accounted for exemptions already granted at the time of the final
annual rule.\148\
---------------------------------------------------------------------------

    \147\ We adopted this interpretation of our regulations in the
2011 final rule. 75 FR 76804. We reaffirmed it in annual rulemakings
since then, including most recently in the 2019 final rule. 83 FR
63740; see also, e.g., 77 FR 1320, 1340; 78 FR 49794, 49825-49826;
80 FR 77420, 77511. We also proposed to follow this interpretation
in the July 29 proposal for this final rule. 84 FR 36797 (July 29,
2019).
    \148\ See, e.g., 80 FR 77420, 77511 (December 14, 2015).
---------------------------------------------------------------------------

    In the October 28 proposal, we proposed to modify the regulations
at 40 CFR 80.1405(c) to account for a projection of the total exempted
volume of gasoline and diesel produced at small refineries, including
for those exemptions granted after the final annual rule.\149\ We are
finalizing the change as proposed. The result is that our calculation
of the applicable percentage standards for 2020 takes into account a
projection of the total exempted volume of gasoline and diesel produced
by small refineries in 2020.
---------------------------------------------------------------------------

    \149\ 84 FR 57677.
---------------------------------------------------------------------------

1. Changes to the Projected Volume of Gasoline and Diesel for Exempt
Small Refineries
    The formulas used to calculate the percentage standards applicable
to producers and importers of gasoline and diesel are provided in 40
CFR 80.1405(c). The formula for the percentage standard calculation for
total renewable fuel, including the definitions of the terms prior to
this action, is shown below. The formulas for the other three
percentage standards follow the same format, with the numerator of the
fraction replaced with the annual volume of cellulosic biofuel,
biomass-based diesel, and advanced biofuel, respectively. In this
action we are only modifying the definitions of the terms
GEi and DEi, which previously referred to the
amount of gasoline and diesel projected to be produced by exempt small
refineries, to now refer to the amount of gasoline and diesel projected
to be exempt. All other terms remain in the same and were not
reexamined in this rulemaking.
[GRAPHIC] [TIFF OMITTED] TR06FE20.003

Where:
StdRF,i = The renewable fuel standard for year i, in
percent.
RFVRF,i = Annual volume of renewable fuel required by 42
U.S.C. 7545(o)(2)(B) for year i, in gallons.
Gi = Amount of gasoline projected to be used in the 48
contiguous states and Hawaii, in year i, in gallons.
Di = Amount of diesel projected to be used in the 48
contiguous states and Hawaii, in year i, in gallons.
RGi = Amount of renewable fuel blended into gasoline that
is projected to be consumed in the 48 contiguous states and Hawaii,
in year i, in gallons.
RDi = Amount of renewable fuel blended into diesel that
is projected to be consumed in the 48 contiguous states and Hawaii,
in year i, in gallons.
GSi = Amount of gasoline projected to be used in Alaska
or a U.S. territory, in year i, if the state or territory has opted-
in or opts-in, in gallons.
RGSi = Amount of renewable fuel blended into gasoline
that is projected to be consumed in Alaska or a U.S. territory,

in year i, if the state or territory opts-in, in gallons.
DSi = Amount of diesel projected to be used in Alaska or
a U.S. territory, in year i, if the state or territory has opted-in
or opts-in, in gallons.
RDSi = Amount of renewable fuel blended into diesel that
is projected to be consumed in Alaska or a U.S. territory, in year
i, if the state or territory opts-in, in gallons.
GEi = The amount of gasoline projected to be produced by
exempt small refineries and small refiners, in year i, in gallons in
any year they are exempt per Sec. Sec.  80.1441 and 80.1442.
DEi = The amount of diesel fuel projected to be produced
by exempt small refineries and small refiners in year i, in gallons,
in any year they are exempt per Sec. Sec.  80.1441 and 80.1442.

    Historically, EPA has interpreted the terms GEi and
DEi to refer to the amount of gasoline and diesel projected
to be produced by small refineries that have already been granted
exemptions from their RFS obligations prior to our issuing the final
rule for the relevant compliance year.\150\ As a result of this
interpretation, any SREs granted after we issued the annual rule
containing the percentage standards for that year effectively reduced
the required volume of renewable fuel for that year. For example, in
August 2019 we granted 31 SREs for the 2018 compliance year after the
percentage standards for 2018 had been established.\151\ These SREs
reduced the obligated volume of gasoline and diesel for 2018 by 13.42
billion gallons, effectively reducing the required volume of total
renewable fuel for 2018 by 1.43 billion RINs.
---------------------------------------------------------------------------

    \150\ See, e.g., 84 FR 36797 (July 29, 2019).
    \151\ The percentage standards for 2018 were established in
December 2017 (82 FR 58486, December 12, 2017).
---------------------------------------------------------------------------

    In comments on the July 29 proposal, many commenters requested that
EPA adopt a different interpretation of the terms for the amount of
gasoline and diesel projected to be produced by exempt small refineries
in the existing percentage standard formula.\152\ Many commenters
requested that these terms refer to a projection of the exempted volume
of gasoline and diesel produced by small refineries, regardless of
whether EPA had already adjudicated such exemption petitions by the
time of the final rule. These commenters argued that this
interpretation of the regulations is reasonable and better implements
the statutory requirement that EPA must ``ensure'' the renewable fuel
volumes are met. Some commenters suggested that adjusting the
percentage standards formula is more important now than in earlier
years of the program as we have recently granted exemptions for more
significant volumes of gasoline and diesel, potentially resulting in
more significant volumes that are not being met at the time of
compliance.\153\ A petition for administrative reconsideration raised
similar issues, asking EPA to reconsider our approach for accounting
for exempted volumes through the formula at 40 CFR 80.1405(c).\154\ In
the October 28 proposal, EPA undertook a process to revisit this issue,
albeit under our inherent authority to revise or amend a rulemaking,
rather than as an exercise of our reconsideration authority under CAA
section 307(d)(7)(B).\155\
---------------------------------------------------------------------------

    \152\ See, e.g., comments from the Renewable Fuels Association
(Docket Item No. EPA-HQ-OAR-2019-0136-0281).
    \153\ See, e.g., comments from Growth Energy (Docket Item No.
EPA-HQ-OAR-2019-0136-0312).
    \154\ ``Petition for Reconsideration of 40 CFR 80.1405(c), EPA
Docket No. EPA-HQ-OAR-2005-0161, promulgated in 75 FR 14670 (Mar.
26, 2010); Petition for Reconsideration of Periodic Reviews for the
Renewable Fuel Standard Program, 82 FR 58364 (Dec. 12, 2017)'' (June
4, 2018).
    \155\ See 84 FR 57680 & n.13 (explaining in greater detail the
basis for EPA's reconsideration of this issue).
---------------------------------------------------------------------------

    In the October 28 proposal we proposed to change the definitions of
the two relevant terms in the percentage standard formula at 40 CFR
80.1405(c), GEi and DEi. We proposed that these
terms represent a projection of the exempted volume of gasoline and
diesel, regardless of whether we had adjudicated exemptions for that
year by the time of the final rule establishing the percentage
standards. We are finalizing these changes, and in turn, also
completing the process of revisiting this issue that we undertook as
described above in response to the above-noted administrative petition.
The term ``GEi'', representing the volume of exempt
gasoline, is now defined as ``the total amount of gasoline projected to
be exempt in year i, in gallons, per Sec. Sec.  80.1441 and 80.1442.''
Similarly, the term ``DEi'', representing the volume of
exempt diesel, is now defined as ``the total amount of diesel projected
to be exempt in year i, in gallons, per Sec. Sec.  80.1441 and
80.1442.''
    We begin by explaining our legal authority to adopt the new
definitions, as well as our rationale for the change in our policy.
While the statute does not specifically require EPA to redistribute
exempted volumes in this manner, we believe that this is a reasonable
interpretation of our authority under Chevron v. NRDC.\156\ Indeed,
making this projection harmonizes various statutory provisions. The
statute authorizes small refineries to petition for and EPA to grant an
exemption based on disproportionate economic hardship ``at any time,''
\157\ while also directing EPA to promulgate standards by November 30
of the prior year to ``ensure[]'' that the renewable fuel volumes are
met.\158\ In other words, small refineries may seek and EPA may grant
hardship exemptions at any time, including after the percentage
standards are established. Meanwhile, EPA may account for a projection
of these exemptions in the annual rule to ``ensure'' the renewable fuel
volumes.\159\
---------------------------------------------------------------------------

    \156\ Chevron, U.S.A., Inc. v. Nat. Res. Def. Council, Inc., 467
U.S. 837, 842-44 (1984).
    \157\ CAA section 211(o)(9)(B)(i).
    \158\ CAA section 211(o)(3)(B)(i); see also CAA section
211(o)(2)(A)(i), (2)(A)(iii)(I), CAA section 301(a). This
projection, moreover, is hardly unique in the RFS program as
Congress required numerous projections in the implementation of the
program. See, e.g., CAA section 211(o)(7)(D) (projection of the
volume of cellulosic biofuel production); (o)(3)(A) (projection of
the volumes of transportation fuel, biomass-based diesel, and
cellulosic biofuel).
    \159\ See CAA section 211(o)(2)(A)(i), (2)(A)(iii)(I),
(3)(B)(i); see also CAA section 301(a).
---------------------------------------------------------------------------

    In more concrete terms, should EPA grant SREs without accounting
for them in the percentage formula, those exemptions would effectively
reduce the volumes of renewable fuel required by the RFS program,
potentially impacting renewable fuel use in the U.S.\160\ By contrast,
under our new approach, the percentage standard for each category of
renewable fuel would increase to account for a projection of the
exempted volume. These higher percentage standards would have the
effect of ensuring that the required volumes of renewable fuel are met
when small refineries are granted exemptions from their 2020
obligations after the issuance of the final rule, provided EPA's
projection of the exempted volume is accurate.
---------------------------------------------------------------------------

    \160\ We note that there are other factors, besides the RFS
program, that affect renewable fuel use. See, e.g., ``Endangered
Species Act No Effect Finding for the 2020 Final Rule,'' available
in the docket for this action.
---------------------------------------------------------------------------

    This new approach entails a change in policy.\161\ We previously
did not account for exemptions granted after the annual rule, and at
times we even suggested that doing so was improper.\162\ We believe our
changed approach is appropriate and largely avoids the problems we
previously identified. First, we had previously stated that ``the Act
is best interpreted to require issuance of a single annual standard in
November that is applicable in the following calendar year, thereby
providing advance notice and certainty to obligated parties regarding
their

regulatory requirements. Periodic revisions to the standards to reflect
waivers issued to small refineries or refiners would be inconsistent
with the statutory text, and would introduce an undesirable level of
uncertainty for obligated parties.'' \163\ Today's changes are
consistent with these views. By projecting exempted volumes in advance
of issuing annual standards, we can issue a single set of standards for
each year without the need for periodic revisions and the associated
uncertainty for obligated parties.
---------------------------------------------------------------------------

    \161\ FCC v. Fox Television Stations, Inc., 556 U.S. 502, 515
(2009).
    \162\ See 78 FR 49825-49826; 77 FR 1340; EPA's Br., Doc No.
1757157, D.C. Cir. No. 17-1258, AFPM v. EPA (Oct. 25, 2018) (``EPA
Br. in AFPM'').
    \163\ 77 FR 1340.
---------------------------------------------------------------------------

    Second, we also had previously noted that ``Congress allowed for
some imprecision to exist in the actual volumes of renewable fuel that
are consumed as a result of the percentage standards that we set each
November. . . .'' \164\ Relatedly, we had noted the inherent
difficulties of projecting exempted small refinery volumes.\165\ We
still agree that Congress allowed for some imprecision to exist in the
actual required volumes of renewable fuel, and that projecting future
exempted volumes involves some uncertainty.
---------------------------------------------------------------------------

    \164\ 77 FR 1340 (January 9, 2012).
    \165\ EPA Br. in AFPM 72-77.
---------------------------------------------------------------------------

    But several recent developments persuade us to reach a different
conclusion in accounting for a projection of exempted small refinery
volumes. For one, we are projecting the aggregate exempted volume in
2020. We thus need not wrestle with the difficulties of predicting
precisely which refineries will apply or the economic circumstances of
specific refineries in 2020. We only need to estimate the total
exempted volume. Moreover, we have the benefit of additional experience
administering the RFS program and knowledge of the relatively high
levels of exempted volumes in recent years, where exempted volumes
associated with SREs granted after the annual percentage standards were
established have constituted a significant portion of the total volume
of obligated fuel, resulting in fewer RINs being used to comply with
the RFS standards.
    Finally, in recent annual rulemakings, EPA has not articulated its
prospective policy to adjudicating SRE petitions for those compliance
years. For instance, in the 2018 final rule, we did not state our
policy to adjudicating 2018 SRE petitions. Instead we articulated that
policy in a separate memorandum issued after the annual rule.\166\
Since EPA's policy to adjudicating SRE petitions affects the exempted
volume, not having established this policy at the time of the annual
rule made it very challenging to project the exempted volume. In
today's rule, by contrast, we are articulating our prospective policy
to adjudicating SRE petitions (beginning with the 2019 SRE petitions
and including the 2020 SRE petitions) concurrently with issuing this
final rule. Doing so augments our ability to reasonably project the
exempted volume for 2020. We explain this policy further below.
---------------------------------------------------------------------------

