a
different energy density, the distribution costs are estimated all the
way to the point of use to capture the full fuel economy effect of
using these fuels.
     In the case of ethanol blended as E10, there is a blending
value that mostly incorporates ethanol's octane value realized by lower
gasoline production costs, but also a volatility cost that accounts for
ethanol's blending volatility in RVP controlled gasoline.
     In the case of higher ethanol blends, there is a retail
cost since retail stations usually need to add equipment or use
compatible materials to enable the sale of these newer fuels.
     Fuel economy cost which is reflected in the relative
fossil fuel volume being displaced.
    We added these various cost components together to reflect the cost
of each biofuel.
    We conducted a similar cost estimate for the fossil fuels being
displaced since their relative cost to the biofuels is used to estimate
the net cost of the increased use of biofuels. Unlike for biofuels,
however, we did not calculate production costs for the fossil fuels
since their production costs are inherent in the wholesale price
projections provided by the Energy Information Administration in its
Annual Energy Outlook.
2. Estimated Cost Impacts
    In this section, we summarize the overall results of our cost
analysis based on changes in the use of renewable fuels which displace
fossil fuel use. The renewable fuel costs presented here do not reflect
any tax subsidies for renewable fuels which might be in effect, since
such subsidies are transfer payments which are not relevant under a
societal cost analysis. A detailed discussion of the renewable fuel
costs relative to the fossil fuel costs is contained in DRIA Chapter
10.
    For each year for which we are proposing volumes, Table IV.C.2-1
provides the total annual cost of the candidate volumes while Table
IV.C.2-2 provides the per-unit cost (per gallon or per thousand cubic
feet) of the biofuel. For the year 2023 costs, the estimated costs are
shown both without and with the costs associated with the Supplemental
Standard renewable fuel volume. For both the total and per-unit cost,
the cost of the total change in renewable fuel volume is expressed over
the gallons of the respective fossil fuel in which it is blended. For
example, the costs associated with corn ethanol relative to that of
gasoline are reflected as a cost over the entire gasoline pool, and
biodiesel and renewable diesel costs are reflected as a cost over the
diesel fuel pool. Biogas displaces natural gas use as CNG in trucks, so
it is reported relative to natural gas supply.
    This rulemaking includes proposed regulatory provisions that would
govern the generation of RINs from renewable electricity (eRINs)
generated from biogas (see Section VIII). Because there is a
substantial quantity of biogas already being used to generate
electricity today, and there is a limited number of electricity-powered
vehicles projected to be in the light-duty vehicle fleet through 2025,
we determined that existing biogas to electricity generation would be
sufficient to supply light-duty vehicles. As a result, the RFS program
would not drive any new biogas-based electricity production through
2025 and as a consequence there would be no biogas-to-electricity
production costs. Nevertheless, since biogas to electricity will be a
new aspect of the RFS program, the sunk cost of using biogas to produce
electricity is estimated and presented in the RIA Chapter.

                                       Table IV.C.2-1--Total Social Costs
                                           [Million 2021 dollars] \a\
----------------------------------------------------------------------------------------------------------------
                                                                     2023 with
                                                       2023        supplemental        2024            2025
                                                                     standard
----------------------------------------------------------------------------------------------------------------
Gasoline........................................             252             252             258             303

Diesel..........................................          10,855          11,512           8,919           8,651
Natural Gas.....................................              92              92             119             148
                                                 ---------------------------------------------------------------
    Total.......................................          11,119          11,856           9,295           9,100
----------------------------------------------------------------------------------------------------------------
\a\ Total cost of the renewable fuel expressed over the fossil fuel it is blended into.

                           Table IV.C.2-2--Per-Gallon or Per-Thousand Cubic Feet Costs
                                                 [2021 dollars]
----------------------------------------------------------------------------------------------------------------
                                                                     2023 with
                                      Units            2023        supplemental        2024            2025
                                                                     standard
----------------------------------------------------------------------------------------------------------------
Gasoline......................  [cent]/gal......            0.18            0.18            0.18            0.22
Diesel........................  [cent]/gal......            19.6            20.7            16.2            15.6
Natural Gas...................  [cent]/thousand             0.30            0.30            0.39            0.48
                                 ft\3\.
Gasoline and Diesel...........  [cent]/gal......             5.7             6.1             4.8             4.7
----------------------------------------------------------------------------------------------------------------
\a\ Per-gallon or per thousand cubic feet cost of the renewable fuel expressed over the fossil fuel it is
  blended into; the last row expresses the cost over the obligated pool of gasoline and diesel fuel.

