biodiesel, and the supply of renewable diesel is projected to exceed
the supply of biodiesel in future years as renewable diesel production
and imports continue to grow.
[GRAPHIC] [TIFF OMITTED] TR12JY23.001

    There are also very small volumes of renewable jet fuel and heating
oil that qualify as BBD, and there are currently significant efforts
underway to incentivize growth in renewable jet fuel in particular
(often referred to as sustainable aviation fuel or SAF).\77\ Jet fuel
has qualified as a RIN-generating advanced biofuel under the RFS
program since 2010, and must achieve at least a 50 percent reduction in
GHGs in comparison to petroleum-based fuels. The technology and
feedstocks that can be used to produce SAF today are often the same as
those currently used to produce renewable diesel. For example, the same
process that produces renewable diesel from waste fats, oils, and
greases or plant oils generally

produces hydrocarbons in the distillation range of jet fuel that can be
separated and sold as SAF instead of being sold as renewable diesel.
While relatively little SAF has been produced since 2010--less than 15
million gallons per year--opportunities for increasing this category of
advanced biofuel exist. A new tax credit for SAF, which was included in
the Inflation Reduction Act, may result in increasing volumes of SAF
produced from existing renewable diesel production facilities. SAF
production from existing renewable diesel facilities would increase the
amount of renewable fuel available for a transportation sector that may
be otherwise particularly difficult to reduce carbon intensity;
however, it would likely result in a decrease in renewable diesel
production, with little or no net change in their overall production of
RIN-generating fuels.\78\ In this rule we have not separately projected
growth in SAF production, but we recognize that some of the projected
growth in renewable diesel production may instead be SAF from the same
production facilities. Other SAF production technologies and production
facilities also being developed could enable the future production of
SAF from new facilities and feedstocks that are not expected to impact
renewable diesel production.
---------------------------------------------------------------------------

    \77\ According to EMTS data renewable jet fuel supply has ranged
from 0-15 million gallons per year from 2014-2022. Jet fuel is
eligible to generate RINs per 40 CFR 80.1426(a)(1)(iv), provided all
other regulatory requirements are met.
    \78\ The equivalence values for renewable diesel and jet fuel
are similar, with renewable diesel generating 1.6-1.7 RINs per
gallon depending on the energy content of the fuel and Jet fuel
generally generating 1.6 RINs per gallon.
---------------------------------------------------------------------------

    In addition, in April 2022 the Biden Administration announced a new
Sustainable Aviation Fuel Grand Challenge to inspire the dramatic
increase in the production of sustainable aviation fuels to at least 3
billion gallons per year by 2030. This effort is accompanied by new and
ongoing funding opportunities to support sustainable aviation fuel
projects and fuel producers totaling up to $4.3 billion.
    The remainder of this section provides historical data on biodiesel
and renewable diesel production and production capacity, briefly
discusses potential feedstock limitations for biodiesel and renewable
diesel production in future years, and summarizes our assessment of the
rate of production and use of qualifying BBD from 2023 to 2025, and
some of the uncertainties associated with those volumes. Our
assessments of production capacity, available feedstocks, and likely
future production of biodiesel and renewable diesel in this final rule
reflect our consideration of the comments we received on this rule as
well as updated data not available at the time of the proposed rule.
Our projections of the likely future production of biodiesel and
renewable diesel in this final rule are higher than in the proposed
rule, particularly in 2025 due to higher projections of feedstock
availability. Further details on these volume projections can be found
in RIA Chapter 6.2.
a. Biodiesel
    Historically, the largest volumes of biomass-based diesel and
advanced biofuel supplied in the RFS program have been biodiesel.
Domestic biodiesel production increased from approximately 1.3 billion
gallons in 2014 to approximately 1.8 billion gallons in 2018. Since
2018 domestic biodiesel production decreased slightly, to approximately
1.6 billion gallons in 2022. The U.S. has also imported significant
volumes of biodiesel in previous years and has been a net importer of
biodiesel since 2013. Biodiesel imports reached a peak in 2016 and
2017, with the majority of the imported biodiesel coming from
Argentina.\79\ In August 2017, the U.S. announced tariffs on biodiesel
imported from Argentina and Indonesia.\80\ These tariffs were
subsequently confirmed in April 2018.\81\ Since that time no biodiesel
has been imported from Argentina or Indonesia, and net biodiesel
imports have been relatively small.
---------------------------------------------------------------------------

    \79\ EIA U.S. Imports by Country of Origin,https://www.eia.gov/dnav/pet/pet_move_impcus_a2_nus_EPOORDB_im0_mbbl_a.htm. According to
EIA data, 67 percent of all biodiesel imports in 2016 and 2017 were
from Argentina.
    \80\ 82 FR 40748 (Aug. 28, 2017).
    \81\ 83 FR 18278 (April 26, 2018).
---------------------------------------------------------------------------

    Available data suggests that there is significant unused biodiesel
production capacity in the U.S., and thus domestic biodiesel production
could grow without the need to invest in additional production
capacity. Consistent with comments we received on the rule, we have
updated our assessment of domestic biodiesel production capacity using
the latest information available from EIA. Data reported by EIA shows
that biodiesel production capacity in January 2023 was approximately
2.05 billion gallons per year.\82\ According to EIA data biodiesel
production capacity grew slowly from about 2.1 billion gallons in 2012
\83\ to a peak of approximately 2.5 billion gallons in 2018.\84\ EIA
reports that domestic biodiesel production capacity was approximately
2.5 billion gallons as recently as October 2021.\85\ This facility
capacity data is collected by EIA in monthly surveys, which suggests
that this capacity represents the production at facilities that are
currently producing some volume of biodiesel and likely does not
include inactive facilities that are far less likely to complete a
monthly survey. EPA separately collects facility capacity information
through the facility registration process. This data includes both
facilities that are currently producing biodiesel and those that are
inactive. EPA's data shows a total domestic biodiesel production
capacity of 3.1 billion gallons per year in April 2022, of which 2.8
billion gallons per year was at biodiesel facilities that generated
RINs in 2021. These estimates of domestic production capacity strongly
suggest that domestic biodiesel production capacity is unlikely to
limit domestic biodiesel production through 2025.
---------------------------------------------------------------------------

    \82\ EIA Monthly Biofuels Feedstock and Capacity Update, https://www.eia.gov/biofuels/update. Mar. 31, 2023 ().
    \83\ EIA Monthly Biodiesel Production Report. February 2013.
    \84\ EIA Monthly Biodiesel Production Report. February 2019.
    \85\ EIA Monthly Biofuels Feedstock and Capacity Update. January
31, 2023 (https://www.eia.gov/biofuels/update).
---------------------------------------------------------------------------

b. Renewable Diesel and SAF
    Renewable diesel and SAF are currently produced using the same
feedstocks and very similar production technologies, and in most cases
are produced at the same production facilities. Historically, greater
incentives have been available for renewable diesel production, which
has caused many of these production facilities to maximize renewable
diesel production. In the near term, we expect that any increase in SAF
production will result in a corresponding decrease in renewable diesel
production.\86\ In this section we have focused on renewable diesel
production, but we acknowledge that an increasing portion of this fuel
may be used as SAF in future years.
---------------------------------------------------------------------------

    \86\ We recognize that new technologies are being developed to
produce SAF from a wider variety of feedstocks. Production of SAF
using these technologies would not negatively impact renewable
diesel production. Through 2025, however, we expect that only
relatively modest volumes of these fuels might be produced.
---------------------------------------------------------------------------

    Renewable diesel has historically been produced and imported in
smaller quantities than biodiesel as shown in Figure III.B.2-1. In
recent years, however, domestic production of renewable diesel has
increased significantly. Renewable diesel production facilities
generally have higher capital costs and production costs relative to
biodiesel, which likely accounts for the much higher volumes

of biodiesel production relative to renewable diesel production to
date. The higher cost of renewable diesel production can largely be
offset through the benefits of economies of scale, since renewable
diesel facilities tend to be much larger than biodiesel production
facilities. More importantly, because renewable diesel more closely
resembles petroleum-based diesel than biodiesel fuel (both renewable
diesel and petroleum-based diesel are hydrocarbons while biodiesel is a
methyl-ester) renewable diesel can be blended at much higher levels
than biodiesel. This allows renewable diesel producers to benefit to a
greater extent from the LCFS credits in California and other states in
addition to the RFS incentives and the federal tax credit. The greater
ability for renewable diesel to generate credits under California's
LCFS program provides a significant advantage over biodiesel. Biodiesel
blends in California containing 6 to 20 percent biodiesel require the
use of an additive to comply with California's Alternative Diesel Fuels
Regulations, making the use of higher level biodiesel blends more
challenging in California.\87\ We expect that an increasing number of
states will adopt clean fuels programs, and that these programs could
provide an advantage to renewable diesel production relative to
biodiesel production in the U.S. See RIA Chapter 6.2 for further
discussion.
---------------------------------------------------------------------------