    \166\ ``Decision on 2018 Small Refinery Exemption Petitions,''
Memorandum from Anne Idsal, Acting Assistant Administrator, Office
of Air and Radiation to Sarah Dunham, Director, Office of
Transportation and Air Quality. August 9, 2019.
---------------------------------------------------------------------------

2. Projecting the Exempted Volume of Gasoline and Diesel in 2020
    As already noted, we acknowledge the inherent uncertainty in
projecting the exempted volume. More concretely, an imprecise
projection has consequences on the actual required volume of renewable
fuel. If we over-project the volume of gasoline and diesel produced by
exempt small refineries in 2020, the actual required volumes of
renewable fuel will be higher than the volumes used in calculating the
percentage standards. By contrast, if we under-project the volume of
exempted gasoline and diesel, the actual required volumes of renewable
fuel will be lower than the volumes used in calculating the percentage
standards. If we project the volume correctly, we will ensure that, as
far as exempted small refinery volumes are concerned, the actual
required volume is equal to the volume established in this final
rule.\167\
---------------------------------------------------------------------------

    \167\ The actual required volume is subject to other
uncertainties besides small refinery exemptions, such as unexpected
changes in gasoline and diesel use.
---------------------------------------------------------------------------

    In selecting the methodology for projecting the exempted volume, we
thus aim to make a neutral projection of exemptions based on the
information now before us. As proposed, we are finalizing a projection
methodology based on a 2016-18 annual average of exempted volumes had
EPA strictly followed DOE recommendations in those years, including by
granting 50 percent relief where DOE recommended 50 percent relief. We
explain why we do so below, beginning with our decision to base the
projection on DOE recommendations and then our decision to use a 2016-
18 annual average. Finally, we state the projected exempt volumes of
gasoline and diesel based on this approach and the corresponding number
of RINs.
    First, we choose to base the projection of exempted volumes on
DOE's recommendations for two reasons, one prospective and one
retrospective. Prospectively, this is our general approach to
adjudicating SRE petitions going forward, beginning with 2019 SRE
petitions and including 2020 SRE petitions. Our approach to evaluating
SREs going forward is to follow DOE's recommendations, including
granting partial (i.e., 50 percent) exemptions, where appropriate. The
statute authorizes EPA to evaluate petitions for SREs considering DOE's
study, recommendation, and other economic factors. While final
decisions on 2020 SREs must await EPA's receipt and adjudication of
those petitions, we generally have the statutory authority to issue a
final decision consistent with DOE's recommendation.\168\ This reading
of the statute is consistent with congressional guidance to DOE \169\
and EPA.\170\
---------------------------------------------------------------------------

    \168\ Other factors, such as judicial resolution of pending
decisions or subsequent Congressional direction, could potentially
affect EPA's SRE policy going forward.
    \169\ See Consolidated Appropriations Act, 2016, Public Law 114-
113 (2015), Explanatory Statement to Senate amendment to H.R. 2029
Military Construction and Veterans Affairs and Related Agencies
Appropriations Act, 2016, Division D--Energy and Water Development
and Related Agencies Appropriations Act, 2016, available at https://docs.house.gov/meetings/RU/RU00/20151216/104298/HMTG-114-RU00-20151216-SD005.pdf. Congress in this Statement directed DOE, under
certain circumstances, ``to recommend to the EPA Administrator a 50
percent waiver of RFS requirements for the [small refinery]
petitioner.'' Id. at 35. Consistent with that guidance and since
2014, DOE has recommended 50 percent exemptions as it deemed
appropriate.
    \170\ S. Rep. 114-281. Congress in this Report provided that
``[w]hen making decisions about small refinery exemptions under the
RFS program, the Agency is directed to follow DOE's
recommendations.'' See also Consolidated Appropriations Act, 2019,
Public Law No. 116-6 (2019), H. Rep. 116-9 at 741, continuing the
directive contained in Senate Report 114-281. See also Sen. Rep.
116-123, Department of the Interior, Environment, and Related
Agencies Appropriations Bill, 2020, Report Accompanying Sen. 2580,
at 87-88 (Sept. 26, 2019) (again ``continu[ing] the directive
contained in Senate Report 114-281 related to small refinery
relief''), available at https://www.congress.gov/116/crpt/srpt123/CRPT-116srpt123.pdf. This guidance, read together with that
discussed in the previous footnote, supports the interpretation that
DOE has authority to recommend partial exemptions for particular
small refineries, and that EPA has discretion to follow that
recommendation and grant a partial exemption.
---------------------------------------------------------------------------

    We acknowledge that on August 9, 2019, we took final agency action
on 36 then-pending small refinery petitions for the 2018 compliance
year (``August 9 Memorandum Decision''),\171\ and stated that the
``best interpretation'' of the statute was that EPA should either grant
or deny petitions in full, and ``not

grant partial relief.'' Specifically, we observed that the statute
provided for exemptions as an ``extension of the exemption under
subparagraph (A)'', where subparagraph (A) stated that the RFS program
requirements ``shall not apply to small refineries under calendar year
2011.'' \172\ We had implemented the ``subparagraph (A)'' pre-2011
exemption as a full exemption for all qualifying small refineries.
Consistent with this interpretation, we concluded that ``when Congress
authorized the Administrator to provide an `extension' of that
exemption for the reason of [disproportionate economic hardship],
Congress intended that extension to be a full, and not partial,
exemption.'' \173\
---------------------------------------------------------------------------

    \171\ ``Decision on 2018 Small Refinery Exemption Petitions,''
Memorandum from Anne Idsal, Acting Assistant Administrator, Office
of Air and Radiation to Sarah Dunham, Director, Office of
Transportation and Air Quality. August 9, 2019 (``August 9
Memorandum Decision'').
    \172\ CAA section 211(o)(9)(B), (o)(9)(A).
    \173\ August 9 Memorandum Decision at 2.
---------------------------------------------------------------------------

    We believe, however, that this is not the only reasonable way to
adjudicate exemption petitions. Had Congress spoken directly to the
issue of the amount of relief EPA could provide to small refineries,
EPA would be bound by that directive. However, the statute is silent
with respect to EPA's authority to issue partial exemptions. Nothing in
the statute directly addresses this issue. No statutory language exists
characterizing the scope of an exemption; there are no terms employed
such as ``partial'' or ``full,'' or ``50%'' or ``100%.'' Moreover,
nothing in the statute obligates EPA to provide full relief where we
find that only partial relief is warranted.
    We think there is another reasonable reading of this provision of
the statute: EPA may issue partial exemptions. Notably, EPA may
determine that only partial relief is warranted based on a particular
small refinery's circumstances. In that case, it is reasonable for the
level of relief that EPA grants to reflect that determination. For
purposes of making the projection of the aggregate exempted volume of
gasoline and diesel in 2020, and going forward, we are adopting this
interpretation of the statute,\174\ and thereby depart from the
interpretation taken in the August 9 Memorandum Decision, under which
EPA ``shall either grant or deny petitions for small refinery hardship
in full, and not grant partial relief.'' \175\ We adopt this new
approach for several reasons, consistent with FCC v. Fox Television
Stations, Inc.\176\
---------------------------------------------------------------------------

    \174\ See Chevron, 467 U.S. at 842-44.
    \175\ August 9 Memorandum Decision at 2.
    \176\ See generally FCC, 556 U.S. at 515.
---------------------------------------------------------------------------

    As already noted, this new policy would allow EPA to ensure that
the level of relief that it grants appropriately reflects the
particular small refinery's disproportionate economic hardship. This
allows EPA to more precisely calibrate its RFS policy, and to strike an
appropriate balance between furthering the production and use of
renewable fuels while granting relief to small refineries that meet the
statutory criteria. This balance, moreover, is also appropriate in
light of the above-cited recent Congressional direction.\177\
---------------------------------------------------------------------------

    \177\ See supra notes 20 and 21.
---------------------------------------------------------------------------

    Even independent of our prospective SRE policy, we believe this
approach is a reasonable estimate of the aggregate exempted volume
based on a retrospective review of EPA's past SRE policies. In prior
years, EPA has taken different approaches in evaluating small refinery
petitions. As noted above, in the August 9 Memorandum Decision, we
granted full exemptions to petitioners where DOE either recommended
full or 50 percent relief. That is, in cases where DOE found a small
refinery experienced either disproportionate impacts or viability
impairment, EPA found the small refinery experienced disproportionate
economic hardship and granted a full exemption. By contrast, in earlier
years of the program, we denied petitions and provided no exemption in
certain cases where DOE recommended a 50 percent exemption, finding
that disproportionate economic hardship existed only where the small
refinery experienced both disproportionate impacts and viability
impairment.\178\ Our approach to projection, then, takes a middle
ground between these prior approaches, and is a reasonable estimate of
the aggregate exempted volume in 2020.
---------------------------------------------------------------------------

    \178\ See, e.g., Hermes Consol., LLC v. EPA, 787 F.3d 568, 575
(D.C. Cir. 2015).
---------------------------------------------------------------------------

    We now turn to our decision to use the 2016-18 annual average under
this methodology. As we have not yet received SRE petitions for 2020,
we must estimate the aggregate amount of DOE recommended relief for
that year. To do so, it is instructive to look back at what the
exempted volumes of gasoline and diesel in previous years would have
been had EPA followed DOE's recommendations, including granting partial
exemptions. These volumes, along with the Renewable Volume Obligation
(RVO) that would have been exempted, are shown in Table VII.B-1.

  Table VII.B-1--Estimated Exempted Volume of Gasoline and Diesel and Estimated RVO Exempted by Compliance Year
                                         Following DOE's Recommendations
----------------------------------------------------------------------------------------------------------------
                                                 Estimated exempted    Estimated exempted       Estimated RVO
                Compliance year                  volume of gasoline     volume of diesel      exempted (million
                                                  (million gallons)     (million gallons)           RINs)
----------------------------------------------------------------------------------------------------------------
2016..........................................                 2,450                 1,930                   440
2017..........................................                 5,650                 3,870                  1020
2018..........................................                 4,620                 3,270                   840
----------------------------------------------------------------------------------------------------------------

    As demonstrated in Table VII.B-1, the volume of gasoline and diesel
that would have been exempted if EPA had followed DOE's recommendations
has varied significantly in previous years.\179\ This is because there
are many factors that affect the number of SREs that are granted in a
given year and the aggregate exempted volume. We believe that it is
appropriate to use an average volume of the gasoline and diesel that
would have been exempted over a three-year period as our projection of
gasoline and diesel that will be exempted in 2020, rather than the
volume of gasoline and diesel that would have been exempted in any
single year. This approach averages out the effects of unique events or
market circumstances that occurred in individual past years that may or
may not occur in 2020. Given that the last year for which we have data
on small refinery exemptions is 2018,\180\ we take the average exempted
volume from 2016-18.
---------------------------------------------------------------------------

    \179\ Information about the number of SREs granted and the
volume of RINs not required to be retired as a result of those
exemptions can be found at: https://www.epa.gov/fuels-registration-reporting-and-compliance-help/rfs-small-refinery-exemptions.
    \180\ To date, we have adjudicated all 2018 small refinery
exemption petitions submitted to us. EPA has not yet adjudicated any
small refinery exemptions for the 2019 or 2020 compliance years.
---------------------------------------------------------------------------

    The average volume of these fuels that would have been exempted in
2016-18

if EPA had followed DOE's recommendations is 4,240 and 3,020 million
gallons, for gasoline and diesel fuel, respectively. We use these
values for GEi and DEi, respectively, in calculating the percentage
standards for each of the renewable fuel types. We also note that these
exempted volumes would have resulted in an average reduction to the RVO
of approximately 770 million RINs.

C. Final Standards

    The formulas in 40 CFR 80.1405 for the calculation of the
percentage standards require the specification of a total of 14
variables covering factors such as the renewable fuel volume
requirements, projected gasoline and diesel demand for all states and
territories where the RFS program applies, renewable fuels projected by
EIA to be included in the gasoline and diesel demand, and projected
gasoline and diesel volumes from exempt small refineries. The values of
all the variables used for this final rule are shown in Table VII.C-1
for the applicable 2020 standards.\181\
---------------------------------------------------------------------------

    \181\ To determine the 49-state values for gasoline and diesel,
the amount of these fuels used in Alaska is subtracted from the
totals provided by EIA because petroleum based fuels used in Alaska
do not incur RFS obligations. The Alaska fractions are determined
from the June 28, 2019 EIA State Energy Data System (SEDS), Energy
Consumption Estimates.

