Regulation of Fuels and Fuel Additives: Changes to Renewable Fuel Standard Program

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[Federal Register: May 26, 2009 (Volume 74, Number 99)]
[Proposed Rules]
[Page 24953-25002]
From the Federal Register Online via GPO Access [wais.access.gpo.gov]
[DOCID:fr26my09-22]

Regulation of Fuels and Fuel Additives: Changes to Renewable Fuel
Standard Program

[[Continued from page 24952]]

[[Page 24953]]

and additional renewable fuel categories added by Congress in CAA
211(o)(2). In general the form of the standard will not change under
RFS2. The renewable fuel standards will continue to be expressed as a
volume percentage, and will be used by each refiner, blender or
importer to determine their renewable volume obligations. The
applicable percentages are set so that if each regulated party meets
the percentages, then the amount of renewable fuel, cellulosic biofuel,
biomass-based diesel, and advanced biofuel used will meet the volumes
specified in Table II.A.1-1.\29\
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    \29\ Actual volumes can vary from the amounts required in the
statute. For instance, lower volumes may result if the statutorily
required volumes are adjusted downward according to the waiver
provisions in CAA 211(o)(7)(D). Also, higher or lower volumes may
result depending on the actual consumption of gasoline and diesel in
comparison to the projected volumes used to set the standards.
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    The new renewable fuel standards would be based on both gasoline
and diesel volumes as opposed to only gasoline. Under CAA section
211(o)(3), EPA must determine the refiners, blenders and importers who
are subject to the standard. We propose that the standard would apply
to refiners, blenders and importers of diesel in addition to gasoline,
for both highway and nonroad uses. As described more fully in Section
III.F.3, we are proposing at this time that other producers of
transportation fuel, such as producers of natural gas, propane, and
electricity from fossil fuels, would not be subject to the standard.
Since the standard would apply to refiners, blenders and importers of
gasoline and diesel, these are also the transportation fuels that would
be used to determine the annual volume obligation of the refiner,
blender or importer.
    The projected volumes of gasoline and diesel used to calculate the
standards would continue to be provided by EIA's Short-Term Energy
Outlook (STEO). The standards applicable to a given calendar year would
be published by November 30 of the previous year. The renewable fuel
standards would also continue to take into account various adjustments.
For instance, gasoline and diesel volumes would be adjusted to account
for the required renewable fuel volumes, and gasoline and diesel
volumes produced by small refineries and small refiners would continue
to be exempt through 2010.
    While the calculation methodology for determination of standards
would not change, there would be four separate standards under the new
RFS2 program, corresponding to the four separate volume requirements
shown in Table II.A.1-1. The specific formulas we propose using to
calculate the renewable fuel standards are described below in Section
III.E.1.
    In order for an obligated party to demonstrate compliance, the
percentage standards would be converted into the volume of renewable
fuel each obligated party is required to satisfy. This volume of
renewable fuel is the volume for which the obligated party is
responsible under the RFS program, and would continue to be referred to
as its Renewable Volume Obligation (RVO). Since there would be four
separate standards under the RFS2 program, there would likewise be four
separate RVOs applicable to each refiner, importer, or other obligated
party. However, all RVOs would be determined in the same way as
described in the current regulations at Sec.  80.1107, with the
exception that each standard would apply to the sum of all gasoline and
diesel produced or imported as opposed to just the gasoline volume. The
formulas we propose using to calculate the RVOs under the RFS2 program
are described in Section III.G.1.
1. Calculation of Standards
a. How Would the Standards Be Calculated?
    Table II.A.1-1 shows the required overall volumes of four types of
renewable fuel specified in EISA. The four separate renewable fuel
standards would be based primarily on (1) the 49-state \30\ gasoline
and diesel consumption volumes projected by EIA, and (2) the total
volume of renewable fuels required by EISA for the coming year. Each
renewable fuel standard will be expressed as a volume percentage of
combined gasoline and diesel sold or introduced into commerce in the
U.S., and will be used by each obligated party to determine its
renewable volume obligation.
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    \30\ Hawaii opted-in to the original RFS program; that opt-in is
carried forward to the proposed new program.
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    While we are proposing that the standards be based on the sum of
all gasoline and diesel, an alternative would split the standards
between those that would be specific to gasoline and those that would
be specific to diesel. To accomplish this, it would be necessary to
project the fraction of the volumes shown in Table II.A.1-1 for
cellulosic biofuel, advanced biofuel, and total renewable fuel that
would represent gasoline-displacing renewable fuel, and apply this
portion of the required volumes to gasoline (by definition the biomass-
based diesel standard would have no component relevant to gasoline).
The remaining portion would apply to diesel. The result would be seven
standards instead of four. This approach to setting standards would
more readily align the RFS obligations with the relative amounts of
gasoline and diesel produced or imported by each obligated party. For
instance, a refiner that produced only diesel fuel would have no
obligations under the RFS program for renewable fuels that are used to
displace gasoline. However, this alternative approach relies on
projections of the relative amounts of gasoline-displacing and diesel-
displacing renewable fuels that would need to be updated every year.
While such projections would be available through our proposed
Production Outlook Reports (see Section III.K), we nevertheless believe
that such an approach would unnecessarily complicate the program, and
thus we are not proposing it. However, we request comment on it.
    In determining the applicable percentages for a calendar year, EISA
requires EPA to adjust the standard to prevent the imposition of
redundant obligations on any person and to account for renewable fuel
use during the previous calendar year by exempt small refineries,
defined as refineries that process less than 75,000 bpd of crude oil.
As a result, in order to be assured that the percentage standards will
in fact result in the volumes shown in Table II.A.1-1, we must make
several adjustments to what otherwise would be a simple calculation.
    As stated, the renewable fuel standards for a given year are
basically the ratio of the amount of each type of renewable fuel
specified in EISA for that year to the projected 49-state non-renewable
combined gasoline and diesel volume for that year. While the required
amount of total renewable fuel for a given year is provided by EISA,
the Act requires EPA to use an EIA estimate of the amount of gasoline
and diesel that will be sold or introduced into commerce for that year
to determine the percentage standards. The levels of the percentage
standards would be reduced if Alaska or a U.S. territory chooses to
participate in the RFS2 program, as gasoline and diesel produced in or
imported into that state or territory would then be subject to the standard.
    As mentioned above, we are proposing that EIA's STEO continue to be
the source for projected gasoline, and now diesel, consumption
estimates. These volumes include renewable fuel use. In order to
achieve the volumes of renewable fuels specified in EISA, the gasoline
and diesel volumes used to

[[Page 24954]]

determine the standard must be the non-renewable portion of the
gasoline and diesel pools. In order to get total non-renewable gasoline
and diesel volumes, we must subtract the total renewable fuel volume
from the total gasoline and diesel volume. As with RFS1, the best
estimation of the coming year's renewable fuel consumption is found in
Table 11 (U.S. Renewable Energy Use by Sector: Base Case) of the STEO.
    CAA section 211(o) exempts small refineries \31\ from the RFS
requirements until the 2011 compliance period. In RFS1, we extended
this exemption to the few remaining small refiners not already
exempted.\32\ Since EPA proposes that small refineries and small
refiners continue to be exempt from the program until 2011 under the
new RFS2 regulations, EPA will exclude their gasoline and diesel
volumes from the overall non-renewable gasoline and diesel volumes used
to determine the applicable percentages until 2011. EPA believes this
is appropriate because the percentage standards need to be based on the
gasoline and diesel subject to the renewable volume obligations, to
achieve the overall required volumes of renewable fuel. Because the
total small refinery and small refiner gasoline production volume is
expected to be fairly constant compared to total U.S. transportation
fuel production, we are proposing to estimate small refinery and small
refiner gasoline and diesel volumes using a constant percentage of
national consumption, as we did in RFS1. Using information from
gasoline batch reports submitted to EPA for 2006, EIA data, and input
from the California Air Resources Board regarding California small
refiners, we estimate that small refinery volumes constitute 11.9% of
the gasoline pool, and 15.2% of the diesel pool.
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    \31\ Under section 211(o) of the Clean Air Act, small refineries
are those with 75,000 bbl/day or less average aggregate daily crude
oil throughput.
    \32\ See Section IV.B.2.
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    CAA section 211(o) requires that the small refinery adjustment also
account for renewable fuels used during the prior year by small
refineries that are exempt and do not participate in the RFS2 program.
Accounting for this volume of renewable fuel would reduce the total
volume of renewable fuel use required of others, and thus directionally
would reduce the percentage standard. However, as we discussed in RFS1,
the amount of renewable fuel that would qualify, i.e., that was used by
exempt small refineries and small refiners but not used as part of the
RFS program, is expected to be very small. In fact, these volumes would
not significantly change the resulting percentage standards. Whatever
renewable fuels small refineries and small refiners blend will be
reflected as RINs available in the market; thus there is no need for a
separate accounting of their renewable fuel use in the equations used
to determine the standards. We thus are proposing, as for RFS1, that
this value be zero.
    Just as with their corresponding gasoline and diesel volumes,
renewable fuels used in Alaska or U.S. territories are not included in
the renewable fuel volumes that are subtracted from the total gasoline
and diesel volume estimates. Section 211(o) of the Clean Air Act
requires that the renewable fuel be consumed in the contiguous 48
states, and any other state or territory that opts in to the program
(Hawaii has subsequently opted in). However, because renewable fuel
produced in Alaska or a U.S. territory is unlikely to be transported to
the contiguous 48 states or to Hawaii, including their renewable fuel
volumes in the calculation of the standard would not serve the purpose
intended by section 211(o) of the Clean Air Act of ensuring that the
statutorily required renewable fuel volumes are consumed in the 48
contiguous states and any state or territory that opts in.
    In summary, we are proposing that the total projected non-renewable
gasoline and diesel volumes from which the annual standards are
calculated be based on EIA projections of gasoline and diesel
consumption in the contiguous 48 states and Hawaii, adjusted by
constant percentages of 11.9% and 15.2% in 2010 to account for small
refinery/refiner gasoline and diesel volumes, respectively, and with
built-in correction factors to be used when and if Alaska or a
territory opt-in to the program. If actual gasoline and diesel
consumption were to exceed the EIA projections, the result would be
that renewable fuel volumes would exceed the statutory volumes.
Conversely, if actual gasoline and diesel consumption was less than the
EIA projection for a given year, actual renewable fuel volumes could be
lower than the statutory volumes depending on market conditions.
Additional special considerations in establishing the annual cellulosic
biofuel standard are discussed below in Section III.E.1.c.
    The following formulas will be used to calculate the percentage standards:
[GRAPHIC] [TIFF OMITTED] TN26MY09.000
[GRAPHIC] [TIFF OMITTED] TN26MY09.001
[GRAPHIC] [TIFF OMITTED] TN26MY09.002
[GRAPHIC] [TIFF OMITTED] TN26MY09.003

[[Page 24955]]

Where

Std_CB,i = The cellulosic biofuel standard for year i, in percent
Std_BBD,i = The biomass-based diesel standard for year i, in percent
Std_AB,i = The advanced biofuel standard for year i, in percent
Std_RF,i = The renewable fuel standard for year i, in percent
RFV_CB,i = Annual volume of cellulosic biofuel required by
section 211(o)(2)(B) of the Clean Air Act for year i, in gallons
RFV_BBD,i = Annual volume of biomass-based diesel required
by section 211(o)(2)(B) of the Clean Air Act for year i, in gallons
RFV_AB,i = Annual volume of advanced biofuel required by
section 211(o)(2)(B) of the Clean Air Act for year i, in gallons
RFV_RF,i = Annual volume of renewable fuel required by
section 211(o)(2)(B) of the Clean Air Act for year i, in gallons
G_i = Amount of gasoline projected to be used in the 48
contiguous states and Hawaii, in year i, in gallons*
D_i = Amount of diesel projected to be used in the 48
contiguous states and Hawaii, in year i, in gallons
RG_i = 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
RD_i = 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
GS_i = Amount of gasoline projected to be used in Alaska
or a U.S. territory in year i if the state or territory opts in, in gallons*
RGS_i = 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
DS_i = Amount of diesel projected to be used in Alaska or
a U.S. territory in year i if the state or territory opts in, in gallons*
RDS_i = 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
GE_i = 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,
respectively. Equivalent to 0.119 * (G_i - RG_i).
DE_i = The amount of diesel 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,
respectively. Equivalent to 0.152 * (D_i - RD_i).
    * Note that these terms for projected volumes of gasoline and
diesel use include gasoline and diesel that has been blended with renewable fuel.

b. Proposed Standards for 2010
    In today's NPRM we are proposing the specific standards that would
apply to all obligated parties in calendar year 2010. We will consider
comments received on these standards as part of the comment period
associated with today's NPRM, and we intend to issue a Federal Register
notice by November 30, 2009 setting the applicable standards for 2010.
While we are not proposing standards for 2011 and beyond, we present
our current projections of these standards in the next section.
    Under CAA section 211(o)(7)(D)(i), EPA is required to make a
determination each year regarding whether the required volumes of
cellulosic biofuel for the following year can be produced. For any
calendar year for which the projected volume of cellulosic biofuel
production is less than the minimum required volume, the projected
volume becomes the basis for the cellulosic biofuel standard. In such a
case, the statute also indicates that EPA may also lower the required
volumes for advanced biofuel and total renewable fuel.
    Based on information available to date, we believe that there are
sufficient plans underway to build plants capable of producing 0.1
billion gallons of cellulosic biofuel in 2010, the minimum volume of
cellulosic biofuel required by EISA for 2010. Our April 2009 industry
assessment concludes that there could be seven small commercial-scale
plants online in 2010 (as well as a series of pilot and demonstration
plants) capable of producing just over 100 million gallons of
cellulosic biofuel. And since the majority of this production (73%) is
projected to be cellulosic diesel, the ethanol-equivalent complaince
volume could be closer to 145 million gallons. While it is possible
that some of these plants could be delayed or a portion of the
projected production may not meet the definition of ``cellulosic
biofuel'' (due to mixed feedstocks), it is also possible that other
plans could proceed ahead of their current schedules. For more on the
2010 cellulosic biofuel production assessment, refer to Section 1.5.3.4
of the DRIA
    On the basis of this information, we are not proposing that any
portion of the cellulosic biofuel requirement for 2010 be waived.
Therefore, we are proposing that the volumes shown in Table II.A.1-1 be
used as the basis for the applicable standards for 2010. As described
more fully in Section III.E.2 below, we are also proposing that the
2010 standard for biomass-based diesel be based on the combined
required volumes for 2009 and 2010, or a total of 1.15 billion gallons.
The proposed standards for 2010 are shown in Table III.E.1.b-1.

             Table III.E.1.b-1--Proposed Standards for 2010
                                [Percent]
------------------------------------------------------------------------

------------------------------------------------------------------------
Cellulosic biofuel.............................................     0.06
Biomass-based diesel...........................................     0.71
Advanced biofuel...............................................     0.59
Renewable fuel.................................................     8.01
------------------------------------------------------------------------

    As described more fully in Section III.E.1.d below, we are
proposing that the RFS2 program take effect on January 1, 2010, but we
are also taking comment on an effective date later than January 1,
2010, including January 1, 2011 and a mid-2010 effective date. If the
RFS2 program became effective mid-2010, the RFS1 program would apply
during the first part of 2010 and the RFS2 program would apply for the
remainder of the year. We request comment on whether the four proposed
standards shown in Table III.E.1.b-1 would apply only to gasoline and
diesel produced or imported after the RFS2 effective date or should
apply to all gasoline and diesel produced in 2010. We also request
comment on whether a single standard for total renewable fuel should
apply under RFS1 regulations for the first part of 2010.
c. Projected Standards for Other Years
    As discussed above, we intend to set the percentage standards for
each upcoming year based on the most recent EIA projections, and using
the other sources of information as noted above. We would publish the
standard in the Federal Register by November 30 of the preceding year.
The standards would be used to determine the renewable volume
obligations based on an obligated party's total gasoline and diesel
production or import volume in a calendar year, January 1 through
December 31. An obligated party will calculate its Renewable Volume
Obligations (discussed in Section III.G.1) using the annual standards.
    For illustrative purposes, we have estimated the standards for 2011
and later based on current information using the formulas discussed
above, and assuming no modifications to the annual volumes
required.\33\ These values are listed below in Table III.E.1.c-1. The
required renewable fuel volumes specified in EISA are shown in Table
II.A.1-1. The projected gasoline, diesel and renewable fuels volumes
were determined from EIA's energy projections. Variables related to
Alaska or territory opt-ins were set to zero since we do not have any
information related

[[Page 24956]]

to their participation at this time. No adjustment was made for small
refiner or small refinery volumes since their exemption is assumed to
end at the end of the 2010 compliance period.
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    \33\ ``Calculation of the Renewable Fuel Standard for Gasoline
and Diesel,'' memo to the docket from Christine Brunner, ASD, OTAQ,
EPA, April 2009.

                                Table III.E.1.c-1--Projected Standards Under RFS2
                                                    [percent]
----------------------------------------------------------------------------------------------------------------
                                                                             Biomass-
                                                               Cellulosic     based       Advanced    Renewable
                                                                biofuel       diesel      biofuel        fuel
----------------------------------------------------------------------------------------------------------------
2011........................................................         0.15         0.49         0.83         8.60
2012........................................................         0.31         0.61         1.22         9.31
2013........................................................         0.61        0.61a         1.68        10.09
2014........................................................         1.07        0.61a         2.28        11.05
2015........................................................         1.83        0.61a         3.35        12.48
2016........................................................         2.58        0.61a         4.40        13.49
2017........................................................         3.34        0.61a         5.46        14.56
2018........................................................         4.25        0.61a         6.68        15.80
2019........................................................         5.19        0.61a         7.95        17.11
2020........................................................         6.47        0.62a         9.25        18.50
2021........................................................         8.40        0.62a        11.21        20.54
2022........................................................        10.07        0.63a        13.21        22.65
----------------------------------------------------------------------------------------------------------------
\a\ These projected standards represent the minimum volume of 1.0 billion gallons required by EISA. The actual
  volume used to set the standard would be determined by EPA through a future rulemaking.

d. Alternative Effective Date
    Although we are proposing that the RFS2 regulatory program begin on
January 1, 2010 which, depending on timing for the final rule, would
allow approximately two months from the anticipated issuance of the
rule to its implementation, we seek comment on whether an effective
date later than January 1, 2010 would be necessary. If the RFS2 program
was not made effective on January 1, 2010, the most straightforward
alternative start date would be January 1, 2011. Delaying to 2011 would
provide regulated parties additional lead time and would allow all the
new requirements and standards to go into effect at the beginning of an
annual compliance period. However, delaying to 2011 would also mean
that demonstrating compliance with the separate requirements for
biomass-based diesel, cellulosic biofuel, and advanced biofuel mandates
would not go into effect until 2011. The total renewable fuel mandate
in EISA may be able to be implemented with the RFS1 regulations until
such time as the RFS2 regulations become effective. However, under the
RFS1 regulations, this entire standard would be for conventional
biofuels and would be applied to gasoline producers and importers only.
There would be no obligation with respect to diesel fuel producers and
importers, resulting in a numerically larger standard that would apply
to gasoline producers only and which could compel them to market a
larger proportion of ethanol as E85 to acquire sufficient RINs for
compliance. One possible way to address this issue would be to reduce
the 2010 total renewable fuel standard proportionately to reflect the
application of the standard only to gasoline producers. However, it
does not appear that EPA has statutory authority, or discretion under
the RFS1 regulations, to modify the total renewable fuel mandate in
this manner. As discussed below in Section III.E.2, any delay beyond
January 1, 2010 also has implications for our proposed treatment of the
biomass-based diesel volumes required for 2009. EPA invites comment on
whether RFS2 implementation should be delayed to January 1, 2011 and,
if so, the manner in which the EISA-mandated RFS program should be
implemented prior to that date.
    Another alternative would be to delay the effective date of the
RFS2 program to some time after January 1, 2010 but before January 1,
2011. This alternative would raise the same issues described above
(regarding the option of a delay until January 1, 2011) for that
portion of 2010 during which RFS2 was not effective. It would also
raise additional transition and implementation issues. For instance, we
would need to determine whether diesel fuel producers and importers
carry a total renewable fuel obligation calculated on the basis of
their production for all of 2010 or just the production period in 2010
during which the RFS2 regulations are effective. We would also need to
determine whether the 2010 cellulosic biofuel, biomass-based diesel,
and advanced biofuel standards applicable under RFS2 should apply to
production of gasoline and diesel for all of 2010 or just the
production that occurred after the RFS2 regulations were effective If
the latter, EPA would need to determine the extent to which RFS1 RINs
generated in the first part of 2010 could be used to satisfy RFS2
obligations, given that some 2010 RINs would be generated under the
RFS1 requirements while other 2010 RINs would be generated under RFS2
requirements. To accomplish this, RINs generated under the RFS2
requirements would need to be distinguished from RINs generated under
RFS1 requirements through the RINs' D codes. Section III.A provides a
more detailed description of this alternative approach to the
assignment of D codes under the RFS2 program. For additional discussion
of how RFS1 RINs would be treated in the transition to the RFS2
program, see our proposed transition approach described in Section III.G.3.
    We are requesting comment on all issues related to the option of an
RFS2 start date sometime after January 1, 2010, including the need for
such a delayed start, the level of the standards, treatment of diesel
producers and importers, whether the standards for advanced biofuel,
cellulosic biofuel and biomass-based diesel should apply to the entire
2010 production or just the production that would occur after the RFS2
effective date, treatment of the 2009 and/or 2010 biomass-based diesel
standard, and the extent to which RFS1 RINs should be valid to show
compliance with RFS2 standards.
2. Treatment of Biomass-Based Diesel in 2009 and 2010
    We are proposing to make the RFS2 program required through EISA
effective on January 1, 2010. The RFS2 program would include an
expansion to four

[[Page 24957]]

separate standards, changes to the RIN system, changes to renewable
fuel definitions, the introduction of lifecycle GHG reduction
thresholds, and the expansion of obligated parties to include producers
and importers of diesel and nonroad fuel. However, EISA requires
promulgation of the final RFS2 regulations within one year of enactment
and presumes full implementation by January 1, 2009. Moreover, EISA
specifies new volume requirements for biomass-based diesel, advanced
biofuel, and total renewable fuel for 2009. As described in Section
II.A.5, it is not possible to have the full RFS2 program implemented by
January 1, 2009. As a result, we must consider how to treat these
separate volume requirements for 2009.
a. Proposed Shift in Biomass-Based Diesel Requirement From 2009 to 2010
    The statutory language in EISA does not indicate that the existing
RFS1 regulations cease to apply on January 1, 2009. Rather, it directs
us to ``revise the regulations'' to ensure that the required volumes of
renewable fuel are contained in transportation fuel. As a result, until
the RFS1 regulations are changed through a notice and comment
rulemaking process, they will remain in effect. If the full RFS2
program goes into effect on January 1, 2010, then the existing RFS1
regulations will continue to apply in 2009.
    Under RFS1, we set the applicable standard each November for the
following compliance period using the required volume of renewable fuel
specified in the Clean Air Act, gasoline volume projections from EIA,
and the formula provided in the regulations at Sec.  80.1105(d). Since
final RFS2 regulations will not be promulgated by the end of 2008, this
RFS1 standard-setting process will apply to the 2009 compliance period
as well. However, EISA modifies the Clean Air Act to increase the
required volume of total renewable fuel for 2009 from 6.1 to 11.1
billion gallons, and thus the applicable standard for 2009, published
in November of 2008,\34\ reflects this higher volume. This will ensure
that the total renewable fuel requirement under EISA for 2009 is implemented.
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    \34\ See 73 FR 70643.
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    While the total renewable fuel volume of 11.1 billion gallons will
be required in 2009, the existing RFS1 regulations do not provide a
mechanism for requiring the 0.5 billion gallons of biomass-based diesel
or the 0.6 billion gallons of advanced biofuel required by EISA for
2009. Below we describe our proposed approach for biomass-based diesel.
With regard to advanced biofuel, we believe that it is not necessary to
implement a separate requirement for the 0.6 billion gallons. Due to
the nested nature of the volume requirements, the 0.5 billion gallon
requirement for biomass-based diesel would count towards meeting the
advanced biofuel requirement, leaving just 0.1 billion gallons that we
believe will be supplied through imports of sugar-based ethanol even
without a specific mandate for advanced biofuel.
    We believe that the deficit carryover provision provides a
conceptual mechanism for ensuring that the volume of biomass-based
diesel that is required by EISA for 2009 is actually consumed. As
described in the RFS1 final rule, the statute permits obligated parties
to carry a deficit of any size from one compliance period to the next,
so long as a deficit is not carried over two years in a row.\35\ In
theory this would allow any and all obligated parties to defer
compliance with any or all of the 2009 standards until 2010. Based on
the precedent set by this statutory provision, we propose that the
compliance demonstration for the 2009 biomass-based diesel requirement
be extended to 2010. We believe this approach would provide a
reasonable transition for biomass-based diesel, given our inability to
issue regulations before the beginning of the 2009 calendar year. Our
proposed approach would implement the 2009 and 2010 biomass-based
diesel volume requirements in a way that ensures that these two years
worth of biomass-based diesel would be used, while providing reasonable
lead time for obligated parties. It would avoid a transition that fails
to have any requirements related to the 2009 biomass-based diesel
volume, and instead would require the use of the 2009 volume but would
achieve this by extending the compliance period by one year. We believe
this is a reasonable exercise of our authority under section 211(o)(2)
to issue regulations that ensure that the volumes for 2009 are
ultimately used, even though we are unable to issue final regulations
prior to the 2009 compliance year. In addition, it is a practical
approach that provides obligated parties with appropriate lead time.
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    \35\ See 72 FR 23935.
---------------------------------------------------------------------------

    To implement our proposed approach, the 2009 requirement of 0.5
billion gallons of biomass-based diesel would be combined with the 2010
requirement of 0.65 billion gallons for a total adjusted 2010
requirement of 1.15 billion gallons of biomass-based diesel. The net
effect is that obligated parties can demonstrate compliance with both
the 2009 and 2010 biomass-based diesel requirements in 2010, consistent
with what the deficit carryover provision would have allowed had we
been able to implement the full RFS2 program by January 1, 2009.
    Furthermore, we propose to allow all 2009 biodiesel and renewable
diesel RINs, identifiable through an RR code of 15 or 17 respectively,
to be valid for showing compliance with the adjusted 2010 biomass-based
diesel standard of 1.15 billion gallons. This use of previous year RINs
for current year compliance would be consistent with our approach to
any other standard for any other year and consistent with the
flexibility available to any obligated party that carried a deficit
from one year to the next. Moreover, it allows an obligated party to
acquire sufficient biodiesel and renewable diesel RINs during 2009 to
comply with the 0.5 billion gallons requirement, even though their
compliance demonstration would not occur until the 2010 compliance period.
    While we recognize that RINs generated in 2009 under RFS1
regulations will differ from those generated in 2010 under RFS2
regulations in terms of the purpose of the D code and the other
criteria for establishing the eligibility of renewable fuel, we believe
that the use of 2009 RINs for compliance with the 2010 adjusted
standard is appropriate. It is also consistent with CAA section
211(o)(5), which provides that validly generated credits may be used to
show compliance for 12 months. The program transition issue of RINs
generated under RFS1 but used to meet standards under RFS2 is discussed
in more detail in Section III.G.3 below.
    Rather than reducing the 2009 volume requirement for total
renewable fuel by 0.5 billion gallons of biomass-based diesel and
increasing the 2010 volume requirements for advanced biofuel and total
renewable fuel by the same amount, we are proposing that the only
standard that would be adjusted would be that for biomass-based diesel
in 2010. This approach would minimize the changes to the annual RFS
volume requirements and thus would more directly implement the
requirements of the statute. However, this approach would also require
that we allow 2009 biodiesel and renewable diesel RINs to be used for
compliance purposes for both the 2009 total renewable fuel standard as
well as the 2010 adjusted biomass-based diesel standard, but not for
the 2010 advanced biofuel or total renewable fuel standards. We have