    \87\ CARB Alternative Diesel Fuels Regulations Frequently Asked
Questions. In 2021 nearly all renewable diesel consumed in the U.S.
was consumed in California. Together renewable diesel and biodiesel
represented approximately 26 percent of all diesel fuel consumed in
California in 2021.
---------------------------------------------------------------------------

    Total domestic renewable diesel production capacity has increased
significantly in recent years from approximately 280 million gallons in
2017 to approximately 2.9 billion gallons in January 2023.\88\
Additionally, a number of parties have announced plans to build new
renewable diesel production capacity with the potential to begin
production by the end of 2025. This new capacity includes new renewable
diesel production facilities, expansions of existing renewable diesel
production facilities, and the conversion of units at petroleum
refineries to produce renewable diesel.
---------------------------------------------------------------------------

    \88\ 2017 renewable diesel capacity based on facilities
registered in EMTS; January 2023 renewable capacity based on EIA
March 2023 Monthly Biofuels Feedstock and Capacity Update.
---------------------------------------------------------------------------

    We received numerous comments on the proposed rule related to
renewable diesel production capacity. These comments generally cited
projections that renewable diesel production capacity will grow
significantly through 2025, and many of these comments cited data and
projections from EIA. In this final rule we have updated our projection
of renewable diesel production capacity through 2025 based on updated
information from EIA, consistent with these comments. As in the
proposed rule, however, we expect that renewable diesel production
through 2025 will be limited to a level below production capacity
primarily due to limited feedstock availability, which is further
discussed later in Section III.B.2.c.
    EIA currently projects that renewable diesel production capacity
could reach nearly 6 billion gallons by 2025,\89\ though it is possible
that not all these announced projects will be completed, and not all of
those that are completed will necessarily produce renewable diesel in
the 2023-2025 timeframe addressed by this rule.\90\ In previous years,
domestic renewable diesel production has increased in concert with
increases in domestic production capacity, with renewable diesel
facilities generally operating at high utilization rates. In future
years we expect that feedstock limitations will result in renewable
diesel and biodiesel facilities operating below their production
capacity. Competition for qualifying feedstocks could also result in
reductions in biodiesel production if larger renewable diesel
facilities are able to out-compete smaller biodiesel producers for
feedstock.
---------------------------------------------------------------------------

    \89\ Domestic renewable diesel capacity could more than double
through 2025. EIA Today in Energy. Feb. 2, 2023.
    \90\ Reuters. CVR Pauses Renewable Diesel Plans as Feedstock
Prices Surge. August 3, 2021. Available at: https://www.reuters.com/business/energy/cvr-pauses-renewable-diesel-plans-feedstock-prices-surge-2021-08-03.
---------------------------------------------------------------------------

    In addition to domestic production of renewable diesel, the U.S.
has also imported renewable diesel, with nearly all of it produced from
FOG and imported from Singapore.\91\ In more recent years, the U.S. has
also exported increasing volumes of renewable diesel. Net imports of
renewable diesel were approximately 120 million gallons in 2021 and 130
million gallons in 2022. This situation, wherein significant volumes of
renewable diesel are both imported and exported, is likely the result
of a number of factors, including the design of the biodiesel tax
credit (which is available to renewable diesel that is either produced
or used in the U.S. and thus eligible for exported volumes as well),
the varying structures of incentives for renewable diesel (with the
level of incentives varying depending on the feedstocks used to produce
the renewable diesel varying as well as by country), and logistical
considerations (renewable diesel may be imported and exported from
different parts of the country). We are projecting that net renewable
diesel imports will continue through 2025 at approximately the levels
observed in recent years, as domestic producers export volumes to take
advantage of both the U.S. tax incentives and other incentives abroad.
However, we also recognize that increasing net imports of renewable
diesel could be a significant source of additional renewable fuel
supply in future years.
---------------------------------------------------------------------------

    \91\ EIA Monthly Renewable Diesel Imports by Country, available
at https://www.eia.gov/dnav/pet/pet_move_impcus_a2_nus_EPOORDO_im0_mbbl_m.htm.
---------------------------------------------------------------------------

c. BBD Feedstocks
    As was highlighted in the proposal, when considering the likely
production and import of biodiesel and renewable diesel in future
years, the availability of feedstock is a key consideration. We
received many comments on our assessment of the availability of BBD
feedstocks in the proposed rule. Many of these commenters stated that
the data from USDA \92\ that EPA used to project domestic soybean oil
production through 2025 was not appropriate for this use. For this
final rule we have updated our projections of soybean oil production in
the U.S. and canola oil production in Canada through 2025. Our current
projections of the production of these feedstocks are significantly
higher than our projections in the proposed rule (which did not
consider increased availability of canola oil from Canada \93\) and are
generally in alignment with the projections provided by the commenters
and discussions with market experts. As in our proposed rule, however,
we continue to believe that the availability of qualifying feedstocks
will serve to limit the production of biodiesel and renewable diesel
through 2025. We also continue to believe that when evaluating the
various statutory factors, the greatest benefits and fewest negative
impacts of these fuels occur when increased production of these fuels
is consistent with increased production of qualifying feedstocks
produced in North America. Our assessment of available feedstocks
(including our consideration of

comments on the proposed rule and data not available at the time of the
proposed rule) is discussed briefly in this section, and in greater
detail in RIA Chapter 6.2 and the RTC document.
---------------------------------------------------------------------------

    \92\ USDA Agricultural Projections to 2031.
    \93\ Since the analyses for the proposed rule were conducted,
EPA approved a pathway for renewable diesel produced from canola
oil. In addition, Canadian feedstocks are covered by an aggregate
compliance approach and are likely to be sourced from increased
production of canola oil rather than diverted from existing uses.
For a further discussion of the inclusion of canola oil from Canada
in our projection of available feedstocks for biodiesel and
renewable diesel production, see RTC Section 4.2.
---------------------------------------------------------------------------

    Currently, biodiesel and renewable diesel in the U.S. are produced
from a number of different feedstocks, including fats, oils and greases
(FOG), distillers corn oil, and virgin vegetable oils such as soybean
oil and canola oil. As domestic production of biodiesel has increased
since 2014, an increasing percentage of total biodiesel production has
been produced from soybean oil, with smaller increases in the use of
FOG, distillers corn oil, and canola oil.
[GRAPHIC] [TIFF OMITTED] TR12JY23.002

    Use of soybean oil to produce biodiesel increased from
approximately 10 percent of all domestic soybean oil production in the
2009/2010 agricultural marketing year to 42 percent in the 2021/2022
agricultural marketing year.\94\ In the intervening years, the total
increase in domestic soybean oil production and the increase in the
quantity of soybean oil used to produce biodiesel and renewable diesel
were very similar, indicating that the increase in oil production was
likely driven by the increasing demand for biofuel. However, as the
production of renewable diesel has increased in recent years it appears
that demand for soybean oil is growing faster than demand for soybean
meal. Notably, the percentage of the soybean value that came from the
soybean oil (rather than the meal and hulls) had been relatively stable
and averaged approximately 33 percent from 2016-2020. The percentage of
the soybean value that came from the soybean oil increased
significantly starting in 2021, reaching a high of 53 percent in
October 2021, before declining slightly to 43 percent in August 2022
(the most recent date for which data are available).
---------------------------------------------------------------------------

    \94\ USDA Oil Crops Yearbook. March 2023.
---------------------------------------------------------------------------

    Through 2020, most of the renewable diesel produced in the U.S. was
made from FOG and distillers corn oil, with smaller volumes produced
from soybean oil. While many biodiesel production facilities are unable
to use FOG and distillers corn oil, renewable diesel production
facilities are generally able to use them. Additionally, nearly all the
renewable diesel consumed in the U.S. is used in California due to the
combined value of RFS and LCFS incentives (together with the blenders'
tax credit). Under California's LCFS program renewable diesel produced
from FOG and distillers corn oil receive more credits than renewable
diesel produced from soybean oil.
    Available volumes of FOG and distillers corn oil from domestic
sources are expected to continue to increase in future years, but these
increases are expected to be limited. FOG are the byproducts of other
activities (rendering operations, for example), and production of FOG
is not responsive to increasing demand for biofuel production. We
therefore expect the availability of FOG to increase slowly, consistent
with the observed trend in recent years. Similarly, distillers corn oil
is a byproduct of ethanol production. Since we do not anticipate
significant growth in ethanol production in future years, we do not
project significant increases in the production of distillers corn oil
for biofuel production, as most ethanol production facilities currently
produce distillers corn oil. Therefore, if renewable diesel production
in future years increases rapidly as suggested by the large production
capacity announcements, it will likely require increased use of
vegetable oils such as soybean oil and canola oil, increased use of
imported feedstocks, or the use of feedstocks diverted from other
markets.
    Greater volumes of soybean oil are projected to be produced from
new or expanded soybean crushing facilities. Several parties have
announced plans to expand existing soybean crushing capacity and/or
build new soybean crushing facilities.\95\ This new crushing

capacity is expected to come online in the 2023-2025 timeframe.
Increased crushing of soybeans in the U.S. will increase domestic
soybean oil production. In this final rule we have updated our
projections of domestic soybean oil production through 2025 to better
reflect recent investments in domestic soybean crushing facilities that
are expected to begin operating by 2025.
---------------------------------------------------------------------------