    Table VII.C-1--Values for Terms in Calculation of the Final 2020
                             Standards \182\
                            (billion gallons)
------------------------------------------------------------------------
                                                         Value for 2020
            Term                     Description            standards
------------------------------------------------------------------------
RFVCB.......................  Required volume of                    0.59
                               cellulosic biofuel.
RFVBBD......................  Required volume of                    2.43
                               biomass-based diesel
                               \a\.
RFVAB.......................  Required volume of                    5.09
                               advanced biofuel.
RFVRF.......................  Required volume of                   20.09
                               renewable fuel.
G...........................  Projected volume of                 142.68
                               gasoline.
D...........................  Projected volume of                  55.30
                               diesel.
RG..........................  Projected volume of                  14.42
                               renewables in gasoline.
RD..........................  Projected volume of                   2.48
                               renewables in diesel.
GS..........................  Projected volume of                      0
                               gasoline for opt-in
                               areas.
RGS.........................  Projected volume of                      0
                               renewables in gasoline
                               for opt-in areas.
DS..........................  Projected volume of                      0
                               diesel for opt-in areas.
RDS.........................  Projected volume of                      0
                               renewables in diesel
                               for opt-in areas.
GE..........................  Projected volume of                   4.24
                               gasoline for exempt
                               small refineries.
DE..........................  Projected volume of                   3.02
                               diesel for exempt small
                               refineries.
------------------------------------------------------------------------
\a\ The BBD volume used in the formula represents physical gallons. The
  formula contains a 1.5 multiplier to convert this physical volume to
  ethanol-equivalent volume.

---------------------------------------------------------------------------

    \182\ See ``Calculation of final % standards for 2020'' in
docket EPA-HQ-OAR-2019-0136.
---------------------------------------------------------------------------

    Projected volumes of gasoline and diesel, and the renewable fuels
contained within them, were provided by EIA in a letter to EPA that is
required under the statute, and represent consumption values from the
October 2019 version of EIA's Short-Term Energy Outlook.\183\ An
estimate of fuel consumed in Alaska, derived from the June 28, 2019
release of EIA's State Energy Data System (SEDS) and based on the 2017
volumes contained therein, was subtracted from the nationwide volumes.
---------------------------------------------------------------------------

    \183\ ``EIA letter to EPA with 2020 volume projections 10-9-
2019,'' available in docket EPA-HQ-OAR-2019-0136.
---------------------------------------------------------------------------

    Using the volumes shown in Table VII.C-1, we have calculated the
final percentage standards for 2020 as shown in Table VII.C-2.

           Table VII.C-2--Final Percentage Standards for 2020
------------------------------------------------------------------------

------------------------------------------------------------------------
Cellulosic biofuel.........................................        0.34%
Biomass-based diesel.......................................    \a\ 2.10%
Advanced biofuel...........................................         2.93
Renewable fuel.............................................       11.56%
------------------------------------------------------------------------
\a\ Based on the ethanol-equivalent volume of BBD.

VIII. Administrative Actions

A. Assessment of the Domestic Aggregate Compliance Approach

    The RFS regulations specify an ``aggregate compliance'' approach
for demonstrating that planted crops and crop residue from the U.S.
complies with the ``renewable biomass'' requirements that address lands
from which qualifying feedstocks may be harvested.\184\ In the 2010
RFS2 rulemaking, EPA established a baseline number of acres for U.S.
agricultural land in 2007 (the year of EISA enactment) and determined
that as long as this baseline number of acres was not exceeded, it was
unlikely that new land outside of the 2007 baseline would be devoted to
crop production based on historical trends and economic considerations.
The regulations specify, therefore, that renewable fuel producers using
planted crops or crop residue from the U.S. as feedstock in renewable
fuel production need not undertake individual recordkeeping and
reporting related to documenting that their feedstocks come from
qualifying lands, unless EPA determines through one of its annual
evaluations that the 2007 baseline acreage of 402 million acres
agricultural land has been exceeded.
---------------------------------------------------------------------------

    \184\ 40 CFR 80.1454(g). EPA has applied this ``aggregate
compliance'' approach for the United States in annual RFS
rulemakings since establishing it in the 2010 RFS2 rule. See 75 FR
14701-04. In this annual rulemaking, we have not reexamined or
reopened this policy, including the regulations at 80.1454(g) and
80.1457. Similarly, as further explained below, we have applied this
approach for Canada since our approval of Canada's petition to use
aggregate compliance in 2011. In this rulemaking, we have also not
reexamined or reopened our decision on that petition. Any comments
on these issues are beyond the scope of this rulemaking.
---------------------------------------------------------------------------

    In the 2010 RFS2 rulemaking, EPA committed to make an annual
finding concerning whether the 2007 baseline amount of U.S.
agricultural land has been exceeded in a given year. If the baseline is
found to have been exceeded, then producers using U.S. planted crops
and crop residue as feedstocks for renewable fuel production would be
required to comply with individual recordkeeping and reporting
requirements to verify

that their feedstocks are renewable biomass.
    Based on data provided by the USDA Farm Service Agency (FSA) and
Natural Resources Conservation Service (NRCS), we have estimated that
U.S. agricultural land reached approximately 379.8 million acres in
2019 and thus did not exceed the 2007 baseline acreage of 402 million
acres. The USDA data used to make this derivation can be found in the
docket to this rule.\185\
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    \185\ USDA also provided EPA with 2019 data from the
discontinued Grassland Reserve Program (GRP) and Wetlands Reserve
Program (WRP). Given this data, EPA estimated the total U.S.
agricultural land both including and omitting the GRP and WRP
acreage. In 2019, combined land under GRP and WRP totaled 2,974,573
acres. Subtracting the GRP, WRP, and Agriculture Conservation
Easement Program acreage yields an estimate of 376,853,632 acres or
approximately 376.9 million total acres of U.S. agricultural land in
2019. Omitting the GRP and WRP data yields approximately 379.8
million acres of U.S. agricultural land in 2019.
---------------------------------------------------------------------------

B. Assessment of the Canadian Aggregate Compliance Approach

    The RFS regulations specify a petition process through which EPA
may approve the use of an aggregate compliance approach for planted
crops and crop residue from foreign countries.\186\ On September 29,
2011, EPA approved such a petition from the Government of Canada.\187\
---------------------------------------------------------------------------

    \186\ 40 CFR 80.1457.
    \187\ See ``EPA Decision on Canadian Aggregate Compliance
Approach Petition'' available in docket EPA-HQ-OAR-2019-0136.
---------------------------------------------------------------------------

    The total agricultural land in Canada in 2019 is estimated at 118.1
million acres. This total agricultural land area includes 95.9 million
acres of cropland and summer fallow, 12.4 million acres of pastureland
and 9.8 million acres of agricultural land under conservation
practices. This acreage estimate is based on the same methodology used
to set the 2007 baseline acreage for Canadian agricultural land in
EPA's response to Canada's petition. The data used to make this
calculation can be found in the docket to this rule. This acreage does
not exceed the 2007 baseline acreage of 122.1 million acres.

IX. Amendments to the RFS and Fuels Program Regulations

    In implementing the RFS program, we have identified several changes
to the program that will assist with implementation in future years.
These regulatory changes include both revisions we proposed in the July
29 proposal--clarification of diesel RVO calculations, pathway petition
conditions, a biodiesel esterification pretreatment pathway, distillers
corn oil and distillers sorghum oil pathways, and renewable fuel
exporter provisions--and certain provisions of the 2016 REGS rule
proposal that we are finalizing here.\188\ These regulatory changes are
described in this section. Comments on these regulatory revisions from
both the 2016 REGS and 2020 RVO proposals, as well as EPA's responses,
are contained in the response to comments (RTC) document in the docket
for this action.\189\
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    \188\ See 81 FR 80828 (November 16, 2016).
    \189\ All comments submitted on the REGS proposal can be found
in Docket No. EPA-HQ-OAR-2016-0041. Specific comments relevant to
the provisions that were under consideration for finalization in
this action have also been added to the docket for this action
(Docket Item No. EPA-HQ-OAR-2019-0136-0002). We are only responding
to comments from the REGS proposal on the provisions that are being
finalized in this action. Comments on the remaining provisions in
the REGS proposal, as well as those on provisions listed in the July
29 proposal but that are not being finalized here, remain under
consideration. We are not responding to them in this action.
---------------------------------------------------------------------------

A. Clarification of Diesel RVO Calculations

1. Overview
    We are finalizing certain provisions regarding clarification of
diesel RVO calculations. Specifically, we are finalizing the ``primary
approach'' proposed in the July 29 proposal, with some modifications
based on comments received. We are not finalizing either of the two
alternative approaches presented in the July 29 proposal, after
consideration of negative comments on these two approaches.
    Historically, home heating oil (HO) and diesel fuel were virtually
indistinguishable because both contained the same distillation range of
hydrocarbons and high level of sulfur. EPA's diesel fuel sulfur
regulations resulted in a distinction in the marketplace beginning in
the 1990s and concluding in 2010 with the phase-in of the ultra-low
sulfur diesel regulations for diesel fuel used in motor vehicles and
motor vehicle engines (MV diesel fuel). Similarly, beginning in 2004,
EPA promulgated requirements for diesel fuel used in nonroad,
locomotive, and marine vehicles and engines (NRLM diesel fuel) that
concluded phasing in at the end of 2014. Thus, all diesel fuel for use
in motor vehicles and motor vehicle engines, and nonroad, locomotive,
and marine vehicles and engines, is currently required to meet a 15 ppm
sulfur per-gallon standard, under regulations set out in 40 CFR part
80, subpart I \190\ (For purposes of subpart I, such diesel fuel is
also now collectively known as MVNRLM diesel fuel). We did not set
standards for HO under subpart I, with the result that it remained high
in sulfur content and cost less to produce than MVNRLM diesel fuel. As
such, subpart I also requires all parties in the distribution system to
ensure that diesel fuel containing 15 ppm sulfur or less (referred to
as 15 ppm diesel fuel, ultra-low sulfur diesel fuel, or ULSD) remains
segregated from higher sulfur fuels and to take measures to prevent
sulfur contamination of ULSD.\191\
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    \190\ Subpart I includes an exception to this requirement that
allows diesel fuel used in locomotive or marine engines to meet a
500 ppm sulfur standard if the fuel is produced from transmix
processors and distributed under an approved compliance plan.
    \191\ See, e.g., 40 CFR 80.610(g).
---------------------------------------------------------------------------

    The RFS regulations, which place an RVO on the production and
importation of diesel transportation fuel, but not on the production or
importation of HO, were promulgated in 2010 and, similar to subpart I
regulations, made the same presumption that HO and MVNRLM diesel fuel
would be segregated. The RFS regulations did not anticipate that these
fuels would become indistinguishable, have the same value in the
marketplace (apart from their RFS compliance cost), and be commingled
in the fuel distribution system. For example, 40 CFR 80.1407 set forth
requirements for obligated parties to include all products meeting the
definition of MVNRLM diesel fuel, collectively called ``diesel fuel,''
at 40 CFR 80.2(qqq) that are produced or imported during a compliance
period in the volume used to calculate their RVOs unless the diesel
fuel is not transportation fuel.\192\ Under definitions of MV and NRLM
diesel fuel, these products include diesel fuel that is ``made
available'' for use in motor vehicles and motor vehicle engines, and
nonroad, locomotive, or marine vehicles and engines.\193\
---------------------------------------------------------------------------

    \192\ See 40 CFR 80.1407(e) and (f).
    \193\ See 40 CFR 80.2(y) and (nnn).
---------------------------------------------------------------------------

    When the RFS regulations were promulgated in 2010, the lower
production cost of HO relative to diesel fuel provided economic
incentive for refiners, pipelines, and terminals to produce and
distribute HO separately from diesel fuel. After we promulgated the RFS
regulations, however, many states began implementing programs designed
to reduce the sulfur content of HO to 15 ppm or less (15 ppm HO).
Currently, the majority of HO is required to meet a 15 ppm sulfur
standard under numerous state and city programs in the Northeast and
Mid-Atlantic,\194\ making HO once again indistinguishable from ULSD and
of the same economic value as MVNRLM

diesel fuel.\195\ Further, in 2015, additional regulations became
effective that required marine diesel fuel used in Emissions Control
Areas (ECA marine fuel) to contain 1,000 ppm sulfur or less.\196\ In
response, many companies have opted to produce and distribute ECA
marine fuel containing 15 ppm sulfur or less (15 ppm ECA marine fuel)
fungibly with 15 ppm diesel fuel, rather than invest in infrastructure
to distribute and segregate higher-sulfur ECA marine fuel. Since HO,
ECA marine fuel, and other non-transportation fuels that meet a 15 ppm
sulfur standard are essentially identical in the marketplace, we
believe that some parties in the fuel distribution system are
distributing them together--i.e., commingling MVNRLM diesel fuel with
15 ppm HO and 15 ppm ECA marine fuel.
---------------------------------------------------------------------------