[[Page 24958]]

identified two possible options for accomplishing this.
i. First Option for Treatment of 2009 Biodiesel and Renewable Diesel RINs
    In the first option, an obligated party would add up the 2009
biodiesel and renewable diesel RINs that he used for 2009 compliance
with the RFS1 standard for renewable fuel, and reduce his 2010 biomass-
based diesel obligation by this amount. Any remaining 2010 biomass-
based diesel obligation would need to be covered with either 2009
biodiesel and renewable diesel RINs that were not used for compliance
with the renewable fuel standard in 2009, or 2010 biomass-based diesel
RINs. This is the option we are proposing in today's notice.
    The primary drawback of our proposed option is that 2009 biodiesel
and renewable diesel RINs used to demonstrate compliance with the 2009
renewable fuel standard could not be traded to any other party for use
in complying with the 2010 biomass-based diesel standard. Thus, for
instance, if a refiner acquired many 2009 biodiesel and renewable
diesel RINs and used them for compliance with the 2009 renewable fuel
standard, and if the number of these 2009 RINs was more than he needed
to comply with his 2010 biomass-based diesel obligation, he could not
trade the excess to another party. These excess RINs could never be
applied to the adjusted 2010 biomass-based diesel standard by any
party, and as a result the actual demand for biomass-based diesel could
exceed 1.15 bill gal. We believe that obligated parties could avoid
this outcome by planning ahead to use no more 2009 biodiesel and
renewable diesel RINs for 2009 compliance with the renewable fuel
standard than they would need for 2010 compliance with the adjusted
biomass-based diesel standard. Moreover, this option could provide
obligated parties with sufficient incentive to collect 0.5 billion
gallons worth of biodiesel and renewable diesel RINs in 2009 without
significant changes to the program's requirements.
ii. Second Option for Treatment of 2009 Biodiesel and Renewable Diesel RINs
    Under the second option, biodiesel and renewable diesel RINs
generated in 2009 would be allowed to be used for compliance purposes
in both 2009 and 2010. To enable this option, for the specific and
limited case of biodiesel and renewable diesel RINs generated in 2009,
we would modify the regulatory prohibition at Sec.  80.1127(a)(3)
limiting the use of RINs for compliance demonstrations to a single
compliance year to allow 2009 biodiesel and renewable diesel RINs to be
used for compliance purposes in two different years. This change would
allow all 2009 biodiesel and renewable diesel RINs to be used to meet
the adjusted biomass-based diesel standard in 2010 regardless of
whether they were also used to meet the total renewable fuel standard
in 2009. We would also need to lift the 20% rollover cap that would
otherwise limit the use of 2009 RINs in 2010, and instead allow any
number of 2009 biodiesel and renewable diesel RINs to be used to meet
the 2010 biomass-based diesel standard.
    This option would also require that we implement additional RIN
tracking procedures. Under the current RFS1 regulations, RINs used for
compliance demonstrations are removed from the RIN market, while under
this alternative approach biodiesel and renewable diesel RINs could
continue to be valid for compliance purposes vis a vis the adjusted
2010 biomass-based diesel standard even if they were already used for
compliance with the renewable fuel standard in 2009. The regulations
would need to be changed to allow this, and both EPA's and industry's
IT systems would need to be modified to allow for this temporary change.
    Due to the additional complexities associated with this option, we
are not proposing it. Nevertheless, we request comment on it, as it
would more explicitly reflect two separate obligations for calendar
year 2009: An RFS1 obligation for total renewable fuel, and an
obligation for biomass-based diesel that starts during 2009 with
compliance required by the end of 2010 for a volume that covers both
2009 and 2010. We also request comment on whether under this option we
should allow 2009 biodiesel and renewable diesel RINs to continue to be
bought and sold after 2009 if they are used to demonstrate compliance
with the 2009 total renewable fuel standard.
b. Proposed Treatment of Deficit Carryovers and Valid RIN Life For
Adjusted 2010 Biomass-Based Diesel Requirement
    Although our proposed transition approach is conceptually similar
to the statutory deficit carryover provision, the regulatory
requirements would not explicitly treat the movement of the 0.5 billion
gallons biomass-based diesel requirement from 2009 to 2010 as a deficit
carryover. In the absence of any modifications to the deficit carryover
provisions, then, an obligated party that did not fully comply with the
2010 biomass-based diesel requirement of 1.15 billion gallons could
carry a deficit of any amount into 2011.
    If we had been able to implement the 2009 biomass-based diesel
volume requirement of 0.5 billion gallons in calendar year 2009, the
2010 biomass-based diesel standard would have been based on 0.65
billion gallons. In this case, the maximum volume of biomass-based
diesel that could have been carried into 2011 as a deficit would have
been 0.65 billion gallons. In the context of our proposed approach to
the treatment of biomass-based diesel in 2009 and 2010, we believe that
it would be inappropriate to allow the full 1.15 billion gallons to be
carried into 2011 as a deficit. Therefore, we are proposing that
obligated parties be prohibited from carrying over a deficit into 2011
larger than 0.65 bill gal. In practice, this would mean that deficit
carryovers from 2010 into 2011 for biomass-based diesel could not
exceed 57% of an obligated party's 2010 RVO.
    Similarly, the combination of the 0.5 billion gallons biomass-based
diesel requirement from 2009 with the 2010 volume raises the question
of whether 2008 biodiesel or renewable diesel RINs could be used for
compliance in 2010 with the adjusted biomass-based diesel standard.
Without a change to the regulations, this practice would not be allowed
because RINs are only valid for compliances purposes for the year
generated or the year after. However, if we had been able to implement
the full RFS2 program for the 2009 compliance year, 2008 biodiesel and
renewable diesel RINs would be valid for compliance with the 0.5
billion gallons biomass-based diesel requirement. Therefore, we are
proposing to modify the regulations to allow excess 2008 biodiesel and
renewable diesel RINs to be used for compliance purposes in 2009 or
2010. We request comment on this proposal.
    We also propose that the 20% rollover cap would continue to apply
in all years as described in more detail in Section IV.D. However, we
are proposing an additional constraint in the application of this cap
to the biomass-based diesel obligation in the 2010 compliance year. If
the 2009 biomass-based diesel volume requirement of 0.5 billion gallons
could have been required in 2009, the use of excess 2008 biodiesel and
renewable diesel RINs would have been limited to 20% of the 2009
requirement, or a maximum of 0.1 billion gallons. Since we are
proposing to require that the 2009 and 2010 biomass-based diesel
requirements be combined for a total of 1.15 billion gallons, we
propose that the maximum allowable portion that could be derived from
2008 biomass-based

[[Page 24959]]

diesel RINs would be 0.1 billion gallons. This would represent 8.7% of
the 2010 obligation (\0.1/1.15\). In addition to this limit on the use
of 2008 RINs for 2010 compliance that is unique to this option, the 20%
rollover cap would continue to apply to the use of all previous-year
RINs used for compliance purposes in 2010. Thus, the total number of
all 2008 and 2009 RINs that could be used to meet the 2010 biomass-
based diesel obligation would continue to be capped at 20%. We request
comment on this approach.
    Finally, we are proposing to allow 2009 RINs that are retired
because they are ultimately used for nonroad or home heating oil
purposes to be valid for compliance with the 2010 RFS standard.
Currently, under RFS1, RINs associated with renewable fuel that is not
ultimately used as motor vehicle fuel must be retired. In contrast,
under EISA, renewable fuel used for nonroad purposes, except for use in
industrial boilers or ocean-going vessels, is considered transportation
fuel, and is eligible for the RFS program. We are proposing that 2009
RINs generated for renewable fuel that is ultimately used for nonroad
or home heating oil purposes continue to be retired by the appropriate
party pursuant to 80.1129(e). However, we are proposing that those
retired 2009 nonroad or home heating oil RINs be eligible for
reinstatement by the retiring party in 2010. These reinstated RINs may
be used by that party to demonstrate compliance with a 2010 RVO, or for
sale to other parties who would then use the RINs for compliance
purposes. While we anticipate that this proposed provision would be
utilized largely for biodiesel RINs that were retired by parties that
sold them for use as nonroad fuel or home heating oil, we propose that
the provision apply to all RINs. We request comment on this proposed approach.
c. Alternative Approach to Treatment of Biomass-Based Diesel in 2009 and 2010
    Under our proposed approach, the 0.5 billion gallon requirement for
biomass-based diesel in 2009 would be added to the 0.65 billion gallon
requirement for 2010, and the total volume of 1.15 billion gallons
would be used as the basis of a single adjusted standard applicable to
obligated parties in 2010. The compliance demonstration for this single
standard would need to be made by February 28, 2011. As an alternative,
we could establish two separate biomass-based diesel standards for
which compliance must be demonstrated by February 28, 2011. One of
these standards would be based on 0.65 billion gallons and would
represent the applicable biomass-based diesel standard for 2010. The
other standard would be based on 0.5 billion gallons and would
represent the applicable biomass-based diesel standard for 2009. In
essence, the standard based on 0.5 billion gallons would be for the
2009 calendar year even though we would extend its compliance
demonstration until February 28, 2011.
    In this alternative, only excess 2008 or 2009 biodiesel and
renewable diesel RINs could be used to comply with the standard based
on 0.5 billion gallons. Excess 2009 biodiesel or renewable diesel RINs
and 2010 biomass-based diesel RINs could be used to comply with the
standard based on 0.65 billion gallons. The 20% rollover cap would
apply to both standards. As a result, this alternative approach would
effectively implement the 2009 biomass-based diesel standard in
calendar year 2009, and thus it may come closer to the statute's
requirements than our proposed approach. Moreover, the existing
provisions for the valid life of RINs and deficit carryover would not
need modification as they would under our proposed approach.
    However, this alternative would arguably provide less than
appropriate lead time for meeting the 0.5 billion gallon obligation, as
it would require obligated parties to begin acquiring sufficient 2008
and 2009 biodiesel and renewable diesel RINs starting in January of
2009 even though our final rulemaking is not expected to be issued
until the fall of 2009. There are two reasons that this lead time might
nevertheless be considered appropriate. First, obligated parties could
wait until the final rule is published to begin acquiring 2008 and 2009
biodiesel and renewable diesel RINs. Moreover, they would not need to
demonstrate compliance with the 0.5 billion gallons standard until
February 28, 2011, providing ample time to locate and acquire
sufficient RINs. Second, the deficit carryover provisions would allow
obligated parties to treat the separate 0.5 and 0.65 billion gallon
requirements as a single requirement that must be met in total by
February 28, 2011. In this sense, this alternative is similar to our
proposed approach. We request comment on this alternative approach.
d. Treatment of Biomass-Based Diesel Under an RFS2 Effective Date Other
Than January 1, 2010
    The above discussion assumes that the RFS2 program is effective on
January 1, 2010. If the program effective date is delayed, similar
issues arise regarding whether EISA volume mandates for fuel categories
with no mandates under RFS1 are lost, or should be recaptured through a
delayed compliance demonstration in the first year of the RFS2 program.
For a delay beyond January 1, 2010, the issues relate to cellulosic
biofuel and advanced biofuel in addition to biomass-based diesel.
    For instance, our proposed approach to biomass-based diesel
effectively makes the one-year deficit carryover a necessary element of
compliance for 2010, and maintains the two-year valid life of RINs.
However, if the effective date of RFS2 were delayed to January 1, 2011,
we could not take the same approach. By requiring compliance
demonstrations to be made in 2011 for the required biomass-based diesel
volumes mandated for 2009, 2010, and 2011, we would be effectively
requiring a 2-year deficit carryover and a three-year valid life of
RINs, contrary to the statutory limitations. As an alternative, one
possible approach would be to only sum the required biomass-based
diesel volumes for 2010 and 2011 and require compliance demonstrations
at the end of 2011.
    If the RFS2 program became effective in mid-2010, we would also
need to determine the appropriate level of the biomass-based diesel
standard, and whether it would apply to gasoline and diesel volumes
produced only after the RFS2 effective date, or all gasoline and diesel
volumes produced in 2010.
    EPA invites comment on whether and how it should recapture these
volume mandates under different start-date scenarios.

F. Fuels That Are Subject to the Standards

    Under RFS1, producers and importers of gasoline are obligated
parties subject to the standards. Any party that produces or imports
only diesel fuel is not subject to the standards. EISA changes this
provision by expanding the RFS program in general to include
transportation fuel. As discussed above, however, section 211(o)(3)
continues to require EPA to determine which refiners, blenders, and
importers are treated as subject to the standard. As described further
in Section III.G below, we are proposing that the sum of all highway
and nonroad gasoline and diesel fuel produced or imported within a
calendar year be the basis on which the RVOs are calculated. This
section provides our proposed definition of gasoline and diesel for the
purposes of the RFS program.

[[Page 24960]]

1. Gasoline
    As with the RFS1 program, the volume of gasoline used in
calculating the RVO under RFS2 would continue to include all finished
gasoline (reformulated gasoline (RFG) and conventional gasoline (CG))
produced or imported for use in the contiguous United States or Hawaii,
as well as all unfinished gasoline that becomes finished gasoline upon
the addition of oxygenate blended downstream from the refinery or
importer. This would include both unfinished reformulated gasoline,
called ``reformulated gasoline blendstock for oxygenate blending,'' or
``RBOB,'' and unfinished conventional gasoline designed for downstream
oxygenate blending (e.g., sub-octane conventional gasoline), called
``CBOB.'' The volume of any other unfinished gasoline or blendstock,
such as butane or naphtha produced in a refinery, would not be included
in the obligated volume, except where the blendstock is combined with
other blendstock or gasoline to produce finished gasoline, RBOB, or
CBOB. Where a blendstock is blended with other blendstock to produce
finished gasoline, RBOB, or CBOB, the total volume of the gasoline
blend would be included in the volume used to determine the blender's
renewable fuels obligation. Where a blendstock is added to finished
gasoline, only the volume of the blendstock would be included, since
the finished gasoline would have been included in the compliance
determinations of the refiner or importer of the gasoline. For purposes
of this preamble, the various gasoline products described above that we
are proposing to include in a party's obligated volume would
collectively be called ``gasoline.''
    Also consistent with the RFS1 program, we propose to continue to
exclude any volume of renewable fuel contained in gasoline from the
volume of gasoline used to determine the renewable fuels obligations.
This exclusion would apply to any renewable fuels that are blended into
gasoline at a refinery, contained in imported gasoline, or added at a
downstream location. Thus, for example, any ethanol added to RBOB or
CBOB at a refinery's rack or terminal downstream from the refinery or
importer would be excluded from the volume of gasoline used by the
refiner or importer to determine the obligation. This is consistent
with how the standard itself is calculated--EPA determines the
applicable percentage by comparing the overall projected volume of
gasoline used to the overall renewable fuel volume that is specified in
EPAct, and EPA excludes ethanol and other renewable fuels that blended
into the gasoline in determining the overall projected volume of
gasoline. When an obligated party determines their RVO by applying the
applicable percentage to the amount of gasoline they produce or import,
it is consistent to also exclude ethanol and other renewable fuel
blends from the calculation of the volume of gasoline produced.
    As with the RFS1 program, we are proposing that Gasoline Treated as
Blendstock (GTAB) would continue to be treated as a blendstock under
the RFS2 program, and thus would not count towards a party's renewable
fuel obligation. Where the GTAB is blended with other blendstock (other
than renewable fuel) to produce gasoline, the total volume of the
gasoline blend, including the GTAB, would be included in the volume of
gasoline used to determine the renewable fuel obligation. Where GTAB is
blended with renewable fuel to produce gasoline, only the GTAB volume
would be included in the volume of gasoline used to determine the
renewable fuel obligation. Where the GTAB is blended with finished
gasoline, only the GTAB volume would be included in the volume of
gasoline used to determine the renewable fuel obligation.
2. Diesel
    As discussed above in Section II.A.4, EISA expanded the RFS program
to include transportation fuels other than gasoline, and we are
proposing that both highway and nonroad diesel be used in calculating a
party's RVO. We are proposing that any party that produces or imports
petroleum-based diesel fuel that is designated as motor vehicle,
nonroad, locomotive, and marine diesel fuel (MVNRLM) (or any
subcategory of MVNRLM) would be required to include the volume of that
diesel fuel in the determination of its RVO under the RFS2 rule. We are
proposing that diesel fuel would include any distillate fuel that meets
the definition of MVNRLM diesel fuel as it has already been defined in
the regulations at Sec.  80.2(qqq), including any subcategories such as
MV (motor vehicle diesel produced for use in highway diesel engines and
vehicles), NRLM (diesel produced for use in nonroad, locomotive, and
marine diesel engines and equipment/vessels), NR (diesel produced for
use in nonroad engines and equipment), and LM (diesel produced for use
in locomotives and marine diesel engines and vessels).\36\ We are
proposing that transportation fuels meeting the definition of MVNRLM
would be used to calculate the RVOs, and refiners, blenders, or
importers of MVNRLM would be treated as obligated parties. As such,
diesel fuel that is designated as heating oil, jet fuel, or any
designation other than MVNRLM or a subcategory of MVNRLM, would not be
subject to the applicable percentage standard and would not be used to
calculate the RVOs.\37\
---------------------------------------------------------------------------

    \36\ EPA's diesel fuel regulations use the term ``nonroad'' to
designate one large category of land-based off-highway engines and
vehicles, recognizing that locomotive and marine engines and vessels
are also nonroad engines and vehicles under EPAct's definition of
nonroad. Except where noted, the discussion of nonroad in reference
to transportation fuel includes the entire category covered by
EPAct's definition of nonroad.
    \37\ See 40 CFR 80.598(a) for the kinds of fuel types used by
refiners or importers in designating their diesel fuel.
---------------------------------------------------------------------------

    We are also requesting comment on the idea that any diesel fuel not
meeting these requirements, such as distillate or residual fuel
intended solely for use in ocean-going vessels, would not be used to
calculate the RVOs. As discussed above in Section II.A.4, EISA
specifies that ``transportation fuels'' do not include fuels for use in
ocean-going vessels. We are interpreting the term ``ocean-going
vessel'' to mean those vessels that are powered by Category 3 (C3)
marine engines and that use residual fuel or operate internationally;
we request comment on this interpretation. As such, we are requesting
comment on the concept that fuel intended solely for use in ocean-going
vessels, or that an obligated party can verify as having been used in
an ocean-going vessel, would be excluded from the renewable fuel
standards. Further, we are also requesting comment on whether fuel used
on such vessels with C2 engines should also be excluded from the
renewable fuel standards, and how such an exemption should be phrased.
3. Other Transportation Fuels
    As discussed further in Section III.J.3, below, we propose that
transportation fuels other than gasoline or MVNRLM diesel fuel (natural
gas, propane, and electricity) would not be used to calculate the RVOs
of any obligated party. We believe this is a reasonable way to
implement the obligations of 211(o)(3) because the volumes are small
and the producers cannot readily differentiate the small transport
portion from the large non-transport portion (in fact, the producer may
have no knowledge of its use in transport); we will reconsider this
approach if and when these volumes grow. At the same time, it is clear
that other fuels can meet the definition of ``transportation fuel,''
and we are proposing that under certain

[[Page 24961]]

circumstances, producers or generators of such other transportation
fuels may generate RINs as a producer or importer of a renewable fuel.
See Section III.B.1.a for further discussion of other RIN-generating fuels.

G. Renewable Volume Obligations (RVOs)

    Under the current RFS program, each obligated party must determine
its RVO based on the applicable percentage standard and its annual
gasoline volume. The RVO represents the volume of renewable fuel that
the obligated party must ensure is used in the U.S. in a given calendar
year. Obligated parties must meet their RVO through the accumulation of
RINs which represent the amount of renewable fuel used as motor vehicle
fuel that is sold or introduced into commerce within the U.S. Each
gallon-RIN would count as one gallon of renewable fuel for compliance purposes.
    We propose to maintain this approach to compliance under the RFS2
program. One primary difference between the current and new RFS
programs in terms of demonstrating compliance would be that each
obligated party would now have four RVOs instead of one (through 2012)
or two (starting in 2013) under the RFS1 program. Also, as discussed
above, RVOs would be calculated based on production or importation of
both gasoline and diesel fuels, rather than gasoline alone.
    By acquiring RINs and applying them to their RVOs, obligated
parties are effectively causing the renewable fuel represented by the
RINs to be consumed as transportation fuel in highway or nonroad
vehicles or engines. Obligated parties would not be required to
physically blend the renewable fuel into gasoline or diesel fuel
themselves. The accumulation of RINs would continue to be the means
through which each obligated party shows compliance with its RVOs and
thus with the renewable fuel standards.
    If an obligated party acquires more RINs than it needs to meet its
RVOs, then in general it could retain the excess RINs for use in
complying with its RVOs in the following year or transfer the excess
RINs to another party. If, alternatively, an obligated party has not
acquired sufficient RINs to meet its RVOs, then under certain
conditions it could carry a deficit into the next year.
    This section describes our proposed approach to the calculation of
RVOs under RFS2 and the RINs that would be valid for demonstrating
compliance with those RVOs. This includes a description of the special
treatment that must be applied to 2009 RINs used for compliance
purposes in 2010, since RINs generated in 2009 under RFS1 would not be
exactly the same as those generated in 2010 under RFS2. We also
describe an alternative approach to the identification of obligated
parties that would place the obligations under RFS2 on only finished
gasoline and diesel rather than on certain blendstocks and unfinished
fuels as well. The implication of this would be that the final blender
of the gasoline or diesel would be the obligated parties rather than
producers of blendstocks and unfinished fuels.
1. Determination of RVOs Corresponding to the Four Standards
    In order for an obligated party to demonstrate compliance, the
percentage standards described in Section III.E.1 which are applicable
to all obligated parties must be converted into the volumes of
renewable fuel each obligated party is required to satisfy. These
volumes of renewable fuel are the volumes for which the obligated party
is responsible under the RFS program, and are referred to here as its
RVO. Under RFS2, each obligated party would need to acquire sufficient
RINs each year to meet each of the four RVOs corresponding to the four
renewable fuel standards.
    The calculation of the RVOs under RFS2 would follow the same format
as the existing formulas in the regulations at Sec.  80.1107(a), with
one modification. The standards for a particular compliance year would
be multiplied by the sum of the gasoline and diesel volume produced or
imported by an obligated party in that year rather than only the
gasoline volume as under the current program.\38\ To the degree that an
obligated party did not demonstrate full compliance with its RVOs for
the previous year, the shortfall would be included as a deficit
carryover in the calculation. CAA section 211(o)(5) only permits a
deficit carryover from one year to the next if the obligated party
achieves full compliance with its RVO including the deficit carryover
in the second year. Thus deficit carryovers could not occur two years
in succession for any of the four standards. They could, however, occur
as frequently as every other year for a given obligated party.
---------------------------------------------------------------------------

    \38\ As discussed above, the diesel fuel that is used to calculate the
RVO is any diesel designated as MVNRLM or a subcategory of MVNRLM.
---------------------------------------------------------------------------

    Note that a party that produces only diesel fuel would have an
obligation for all four standards even though he would not have the
opportunity to blend ethanol into his own gasoline. Likewise, a party
that produces only gasoline will have an obligation for all four
standards even though he would not have an opportunity to blend
biomass-based diesel into his own diesel fuel. Although these
circumstances might imply that the four standards should be further
subdivided into gasoline-specific and diesel-specific standards, we do
not believe that this would be appropriate as described in Section
III.E.1. Instead, since the obligations are met through the use of
RINs, compliance with the standards does not require an obligated party
to blend renewable fuel into their own or anyone else's gasoline or
diesel fuel.
2. RINs Eligible To Meet Each RVO
    Under RFS1, all RINs had the same compliance value and thus it did
not matter what the RR or D code was for a given RIN when using that
RIN to meet the total renewable fuel standard. In contrast, under RFS2
only RINs with specified D codes could be used to meet each of the four
standards.
    As described in Section II.A.1, the volume requirements in EISA are
generally nested within one another, so that the advanced biofuel
requirement includes fuel that meets either the cellulosic biofuel or
the biomass-based diesel requirements, and the total renewable fuel
requirement includes fuel that meets the advanced biofuel requirement.
As a result, the RINs that can be used to meet the four standards are
likewise nested. Using the proposed D codes defined in Table III.A-1,
the RINs that could be used to meet each of the four standards are
shown in Table III.G.2-1.

                          Table III.G.2-1--RINs That Can Be Used To Meet Each Standard
----------------------------------------------------------------------------------------------------------------
               Standard                              Obligation                       Allowable D codes
----------------------------------------------------------------------------------------------------------------
Cellulosic biofuel....................  RVOCB..............................  1.