    \95\ For example, see Demaree-Saddler, Holly, Cargill plans US
soy processing operations expansion, World Grain, March 4, 2021;
Sanicola, Laura, Chevron to invest in Bunge soybean crushers to
secure renewable feedstock, Reuters, Sept. 2, 2021.
---------------------------------------------------------------------------

    If domestic crushing of soybeans increases at the expense of
soybean exports, domestic vegetable oil production could be increased
without the need for additional soybean production. Alternatively,
increased demand for soybeans from new or expanded crushing facilities
could result in increased soybean production in the U.S or increasing
volumes of qualifying feedstocks such as soybean oil and canola oil may
be diverted from existing markets to produce renewable diesel, with
non-qualifying feedstocks such as palm oil used in place of soybean and
canola oil in food and oleochemical markets.
    We also expect that production of canola oil will increase in
future years due to expanding canola crushing capacity in Canada.
Similar to the investments in soybean crushing in the U.S., a number of
companies have announced investment in additional canola crushing
capacity, and some of these projects are already under construction.
Increasing canola oil production in Canada could provide an opportunity
for domestic renewable diesel producers to import canola oil for
biofuel production, however we expect that these parties will face
competition for this feedstock from Canadian biofuel producers as well
as food and other non-biofuel markets. The assessment of feedstock
availability for this final rule (discussed in greater detail in RIA
Chapter 6.2.3) includes volumes of imported canola oil we project could
be available to domestic BBD producers.
d. Projected BBD Production and Imports
    We project that the supply of BBD to the U.S. will increase through
2025. Consistent with our updated projections of feedstock availability
discussed in the preceding section, our projections of BBD production
and imports are higher in this final rule than in the proposed rule,
particularly in 2025. We project that the largest increases will come
from domestic renewable diesel as new production facilities come
online. We project slight decreases in the volume of biodiesel used in
the U.S. as new renewable diesel producers are able to out-compete some
existing biodiesel producers for limited feedstocks. One significant
factor that is likely to negatively impact biodiesel production
relative to renewable diesel production is that opportunities for
renewable diesel expansion in California are not constrained by
blending limits. Renewable diesel can therefore continue to benefit
from both LCFS credits and the RFS RIN incentives. In contrast,
continued biodiesel expansion in California is expected to be more
limited due to requirements for the use of additives in higher level
biodiesel blends. Consequently, for biodiesel to continue to expand, it
must do so primarily outside of California and without the added
financial incentive of the LCFS credits. This provides a significant
advantage to renewable diesel in the competition for access to new
feedstocks, particularly feedstocks with low carbon intensity (CI)
scores in California's LCFS program and Oregon and Washington's Clean
Fuels programs. While we project most of the biodiesel and renewable
diesel supplied to the U.S. will be produced domestically, we project
that imports of both biodiesel and renewable diesel will continue to
contribute to the supply of these fuels through 2025. We note that in
the first quarter of 2023 imports of biodiesel and renewable diesel,
and the feedstocks used to produce these fuels in the U.S., increased
substantially on a year-over-year basis, seemingly in response to the
proposed volume requirements for 2023-2025. See RIA Chapter 6.2 for
more information on the projected supply of biodiesel and renewable
diesel to the U.S. in 2023-2025. We take this data into consideration
both in our assessment of the candidate volumes of non-cellulosic
advanced biofuel (discussed in Section III.C.2) and the final volumes
of advanced and total renewable fuel (discussed in Section VI).
3. Other Advanced Biofuel
    In addition to BBD, other renewable fuels that qualify as advanced
biofuel have been consumed in the U.S. in the past and would be
expected to contribute to compliance with applicable volume
requirements in the years after 2022. These other advanced biofuels
include imported sugarcane ethanol, domestically produced advanced
ethanol, biogas that is purified and compressed to be used in CNG or
LNG vehicles, heating oil, naphtha, and renewable diesel that does not
qualify as BBD.\96\ However, these biofuels have been consumed in much
smaller quantities than biodiesel and renewable diesel in the past,
and/or have been highly variable.
---------------------------------------------------------------------------

    \96\ Renewable diesel produced through coprocessing vegetable
oils or animal fats with petroleum cannot be categorized as BBD but
remains advanced biofuel. See 40 CFR 80.1426(f)(1).
---------------------------------------------------------------------------

    We did not receive a significant number of comments suggesting
alternative projections of other advanced biofuel volumes. The comments
we did receive generally suggested higher volumes might be appropriate
due to expectations of increased production of SAF \97\ (which is
covered in Section III.B.2) and CNG/LNG produced from food waste or
other non-cellulosic feedstocks. For this final rule we used the same
general projection methodology as in the proposed rule, but we included
data from 2022 that was not available at the time of the proposed rule.
The inclusion of this additional data resulted in slightly higher
volumes of other advanced biofuels relative to the proposed rule.
---------------------------------------------------------------------------

    \97\ While the existing pathways for SAF qualify as BBD, rather
than advanced biofuel, some commenters stated that increasing
production of SAF would result in additional volumes of other
advanced biofuel.
---------------------------------------------------------------------------

    In order to estimate the volumes of these other advanced biofuels
that may be available in 2023-2025, we used the same general
methodology as in the proposed rule. This methodology was originally
presented in the annual rulemaking establishing the applicable
standards for 2020-2022.\98\ This methodology addresses the historical
variability in these categories of advanced biofuel while recognizing
that consumption in more recent years is likely to provide a better
basis for making future projections than consumption in earlier years.
Specifically, we applied a weighting scheme to historical volumes
wherein the weighting was higher for more recent years and lower for
earlier years. The result of this approach is shown in the table below.
Details of the derivation of these estimates can be found in RIA
Chapter 5.4.
---------------------------------------------------------------------------

    \98\ 87 FR 39600 (July 1, 2022).

    Table III.B.3-1--Estimate of Future Consumption of Other Advanced
                                 Biofuel
------------------------------------------------------------------------
                                                              Volume
                          Fuel                            (million RINs)
------------------------------------------------------------------------
Imported sugarcane ethanol..............................              95
Domestic ethanol........................................              27
CNG/LNG.................................................               6
Heating oil.............................................               3

Naphtha.................................................              55
Renewable diesel........................................             104
                                                         ---------------
    Total...............................................             290
------------------------------------------------------------------------

    As the available data does not permit us to identify an upward or
downward trend in the historical consumption of these other advanced
biofuels, we have used the volumes in Table III.B.3-1 for all years
covered in this final rule (i.e., 2023-2025).
4. Conventional Renewable Fuel
    Conventional renewable fuel includes any renewable fuel that is
made from renewable biomass as defined in 40 CFR 80.1401, does not
qualify as advanced biofuel, and meets one of the following criteria:
     Is demonstrated to achieve a minimum 20 percent reduction
in GHGs in comparison to the gasoline or diesel which it displaces; or
     Is exempt (``grandfathered'') from the 20 percent minimum
GHG reduction requirement due to having been produced in a facility or
facility expansion that commenced construction on or before December
19, 2007, as described in 40 CFR 80.1403.\99\
---------------------------------------------------------------------------

    \99\ CAA section 211(o)(2)(A)(i).
---------------------------------------------------------------------------

    Under the statute, there is no volume requirement for conventional
renewable fuel. Instead, conventional renewable fuel is that portion of
the total renewable fuel volume requirement that is not required to be
advanced biofuel. In some cases, it is referred to as an ``implied''
volume requirement. However, obligated parties are not required to
comply with it per se since any portion of it can be met with advanced
biofuel volumes in excess of that needed to meet the advanced biofuel
volume requirement.
    To estimate candidate volumes of conventional renewable fuel for
2023-2025, we focused primarily on projecting volumes of corn ethanol
consumption, which in turn is driven by total ethanol consumption. For
this final rule we have updated our projections of total ethanol
consumption and corn ethanol consumption based on the comments we
received and additional data that was not available for the proposed
rule. We also investigated potential volumes of non-advanced biodiesel
and renewable diesel.
a. Corn Ethanol
    Ethanol made from corn starch has dominated the renewable fuels
market on a volume basis in the past and is expected to continue to do
so for the time period addressed by this rulemaking.\100\ Corn starch
ethanol is prohibited by statute from being an advanced biofuel
regardless of its GHG performance in comparison to gasoline.\101\
---------------------------------------------------------------------------

    \100\ 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 in that year; grain
sorghum ethanol in 2022 was only 77 million gallons. Waste
industrial ethanol and ethanol made from non-cellulosic portions of
separated food waste have been produced more sporadically and at
even lower volumes. These other sources do not materially affect our
assessment of volumes of conventional ethanol that can be produced.
    \101\ CAA section 211(o)(1)(B)(i).
---------------------------------------------------------------------------