    The biofuel costs are higher than the costs of the gasoline,
diesel, and natural gas that they displace as evidenced by the
increases in fuel costs shown in the above table associated with the
candidate volumes. Despite increasing renewable diesel fuel volumes
over the 2023 to 2025 year timeframe, the projected cost to diesel fuel
for the increased renewable diesel volume is decreasing due to year-
over-year decreases in projected vegetable oil prices which in turn
decreases the relative cost of renewable diesel. However, as described
more fully in DRIA Chapter 10, our assessment of costs did not yield a
specific threshold value below which the incremental costs of biofuels
are reasonable and above which they are not. In Section VI we consider
these directional inferences along with those for the other factors
that we analyzed in the context of our discussion of the proposed
volumes for 2023-2025.
3. Cost To Transport Goods
    We also estimated the impact of the candidate volumes on the cost
to transport goods. However, it is not appropriate to use the social
cost for this analysis because the social costs are effectively reduced
by the cellulosic and biodiesel subsidies and other market factors. The
per-unit costs from Table IV.C.2-2 are adjusted with estimated RIN
prices that account for the biofuel subsidies and other market factors,
and the resulting values can be thought of as retail costs. Consistent
with our assessment of the fuels markets, we have assumed that
obligated parties pass through their RIN costs to consumers and that
fuel blenders reflect the RIN value of the renewable fuels in the price
of the blended fuels they sell. More detailed information on our
estimates of the fuel price impacts of this rule can be found in DRIA
Chapter 10.5. Table IV.C.3-1 summarizes the estimated impacts of the
candidate volumes on gasoline, diesel, and natural gas fuel prices at
retail when the costs of each biofuel is amortized over the fossil fuel
it displaces. In the final row of the table, we show the estimated
retail costs when the total costs are amortized evenly over the entire
gasoline and diesel fuel pools since these are the obligated fuel
pools.

                       Table IV.C.3-1--Estimated Effect of Biofuels on Retail Fuel Prices
                                                  [[cent]/gal]
----------------------------------------------------------------------------------------------------------------
                                                                       2023            2024            2025
----------------------------------------------------------------------------------------------------------------
Relative to No RFS Baseline:
    Gasoline....................................................             0.6             1.8             3.1
    Diesel......................................................            14.1            14.4            14.9
    Gasoline and Diesel.........................................             4.3             5.3             6.3
Relative to 2022 Baseline:
    Gasoline....................................................             1.7             2.6             3.3
    Diesel......................................................             0.8             1.5             3.2
    Gasoline and Diesel.........................................             1.4             2.3             3.3
----------------------------------------------------------------------------------------------------------------

    For estimating the cost to transport goods, we focus on the impact
on diesel fuel prices since trucks which transport goods are normally
fueled by diesel fuel. Reviewing the data in Table IV.C.3-1, the
largest projected price increase is 14.9[cent] per gallon for diesel
fuel in 2025.
    The impact of fuel price increases on the price of goods can be
estimated based upon a study conducted by the United States Department
of Agriculture (USDA) which analyzed the impact of fuel prices on the
wholesale price of

produce.\113\ Applying the price correlation from the USDA study would
indicate that the 14.9[cent] per gallon diesel fuel cost increment
associated with the 2025 RFS volumes which increases retail prices by
about 5.1 percent, would then increase the wholesale price of produce
by about 1.18 percent. If produce being transported by a diesel truck
costs $3 per pound, the increase in that product's price would be
$0.035 per pound.\114\ If all the estimated program subsidized costs
are averaged over the combined gasoline and diesel fuel pool as shown
in the bottom row of Table IV.C.3-1, the impact on produce prices would
be proportionally lower based on the lower per-gallon cost.
---------------------------------------------------------------------------