[[Page 24962]]

Biomass-based diesel..................  RVOBBD.............................  2.
Advanced biofuel......................  RVOAB..............................  1, 2, and 3.
Renewable fuel........................  RVORF..............................  1, 2, 3, and 4.
----------------------------------------------------------------------------------------------------------------

    The nested nature of the four standards also means that we must
allow the same RIN to be used to meet more than one standard in the
same year. Thus, for instance, a RIN with a D code of 1 could be used
to meet three of the four standards, while a RIN with a D code of 3
could be used to meet both the advanced biofuel and total renewable
fuel standards. However, we propose continuing to prohibit the use of a
single RIN for compliance purposes in more than one year or by more
than one party.\39\
---------------------------------------------------------------------------

    \39\ Note that we are proposing an exception to this general
prohibition for the specific and limited case of excess 2008 and
2009 biodiesel and renewable diesel RINs used to demonstrate
compliance with both the 2009 total renewable fuel standard and the
2010 biomass-based diesel standard. See Section III.E.2.a.
---------------------------------------------------------------------------

3. Treatment of RFS1 RINs Under RFS2
    As described in Section II.A, we are proposing a number of changes
to the RFS program as a result of the requirements in EISA. These
changes would go into effect on January 1, 2010 and, among other
things, would affect the conditions under which RINs are generated and
their applicability to each of the four standards. As a result, RINs
generated in 2010 under RFS2 will not be exactly the same as RINs
generated in 2009 under RFS1. Given the valid RIN life that allows a
RIN to be used in the year generated or the year after, we must address
circumstances in which excess 2009 RINs are used for compliance
purposes in 2010. We must also address deficit carryovers from 2009 to
2010, since the total renewable fuel standards in these two years will
be defined differently.
a. Use of 2009 RINs in 2010
    In 2009, the RFS1 regulations will continue to apply and thus
producers will not be required to demonstrate that their renewable fuel
is made from renewable biomass as defined by EISA, nor that their
combination of fuel type, feedstock, and process meets the GHG
thresholds specified in EISA. Moreover, there is no practical way to
determine after the fact if RINs generated in 2009 meet any of these
criteria. However, we believe that the vast majority of RINs generated
in 2009 would in fact meet the RFS2 requirements. First, while ethanol
made from corn must meet a 20% GHG threshold under RFS2 if produced by
a facility that commenced construction after December 19, 2007,
facilities that were already built or had commenced construction as of
December 19, 2007 are exempt from this requirement. Essentially all
ethanol produced in 2009 will meet the prerequisites for this
exemption. Second, it is unlikely that renewable fuels produced in 2009
will have been made from feedstocks grown on agricultural land that had
not been cleared or cultivated prior to December 19, 2007. In the
intervening time period, it is much more likely that the additional
feedstocks needed for renewable fuel production would come from
existing cropland or cropland that has lain fallow for some time.
Finally, the text of section 211(o)(5) states that a ``credit generated
under this paragraph shall be valid to show compliance for the 12
months as of the date of generation,'' and EISA did not change this
provision and did not specify any particular transition protocol to
follow. A straightforward interpretation of this provision is to allow
2009 RINs to be valid to show compliance for 2010 obligations.
    Since there will be separate standards for cellulosic biofuel and
biomass-based diesel in 2010, RINs generated in 2009 that could be used
to meet either of these two 2010 standards should meet the GHG
thresholds of 60% and 50%, respectively. While we will not have a
mechanism in place to determine if these thresholds have been met for
RINs generated in 2009, and there are indications from our assessment
of lifecycle GHG performance that at least some renewable fuels
produced in 2009 would not meet these thresholds, nevertheless any
shortfall in GHG performance for this one transition year is unlikely
to have a significant impact on long-term GHG benefits of the program.
Based on our belief that it is critical to the smooth operation of the
program that excess 2009 RINs be allowed to be used for compliance
purposes in 2010, we are proposing that RINs generated in 2009 to
represent cellulosic biomass ethanol whose GHG performance has not been
verified would still be valid for use for 2010 compliance purposes for
the cellulosic biofuel standard. Likewise, we are proposing that RINs
generated in 2009 to represent biodiesel and renewable diesel whose GHG
performance has not been verified would still be valid for use for 2010
compliance purposes for the biomass-based diesel standard. We request
comment on this approach.
    We propose to use information contained in the RR and D codes of
RFS1 RINs to determine how those RINs should be treated under RFS2. The
RR code is used to identify the Equivalence Value of each renewable
fuel, and under RFS1 these Equivalence Values are unique to specific
types of renewable fuel. For instance, biodiesel (mono alkyl ester) has
an Equivalence Value of 1.5, and non-ester renewable diesel has an
Equivalence Value of 1.7, and both of these fuels may be valid for
meeting the biomass-based diesel standard under RFS2. Likewise, RINs
generated for cellulosic biomass ethanol in 2009 must be identified
with a D code of 1, and these fuels may be valid for meeting the
cellulosic biofuel standard under RFS2. Our proposed treatment of 2009
RINs in 2010 is shown in Table III.G.3.a-1.

    Table III.G.3.a-1--Proposed Treatment of Excess 2009 RINs in 2010
------------------------------------------------------------------------
             Excess 2009 RINs                     Treatment in 2010
------------------------------------------------------------------------
RFS1 RINs with RR code of 15 or 17........  Equivalent to RFS2 RINs with
                                             D code of 2.
RFS1 RINs with D code of 1................  Equivalent to RFS2 RINs with
                                             D code of 1.
All other RFS1 RINs.......................  Equivalent to RFS2 RINs with
                                             D code of 4.
------------------------------------------------------------------------

    Although we have discussed the issue of RFS1 RINs being used for
RFS2 purposes in the context of our proposal that the RFS2 program be
effective on January 1, 2010, we would expect a similar treatment of
RFS1 RINs for RFS2 compliance purposes if the RFS2 effective date is
delayed. In that case RFS1 RINs generated in 2010 would be available to
show compliance for both the 2010 and 2011 compliance years, in a
manner similar to that described above.

[[Page 24963]]

b. Deficit Carryovers From the RFS1 Program to RFS2
    If the RFS2 program goes into effect on January 1, 2010, the
calculation of RVOs in 2009 under the existing regulations will be
somewhat different than the calculation of RVOs in 2010 under RFS2. In
particular, 2009 RVOs will be based upon gasoline production only,
while 2010 RVOs would be based on volumes of gasoline and diesel. As a
result, 2010 compliance demonstrations that include a deficit carried
over from 2009 will combine obligations calculated on two different bases.
    We do not believe that deficits carried over from 2009 to 2010
would undermine the goals of the program in requiring specific volumes
of renewable fuel to be used each year. Although RVOs in 2009 and 2010
would be calculated differently, obligated parties must acquire
sufficient RINs in 2010 to cover any deficit carried over from 2009 in
addition to that portion of their 2010 obligation which is based on
their 2010 gasoline and diesel production. As a result, the 2009
nationwide volume requirement of 11.1 billion gallons of renewable fuel
will be consumed over the two year period concluding at the end of
2010. Thus, we are not proposing special treatment for deficits carried
over from 2009 to 2010.
    We propose that a deficit carried over from 2009 to 2010 would only
affect a party's total renewable fuel obligation in 2010
(RVO_RF,i as discussed in Section III.G.1), as the 2009
obligation is for total renewable fuel use, not a subcategory. The RVOs
for cellulosic biofuel, biomass-based diesel, or advanced biofuel would
not be affected, as they do not have parallel obligations in 2009 under RFS1.
    If the RFS2 start date is delayed to be later than January 1, 2010,
we expect that the same principles described above would apply for any
deficit calculated under the RFS1 program and carried forward to RFS2.
4. Alternative Approach to Designation of Obligated Parties
    Under RFS1, obligated parties who are subject to the standard are
those that produce or import finished gasoline (RFG and conventional)
or unfinished gasoline that becomes finished gasoline upon the addition
of an oxygenate blended downstream from the refinery or importer.
Unfinished gasoline includes reformulated gasoline blendstock for
oxygenate blending (RBOB), and conventional gasoline blendstock
designed for downstream oxygenate blending (CBOB) which is generally
sub-octane conventional gasoline. The volume of any other unfinished
gasoline or blendstock, such as butane, is not included in the volume
used to determine the RVO, except where the blendstock is combined with
other blendstock or finished gasoline to produce finished gasoline,
RBOB, or CBOB. Thus, parties downstream of a refinery or importer are
only obligated parties to the degree that they use non-renewable
blendstocks to make finished gasoline, RBOB, or CBOB.
    The approach we took for RFS1 was based on our expectation at that
time that there would be an excess of RINs at low cost, and our belief
that the ability of RINs to be traded freely between any parties once
separated from renewable fuel would provide ample opportunity for
parties who were in need of RINs to acquire them from parties who had
excess. We also pointed out that the designation of ethanol blenders as
obligated parties would have greatly expanded the number of regulated
parties and increased the complexity of the RFS program beyond that
which was necessary to carry out the renewable fuels mandate under CAA
section 211(o).
    Following the new requirements under EISA, the required volumes of
renewable fuel will be increasing significantly above the levels
required under RFS1. These higher volumes are already resulting in
changes in the demand for RINs and operation of the RIN market. First,
obligated parties who have excess RINs are increasingly opting to
retain rather than sell them to ensure they have a sufficient number
for the next year's compliance. Second, since all gasoline is expected
to contain ethanol by 2013, few blenders would be able to avoid taking
ownership of RINs by that time under the existing definition of
obligated party. As a result, by 2013 essentially every blender would
be a regulated party who is subject to recordkeeping and reporting
requirements, and thus the additional burden of demonstrating
compliance with the standard could be small. Third, major integrated
refiners who operate gasoline marketing operations have direct access
to RINs for ethanol blended into their gasoline, while refiners whose
operations are focused primarily on producing refined products do not
have such direct access to RINs. The result is that in some cases there
are significant disparities between obligated parties in terms of
opportunities to acquire RINs. If those that have excess RINs are
reluctant to sell them, those who are seeking RINs may be forced to
market a disproportionate share of E85 in order to gain access to the
RINs they need for compliance. If obligated parties seeking RINs cannot
acquire a sufficient number, they can only carry a deficit into the
following year, after which they would be in noncompliance if they
could not acquire sufficient RINs. The result might be a much higher
price for RINs (and fuel) in the marketplace than would be expected
under a more liquid market.
    Given the change in circumstances brought about through EISA, it
may be appropriate to consider a change in the way that obligated
parties are defined to more evenly align a party's access to RINs with
that party's obligations under the RFS2 program. The most
straightforward approach would be to eliminate RBOB and CBOB from the
list of fuels that are subject to the standard, such that a party's RVO
would be based only on the non-renewable volume of finished gasoline or
diesel that he produces or imports. Parties that blend ethanol into
RBOB and CBOB to make finished gasoline would thus be obligated
parties, and their RVOs would be based upon the volume of RBOB and CBOB
prior to ethanol blending. Traditional refiners that convert crude oil
into transportation fuels would only have an RVO to the degree that
they produced finished gasoline or diesel, with all RBOB and CBOB sold
to another party being excluded from the calculation of their RVO.
    Since essentially all gasoline is expected to be E10 within the
next few years (see discussion in Section V.D.2 below), this approach
would effectively shift the obligation for all gasoline from refiners
and importers to ethanol blenders (who in many cases are still the
refiners). However, this approach by itself would maintain the
obligation for diesel on refiners and importers. Thus, a variation of
this approach would be to move the obligations for all gasoline and
diesel downstream to parties who supply finished transportation fuels
to retail outlets or to wholesale purchaser-consumer facilities. This
variation would have the additional effect of more closely aligning
obligations and access to RINs for parties that blend biodiesel and
renewable diesel into petroleum-based diesel.
    We are not proposing to eliminate RBOB and CBOB from the list of
fuels that are subject to the standard in today's notice since it would
result in a significant change in the number of obligated parties and
the movement of RINs. Many parties that are not obligated under the
current RFS program would become obligated, and would be forced to
implement new systems for determining and reporting compliance.
Nevertheless, it would have certain advantages. Currently, blenders

[[Page 24964]]

that are not obligated parties are profiting from the sale of RINs they
acquire through splash blending of ethanol. By eliminating RBOB and
CBOB from the list of obligated fuels, these blenders would become
directly responsible for ensuring that the volume requirements of the
RFS program are met, and the cost of meeting the standard would be more
evenly distributed among parties that blend renewable fuel into
gasoline. With obligations placed more closely to the points in the
distribution system where RINs are made available, the overall market
prices for RINs may be lowered and consequently the cost of the program
to consumers may be reduced.
    While eliminating the categories of RBOB and CBOB from the list of
obligated fuels would result in a significant change in the
distribution of obligations among transportation fuel producers, it
could help to ensure that the RIN market functions as we originally
intended. As a result, RINs would more directly be made available to
the parties that need them for compliance. This is similar to the goal
of the direct transfer approach to RIN distribution as described in the
proposed rulemaking for the RFS1 program and presented again in Section
III.H.4 below. We request comment on the degree to which access to RINs
is a concern among current obligated parties. Since either the
elimination of RBOB and CBOB from the list of obligated fuels or the
direct transfer approach to RIN distribution could both accomplish the
same goal, we request comment on which one would be more appropriate, if any.
    We have also considered a number of alternative approaches that
could be used to help ensure that obligated parties can demonstrate
compliance. For instance, one alternative approach would leave our
proposed definitions for obligated parties in place, but would add a
regulatory requirement that any party who blends ethanol into RBOB or
CBOB must transfer the RINs associated with the ethanol to the original
producer of the RBOB or CBOB. However, we believe that such an approach
would be both inappropriate and difficult to implement. RBOB and CBOB
is often transferred between multiple parties prior to ethanol
blending. As a result, a regulatory requirement for RIN transfers back
to the original producer would necessitate an additional tracking
requirement for RBOB and CBOB so that the blender would know the
identity of the original producer. It would also be difficult to ensure
that RINs representing the specific category of renewable fuel blended
were transferred to the producer of the RBOB or CBOB, given the
fungible nature of RINs assigned to batches of renewable fuel. For
these reasons, we do not believe that this alternative approach would
be appropriate.
    In another alternative approach, some RINs that expire without
being used for compliance by an obligated party could be used to reduce
the nationwide volume of renewable fuel required in the following year.
We would only reduce the required volume of renewable fuel to the
degree that sufficient RINs had been generated to permit all obligated
parties to demonstrate compliance, but some obligated parties
nevertheless could not acquire a sufficient number of RINs. Moreover,
only RINs that were expiring would be used to reduce the nationwide
volume for the next year. This alternative approach would ensure that
the volumes required in the statute would actually be produced and
would prevent the hoarding of RINs from driving up demand for renewable
fuel. However, it would also reduce the impact of the valid life limit for RINs.
    We could lower the 20% rollover cap applicable to the use of
previous-year RINs to a lower value, such as 10%. This approach would
provide a greater incentive for obligated parties with excess RINs to
sell them but would further restrict a potentially useful means of
managing an obligated party's risk. As described in Section IV.D, we
are not proposing any changes in the 20% rollover cap in today's
notice. However, we request comment on it.
    Finally, another change to the program that would not change the
definition of obligated parties, but could help address the disparity
of access to RINs among obligated parties, would be to remove the
requirement developed under RFS1 that RINs be transferred with
renewable fuel volume by the renewable fuel producers and importers.
This alternative is discussed further in Section III.H.4 below.

H. Separation of RINs

    We propose that most of the RFS1 provisions regarding the
separation of RINs from volumes of renewable fuel be retained for RFS2.
However, the modifications in EISA will require a number of changes,
primarily to the treatment of RINs associated with nonroad renewable
fuel and renewable fuels used in heating oil and jet fuel. Our approach
to the separation of RINs by exporters must also be modified to account
for the fact that there would be four categories of renewable fuel under RFS2.
1. Nonroad
    Under RFS1, RINs associated with renewable fuels used in nonroad
vehicles and engines downstream of the renewable fuel producer are
required to be retired by the party who owns the renewable fuel at the
time of blending. This provision derived from the EPAct definition of
renewable fuel which was limited to fuel used to replace fossil fuel
used in a motor vehicle. EISA however expands the definition of
renewable fuel, and ties it to the definition of transportation fuel,
which is defined as any ``fuel for use in motor vehicles, motor vehicle
engines, nonroad vehicles, or nonroad engines (except for ocean-going
vessels). To implement these changes, the proposed RFS2 program
eliminates the RFS1 RIN retirement requirement for renewable fuels used
in nonroad applications, with the exception of RINs associated with
renewable fuels used in ocean-going vessels.
2. Heating Oil and Jet Fuel
    EISA defined `additional renewable fuel' as ``fuel that is produced
from renewable biomass and that is used to replace or reduce the
quantity of fossil fuel present in home heating oil or jet fuel.'' \40\
While we are proposing that fossil-based heating oil and jet fuel would
not be included in the fuel used by a refiner or importer to calculate
their RVO, we are proposing that renewable fuels used as or in heating
oil and jet fuel may generate RINs for credit purposes. Thus, the RINs
of a renewable fuel, such as biodiesel, that is blended into heating
oil continue to be valid. See also discussion in Section III.B.1.e.
---------------------------------------------------------------------------

    \40\ EISA, Title II, Subtitle A-Renewable Fuel Standard, Section 201.
---------------------------------------------------------------------------

3. Exporters
    Under RFS1, exporters are assigned an RVO representing the volume
of renewable fuel that has been exported, and they are required to
separate all RINs that have been assigned to fuel that is exported.
Since there is only one standard, there is only one possible RVO
applicable to exporters.
    Under RFS2, there are four possible RVOs corresponding to the four
categories of renewable fuel (cellulosic biofuel, biomass-based diesel,
advanced biofuel, total renewable fuel). However, given the fungible
nature of the RIN system and the fact that an assigned RIN transferred
with a volume of renewable fuel may not be the same RIN that was
originally generated to represent that volume, there is no way for an
exporter to determine from an assigned RIN which of the four categories
applies to

[[Page 24965]]

an exported volume. In order to determine its RVOs, the only
information available to the exporter is the type of renewable fuel
that he is exporting.
    For RFS2, we are proposing that exporters use the fuel type and its
associated volume to determine his applicable RVO. To accomplish this,
an exporter must know which of the four renewable fuel categories
applies to a given type of renewable fuel. We are proposing that all
biodiesel (mono alkyl esters) and renewable diesel would be categorized
as biomass-based diesel (D code of 4), and that exported volumes of
these two fuels would be used to determine the exporter's RVO for
biomass-based diesel. For all other types of renewable fuel, the most
likely category for most of the phase-in period of the RFS2 program is
general renewable fuel, and as a result we propose that all other types
of renewable fuel be used to determine the exporter's RVO for total
renewable fuel. Our proposed approach is provided at Sec.  80.1430. We
recognize that by 2022 the required volume of cellulosic biofuel will
exceed the required volume of general renewable fuel that is in excess
of the advanced biofuel requirements. Thus we request comment on
requiring all or some portion of renewable fuels other than biodiesel
and renewable diesel to be categorized as cellulosic biofuel in 2022 and beyond.
    An alternative approach could be required that would more closely
estimate the amount of exported renewable fuels that fall into the four
categories defined by EISA. In this alternative, the total nationwide
volumes required in each year (see Table II.A.1-1) would be used to
apportion specific types of renewable fuel into each of the four
categories. For example, exported ethanol may have originally been
produced from cellulose to meet the cellulosic biofuel requirement,
from corn to meet the total renewable fuel requirement, or may have
been imported as advanced biofuel. If ethanol were exported, we could
divide the exported volume into three RVOs for cellulosic biofuel,
advanced biofuel, and total renewable fuel using the same proportions
represented by the national volume requirements for that year. However,
we believe that this alternative approach would add considerable
complexity to the compliance determinations for exporters without
necessarily adding more precision. Given the expected small volumes of
exported renewable fuel, this added complexity does not seem warranted
at this time. Nevertheless, we request comment on it.
4. Alternative Approaches to RIN Transfers
    In the NPRM for the RFS1 rulemaking, we presented a variety of
approaches to the transfer of RINs, ultimately requiring that RINs
generated by renewable fuel producers and importers must be assigned to
batches of renewable fuel and transfered along with those batches.
However, given the higher volumes required under RFS2 and the resulting
expansion in the number of regulated parties, we believe that two of
the alternative approaches to RIN transfers should be considered for
RFS2. Our proposal for an EPA-moderated RIN trading system (EMTS) may
also support the implementation of one of these approaches.
    In one of the alternative approaches, we would entirely remove the
restriction established under the RFS1 rule requiring that RINs be
assigned to batches of renewable fuel and transferred with those
batches. Instead, renewable fuel producers could sell RINs (with a K
code of 2 rather than 1) separately from volumes of renewable fuel to
any party. This approach could significantly streamline the tracking
and trading of RINs. For instance, there would no longer be a need for
K-codes and restrictions on separation of RINs, there would only be a
single RIN market rather than two (one for RINs assigned to volume and
another for separated RINs), there would be no need for volume/RIN
balance calculations at the end of each quarter, and there would be no
need for restrictions on the number of RINs that can be transfered with
each gallon of renewable fuel. As described more fully in Section
III.B.4.b.ii, this approach could also provide a greater incentive for
producers to demonstrate that the renewable biomass definition has been
met for their feedstocks. As discussed in Section III.G.4, this approch
could help level the playing field among obligated parties for access
to RINs regardless of whether they market a substantial volume of
gasoline or not. However, as discussed in the RFS1 rulemaking, this
approach could also place obligated parties at greater risk of market
manipulation by renewable fuel producers.
    In order to address some of the concerns raised about allowing
producers and importers to separate RINs from their volume, in the NPRM
for the RFS1 rulemaking we also presented an alternative concept for
RIN distribution in which producers and importers of renewable fuels
would be required to transfer the RIN, but only to an obligated party
(see 71 FR 55591). This ''direct transfer'' approach would require
renewable fuel producers to transfer RINs with renewable fuel for all
transactions with obligated parties, and sell all other RINs directly
to obligated parties on a quarterly basis for any renewable fuel
volumes that were not sold directly to obligated parties. Only
renewable fuel producers, importers, and obligated parties would be
allowed to own RINs, and only obligated parties could take ownership of
RINs from producers and importers. This approach would spare marketers
and distributors of renewable fuel from the burdens associated with
transferring RINs with batches, and thus would eliminate the tracking,
recordkeeping and reporting requirements that would continue to be
applicable to them if RINs are transferred through the distribution
system as required under the RFS1 program.
    Under the direct transfer alternative, the renewable fuel producer
or importer would be required to transfer the RINs associated with his
renewable fuel to an obligated party who purchases the renewable fuel.
The RINs associated with any renewable fuel that is not directly
transferred to an obligated party would not be transferred with the
fuel as required under the RFS1 program. Instead, the renewable fuel
producer or importer would be required to sell the RINs directly to an
obligated party. Any RINs not sold in this way would be required to be
offered for sale to all obligated parties through a public auction.
This could be through an EPA moderated trading system, an existing
internet auction web site, or through another auction mechanism
implemented by a renewable fuel producer.
    Although we believe that the direct transfer approach has merit,
many of the concerns laid out in the RFS1 NPRM remain valid today. In
particular, the auctions would need to be regulated in some way to
ensure that RIN generators could not withhold RINs from the market by
such means as failing to adequately advertise the time and location of
an auction, by setting the selling price too high, by specifying a
minimum number of bids before selling, by conducting auctions
infrequently, by having unduly short bidding windows, etc. We seek
comment on how we could regulate such auctions to ensure that obligated
parties could acquire sufficient RINs for compliance purposes in a
timely manner.
    Our proposed EPA-moderated RIN trading system (see Section IV.E)
could help to make the direct transfer approach feasible. By creating accounts

[[Page 24966]]

in a centralized system within which all RIN transfers between parties
would be made, it may be more straightforward for obligated parties to
identify available RINs owned by producers and importers, and to bid on
those RINs. Therefore, while we are not proposing the direct transfer
approach in today's action, we nevertheless request comment on it.
5. Neat Renewable Fuel and Renewable Fuel Blends Designated as
Transportation Fuel, Home Heating Oil, or Jet Fuel
    Under RFS1, RINs must, with limited exceptions, be separated by an
obligated party taking ownership of the renewable fuel, or by a party
that blends renewable fuel with gasoline or diesel. In addition, a
party that designates neat renewable fuel as motor vehicle fuel may
separate RINs associated with that fuel if the fuel is in fact used in
that manner without further blending. For purposes of the RFS program,
``neat renewable fuel'' is defined in 80.1101(p) as ``a renewable fuel
to which only de minimis amounts of conventional gasoline or diesel
have been added.'' One exception to these provisions is that biodiesel
blends in which diesel constitutes less than 20 volume percent are
ineligible for RIN separation by a blender. As noted in the preamble to
the final RFS1 regulations, EPA understands that in the vast majority
of cases, biodiesel is blended with diesel in concentrations of 80
volume percent or less.
    However, in order to account for situations in which biodiesel
blends of 81 percent or greater may be used as motor vehicle fuel
without ever having been owned by an obligated party, EPA is proposing
to change the applicability of the RIN separation provisions for RFS2.
EPA is proposing that 80.1429(b)(4) allow for separation of RINs for
neat renewable fuel or blends of renewable fuel and or diesel fuel that
the party designates as transportation fuel, home heating oil, or jet
fuel, provided the neat renewable fuel or blend is used in the
designated form, without further blending, as transportation fuel, home
heating oil, or jet fuel. As in RFS1, those parties that blend
renewable fuel with gasoline or diesel fuel (in a blend containing less
than 80 percent biodiesel would in all cases be required to separate
RINs pursuant 80.1429(b)(2).
    Thus, for example, under these proposed regulations, if a party
intends to separate RINs from a volume of B85, the party must designate
the blend for use as transportation fuel, home heating oil, or jet fuel
and the blend must be used in its designated form without further
blending. The party would also be required maintain records of this
designation pursuant to 80.1451(b)(5). Finally, the party would be
required to comply with the proposed PTD requirements in
80.1453(a)(5)(iv), which serve to notify downstream parties that the
volume of fuel has been designated for use as transportation fuel, home
heating oil, or jet fuel, and must be used in that designated form
without further blending. Parties could separate RINs at the time they
complied with the designation and PTD requirements, and would not need
to physically track ultimate fuel use.
    EPA requests comment on this proposed approach to RIN separation.
Additionally, EPA requests comment on an alternative approach to
modifying the current program for separation of RINs. Under this second
approach, 80.1429(b)(2) and (b)(5)would be eliminated as redundant, and
80.1429(b)(4) would be broadened to require separation of RINs for all
neat renewable fuels and all blends of renewable fuels with either
gasoline or diesel, when a party designates such fuel as transportation
fuel, home heating oil or jet fuel, and the fuel is in fact used in
accordance with that designation without further blending. The party
would be required to maintain records that verify the ultimate use of
the fuel as transportation, home heating, or jet fuel. Additionally,
there would be a PTD requirement to inform downstream parties that the
fuel has been designated as transportation, home heating, or jet fuel
and may not be further blended. This proposed approach would eliminate
the need for parties to distinguish for purposes of separating RINs
between fuels that are neat or blended or, for biodiesel, between
blends of E80 and below or E81 and above.