    \194\ Connecticut, Delaware, Maine, Massachusetts, New
Hampshire, New Jersey, New York, Rhode Island, Vermont, the District
of Columbia, and the city of Philadelphia.
    \195\ See the New England Fuel Institute's (NEFI) ``State Sulfur
& Bioheat Requirements for No. 2 Heating Oil in the Northeast & Mid-
Atlantic States,'' available in the docket for this action.
    \196\ See 40 CFR 80.610(e)(6). ECA marine fuel is not
transportation fuel under the RFS regulations. Therefore, refiners
and importers do not incur an RVO for ECA marine fuel that they
produce or import.
---------------------------------------------------------------------------

    The regulations in 40 CFR part 80, subpart I, do not prohibit
parties from commingling MVNRLM diesel fuel with other 15 ppm
distillate fuel (i.e., distillate fuel that contains 15 ppm sulfur or
less) that is designated for non-transportation purposes. However,
commingled fuel must meet all of the applicable requirements in subpart
I because the resulting fuel is ``made available'' for use in motor
vehicles, or nonroad, locomotive, or marine vehicles and engines.\197\
This means that any refiner or importer that produces or imports 15 ppm
distillate fuel that is designated for non-transportation purposes and
is commingled with MVNRLM diesel fuel must also certify the fuel as
meeting the sampling, testing, reporting, and recordkeeping
requirements in subpart I.\198\
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    \197\ See 40 CFR 80.2(y) and (nnn).
    \198\ We have received requests from a number of regulated
parties asking the agency to amend the fuels regulations to allow
parties to more easily mix and fungibly ship HO, ECA marine fuel,
and MVNRLM fuel that meet the 15 ppm sulfur standard. In a separate
action, we intend to propose additional amendments that would
significantly streamline these regulations (see RIN 2060-AT31 in
EPA's Regulatory Agenda).
---------------------------------------------------------------------------

    Although this approach does not create compliance issues relating
to subpart I requirements, at proposal we explained that we were
concerned that some obligated parties (e.g., refiners and importers)
under the RFS program may be calculating RVOs without accounting for
all of their 15 ppm distillate fuel that is ultimately sold for use as
MVNRLM diesel fuel. Specifically, obligated parties may be excluding 15
ppm HO or 15 ppm ECA marine fuel from their RVO calculations, and
downstream parties may be re-designating this fuel as MVNRLM diesel
fuel and not incurring an RVO.\199\
---------------------------------------------------------------------------

    \199\ A similar situation exists with respect to #1 diesel fuel,
which is used/blended in the winter due to cold temperature
constraints and its often-identical counterparts of kerosene and jet
fuel.
---------------------------------------------------------------------------

    We also explained that with the convergence of the MVNRLM diesel
fuel, HO, and ECA marine fuel sulfur standards, some stakeholders had
expressed confusion to EPA on accounting for 15 ppm distillate fuel
that leaves the obligated party's gate designated as HO, ECA marine
fuel, or other non-transportation fuels, but is subsequently re-
designated as either MVNRLM diesel fuel or ultimately used as MVNRLM
diesel fuel by a downstream entity. Specifically, some obligated
parties had asked whether they are required to add re-designated MVNRLM
diesel fuel back to their RVO calculations while some downstream
entities had asked whether they are required to incur an RVO for MVNRLM
diesel fuel they re-designate from non-transportation fuel to
transportation fuel.
    We further explained in the July 29 proposal that we intended for
any diesel fuel not used as transportation fuel, such as HO or ECA
marine fuel, to be excluded from RVO calculations in keeping with
statutory requirements.\200\ We also intended for all diesel fuel
ultimately used as transportation fuel to incur an RVO, even 15 ppm
distillate fuel that is initially designated as non-transportation fuel
and subsequently re-designated as transportation fuel by downstream
parties.\201\ Thus, existing regulations allow downstream parties who
are registered as refiners and who comply with all sampling, testing,
recordkeeping, and other refiner requirements to ``produce'' MVNRLM
diesel fuel from HO, ECA marine fuel, and other non-transportation
fuels. These refiners incur RVOs for all MVNRLM diesel fuel that they
``produce'' from the non-transportation fuel. However, we believe that
stakeholder confusion over who should account for re-designated fuel in
their RVO may be causing the omission of some re-designated MVNRLM
diesel fuel from RVO calculations altogether. Therefore, we are
revising the RFS regulations to more clearly specify how volumes of re-
designated MVNRLM diesel fuel are accounted for in obligated parties'
RVO calculations in order to ensure that the RFS mandates continue to
be met.
---------------------------------------------------------------------------

    \200\ See 40 CFR 80.1407(f)(8).
    \201\ With the other exceptions listed in 40 CFR 80.1407(f).
---------------------------------------------------------------------------

    Consistent with our proposal, we are clarifying the requirement for
refiners and importers to include distillate fuel in their RVO
compliance calculations and providing exceptions for the following
three additional categories of fuel:
     Distillate fuel, such as HO or ECA marine fuel, with a
sulfur content greater than 15 ppm that is clearly designated for a use
other than transportation fuel.
     Distillate fuel that meets the 15 ppm sulfur standard,
that is designated for non-transportation use, and that remains
completely segregated from MVNRLM diesel fuel from the point of
production through to the point of use for a non-transportation
purpose.
     Distillate fuel that meets the 15 ppm diesel sulfur
standard, that is ultimately used for non-transportation purposes, and
that does not remain completely segregated from MVNRLM diesel fuel.
    As also explained in the July 29 proposal, since the first two
categories of distillate fuel above are completely segregated from
MVNRLM diesel fuel, we do not believe that they would be used as
transportation fuel and are therefore not finalizing any additional
requirements for these fuels to be excluded from a refiner or
importer's RVO compliance calculations. However, consistent with the
July 29 proposal, and as described below, because the third category of
distillate fuel is not completely segregated and is indistinguishable
from MVNRLM diesel fuel, we are finalizing additional requirements for
this type of distillate fuel to be excluded from a refiner or
importer's RVO compliance calculations.
2. Downstream Re-Designation of Certified Non-Transportation 15 ppm
Distillate Fuel to MVNRLM Diesel Fuel
    Consistent with the July 29 proposal, and in order to allow
refiners and importers to exclude distillate fuel that that meets the
15 ppm diesel sulfur standard, is ultimately used for non-
transportation purposes, and does not remain completely segregated from
MVNRLM diesel fuel from their RVO calculations, we are establishing a
new category of distillate fuel: Certified non-transportation 15 ppm
distillate fuel (``certified NTDF''). We are defining certified NTDF as
distillate fuel that meets all of the following requirements:
     Fuel that is certified as complying with the 15 ppm sulfur
standard, cetane/aromatics standard, and all applicable sampling,
testing, and

recordkeeping requirements of 40 CFR part 80, subpart I.
     Fuel that is designated on the product transfer document
as 15 ppm HO, 15 ppm ECA marine fuel, or other non-transportation fuel
(e.g., jet fuel, kerosene, No. 4 fuel, or distillate fuel for export
only) with a notation that the fuel is ``15 ppm sulfur (maximum)
certified NTDF--This fuel is designated for non-transportation use.''
with no designation as MVNRLM diesel fuel.
    Some commenters noted that our proposed PTD language stating,
``This fuel meets all MVNRLM diesel fuel standards'' could potentially
cause confusion as to whether the fuel qualified as MVNRLM diesel fuel
or not. We are therefore finalizing PTD language similar to that
suggested by commenters, which avoids any reference to MVNRLM diesel
fuel.
    In order to prevent refiners and importers from circumventing the
requirement to incur an RVO for all transportation fuel by simply
designating transportation fuel as non-transportation fuel, we had
proposed that refiners or importers must have a reasonable expectation
that their NTDF will be used as HO, ECA marine fuel, or another non-
transportation purpose in order to exclude it from their RVO
calculations. We proposed that refiners or importers would need to meet
the following three criteria to demonstrate they have a reasonable
expectation that NTDF will not be used as transportation fuel:
     The refiner or importer supplies areas that use HO, ECA
marine fuel, or 15 ppm distillate fuel for non-transportation purposes
in the quantities being supplied by the refiner or importer.
     The refiner or importer has entered into a contractual
arrangement that prohibits the buyer from selling the fuel as MVNRLM
diesel fuel.
     The volume of fuel designated as HO, ECA marine fuel, or
other non-transportation purposes is consistent with the refiner's or
importer's past practices or reflect changed market conditions.
    We also noted that EPA may consider any other relevant information
in assessing whether a refiner or importer has a reasonable expectation
that the fuel was used for non-transportation purposes.
    We received comments indicating that it would be complex and
disruptive to require refiners and importers to enter into contractual
arrangements that prohibit the buyers from selling NTDF as MVNRLM
diesel fuel. We agree with these comments and have eliminated this
criterion. In light of these comments and in order to simplify the
proposed regulations, we have also consolidated the first and third
criterion into one sentence that states ``[t]o establish a reasonable
expectation that the fuel will be used for non-transportation purposes,
a refiner or importer must, at a minimum, be able to demonstrate that
they supply areas that use heating oil, ECA marine fuel, or 15 ppm
distillate fuel for non-transportation purposes in quantities that are
consistent with past practices or changed circumstances.'' With these
changes, we are finalizing the requirement that refiners or importers
may only exclude NTDF from their compliance calculations if they have a
reasonable expectation that the fuel will be used for non-
transportation purposes.
    Some commenters also noted that there is normally a noticeable
price difference between fuel sold for transportation fuel and non-
transportation fuel, and that this price difference is a relevant
consideration for determining if the fuel was intended to be sold as
transportation fuel or non-transportation fuel. We agree with this
comment and the final rule explicitly identifies price as relevant
information that EPA may consider in evaluating whether a refiner or
importer had a reasonable expectation that the fuel will be sold for
non-transportation purposes.
    As previously noted, our intent is to ensure that all fuel
ultimately used as MVNRLM diesel fuel incurs an RVO. In order to
achieve this goal, we are also finalizing requirements that will allow
parties in the fuel distribution system (e.g., downstream of the
original refinery or import facility) to sell certified NTDF as MVNRLM
diesel fuel without incurring an RVO if the total volume of MVNRLM
diesel fuel delivered during each compliance period does not exceed the
amount of MVNRLM diesel fuel received during that compliance period.
Any party who re-designates certified NTDF as MVNRLM diesel fuel is a
refiner for purposes of the RFS program and is therefore required to
register as a refiner. They will also be required to calculate whether
the volume of MVNRLM diesel fuel that they deliver exceeds the volume
of MVNRLM diesel fuel that they receive, during an annual compliance
period. If a downstream party delivers a volume of MVNRLM diesel fuel
that exceeds the volume of MVNRLM diesel fuel they received during a
compliance period, they are required to treat the difference as diesel
fuel that they ``produced'' and incur an RVO on this volume. This will
enable proper accounting for the aggregate volume of non-transportation
fuel that is re-designated as MVNRLM diesel fuel under the RFS program.
This one-sided test allows MVNRLM diesel fuel to be sold as HO or ECA
marine fuel but prevents the erosion of the renewable fuel mandate.
These parties will also be subject to recordkeeping requirements to
ensure the enforceability of this program.
    We received several comments recommending modifications and
clarifications to the proposed volume balance provisions, and are
finalizing the following changes in response to these comments:
     We are adding an equation to the regulations that provides
specific guidance on how to calculate the volume balance. This is in
response to a comment suggesting that EPA should include a balance
equation for diesel fuel, similar to the heating oil balance in 40 CFR
80.599(c)(3) and (4). The new balance equation accounts for changes in
diesel inventory, in addition to diesel volumes in and out.
     We are clarifying that the volume balance requirement
applies to each facility that is registered as a diesel refinery. This
is in response to comments suggesting that EPA clarify whether the
volume balances were applicable on a facility basis or an aggregated
basis. Our intent was that the balances apply on a facility basis and
have clarified this in the final regulations.
    One commenter also recommended that the new provisions for
redesignation of certified NTDF to MVNRLM diesel fuel should apply to
the owner of the certified NTDF at the time of redesignation and not
the custody holder of the certified NTDF, or the original refiner of
the NTDF. We agree with this recommendation and have included final
rule requirements that reflect this recommendation. Since the owner of
certified NTDF would be responsible for making any decisions regarding
redesignation of NTDF to MVNRLM diesel fuel, we intend for the owner of
the certified NTDF to meet the regulatory requirements associated with
redesignation, such as registration, reporting, and incurring an RVO.
    We are also finalizing corresponding reporting requirements,
including requiring refiners and importers to report the volume of
MVNRLM diesel fuel they produce or import, the volume of distillate
fuel they produce or import that is not transportation fuel, and the
volume of distillate fuel they produce or import that is certified
NTDF. We are also requiring some downstream parties who redesignate
NTDF as MVNRLM diesel fuel to submit reports to EPA identifying the
volume of MVNRLM

diesel fuel received, the volume of MVNRLM diesel fuel delivered, the
volume of fuel re-designated from certified NTDF to MVNRLM diesel fuel,
and the volume of MVNRLM diesel fuel redesignated to non-transportation
use. Further, for purposes of evaluating compliance, we are also:
     Requiring parties who re-designate certified NTDF to
MVNRLM diesel fuel to keep all records relating to these transactions.
     Prohibiting a party from exceeding its balance
requirements without incurring an RVO.
     Ensuring that the attest auditors review relevant
information to ensure compliance with applicable RFS program
requirements.
    Some commenters stated that it was not necessary to require that
volume balance reports and attest engagements be submitted by all
parties who redesignate certified NTDF to MVNRLM diesel fuel, and that
EPA should only require reports from those parties who redesignated a
net positive volume of certified NTDF to MVNRLM diesel fuel (i.e.,
incurred an RVO). We agree with these comments and are finalizing
provisions to require parties that only incur an RVO through
redesignation of certified NTDF to MVNRLM diesel fuel to submit volume
balance reports and meet the required attest engagements. Obligated
parties that would otherwise have an attest engagement performed (e.g.,
because they produced gasoline or diesel fuel, exported renewable
fuels, etc.) would now have the attest auditor perform the additional
attest engagement procedures for the obligated party. We believe that
the types of reports and records attest auditors review for obligated
parties annual attest engagements would already include much of the
information we are requiring and would therefore represent a minimal
increase in burden for these obligated parties. Parties that
redesignate certified NTDF to MVNRLM diesel fuel during a compliance
period but did not incur an RVO (because they redesignated an
equivalent or greater volume of MVNRLM diesel fuel to non-
transportation fuel during the compliance period) are required to
submit a short report stating that they redesignated certified NTDF to
MVNRLM diesel fuel, but did not incur an RVO. We are also not
finalizing the proposed requirement for quarterly reports, since
compliance will be on an annual basis and can be demonstrated through
annual reports.
    Lastly, implementation of these new provisions will be delayed
until January 1, 2021, to allow time for updates to product codes and
tracking software used by distillate distributors. Some commenters
suggested that this would be helpful for them to avoid implementing the
new regulations in the middle of a compliance period, and we agree with
these commenters.