    \113\ Volpe, Richard; How Transportation Costs Affect Fresh
Fruit and Vegetable Prices; United States Department of Agriculture;
November 2013.
    \114\ Comparing Prices on Groceries; May 4, 2021: http://www.coupons.com/thegoodstuff/comparing-prices-on-groceries.
---------------------------------------------------------------------------

D. Comparison of Costs and Impacts

    As explained in Section III of this rule, the statutory factors for
which the potential impacts of the candidate volumes are reasonably
quantifiable are compared against a No RFS baseline, which assumes the
RFS program remains intact through 2022 but ceases to exist thereafter.
The statute does not specify how EPA should assess each factor,
including whether the assessment must be quantitative or qualitative.
For two of the statutory factors (fuel costs and energy security
benefits) we were able to quantify and monetize the expected impacts of
the candidate volumes.\115\ Information and specifics on how fuel costs
are calculated are presented in DRIA Chapter 9, while energy security
benefits are discussed in DRIA Chapter 4. A summary of the fuel costs
and energy security benefits is shown in Tables IV.D-1 and 2. Other
factors, such as job creation and the price and supply of agricultural
commodities, are quantified but have not been monetized. Further
information and the quantified impacts of the candidate volumes on
these factors can be found in the DRIA. We were not able to quantify
many of the impacts of the candidate volumes, including impacts on many
of the statutory factors such as the environmental impacts (water
quality and quantity, soil quality, etc.) and rural economic
development. We request comment on our assessment of these factors and
methods that could be used to quantify the impact of the RFS on these
factors in future actions.
---------------------------------------------------------------------------

    \115\ Due to the uncertainty related to the GHG emission impacts
of the candidate volumes (discussed in further detail in Chapter 3.2
of the RIA) we have not included a quantified projection of the GHG
emission impacts in this proposal.

                                Table IV.D-1--Fuel Costs of the Candidate Volumes
                                          [2021 Dollars, millions] \a\
----------------------------------------------------------------------------------------------------------------
                                                                                Discount rate
                              Year                               -----------------------------------------------
                                                                        0%              3%              7%
----------------------------------------------------------------------------------------------------------------
2023:
    Excluding Supplemental Standard.............................          11,199          11,199          11,199
    Including Supplemental Standard.............................          11,856          11,856          11,856
2024............................................................           9,295           9,025           8,687
2025............................................................           9,100           8,578           7,948
Cumulative Discounted Costs:
    Excluding Supplemental Standard.............................  ..............          28,801          27,835
    Including Supplemental Standard.............................  ..............          29,458          28,492
----------------------------------------------------------------------------------------------------------------
\a\ These costs represent the costs of producing and using biofuels relative to the petroleum fuels they
  displace. They do not include other factors, such as the potential impacts on soil and water quality or
  potential GHG reduction benefits.

                         Table IV.D-2--Energy Security Benefits of the Candidate Volumes
                                            [2021 Dollars, millions]
----------------------------------------------------------------------------------------------------------------
                                                                                Discount rate
                              Year                               -----------------------------------------------
                                                                        0%              3%              7%
----------------------------------------------------------------------------------------------------------------
2023:
    Excluding Supplemental Standard.............................             200             200             200
    Including Supplemental Standard.............................             211             211             211
2024............................................................             219             213             205
2025............................................................             223             210             195
Cumulative Discounted Benefits:
    Excluding Supplemental Standard.............................  ..............             623             600
    Including Supplemental Standard.............................  ..............             634             611
----------------------------------------------------------------------------------------------------------------

    Regardless of whether or not we were able to quantify or monetize
the impact of the candidate volumes on each of the statutory factors,
consideration of these factors is still required by the statute. We
request comment generally on how costs and benefits quantified in this
proposed rule are calculated and accounted for, as well as methods to
quantify and monetize additional statutory factors where appropriate.