I. Treatment of Cellulosic Biofuel

1. Cellulosic Biofuel Standard
    EISA requires in section 202(e) that the Administrator set the
cellulosic biofuel standard each November for the next year based on
the lesser of the volume specified in the Act or the projected volume
of cellulosic biofuel production for that year. In the event that the
projected volume is less than the amount required in the Act, EPA may
also reduce the applicable volume of the advanced biofuels requirement
by the same or a lesser volume. We intend to examine EIA's projected
volumes and other available data including the production outlook
reports proposed in Section III.K to be submitted to the EPA to decide
the appropriate standard for the following year. The outlook reports
from all renewable fuel producers would assist EPA in determining what
the cellulosic biofuel standard should be and if the advanced biofuel
standard should be adjusted. For years where EPA determines that the
projected volume of cellulosic biofuels is not sufficient to meet the
levels in EISA we will consider the availability of other advanced
biofuels in deciding whether to lower the advanced biofuel standard as well.
2. EPA Cellulosic Allowances for Cellulosic Biofuel
    Whenever EPA sets the cellulosic biofuel standard at a level lower
than that required in EISA, EPA is required to provide a number of
cellulosic credits for sale that is no more than the volume used to set
the standard. Congress also specified the price for such credits:
adjusted for inflation, they must be offered at the price of the higher
of 25 cents per gallon or the amount by which $3.00 per gallon exceeds
the average wholesale price of a gallon of gasoline in the United
States. The inflation adjustment will be for years after 2008. We
propose that the inflation adjustment would be based on the Consumer
Price Index for All Urban Consumers (CPI-U) for All Items expenditure
category as provided by the Bureau of Labor Statistics.\41\
---------------------------------------------------------------------------

    \41\ See U.S. Department of Labor, Bureau of Labor Statistics
(BLS), Consumer Price Index Web site at: http://www.bls.gov/cpi/.
---------------------------------------------------------------------------

    Congress afforded the Agency considerable flexibility in
implementing the system of cellulosic biofuel credits. EISA states EPA;
``shall include such provisions, including limiting the credits' uses
and useful life, as the Administrator deems appropriate to assist
market liquidity and transparency, to provide appropriate certainty for
regulated entities and renewable fuel producers, and to limit any
potential misuse of cellulosic biofuel credits to reduce the use of
other renewable fuels, and for such other purposes as the Administrator
determines will help achieve the goals of this subsection.''
    Though EISA gives EPA broad flexibility, we believe the best way to
accomplish the goals of providing certainty to both the cellulosic
biofuel industry and the obligated parties is to propose credits with
few degrees of freedom. We believe this would prevent speculation in
the market and provide certainty for investments in real cellulosic biofuels.
    Specifically, we propose that the credits would be called allowances so

[[Page 24967]]

that there is no confusion with RINs, such allowances would only be
available for the current compliance year for which we have waived some
portion of the cellulosic biofuel standard, they would only be
available to obligated parties, and they would be nontransferable and
nonrefundable. Further, we propose that obligated parties would only be
able to purchase allowances up to the level of their cellulosic biofuel
RVO less the number of cellulosic biofuel RINs that they own. This
would help ensure that every party that needs to meet the cellulosic
biofuel standard will have equal access to the allowances. A company
would also then only use an allowance to meet its total renewable and
advanced biofuel standards if it used the allowance for the cellulosic
biofuel standard. We believe that if a company can only purchase as
many allowances as it needs to meet its cellulosic biofuel obligation,
it can not hinder another obligated party from meeting the standard and
therefore every company that needs to meet the standard will have equal
access to the allowances in the event that they do not acquire
sufficient cellulosic biofuel RINs. If we were to allow a company to
purchase more allowances than they needed, another company may not be
able to meet the standard which we believe was not the intent of Congress.
    We also propose that these allowances would be offered in a generic
format rather than a serialized format, like RINs. Allowances would be
purchased from the EPA at the time that an obligated party submits its
annual compliance demonstration to the EPA and establishes that it owns
insufficient cellulosic biofuel RINs to meet its cellulosic biofuel
RVO. A company owning cellulosic biofuel RINs and cellulosic allowances
may use both types of credits if desired to meet their RVOs, but unlike
RINs they would not be able to carry allowances over to the next calendar year.
    Congress refers to allowances as ``cellulosic biofuel credits,''
with no indication that the ``credits'' should be given any less role
in meeting a party's obligations under the CAA section 211(o) than
would the purchase and use of a cellulosic biofuel RIN that reflects
actual production and use of cellulosic biofuel. Because cellulosic
biofuel RINs can be used to meet the advanced biofuel and total
renewable fuel standards in addition to the cellulosic biofuel
standard, we propose that cellulosic biofuel allowances also be
available for use in meeting those three standards.
    We propose that the wholesale price of gasoline will be based on
the average monthly bulk (refinery gate) price of gasoline using data
from the most recent twelve months of data from EIA's annual cellulosic
ethanol forecast each October.\42\ Thus we will set the allowance price
for the following year each November along with the cellulosic biofuel
standard for the following year. We seek comment on using the average
monthly rack (terminal) price for the same period and changing the
allowance price as often as quarterly. Though EISA allows EPA to change
the price as often as quarterly we believe this will lead to
speculation which may introduce more uncertainty for the obligated
parties and the cellulosic biofuel industry.
---------------------------------------------------------------------------

    \42\ More information on wholesale gasoline prices can be found
on the Department of Energy's (DOE), Energy Information
Administration's (EIA) Web site at: http://tonto.eia.doe.gov/dnav/
pet/pet_pri_allmg_d_nus_PBS_cpgal_m.htm.
---------------------------------------------------------------------------

3. Potential Adverse Impacts of Allowances
    While the credit provisions of section 202(e) of EISA ensure that
there is a predictable upper limit to the price that cellulosic biofuel
producers can charge for a gallon of cellulosic biofuel and its
assigned RIN, there may be circumstances in which this provision has
other unintended impacts. For instance, if we made all cellulosic
allowances available to any obligated party, one obligated party could
purchase more allowances than he needs to meet his cellulosic biofuel
RVO and then sell the remaining allowances at an inflated price to
other obligated parties. Thus, we are proposing that each obligated
party could only purchase allowances from the EPA up to the level of
their cellulosic biofuel RVO. However, even with this restriction an
obligated party could still purchase both cellulosic biofuel volume
with its assigned RINs sufficient to meet its cellulosic biofuel RVO,
and also purchase allowances from the EPA. In this case, the obligated
party would effectively be using allowances as a replacement for corn
ethanol rather than cellulosic biofuel. To prevent this, we are
proposing an additional restriction: an obligated party could only
purchase allowances from the EPA to the degree that it establishes it
owns insufficient cellulosic biofuel RINs to meet its cellulosic
biofuel RVO. This approach forces obligated parties to apply all their
cellulosic biofuel RINs to their cellulosic biofuel RVO before appying
any allowances to their cellulosic biofuel RVO.
    However, even with these proposed restrictions on the purchase and
application of allowances, the statutory provision may not operate as
intended. For instance, if the combination of cellulosic biofuel volume
price and RIN price is low compared to that for corn-ethanol, a small
number of obligated parties could purchase more cellulosic biofuel than
they need to meet their cellulosic biofuel RVOs and could use the
additional cellulosic biofuel RINs to meet their advanced biofuel and
total renewable fuel RVOs. Other obligated parties would then have no
access to cellulosic biofuel volume nor cellulosic biofuel RINs, and
would be forced to purchase allowances from the EPA. This situation
would have the net effect of allowances replacing imported sugarcane
ethanol and/or corn-ethanol rather than cellulosic biofuel.
    Moreover, under certain conditions it may be possible for the
market price of corn-ethanol RINs to be significantly higher than the
market price of cellulosic biofuel RINs, as the latter is limited in
the market by the price of EPA-generated allowances according to the
statutory formula described in Section III.I.2 above. Under some
conditions, this could result in a competitive disadvantage for
cellulosic biofuel in comparison to corn ethanol. For instance, if
gasoline prices at the pump are significantly higher than ethanol
production costs, while at the same time corn-ethanol production costs
are lower than cellulosic ethanol production costs, profit margins for
corn-ethanol producers would be larger than for cellulosic ethanol
producers. Under these conditions, while obligated parties may still
purchase cellulosic ethanol volume and its associated RIN rather than
allowances, cellulosic ethanol producers would realize lower profits
than corn-ethanol producers due to the upper limit placed on the price
of cellulosic biofuel RINs through the pricing formula for allowances.
For a newly forming and growing cellulosic biofuel industry, this
competitive disadvantage could make it more difficult for investors to
secure funding for new projects, threatening the ability of the
industry to reach the statutorily mandated volumes.
    We have not established the likelihood that these circumstances
would arise in practice, and we request comment on the specific market
conditions that could lead to them. Nevertheless, we have explored a
variety of ways that we could modify the RFS program structure to
mitigate these potential negative outcomes. For instance, as mentioned
in Section III.I.2 above, we are proposing that each

[[Page 24968]]

cellulosic allowance could be used to meet an obligated party's RVOs
for cellulosic biofuel, advanced biofuel, and total renewable fuel.
However, we could restrict the applicability of allowances to only the
cellulosic biofuel RVO. This approach could help ensure that demand for
imported sugarcane ethanol and corn ethanol does not fall in the event
that a small number of obligated parties purchase all available
cellulosic biofuel volume, compelling the remaining obligated parties
to purchase allowances. However, this approach could also have the
effect of making the advanced biofuel and total renewable fuel
standards more stringent. This could occur as obligated parties are
forced to buy additional imported sugarcane ethanol and corn ethanol to
make up for the fact that the allowances they purchase from the EPA
would not apply to the advanced biofuel and total renewable fuel standards.
    As a variation to this approach, while still restricting the
applicability of allowances to only the cellulosic biofuel RVO, we
could similarly make cellulosic biofuel RINs applicable to only the
cellulosic biofuel RVO. This approach would ensure that the compliance
value of both cellulosic biofuel RINs and allowances is the same, but
would necessarily result in an increase in the effective stringency of
the advanced biofuel and total renewable fuel standards.
    Finally, we could institute a ``dual RIN'' approach to cellulosic
biofuel that has the potential to address some of the shortcomings of
the previous approaches. In this approach, both cellulosic biofuel RINs
(with a D code of 1) and allowances could only be applied to an
obligated party's cellulosic biofuel RVO, but producers of cellulosic
biofuel would also generate an additional RIN representing advanced
biofuel (with a D code of 3). The producer would only be required to
transfer the advanced biofuel RIN with a batch of cellulosic biofuel,
and could retain the cellulosic biofuel RIN for separate sale to any
party.\43\ The cellulosic biofuel and its attached advanced biofuel RIN
would then compete directly with other advanced biofuel and its
attached advanced biofuel RIN, while the separate cellulosic biofuel
RIN would have an independent market value that would be effectively
limited by the pricing formula for allowances as described in Section
III.I.2. However, this approach would be a more significant deviation
from the RIN generation and transfer program structure that was
developed cooperatively with stakeholders during RFS1. It would provide
cellulosic biofuel producers with significantly more control over the
sale and price of cellulosic biofuel RINs, which was one of the primary
concerns of obligated parties during the development of RFS1.
---------------------------------------------------------------------------

    \43\ The cellulosic biofuel RIN would be a separated RIN with a
K code of 2 immediately upon generation.
---------------------------------------------------------------------------

    Due to the drawbacks of each of these potential changes to the RFS
program structure, we are not proposing any of them in today's NPRM.
However, we request comment on whether any of them, or alternatives,
could address the adverse situations described above. We also request
comment on the degree to which the adverse situations are likely to
occur, and the degree of severity of the negative impacts that could result.

J. Changes to Recordkeeping and Reporting Requirements

1. Recordkeeping
    As with the existing renewable fuel standard program, recordkeeping
under this proposed program will support the enforcement of the use of
RINs for compliance purposes. As with the existing renewable fuels
program, we are proposing that parties be afforded significant freedom
with regard to the form that product transfer documents (PTDs) take. We
propose to permit the use of product codes as long as they are
understood by all parties. We propose that product codes may not be
used for transfers to truck carriers or to retailers or wholesale
purchaser-consumers. We propose that parties must keep copies of all
PTDs they generate and receive, as well as copies of all reports
submitted to EPA and all records related to the sale, purchase,
brokering or transfer or RINs, for five (5) years. We also propose that
parties must also keep copies of records that relate to flexibilities,
as described in Section IV.A. through C. of this preamble. Such
flexibilities are related to attest engagements, the upward delegation
of RIN-separating responsibilities, and various small business oriented
provisions. Upon request, parties would be responsible for providing
their records to the Administrator or the Administrator's authorized
representative. We would reserve the right to request to receive
documents in a format that we can read and use.
    In Section IV.E. of this preamble, we propose an EPA-Moderated
Trading System for RINs. If adopted, the new system would allow for
real-time reporting of RIN generation (i.e., batch reports by producers
and importers) and RIN transactions.
2. Reporting
    Under the existing renewable fuels program, obligated parties,
exporters of renewable fuel, producers and importers of renewable
fuels, and any party who owns RINs must report appropriate information
to EPA on a quarterly and/or annual basis. We are proposing a change in
the schedule for submission of producers' and importers' batch reports,
and for the submission of RIN transaction reports. This proposed change
in schedule, which is discussed in great detail in Section IV.E. of
this preamble, is effective for 2010 only. We are proposing that, for
2010, these reports (which were submitted quarterly under RFS1) be
submitted monthly rather than quarterly. The reason for proposing
monthly reporting for 2010 is to minimize difficulties associated with
invalid RINs, while the EPA-Moderated Trading System is still under
development. As described in detail in IV.E. we intend to have an EPA-
Moderated Trading System fully operational by 2011. At the time that
system becomes fully operational, all batch and RIN transactional
reporting would be submitted in real time. The following deadlines
would apply to ``real time,' monthly, quarterly, and annual reports.
    ``Real time'' reports within the EPA-Moderating Trading System
would be submitted within three (3) business days of a reportable event
(e.g. generation of a RIN, a transaction occurring involving a RIN).
Real time reporting would apply to batch reports submitted by producers
and importers who generate RINs and to to RIN transaction reports
submitted in 2011 and future years.
    Monthly reports would be submitted according to the following schedule:

               Table III.J.2-1--Monthly Reporting Schedule
------------------------------------------------------------------------
         Month covered by  report                Due date for report
------------------------------------------------------------------------
January...................................  February 28.
February..................................  March 31.
March.....................................  April 30.
April.....................................  May 31.
May.......................................  June 30.
June......................................  July 31.
July......................................  August 31.
August....................................  September 30.
September.................................  October 31.
October...................................  November 30.
November..................................  December 31.
December..................................  January 31.
------------------------------------------------------------------------

    The monthly reporting schedule would apply to batch reports
submitted by producers and importers who generate RINs and to RIN
transaction reports submitted for 2010 only.

[[Page 24969]]

    Quarterly reports would be submitted on the following schedule:

              Table III.J.-2--Quarterly Reporting Schedule
------------------------------------------------------------------------
        Quarter covered by  report              Due date for  report
------------------------------------------------------------------------
January-March.............................  May 31.
April-June................................  August 31.
July-September............................  November 30.
October-December..........................  February 28.
------------------------------------------------------------------------

    Quarterly reports include summary reports related to RIN
activities.
    Annual reports (covering January through December) would continue
to be due on February 28. Annual reports include compliance
demonstrations by obligated parties.
    Under this proposed rule, the universe of reporting parties would
grow, but we propose similar reporting to existing reporting. We
believe that the proposed EPA-Moderating Trading System will make
reporting easier for most parties. Existing reporting forms and
instructions are posted at http://www.epa.gov/otaq/regs/fuels/
rfsforms.htm. You may wish to refer to these existing forms in
preparing your comments on this proposal.
    Simplified, secure reporting is currently available through our
Central Data Exchange (CDX). CDX permits us to accept reports that are
electronically signed and certified by the submitter in a secure and
robustly encrypted fashion. Using CDX eliminates the need for wet ink
signatures and reduces the reporting burden on regulated parties. It is
our intention to continue to encourage the use of CDX for reporting
under this proposed program as well.
    Due to the criteria that renewable fuel producers and importers
must meet in order to generate RINs under RFS2, and due to the fact
that renewable fuel producers and importers must have documentation
about whether their feedstock(s) meets the definition of ``renewable
biomass,'' we propose several changes to the RFS1 RIN generation
report. We propose to make the report a more general report on
renewable fuel production in order to capture information on all
batches of renewable fuel, whether or not RINs are generated for them.
All renewable fuel producers and importers above 10,000 gallons per
year would report to EPA on each batch of their fuel and indicate
whether or not RINs are generated for the batch. If RINs are generated,
the producer or importer would be required to certify that his
feedstock meets the definition of ``renewable biomass.'' If RINs are
not generated, the producer or importer would be required to state the
reason for not generating RINs, such as they have documentation that
states that their feedstock did not meet the definition of ``renewable
biomass,'' or the fuel pathway used to produce the fuel was such that
the fuel did not qualify for any D code (see Section III.B.4.b for a
discussion about demonstrating whether or not feedstock meets the
definition of ``renewable biomass''). For each batch of renewable fuel
produced, we also propose to require information about the types and
volumes of feedstock used and the types and volumes of co-products
produced, as well as information about the process or processes used.
This information is necessary to confirm that the producer or importer
assigned the appropriate D code to their fuel and that the D code was
consistent with their registration information.
    Two minor additions are being incorporated into the RIN transaction
report. First, for reports of RINs assigned to a volume of renewable
fuel, we are asking that the volume of renewable fuel be reported.
Additionally, we propose that RIN price information be submitted for
transactions involving both separated RINs and RINs assigned to a
renewable volume. This information is not collected under RFS1, but we
believe this information has great programmatic value to EPA because it
may help us to anticipate and appropriately react to market disruptions
and other compliance challenges, will be beneficial when setting future
renewable standards, and will provide additional insight into the
market when assessing potential waivers. We anticipate that having
current market information such as total number of RINs produced and
RINs available in the separated market is incomplete. Missing is our
ability to assess the general health and direction of the market and
overall liquidity of RINs. Tracking price trend information will allow
us to identify market inefficiencies and perceptions of RIN supply.
When price information is combined with information from the production
outlook reports, we will be better able to judge realistic expectations
of renewable production and be in a better position when setting and
justifying future renewable standards or pursuing relief through waiver
provisions. Also, we believe the addition of price information will be
highly beneficial to regulated parties. With price information being
noted on transaction reports, buyers and sellers will have an
additional and immediate reference when confirming transactions.
Additionally, we believe that highly summarized price information
(e.g., the average price of RINs traded) should be available to
regulated parties, as well, and may help them to anticipate and avoid
market disruptions.
    We also propose to make minor changes to compliance reports related
to the identification of types of RINs. Please refer to Section III.B.
of this preamble for a discussion of types of renewable fuels. Also,
please refer to Section III.A. for a discussion of proposed changes to RINs.
    Under our proposed EPA-Moderated Trading System described in
Section IV.E. of this preamble, then there would be a change in
reporting burden on regulated parties that affects the frequency of
reporting and the number of reports. Instead of quarterly and/or annual
contact with EPA, there would be real time contact--i.e., as batches of
renewable fuel are generated or as RINs are transacted. However, we
believe that any burden is offset by the advantage of having a
simplified system for RIN management that will promote the integrity of
RINs and will remove ``guesswork'' now associated with RIN management.
As things are now, a regulated party may experience frustration and
incur expense in trying to track down and correct errors. Once an error
is made, it propagates throughout the distribution system with each
transfer from party to party. By having EPA moderate RIN management, we
believe that errors would be minimized and regulated parties would be
freed of the greater burden to attempt to track down and correct errors
they may have made. Implementation of the EPA-Moderated Trading System
would correspond to real-time reporting of the type of information
contained in the following two quarterly reports: The Renewable Fuel
Production Report, known as the RIN Generation Report or ``batch
report'' under RFS1 (Report Form Template RFS0400), and the RIN
Transaction Report (Report Form Template RFS0200), starting in 2011.
For 2010, we are proposing that the type of information contained in
these two forms be submitted monthly. These and other reports and
instructions related to the existing renewable fuel standard program
(RFS1) are posted at http://www.epa.gov/otaq/regs/fuels/rfsforms.htm.
3. Additional Requirements for Producers of Renewable Natural Gas,
Electricity, and Propane
    In addition to the general reporting requirement listed above, we
are proposing an additional item of reporting for producers of renewable

[[Page 24970]]

natural gas, electricity, and propane who choose to generate and assign
RINs. While producers of renewable natural gas, electricity, and
propane who generate and assign RINs would be responsible for filing
the same reports as other producers of RIN-generating renewable fuels,
we propose that additional reporting for these producers be required to
support the actual use of their products in the transportation sector.
We believe that one simple way to achieve this may be to add a
requirement that producers of renewable natural gas, electricity, and
propane add the name of the purchaser (e.g., the name of the wholesale
purchaser-consumer (WPC) or fleet) to their quarterly RIN generation
reports and then maintain appropriate records that further identify the
purchaser and the details of the transaction. We are not proposing that
a purchaser who is either a WPC or an end user would have to register
under this scenario, unless that party engages in other activities
requiring registration under this program.

K. Production Outlook Reports

    We are also proposing additional reporting--annual production
outlook reports that would be required of all domestic renewable fuel
producers, foreign renewable fuel producers who register to generate
RINs, and importers of covered renewable fuels starting in 2010. These
production outlook reports would be similar to the pre-compliance
reports required under the Highway and Nonroad Diesel programs. These
reports would contain information about existing and planned production
capacity, long-range plans, and feedstocks and production processes to
be used at each production facility. For expanded production capacity
that is planned or underway at each existing facility, or new
production facilities that are planned or underway, the progress
reports would require information on: (1) Strategic planning; (2)
Planning and front-end engineering; (3) Detailed engineering and
permitting; (4) Procurement and Construction; and (5) Commissioning and
startup. These five project phases are described in EPA's June 2002
Highway Diesel Progress Review report (EPA document number EPA420-R-02-
016, located at: www.epa.gov/otaq/regs/hd2007/420r02016.pdf).
    The full list of requirements for the proposed production outlook
reports is provided in the proposed regulations at Sec.  80.1449. The
information submitted in the reports would be used to evaluate the
progress that the industry is making towards the renewable fuels volume
goals mandated by EISA and to set the annual cellulosic biofuel,
advanced biofuel, biomass-based diesel, and total renewable fuel
standards (see Section II.A.7 of this preamble). We are proposing that
the annual production outlook reports be due annually by February 28,
beginning in 2010 and continuing through 2022, and we are proposing
that each annual report must provide projected information through
calendar year 2022.
    EPA currently receives data on projected flexible-fuel vehicle
(FFV) sales and conversions from vehicle manufacturers; however, we do
not have information on renewable fuels in the distribution system.
Thus, EPA is also considering whether to require the annual submission
of data to facilitate our evaluation of the ability of the distribution
system to deliver the projected volumes of biofuels to petroleum
terminals that are needed to meet the RFS2 standards. We request
comment on the extent to which such information is already publicly
available or can be purchased from a proprietary source. We further
request comment on the extent to which such publicly available or
purchasable data would be sufficient for EPA to make its determination.
To the extent that additional data might be needed, we request comment
on the parties that should be required to report to EPA and what data
should be required. For example, would it be appropriate to require
terminal operators to report to EPA annually on their ability to
receive, store, and blend biofuels into petroleum-based fuels? We
believe that publicly available information on E85 refueling facilities
is sufficient for us to make a determination about the adequacy of such
facilities to support the projected volumes of E85 that would be used
to satisfy the RFS2 standards.
    We request comment on the proposed requirement of annual production
outlook reports, and all other aspects mentioned above (e.g., reporting
requirements, reporting dates, etc.).

L. What Acts Are Prohibited and Who Is Liable for Violations?

    The prohibition and liability provisions applicable to the proposed
RFS2 program would be similar to those of the RFS1 program and other
gasoline programs. The proposed rule identifies certain prohibited
acts, such as a failure to acquire sufficient RINs to meet a party's
RVOs, producing or importing a renewable fuel that is not assigned a
proper RIN category (or D Code), improperly assigning RINs to renewable
fuel that was not produced with renewable biomass, failing to assign
RINs to qualifying fuel, or creating or transferring invalid RINs. Any
person subject to a prohibition would be held liable for violating that
prohibition. Thus, for example, an obligated party would be liable if
the party failed to acquire sufficient RINs to meet its RVO. A party
who produces or imports renewable fuels would be liable for a failure
to assign proper RINs to qualifying batches of renewable fuel produced
or imported. Any party, including an obligated party, would be liable
for transferring a RIN that was not properly identified.
    In addition, any person who is subject to an affirmative
requirement under this program would be liable for a failure to comply
with the requirement. For example, an obligated party would be liable
for a failure to comply with the annual compliance reporting
requirements. A renewable fuel producer or importer would be liable for
a failure to comply with the applicable batch reporting requirements.
Any party subject to recordkeeping or product transfer document (PTD)
requirements would be liable for a failure to comply with these
requirements. Like other EPA fuels programs, the proposed rule provides
that a party who causes another party to violate a prohibition or fail
to comply with a requirement may be found liable for the violation.
    EPAct amended the penalty and injunction provisions in section
211(d) of the Clean Air Act to apply to violations of the renewable
fuels requirements in section 211(o). Accordingly, under the proposed
rule, any person who violates any prohibition or requirement of the
RFS2 program may be subject to civil penalties of $32,500 for every day
of each such violation and the amount of economic benefit or savings
resulting from the violation. Under the proposed rule, a failure to
acquire sufficient RINs to meet a party's renewable fuels obligation
would constitute a separate day of violation for each day the violation
occurred during the annual averaging period.
    As discussed above, the regulations would prohibit any party from
creating or transferring invalid RINs. These invalid RIN provisions
apply regardless of the good faith belief of a party that the RINs are
valid. These enforcement provisions are necessary to ensure the RFS2
program goals are not compromised by illegal conduct in the creation
and transfer of RINs.
    As in other motor vehicle fuel credit programs, the regulations
would address the consequences if an obligated party was found to have
used invalid RINs to demonstrate compliance with its RVO.

[[Page 24971]]

In this situation, the obligated party that used the invalid RINs would
be required to deduct any invalid RINs from its compliance
calculations. Obligated parties would be liable for violating the
standard if the remaining number of valid RINs was insufficient to meet
its RVO, and the obligated party might be subject to monetary penalties
if it used invalid RINs in its compliance demonstration. In determining
what penalty is appropriate, if any, we would consider a number of
factors, including whether the obligated party did in fact procure
sufficient valid RINs to cover the deficit created by the invalid RINs,
and whether the purchaser was indeed a good faith purchaser based on an
investigation of the RIN transfer. A penalty might include both the
economic benefit of using invalid RINs and/or a gravity component.
    Although an obligated party would be liable under our proposed
program for a violation if it used invalid RINs for compliance
purposes, we would normally look first to the generator or seller of
the invalid RINs both for payment of penalty and to procure sufficient
valid RINs to offset the invalid RINs. However, if, for example, that
party was out of business, then attention would turn to the obligated
party who would have to obtain sufficient valid RINs to offset the invalid RINs.
    We request comment on the need for additional prohibition and
liability provisions specific to the proposed RFS 2 program.

IV. What Other Program Changes Have We Considered?

    In addition to the regulatory changes we are proposing today in
response to EISA that are designed to implement the provisions of RFS2,
there are a number of other changes to the RFS program that we are
considering. These changes would be designed to increase flexibility,
simplify compliance, or address RIN transfer issues that have arisen
since the start of the RFS1 program. We have also investigated impacts
on small businesses and are proposing approaches designed to address
the impacts of the program on them.

A. Attest Engagements

    The purpose of an attest engagement is to receive third party
verification of information reported to EPA. An attest engagement,
which is similar to a financial audit, is conducted by a Certified
Public Accountant (CPA) or Certified Independent Auditor (CIA)
following agreed-upon procedures. Under the RFS1 program, an attest
engagement must be conducted annually. We propose to apply the same
provision to this proposed RFS2 rule. However, we seek comment on
whether there should be any flexibility provisions for those who own a
small number of RINs and what level of flexibility might be appropriate
(e.g., allowing those who own a small number of RINs to submit an
attest engagement every two years, rather than every year).