B. Pathway Petition Conditions

    We are clarifying our authority to enforce conditions created by
requirements included in an approval document for a facility-specific
pathway petition submitted under 40 CFR 80.1416. Since December 2010,
we have approved over 100 facility-specific pathway petitions. To
qualify for the generation of RINs under an approved pathway petition,
the fuel produced under that pathway must also meet the conditions and
applicable regulatory provisions specified in EPA's petition approval
document and the other definitional and regulatory requirements for
renewable fuel specified in the CAA and EPA implementing regulations,
including for RIN generation, registration, reporting, and
recordkeeping. Common conditions include, but are not limited to,
compliance monitoring plans detailing how parties will accurately and
reliably measure and record the energy and material inputs and outputs
required to ensure fuels are produced consistent with the
specifications evaluated in the lifecycle analysis, process flow
diagrams showing the energy used for feedstock, fuel, and co-product
operations, and certifications signed by responsible corporate officers
(RCOs).
    We have authority to bring an enforcement action of these
conditions under 40 CFR 80.1460(a), which prohibits producing or
importing a renewable fuel without complying with the RIN generation
and assignment requirements. The RFS regulations provide that RINs may
only be generated if the fuel qualifies for a D code pursuant to 40 CFR
80.1426(f) or an approved petition submitted under 40 CFR 80.1416.\202\
If any of the conditions required by an approval document for a pathway
petition are not met, then the fuel does not qualify for a D code per
the terms of the approval, and RINs may not be generated. These
conditions are also enforceable under 40 CFR 80.1460(b)(2), which
prohibits creating a RIN that is invalid; a RIN is invalid if it was
improperly generated.\203\ As stated above, a RIN is improperly
generated if the fuel representing the RIN does not qualify for a D
code, which is the case if a fuel producer does not follow all of the
required conditions in the pathway petition approval document.
---------------------------------------------------------------------------

    \202\ See 40 CFR 80.1426(a)(1)(i).
    \203\ See 40 CFR 80.1431(a)(ix).
---------------------------------------------------------------------------

    We are adding a provision at 40 CFR 80.1426(a)(1)(iii) to clarify
that renewable fuel that qualifies for a D code pursuant to an approved
petition submitted under 40 CFR 80.1416 must be produced in compliance
with all conditions set forth in the petition approval document (in
addition to the applicable statutory requirements and requirements of
subpart M). We are also adding a prohibited act at 40 CFR 80.1460(b)(7)
for generating a RIN for fuel that fails to meet all the conditions set
forth in a petition approval document for a pathway petition submitted
under 40 CFR 80.1416 in order to provide more clarity regarding our
ability to bring enforcement actions for failure to meet such
conditions.

C. Esterification Pretreatment Pathway

    We are revising rows F and H of Table 1 to 40 CFR 80.1426 by
changing the existing approved production process ``Trans-
Esterification'' to be ``Transesterification with or without
esterification pretreatment.'' We are finalizing these revisions to
rows F and H without modifying the feedstocks listed in those rows, as
these changes do not make any additional feedstocks eligible beyond
those already listed in rows F and H. Table 1 to 40 CFR 80.1426
includes pathways for the production of biodiesel using specified
feedstocks and the production process transesterification.\204\
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    \204\ While we expect these pathways to be used predominately
for biodiesel, they may also be used for heating oil and jet fuel.
Renewable diesel is excluded because it is by definition ``not a
mono-alkyl ester'' (40 CFR 80.1401) and that is what
transesterification produces.
---------------------------------------------------------------------------

    Transesterification is the most commonly used method to produce
biodiesel and involves reacting triglycerides with methanol, typically
under the presence of a base catalyst.\205\ While the main component of
oils, fats, and grease feedstocks are typically triglycerides, other
components, such as free fatty acids (FFAs), can also exist. Removal or
conversion of the FFAs is important where the traditional base-
catalyzed transesterification production process is used; if they are
not removed or converted prior to this process, FFAs will react with
base catalysts to produce soaps that inhibit the transesterification
reaction.
---------------------------------------------------------------------------

    \205\ Commonly used base catalysts include sodium hydroxide
(NaOH), potassium hydroxide (KOH) and sodium methoxide
(NaOCH3).
---------------------------------------------------------------------------

    One of the most widely used methods for treating biodiesel
feedstocks with a higher FFA content is acid catalysis. Acid catalysis
typically uses a strong

acid, such as sulfuric acid, to catalyze the esterification of the FFAs
prior to the transesterification of the triglycerides as a pre-
treatment step. Acid esterification can be applied to feedstocks with
FFA contents above 5 percent to produce biodiesel. Because the
transesterification of triglycerides is slow under acid catalysis, a
technique commonly used to overcome the reaction rate issue is to first
convert the FFAs through an acid esterification (also known as an acid
``pretreatment'' step), and then follow-up with the traditional base-
catalyzed transesterification of triglycerides.
    Under the RFS2 final rule, biodiesel from biogenic waste oils/fats/
greases qualifies for D-codes 4 or 5 using a transesterification
process. This conclusion was based on the analysis of yellow grease as
a feedstock, where there was an acid pretreatment of the FFAs contained
in the feedstock. In fact, one of the material inputs assumed in the
modeling for the final RFS2 rule yellow grease pathway was sulfuric
acid, which is the catalyst commonly used for acid esterification.\206\
As we had not stipulated transesterification with esterification
pretreatment as a qualified production process in rows F and H to Table
1 to 40 CFR 80.1426, we are revising these entries to include
``transesterification with or without esterification pre-treatment'' as
a production process requirement so that RINs may be generated for
biodiesel produced by the esterification pretreatment, as well as for
the biodiesel produced through transesterification.\207\
---------------------------------------------------------------------------

    \206\ Section <IP_ADDRESS>.3 of the Regulatory Impact Analysis for
the March 2010 final rule describes the material inputs evaluated
for biodiesel production. For conversion of yellow grease to
biodiesel, sulfuric acid accounted for 4.7 percent of the material
inputs on a mass basis (0.02 kg per gallon of biodiesel).
    \207\ In 2012, we issued a direct final rule and a parallel
proposed rule (see 77 FR 700 and 77 FR 462, respectively; January 5,
2012) that would have determined that, among other regulatory
changes, biodiesel produced from esterification met the GHG
reduction requirements. Because we received adverse comment, we
withdrew the direct final rule in its entirety (see 77 FR 13009,
March 5, 2012). In the 2013 final rule based on the parallel
proposal (78 FR 14190, March 5, 2013), we decided not to finalize a
determination at that time on biodiesel produced from esterification
and noted that we would instead make a final determination at a
later time.
---------------------------------------------------------------------------

    In the July 29 proposal, we also proposed to add a standalone
esterification pathway to rows F and H to Table 1 to 40 CFR 80.1426,
which would allow parties who have processing units that can take
feedstocks listed in rows F and H of Table 1 to 40 CFR 80.1426 that
have high-FFA content and separate the FFAs and triglycerides for
chemical processing in separate standalone esterification and
transesterification units to generate RINs for the biodiesel produced.
However, we are not at this time finalizing the proposed standalone
esterification pathway. It remains under consideration and may be
finalized in a future action.

D. Distillers Corn Oil and Distillers Sorghum Oil Pathways

    We are adding distillers corn oil and commingled distillers corn
oil and sorghum oil as feedstocks to row I of Table 1 to 40 CFR
80.1426. While the lifecycle GHG emissions associated with using a very
similar feedstock--distillers sorghum oil--as part of this pathway were
evaluated in the grain sorghum oil pathway final rule (``sorghum oil
rule''),\208\ these two feedstocks were not added to row I as part of
that rulemaking. This section discusses the addition of distillers corn
oil and commingled distillers corn oil and sorghum oil as feedstocks to
row I and presents the lifecycle GHG emissions associated with these
pathways. We also explain why the most likely effect of adding these
pathways will be to reduce the number of petitions submitted pursuant
to 40 CFR 80.1416.
---------------------------------------------------------------------------

    \208\ See 83 FR 37735 (August 2, 2018).
---------------------------------------------------------------------------

    The March 2010 RFS2 rule included pathways for biodiesel and
renewable diesel produced from non-food grade corn oil. The March 2013
Pathways I rule added pathways for heating oil and jet fuel from non-
food grade corn oil in rows F and H of Table 1 to 40 CFR 80.1426, and
added pathways for naphtha and LPG from Camelina sativa oil in row
I.\209\ The sorghum oil rule amended the RFS regulations to add a new
definition of distillers sorghum oil and to replace existing references
to non-food grade corn oil with the newly defined term ``distillers
corn oil.'' That rule also added a number of pathways to rows F and H
of Table 1 to 40 CFR 80.1426 for biodiesel, renewable diesel, jet fuel,
and heating oil produced from distillers sorghum oil and commingled
distillers sorghum and corn oil. Pathways for naphtha and LPG produced
from distillers sorghum oil via a hydrotreating process were also added
to row I of Table 1 to 40 CFR 80.1426.
---------------------------------------------------------------------------

    \209\ See 78 FR 14190 (March 5, 2013).
---------------------------------------------------------------------------

    Commingled distillers corn oil and sorghum oil was added as a
feedstock to rows F and H of Table 1 to 40 CFR 80.1426 because
distillers sorghum oil is often co-produced with distillers corn oil at
ethanol plants using a combination of grain sorghum and corn as
feedstocks for ethanol production. Due to the recovery process of the
oils from the distillers grains and solubles (DGS), where the ethanol
plant is using a feedstock that combines grain sorghum and corn, it is
not possible to physically separate the distillers sorghum and corn
oils into two streams, nor is it possible to account for the volume of
sorghum oil or corn oil in this mixture. For these and other
reasons,\210\ after concluding that distillers sorghum oil satisfies
the 50 percent GHG reduction threshold required for the advanced
biofuel and biomass-based diesel, we added both distillers sorghum oil
and ``commingled distillers corn oil and sorghum oil'' to rows F and H
of Table 1 to 40 CFR 80.1426 in the sorghum oil rule. However, unlike
rows F and H, row I did not include a pathway using ``non-food grade
corn oil'' prior to that final rule, nor did we propose to add
``distillers corn oil'' to that row in the December 2017 sorghum oil
proposed rule.\211\ Thus, in the absence of an assessment of lifecycle
emissions showing that distillers corn oil also meets the GHG reduction
threshold required for the pathways therein, in the sorghum oil rule we
decided ``it would be premature for EPA to add either distillers corn
oil or commingled distillers corn and sorghum oil as feedstocks in row
I.'' \212\ Currently, in order to generate D-code 5 RINs for naphtha
and/or LPG produced from distillers corn oil and/or commingled
distillers corn and sorghum oil, a fuel producer would first need to
petition EPA pursuant to 40 CFR 80.1416, have EPA review and approve
their requested pathway, and then submit and have EPA accept the
registration for the new pathway. Adding these feedstocks to row I
eliminates the need for these petitions.
---------------------------------------------------------------------------

    \210\ For the other reasons discussed in the sorghum oil rule
preamble, see 83 FR 37737-39 (August 2, 2018).
    \211\ See 82 FR 61205 (December 27, 2017).
    \212\ See 83 FR 37738 (August 2, 2018).
---------------------------------------------------------------------------

    Table IX.D-1 shows the lifecycle GHG emissions associated with
renewable diesel, jet fuel, naphtha, and LPG produced from distillers
sorghum oil. These results are based on the analysis completed for the
sorghum oil rule.\213\ The lifecycle GHG emissions associated with the
statutory baseline fuels, 2005 average diesel and gasoline, are shown
for comparison. Based on the distillers sorghum oil results, as
explained below we have concluded that naphtha and LPG produced from
distillers corn oil and commingled distillers corn and sorghum oil also
satisfy the 50 percent lifecycle GHG reduction requirement at CAA
section 211(o)(1)(B), relative to the

statutory petroleum baseline, to be eligible for advanced biofuel RINs.
---------------------------------------------------------------------------

    \213\ See Table III.4 of the sorghum oil rule preamble (83 FR
37743, August 2, 2018).