    Total domestic corn ethanol production capacity increased
dramatically between 2005 and 2010 and increased at a slower rate
thereafter. In 2022, production capacity had reached 17.7 billion
gallons.102 103 Available production capacity was
significantly underused in 2020 and to some degree in 2021 because the
COVID-19 pandemic depressed gasoline demand in comparison to previous
years and thus ethanol demand in the form of E10 (gasoline containing
10% denatured ethanol). Actual production of ethanol in the U.S.
reached 15.4 billion gallons in 2022, compared to 16.1 billion gallons
in 2018.\104\
---------------------------------------------------------------------------

    \102\ ``2022 Ethanol Industry Outlook--RFA,'' available in the
docket.
    \103\ ``Ethanol production capacity--EIA August 2022,''
available in the docket.
    \104\ ``EIA Monthly Energy Review, April 2023,'' 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 the demand for E0, E15, and E85. We
have incorporated projected growth in opportunities for sales of E15
and E85 into our assessment. There is an excess of production capacity
of ethanol and corn feedstock 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. Thus, consistent with the
proposed rule, 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 at significant 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.
While conventional biodiesel and renewable diesel could be used in
2023-2025, as in the proposed rule we are not projecting any volumes of
these fuels will be used in these years.\105\
---------------------------------------------------------------------------

    \105\ Data from EMTS shows some generation of D6 RINs for
biodiesel and renewable diesel in recent years, however these RINs
were retired using the retirement code ``renewable fuel used or
designated to be used in any application that is not transportation
fuel, heating oil, or jet fuel.'' These RINs therefore do not
represent qualifying fuel under the RFS program.
---------------------------------------------------------------------------

    Actual global production of palm oil biodiesel and renewable diesel
was about 4.5 billion gallons in 2021.\106\ 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 approximately 1 billion gallons, suggesting that
significant volumes of grandfathered biodiesel and renewable diesel
could be imported under favorable market conditions.
---------------------------------------------------------------------------

    \106\ Total worldwide production of biodiesel and renewable
diesel was 55 billion liters in 2021, of which 31 percent was from
palm oil. See OECD-FAO Agricultural Outlook 2022-2031, p.236,
available at https://www.oecd.org/development/oecd-fao-agricultural-outlook-19991142.htm.
---------------------------------------------------------------------------

    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.\107\ 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 with no conventional renewable diesel imported since
2017.\108\ The highest imported volume of total conventional biodiesel
and renewable diesel occurred in 2016 with 160 million gallons (258
million RINs).
---------------------------------------------------------------------------

    \107\ ``RIN supply as of 3-7-23,'' available in the docket.
    \108\ ``RIN supply as of 3-7-23,'' 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.\109\
---------------------------------------------------------------------------

    \109\ As discussed in Section VII.B, the gasoline+diesel
estimates used to calculate the percentage standards have
historically been lower than the gasoline+diesel volumes used by
obligated parties to determine their Renewable Volume Obligations
(RVO). Relatedly, the historical ethanol concentration values shown
in Figure III are likely to be higher than actual values due to some
underestimates of total gasoline demand.
[GRAPHIC] [TIFF OMITTED] TR12JY23.003

    As the average ethanol concentration approached and then exceeded
10 percent, the gasoline pool became saturated with E10, with a small,
likely stable volume of E0 and small but increasing volumes of E15 and
E85. The average ethanol concentration can exceed 10 percent only
insofar as the ethanol in E15 and E85 exceeds the ethanol content of
E10 and more than offsets the volume of E0.
    We used the same general methodology to project total ethanol
consumption in this final rule as in the proposed rule, but we updated
the projections of poolwide ethanol concentration and total gasoline
consumption using more recent data. This methodology is different than
the methodology used in previous RFS rules, which generally looked to
EIA projections of ethanol concentration in the gasoline pool. We have
used this new methodology to better account for the projected increase
in retail stations selling higher level blends such as E15 and
E85.\110\
---------------------------------------------------------------------------

    \110\ See RIA Chapter 6.5.1 for more information on our
projections of ethanol concentration in the gasoline pool.
---------------------------------------------------------------------------

    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. In
this final rule we updated both the correlations between E15 and E85
stations and poolwide ethanol consumption and our projections of the
number of E15 and E85 stations for 2023-2025. The results are shown in
Table III.B.5-1. While the projected ethanol concentration in 2023-2025
are similar to the projected concentrations from the proposed rule,
projected ethanol consumption for 2023-2025 is significantly lower due
to lower projected gasoline demand in these years in EIA's most recent
AEO. Details of these calculations can be found in the RIA.

             Table III.B.5-1--Projected Ethanol Consumption
------------------------------------------------------------------------
                                                             Projected
                                             Projected        ethanol
                  Year                        ethanol       consumption
                                           concentration     (million
                                                (%)          gallons)
------------------------------------------------------------------------
2023....................................           10.41          13,974
2024....................................           10.46          14,128
2025....................................           10.51          13,978
------------------------------------------------------------------------

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 analyzed under the other economic and environmental factors
required by the statute. This section describes the candidate volumes,
while Section IV summarizes the results of the additional analyses we
performed. Relative to the candidate volumes in the proposed rule, the
candidate volumes for cellulosic biofuel, BBD, and other advanced
biofuels in this final rule are all higher for all three years (after
accounting for the fact that we are not finalizing the proposed eRIN
provisions in this rule). The candidate volumes for conventional
biofuel in this final rule are lower than the volumes from the proposed
rule.
    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 equivalent to analyzing the statutory categories, since
doing so would effectively require us to evaluate the difference
between various statutory categories (e.g., assessing ``the difference
between volumes of advanced biofuel and total renewable fuel'' instead
of assessing ``the volume of conventional renewable fuel''), adding
unnecessary complexity 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
    In determining the candidate volumes for cellulosic biofuel, we
started by considering the statutory volume targets for 2010-2022. The
statutory volumes for cellulosic biofuel increased rapidly, from 100
million gallons in 2010 to 16 billion gallons in 2022 with the largest
increases in the later years. While notable on its own, it is even more
notable in comparison to the implied statutory volumes for the other
renewable fuel volumes. Statutory BBD volumes did not increase after
2012, implied conventional renewable fuel volumes did not increase
after 2015, and non-cellulosic advanced biofuel volume increases
tapered off in recent years with a final increment in 2022. Thus, the
clear focus of the statute by 2022 was on growth in cellulosic biofuel
volumes, which have the greatest greenhouse gas reduction threshold
requirement in the statute.\111\ The statutory cellulosic waiver
provision,\112\ while acknowledging that the statutory cellulosic
biofuel volumes may not be met, nevertheless effectively expresses
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
in the statute on cellulosic biofuel over time is likely due to
expectations that cellulosic biofuel has significant potential to
reduce GHG emissions (cellulosic biofuels are required to reduce GHG
emissions by 60 percent relative to the gasoline or diesel fuel they
displace), that cellulosic biofuel feedstocks could be produced or
collected with relatively few negative environmental impacts, that the
feedstocks would be comparable or cheaper in cost relative to other
fuel feedstocks, allowing for lower cost biofuels to be produced than
those produced from feedstocks without other primary uses such as food,
and that the technological breakthroughs needed to convert cellulosic
feedstocks into biofuel were likely imminent.
---------------------------------------------------------------------------

    \111\ CAA section 211(o)(1)(E). Cf. CAA section 211(o)(1)(B)(i),
(D), (2)(A)(i). See also definition of ``cellulosic biofuel'' at 40
CFR part 80, section 1401.
    \112\ CAA section 211(o)(7)(D).
---------------------------------------------------------------------------

    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 2023-2025, after taking into consideration
the incentives provided by the RFS program and other available state
and federal incentives. The candidate volumes for 2023-2025 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 and CNG/LNG derived
from biogas separately. Relative to the proposed rule the candidate
volumes of CNG/LNG derived from biogas are higher in all three years
due to the use of a higher growth rate to project these volumes.
Similarly, volumes of ethanol from CKF are higher in all three years as
we are now projecting additional facilities will register as cellulosic
biofuel producers using this pathway. Despite the increase in RNG use
as CNG/LNG and the addition of ethanol from CKF, total cellulosic
biofuel volumes for 2024 and 2025 are significantly lower in this final
rule relative to the proposal because we are not finalizing the eRIN
provisions in this rule.