B. Small Refinery and Small Refiner Flexibilities

1. Small Refinery Temporary Exemption
    CAA section 211(o)(8), enacted as part of EPAct, provides a
temporary exemption to small refineries (those refineries with a crude
throughput of no more than 75,000 barrels of crude per day, as defined
in section 211(o)(1)(K)) through December 31, 2010.\44\ Accordingly,
the RFS1 program regulations exempt gasoline produced by small
refineries from the renewable fuels standard (unless the exemption was
waived), see 40 CFR 80.1141. EISA did not alter the small refinery
exemption in any way. Therefore, we intend to retain this small
refinery temporary exemption in the RFS2 program without change.
Further, as discussed below in Section IV.B.2.c, we are proposing to
continue one of the hardship provisions for small refineries provided
at 40 CFR 80.1141(e).
---------------------------------------------------------------------------

    \44\ Small refineries are also allowed to waive this exemption.
---------------------------------------------------------------------------

2. Small Refiner Flexibilities
    As mentioned above, EPAct granted a temporary exemption from the
RFS program to small refineries through December 31, 2010. In the RFS1
final rule, we exercised our discretion under section 211(o)(3)(B) and
extended this temporary exemption to the few remaining small refiners
that met the Small Business Administration's (SBA) definition of a
small business (1,500 employees or less company-wide) but did not meet
the Congressional small refinery definition as noted above.
    As explained in the discussion of our compliance with the
Regulatory Flexibility Act below in Section XII.C and in the Initial
Regulatory Flexibility Analysis in Chapter 7 of the draft RIA, we
considered the impacts of today's proposed regulations on small
businesses. Most of our analysis of small business impacts was
performed as a part of the work of the Small Business Advocacy Review
Panel (SBAR Panel, or ``the Panel'') convened by EPA, pursuant to the
Regulatory Flexibility Act as amended by the Small Business Regulatory
Enforcement Fairness Act of 1996 (SBREFA). The Final Report of the
Panel is available in the docket for this proposed rule. For the SBREFA
process, we conducted outreach, fact-finding, and analysis of the
potential impacts of our regulations on small businesses.
    During the SBREFA process, small refiners informed us that they
would need to rely heavily on RINs and/or make capital improvements to
comply with the RFS2 requirements. These refiners raised concerns about
the RIN program itself, uncertainty (with the required renewable fuel
volumes, RIN availability, and cost), and the desire for a RIN system
review access to RINs, and the difficulty in raising capital and
competing for engineering resources to make capital improvements.
    During the Panel process, EPA raised a concern regarding provisions
for small refiners in the RFS2 rule; and this rule presents a very
different issue than the small refinery versus small refiner concept
from RFS1. This issue deals with whether or not EPA has the authority
to provide a subset of small refineries (those that are operated by
small refiners) with an extension of time that would be different from,
and more than, the temporary exemption specified by Congress in section
211(o)(9) for small refineries (temporary exemption through December
31, 2010, with the potential for extensions of the exemption beyond
this date if certain criteria are met.). In other words, the temporary
exemption specified by Congress provided relief for those small
refiners that are covered by the small refinery provision; EPA believes
that providing these refiners with an additional exemption different
from that provided by section 211(o)(9) may be inconsistent with the
intent of Congress. Congress spoke directly to the relief that EPA may
provide for small refineries, including those small refineries operated
by small refiners, and limited it to a blanket exemption through
December 31, 2010, with additional extensions if the criteria specified
by Congress were met.
    The Panel recommended that EPA consider the issues raised by the
SERs and discussions had by the Panel itself, and that EPA should
consider comments on flexibility alternatives that would help to
mitigate negative impacts on small businesses to the extent allowable
by the Clean Air Act. A summary of further recommendations of the Panel
are discussed in Section XII.C of this preamble, and a full discussion
of the regulatory alternatives discussed and recommended by the Panel
can be found in the SBREFA Final Panel Report.

[[Page 24972]]

a. Extension of Existing RFS1 Temporary Exemption
    As previously stated, the RFS1 program regulations provide small
refiners who operate small refineries, as well as those small refiners
who do not operate small refineries, with a temporary exemption from
the standards through December 31, 2010. Small refiner SERs suggested
that an additional temporary exemption for the RFS2 program would be
beneficial to them in meeting the RFS2 standards; and the Panel
recommended that EPA propose a delay in the effective date of the
standards until 2014 for small entities, to the maximum extent allowed
by the statute.
    We have evaluated an additional temporary exemption for small
refiners for the required RFS2 standards, and we have also evaluated
such an exemption with respect to our concerns about our authority to
provide an extension of the temporary exemption for small refineries
that is different from that provided in CAA section 211(o)(9). As a
result, we believe that the limitations of the statute do not
necessarily allow us the discretion to provide an exemption for small
refiners only (i.e., small refiners but not small refineries) beyond
that provided in section 211(o)(9). However, it is important to
recognize that the 211(o)(9) small refinery provision does allow for
extensions beyond December 31, 2010, with two separate provisions
addressing extensions beyond 2010. These provisions are discussed below
in Section IV.B.2.c.
    Therefore, we are proposing to continue the temporary exemption
finalized in RFS1--through December 31, 2010--for small refineries and
all qualified small refiners. We also request comment on the
interpretation of our authority under the CAA and the appropriateness
of providing an extension to small refiners only beyond that authorized
by section 211(o)(9).
b. Program Review
    During the SBREFA process, the small refiner SERs also requested
that EPA perform an annual program review, to begin one year before
small refiners are required to comply with the program. We have slight
concerns that such a review could lead to some redundancy since EPA is
required to publish a notice of the applicable RFS standards in the
Federal Register annually, and this annual process will inevitably
include an evaluation of the projected availability of renewable fuels.
Nevertheless, some Panel members commented that they believe a program
review could be beneficial to small entities in providing them some
insight to the RFS program's progress and alleviate some uncertainty
regarding the RIN system. As we will be publishing a Federal Register
notice annually, the Panel recommended that we include an update of RIN
system progress (e.g., RIN trading, publicly-available information RIN
availability, etc.) in this annual notice.
    We propose to include elements of RIN system progress--such as RIN
trading and availability--in the annual Federal Register RFS2 standards
notice. We also invite comment on additional elements to include in
this review.
c. Extensions of the Temporary Exemption Based on Disproportionate
Economic Hardship
    As noted above, there are two provisions in section 211(o)(9) that
allow for an extension of the temporary exemption beyond December 31,
2010. One involves a study by the Department of Energy (DOE) concerning
whether compliance with the renewable fuel requirements would impose
disproportionate economic hardship on small refineries, and would grant
an extension of at least two years for a small refinery that DOE
determines would be subject to such disproportionate hardship. Another
provision authorizes EPA to grant an extension for a small refinery
based upon disproportionate economic hardship, on a case-by-case basis.
    We believe that these avenues of relief can and should be fully
explored by small refiners who are covered by the small refinery
provision. In addition, we believe that it is appropriate to consider
allowing petitions to EPA for an extension of the temporary exemption
based on disproportionate economic hardship for those small refiners
who are not covered by the small refinery provision (again, per our
discretion under section 211(o)(3)(B)); this would ensure that all
small refiners have the same relief available to them as small
refineries do. Thus, we are proposing a hardship provision for small
refineries in the RFS2 program, that any small refinery may apply for a
case-by-case hardship at any time on the basis of disproportionate
economic hardship per CAA section 211(o)(9)(B). While EISA stated (per
section 211(o)(9)(A)(ii)(I)) that the small refinery temporary
exemption shall be extended for at least two years for any small
refinery that the DOE small refinery study determines would face
disproportionate economic hardship in meeting the requirements of the
RFS2 program, we are not proposing this hardship provision given the
outcome of the DOE small refinery study (as discussed below).
    In the small refinery study, ``EPACT 2005 Section 1501 Small
Refineries Exemption Study'', DOE's finding was that there is no reason
to believe that any small refinery would be disproportionately harmed
by inclusion in the proposed RFS2 program. This finding was based on
the fact that there appeared to be no shortage of RINs available under
RFS1, and EISA has provided flexibility through waiver authority (per
section 211(o)(7)). Further, in the case of the cellulosic biofuel
standard, cellulosic biofuel allowances can be provided from EPA at
prices established in EISA (see proposed regulation section 80.1455).
DOE thus determined that no small refinery would be subject to
disproportionate economic hardship under the proposed RFS2 program, and
that the small refinery exemption should not be extended beyond
December 31, 2010. DOE noted in the study that, if circumstances were
to change and/or the RIN market were to become non-competitive or
illiquid, individual small refineries have the ability to petition EPA
for an extension of their small refinery exemption (as proposed at
draft regulation section 80.1441). We note that the findings of DOE's
small refinery study, and a consideration of EPA's ongoing review of
the functioning of the RIN market, could factor into the basis for
approval of such a hardship request.
    We are also proposing a case-by-case hardship provision for those
small refiners that do not operate small refineries, at draft
regulation section 80.1442(h), using our discretion under CAA section
211(o)(3)(B). This proposed provision would allow those small refiners
that do not operate small refineries to apply for the same kind of
extension as a small refinery. In evaluating applications for this
proposed hardship provision, it was recommended by the SBAR Panel that
EPA take into consideration information gathered from annual reports
and RIN system progress updates.
d. Phase-in
    The small refiner SERs suggested that a phase-in of the obligations
applicable to small refiners would be beneficial for compliance, such
that small refiners would comply by gradually meeting the standards on
an incremental basis over a period of time, after which point they
would comply fully with the RFS2 standards, however we have concerns
about our authority under the statute to allow for such a phase-in of
the standards. CAA section 211(o)(3)(B) states that the renewable fuel
obligation

[[Page 24973]]

shall ``consist of a single applicable percentage that applies to all
categories of persons specified'' as obligated parties. This kind of
phase-in approach would result in different applicable percentages
being applied to different obligated parties. Further, as discussed
above, such a phase-in approach would provide more relief to small
refineries operated by small refiners than that provided under the
small refinery provision. We do not believe that we can use our
discretion under the statute to allow for such a provision; however we
invite comment on the concept of a phase-in provision for all small refiners.
e. RIN-Related Flexibilities
    The small refiner SERs requested that the proposed rule contain
provisions for small refiners related to the RIN system, such as
flexibilities in the RIN rollover cap percentage and allowing all small
refiners to use RINs interchangeably. Currently in the RFS program, up
to 20% of a previous year's RINs may be ``rolled over'' and used for
compliance in the following year. A provision to allow for
flexibilities in the rollover cap could include a higher RIN rollover
cap for small refiners for some period of time or for at least some of
the four standards. While the rollover cap is the means through which
we are implementing the limited credit lifetime provisions in section
211(o) of the CAA, and therefore cannot simply be eliminated, the
magnitude of the cap can be modified to some extent. Thus, there could
be an opportunity to provide appropriate flexibility in this area.
However, given the results of the DOE small refinery study, we do not
believe it would be appropriate to propose a change to the RIN rollover
cap for small refiners today. However, we request comment on the
concept of increasing the RIN rollover cap percentage for small
refiners. We also request comment on an appropriate level of that
percentage. For example, would a rollover cap of 50% for small refiners
be appropriate? Or, would an intermediate value between 20% and 50%,
such as 35%, be more appropriate?
    The Panel recommended that we take comment on allowing RINs to be
used interchangeably for small refiners, but not propose this concept
because under this approach small refiners would arguably be subject to
a different applicable percentage than other obligated parties.
However, this concept fails to require the four different standards
mandated by Congress (e.g., conventional biofuel could not be used
instead of cellulosic biofuel or biomass-based diesel), and is not
consistent with section 211(o) of the Clean Air Act. Thus, we are not
proposing this provision in this action, however we invite comment on
such an approach for small refiners.

C. Other Flexibilities

1. Upward Delegation of RIN-Separating Responsibilities
    Since the start of the RFS1 program on September 1, 2007, there
have been a number of instances in which a party who receives RINs with
a volume of renewable fuel is required to either separate or retire
those RINs, but views the recordkeeping and reporting requirements
under the RFS program as an unnecessary burden. Such circumstances
typically might involve a renewable fuel blender, a party that uses
renewable fuel in its neat form, or a party that uses renewable fuel in
a non-highway application and is therefore required to retire the RINs
(under RFS1) associated with the volume. In some of these cases, the
affected party may purchase and/or use only small volumes of renewable
fuel and, absent the RFS program, would be subject to few if any other
EPA regulations governing fuels.
    This situation will become more prevalent with the RFS2 program, as
EISA added diesel fuel to the RFS program. With the RFS1 rule, small
blenders (generally farmers and other parties that use nonroad diesel
fuel) blending small amounts of biodiesel were not covered under the
rule as EPAct mandated renewable fuel blending for highway use only.
EISA mandates certain amounts of renewable fuels to be blended into
transportation fuels--which includes nonroad diesel fuel. Thus, parties
that were not regulated under the RFS1 rule who only blend a small
amount of renewable fuel (and, as mentioned above, are generally not
subject to many of the EPA fuels regulations) would now be regulated by
the program.
    Consequently, we believe it may be appropriate, and thus we are
proposing today, to permit blenders who only blend a small amount of
renewable fuel to allow the party directly upstream to separate RINs on
their behalf. Such a provision would be consistent with the fact that
the RFS1 program already allows marketers of renewable fuels to assign
more RINs to some of their sold product and no RINs to the rest of
their sold product. We believe that this provision would eliminate
undue burden on small parties who would otherwise not be regulated by
this program. We are proposing that this provision apply to small
blenders who blend and trade less than 125,000 total gallons of
renewable fuel per year. We also request comment on whether or not this
threshold is appropriate.
    We envision that such a provision would be available to any blender
who must separate RINs from a volume of renewable fuel under Sec. 
80.1429(b)(2). We also request comment on appropriate documentation to
authorize this upward delegation. This could be something such as a
document given to the supplier identifying the RIN separation that the
supplier would perform. The document could include sufficient
information to precisely identify the conditions of the authorization,
such as the volume of renewable fuel in question and the number of RINs
assigned to that volume. By necessity the document would need to be
signed by both parties, and copies retained as records by both parties,
since the supplier would then be responsible for these actions. The
supplier would then be allowed to retain ownership of RINs assigned to
a volume of renewable fuel when that volume is transferred, under the
condition that the RINs be separated or retired concurrently with the
transfer of the volume. We are proposing an annual authorization that
would apply to all volumes of renewable fuel transferred between two
parties for a given year (i.e., the two parties would enter into a
contract stating that the supplier has RIN-separation responsibilities
for all transferred volumes).
    We are proposing this provision solely for the case of blenders who
blend and trade less than 125,000 total gallons of renewable fuel per
year. A company that blends 100,000 gallons and trades 100,000 gallons
would not be able to use this provision. However, we request comment on
whether authorization to delegate RIN-separation responsibilities
should also be allowed for other parties as well.
2. Small Producer Exemption
    Under the RFS1 program, parties who produce or import less than
10,000 gallons of renewable fuel in a year are not required to generate
RINs for that volume, and are not required to register with the EPA if
they do not take ownership of RINs generated by other parties. We
propose to maintain this exemption under the RFS2 rule. However, we
request comment on whether the 10,000 gallon threshold should be higher
given that the total volume of renewable fuel mandated by EISA is
considerably higher than that required by the RFS1 program, or
conversely whether it should be lower given that the biomass-based
diesel standard is considerably lower than the

[[Page 24974]]

mandated volume for total renewable fuel.

D. 20% Rollover Cap

    EISA does not change the language in CAA section 211(o)(5) stating
that renewable fuel credits must be valid for showing compliance for 12
months as of the date of generation. As discussed in the RFS1 final
rulemaking, we interpreted the statute such that credits would
represent renewable fuel volumes in excess of what an obligated party
needs to meet their annual compliance obligation. Given that the
renewable fuel standard is an annual standard, obligated parties
determine compliance shortly after the end of the year, and credits
would be identified at that time. In the context of our RIN-based
program, we have accomplished the statute's objective by allowing RINs
to be used to show compliance for the year in which the renewable fuel
was produced and its associated RIN first generated, or for the
following year. RINs not used for compliance purposes in the year in
which they were generated will by definition be in excess of the RINs
needed by obligated parties in that year, making excess RINs equivalent
to the credits referred to in section 211(o)(5). Excess RINs are valid
for compliance purposes in the year following the one in which they
initially came into existence. RINs not used within their valid life
will thereafter cease to be valid for compliance purposes.
    In the RFS1 final rulemaking, we also discussed the potential
``rollover'' of excess RINs over multiple years. This can occur in
situations wherein the total number of RINs generated each year for a
number of years in a row exceeds the number of RINs required under the
RFS program for those years. The excess RINs generated in one year
could be used to show compliance in the next year, leading to the
generation of new excess RINs in the next year, causing the total
number of excess RINs in the market to accumulate over multiple years
despite the limit on RIN life. The rollover issue could in some
circumstances undermine the ability of a limit on credit life to
guarantee an ongoing market for renewable fuels.
    To implement the Act's restriction on the life of credits and
address the rollover issue, the RFS1 final rulemaking implemented a 20%
cap on the amount of an obligated party's RVO that can be met using
previous-year RINs. Thus each obligated party is required to use
current-year RINs to meet at least 80% of its RVO, with a maximum of
20% being derived from previous-year RINs. Any previous-year RINs that
an obligated party may have that are in excess of the 20% cap can be
traded to other obligated parties that need them. If the previous-year
RINs in excess of the 20% cap are not used by any obligated party for
compliance, they will thereafter cease to be valid for compliance purposes.
    EISA does not modify the statutory provisions regarding credit
life, and the volume changes by EISA also do not change at least the
possibility of large rollovers of RINs for individual obligated
parties. Therefore, we propose to maintain the regulatory requirement
for a 20% rollover cap under the new RFS2 program. However, under RFS2
obligated parties will have four RVOs instead of one. As a result, we
are proposing that the 20% rollover cap would apply separately to all
four RVOs. We do not believe it would be appropriate to apply the
rollover cap to only the RVO representing total renewable fuel, leaving
the other three RVOs with no rollover cap. Doing so would allow all
previous-year RINs used for compliance to be those with a D code of 4,
and this in turn would allow an obligated party to meet one of the
nested standards, such as that for biomass-based diesel, using more
than 20% previous-year RINs. This could result in significant rollover
of RINs with a D code of 2, representing biomass-based diesel, and the
valid life of these RINs would have no meaning in this case.
    Some obligated parties have suggested that the rollover cap should
be raised to a value higher than 20%, citing the need for greater
flexibility in the face of significantly higher volume requirements.
However, we believe that a higher value could create disruptions in the
RIN market as parties with excess RINs would have a greater incentive
to hold onto them rather than sell them. This would especially be a
concern in years where the volume of renewable fuel available in the
market is very close to the RFS requirements. Nevertheless, we request
comment on whether the 20% rollover cap should be raised to a higher value.
    As described in Section III.G.4, some parties have also suggested
that the rollover cap should be lowered to a value lower than 20%, such
as 10%. In the event of concerns about the availability of RINs, a
lower rollover cap would provide a greater incentive for parties with
excess RINs to sell them rather than hold onto them. However, a lower
rollover cap would also reduce flexibility for many obligated parties.
While we are not proposing it in today's notice, we request comment on it.

E. Concept for EPA Moderated Transaction System

1. The Need for an EPA Moderated Transaction System
    In implementing RFS1, we found that the 38-digit standardized RINs
have proven confusing to many parties in the distribution chain.
Parties have made various errors in generating and using RINs. For
example, we have seen errors wherein parties have transposed digits
within the RIN. We have seen parties creating alphanumeric RINs,
despite the fact that RINs are supposed to consist of all numbers. We
have also seen incorrect numbering of volume start and end codes.
    Once an error is made within a RIN, the error propagates throughout
the distribution system. Correcting an error can require significant
time and resources and involve many steps. Not only must reports to EPA
be corrected, underlying records and reports reflecting RIN
transactions must also be located and corrected to reflect discovery of
an error. Because reporting related to RIN transactions under RFS1 is
only on a quarterly basis, a RIN error may exist for several months
before being discovered.
    Incorrect RINs are invalid RINs. If parties in the distribution
system cannot track down and correct the error made by one of them in a
timely manner, then all downstream parties that trade the invalid RIN
will be in violation. Because RINs are the basic unit of compliance for
the RFS1 program, it is important that parties have confidence when
generating and using them.
    All parties in the RFS1 and the proposed RFS2 regulated community
use RINs. These parties include producers of renewable fuels, obligated
parties, exporters, and other owners of RINS, typically marketers of
renewable fuels and blenders. (Anyone can own RINs, but those who do
would be subject to registration, recordkeeping, reporting, and attest
engagement requirements described in this preamble.). Currently under
RFS1, all RINs are used to comply with a single standard, and in 2013
an additional cellulosic standard would have been added. Under this
proposed rule, there are four standards, and RINs must be generated to
identify four types of renewable fuels: cellulosic biofuel, biomass-
based diesel, other advanced biofuels, and other renewable fuels (e.g.,
corn ethanol). (For a more detailed discussion of RINs, see Section
III.A of this preamble.) In the proposed EPA Moderated Transaction
System (EMTS), the four types of RINs will be managed through four
types of account.

[[Page 24975]]

    Based upon problems we observed with the use of RINs under RFS1,
and considering that we will now have a more complex system including
four standards instead of just one, we believe that the best way to
screen RINs and conduct RIN-based transactions is through EMTS.
    This section describes the proposed EMTS and options for
implementing it. By implementing EMTS, we believe that we would be able
to greatly reduce RIN-related errors and efficiently and accurately
manage the universe of RINs. There are two aspects to our proposal for
EMTS. The first aspect focuses upon creating four, generic types of RIN
account. The second aspect focuses upon actually developing a ``real
time'' environment for handling RIN trades.
2. How EMTS Would Work
    EMTS would be a closed, EPA-managed system that provides a
mechanism for screening RINs as well as a structured environment for
conducting RIN transactions. ``Screening'' RINs will mean that parties
would have much greater confidence that the RINs they handle are
genuine. Although screening cannot remove all human error, we believe
it can remove most of it.
    We propose that screening and assignment of RINs be made at the
logical point, i.e., the point when RINs are generated through
production or importation of renewable fuel. A renewable producer would
electronically submit, in ``real time,'' a batch report for the volume
of renewable fuel produced or imported, as well as a list of the RINs
generated and assigned. EMTS would automatically screen each batch and
either reject the RINs or permit them to pass into the transaction
system, into the RIN generator's account, as one of the four types of
RINs. Note that under RFS1, RIN generation (batch) and RIN transaction
reports are submitted quarterly. Batch reports are submitted by
producers and importers quarterly and reflect how they generated and
assigned RINS to batches. RIN transaction reports are submitted by all
parties who engage in RIN transactions, including buying or selling
RINs. Under this proposed approach for RFS2, these batch reports and
RIN transaction reports would be submitted monthly for calendar year
2010. However, once EMTS is implemented in calendar year 2011, these
separate periodic reports may no longer be necessary. Instead the
information would be submitted as RINs are generated and assigned within EMTS.
    Under RFS1, the producer or importer list RINs they generate and
assign via the batch report. EPA, in turn, uses the batch report data
to verify RINs generated and transacted. The report is submitted
quarterly. Under RFS1, the purpose of the RIN transaction report is to
document RIN transactions and to document that RINs have been sold or
transferred from party to party in the distribution system. This report
is also submitted quarterly. The RIN transaction report includes the
following information in this report: its name, its EPA company
registration number, and in some cases (where compliance is on a
facility basis), its EPA facility identification number. For the
quarterly reporting period, the reporting party indicates the
transaction type (RIN purchase, RIN sale, expired RIN, or retired RIN),
and the date of the transaction. For a RIN purchase or sale, the
transaction report includes the trading partner's name and the trading
partner's EPA company registration number. There is also information
that may have to be submitted in the event a reporting party must
report a RIN that has been retired (e.g., when a RIN has become invalid
due to the spillage of the associated volume of renewable fuel). As
discussed above, the shortcoming of these reports is that they are only
submitted quarterly. RIN errors that affect compliance may not be
discovered for many months because of the relative infrequency of
reporting transactions to EPA. EMTS will assume the functionality of
batch reporting and transaction reporting used by regulated parties,
allowing EPA to better screen RINs and reduce or eliminate generation
and transaction errors.
    Under the RFS2 program, we are proposing that batch reports
submitted by producers and importers and RIN transaction reports be
submitted monthly rather than quarterly in the first year of the
program (i.e., calendar year 2010). During 2010, we will be finishing
development and testing of the EMTS. In order to minimize the hardship
that undiscovered, invalid RINs may cause, we propose and seek comment
on increasing the frequency of reporting and our own review of reports
in order to assist the regulated community with compliance. As we
develop EMTS through calendar year 2010, we intend to invite and
encourage interested reporting parties to ``opt in'' to EMTS. This will
serve a two-fold purpose: regulated parties may opt to gain familiarity
EMTS before it becomes fully operational and we may have actual
customers with which to test EMTS prior to it becoming fully
operational. We believe that permitting interested parties to ``opt
in'' will result in a better EMTS for all.
    In the second year of the program (i.e., calendar year 2011 and
forward), we anticipate fully implementing the proposed EMTS and
receiving the data contained in batch and RIN transaction reports in
relatively ``real time'' (i.e., as transactions occur). We propose that
``real time'' be construed as within three (3) business days of a
reportable event (e.g., generation and assignment of RINs, transfer of RINs).
    Parties who use EMTS would have to register with EPA in accordance
with the proposed RFS2 registration program described in Section III.C
of this preamble. They would also have to create an account (i.e.,
register) via EPA's Central Data Exchange (CDX), as we envision
managing EMTS via CDX. CDX is a secure and central portal through which
parties may submit compliance reports. We propose that parties must
establish an account with EMTS by October 1, 2010 or 60 days prior to
engaging in any transaction involving RINs, whichever is later. As
discussed above, the actual items of information covered by reporting
under RFS2 are nearly identical to those reported under RFS1.
    Once registration occurs with EMTS, individual RIN accounts would
be established and the system would manage the accounts for each
individual party. The RIN accounts would correspond to the four broad
types of renewable fuel. RIN accounts would be established for
cellulosic biofuel, biomass-based diesel, other advanced biofuels, and
other renewable fuels (including corn ethanol). One big advantage of
RIN accounts is that the system would make available generic accounts
for transactions involving RINs of similar type. The unique
identification of the RIN would exist within EMTS, but parties engaging
in RIN transactions would no longer have to worry about incorrectly
recording or using 38-digit RIN numbers. As with RFS1, there is no
``good faith'' provision to RIN ownership. An underlying principle of
RIN ownership is still one of ``buyer beware'' and RINs may be
prohibited from use at any time if they are found to be invalid.
Because of the ``buyer beware'' aspect, we intend to offer the option
for a buyer to accept or reject RINs from specific RIN generators or
from classes of RIN generators. Also, we propose to collect information
about the price associated with RINs traded. This information is not
collected under RFS1, but we believe this information has great
programmatic value to EPA because it may help us to anticipate and