       Table IX.D-1--Lifecycle GHG Emissions Associated With Biofuels Produced From Distillers Sorghum Oil
                                                [kgCO2-eq/mmBtu]
----------------------------------------------------------------------------------------------------------------
                                     Renewable
              Fuel                  diesel, jet       Naphtha           LPG         2005 Diesel    2005 Gasoline
                                       fuel                                          baseline        baseline
----------------------------------------------------------------------------------------------------------------
Production Process..............                   Hydrotreating
                                             Refining
                                 -------------------------------------------------------------------------------
Livestock Sector Impacts........            19.4            19.4            19.4  ..............  ..............
Feedstock Production............             6.2             6.2             6.2            18.0            19.2
Feedstock Transport.............             0.3             0.3             0.3  ..............  ..............
Feedstock Pretreatment..........             0.0             0.0             0.0  ..............  ..............
Fuel Production.................             8.0             8.0             8.0  ..............  ..............
Fuel Distribution...............             0.8             0.8             0.8  ..............  ..............
Fuel Use........................             0.7             1.7             1.5            79.0            79.0
                                 -------------------------------------------------------------------------------
    Total.......................            35.4            36.4            36.2            97.0            98.2
Percent Reduction...............             64%             63%             63%  ..............  ..............
----------------------------------------------------------------------------------------------------------------

    Although the lifecycle GHG analysis for the sorghum oil rule
focused on distillers sorghum oil, we believe it is also applicable to
distillers corn oil and commingled distillers corn oil and sorghum oil
for purposes of determining whether these satisfy the 50 percent GHG
reduction requirement. For the sorghum oil rule, we estimated the
livestock sector impacts associated with distillers sorghum oil based
on a set of assumptions about the type of feed that would need to
backfill for the reduction in mass of de-oiled DGS as compared to full-
oil DGS. For that analysis we calculated a substitution rate for how
much corn would be needed to backfill in livestock feed for every pound
of grain sorghum oil diverted to biofuel production, by livestock type.
The amounts of corn needed to replace each pound of extracted sorghum
oil were largely based on studies that evaluated the nutritional values
of regular and reduced-oil distillers grains produced as a co-product
of corn starch ethanol.\214\ Given that the underlying data for our
distillers sorghum oil assessment was largely based on studies
conducted on corn ethanol co-products, we believe it is appropriate to
apply the same results to similar pathways using distillers corn oil
feedstock. Based on the similarities between the two products and how
they are produced (i.e., co-produced at ethanol plants), we are also
assuming that the lifecycle GHG emission for distillers corn oil and
distillers sorghum oil are the same for the other lifecycle stages
evaluated (e.g., feedstock production, fuel production).
---------------------------------------------------------------------------

    \214\ See Table III.2 (Full-Oil and Reduced-Oil Sorghum
Distillers Grains with Solubles Displacement Ratios) of the sorghum
oil rule (83 FR 37741, August 2, 2018) and accompanying footnote
number 36, which lists the sources for the data in that table.
---------------------------------------------------------------------------

    One difference between distillers corn oil and sorghum oil is the
rate of oil recovered per pound of corn versus grain sorghum processed.
The distillers sorghum oil petition submitted by the National Sorghum
Producers reported that 0.67 pounds of distillers sorghum oil are
recovered per bushel of grain sorghum processed to ethanol, whereas
0.84 pounds of distillers corn oil is extracted per bushel of
corn.\215\ Adjusting for this difference results in slightly lower
livestock sector GHG emissions associated with naphtha and LPG produced
from distillers corn oil.\216\ Based on this adjustment the results in
Table IX.D-1 change from a 63 percent GHG reduction for naphtha and LPG
produced from distillers sorghum oil to a 64 percent reduction for
naphtha and LPG production from distillers corn oil. We have therefore
concluded that these pathways satisfy the 50 percent GHG reduction
requirement to qualify as advanced biofuel under the RFS program and
are adding ``distillers corn oil'' and ``commingled distillers corn oil
and sorghum oil'' as feedstocks in row I to Table 1 to 40 CFR 80.1426.
---------------------------------------------------------------------------

    \215\ See Table 4 of ``Grain Sorghum Oil Pathway Petition,''
Docket Item No. EPA-HQ-OAR-2017-0655-0005.
    \216\ The source of the difference is the amount of corn needed
to replace one pound of full-oil versus reduced-oiled DDGS in beef
cattle diets. In our analysis for the sorghum oil rule, we assumed,
based on the best available data provided by NSP, USDA, and
commenters, that reduced-oil DDGS are replaced at a lower rate
(1.173 lbs corn per lbs DDGS) than full-oil DDGS (1.196 lbs corn per
lbs DDGS). Increasing the rate of oil extraction produces less de-
oiled DDGS and requires corn replacement at the lower rate of 1.173.
Thus, all else equal, higher rates of oil extraction result in lower
GHG emissions per pound of oil extracted. It is possible this effect
would disappear if we had higher resolution data on corn
displacement ratios for DDGS with different oil contents, but such
data are currently not available.
---------------------------------------------------------------------------

E. Clarification of the Definition of Renewable Fuel Exporter and
Associated Provisions

    We are finalizing our proposed clarification of the definition of
``exporter of renewable fuel.'' These changes are meant to ensure
appropriate flexibility for market participants to meet export
obligations and to ensure RINs are properly retired, as well to as to
clarify exporter obligations for parties who transfer renewable fuel
between the 48 states or Hawaii and an approved opt-in area (i.e.,
Alaska or the U.S. territories were any of them to opt-in).
    The RFS regulations require an exporter of renewable fuel to
acquire sufficient RINs to comply with all applicable RVOs incurred
from the volumes of the renewable fuel exported.\217\ We previously
defined ``exporter of renewable fuel'' in 40 CFR 80.1401 as: ``(1) A
person that transfers any renewable fuel from a location within the
contiguous 48 states or Hawaii to a location outside the contiguous 48
states and Hawaii; and (2) A person that transfers any renewable fuel
from a location in the contiguous 48 states or Hawaii to Alaska or a
United

States territory, unless that state or territory has received an
approval from the Administrator to opt in to the renewable fuel program
pursuant to Sec.  80.1443.'' \218\
---------------------------------------------------------------------------

    \217\ In this rulemaking, we did not reexamine our well-settled
policy of exporter RVOs, which generally require exporters to retire
RINs for biofuels they export. We established this policy when we
promulgated the regulations implementing the RFS1 and RFS2 programs
in 2007 and 2010. See 72 FR 23936 (May 1, 2007); 75 FR 14724 (March
26, 2010). We did not reexamine this issue in this rulemaking, and
comments on it are beyond the scope of the rulemaking. We are not
making any substantive changes to the relevant provisions,
particularly those at 40 CFR 80.1430(a) or (b). Consistent with our
long-standing policy, exporters of renewable fuel must continue to
acquire sufficient RINs to comply with all applicable RVOs.
    \218\ 75 FR 14865 (March 26, 2010).
---------------------------------------------------------------------------

    We are revising these regulations for two key reasons. First,
during implementation of the RFS program, we have observed contract
structuring practices that may have eroded compliance assurance.
Notably, we have observed instances of export transactions in which
parties have sold renewable fuel for export to entities purporting to
accept RIN retirement obligations that were then not fulfilled by the
buyer. These instances demonstrate that the RFS program could benefit
from regulatory changes designed to ensure that exporter obligations
are fulfilled. Therefore, we are revising the definition to resolve any
potential ambiguity and clarify which parties may and may not be liable
for exporter obligations in order to ensure exporter obligations are
fulfilled.
    Second, the previous definition could have been construed to
include parties who transfer renewable fuel from the contiguous 48
states and Hawaii, to an area (either Alaska or a U.S. territory) that
has received an approval to opt-in to the RFS program. We did not
intend to impose a RIN retirement obligation on these parties. We are
therefore clarifying how exporter obligations apply to renewable fuel
transferred between the 48 states and Hawaii, and opt-in areas.
    To achieve these goals when we developed the proposal, we initially
considered whether to amend the RFS program regulations consistent with
the Foreign Trade Regulations (FTR) and other federal export-related
regulations, such as United States Principal Party in Interest (USPPI)
and Foreign Principal Party in Interest (FPPI).\219\ While there were
some commenters that suggested adopting those terms, we chose not to do
so for the following reasons. The FTR and other export-related
obligations in other federal programs use a traditional definition of
``export'' where exported goods leave the U.S. The RFS program
addresses obligations incurred through the transfer of renewable fuel
from areas covered by the program to both domestic and foreign areas
not covered by the program. For instance, the transport of goods from
Oregon to Alaska would not qualify as export under most federal export
regulations, but the transport of biofuel from Oregon, a covered area,
to Alaska, a non-covered area (unless Alaska chooses to opt in), would
qualify as export under the RFS program. In addition, if we merely
adopted the FTR approach to allow allocation of exporter obligations
among parties to an export transaction, we have concerns that a party
that is insolvent or lacking assets in the U.S. could undertake those
obligations, and enforcement efforts could become overly resource
intensive where the fuel has left the country. For these reasons, we do
not believe it would be appropriate to amend the RFS program
regulations to define an exporter as the USPPI or the FPPI.
---------------------------------------------------------------------------

    \219\ See, e.g., 15 CFR 772.1 (defining exporter as ``[t]he
person in the United States who has the authority of a principal
party in interest to determine and control the sending of items out
of the United States''). We also considered and rejected other
alternatives, which we discuss further in the RTC document in the
docket for this action.
---------------------------------------------------------------------------

    In reviewing the FTR, we also considered the concept of routed
export transactions and the associated flexibility for parties to an
export transaction to structure that transaction to place some
responsibilities with an FPPI.\220\ We believe that this framework is
reflective of market custom, practice, and capability to contractually
allocate liabilities and indemnities among parties to a commercial
transaction. We prefer regulations that accommodate these
flexibilities, while also balancing the need to protect RFS program
integrity. Specifically, we want to allow parties to an export
transaction to allocate RFS program exporter obligations as they see
fit among themselves, but we also want to protect against contract
structuring that may erode compliance assurance.
---------------------------------------------------------------------------

    \220\ Routed export transaction is the term used to describe an
export transaction in which an FPPI directs the movement of goods
out of the U.S. and authorizes a U.S. agent to file certain
information required by the FTR.
---------------------------------------------------------------------------

    Therefore, we are revising the definition of ``exporter of
renewable fuel'' to mean ``all buyers, sellers, and owners of the
renewable fuel in any transaction that results in renewable fuel being
transferred from a covered location to a destination outside of the
covered locations.'' In conjunction with this revision, we are creating
a definition of ``covered location'' as ``the contiguous 48 states,
Hawaii, and any state or territory that has received an approval from
the Administrator to opt-in to the RFS program under Sec.  80.1443.''
As described above, this revised definition permits contract
flexibilities frequently employed in export transactions with respect
to export obligations under other regulatory programs, such as the FTR.
All buyers, sellers, and owners of the renewable fuel in a transaction
that results in renewable fuel being transferred from a covered
location to a destination outside of any covered location may
contractually allocate RFS program obligations, indemnities, and
pricing as they see fit in light of the regulatory requirements. At the
same time, the revised definition provides enhanced compliance
assurance so as to maintain a level playing field among would-be
exporters and ensures RIN retirement so as to maintain the integrity of
that market in accordance with the regulatory requirements. Ultimately,
the revised definition contributes to satisfying Congress's mandate
that EPA promulgate regulations that ``ensure'' the nationally-
applicable renewable fuel volumes are met.\221\ We note, moreover, that
the existing RFS regulations provide that ``[n]o person shall cause
another person to commit an act in violation of any prohibited act
under this section.'' \222\ We believe that this prohibition coupled
with the revised definitions will deter parties from engaging in sham
transactions to evade RIN retirement obligations by transferring
ownership of renewable fuels to undercapitalized entities that do not
meet their RIN retirement obligations. This includes the specific
earlier-described practices we have already observed. The revised
definition also clarifies how exporter obligations apply to transfers
to and from the contiguous 48 states and Hawaii, and opt-in areas
(i.e., Alaska and U.S. territories were they to opt-in). Notably, it
avoids imposing exporter obligations on biofuels transferred from the
48 states and Hawaii to an opt-in area.
---------------------------------------------------------------------------