                              Table III.C.1-1--Cellulosic Biofuel Candidate Volumes
                                                 [Million RINs]
----------------------------------------------------------------------------------------------------------------
                                                                       2023            2024            2025
----------------------------------------------------------------------------------------------------------------
RNG use as CNG/LNG..............................................             831           1,039           1,299
Ethanol from CKF................................................               7              51              77
                                                                 -----------------------------------------------
    Total Cellulosic Biofuel....................................             838           1,090           1,376
----------------------------------------------------------------------------------------------------------------

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.\113\ It remained at 4.5 billion gallons for three years before
finally rising to 5.0 billion gallons in 2022. The candidate volumes
for non-cellulosic advanced biofuel in the final rule are higher than
the candidate volumes from the proposed rule for 2023-2025. The
increases are primarily the result of higher projections of feedstock
availability allowing for greater renewable diesel production relative
to the proposed rule.
---------------------------------------------------------------------------

    \113\ See CAA section 211(o)(2)(B).
---------------------------------------------------------------------------

    For years after 2022, we anticipate that a key factor in the growth
in the production of advanced biodiesel and renewable diesel (the two
non-cellulosic advanced biofuels projected to be available in the
greatest quantities through 2025) will be the availability of
feedstocks as discussed in III.B.2.c. above. We expect small increases
in the supply of FOG and distillers corn oil, but we project that the
largest increases in feedstock availability in the U.S. will come from
increased production of soybean oil. This expectation is largely in
line with data and input provided by commenters on the December 2022
proposed rule. Significant investments have been made in recent years
that would result in higher domestic soybean crushing capacity and thus
soybean oil production, particularly in 2024 and 2025 (see additional
discussion of the availability of biodiesel and renewable feedstocks in
RIA Chapter 6.2.3). Similar investments have also been made to increase
the production of canola oil in Canada, much of which could be supplied
to U.S. markets for biofuel production. 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 higher-GHG feedstocks in non-biofuel markets as low-
GHG feedstocks are increasingly used for biofuel production, then it
would prove counterproductive.
    Based on these considerations, we believe that increases in the
volume of non-cellulosic advanced biofuel in the 2023-2025 timeframe
should primarily be based on projected increases in the availability of
feedstocks from the U.S. and Canada. One potential methodology for
projecting the available supply of BBD in 2023-2025 is to base the
projected supply for these years solely on the quantity of these fuels
supplied in 2022 and the projected increases in feedstock availability
in the U.S. and Canada (see RIA Chapter 6.2 for additional detail on
our projections of biodiesel and renewable diesel supply for 2023-
2025). However, RIN generation data from the first three months of 2023
indicates that the market is supplying greater volumes of non-
cellulosic advanced biofuel than we would project based only on the
quantity of these fuels used in 2022 plus the projected growth in
feedstock production in the U.S. and Canada. The market appears to be
responding to the proposed RFS volume requirements for 2023 by drawing
upon imports and other sources of feedstock.
    The candidate volumes for non-cellulosic advanced biofuel for 2023-
2025 attempt to balance the longer-term desire to maximize the benefits
(and minimize the potential negative impacts) of non-cellulosic
advanced biofuel production by aligning growth in these fuels with the
projected growth in feedstock production in North America and the
observed data on the quantities of these fuels that have been supplied
to the U.S. in the first quarter of 2023 (see Section VI for further
discussion of this topic). The candidate volume for 2023 is equal to
the quantity of non-cellulosic advanced biofuels to meet the proposed
RFS volumes for 2023 (including the projected shortfall in conventional
renewable fuel), consistent with the recent market data that indicates
that the market is on track to supply this quantity of non-cellulosic
advanced biofuel. The candidate volume for 2024 was determined in the
same way, but we note that we project that a greater proportion of the
increase over the quantity of these fuels supplied in 2022 is project
to be supplied with feedstocks from North America (rather than other
foreign countries) as soybean and canola crush capacity increases.
Finally, the candidate volume for 2025 is primarily based on the
projected increase in feedstocks from North America projected to be
available to biofuel producers. These candidate volumes are shown in
Table III.C.2-1, and the basis for these volumes are discussed in more
detail in RIA Chapter 6.

                    Table III.C.2-1--Total Non-Cellulosic Advanced Biofuel Candidate Volumes
                                                 [Million RINs]
----------------------------------------------------------------------------------------------------------------
                                                                       2023            2024            2025
----------------------------------------------------------------------------------------------------------------
Advanced biodiesel..............................................           2,565           2,500           2,436
Advanced renewable diesel \a\...................................           3,650           3,705           4,445
Other advanced biofuel..........................................             290             290             290
                                                                 -----------------------------------------------

    Total.......................................................           6,505           6,495           7,171
----------------------------------------------------------------------------------------------------------------
\a\ Represents only renewable diesel and jet fuel 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.

3. Conventional Renewable Fuel
    Consistent with the statute, EPA increased the implied conventional
renewable fuel volumes every year between 2009 and 2015, after which it
remained at 15 billion gallons through 2022.114 115 However,
since 2017 these standards were set with the expectation that corn
ethanol and other conventional biofuel volumes would not be sufficient
to meet the standards, and instead advanced biofuel volumes would be
required to make up for the shortfall. This is consistent with our
observations of the market, in which the total supply of conventional
renewable reached a maximum of approximately 14.5 billion gallons in
2016-2018. The candidate volume for conventional renewable in this
final rule are based primarily on supply related factors rather than
the implied volume requirements for conventional renewable fuel in
previous RFS rules.
---------------------------------------------------------------------------

    \114\ See CAA section 211(o)(2)(B).
    \115\ While the 2020 implied volume requirement was originally
set at 15 billion gallons (85 FR 7016, February 6, 2020), we 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 set the
implied volume requirement for conventional renewable fuel at the
level actually consumed. In 2016 EPA reduced the implied
conventional renewable fuel volume to 14.5 billion gallons under our
general waiver authority; this action was subsequently invalidated
by the D.C. Circuit Court of Appeals in ACE. In this rule we are
completing our response to the ACE remand by establishing a
supplemental volume requirement of 250 million gallons of renewable
fuel for 2023. This ``supplemental standard'' follows the
implementation of a 250-million-gallon supplement for 2022 in a
previous action. These two supplemental actions effectuates the
Congressionally determined renewable fuel volume for 2016, modified
only by the proper exercise of EPA's waiver authorities, as upheld
by the court in ACE, as discussed in Section V.
---------------------------------------------------------------------------

    The amount of conventional 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. Relative to the proposed
rule both total ethanol consumption and corn ethanol consumption are
significantly lower in all years, primarily due to lower projections of
gasoline consumption in EIA's most recent AEO. We do not currently
project that non-ethanol conventional renewable fuels will be supplied
to the U.S. in 2023-2025. Therefore, our candidate volumes for
conventional renewable fuel are equal to our projections of
conventional ethanol consumption for 2023-2025.

                               Table III.C.3-1--Projections of Ethanol Consumption
                                                [Million gallons]
----------------------------------------------------------------------------------------------------------------
                                                                       2023            2024            2025
----------------------------------------------------------------------------------------------------------------
Ethanol in all blends...........................................          13,974          14,128          13,978
Cellulosic ethanol..............................................               7              51              77
Imported sugarcane ethanol......................................              95              95              95
Domestic advanced ethanol.......................................              27              27              27
Conventional ethanol............................................          13,845          13,955          13,779
----------------------------------------------------------------------------------------------------------------

    Since conventional ethanol consumption would be about 13.8-14.0
billion gallons, there would need to be about 1.0-1.2 billion ethanol-
equivalent gallons of non-ethanol renewable fuel in order for the
implied conventional renewable fuel volumes of 15.0 billion gallons to
be met.
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. 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 final 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 the RFS
regulations limit the use of these carryover RINs to 20 percent of the
obligated party's renewable volume obligation (RVO).\116\ For the
collective supply of carryover RINs to be preserved from one year to
the next, individual carryover RINs are used for compliance before they
expire and are essentially replaced with newer vintage RINs that are
then held for use in the next year. For example, vintage 2022 carryover
RINs must be used for compliance with 2023 compliance year obligations,
or they will expire.

However, vintage 2023 RINs can then be saved for use toward 2024
compliance.
---------------------------------------------------------------------------

    \116\ 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.\117\ Carryover RINs are 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.\118\ 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.
---------------------------------------------------------------------------

    \117\ See, e.g., 72 FR 23904 (May 1, 2007).
    \118\ 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 number of available
carryover RINs may negatively impact the RIN market, even when the
market overall could satisfy the standards. In such a case, market
disruptions could force the need for a retroactive waiver of the
standards, undermining the market certainty so critical to the RFS
program. For all of these reasons, carryover RINs provide a necessary
programmatic buffer that helps facilitate compliance by individual
obligated parties, provides for smooth overall functioning of the
program to the benefit of all market participants, and is consistent
with the statutory provision requiring the generation and use of
credits.
    Carryover RINs have also provided flexibility when EPA considered
the need to use its waiver authorities to lower previously established
volumes. For example, in the context of the 2013 RFS rulemaking we
noted that an abundance of carryover RINs available in that year,
together with possible increases in renewable fuel production and
import, justified maintaining the advanced and total renewable fuel
volume requirements for that year at the levels specified in the
statute.\119\
---------------------------------------------------------------------------

    \119\ 79 FR 49793-95 (August 15, 2013).
---------------------------------------------------------------------------

a. Projected Number of Available Carryover RINs
    The projected number of available carryover RINs after compliance
with the 2021 standards (i.e., the number of carryover RINs available
for compliance with the 2022 standards) are summarized in Table
III.C.4.a-1.\120\
---------------------------------------------------------------------------

    \120\ The calculations performed to project the number of
available carryover RINs can be found in RIA Chapter 1.10.