[[Page 24976]]

appropriately react to market disruptions and other compliance
challenges, assess and develop responses to potential waivers, and
assist in setting future renewable standards. We believe that highly
summarized price information (e.g., the average price of RINs traded
nationwide) may be valuable to regulated parties, as well, and may help
them to anticipate and avoid market disruptions.
    The following is an example of how a RIN transaction might occur in
the proposed EMTS model:
    1. Seller logs into EMTS and posts his sale of 10,000 RINs to
Buyer. For this example, assume the RINs were generated in 2008 and
were assigned to 10,000 gallons of ``other renewable fuel'' (corn
ethanol). Seller's RIN account for ``other renewable fuel'' is
automatically reduced by 10,000 with the posting of his sale to Buyer.
Buyer receives automatic notification of the pending transaction.
    2. Buyer logs into EMTS. She sees the sale transaction pending.
Assuming it is correct, she accepts it. Upon her acceptance, her RIN
account for ``other renewable fuel'' (corn ethanol) is automatically
increased by 10,000 2008 assigned RINs.
    3. After Seller has posted his sale and Buyer has accepted it, EMTS
automatically notifies both Buyer and Seller that the transaction has
been fully completed.
    Under EMTS as we are proposing it, the seller would always have to
initiate any transaction. The seller's account is reduced when he posts
his sale. The buyer must acknowledge the sale in order to have the RINs
transferred to her account. Transactions would always be limited to
available RINs. Notification would automatically be sent to both the
buyer and the seller upon completion of the transaction. EPA proposes
to consider any sale or transfer as complete upon acknowledgement by the buyer.
    We propose that RINs and the parameters of RIN generation (e.g.,
year) be considered public information. We also propose that summary
RIN price information, such as average price of all RINs in a broad
geographic area (such as a state, region, or nationwide) be considered
public information. This summary price information would be aggregated
from transactions conducted within EMTS, but would not be identified
with individual companies or particular transactions that have
occurred. Because we believe information about RIN pricing in general
will be useful to regulated parties, we are proposing to make this
information available to them. We propose that the actual transactions
between parties and that individual company account information may be
claimed as confidential business information (CBI) by the parties to
that transaction. EPA would treat any information submitted that is
covered by a CBI claim in accordance with the procedures at 40 CFR Part
2 and applicable Agency policies and guidelines for the handling of claimed CBI.
3. Implementation of EMTS
    We anticipate that implementing EMTS will take until January 1,
2011, although we are proposing that the RFS2 program be effective on
January 1, 2010. We anticipate that development of EMTS will require
significant time and effort and that a delayed effective date may
permit better pre-testing with interested regulated parties. We propose
to permit regulated parties who are willing to participate in EMTS
early to voluntarily opt-in to the system before January 1, 2011. The
actual date for these parties' opt-in will depend upon the actual
timeline for development of EMTS. We encourage comments from interested
parties as to how we might best make use of the development period and
the proposed opportunity for willing and interested parties to ``opt
in'' early.
    Under our proposed scenario, for the 2010 compliance year,
recordkeeping and reporting would be analogous to RFS1, although
registration would be enhanced in accordance with the discussion in
Section III.C of this preamble and recordkeeping and reporting would
reflect the four types of RIN described above. In order to avoid
propagation of RIN-related errors and to prevent errors from going too
long without being detected, we believe it is necessary to increase the
frequency of batch reporting and RIN transaction reporting to monthly
rather than quarterly during 2010.
    EPA will implement the EMTS during the first year of the RFS2
program. RINs generated under the RFS1 regulations will continue to be
traded and reported using the current processes. RINs would still have
unique identifying information, but EMTS will allow transactions to
take place on a generic basis having the system track the specific
unique identifiers. We believe that EMTS will virtually eliminate
errors related to tracking and using individual RINs. Parties will be
required to submit RIN transactions by specifying RIN year, RIN
assignment, RIN fuel type, and any other reporting requirement
specified by the administrator.
    Implementation of EMTS should save considerable time and resources
for both industry and EPA. This is most evident considering that the
proposed system virtually eliminates multiple sources of administrative
errors, resulting in a reduction in costs and effort expended to
correct and regenerate product transfer documents, documentation and
recordkeeping, and resubmitting reports to EPA. We anticipate that a
fully functioning EMTS will result in fewer reports and easier
reporting for industry, and fewer reports requiring processing by EPA.
Industry will need to spend less time and effort verifying the validity
of the RINs they procure and allowing them to procure them on the open
market with confidence. EPA will need to spend less time tracking down
the responsible parties for invalid RINs. This is possible because EMTS
will remove management of the 38-digit RIN from the hands of the
reporting community. At the same time, EPA and the reporting community
will be working with a standardized system, reducing stresses and
development costs on IT systems.
    In summary, the advantage to implementing EMTS is that parties may
engage in RIN transactions with a high degree of confidence. Errors
would be virtually eliminated. Everyone engaging in RIN transactions
would have a simplified environment in which to work which should
minimize the level of resources needed for implementation. However, the
one unavoidable disadvantage that we foresee is that parties would have
to switch to a new and different reporting system in the second year of
the RFS2 program. Some errors may still occur in by parties who
continue to generate and use the 38-digit RINs during 2010. As
discussed above, we propose to increase the frequency of batch and RIN
transaction reporting to monthly for 2010, in order that we may help
parties discover errors and correct them before they become violations.
We also propose to permit parties to voluntarily ``opt in'' to using
EMTS while it is still in development in order to ease the transition.
We invite comment from all interested parties as to how we may best
assist regulated parties in transitioning from the ``old'' RFS1 method
of handing RINs to the ``new,'' proposed RFS2 EMTS method on January 1, 2011.
    We also invite comment on whether, in the event the RFS2 start date
is delayed, EPA should nevertheless allow a one-year period during
which use of EMTS is optional, or if EPA should begin the program at
the inception of the delayed RFS2 program if EMTS is fully operational
at that time.

[[Page 24977]]

F. Retail Dispenser Labelling for Gasoline With Greater Than 10 Percent Ethanol

    Fuel retailers expressed concern that the magnitude of the price
discount for E85 relative to E10 that would be necessary to facilitate
sufficient use of E85 would encourage widespread misfueling of non-flex
fuel vehicles. Today's proposal contains labeling requirements for
pumps that dispense blends that contain greater than 10% ethanol which
state that the use in non-flex fuel vehicles is prohibited and may
cause damage to the vehicle.\45\ We anticipate that the industry would
also conduct public information activities to alert customers who may
not have yet become accustomed to seeing E85 at retail to avoid using
E85 in their non-flex-fuel vehicles. Uniquely colored/labeled nozzle
handles may also be useful in helping to prevent accidental cases of
misfueling. We believe that in most cases the warnings that the use of
E85 in non-flex fuel vehicles is illegal, can damage the vehicle, and
can void vehicle manufacturer warranties may be a sufficient
disincentive to prevent intentional misfueling. In cases where
intentional misfueling may occasionally take place, the party is likely
to experience drivability problems and thus would not repeat the act.
---------------------------------------------------------------------------

    \45\ See section 80.1469 in the proposed regulatory text.
---------------------------------------------------------------------------

    Today's proposal does not contain requirements that E85 refueling
hardware be configured to prevent the introduction of E85 into non-
flex-fuel vehicles. It is unclear how such an approach could be
implemented to allow the approximately 6 million flex-fuel vehicles on
the road today to continue to be fueled with E85 without modification
to their filler neck hardware.\46\ In any event, we do not believe that
unique E85 nozzles are necessary.
---------------------------------------------------------------------------

    \46\ An E85 nozzle design and corresponding flex-fuel vehicle
filler design that would prevent the introduction of E85 into non-
flex-fuel vehicles while allowing flex fuel vehicles to be fueled
with E10 as well as E85 would also prevent the introduction of E85
into current flex-fuel vehicles since there is currently no
difference in nozzle/filler neck hardware between flex-fuel and non-
flex-fuel vehicles.
---------------------------------------------------------------------------

    We request comment on whether the proposed labeling requirements
and voluntary measures such as those described above would provide
sufficient warning to fuel retail customers not to refuel non-flex-fuel
vehicles with E85. To the extent that other measures to prevent
misfueling are thought to be necessary, comment is requested on the
specific nature of such measures and the associated potential costs and
benefits. One additional potential measure to prevent misfueling would
be for cards to be issued to flex fuel vehicle owners and for all E85
dispensers to be equipped with card readers that would allow E85 to be
dispensed only to card holders.

V. Assessment of Renewable Fuel Production Capacity and Use

    To assess the impacts of this rule, there must be a clear
understanding of the kind of renewable fuels that could be used, the
types and locations of their feedstocks, the fuel volumes that could be
produced by a given feedstock, and any challenges associated with their
use. This section provides this assessment of the potential feedstocks
and renewable fuels that may be used to meet the Energy Independence
and Security Act (EISA) and the rationale behind our projections of
various fuel types to represent the control case for analysis purposes.
Definitional issues regarding the four types of renewable fuel required
under EISA are discussed in Section III.B of this preamble.

A. Summary of Projected Volumes

    EISA mandates the use of increasing volumes of renewable fuel. To
assess the impacts of this increase in renewable fuel volume from
business-as-usual (what is likely to have occurred without EISA), we
have established a reference and control case from which subsequent
analyses are based. The reference case is essentially a projection of
renewable fuel volumes without the enactment of EISA. The control case
is a projection of the volumes and types of renewable fuel that might
be used to comply with the EISA volume mandates. Both the reference and
control cases are discussed in further detail below.
1. Reference Case
    Our reference case renewable fuel volumes are based on the Energy
Information Administration's (EIA) Annual Energy Outlook (AEO) 2007
reference case projections. The AEO 2007 presents long-term projections
of energy supply, demand, and prices through 2030 based on results from
EIA's National Energy Modeling System (NEMS). EIA's analysis focuses
primarily on a reference case (which we use as our reference case),
lower and higher economic growth cases, and lower and higher energy
price cases. AEO 2007 projections generally are based on Federal,
State, and local laws and regulations in effect on or before October
31, 2006.\47\ The potential impacts of pending or proposed legislation,
regulations, and standards are not reflected in the projections. While
AEO 2007 is not as up-to-date as AEO 2008 (or the recently released AEO
2009), we chose to use AEO 2007 because AEO 2008 already includes the
impact of increased renewable fuel volumes under EISA as well as fuel
economy improvements under CAFE, whereas AEO 2007 did not. Table V.A.1-
1 summarizes the fuel types and volumes for the years 2009-2022 as
taken from AEO 2007. For our air quality analysis we also considered a
reference case assuming the mandated renewable fuel volumes under the
Renewable Fuel Standard Program from the Energy Policy Act of 2005
(EPAct). Refer to Section VII for further details.
---------------------------------------------------------------------------

    \47\ EIA. Annual Energy Outlook 2007 with Projections to 2030.
http://www.eia.doe.gov/oiaf/archive/aeo07/index.html. Accessed
February 2008.

                     Table V.A.1-1--AEO 2007 Reference Case Projected Renewable Fuel Volumes
                                                [billion gallons]
----------------------------------------------------------------------------------------------------------------
                                                 Advanced biofuel                  Non-advanced
                                 ------------------------------------------------     biofuel
                                    Cellulosic     Biomass-based  Other advanced ----------------      Total
              Year                    biofuel        diesel\a\        biofuel                        renewable
                                 ------------------------------------------------                      fuel
                                    Cellulosic         FAME          Imported      Corn  ethanol
                                      ethanol      biodiesel\b\       ethanol
----------------------------------------------------------------------------------------------------------------
2009............................            0.07            0.32            0.50            9.44           10.33
2010............................            0.12            0.32            0.29           10.49           11.22
2011............................            0.19            0.33            0.16           10.69           11.37
2012............................            0.25            0.33            0.18           10.81           11.57

[[Page 24978]]


2013............................            0.25            0.33            0.19           10.93           11.70
2014............................            0.25            0.23            0.20           11.01           11.69
2015............................            0.25            0.25            0.39           11.10           11.99
2016............................            0.25            0.35            0.51           11.16           12.27
2017............................            0.25            0.36            0.53           11.30           12.44
2018............................            0.25            0.36            0.54           11.49           12.64
2019............................            0.25            0.37            0.58           11.69           12.89
2020............................            0.25            0.37            0.60           11.83           13.05
2021............................            0.25            0.38            0.63           12.07           13.33
2022............................            0.25            0.38            0.64           12.29           13.56
----------------------------------------------------------------------------------------------------------------
\a\ Biomass-Based Diesel includes FAME biodiesel, cellulosic diesel, and non-co-processed renewable diesel. AEO
  2007 only projects FAME biodiesel volumes.
\b\ Fatty acid methyl ester (FAME) biodiesel.

2. Control Case for Analyses
    Our assessment of the renewable fuel volumes required to meet EISA
necessitates establishing a primary set of fuel types and volumes on
which to base our assessment of the impacts of the new standards. EISA
contains four broad categories: cellulosic biofuel, biomass-based
diesel, total advanced biofuel, and total renewable fuel. As these
categories could be met with a wide variety of fuel choices, in order
to assess the impacts of the rule, we projected a set of reasonable
renewable fuel volumes based on our interpretation at the time we began
our analysis of likely fuels that could come to market.
    Although actual volumes and feedstocks may be different, we believe
the projections made for our control case are within the range of
reasonable predictions and allow for an assessment of the potential
impacts of the RFS2 standards. Table V.A.2-1 summarizes the fuel types
used for the control case and their corresponding volumes for the years
2009-2022.

                                              Table V.A. 2-1--Control Case Projected Renewable Fuel Volumes
                                                                    [billion gallons]
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                       Advanced biofuel                             Non-
                                                              -----------------------------------------------------------------   Advanced
                                                                Cellulosic  Biomass-based diesel \a\   Other advanced biofuel     Biofuel
                                                                 biofuel   -----------------------------------------------------------------    Total
                             Year                             -------------                Non-co-        Co-                                 renewable
                                                                              FAME \b\    processed    processed     Imported       Corn         fuel
                                                                Cellulosic   biodiesel    renewable    renewable     ethanol      ethanol
                                                                 ethanol                    diesel       diesel
--------------------------------------------------------------------------------------------------------------------------------------------------------
2009.........................................................         0.00         0.50         0.00         0.00         0.50         9.85        10.85
2010.........................................................         0.10         0.64         0.01         0.01         0.29        11.55        12.60
2011.........................................................         0.25         0.77         0.03         0.03         0.16        12.29        13.53
2012.........................................................         0.50         0.96         0.04         0.04         0.18        12.94        14.66
2013.........................................................         1.00         0.94         0.06         0.06         0.19        13.75        16.00
2014.........................................................         1.75         0.93         0.07         0.07         0.36        14.40        17.58
2015.........................................................         3.00         0.91         0.09         0.09         0.83        15.00        19.92
2016.........................................................         4.25         0.90         0.10         0.10         1.31        15.00        21.66
2017.........................................................         5.50         0.88         0.12         0.12         1.78        15.00        23.40
2018.........................................................         7.00         0.87         0.13         0.13         2.25        15.00        25.38
2019.........................................................         8.50         0.85         0.15         0.15         2.72        15.00        27.37
2020.........................................................        10.50         0.84         0.16         0.16         2.70        15.00        29.36
2021.........................................................        13.50         0.83         0.17         0.17         2.67        15.00        32.34
2022.........................................................        16.00         0.81         0.19         0.19         3.14        15.00        35.33
--------------------------------------------------------------------------------------------------------------------------------------------------------
\a\ Biomass-Based Diesel includes FAME biodiesel, cellulosic diesel, and non-co-processed renewable diesel.
\b\ Fatty acid methyl ester (FAME) biodiesel.

    We needed to make this projection soon after EISA was signed to
allow sufficient time to conduct our long lead-time analyses. As a
result, we used the same ethanol-equivalence basis for these
projections as was used in the RFS1 rulemaking. However, as described
in Section III.D.1, we are also co-proposing that volumes of renewable
fuel be counted on a straight gallon-for-gallon basis under RFS2, such
that all Equivalence Values would be 1.0. The net effect of these two
approaches to Equivalence Values on projected volumes is very small;
instead of 36 billion gallons of renewable fuel in 2022, our control
case includes 35.3 billion gallons. We do not believe that

[[Page 24979]]

this difference will substantively affect the analyses that are based
on our projected control case volumes.
    The following subsections detail our rationale for projecting the
amount and type of fuels needed to meet EISA as shown in Table V.A.2-1.
For cellulosic biofuel we have assumed that the entire volume will be
domestically produced cellulosic ethanol. Biomass-based diesel is
assumed to be comprised of a majority of fatty-acid methyl ester (FAME)
biodiesel and a smaller portion of non-co-processed renewable diesel.
The portion of the advanced biofuel category not met from cellulosic
biofuel and biomass-based diesel is assumed to come mainly from
imported (sugarcane) ethanol with a smaller amount from co-processed
renewable diesel. The total renewable fuel volume not required to be
comprised of advanced biofuels is assumed to be met with corn ethanol.
    In addition, the following subsections also describe other fuels
that have the potential to contribute to meeting EISA, but because of
their uncertainty of use, or because their use likely might be
negligible we have chosen to not assume any use for our analysis.
Examples of these types of renewable fuels or blendstocks include bio-
butanol, biogas, cellulosic diesel, cellulosic gasoline, biofuel from
algae, jatropha, or palm, imported cellulosic ethanol, other biomass-
to-liquids (BTL), and other alcohols or ethers. We intend to revisit
these assumptions for the final rule and invite comment on whether
these renewable fuels or other potential fuels which have not been
included in our analyses should be included.
a. Cellulosic Biofuel
    As defined in EISA, cellulosic biofuel means renewable fuel
produced from any cellulose, hemicellulose, or lignin that is derived
from renewable biomass and that has lifecycle greenhouse gas emissions,
as determined by the Administrator, that are at least 60% less than the
baseline lifecycle greenhouse gas emissions.
    When many people think of cellulosic biofuel, they immediately
think of cellulosic ethanol. However, cellulosic biofuel could be
comprised of other alcohols, synthetic gasoline, synthetic diesel fuel,
and synthetic jet fuel, propane, and biogas. Whether cellulosic biofuel
is ethanol will depend on a number of factors, including production
costs, the form of tax subsidies, credit programs, and issues
associated with blending the biofuel into the fuel pool. It will also
depend on the relative demand for gasoline and diesel fuel. For
instance, European refineries are undersupplying the European market
with diesel fuel and oversupplying it with gasoline, and based on the
recent high diesel fuel price margins over gasoline, it seems that the
U.S. is falling in line with Europe. Therefore, if the U.S. trend is
toward being relatively oversupplied with gasoline, there could be a
price advantage towards producing renewable fuels that displace diesel
fuel rather than a gasoline fuel replacement like ethanol.
    Current efforts in converting cellulosic feedstocks into fuels
focus on biochemical and thermochemical conversion processes.
Biochemical processes use live bacteria or isolated enzymes, or acids,
to break cellulose down into fermentable sugars. The advantage of using
live bacteria or enzymes is that simple carbon steel could be used
which helps to control the capital costs. However, bacteria and enzymes
that break down cellulose are generally specific to certain types of
cellulose, thus, the cellulosic biofuel facility may have difficulty
processing different types of feedstocks.\48\ If live bacteria are
used, the bacteria could be susceptible to contamination that could
force a plant shutdown. An example of a company using enzymes to
process cellulose into ethanol is Iogen, which has a demonstration
plant in Canada.
---------------------------------------------------------------------------

    \48\ This is currently an area of intense research.
---------------------------------------------------------------------------

    On the other hand, biochemical processes which rely on strong acids
will likely be less susceptible to contamination issues, and could more
easily process mixed feedstocks. Thus, strong acid biochemical
cellulosic ethanol plants could process MSW or a variety of feedstocks
which may be available in areas where no single feedstock dominates.
The strong acids, however, would likely require more expensive
metallurgy. A company which is planning to use strong acids to
hydrolyze the cellulose is Blue Fire Ethanol. Blue Fire is planning on
building a MSW plant in Southern California. Once cellulose is reduced
to simple sugars, either strong acid or enzymatic cellulosic ethanol
plants operate in a manner similar to a corn ethanol plant. This
consists of fermenting sugars into ethanol and then separating the
ethanol from the water that facilitated the fermentation step.
    The thermochemical conversion process is very different from the
biochemical process right from the beginning. For the thermochemical
process, feedstocks are partially burned with oxygen at a very high
temperature and converted into a synthesis gas comprised of carbon
monoxide and hydrogen. The principal advantage of the thermochemical
process is that virtually any hydrocarbon material could be processed
as feedstock, as they would all be converted to the synthesis gas, even
if they produce different relative concentrations of carbon monoxide
and hydrogen. The synthesis gas is typically converted to ethanol or
diesel by one of several different processes.
    Examples of companies currently pursuing the thermochemical route
to selectively produce ethanol include Range Ethanol and Coskata. Range
Ethanol is using a specially formulated catalyst that will primarily
produce ethanol, but it will produce other higher molecular weight
alcohols as well which would be recycled and mostly converted to
ethanol. Coskata, which is being supported by General Motors, is
planning on using bacteria to convert the synthesis gas to ethanol.
    Another thermochemical plant could employ a very similar
gasification reactor, but instead of producing ethanol from syngas, a
Fischer Tropsch (F-T) reactor would be used to produce a primarily
diesel product, i.e., cellulosic diesel. The F-T reactor would use a
specially designed iron or cobalt catalyst to convert the syngas to
straight chain hydrocarbon compounds of varying lengths and molecular
weights. The heavier of these hydrocarbon compounds are then
hydrocracked to produce a very high percentage of valuable diesel fuel
and naphtha (gasoline type compounds). The F-T diesel fuel produced
from the F-T process is very high in quality due to its high cetane and
essentially zero sulfur level. While the naphtha produced from the F-T
process also contains essentially zero sulfur, it is very low in octane
and thus is a poor gasoline blendstock (although it could still be
desirable as a gasoline blendstock because of all the high octane
ethanol being blended into gasoline). Cellulosic naphtha is also
valuable as a cracking feedstock for producing various petrochemical
compounds. Since the F-T diesel is of better quality than the naphtha,
the heavier hydrocarbon compounds are selectively hydrocracked to
produce more diesel over naphtha.
    No commercial cellulosic diesel plants currently exist in the U.S.,
nor elsewhere in the world. Currently, there is a cellulosic diesel
pilot plant operated by Choren in Germany and a commercial sized plant
in the planning stages by Choren also in Germany. Choren is planning to
employ woody materials and agricultural residue as feedstocks. Choren
specially developed a three-stage gasification process for dealing with
the complexities of

[[Page 24980]]

biomass and has partnered with Shell which has commercialized a F-T
reaction process. The Choren commercial cellulosic diesel plant in
Germany is expected to begin operating in 2010. Although coal-to-
liquids (CTL) plants rely on coal as their feedstock, they are very
similar to cellulosic diesel plants in design and help to demonstrate
the feasibility of the cellulosic diesel process. There are CTL pilot
plants which are operating today, as well as a number of commercial CTL
plants operating today or in the planning stages. Some of these plants
have experimented with or are being planned for co-feeding biomass
along with the coal. A current list of proposed cellulosic diesel and
CTL plants is provided in Chapter 1 of the DRIA.
    In terms of production costs, at least for the current state of
technology, neither the biochemical nor thermochemical platforms
(comparing enzymatic biochemical processing to ethanol and
thermochemical processing to cellulosic diesel) appear to have clear
advantages in capital costs or operating costs.\49\ Other processing
techniques, for example, the syngas-to-ethanol process used by Coskata,
claim to be capable of producing at even lower production costs, but
without any commercial facilities operating today, it is hard to
predict how these other processing techniques differ from our estimates
of what the production costs for cellulosic biofuel facilities will be
in the future and which technology pathways will be most economic. As
such, both enzymatic biochemical and thermochemical technologies could
be key processing pathways for the production of cellulosic biofuel.
---------------------------------------------------------------------------

    \49\ Wright, M. and Brown, R, ``Comparative Economics of
Biorefineries Based on the Biochemical and Thermochemical
Platforms,'' Biofuels, Bioprod. Bioref. 1:49-56, 2007.
---------------------------------------------------------------------------

    The economic competitiveness of cellulosic biofuels will also
depend on the extent of financial support from the government. Under
the Farm Bill of 2008, both cellulosic ethanol and cellulosic diesel
receive the same tax subsidies ($1.01 per gallon each). The tax
subsidy, however, gives ethanol producers a considerable advantage over
those producing cellulosic diesel due to the feedstock quantity needed
per gallon produced (i.e., typically the higher the energy content of
the product, the more feedstock that is required). On an energy basis,
cellulosic ethanol would receive approximately $13/mmBtu while
cellulosic diesel would receive approximately $8/mmBtu. In a similar
manner, if we were to finalize an approach to the Equivalence Values
for generating RINs in which volume rather than energy content is the
basis, there would be an advantage for the production of cellulosic
ethanol over cellulosic diesel.
    One large advantage that cellulosic diesel has over ethanol is the
ability for the fuel to be blended easily into the current distribution
infrastructure at sizeable volumes. There are currently factors tending
to limit the amount of ethanol that can be blended into the fuel pool
(see Section V.D. for more discussion). Thus, the production of
cellulosic diesel instead of cellulosic ethanol could help increase
consumption of renewable fuels.
    Thus, there is uncertainty as to which mix of cellulosic biofuels
will be produced to fulfill the 16 Bgal mandate by 2022. The latest
release of AEO 2009, for example, estimates a mixture of cellulosic
diesel and ethanol produced for cellulosic biofuel. For assessing the
impacts of the RFS2 standards, we made the simplifying assumption that
cellulosic biofuel would only consist of ethanol, though market
realities may also result in cellulosic diesel and other products. We
are requesting comment on the types of cellulosic biofuel that should
be accounted for in our analyses and whether certain fuels are more
likely to come to fruition than others.
    Cellulosic biofuel could also be produced internationally. One
example of internationally produced cellulosic biofuel is ethanol
produced from bagasse or straw from sugarcane processing in Brazil.
Currently, Brazil burns bagasse to produce steam and generate
bioelectricity. However, improving efficiencies over the coming decade
may allow an increasing portion of bagasse to be allocated to other
uses, including cellulosic biofuel, as the demand for bagasse for steam
and bioelectricity could remain relatively constant.
    One recent study assessed the biomass feedstock potential for
selected countries outside the United States and projected supply
available for export or for biofuel production.50 51 For the
study's baseline projection in 2017, it was estimated that
approximately 21 billion ethanol-equivalent gallons could be produced
from cellulosic feedstocks at $36/dry tonne or less. The majority
(~80%) projected is from bagasse, with the rest from forest products.
Brazil was projected to have the most potential for cellulosic
feedstock production from both bagasse and forest products. Other
countries include India, China, and those belonging to the Caribbean
Basin Initiative (CBI), though much smaller feedstock supplies are
projected as compared to Brazil. Although international production of
cellulosic biofuel is possible, it is uncertain whether this supply
would be available primarily to the U.S. or whether other nations would
consume the fuel domestically. Therefore, for our analyses we have
chosen to assume that all the cellulosic biofuel used to comply with
RFS2 would be produced domestically.
---------------------------------------------------------------------------

    \50\ Countries evaluated include Argentina, Brazil, Canada,
China, Colombia, India, Mexico, and CBI.
    \51\ Kline, K. et al., ``Biofuel Feedstock Assessment for
Selected Countries,'' Oak Ridge National Laboratory, February 2008.
---------------------------------------------------------------------------

b. Biomass-Based Diesel
    Biomass-based diesel as defined in EISA means renewable fuel that
is biodiesel as defined in section 312(f) of the Energy Policy Act of
1992 with lifecycle greenhouse gas emissions, as determined by the
Administrator, that are at least 50% less than the baseline lifecycle
greenhouse gas emissions. Biomass-based diesel can include fatty acid
methyl ester (FAME) biodiesel, renewable diesel (RD) that has not been
co-processed with a petroleum feedstock, as well as cellulosic diesel.
Although cellulosic diesel produced through the Fischer-Tropsch (F-T)
process could potentially contribute to the biomass-based diesel
category, we have assumed for our analyses that the fuel and its
corresponding feedstocks (cellulosic biomass) are already accounted for
in the cellulosic biofuel category discussed previously in Section V.A.2.a.
    FAME and RD processes can make acceptable quality fuel from
vegetable oils, fats, and greases, and thus will generally compete for
the same feedstock pool. For our analyses, we have assumed that the
volume contribution from FAME biodiesel and RD will be a function of
the available feedstock types. In our analysis we assumed that virgin
plant oils would be preferentially processed by biodiesel plants, while
the majority of fats and greases would be routed to RD
production.52 53 This is because the RD process involves
hydrotreating (or thermal depolymerization), which is more severe and
uses multiple chemical mechanisms to reform the fat molecules into
diesel range material. The FAME

[[Page 24981]]

process, by contrast, relies on more specific chemical mechanisms and
requires pre-treatment if the feedstocks contain more than trace
amounts of free fatty acids or other contaminates which are typical of
recycled fats and greases. In terms of volume availability of
feedstocks, supplies of fats and greases are more limited than virgin
vegetable oils. As a result, our control case assumes the majority of
biomass-based diesel volume is met using biodiesel facilities
processing vegetable oils, with RD making up a smaller portion and
using solely fats and greases.
---------------------------------------------------------------------------

    \52\ Recent changes to federal tax subsidies and market shifts
may warrant changes to this assumption. We will reevaluate the
relative production volumes of biodiesel and renewable diesel for the FRM.
    \53\ This analysis was conducted prior to the completion of our
lifecycle analysis discussed in Section VI, and assumes the fuels
will meet the required GHG threshold.
---------------------------------------------------------------------------

    The RD production volume must be further classified as co-processed
or non-co-processed, depending on whether the renewable material was
mixed with petroleum during the hydrotreating operations (more details
on this definition are in Section III.B.1). EISA specifically forbids
co-processed RD from being counted as biomass-based diesel, but it can
still count toward the total advanced biofuel requirement. What
fraction of RD will ultimately be co-processed is uncertain at this
time, since little or no commercial production of RD is currently
underway, and little public information is available about the
comparative economics and feasibility of the two methods. We assumed in
our control case that half the material will be non-co-processed and
thus qualify as biomass-based diesel. We invite comment on whether RD
production will favor co-processing or non-co-processing with a
petroleum feedstock in the future.
    Perhaps the feedstock with the greatest potential for providing
large volumes of oil for the production of biomass-based diesel is
microalgae. Algae grown on land in photo-bioreactors or in open ponds
could potentially yield 15 to 50 times more oil per acre than
traditional oil crops such as soy, rapeseed, or oil palm. Additionally
it can be cultivated on marginal land with low nutrient inputs, and
thus does not suffer from the sheer resource constraints that make
other biofuel feedstocks problematic at large scale. However, several
technical hurdles do still exist. Specifically, more efficient
harvesting, dewatering and lipid extraction methods are needed to lower
costs to a level competitive with other biodiesel feedstocks (20-30% of
current costs). Until these hurdles are overcome, it is unlikely that
algae-based biodiesel can be commercially competitive with other
biodiesel fuels. Thus, for our control case we have chosen not to
include oil from algae as a feedstock. Although the majority of algae
to biofuel companies are focusing on producing algae oil for
traditional biodiesel production, several companies are alternatively
using algae for producing ethanol or crude oil for gasoline or diesel
which could also help contribute to the advanced biofuel mandate.\54\
For more detail on algae as a feedstock refer to Section 1.1 of the DRIA.
---------------------------------------------------------------------------

    \54\ Algenol and Sapphire Energy, see http://
www.algenolbiofuels.com/  and http://www.sapphireenergy.com/.