E. Assessment of Environmental Justice

    Although the statute identifies a number of environmental factors
that we must analyze as described in Section I, environmental justice
is not explicitly included in those factors. However, Executive Order
12898 (59 FR 7629; February 16, 1994) establishes federal executive
policy on environmental justice. Its main provision directs federal
agencies, to the greatest extent practicable and permitted by law, to

make environmental justice part of their mission by identifying and
addressing, as appropriate, disproportionately high and adverse human
health or environmental effects of their programs, policies, and
activities on minority populations and low-income populations in the
United States. EPA defines environmental justice as the fair treatment
and meaningful involvement of all people regardless of race, color,
national origin, or income with respect to the development,
implementation, and enforcement of environmental laws, regulations, and
policies.\1\ Executive Order 14008 (86 FR 7619; February 1, 2021) also
calls on federal agencies to make achieving environmental justice part
of their missions ``by developing programs, policies, and activities to
address the disproportionately high and adverse human health,
environmental, climate-related and other cumulative impacts on
disadvantaged communities, as well as the accompanying economic
challenges of such impacts.'' It also declares a policy ``to secure
environmental justice and spur economic opportunity for disadvantaged
communities that have been historically marginalized and overburdened
by pollution and under-investment in housing, transportation, water and
wastewater infrastructure and health care.'' EPA also released its
``Technical Guidance for Assessing Environmental Justice in Regulatory
Analysis'' (U.S. EPA, 2016) to provide recommendations that encourage
analysts to conduct the highest quality analysis feasible, recognizing
that data limitations, time and resource constraints, and analytic
challenges will vary by media and circumstance.
    When assessing the potential for disproportionately high and
adverse health or environmental impacts of regulatory actions on
minority populations, low-income populations, tribes, and/or indigenous
peoples, EPA strives to answer three broad questions:
     Is there evidence of potential environmental justice (EJ)
concerns in the baseline (the state of the world absent the regulatory
action)? Assessing the baseline allows EPA to determine whether pre-
existing disparities are associated with the pollutant(s) under
consideration (e.g., if the effects of the pollutant(s) are more
concentrated in some population groups).
     Is there evidence of potential EJ concerns for the
regulatory option(s) under consideration? Specifically, how are the
pollutant(s) and its effects distributed for the regulatory options
under consideration?
     Do the regulatory option(s) under consideration exacerbate
or mitigate EJ concerns relative to the baseline?
    It is not always possible to quantitatively assess these questions,
though it may still be possible to describe then qualitatively.
    EPA's 2016 Technical Guidance does not prescribe or recommend a
specific approach or methodology for conducting an environmental
justice analysis, though a key consideration is consistency with the
assumptions underlying other parts of the regulatory analysis when
evaluating the baseline and regulatory options. Where applicable and
practicable, the Agency endeavors to conduct such an analysis. Going
forward, EPA is committed to conducting environmental justice analysis
for rulemakings based on a framework similar to what is outlined in
EPA's Technical Guidance, in addition to investigating ways to further
weave environmental justice into the fabric of the rulemaking process.
    In accordance with Executive Orders 12898 and 14008, as well as
EPA's 2016 Technical Guidance, we have assessed demographics near
biofuel and petroleum-based fuel facilities to identify populations
that may be affected by changes to fuel production volumes that result
in changes to air quality. The displacement of fuels such as gasoline
and diesel by biofuels has positive GHG benefits which
disproportionately benefit EJ communities. We have also considered the
effects of the RFS program on fuel and food prices, as low-income
populations often spend a larger percentage of their earnings on these
commodities compared to the rest of the U.S.
1. Air Quality
    There is evidence that communities with EJ concerns are impacted by
non-GHG emissions. Numerous studies have found that environmental
hazards such as air pollution are more prevalent in areas where racial/
ethnic minorities and people with low socioeconomic status (SES)
represent a higher fraction of the population compared with the general
population.116 117 118 119 Consistent with this evidence, a
recent study found that most anthropogenic sources of PM2.5,
including industrial sources, and light- and heavy-duty vehicle
sources, disproportionately affect people of color.\120\ There is also
substantial evidence that people who live or attend school near major
roadways are more likely to be of a minority race, Hispanic ethnicity,
and/or low socioeconomic status.121 122 123 As this
rulemaking would displace petroleum-based fuels with biofuels, we have
examined near-facility demographics of biodiesel, renewable diesel,
RNG, ethanol, and petroleum facilities.
---------------------------------------------------------------------------