                                Table III.C.4.a-1--Projected 2021 Carryover RINs
                                                 [Million RINs]
----------------------------------------------------------------------------------------------------------------
                                                                                Absolute 2021  Effective 2021
                 RFS standard                               RIN type              carryover RINs  carryover RINs
                                                                                \a\             \b\
----------------------------------------------------------------------------------------------------------------
Cellulosic Biofuel............................  D3+D7...........................              25               0
Non-Cellulosic Advanced Biofuel \c\...........  D4+D5...........................              61               0
Conventional Renewable Fuel \d\...............  D6..............................           1,047             494
----------------------------------------------------------------------------------------------------------------
\a\ Represents the absolute number of 2021 carryover RINs that are available for compliance with the 2022
  standards and does not account for deficits carried forward from 2021 into 2022.
\b\ Represents the effective number of 2021 carryover RINs that are available for compliance with the 2022
  standards after accounting for deficits carried forward from 2021 into 2022. Standards for which deficits
  exceed the number of available carryover RINs are represented as zero.
\c\ Non-cellulosic advanced biofuel is not an RFS standard category but is calculated by subtracting the number
  of cellulosic RINs from the number of advanced RINs.
\d\ Conventional renewable fuel is not an RFS standard category but is calculated by subtracting the number of
  advanced RINs from the number of total renewable fuel RINs.

    Assuming that the market exactly meets the 2022, 2023, and 2024
standards with new RIN generation, these are also the number of
carryover RINs that would be available for 2023, 2024, and 2025
(including the 2023 supplemental standard). 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 2023-
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.\121\ 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). In
particular, as discussed in RIA Chapter 1.11, the percentage standards
established for 2020 and 2021 were more stringent than EPA anticipated
(i.e., the volume of gasoline and diesel reported by obligated parties
for these compliance years was higher than volume used by EPA to set
the standards), resulting in an unexpected drawdown of the number of
available

carryover RINs as a result of compliance with the 2020 and 2021
standards. In addition, a number of small refineries have elected to
defer compliance with their 2020 obligations by opting-in to the
alternative RIN retirement schedule for small refineries.\122\ This
flexibility allows small refineries to use any valid RIN (including
2023 and 2024) to comply with their 2020 RVOs as part of a quarterly
RIN retirement schedule and effectively reduces the number of 2021-2024
carryover RINs available to comply with the 2022-2025 standards.
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 number of
available carryover RINs could be larger or smaller than the number
projected in Table III.C.4.a-1.
---------------------------------------------------------------------------

    \121\ Per 40 CFR 80.1451(f)(1)(i)(B)(4), the compliance deadline
for the 2022 standards will be the first quarterly reporting
deadline after the effective date of this action. We expect this
deadline is likely to be December 1, 2023.
    \122\ 40 CFR 80.1444.
---------------------------------------------------------------------------

    We acknowledge that the effective number of cellulosic and non-
cellulosic advanced biofuel carryover RINs is zero, and that the
effective number of conventional renewable fuel carryover RINs is
significantly lower than it has been in recent years. We have recently
taken actions to preserve the number of carryover RINs, and to ensure
the continued functioning of the RIN market, and continue to believe
that carryover RINs serve a vital programmatic function.\123\ We have
monitored RIN prices as a proxy for RIN market functioning, and given
current RIN prices, we continue to believe the RIN market is liquid and
fungible. Moreover, we note that the demand for RINs has been somewhat
reduced and dispersed across a broad range of RIN vintages as a result
of several actions related to small refineries: (1) The use of the
alternative RIN retirement schedule in 40 CFR 80.1444, which gives
small refineries additional time and opens a broader range of RIN
vintages to acquire and retire the RINs needed to demonstrate
compliance for the 2020 compliance year; and (2) The requests by
several small refineries, granted by three different U.S. Circuit
Courts of Appeals, to stay their RFS compliance obligations as part of
the pending litigation challenging the EPA's April 2022 \124\ and June
2022 \125\ SRE Denial Actions.\126\ We will continue to monitor RIN
prices and the market, and retain our ability to modify future volumes
through the use of our waiver authorities as discussed in Section II.F.
---------------------------------------------------------------------------

    \123\ See 87 FR 39600 (July 1, 2022), See also, ``April 2022
Alternative RFS Compliance Demonstration Approach for Certain Small
Refineries,'' EPA-420-R-22-006, April 2022; and ``June 2022
Alternative RFS Compliance Demonstration Approach for Certain Small
Refineries,'' EPA-420-R-22-012, June 2022.
    \124\ ``April 2022 Denial of Petitions for RFS Small Refinery
Exemption,'' EPA-420-R-22-005, April 2022 (``April 2022 SRE Denial
Action'').
    \125\ ``June 2022 Denial of Petitions for RFS Small Refinery
Exemption,'' EPA-420-R-22-011, June 2022 (``June 2022 SRE Denial
Action'').
    \126\ See, e.g., Hunt Refining Co. v. EPA, No. 22-12535-A,
Document 33 (11th Cir.), Calumet Shreveport Refining, et al. v. EPA,
No. 22-60266, Documents 209-1, 304-1 (5th Cir.), Sinclair Wyoming,
et. al. v. EPA, No. 22-1073, Document 1992426 (D.C. Cir.).
---------------------------------------------------------------------------

    Even though carryover RIN levels are low, we believe that the
standards we are finalizing in this action, including the supplemental
standard, can be met through additional production of renewable fuel in
the market. Additionally, should the market fall short of the volumes
we are finalizing, obligated parties will continue to be able to carry
forward a RIN deficit from one year into the next, although they may
not carry forward a deficit for consecutive years. Conversely, should
the market over-comply with the standards we are finalizing, the number
of available carryover RINs could again grow.
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 finalized for 2023-2025 (including the 2023
supplemental volume). Doing so would be equivalent to intentionally
drawing down the number of available carryover RINs in setting those
volume requirements. We do not believe that this would be appropriate.
In reaching this determination, we considered the functions of
carryover RINs, the projected number available, the uncertainties
associated with this projection, the potential impact of carryover RINs
on the production and use of renewable fuel, the ability and need for
obligated parties to draw on carryover RINs to comply with their
obligations (both on an individual basis and on a market-wide basis),
and the impacts of drawing down the number of available carryover RINs
on obligated parties and the fuels market more broadly. As previously
described, carryover RINs provide important and necessary programmatic
functions--including as a cost spike buffer--that will both facilitate
individual compliance and provide for smooth overall functioning of the
program. We believe that a balanced consideration of the possible role
of carryover RINs in achieving the volume requirements, versus
maintaining an adequate number of carryover RINs for important
programmatic functions, is appropriate when EPA exercises its
discretion under its statutory authorities.
    Furthermore, as discussed in the previous section and in RIA
Chapter 1.10, the number of available carryover RINs has been
significantly and unexpectedly drawn down as a result of 2020 and 2021
compliance, including effectively depleting the number of available
cellulosic and non-cellulosic advanced carryover RINs. Moreover, 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 believed that the market could make sufficient
renewable fuel available to meet the 2022 standards, there may be some
challenges.\127\ In addition, in this action we are for the first time
prospectively establishing volume requirements for multiple years. This
inherently adds uncertainty and makes it more challenging to project
with accuracy the number of carryover RINs that will 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 number of available carryover RINs could lead to
significant deficit carryforwards and noncompliance 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 including
carryover RINs in the candidate volumes, nor setting the 2023, 2024,
and 2025 volume requirements (including the 2023 supplemental standard)
at levels that would intentionally draw down the number of available
carryover RINs.
---------------------------------------------------------------------------

    \127\ 87 FR 39600 (July 1, 2022).
---------------------------------------------------------------------------

    We are not determining that the number of carryover RINs projected
in Table III.C.4.a-1 is a bright-line threshold for the number of
carryover

RINs that provides sufficient market liquidity and allows carryover
RINs to play their important programmatic functions. As in past years,
we are instead evaluating, on a case-by-case basis, the number of
available carryover RINs 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 a larger number of
available carryover RINs may provide greater assurance of market
liquidity, we do not believe it would be appropriate to set the
standards at levels specifically designed 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 that we
believe represent achievable levels of supply related factors and other
relevant considerations. These volumes are summarized in Table III.C.5-
1.