    \221\ CAA section 211(o)(2)(A)(i); see also CAA section 301(a).
    \222\ See 40 CFR 80.1460(c).
---------------------------------------------------------------------------

    Under the revised definition, multiple parties may meet the
definition of an exporter of renewable fuel for the same volume of
renewable fuel. In addition, although the definition uses the term
``transaction,'' in many cases there may be more than one discrete
exchange or interaction that results in a volume of renewable fuel
being exported. We intend the regulatory term ``transaction'' to cover
all those exchanges and interactions in which the buyers, sellers, and
owners know or have reason to know will result in renewable fuel being
transferred from a covered location to a destination outside of any
covered location.\223\ For instance, a person holding title to
renewable fuel in the U.S. may sell renewable fuel to another person
(either inside or outside of the

covered areas) and cause the renewable fuel to leave the covered areas.
Further, that buyer and seller may have a third party hold title to the
renewable fuel during transit out of the covered areas. In this case,
the buyer and the seller, both of whom are also owners of the renewable
fuel, and the third-party holding company, as another owner of the
renewable fuel in the transaction, would be jointly-and-severally
liable for complying with the exporter provisions.\224\
---------------------------------------------------------------------------

    \223\ To clarify this point, we have revised the regulatory text
from the proposed ``a transaction'' to ``any transaction'' in this
final rulemaking.
    \224\ This example is meant to be a stylized illustration of how
our regulations could apply. It is not meant to exhaustively detail
the entities that could meet the definition of exporter of renewable
fuel in this type of transaction. To the extent that other parties
meet the definition of exporter of renewable fuel, they would also
be subject to the exporter provisions.
---------------------------------------------------------------------------

    However, our revised regulations create broad flexibility for
parties to assign responsibilities as they see fit among themselves in
structuring an export transaction. These parties may contractually
allocate RIN retirement, and associated registration, reporting, and
attest engagement obligations, to any one of the parties that meets the
definition of an exporter of renewable fuel. The party undertaking
these requirements would then register as an exporter of renewable fuel
as set forth in 40 CFR 80.1450(a). This approach is also consistent
with our approach to the term ``refiner,'' under which multiple parties
could be considered the refiner of a batch of fuel. In such instances,
we have stated that each party meeting the definition of refiner will
be held jointly-and-severally liable for refiner requirements, and we
are adopting a consistent approach for exporters of renewable
fuel.\225\ However, our revised regulations create broad flexibility
for parties to assign responsibilities as they see fit among themselves
in structuring an export transaction. These parties may contractually
allocate RIN retirement, and associated registration, reporting, and
attest engagement obligations, to any one of the parties that meets the
definition of an exporter of renewable fuel. The party undertaking
these requirements would then register as an exporter of renewable fuel
as set forth in 40 CFR 80.1450(a). This approach is also consistent
with our approach to the term ``refiner,'' under which multiple parties
could be considered the refiner of a batch of fuel. In such instances,
we have stated that each party meeting the definition of refiner will
be held jointly-and-severally liable for refiner requirements, and we
are adopting a consistent approach for exporters of renewable
fuel.\226\
---------------------------------------------------------------------------

    \225\ See ``Consolidated List of Reformulated Gasoline and Anti-
Dumping Questions and Answers: July 1, 1994 through November 10,
1997,'' EPA420-R-03-009, at 256 (July 2003) (discussing a scenario
in which two parties would be considered refiners and would be
independently responsible for all refinery requirements, which would
only need to be met once).
    \226\ See ``Consolidated List of Reformulated Gasoline and Anti-
Dumping Questions and Answers: July 1, 1994 through November 10,
1997,'' EPA420-R-03-009, at 256 (July 2003) (discussing a scenario
in which two parties would be considered refiners and would be
independently responsible for all refinery requirements, which would
only need to be met once).
---------------------------------------------------------------------------

    EPA does not consider a person to be an exporter of renewable fuel
if that person does not know and does not have reason to know that the
renewable fuel will be exported. For instance, a renewable fuel
producer who produces a batch of fuel, generates RINs, and sells the
renewable fuel with attached RINs into the fungible fuel distribution
system would not be considered an exporter of renewable fuel under the
revised definition unless they know or have reason to know that the
batch of fuel would be exported. More specifically, the mere fact that
a producer introduces renewable fuels into the stream of commerce,
coupled with the fact that a significant portion of domestically
produced biofuel is exported, does not make the producer an exporter of
renewable fuel.
    We are also finalizing minor, non-substantive changes throughout
the RFS regulations to more consistently use the term ``exporter of
renewable fuel'' rather than the term ``exporter.'' These clarifying
edits reflect that the ``exporter of renewable fuel'' may be different
than the ``exporter'' under other state and federal regulatory
programs.

F. REGS Rule Provisions

    We are finalizing a number of changes to the RFS and fuels programs
that were previously proposed in the REGS rule,\227\ and that we listed
in the preamble to July 29 proposal as candidates for finalization in
this action.\228\ In reaching our final decisions on these provisions
we considered relevant comments on both the 2016 REGS proposal and the
July 29 proposal. As noted in the July 29 proposal, we believe these
provisions to be relatively straightforward and would reduce the burden
of RFS program implementation. Commenters were generally supportive of
these provisions and we are largely finalizing them as proposed;
changes to the final provisions relative to the 2016 REGS proposal are
discussed in detail in the following sections.
---------------------------------------------------------------------------

    \227\ See 81 FR 80828 (November 16, 2016).
    \228\ We are not taking final action at this time on several
changes from the REGS proposal that were listed in the July 29
proposal (Allowing Production of Biomass-Based Diesel From Separated
Food Waste (REGS Section VIII.C), RFS Facility Ownership Changes
(REGS Section VIII.H), Public Access to Information (REGS Section
VIII.O), and Redesignation of Renewable Fuel on a PTD for Non-
Qualifying Uses (REGS Section VIII.R), and certain portions of Other
Revisions to the Fuels Program (REGS Section IX), primarily related
to test methods). These provisions, along with the other provisions
in the REGS proposal that are not being finalized here, remain under
consideration and may be finalized in a future action.
---------------------------------------------------------------------------

1. Flexibilities for Renewable Fuel Blending for Military Use
    We are amending 40 CFR 80.1440 to provide new flexibilities for
parties that blend renewable fuel to produce fuels for use as
transportation fuel, heating oil, or jet fuel under a national security
exemption or that sell neat renewable fuel for use in vehicles,
engines, and equipment that have a national security exemption for
emissions certification. Specifically, these parties will be able to
delegate to an upstream party the RIN-related responsibilities (i.e.,
RIN separation, reporting, recordkeeping, and attest engagement
requirements) associated with the renewable fuel. These parties could
include the U.S. Military itself, or contractors working for the U.S.
Military. The RFS program has a provision that allows blenders that
handle and blend small volumes of renewable fuel per year (less than
250,000 gallons per year) to delegate RIN-related responsibilities to
an upstream party. We have received a number of inquiries from parties
that have wished to provide renewable fuel, either neat or blended into
transportation fuel, for use by the U.S. Military as part of Department
of Defense (DOD) renewable military initiatives. One obstacle to this
use of renewable fuel by the DOD is that, unlike other EPA fuels
programs, there were no exemptions related to national security uses in
the RFS regulatory program.
    We believe that it is appropriate to allow DOD or its contractors
to delegate RFS RIN responsibilities to upstream parties; doing so
removes a potential obstacle to the use of renewable fuels by DOD and
will promote use of renewable fuel by the military. Therefore, we are
finalizing similar upstream delegation provisions for neat and blended
renewable fuels supplied to DOD under a national security exemption as
those already in place for small renewable fuel blenders.
2. Heating Oil Used for Cooling
    We are expanding the definition of heating oil in 40 CFR 80.1401 to
include fuels that differ from those meeting the current definition
only because they are used to cool, rather than heat, interior spaces
of homes or buildings. The first

sentence of the definition of heating oil thus now reads: ``A fuel oil
that is used to heat or cool interior spaces of homes or buildings to
control ambient climate for human comfort.'' We are also making minor
modifications to the registration, reporting, PTD, and recordkeeping
requirements for renewable heating oil to correspond with this change.
We had received questions related to the use of renewable heating oil
in equipment that cools interior spaces and believe that displacing the
use of petroleum based fuel oil with renewable heating oil for cooling
is consistent with CAA section 211(o)'s provision for home heating oil
to be treated as additional renewable fuel and should be allowed.
3. Separated Food Waste Plans
    We are amending the RFS registration procedures for separated food
waste plans at 40 CFR 80.1450(b)(1)(vii)(B) and the recordkeeping
requirements for separated food waste at 40 CFR 80.1454(j). We are also
adding requirements for renewable fuel produced from biogenic waste
oils/fats/greases at 40 CFR 80.1450(b)(1)(vii)(B) and 80.1454(d)(4) and
(j).
    The RFS regulations promulgated in the RFS2 rulemaking required
that separated food waste plans include: ``(1) The location of any
municipal waste facility or other facility from which the waste stream
consisting solely of separated food waste is collected; and (2) A plan
documenting how the waste will be collected, how the cellulosic and
non-cellulosic portions of the waste will be quantified, and for
ongoing verification that such waste consists only of food waste (and
incidental other components such as paper and plastics) that is kept
separate since generation from other waste materials.'' \229\ In
addition to the initial submission of separated food waste plans during
RFS registration, we also required that renewable fuel producers using
separated food waste feedstock update the registration information
whenever there was a change to the plan, including to the location(s)
of establishments from which the separated food waste is collected, and
in some cases the newly updated plan must have been reviewed by a
third-party engineer in accordance with EPA registration procedures. We
have received numerous company updates for production facilities with
separated food waste plans, and some parties noted that the requirement
to identify and update suppliers of feedstocks through a plan was
overly burdensome.
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    \229\ See 40 CFR 80.1450(b)(1)(vii)(B).
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    Recognizing that business relationships for recovery of food wastes
evolve and that a renewable fuel producer may elect over time to
purchase feedstocks from different or multiple parties, we are removing
the requirement to provide the location of every facility from which
separated food waste feedstock is collected as part of the information
required for registration. Removing this registration requirement
alleviates the need for numerous company registration updates as a
facility's feedstock supplier list evolves, as well as makes it easier
for EPA to review renewable fuel producers' separated food waste plans
in a timely manner. However, the recordkeeping section of the
regulations requires renewable fuel producers to keep documents
associated with feedstock purchases and transfers that identify where
the feedstocks were produced; these documents must be sufficient to
verify that the feedstocks meet the definition of renewable
biomass.\230\ Thus, renewable fuel producers will still be required to
maintain records that demonstrate that they used a qualifying feedstock
to produce renewable fuels for the generation of RINs pursuant to the
recordkeeping requirements at 40 CFR 80.1454(d)(4) and (j). We are also
adding a provision at 40 CFR 80.1454(j)(1)(ii) that will require
renewable fuel producers to maintain records demonstrating the location
of any establishment from which the waste stream is collected. Since
many renewable fuel producers receive wastes used as feedstocks from an
aggregator, we interpret the term ``location'' to mean the physical
address that the aggregator obtained the wastes used as feedstocks
from, not the physical or company address of the aggregator.
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    \230\ See 40 CFR 80.1454(d)(4) and (j).
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    In addition to removing the registration requirement to provide the
locations of establishments from which separated food waste is
collected, we are also modifying the registration regulations to
require that separated food waste plans identify the type(s) of
separated food waste(s) to be used and the type(s) of establishment(s)
the waste will be collected from. For instance, CAA section 211(o)
identifies ``recycled cooking and trap grease'' as a type of separated
food waste. Examples of types of establishments could be restaurants,
slaughterhouses, or specific food production plants (the kind of food
production should be provided). We believe this information is
necessary for EPA to determine at registration whether a renewable fuel
producer can make fuel from its proposed feedstock under currently
approved separated food waste pathways. Without this information, we
would not know what the specific feedstock is (e.g., tallow, yellow
grease, etc.) or whether it qualifies as a separated food waste.
    We are also requiring under 40 CFR 80.1450(b)(1)(vii)(B) that
producers of renewable fuels made from biogenic waste oils/fats/greases
that are not separated food waste submit a plan at registration with
the same requirements as the plan for producers of renewable fuels made
from separated food waste. We are henceforth referring to such plans as
``waste oils/fats/greases feedstock plans.'' There is significant
overlap between the two categories of feedstock, with a considerable
quantity of biogenic waste oils/fats/greases qualifying as renewable
biomass as a result of its additional qualification as separated food
waste. For these reasons, as a matter of practice we have required
parties intending to use biogenic waste oils/fats/greases as a
renewable fuel feedstock to submit separated food waste plans at
registration. In addition to helping EPA determine if the feedstock in
question meets renewable biomass requirements, we have found that the
plans help us assess whether the feedstocks specified by a prospective
producer qualify as biogenic waste oils/fats/greases. This assessment
is made on a case-by-case basis. This amendment conforms the
regulations to EPA's current practice. A party fully describing its
feedstock in a separated food waste plan will not be required to submit
an additional waste oils/fats/greases plan. Since most, if not all,
producers of renewable fuel from biogenic waste oils/fats/greases have
submitted a separated food waste plan at registration, we do not
believe that this revision will add much, if any, burden to existing
registered facilities. Those few registered producers using biogenic
waste oils/fats/greases that have not previously submitted a separated
food waste plan at registration or in a subsequent registration update
will be required to do so as part of their next periodic registration
update.
    In addition to adding the registration requirement for a waste
oils/fats/greases feedstock plan to 40 CFR 80.1540(b)(1)(vii)(B), we
are also adding the same recordkeeping requirements for biogenic oils/
fats/greases as for separated food waste at 40 CFR 80.1454(d)(4) and
(j), and providing further clarity that the locations from which
separated food waste or biogenic oils/fats/greases was sourced is a
recordkeeping requirement.