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

    Jatropha curcas, a shrub native to Central America, is yet another
possible biofuel feedstock. The perennial yields oil-rich seeds yearly,
with oil yields per acre up to 4 times that of soy and twice that of
rapeseed under optimal conditions. It can grow on low-nutrient lands,
and is tolerant of drought. However, jatropha yields under these
marginal conditions are hard to predict because of insufficient
commercial experience; it is possible that jatropha will have low
yields in the sub-optimal conditions where its cultivation would be
most advantageous. Furthermore, jatropha seed harvesting is very labor
intensive, and little is known about the crop's sustainability impacts,
its long-term yield, or the feasibility of cultivation as a
monoculture. It is unlikely that jatropha can be cultivated in the
United States economically or sustainably, and the possibility of
importing jatropha oil or biodiesel from producing countries is very
uncertain because overseas cultivation efforts are still underdeveloped
and initial volumes will likely be used domestically. As a result, we
have not projected the use of jatropha as a feedstock under our control
case. For more detail on the potential use of jatropha refer to Section
1.1 of the DRIA.
c. Other Advanced Biofuel
    As defined in EISA, advanced biofuel means renewable fuel, other
than ethanol derived from corn starch, that has lifecycle greenhouse
gas emissions, as determined by the Administrator, that are at least
50% less than baseline lifecycle greenhouse gas emissions. As described
more fully in Section VI.D, we are proposing that the GHG threshold for
advanced biofuels be adjusted to 44% or potentially as low as 40%
depending on the results from the analyses that will be conducted for
the final rule. As defined in EISA, advanced biofuel includes the
cellulosic biofuel, biomass-based diesel, and co-processed renewable
diesel categories that were mentioned in Sections V.A.2.a and V.A.2.b
above. However, EISA requires greater volumes of advanced biofuel than
just the volumes required of these fuels; see Table V.A.2-1. It is
entirely possible that greater volumes of cellulosic biofuel, biomass-
based diesel, and co-processed renewable diesel than required by EISA
could be produced in the future. Our control case, however, does not
assume that cellulosic biofuel and biomass-based diesel volumes will
exceed those required under EISA.\55\ As a result, to meet the total
advanced biofuel volume required under EISA, advanced biofuel types are
needed other than cellulosic biofuel, biomass-based diesel, and co-
processed renewable diesel through 2022.
---------------------------------------------------------------------------

    \55\ While cellulosic biofuel will not be limited by feedstock
availability, it likely will be limited by the very aggressive ramp
up in production volume for an industry which is still being
demonstrated on the pilot scale and therefore is not yet
commercially viable. On the other hand, biomass-based diesel derived
from agricultural oils and animal fats are faced with relatively
high feedstock costs which limit feedstock supply.
---------------------------------------------------------------------------

    We have assumed for our control case that the most likely source of
advanced fuel other than cellulosic biofuel, biomass-based diesel, and
co-processed renewable diesel would be from imported sugarcane
ethanol.\56\ Our assessment of international fuel ethanol production
and demand indicate that anywhere from 3.8-4.2 Bgal of sugarcane
ethanol from Brazil could be available for export by 2020/2022. If this
volume were to be made available to the U.S., then there would be
sufficient volume to meet the advanced biofuel standard. To calculate
the amount of imported ethanol needed to meet the EISA standards, we
took the difference between the total advanced biofuel category and
cellulosic biofuel, biomass-based diesel, and co-processed renewable
diesel categories. The amount of imported ethanol required by 2022 is
approximately 3.2 Bgal. We solicit comment on our estimate of 3.2 Bgal
and whether or not it is reasonable to assume that Brazil (or any other
country) could satisfy this demand.
---------------------------------------------------------------------------

    \56\ This analysis was conducted prior to the completion of our
lifecycle analysis discussed in Section VI, and assumes the fuel
will meet the required GHG threshold.
---------------------------------------------------------------------------

    Recent news indicates that there are also plans for sugarcane
ethanol to be produced in the U.S in places where the sugar subsidy
does not apply. For instance, sugarcane has been grown in California's
Imperial Valley specifically for the purpose of making ethanol and
using the cane's biomass to generate electricity to power the ethanol
distillery as well as export excess electricity to the electric
grid.\57\ There are at least two projects being developed at this time
that could result in several

[[Page 24982]]

hundred million gallons of ethanol produced. The sugarcane is being
grown on marginal and existing cropland that is unsuitable for food
crops and will replace forage crops like alfalfa, Bermuda grass, Klein
grass, etc. Harvesting is expected to be fully mechanized. Thus, there
is potential for these projects and perhaps others to help contribute
to the EISA biofuels mandate. This could lower the volume needed to be
imported from Brazil.
---------------------------------------------------------------------------

    \57\ Personal communication with Nathalie Hoffman, Managing
Member of California Renewable Energies, LLC, August 27, 2008.
---------------------------------------------------------------------------

    Butanol is another potential motor vehicle fuel which could be
produced from biomass and used in lieu of ethanol to comply with the
RFS2 standard. Production of butanol is being pursued by a number of
companies including a partnership between BP and Dupont. Other
companies which have expressed the intent to produce biobutanol are
Baer Biofuels and Gevo. The near term technology being pursued for
producing butanol involves fermentation of starch compounds, although
it can also be produced from cellulose. Butanol has several inherent
advantages compared to ethanol. First, it has higher energy density
than ethanol which would improve fuel economy (mpg). Second, butanol is
much less water soluble which may allow the butanol to be blended in at
the refinery and the resulting butanol-gasoline blend then more easily
shipped through pipelines. This would reduce distribution costs
associated with ethanol's need to be shipped separately from its
gasoline blendstock and also save on the blending costs incurred at the
terminal. Third, butanol can be blended in higher concentrations than
10% which would likely allow butanol to be blended with gasoline at
high enough concentrations to avoid the need for most or all of high
concentration ethanol-gasoline blends, such as E85, that require the
use of fuel flexible vehicles. For example, because of butanol's lower
oxygen content, it can be blended at 16% (by volume) to match the
oxygen concentration of ethanol blended at 10% (by volume).\58\ Because
of butanol's higher energy density, when blending butanol at 16% by
volume, it is the renewable fuels equivalent to blending ethanol at
about 20 percent. Thus, butanol would enable achieving most of the RFS2
standard by blending a lower concentration of renewable fuel than
having to resort to a sizable volume of E85 as in the case of ethanol.
As pointed out in Section V.D., the need to blend ethanol as E85
provides some difficult challenges. The use of butanol may be one means
of avoiding these blending difficulties.
---------------------------------------------------------------------------

    \58\ To obtain EPA approval for butanol blends as high as 16% by
volume would require that the butanol be blended with an approved
corrosion inhibitor.
---------------------------------------------------------------------------

    At the same time, butanol has a couple of less desirable aspects
relative to ethanol. First, butanol is lower in octane compared to
ethanol--ethanol has a very high blending octane of around 115, while
butanol's octane ranges from 87 octane numbers for normal butanol and
94 octane numbers for isobutanol. Potential butanol producers are
likely to pursue producing isobutanol over normal butanol because of
isobutanol's higher octane content. Higher octane is a valuable
attribute of any gasoline blendstock because it helps to reduce
refining costs. A second negative property of butanol is that it has a
much higher viscosity compared to either gasoline or ethanol. High
viscosity makes a fuel harder to pump, and more difficult to atomize in
the combustion chamber in an internal combustion engine. The third
downside to butanol is that it is more expensive to produce than
ethanol, although the higher production cost is partially offset by its
higher energy density.
    Another potential source of renewable transportation fuel is
biomethane refined from biogas. Biogas is a term meaning a combustible
mixture of methane and other light gases derived from biogenic sources.
It can be combusted directly in some applications, but for use in
highway vehicles it is typically purified to closely resemble fossil
natural gas for which the vehicles are typically designed. The
definition of biogas as given in EISA is sufficiently broad to cover
combustible gases produced by biological decomposition of organic
matter, as in a landfill or wastewater treatment facility, as well as
those produced via thermochemical decomposition of biomass.
    Currently, the largest source of biogas is landfill gas collection,
where the majority of fuel is combusted to generate electricity, with a
small portion being upgraded to methane suitable for use in heavy duty
vehicle fleets. Current literature suggests approximately 16 billion
gasoline gallons equivalent of biogas (referring to energy content)
could potentially be produced in the long term, with about two thirds
coming from biomass gasification and about one third coming from waste
streams such as landfills and human and animal sewage
digestion.59 60
---------------------------------------------------------------------------

    \59\ National Renewable Energy Laboratory estimate based on
biomass portion available at $45-$55/dry ton. Using POLYSYS Policy
Analysis System, Agricultural Policy Analysis Center, University of
Tennessee. http://www.agpolicy.org/polysys.html.  Accessed May 2008.
    \60\ Milbrandt, A., ``Geographic Perspective on the Current
Biomass Resource Availability in the United States.'' 70 pp., NREL
Report No. TP-560-39181, 2005.
---------------------------------------------------------------------------

    Because the majority of the biogas volume estimates assume biomass
as a feedstock, we have chosen not to include this fuel in our analyses
since we are projecting most available biomass will be used for
cellulosic liquid biofuel production in the long term. The remaining
biogas potentially available from waste-related sources would come from
a large number of small streams requiring purification and connection
to storage and/or distribution facilities, which would involve
significant economic hurdles. An additional and important source of
uncertainty is whether there would be a sufficient number of vehicles
configured to consume these volumes of biogas. Thus, we expect future
biogas fuel streams to continue to find non-transportation uses such as
electrical power generation or facility heating.
d. Other Renewable Fuel
    The remaining portion of total renewable fuel not met with advanced
biofuel is assumed to come from corn-based ethanol. EISA effectively
sets a limit for participation in the RFS program of 15 Bgal of corn
ethanol by 2022. It should be noted, however, that there is no specific
``corn-ethanol'' mandated volume, and that any advanced biofuel
produced above and beyond what is required for the advanced biofuel
requirements could reduce the amount of corn ethanol needed to meet the
total renewable fuel standard. This occurs in our projections during
the earlier years (2009-2014) in which we project that some fuels could
compete favorably with corn ethanol (e.g. biodiesel and imported
ethanol). Beginning around 2015, fuels qualifying as advanced biofuels
likely will be devoted to meeting the increasingly stringent volume
mandates for advanced biofuel. It is also worth noting that more than
15 Bgal of corn ethanol could be produced and RINs generated for that
volume under our proposed RFS2 regulations. However, obligated parties
would not be required to purchase more than 15 Bgal worth of corn ethanol RINs.
    We are assuming for our analysis that sufficient corn ethanol will
be produced to meet the 15 Bgal limit. However, this assumes that in
the future corn ethanol production is not limited due to environmental
constraints, such as water quantity issues (see Section 6.10 of the
DRIA). This also assumes that in

[[Page 24983]]

the future either corn ethanol plants are constructed or modified to
meet the 20% GHG threshold, or that sufficient corn ethanol production
exists that is grandfathered and not required to meet the 20%
threshold. Our current projection is that up to 15 Bgal could be
grandfathered, but actual volumes will be determined at the time of
facility registration. Refer to Section 1.5.1.4 of the DRIA for more
information. Since our current lifecycle analysis estimates that much
of the current corn ethanol would not meet the 20% GHG reduction
threshold required of non-grandfathered facilities without facility
upgrades, then if actual grandfathered corn volumes are less than 15
Bgal it may be necessary to meet the volume mandate with other
renewable fuels or through the use of advanced technologies that could
improve the corn ethanol lifecycle GHG estimates.

B. Renewable Fuel Production

1. Corn/Starch Ethanol
    The majority of domestic biofuel production currently comes from
plants processing corn and other similarly-processed grains in the
Midwest. However, there are a handful of plants located outside the
Corn Belt and a few plants processing simple sugars from food or
beverage waste. In this section, we will summarize the present state of
the corn/starch ethanol industry and discuss how we expect things to
change in the future under the proposed RFS2 program.
a. Historic/Current Production
    The United States is currently the largest ethanol producer in the
world. In 2008, the U.S. produced almost nine billion gallons of fuel
ethanol for domestic consumption, the majority of which came from
locally-grown corn.\61\ Although the U.S. ethanol industry has been in
existence since the 1970s, it has rapidly expanded over the past few
years due to the phase-out of methyl tertiary butyl ether (MTBE),\62\
elevated crude oil prices, state mandates and tax incentives, the
introduction of the Federal Volume Ethanol Excise Tax Credit
(VEETC),\63\ and the implementation of the existing RFS1 program.\64\
As shown in Figure V.B.1-1, U.S. ethanol production has grown
exponentially over the past decade.
---------------------------------------------------------------------------

    \61\ Based on total transportation ethanol reported in EIA's
March 2009 Monthly Energy Review (Table 10.2) less imports (http://
tonto.eia.doe.gov/dnav/pet/hist/mfeimus1a.htm).
    \62\ For more information on how the phase-out of MTBE helped
spur ethanol production/consumption, refer to Section V.D.1.
    \63\ On October 22, 2004, President Bush signed into law H.R.
4520, the American Jobs Creation Act of 2004 (JOBS Bill), which
created the Volumetric Ethanol Excise Tax Credit (VEETC). The $0.51/
gal VEETC for ethanol blender replaced the former fuel excise tax
exemption, blender's credit, and pure ethanol fuel credit. However,
the recently-enacted 2008 Farm Bill modifies the alcohol credit so
that corn ethanol gets a reduced credit of $0.45/gal and cellulosic
biofuel a credit of $1.01/gal effective January 1, 2009.
    \64\ On May 1, 2007, EPA published a final rule (72 FR 23900)
implementing the Renewable Fuel Standard (RFS) required by EPAct.
The RFS requires that 4.0 billion gallons of renewable fuel be
blended into gasoline/diesel by 2006, growing to 7.5 billion gallons by 2012.
    \65\ Based on total transportation ethanol reported in EIA's
March 2009 Monthly Energy Review (Table 10.2) less imports (http://
tonto.eia.doe.gov/dnav/pet/hist/mfeimus1a.htm).
[GRAPHIC] [TIFF OMITTED] TP26MY09.004


[[Page 24984]]

    As of April 1, 2009, there were 169 corn/starch ethanol plants
operating in the U.S. with a combined estimated production capacity of
10.5 billion gallons per year.\66\ This does not include a number of
ethanol plants that are currently idled.\67\ The majority of today's
ethanol (over 91% by volume) is produced exclusively from corn. Another
8% comes from a blend of corn and/or similarly processed grains (milo,
wheat, or barley) and less than half a percent is produced from cheese
whey, waste beverages, and sugars/starches combined. A summary of U.S.
ethanol production by feedstock is presented in Table V.B.1-1.
---------------------------------------------------------------------------

    \66\ Our April 2009 corn/starch ethanol industry
characterization was based on a variety of sources including:
Renewable Fuels Association (RFA) Ethanol Biorefinery Locations
(updated March 31, 2009); Ethanol Producer Magazine (EPM) Producing
plant list (last modified on April 7, 2009), and ethanol producer
Web sites. The baseline does not include ethanol plants whose
primary business is industrial or food-grade ethanol production nor
does it include plants that might be located in the Virgin Islands
or U.S. territories. Where applicable, current/historic production
levels have been used in lieu of nameplate capacities to estimate
production capacity. The April 2009 information presented in this
section reflects our most recent knowledge of the corn/starch
ethanol industry. However, for various NPRM impact analyses, an
earlier May 2008 industry assessment was used. For more on this
assessment, refer to Section 1.5.1.5 of the DRIA.
    \67\ In addition to idled plants, the assessment does not
include idled production capacity at facilities that are currently
operating at 50% or less than their nameplate capacity.

                   Table V.B.1-1--Current Corn/Starch Ethanol Production Capacity by Feedstock
----------------------------------------------------------------------------------------------------------------
                                                                Capacity    Percent of   Number of    Percent of
           Plant feedstock (Primary listed first)                 MGY        capacity      plants       plants
----------------------------------------------------------------------------------------------------------------
Corn \a\....................................................        9,605         91.2          144         85.2
Corn, Milo \b\..............................................          717          6.8           14          8.3
Corn, Wheat.................................................          130          1.2            1          0.6
Milo........................................................            3          0.0            1          0.6
Wheat, Milo.................................................           50          0.5            1          0.6
Cheese Whey.................................................            5          0.0            1          0.6
Waste Beverages \c\.........................................           19          0.2            5          3.0
Waste Sugars & Starches \d\.................................            7          0.1            2          1.2
                                                             ---------------------------------------------------
    Total...................................................       10,535          100          169          100
----------------------------------------------------------------------------------------------------------------
\a\ Includes one facility processing seed corn, two facilities also operating pilot-level cellulosic ethanol
  plants at these locations, and four facilities planning on incorporating cellulosic feedstocks in the future.
\b\ Includes one facility processing a small amount of molasses in addition to corn and milo.
\c\ Includes two facilities processing brewery waste.
\d\ Includes one facility processing potato waste that intends to add corn in the future.

    As shown in Table V.B.1-1, of the 169 operating plants, 161 process
corn and/or other similarly processed grains. Of these facilities, 150
utilize dry-milling technologies and the remaining 11 plants rely on
wet-milling processes. Dry mill ethanol plants grind the entire kernel
and generally produce only one primary co-product: Distillers grains
with solubles (DGS). The co-product is sold wet (WDGS) or dried (DDGS)
to the agricultural market as animal feed. However, there are a growing
number of dry mill ethanol plants pursuing front-end fractionation or
back-end extraction to produce fuel-grade corn oil for the biodiesel
industry. There are also additional plants pursuing cold starch
fermentation and other energy-saving processing technologies. For more
on the dry-milling and wet-milling processes as well as emerging
advanced technologies, refer to Section 1.4 of the DRIA.
    In contrast to dry mill plants, wet mill facilities separate the
kernel prior to processing into its component parts (germ, fiber,
protein, and starch) and in turn produce other co-products (usually
gluten feed, gluten meal, and food-grade corn oil) in addition to DGS.
Wet mill plants are generally more costly to build but are larger in
size on average.\68\ As such, 11.5% of the current grain ethanol
production comes from the 11 previously-mentioned wet mill facilities.
The remaining eight plants which process cheese whey, waste beverages
or sugars/starches, operate differently than their grain-based
counterparts. These small production facilities do not require milling
and operate a simpler enzymatic fermentation process.
---------------------------------------------------------------------------

    \68\ According to our April 2009 corn ethanol plant assessment,
the average wet mill plant capacity was 111 million gallons per
year--almost twice that of the average dry mill plant capacity (62
million gallons per year). For more on average plant sizes, refer to
Section 1.5.1.1 of the DRIA.
---------------------------------------------------------------------------

    Ethanol production is a relatively resource-intensive process that
requires the use of water, electricity, and steam.\69\ Steam needed to
heat the process is generally produced on-site or by other dedicated
boilers.\70\ The ethanol industry relies primarily on natural gas. Of
today's 169 ethanol production facilities, 142 burn natural gas \71\
(exclusively), three burn a combination of natural gas and biomass, one
recently started burning a combination of natural gas, landfill biogas
and wood, and two burn a combination of natural gas and syrup from the
process. In addition, 20 plants burn coal as their primary fuel and one
burns a combination of coal and biomass. Our research suggests that 25
plants currently utilize cogeneration or combined heat and power (CHP)
technology, although others may exist. CHP is a mechanism for improving
overall plant efficiency. Whether owned by the ethanol facility, their
local utility, or a third party, CHP facilities produce their own
electricity and use the waste heat from power production for process
steam, reducing the energy intensity of ethanol production.\72\ A
summary of the energy sources and CHP technology utilized by today's
ethanol plants is found in Table V.B.1-2.
---------------------------------------------------------------------------

    \69\ For more information on plant energy requirements, refer to
Section 1.5.1.3 of the DRIA.
    \70\ We are also aware of a couple plants that pull steam
directly from a nearby utility.
    \71\ Facilities were assumed to burn natural gas if the plant
boiler fuel was unspecified or unavailable on the public domain.
    \72\ For more on CHP technology, refer to Section 1.4.1.3 of the DRIA.

[[Page 24985]]

                 Table V.B.1-2--Current Corn/Starch Ethanol Production Capacity by Energy Source
----------------------------------------------------------------------------------------------------------------
                                                   Capacity    Percent of   Number of    Percent of
   Plant energy source (primary listed first)        MGY        capacity      plants       plants     CHP tech.
----------------------------------------------------------------------------------------------------------------
Coal \a\.......................................        1,868         17.7           20         11.8            9
Coal, Biomass..................................           50          0.5            1          0.6            0
Natural Gas \b\................................        8,294         78.7          142         84.0           15
Natural Gas, Biomass \c\.......................          113          1.1            3          1.8            1
Natural Gas, Landfill Biogas, Wood.............          110          1.0            1          0.6            0
Natural Gas, Syrup.............................          101          1.0            2          1.2            0
                                                ----------------------------------------------------------------
    Total......................................       10,535        100.0          169        100.0           25
----------------------------------------------------------------------------------------------------------------
\a\ Includes four plants that are permitted to burn biomass, tires, petroleum coke, and wood waste in addition
  to coal and one facility that intends to transition to biomas in the future.
\b\ Includes one facility that intends to switch to biomass, one facility that intends to burn thin stillage
  biogas, and two facilities that might switch to coal in the future.
\c\ Includes one facility processing bran in addition to natural gas.

    Since the majority of ethanol is made from corn, it is no surprise
that most of the plants are located in the Midwest near the Corn Belt.
Of today's 169 ethanol production facilities, 151 are located in the 15
states comprising PADD 2. For a map of the Petroleum Administration for
Defense Districts or PADDs, refer to Figure V.B.1-2.
[GRAPHIC] [TIFF OMITTED] TP26MY09.005

    As a region, PADD 2 accounts for 94% (or almost 10 billion gallons)
of today's estimated ethanol production capacity, as shown in Table
V.B.1-3. For more information on today's ethanol plants and a detailed
map of their locations, refer to Section 1.5 of the DRIA.

                     Table V.B.1-3--Current Corn/Starch Ethanol Production Capacity by PADD
----------------------------------------------------------------------------------------------------------------
                                                                Capacity    Percent of   Number of    Percent of
                            PADD                                  MGY        capacity      plants       plants
----------------------------------------------------------------------------------------------------------------
PADD 1......................................................          150          1.4            3          1.8
PADD 2......................................................        9,900         94.0          151         89.3
PADD 3......................................................          194          1.8            3          1.8
PADD 4......................................................          160          1.5            7          4.1
PADD 5......................................................          131          1.2            5          3.0
                                                             ---------------------------------------------------
    Total...................................................       10,535        100.0          169        100.0
----------------------------------------------------------------------------------------------------------------

    The U.S. ethanol industry is currently comprised of a mixture of
company-owned plants and locally-owned farmer cooperatives (co-ops).
The majority of today's ethanol production facilities are company-
owned, and on average these plants are larger in size than farmer-owned
co-ops. Accordingly, company-owned plants account for more than 79% of
today's ethanol production capacity.\73\ Furthermore, 30% of the total
domestic product comes from 38 plants owned by just three different
companies--POET Biorefining, Archer Daniels Midland (ADM), and Valero
Renewables.\74\
---------------------------------------------------------------------------

    \73\ Farmer-owned plant status derived from Renewable Fuels
Association (RFA), Ethanol Biorefinery Locations (updated March 31,
2009). For more on average plant sizes, refer to Section 1.5.1 of
the DRIA.
    \74\ Valero recently entered into the renewable fuels business
by acquiring five idled corn ethanol plants and one construction
site formerly owned by VeraSun Energy Corporation. Valero has since
purchased two more idled VeraSun plants, but they have not been
brought back online yet.