                Table III.C.5-1--Candidate Volume Components Derived From Supply-Related Factors
                                               [Million RINs] \a\
----------------------------------------------------------------------------------------------------------------
                                                                       2023            2024            2025
----------------------------------------------------------------------------------------------------------------
Cellulosic biofuel (D3 & D7)....................................             838           1,090           1,376
Biomass-based diesel (D4).......................................           6,215           6,205           6,881
Other advanced biofuel (D5).....................................             290             290             290
Conventional renewable fuel (D6)................................          13,845          13,955          13,779
----------------------------------------------------------------------------------------------------------------
\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 RIA
Chapter 3. These candidate volumes represent our assessment of the
volume of renewable fuels we project could be used in the U.S. based on
the expected annual rate of future commercial production of renewable
fuels (one of the statutory factors), potential constraints on the
domestic consumption of renewable fuels, and other relevant factors. We
considered these candidate volumes when conducting the analyses of the
additional statutory factors, which are summarized in Section IV and
discussed in greater detail in the RIA. In Section VI, we discuss the
final applicable volume targets based on a consideration of all of the
factors that we analyzed--both the supply-related factors that were
considered in developing the candidate volumes (discussed in this
section) and the additional statutory factors discussed in Section IV.
    Note that the volumes shown in Table III.C.5-1 represent the total
candidate volumes 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 that could
be used to satisfy 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.

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 used 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 in
the proposal, we did not use to assess 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.''
    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 the economics for 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 (e.g., did they lose
money in a previous year), current, and perceived future economics of
the biofuel market when deciding whether to continue to operate their
biofuel plants, and our analysis attempted to account for these
factors.
    The No RFS Baseline analysis for 2023-2025 compares the biofuel
cost 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 to blenders. 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 (within the constraints described below).
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 society at large (see Section IV.C and RIA
Chapter 10 for descriptions of the social cost analysis). 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 generally 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 higher rate of return more typical for industry
investment instead of the 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 must price E85 lower
than the primary alternative E10 to account for this bias and they must
consider this in their decisions to blend and sell E85. 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 Baseline
discussion in RIA Chapter 2.
    We added these various cost components (i.e., production cost,
distribution cost, any blending cost, retail cost, applicable tax
subsidies) 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. An important subsidy is the $1 federal
tax incentives for blending biodiesel and other biofuels into diesel
fuel which was extended in the IRA.\128\ 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 Higher Blends
Infrastructure Incentive Program (HBIIP) program administered by the
United States Department of Agriculture.
---------------------------------------------------------------------------

    \128\ H.R. 5376--The Inflation Reduction Act of 2022
---------------------------------------------------------------------------

    In addition, there are a number of state programs that create
subsidies for biodiesel and renewable diesel fuel, the largest being
offered by California and Oregon through their LCFS programs. 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.\129\ To account
for the various state assumptions, it was necessary to model the cost
of using these biofuels on a state-by-state basis.
---------------------------------------------------------------------------

    \129\ In light of the fluid situation with respect to a 1-psi
RVP waiver for E15 or actions to remove the 1 psi wavier for E10 in
eight midwestern states, our analysis did not specifically assume
either of these potential changes. These assumptions can affect the
relative cost of E15, however, adopting these assumptions would not
have impacted the overall conclusions with respect to blending E15
in the absence of the RFS program.
---------------------------------------------------------------------------

    For most 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 to determine whether to continue to operate their
plants, or shutdown. Thus, to smooth out the swings in the economics
for using biodiesel and renewable diesel and look at it the way plant
operators and their 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 distinct four-year periods. As a
result, the first 4-year modeled period 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 in Table III.D.1-1.
A more complete description of the No RFS baseline and its derivation
is provided in RIA Chapter 2. The projected consumption of cellulosic
biofuel and

other advanced biofuel in this final rule is similar to the volumes for
these fuel types projected in the proposed rule, with slight variations
based on updated data. The projected BBD volumes for the No RFS
baseline are significantly higher in all years, primarily because the
significantly higher crude oil prices from the most recent AEO make BBD
more cost competitive with petroleum diesel, after accounting for the
available non-RFS incentives such as the federal tax credit for BBD and
the incentives offered by California's LCFS program. Finally, the
conventional renewable fuel volumes for the No RFS baseline are
significantly lower in all years, relative to the volumes in the
proposed rule, primarily due to lower projected gasoline consumption in
2023-2025 from EIA.

                    Table III.D.1-1--Biofuel Consumption in 2023-2025 Under a No RFS Baseline
                                                 [Million RINs]
----------------------------------------------------------------------------------------------------------------
                                                                       2023            2024            2025
----------------------------------------------------------------------------------------------------------------
Cellulosic biofuel (D3 & D7)....................................             343             402             444
Biomass-based diesel (D4).......................................           2,796           3,139           3,496
Other advanced biofuel (D5).....................................             226             226             226
Conventional renewable fuel (D6)................................          13,185          13,224          12,992
----------------------------------------------------------------------------------------------------------------

    Our analysis shows that corn ethanol is economical to use in 10
percent blends (E10) 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. Higher-
level ethanol blends are not as economical as ethanol blended as E10
because the octane value of ethanol is generally not realized in these
blends, and the infrastructure cost for dispensing these fuels are high
(see RIA Chapter 10). 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.
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 neglect
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.\130\ 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.
---------------------------------------------------------------------------

    \130\ 75 FR 14670 (March 26, 2010).
---------------------------------------------------------------------------

3. Previous Year Volumes
    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.\131\
---------------------------------------------------------------------------

    \131\ 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 2022 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.
Therefore, we used actual data on 2020

biofuels consumption as the primary baseline in that rule.
    In the Set rule proposal, we used the 2022 volume requirements as
an informational case in addition to the No RFS baseline, but we did so
only for costs to allow for a comparison to the analysis and results
presented in recent annual rules. We continue to believe that this is
appropriate in this final rule. However, we now have data on how the
market responded to the applicable 2022 standards, and we believe that
this data on actual market performance is a better point of reference
than the 2022 volume requirements established in the July 1, 2022 final
rule. Therefore, we have used actual 2022 biofuel consumption as a
baseline in the estimation of costs for this final rule, in addition to
the No RFS baseline. This approach is consistent with the approach we
took in the rulemaking which established the volume requirements for
2020, 2021, and 2022,\132\ as well as the rulemaking which established
the volume requirements for 2014, 2015, and 2016.\133\ 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.\134\
---------------------------------------------------------------------------

    \132\ 87 FR 39600 (July 1, 2022).
    \133\ 80 FR 77420 (Dec. 14, 2015).
    \134\ The 2015 volumes were based on actual consumption data for
January-September and a projection for October-December.
---------------------------------------------------------------------------

    The volumes of biofuel consumption for 2022 are shown below. More
details on 2022 biofuel consumption can be found in RIA Chapter 2.

                Table III.D.3-2--2022 Biofuel Consumption
------------------------------------------------------------------------
                                                              Volume
                                                          (million RINs)
------------------------------------------------------------------------
Cellulosic biofuel (D3 & D7)............................             667
Biomass-based diesel (D4)...............................           4,956
Other advanced biofuel (D5).............................             318
Conventional renewable fuel (D6)........................          14,034
------------------------------------------------------------------------

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.5-1) 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 RIA 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. As noted above, we also consider the impacts of this rule
relative to a 2022 baseline for some of our analyses, such as the cost
of the rule. The changes in biofuel consumption in the transportation
sector relative to the 2022 baseline are shown in in Table III.E-2.

 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)....................................             495             688             932
Biomass-Based Diesel (D4).......................................           3,169           3,066           3,385
Other Advanced Biofuel (D5).....................................              64              64              64
Conventional Renewable Fuel (D6)................................             660             731             787
----------------------------------------------------------------------------------------------------------------

  Table III.E-2--Changes in Biofuel Consumption in the Transportation Sector in Comparison to the 2022 Baseline
                                                 [Million RINs]
----------------------------------------------------------------------------------------------------------------
                                                                       2023            2024            2025
----------------------------------------------------------------------------------------------------------------
Cellulosic biofuel (D3 & D7)....................................             172             424             710
Biomass-Based Diesel (D4).......................................           1,271           1,511           2,187
Other Advanced Biofuel (D5).....................................             -28             -28             -28
Conventional Renewable Fuel (D6)................................            -189             -79            -255
----------------------------------------------------------------------------------------------------------------

    The volumes shown in Table III.D.1-1 and the volume changes shown
in Tables III.E-1 and 2 include the volume of renewable fuel projected
to be supplied to meet the supplemental volume requirements in 2023.
For purposes of analyzing the environmental and economic impacts
(discussed in Section IV), we treat the 2023 supplemental volume
requirement separately as discussed in RIA Chapter 3.3. We project that
the supplemental volume will be met with 147 million gallons (250
million RINs) of renewable diesel produced from soybean oil. Our
analyses of the statutory factors described in Section IV generally do
not include the impacts of the supplemental volume requirement, except
where noted.

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 RIA. 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.5-1 for the candidate volume, 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 a summary of our consideration of all factors in determining
the volume requirements that we have determined are appropriate for
2023-2025.