    \116\ Mohai, P.; Pellow, D.; Roberts Timmons, J. (2009)
Environmental justice. Annual Reviews 34: 405-430. https://doi.org/10.1146/annurev-environ-082508-094348.
    \117\ Rowangould, G.M. (2013) A census of the near-roadway
population: public health and environmental justice considerations.
Trans Res D 25: 59-67. http://dx.doi.org/10.1016/j.trd.2013.08.003.
    \118\ Marshall, J.D., Swor, K.R.; Nguyen, N.P (2014)
Prioritizing environmental justice and equality: diesel emissions in
Southern California. Environ Sci Technol 48: 4063-4068. https://doi.org/10.1021/es405167f.
    \119\ Marshall, J.D. (2000) Environmental inequality: air
pollution exposures in California's South Coast Air Basin. Atmos
Environ 21: 5499-5503. https://doi.org/10.1016/j.atmosenv.2008.02.005.
    \120\ C.W. Tessum, D.A. Paolella, S.E. Chambliss, J.S. Apte,
J.D. Hill, J.D. Marshall (2021). PM2.5 polluters
disproportionately and systemically affect people of color in the
United States. Sci. Adv. 7, eabf4491.
    \121\ Rowangould, G.M. (2013) A census of the U.S. near-roadway
population: public health and environmental justice considerations.
Transportation Research Part D; 59-67.
    \122\ Tian, N.; Xue, J.; Barzyk. T.M. (2013) Evaluating
socioeconomic and racial differences in traffic-related metrics in
the United States using a GIS approach. J Exposure Sci Environ
Epidemiol 23: 215-222.
    \123\ Boehmer, T.K.; Foster, S.L.; Henry, J.R.; Woghiren-
Akinnifesi, E.L.; Yip, F.Y. (2013) Residential proximity to major
highways--United States, 2010. Morbidity and Mortality Weekly Report
62(3): 46-50.
---------------------------------------------------------------------------

    Emissions of non-GHG pollutants associated with the candidate
volumes, including, for example, PM, NOX, CO, SO2
and air toxics, occur during the production, storage, transport,
distribution, and combustion of petroleum-based fuels and
biofuels.\124\ EJ communities may be located near petroleum and biofuel
production facilities as well as their distribution systems. Given
their long history and prominence, petroleum refineries have been the
focus of past research which has found that vulnerable populations near
them may experience potential disparities in pollution-related health
risk from that source.\125\
---------------------------------------------------------------------------

    \124\ U.S. EPA (2022) Health and environmental effects of
pollutants discussed in chapter 4 of draft regulatory impact
analysis (DRIA) supporting proposed RFS standards for 2023-2025.
Memorandum from Rich Cook to Docket No. EPA-HQ-OAR-2021-0427, July
21, 2022.
    \125\ Final Petroleum Refinery Sector Risk and Technology Review
and New Source Performance Standards, https://www.epa.gov/sites/default/files/2016-06/documents/2010-0682_factsheet_overview.pdf.
---------------------------------------------------------------------------

    DRIA Chapter 4.1 summarizes what is known about potential air
quality impacts of the candidate volumes assessed for this rule. We
expect that

small increases in non-GHG emissions from biofuel production and small
reductions in petroleum-based emissions would lead to small changes in
exposure to these non-GHG pollutants for people living in the
communities near these facilities. We do not have the information
needed to understand the magnitude and direction of travel of facility-
specific emissions associated with the candidate volumes, and therefore
we are unable to evaluate impacts on air quality in the specific EJ
communities near biofuel and petroleum facilities. However, modeled
averaged facility emissions for biodiesel, ethanol, gasoline, and
diesel production do offer some insight into the differences these
near-facility populations may experience, as seen in DRIA Table 4.1.1-
1.
    Both biofuel facilities and petroleum refineries could see changes
to their production output as a result of candidate volumes analyzed in
this proposed rule, and as a result the air quality near these
facilities may change. We examined demographics based on 2020 American
Community Survey data near registered biofuel facilities and within 5
kilometers of petroleum refineries to identify any disproportionate
impacts these volume changes may have on nearby minority or low-income
populations.\126\ Information on these populations and potential
impacts upon them are further discussed in DRIA Chapter 9. Several
regional disparities have been identified in near-refinery populations.