4. Additional Registration Deactivation Justifications
    We are adding additional circumstances in which EPA may deactivate
the registration of any party required to register under 40 CFR
80.1450. These amendments will help parties better understand when EPA
intends to restrict a party's participation in the RFS program as well
as the procedures that will be used in such circumstances.
    In July 2014, we finalized requirements that described
circumstances under which EPA may deactivate a company registration and
an administrative process to initiate deactivation that provides
companies an opportunity to respond to and/or submit the required
information in a timely manner.\231\ Since finalizing these
requirements, we have identified a number of other cases in which it is
appropriate to deactivate the registration of a company. In addition,
we believe the provisions should be extended to cover deactivation of
registrations for any party required to register with EPA under 40 CFR
80.1450 (e.g., third-party auditors).\232\ Specifically, we are
amending 40 CFR 80.1450(h)(1) to provide that EPA may deactivate
registrations of a party for the following reasons in addition to those
previously listed:
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    \231\ Under this administrative process, the party has 14
calendar days from the date of the notification to correct the
deficiencies identified or explain why there is no need for
corrective action. See 40 CFR 80.1450(h)(2)(i).
    \232\ In the REGS proposal, we proposed to use the term
``company, third-party auditor, or third-party engineer'' in the
registration deactivation provisions; however, we are now using the
term ``party'' to refer more generally to any person that may be
required to register with EPA.
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     The party fails to comply with the registration
requirements of 40 CFR 80.1450.
     The party fails to submit any required report within
thirty days of the required submission date.
     The party fails to pay a penalty or to perform any
requirements under the terms of a court order, administrative order,
consent decree, or administrative settlement agreement between the
party and EPA.
     The party submits false or incomplete information.
     The party denies EPA access or prevents EPA from
completing authorized activities under CAA section 114 despite our
presenting a warrant or court order. This includes a failure to provide
reasonable assistance.
     The party fails to keep or provide EPA with the records
required in 40 CFR part 80, subpart M.
     The party otherwise circumvents the intent of the CAA or
40 CFR part 80, subpart M.
    These deactivation circumstances are consistent with cases where
EPA may deny or revoke a certificate of conformity under 40 CFR
1051.255(c) and 86.442-78 for engines and vehicles manufactured in or
imported into the U.S. In addition, we are finalizing requirements that
state that in instances of willful violation of an applicable
requirement or those in which public health, interest, or safety
requires otherwise, EPA may also deactivate the registration of a party
without providing notice to the party prior to deactivation and will
send written notification to the RCO describing the reasons for the
deactivation. Parties can still submit new registrations after
appropriate actions are taken by the party to remedy the deficiency.
5. New RIN Retirement Section
    We are creating a new section in the RFS regulations for RIN
retirements. The regulations have specific sections that address when
and how parties may generate and separate RINs. However, the cases
where parties must retire RINs were identified in various sections
throughout the regulations. The new section of the RFS regulations for
RIN retirements, 40 CFR 80.1434, simply organizes these current
sections into one place and will provide beneficial clarification by
enumerating the specific instances in which a party must retire RINs in
a new section of the regulations and by making those retirements
consistent with how parties administratively retire RINs in EMTS. We
are aware of some confusion for some parties causing those parties to
improperly retire RINs or fail to retire RINs when they have a
responsibility to do so under the regulations. Improper retirements can
lead to a time-consuming remediation process, both for EPA and
responsible parties. This new section organizes these requirements into
one location in the regulations to make the circumstances under which
RINs must be retired simpler to locate and understand. The section also
includes new regulatory language for cases requiring RIN retirement
that are identified in EMTS, but may not be clear in the regulations,
given their current organization (e.g., in the case of contaminated or
spoiled fuel). Our intent is not to add additional burden on parties
that must retire RINs under the RFS program, but rather to make the
regulations consistent with how parties already retire RINs in EMTS and
help reduce potential confusion regarding the situations in which
parties must retire RINs.
    We are finalizing the elements of the new RIN retirement section at
40 CFR 80.1434 as proposed, with the exception of the provisions for
expired RINs and redesignated renewable fuel, which we are not
finalizing because we have determined they are not necessary for
program implementation at this time.
6. New Pathway for Co-Processing Biomass With Petroleum To Produce Co-
Processed Cellulosic Diesel, Jet Fuel, and Heating Oil
    We are creating a new definition of ``co-processed cellulosic
diesel'' to refer to biodiesel or non-ester renewable diesel fuels that
meet the definition for cellulosic biofuel but not the definition of
biomass-based diesel. We are also finalizing new pathways that allow
co-processed cellulosic diesel, jet fuel, and heating oil that are
derived from co-processing biomass with petroleum to qualify as
cellulosic biofuel and generate cellulosic (D-code 3) RINs, provided
certain production process requirements are satisfied. Fuels that meet
the cellulosic diesel definition will continue to be able to generate
D7 RINs, while fuels that meet the co-processed cellulosic diesel
definition but not the cellulosic diesel definition due to co-
processing with petroleum will be able to generate D3 RINs. Fuels
produced through co-processing with petroleum will also be required to
meet, among other requirements, the requirements of 40 CFR
80.1426(f)(4) to determine the number of RINs that can be generated.
    While pathways existed for renewable gasoline and gasoline
blendstock (row M in Table 1 to 40 CFR 80.1426) and naphtha (row N in
Table 1 to 40 CFR 80.1426) produced from cellulosic biomass that is co-
processed with petroleum, there was no pathway for diesel, jet fuel, or
heating oil produced in this manner. The pathway for cellulosic diesel,
jet fuel, and heating oil (Pathway L in Table 1 to 40 CFR 80.1426)
excludes processes that co-process renewable biomass and petroleum. To
qualify as cellulosic diesel, a fuel must meet the requirements for
both cellulosic biofuel and biomass-based diesel. The definition of
biomass-based diesel explicitly excludes renewable fuels that are
derived from co-processing biomass with petroleum, and therefore a
process that produced diesel, jet fuel, or heating oil by co-processing
renewable biomass with petroleum could not qualify as biomass-based
diesel or cellulosic diesel under Pathway L in Table 1 to 40 CFR
80.1426. However, cellulosic biofuels other than cellulosic diesel are
not

prohibited from being derived from biomass co-processed with petroleum.
    In the 2016 REGS proposed rule, we proposed to add a new row U to
Table 1 to 40 CFR 80.1426 that would have allowed for cellulosic
diesel, jet fuel and heating oil produced from any of the feedstocks
listed in row L via any process that co-processes renewable biomass
with petroleum and converts cellulosic biomass to fuel to qualify for
cellulosic biofuel (D-code 3) RINs.\233\ While most commenters
supported this proposed addition, several commenters disagreed. The
dissenting commenters stated that EPA had not conducted a sufficient
lifecycle GHG analysis to support the pathways proposed for row U.
After reviewing these comments, we have decided to finalize a narrower
set of pathways for co-processed cellulosic diesel. Instead of adding a
new row U to Table 1 to 40 CFR 80.1426, we are instead adding ``Co-
Processed Cellulosic Diesel, Jet Fuel, and Heating Oil'' as fuel types
in row M. Thus, as we had proposed, we are finalizing new pathways for
co-processed cellulosic diesel, jet fuel, and heating oil, but for a
narrower set of feedstocks and production process requirements.
Compared to the proposed row U, row M contains the same feedstocks
except that it does not include any energy grasses (i.e., switchgrass,
miscanthus, energy cane, Arundo donax, Pennisetum purpureum), and row M
contains a more narrowly defined set of production process
requirements. Note that the energy grass feedstocks are the only ones
in the proposed row U that include significant indirect land use change
emissions based on EPA's lifecycle GHG analysis of switchgrass for the
March 2010 RFS2 rule. Finalizing this narrower set of pathways
addresses the commenters concerns about insufficient analysis because
approval of these pathways is supported by the extensive analyses that
we conducted for a previous rule.
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    \233\ Another part of the 2016 REGS proposal, which we are not
finalizing here, would have amended the definition of ``cellulosic
diesel'' so that it no longer required that such fuel meet the
definition of biomass-based diesel.
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    The pathways in row M were approved in the March 2013 Pathways I
rule and may include fuels produced through the co-processing renewable
biomass and petroleum.\234\ The analysis supporting that rulemaking
found that the pathways evaluated for corn stover feedstock reduced
lifecycle GHG emissions by at least 65 to 129 percent compared to the
statutory petroleum baseline, and the results for corn stover were
extended to the other feedstocks listed in row M. We are now extending
those results to cover co-processed cellulosic diesel, jet fuel, and
heating oil produced from the same feedstocks and processes listed in
row M. The analysis for the March 2013 Pathways I rule did not
explicitly evaluate co-processing but the upgrading processes were
modeled as using the same types of equipment and processes as petroleum
refining.\235\ Indeed, the analysis was largely based on a report that
evaluated processes that co-produce gasoline and diesel products.\236\
The most likely processes in row M to include co-processing are the
ones that have upgrading as the final step, as upgrading is a common
part of petroleum refining. Our analysis for the March 2013 Pathways I
rule estimated a 67 percent GHG reduction compared to conventional
gasoline for renewable gasoline and renewable gasoline blendstock
produced from corn stover through catalytic pyrolysis and upgrading.
Producing cellulosic diesel instead of renewable gasoline through this
same pathway would produce similar results satisfying the 60 percent
GHG reduction threshold. When energy allocation is used for GHG
accounting, which is the approach we have used for co-produced RIN
generating fuels,\237\ co-produced gasoline and diesel products will
have the same, or nearly the same GHG emissions per unit of energy.
Studies looking at petroleum refining have also found that upgrading to
diesel fuel is less GHG-intensive than upgrading to gasoline.\238\
Based on these assessments we conclude that the lifecycle GHG emissions
associated with the new pathways being added to row M satisfy the
statutory 60 percent GHG reduction requirement to qualify as cellulosic
biofuel. In summary, the analyses conducted for the March 2013 Pathways
I rule support the addition of ``co-processed cellulosic diesel, jet
fuel and heating oil'' as feedstocks to row M of Table 1 to 40 CFR
80.1426, and commenters did not provide sufficient data or information
to support a different conclusion.
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    \234\ See 78 FR 14190 (March 5, 2013).
    \235\ Kinchin, Christopher. Catalytic Fast Pyrolysis with
Upgrading to Gasoline and Diesel Blendstocks. National Renewable
Energy Laboratory (NREL). 2011. EPA-HQ-OAR-2011-0542-0007
    \236\ Id.
    \237\ See for example discussion of hydrotreated camelina oil in
that March 2013 Pathways I rule at 78 FR 14198.
    \238\ For example, for the 2010 RFS2 rule EPA estimated slightly
lower refining emissions (9.2 gCO2e/MJ) for 2005 average U.S.
gasoline than for 2005 U.S. average diesel (9.0 gCO2e/MJ). Other
studies have found an even larger reduction for refining diesel as
compared to gasoline. See for example: Cooney, G., et al. (2017).
``Updating the U.S. Life Cycle GHG Petroleum Baseline to 2014 with
Projections to 2040 Using Open-Source Engineering-Based Models.''
Environmental Science & Technology 51(2): 977-987. While this may be
different when biogenic feedstocks are used, it is reasonable to
conclude that any differences would not be large enough to
disqualify the fuel from satisfying the 60 percent GHG reduction
threshold.
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    The 2016 REGS proposal also included a revised definition for
``cellulosic diesel'' and a new term, ``cellulosic biomass-based
diesel.'' \239\ These proposed revisions would have, among other
things, removed the requirement for ``cellulosic diesel'' to meet the
definitions of both cellulosic biofuel and biomass-based diesel. The
new term, ``cellulosic biomass-based diesel,'' would have effectively
replaced ``cellulosic diesel'' and would have required that the
renewable fuel meet both definitions. However, after considering the
implementation issues associated with revising an existing definition
within EPA's IT systems (e.g., changing existing registrations), we
have decided not to finalize either of the definitional changes