A. Climate Change

    This section begins with a description of our analysis of the
climate change impacts of the candidate volumes. Following this, in
Section IV.A.2, is a description of a model comparison exercise that
was not conducted for the purpose of evaluating the candidate volumes,
nor does it inform the volumes in this final rule.
1. Climate Change Analysis Supporting Rule
    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,\135\ and GHG emissions contribute to climate
change.\136\ Thus, in the proposed rule we used lifecycle GHG emissions
estimates as a proxy for climate change impacts.\137\ We continue to
believe this approach is reasonable and appropriate for the final rule.
---------------------------------------------------------------------------

    \135\ 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.'')
    \136\ 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)).
    \137\ This is consistent with EPA's analysis of the same
statutory factor in the 2020-2022 Rule. See ``Renewable Fuel
Standard (RFS) Program: RFS Annual Rules--Regulatory Impact
Analysis,'' EPA-420-R-22-008, June 2022, pp 65-96.
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    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,\138\ while cellulosic biofuel is required to have
lifecycle emissions at least 60 percent less than the baseline
fuels.\139\ Congress also allowed for facilities that existed or were
under construction when the EISA was enacted to be grandfathered into
the RFS program and exempt from the lifecycle GHG emission reduction
requirements.\140\
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    \138\ CAA Sections 211(o)(1)(B)(i) and 211(o)(1)(D).
    \139\ CAA Section 211(o)(1)(E).
    \140\ CAA Section 211(o)(2)(A)(i).
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    In the proposed rule, we presented biofuel LCA estimates from a
range of published values from the scientific/technical literature. We
are using the same approach as the proposed rule, whereby we multiply
the lifecycle emissions value for each individual fuel by the change in
the volume 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. We provide a high and low estimate of the potential GHG
impacts of each pathway (combination of biofuel type, feedstock, and
production process) based on the range of published LCA estimates from
the scientific literature. We then use this range of values for
considering the GHG impacts of the renewable fuel volumes that change
relative to the No RFS baseline described in Section III. Specifically,
we use the LCA ranges to develop an illustrative scenario of the GHG
impacts, which is described and presented in RIA Chapter 4.2.3.\141\
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    \141\ To be more precise, for the crop-based biofuel pathways we
use the range of LCA estimates that include an annual stream of
emissions, which are based on the modeling for the March 2010 RFS2
rule.
---------------------------------------------------------------------------

    To develop the range of LCA values, we conducted a high-level
review of relevant literature for the biofuel pathways that would be
most likely to satisfy the candidate renewable fuel volumes, as well as
the petroleum-based fuels they are used to replace or reduce. Based on
our review, we compiled the LCA estimates in the literature for each
pathway. We include estimates from peer-reviewed journal articles,
authoritative governmental reports, and other credible publications,
such as studies by non-governmental organizations. Given that all LCA
studies and models have particular strengths and weaknesses, as well as
uncertainties and limitations, our goal for this compilation of
literatures estimates is to consider the ranges of published estimates,
not to adjudicate which particular studies, estimates or assumptions
are most appropriate. Reflecting the many approaches to LCA and
associated assumptions and uncertainties, our review is intentionally
broad and inclusive of a wide range of estimates based on a variety of
study types and assumptions. We focused on LCA estimates for the
average type of each fuel produced in the United States.\142\ 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.\143\
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    \142\ 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 gradually
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.
    \143\ 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.
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    We made minor changes to the LCA ranges used in the proposed rule.
We reviewed the public comments and searched the literature to identify
new or additional studies to add to our review. However, public
commenters did not identify any additional LCA estimates that we had
not already considered. Likewise, our updated search of the literature
did not identify any additional estimates. The one update we made was
replacing estimates from the 2021 version of the Greenhouse gases,
Regulated Emissions, and Energy use in Technologies (GREET) Model with
estimates from the

2022 version. Some of the public comments recommended removing some of
the studies considered in the proposed rule. We considered these
comments carefully but decided not to remove any of the studies
considered in the proposed rule as they meet the broad criteria for our
compilation of published estimates. We discuss these comments and our
reasoning in the summary and analysis of comments document that is part
of this rulemaking package.
    The ranges of values in our compilation vary considerably for
different types of renewable fuels, particularly for crop-based
biofuels. The ranges of estimates for non-crop based biofuel pathways
tend to be narrower relative to the crop-based pathways (See Table
IV.A-1).

 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
Natural Gas CNG..........................  73 to 81
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.........................  16 to 58
Tallow Renewable Diesel..................  14 to 81
Distillers Corn Oil Biodiesel............  14 to 37
Distillers Corn Oil Renewable Diesel.....  12 to 46
Landfill Gas CNG.........................  6 to 70
Manure Biogas CNG........................  -533 to 52
------------------------------------------------------------------------

2. Description of Separate Model Comparison Exercise
    This section describes a model comparison exercise that we
conducted for the purpose of advancing our understanding of available
models and science related to the GHG impacts of biofuel consumption.
We requested comment on a number of issues related to the model
comparison exercise, including the approach for conducting the model
comparison. At the time of proposal, we were contemplating using the
model comparison exercise to inform the final rule.\144\ However, we
did not ultimately rely on the model comparison exercise to evaluate
the candidate volumes or to inform the volumes in this final rule. The
model comparison exercise highlighted areas of uncertainty across the
models used, a wide range of estimated GHG impacts, and areas for
further research. Work to refine models to inform future rulemakings is
ongoing. We want to engage with stakeholders and receive feedback on
the MCE before deciding how to use any results in a rulemaking context.
While we did not ultimately rely on the model comparison exercise to
evaluate the candidate volumes or to inform the volumes in this final
rule, we describe it here solely for informational purposes, as readers
of Section IV.A may be interested in the technical information provided
through this separate exercise.
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    \144\ See 87 FR 80582, 80611 (December 30, 2022).
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    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. 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 a better
understanding of these newer models and data is needed. In the proposed
rule, we did not propose to reopen the related aspects of the 2010 RFS2
rule or any prior EPA lifecycle greenhouse gas analyses, methodologies,
or actions, as that is beyond the scope of this rulemaking. While
updating our LCA methodology is beyond the scope of this rulemaking, to
make this information available to the public we are including the
outcome of a model comparison exercise by placing it in the docket for
this rulemaking in the document titled, ``Model Comparison Exercise
Technical Document.''
    The model comparison exercise has three main goals: (1) Advance the
science in the area of analyzing the lifecycle greenhouse gas emissions
impacts from increasing use of biofuel; (2) Identify and understand
differences in scope, coverage, and key assumptions in each model, and
to the extent possible the impact that those differences have on the
appropriateness of using a given model to evaluate the GHG impacts of
biofuels; and (3) Understand how differences between models and data
sources lead to varying results. As we designed and conducted the model
comparison exercise, we consulted with our colleagues within the USDA
and DOE.
    Following the proposed rule, the National Academies of Sciences,
Engineering, and Medicine (NASEM) published a report titled ``Current
Methods for Life Cycle Analyses of Low-Carbon Transportation Fuels in
the United States.'' The conclusions and recommendations from the NASEM
report support our motivations for conducting the model comparison. In
particular, recommendation 4-2 from the report states, ``Current and
future LCFS [low carbon fuel standard] policies should strive to reduce
model uncertainties and compare results across multiple economic
modeling approaches and transparently communicate uncertainties.''
Consistent with this and other recommendations in the NASEM report, our
model comparison exercise compares results from multiple models, and we
strive to transparently consider parameter, scenario and model
uncertainties.
    LCA plays several diverse roles in the context of the RFS program.
Under Section 211(o)(2)(B)(ii)(I) of the CAA, EPA is required to
analyze the climate change impacts of this rule and other RFS rules
that establish the renewable fuel standards subject to the requirements
of CAA section 211(o)(2)(B)(ii). This work is related to, but distinct
from, EPA's responsibility to determine which biofuel pathways satisfy
the lifecycle GHG reduction thresholds corresponding with the four
categories of renewable fuel. The model comparison exercise does not
support these analytical needs at this time, but the insights on
modeling and science from this exercise may inform future analytical
efforts on both of these topics. Our work related to biofuel GHG
modeling and lifecycle analysis will continue after this rulemaking.
    For the model comparison exercise we selected five models, listed
below in alphabetical order, that provide different insights into the
climate change impacts of crop-based biofuel production. First, the
Applied Dynamic Analysis of the Global Economy (ADAGE) model, is an
economic model that includes all sectors of the economy, including
agriculture, bioenergy, and transportation. Second, the Global Change
Analysis Model (GCAM), simulates the world's energy, water,
agriculture, land, climate and economic systems. Third, the Global
Biosphere Management Model (GLOBIOM) is an economic model of the
agricultural, forest and bioenergy sectors. Fourth, the Greenhouse
gases, Regulated Emissions, and Energy use in Technologies (GREET)
Model is a lifecycle analysis model that estimates the well-to-wheels
impacts of transportation technologies.

Finally, the Global Trade Analysis Project (GTAP) model is a general
equilibrium model of all sectors of the economy. We selected these
models based on our many years of experience with biofuel GHG modeling
and based on stakeholder input, including the proceedings and public
comments associated with the biofuel GHG modeling workshop that we