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

[[Page 24986]]

b. Forecasted Production Under RFS2
    As highlighted above, 10.5 billion gallons of corn/starch ethanol
plant capacity was online as of April 1, 2009. So even if no additional
capacity was added, U.S. ethanol production would grow from 2008 to
2009, provided facilities continue to operate at or above today's
production levels. And despite today's temporary unfavorable market
conditions (i.e., low ethanol market values), we expect the ethanol
industry will continue to expand in the future under RFS2. Although
there is not a set corn ethanol standard, EISA allows for 15 billion
gallons of the 36-billion gallon renewable fuel standard to be met by
conventional biofuels. And we expect that corn and other sugar or
starch-based ethanol will fulfill this requirement. Furthermore, we
project that all new corn/starch ethanol plant capacity brought online
under RFS2 would either meet the conventional biofuel GHG threshold
requirement \75\ or meet the grandfathering requirement (for more
information, refer to Section 1.5.1.4 of the DRIA).
---------------------------------------------------------------------------

    \75\ The lifecycle assessment values which assume a 2% discount
rate over a 100-year timeframe.
---------------------------------------------------------------------------

    In addition to the 169 corn/starch ethanol plants that are
currently online today, 36 plants are presently idled. Some of these
constructed facilities (namely smaller ethanol plants) have been idled
for quite some time, whereas other plants have just recently been put
into ``hot idle'' mode. A number of ethanol producers (e.g., VeraSun)
are idling operations, putting projects on hold, selling off plants,
and even filing for Chapter 11 bankruptcy. In addition, we are aware of
two facilities that are currently operating at 50% or less than their
nameplate capacity. As crude oil and gasoline prices rise again in the
future, corn ethanol production will become more viable again and we
expect that these plants will resume operations. At the time of our
April 2009 ethanol industry assessment, there were also 19 new ethanol
plants under construction in the U.S, and two plant expansion projects
underway. While many of these projects are also on hold due to the
current economic conditions, we expect these facilities will eventually
come online under the RFS2 program. A summary of the projected industry
growth is found in Table V.B.1-4.\76\
---------------------------------------------------------------------------

    \76\ Idled plants and construction projects based on Renewable
Fuels Association (RFA) Ethanol Biorefinery Locations (updated March
31, 2009); Ethanol Producer Magazine (EPM) Not Producing and Under
Construction plant lists (last modified on April 7, 2009), ethanol
producer Web sites, and follow-up correspondence with ethanol
producers. It is worth noting that for our industry assessment,
``under construction'' implies that more than just a ground breaking
ceremony has taken place.

                             Table V.B.1-4--Potential Industry Expansion Under RFS2
----------------------------------------------------------------------------------------------------------------
                                                           Growth in ethanol production
                                 -------------------------------------------------------------------------------
                                      Plants                            New
                                     currently     Idled plants/   construction      Expansion         Total
                                      online       capacity \a\      projects        projects
----------------------------------------------------------------------------------------------------------------
Plant Capacity (MGY)............          10,535           2,471           1,955              80          15,042
Total No. of Plants.............             169              36              19               2             226
----------------------------------------------------------------------------------------------------------------
\a\ Includes the idled plant capacity of the two facilities that are currently operating at 50% or less than
  nameplate capacity.

    While theoretically it only takes 12 to 18 months to build an
ethanol plant,\77\ the rate at which new plant capacity comes online
will be dictated by market conditions, which will in part be influenced
by the RFS2 requirements. As mentioned above, today's proposed program
will create a growing demand for corn ethanol reaching 15 billion
gallons by 2015. However, it is possible that market conditions could
drive demand even higher. Whether the nation will overcomply with the
corn ethanol standard is uncertain and will be determined by feedstock
availability/pricing, crude oil pricing, and the relative ethanol/
gasoline price relationship. To measure the impacts of the proposed
RFS2 program, we assumed that corn ethanol production would not exceed
15 billion gallons. We also assumed that all growth would come from new
plants or plant expansion projects (in addition to idled plants being
brought back online).\78\ However, it is possible that some of the
growth could come from minor process improvements (e.g.,
debottlenecking) at existing facilities.
---------------------------------------------------------------------------

    \77\ For more information on plant build rates, refer to Section
1.2.5 of the RIA.
    \78\ For our NPRM impact analyses, we relied on an earlier May
2008 industry assessment. For more information, refer to Section
1.5.1.5 of the DRIA.
---------------------------------------------------------------------------

    Once all the aforementioned projects are complete, we project that
there would be 226 corn/starch ethanol plants operating in the U.S.
with a combined production capacity of around 15 billion gallons per
year. Much like today's ethanol industry, the overwhelming majority of
new production capacity (93% by volume) is expected to come from corn-
fed plants. Another 7% is forecasted to come from plants processing a
blend of corn and other grains, and a very small increase is projected
to come from idled cheese whey and waste beverage plants coming back
online. A summary of the forecasted ethanol production by feedstock
under the RFS2 program is found in Table V.B.1-5.

               Table V.B.1-5--Projected RFS2 Corn/Starch Ethanol Production Capacity by Feedstock
----------------------------------------------------------------------------------------------------------------
                                                                Additional production      Total RFS2 estimate
                                                             ---------------------------------------------------
           Plant feedstock (primary listed first)               Capacity    Number of     Capacity    Number of
                                                                  MGY         plants        MGY         plants
----------------------------------------------------------------------------------------------------------------
Corn \a\....................................................        4,197           49       13,802          193
Corn, Milo \b\..............................................          185            3          902           17
Corn, Wheat.................................................            8            1          138            2
Corn, Wheat, Milo...........................................          110            2          110            2
Milo........................................................            0            0            3            1
Wheat, Milo.................................................            0            0           50            1

[[Page 24987]]

Cheese Whey.................................................            3            1            8            2
Waste Beverages \c\.........................................            4            1           23            6
Waste Sugars & Starches \d\.................................            0            0            7            2
                                                             ---------------------------------------------------
    Total...................................................        4,507           57       15,042          226
----------------------------------------------------------------------------------------------------------------
\a\ Includes one facility processing seed corn, another facility processing small amounts of whey, two
  facilities also operating pilot-level cellulosic ethanol plants at these locations, and four facilities
  planning on incorporating cellulosic feedstocks in the future.
\b\ Includes one facility processing a small amount of molasses in addition to corn and milo.
\c\ Includes two facilities processing brewery waste.
\d\ Includes one facility processing potato waste that intends to add corn in the future.

    Based on current industry plans, the majority of additional corn/
grain ethanol production capacity (almost 84% by volume) is predicted
to come from new or expanded plants burning natural gas.\79\
Additionally, we are forecasting one new plant and a reopening of
another plant relying on manure biogas. We are also predicting
expansions at three coal-fired ethanol plants.\80\ Of the 55 new
ethanol plants, our research indicates that five would utilize
cogeneration, bringing the total number of CHP facilities to 30. A
summary of the projected near-term ethanol plant energy sources is
found in Table V.B.1-6.
---------------------------------------------------------------------------

    \79\ Facilities were assumed to burn natural gas if the plant
boiler fuel was unspecified or unavailable on the public domain.
    \80\ Two of the three coal-fired plant expansions appear as new
plants in Table V.B.1-6. This is because two of the expansion
projects consist of adding dry milling plant capacity to an existing
wet mill plant. However, our interpretation is that these facilities
will rely on the same (potentially expanded) coal-fired boilers for
process steam. Since all the aforementioned coal-fired ethanol
production facilities appear to have commenced construction prior to
December 19, 2007, we project that the ethanol produced at these
facilities will be grandfathered under the proposed RFS2 rule. For
more on our grandfathered volume estimate, refer to Section 1.5.1.4
of the DRIA.

           Table V.B.1-6--Projected Near-Term Corn/Starch Ethanol Production Capacity by Energy Source
----------------------------------------------------------------------------------------------------------------
                                                   Additional production            Total RFS2 estimate
                                                ----------------------------------------------------------------
   Plant energy source (primary listed first)      Capacity    Number of     Capacity    Number of
                                                     MGY         plants        MGY         plants     CHP tech.
----------------------------------------------------------------------------------------------------------------
Coal \a\.......................................          610            2        2,478           22           11
Coal, Biomass..................................            0            0           50            1            0
Manure Biogas..................................          134            2          134            2            0
Natural Gas \b\................................        3,763           53       12,056          195           18
Natural Gas, Biomass \c\.......................            0            0          113            3            1
Natural Gas, Landfill Biogas, Wood.............            0            0          110            1            0
Natural Gas, Syrup.............................            0            0          101            2            0
                                                ----------------------------------------------------------------
    Total......................................        4,507           57       15,042          226           30
----------------------------------------------------------------------------------------------------------------
\a\ Includes six plants that are permitted to burn biomass, tires, petroleum coke, and wood waste in addition to
  coal and one facility that intends to transition to biomass in the future.
\b\ Includes one facility that intends to switch to biomass, one facility that intends to burn thin stillage
  biogas, and six facilities that might switch to coal in the future.
\c\ Includes one facility processing bran in addition to natural gas.

    The information in Table V.B.1.6 is based on short-term industry
production plans at the time of our April 1, 2009 plant assessment.
However, we are anticipating growth in advanced ethanol production
technologies under the proposed RFS2 program. We project that fuel
prices will drive a large number of corn ethanol plants to transition
from conventional boiler fuels to advanced biomass-based feedstocks. We
also believe that fossil fuel/electricity prices will drive a number of
ethanol producers to pursue CHP technology. For more on our projected
2022 utilization of these technologies under the RFS2 program, refer to
Section 1.5.1.3 of the DRIA.
    Under the proposed RFS2 program, the majority of new ethanol
production is expected to originate from PADD 2, close to where most of
the corn is grown. However, there are a number of ``destination''
ethanol plants being built outside the Midwest in response to
production subsidies, E10/E85 retail pump incentives, and state
mandates. A summary of the forecasted ethanol production by PADD under
the RFS2 program can be found in Table V.B.1-7.

[[Page 24988]]

                  Table V.B.1-7--Projected RFS2 Corn/Starch Ethanol Production Capacity by PADD
----------------------------------------------------------------------------------------------------------------
                                                                Additional production      Total RFS2 Estimate
                                                             ---------------------------------------------------
                            PADD                                Capacity    Number of     Capacity    Number of
                                                                  MGY         plants        MGY         plants
----------------------------------------------------------------------------------------------------------------
PADD 1......................................................          178            3          328            6
PADD 2......................................................        3,566           43       13,466          194
PADD 3......................................................          350            4          544            7
PADD 4......................................................           50            1          210            8
PADD 5......................................................          363            6          494           11
                                                             ---------------------------------------------------
    Total...................................................        4,507           57       15,042          226
----------------------------------------------------------------------------------------------------------------

2. Cellulosic Biofuel
    Ethanol currently dominates U.S. biofuel production, and more
specifically, ethanol produced from corn and other grains. However,
cellulosic feedstocks have the potential to greatly expand domestic
ethanol production, both volumetrically and geographically. It is also
possible to produce synthetic diesel fuel from cellulosic feedstocks
(also known as ``cellulosic diesel'') through a Fischer-Tropsch
gasification process or a thermal depolymerization process. We are also
aware of one company using live bacteria to break down biomass and
produce cellulosic diesel and other petroleum replacements. Before
wide-scale commercialization of cellulosic biofuel can occur in today's
marketplace, technical and logistical barriers must be overcome. In
addition to today's RFS2 program which sets aggressive goals for all
ethanol production, the Department of Energy (DOE) and other federal
and state agencies are helping to spur industry growth.
a. Current Production/Plans
    The cellulosic biofuel industry is essentially in its infancy. With
the exception of a 20 million-gallon-per year cellulosic diesel plant
recently opened by Cello Energy in Bay Minette, AL, the majority of
facilities in operation today are small pilot- or demonstration-level
plants. Most of these facilities operate intermittently and produce
insignificant volumes of biofuel. Some researchers are focusing on
processing corn residues, e.g., corn stover, cobs, and/or fiber. Some
are focusing on other agricultural residues such as sugarcane bagasse,
rice and wheat straw. Others are looking at waste products such as
forestry residues, citrus residues, pulp or paper mill waste, municipal
solid waste (MSW), and construction and demolition (C&D) debris.
Dedicated energy crops including switchgrass and poplar trees are also
being investigated.
    Based on an April 2009 assessment of information available on the
public domain, there are currently 25 pilot- and demonstration-level
(or smaller) cellulosic ethanol plants operating in the United States.
However, only 9 of these plants report measurable volumes of ethanol
production. In addition, we are aware of one pilot-level cellulosic
diesel plant in addition to the commercial-level Cello Energy
plant.\81\ A summary of these 11 facilities totaling just over 23
million gallons of annual production capacity is provided in Table
V.B.2-1. The date listed in the table indicates when the facility first
began operations. For more on the existing cellulosic ethanol and
diesel plants, refer to Sections 1.5.3.1 and 1.5.3.3 of the DRIA.
---------------------------------------------------------------------------

    \81\ Our April 2009 cellulosic ethanol industry characterization
was based on researching DOE- and USDA-supported projects, plants
referenced in HART's Ethanol & Biodiesel News (through the April 14,
2009 issue), plants included on the Cellulosic Ethanol Site (http://
www.thecesite.com/ ), and plants referenced on other biofuel industry
Web sites.

                                Table V.B.2-1--Existing Cellulosic Biofuel Plants
----------------------------------------------------------------------------------------------------------------
                                                                                   Prod     Est.
  Company or organization name             Location              Feedstocks        cap      Op.     Conv. tech.
                                                                                  (MGY)     date        \a\
----------------------------------------------------------------------------------------------------------------
Cellulosic Ethanol
----------------------------------------------------------------------------------------------------------------
Abengoa Bioenergy Corporation     York, NE.................  Wheat straw, corn      0.02   Sep-07  Bio.
 \b\.                                                         stover, energy
                                                              crops.
Bioengineering Resources, Inc.    Fayetteville, AR.........  MSW, wood waste,       0.04     1998  Therm.
 (BRI).                                                       coal.
BPI & Universal Entech..........  Phoenix, AZ..............  Paper waste            0.01     2004  Bio.
                                                              (sorted MSW).
Gulf Coast Energy...............  Livingston, AL...........  Wood waste (sorted     0.20   Dec-08  Therm.
                                                              MSW).
Mascoma Corporation.............  Rome, NY.................  Wood chips........     0.20   Feb-09  Bio.
POET Project Bell \b\...........  Scotland, SD.............  Corn cobs & fiber.     0.02   Jan-09  Bio.
Verenium........................  Jennings, LA.............  Sugarcane bagasse.     0.05     2006  Bio.
Verenium........................  Jennings, LA.............  Sugarcane bagasse,     1.50   Feb-09  Bio.
                                                              wood, energy cane.
Western Biomass Energy LLC.       Upton, WY................  Wood waste             1.50     2007  Bio.
 (WBE).                                                       (softwood).
----------------------------------------------------------------------------------------------------------------
Cellulosic Diesel
----------------------------------------------------------------------------------------------------------------
Cello Energy....................  Bay Minette, AL..........  Wood chips, hay...    20.00   Dec-08  CatDep.
Bell BioEnergy..................  Fort Stewart, GA.........  Wood chips........     0.01   Dec-08  Bact.
----------------------------------------------------------------------------------------------------------------
                              Total Existing Production Capacity £23 MGY
----------------------------------------------------------------------------------------------------------------
\a\ Bio = biochemical pre-treatment, Therm = thermochemical conversion, CatDep = catalytic depolymerization,
  Bact = involves the use of live bacteria to break down biomass for cellulosic diesel production.
\b\ Cellulosic pilot plant is collocated with a corn ethanol plant.

[[Page 24989]]

    To date, the majority of cellulosic ethanol research has focused on
biochemical pre-treatment technologies, i.e., the use of acids and/or
enzymes to break down cellulosic materials into fermentable sugars.
However, there are a growing number of companies investigating the
thermochemical pathway which involves gasification of biomass into a
synthesis gas or pyrolysis of biomass into a bio-crude oil for
processing. Cellulosic diesel can also be made from thermochemical as
well as other processes. Many companies are also researching the
potential of co-firing biomass to produce plant energy in addition to
biofuels. For more on cellulosic biofuel processing technologies, refer
to Section 1.4.3 of the DRIA.
    In addition to the existing facilities in Table V.B.2-1, our April
2009 industry assessment suggests that there are currently three
cellulosic ethanol plants under construction in the United States. Like
the existing plants, two are pilot-level facilities that are still
working towards proving their conversion technologies. However, Range
Fuels, a company that received $76 million from DOE and an $80 loan
guarantee from USDA to build one of the first commercial-scale
cellulosic ethanol plants in the U.S., is currently building a 40
million gallon per year plant in Soperton, GA.\82\ At this time, the
company is just working on the initial 10 million gallon per year
phase. Bell Bioenergy, a company that received $7.5 million in funding
from the Department of Defense to convert biomass into cellulosic
diesel using live bacteria, also has six pilot plants under
construction in various locations through the country. A summary of
these nine cellulosic biofuel plants, totaling over 10 million gallons
of annual production capacity, is presented in Table V.B.2-2.
---------------------------------------------------------------------------

    \82\ Range Fuels' ultimate goal is to expand the Soperton, GA
facility to produce 100 million gallons of cellulosic ethanol per year.
---------------------------------------------------------------------------

    As shown in Tables V.B.2-1 and V.B.2-2, unlike corn ethanol
production, which is primarily located in the Midwest near the Corn
Belt, cellulosic biofuel production is spread throughout the country.
The geographic distribution of plants is due to the wide variety and
availability of cellulosic feedstocks. Corn stover is found primarily
in the Midwest, while the Pacific Northwest, the Northeast, and the
Southeast all have forestry residues. Some southern states have access
to sugarcane bagasse and citrus waste while MSW and C&D debris are
available in highly populated areas throughout the country. For more
information on cellulosic feedstock availability, refer to Section
1.1.2 of the DRIA.

                      Table V.B.2-2--Cellulosic Biofuel Plants Currently Under Construction
----------------------------------------------------------------------------------------------------------------
                                                                                   Prod     Est.
       Company plant name                  Location              Feedstocks        cap      op.     Conv. tech.
                                                                                  (MGY)    date.        \a\
----------------------------------------------------------------------------------------------------------------
Cellulosic Ethanol
----------------------------------------------------------------------------------------------------------------
Coskata.........................  Madison, PA..............  MSW, natural gas,      0.04   Jul-09  Therm.
                                                              woodchips,
                                                              bagasse,
                                                              switchgrass.
DuPont Dansico Cellulosic         Vonore, TN...............  Corn cobs then         0.25   Dec-09  Bio.
 Ethanol (DDCE).                                              switchgrass.
Range Fuels \b\.................  Soperton, GA.............  Wood waste,           10.00   Dec-09  Therm.
                                                              switchgrass.
----------------------------------------------------------------------------------------------------------------
Cellulosic Diesel
----------------------------------------------------------------------------------------------------------------
Bell Bio-Energy.................  Fort Lewis, WA...........  Cellulose.........     0.01     2009  Bact.
Bell Bio-Energy.................  Fort Drum, NY............  Cellulose.........     0.01     2009  Bact.
Bell Bio-Energy.................  Fort AP Hill, VA.........  Cellulose.........     0.01     2009  Bact.
Bell Bio-Energy.................  Fort Bragg, NC...........  Cellulose.........     0.01     2009  Bact.
Bell Bio-Energy.................  Fort Benning, GA.........  Cellulose.........     0.01     2009  Bact.
Bell Bio-Energy.................  San Pedro, CA............  Cellulose.........     0.01     2009  Bact.
----------------------------------------------------------------------------------------------------------------
                         Total Under Construction Production Capacity £10 MGY
----------------------------------------------------------------------------------------------------------------
\a\ Bio = biochemical pre-treatment, Therm = thermochemical conversion, Bact = involves the use of live bacteria
  to break down biomass for cellulosic diesel production.
\b\ The first 10 MGY phase is currently under construction in Soperton, GA. Once this second 30 MGY phase is
  added, the plant will be capable of producing 40 MGY of cellulosic ethanol.

    Increased public interest, government support, technological
advancement, and the recently-enacted EISA have helped spur many plans
for new cellulosic biofuel plants. Although more and more plants are
being announced, most are limited in size and contingent upon
technology breakthroughs and efficiency improvements at the pilot or
demonstration level. Additionally, because cellulosic biofuel
production has not yet been proven on the commercial level, financing
of these projects has primarily been through venture capital and
similar funding mechanisms, as opposed to conventional bank loans.
    Consequently, recently-announced Federal grant and loan guarantee
programs may serve as a significant asset to the cellulosic biofuel
industry in this area. In February 2007, DOE announced that it would
invest up to $385 million in six commercial-scale ethanol projects over
the next four years. Since the announcement, two of the companies have
forfeited their funding. Iogen has decided to locate its first
commercial-scale plant in Canada and Alico has discontinued plans to
produce ethanol all together. The four remaining ``pioneer'' plants
(including Range Fuels) hold promise and could very well be some of the
first plants to demonstrate the commercial-scale viability of
cellulosic ethanol production. However, there is still more to be
learned at the pilot level. Although technologies needed to convert

[[Page 24990]]

cellulosic feedstocks into ethanol (and diesel) are becoming more and
more understood, there are still a number of efficiency improvements
that need to occur before cellulosic biofuels can compete in today's marketplace.
    In May 2007, DOE announced that it would provide up to $200 million
to help fund small-scale cellulosic biorefineries experimenting with
novel processing technologies that could later be expanded to
commercial production facilities. Four recipients were announced in
January 2008 and three more were announced in April 2008. Three months
later, DOE announced that it would provide $40 million more to help
fund two additional small-scale plants. Of the nine announced small-
scale plants, seven were pursuing cellulosic ethanol production
(including Verenium Corp.) and two are pursuing cellulosic diesel
production. However, Lignol Innovations, recently suspended plans to
build a 2.5 million gallon per year cellulosic ethanol plant in Grand
Junction, CO due to market uncertainty.
    The Department of Energy has also introduced a loan guarantee
program to help reduce risk and spur investment in projects that employ
new, clean energy technologies. In October 2007, DOE issued final
regulations and invited 16 project sponsors who submitted pre-
applications to submit full applications for loan guarantees. Of those
who were invited to participate, five were pursuing cellulosic biofuel
production. However, only three companies appear to still be
eligible.\83\ Of the three remaining companies, two are pursuing
cellulosic ethanol production (and are also DOE grant recipients) and
one is pursuing cellulosic diesel production. The U.S. Department of
Agriculture is also providing an $80 million loan guarantee to Range
Fuels to help support construction of its 40 million-gallon-per-year
cellulosic ethanol plant in Soperton, GA. For more on information on
Federal support for biofuel production, refer to Section 1.5.3 of the DRIA.
---------------------------------------------------------------------------

    \83\ Iogen and Alico have also forfeited a potential loan
guarantee from DOE.
---------------------------------------------------------------------------

    In addition to the companies receiving government funding, there
are a growing number of privately-funded companies (including Cello
Energy) with plans to build more cellulosic biofuel plants in the
United States. These facilities range in size from pilot- and
demonstration-level plants (similar to those currently operational or
under construction), to small commercial plants (similar to the four
commercial-scale plants receiving DOE funding), to large commercial
plants (similar in size to an average corn ethanol plant). These
projects are also at various stages of planning. According to our April
2009 industry assessment, 11 plants are currently at advanced stages of
planning and likely to go online in the near future. Along with those
plants currently operational or under construction, we believe that
these facilities will enable the U.S. to meet the 100 million gallon
cellulosic biofuel standard in 2010. For a summary of the plants and
their respective projected contributions, refer to Table V.B.2-3 below.
For a greater discussion on these and other cellulosic biofuel
projects, refer to Section 1.5.3.1 of the DRIA.

                         Table V.B.2-3--Projected Cellulosic Biofuel Production in 2010
----------------------------------------------------------------------------------------------------------------
                                                                                                        Est 2010
                                                                                            Est. 2010    ETOH-
   Company or organization name            Location         Prod cap      Est. op. date      million     equiv.
                                                             (MGY)                           gallons    million
                                                                                                        gallons
----------------------------------------------------------------------------------------------------------------
Cellulosic Ethanol
----------------------------------------------------------------------------------------------------------------
BPI & Universal Entech............  Phoenix, AZ..........       0.01  Online..............       0.01       0.01
POET Project Bell.................  Scotland, SD.........       0.02  Online..............       0.02       0.02
Abengoa Bioenergy Corporation.....  York, NE.............       0.02  Online..............       0.02       0.02
Bioengineering Resources, Inc.      Fayetteville, AK.....       0.04  Online..............       0.04       0.04
 (BRI).
Verenium..........................  Jennings, LA.........       0.05  Online..............       0.05       0.05
Gulf Coast Energy.................  Livingston, AL.......       0.20  Online..............       0.20       0.20
Mascoma Corporation...............  Rome, NY.............       0.20  Online..............       0.20       0.20
Verenium..........................  Jennings, LA.........       1.50  Online..............       1.50       1.50
Western Biomass Energy, LLC. (WBE)  Upton, WY............       1.50  Online..............       1.50       1.50
Coskata...........................  Madison, PA..........       0.04  Jul-09..............       0.04       0.04
DuPont Dansico Cellulosic Ethanol   Vonore, TN...........       0.25  Dec-09..............       0.25       0.25
 (DDCE).
Range Fuels.......................  Soperton, GA.........       10.0  Dec-09..............       10.0       10.0
Ecofin/Alltech....................  Springfield, KY......       1.30  2010................       0.65       0.65
Fulcrum Bioenergy.................  Storey County, NV....      10.50  2010................       5.25       5.25
ICM Inc...........................  St. Joseph, MO.......       1.50  2010................       0.75       0.75
RSE Pulp & Chemical...............  Old Town, ME.........       2.20  2010................       1.10       1.10
ZeaChem...........................  Boardman, OR.........       1.50  2010................       0.75       0.75
ClearFuels Technology.............  Kauai, HI............       1.50  End of 2010.........       0.38       0.38
Southeast Renewable Fuels LLC.....  Clewiston, FL........      20.00  End of 2010.........       5.00       5.00
----------------------------------------------------------------------------------------------------------------
Cellulosic Diesel
----------------------------------------------------------------------------------------------------------------
Cello Energy......................  Bay Minette, AL......      20.00  Online..............      20.00      32.00
Bell Bio-Energy...................  Fort Stewart, GA.....       0.01  2008................       0.01       0.01
Bell Bio-Energy...................  Fort Lewis, WA.......       0.01  2009................       0.01       0.01
Bell Bio-Energy...................  Fort Drum, NY........       0.01  2009................       0.01       0.01
Bell Bio-Energy...................  Fort AP Hill, VA.....       0.01  2009................       0.01       0.01
Bell Bio-Energy...................  Fort Bragg, NC.......       0.01  2009................       0.01       0.01
Bell Bio-Energy...................  Fort Benning, GA.....       0.01  2009................       0.01       0.01
Bell Bio-Energy...................  San Pedro, CA........       0.01  2009................       0.01       0.01

[[Page 24991]]

Cello Energy......................  TBD (AL).............      50.00  2010................      16.67      26.67
Cello Energy......................  TBD (AL).............      50.00  2010................      16.67      26.67
Cello Energy......................  TBD (GA).............      50.00  2010................      16.67      26.67
Flambeau River Biofuels...........  Park Falls, WI.......       6.00  2010................       3.00       4.80
                                   -----------------------------------------------------------------------------
    Total 2010 Production Forecast  .....................  .........  ....................     100.74     144.57
----------------------------------------------------------------------------------------------------------------

b. Federal/State Production Incentives
    In addition to helping fund a series of small-scale cellulosic
biofuel plants, the Department of Energy, along with the U.S.
Department of Agriculture (USDA), is also helping to fund critical
research to help make cellulosic biofuel production more commercially
viable. In March 2007, DOE awarded $23 million in grants to four
companies and one university to develop more efficient microbes for
ethanol refining. In June 2007, DOE and USDA awarded $8.3 million to 10
universities, laboratories, and research centers to conduct genomics
research on woody plant tissue for bioenergy. Later that same month,
DOE announced plans to spend $375 million to build three bioenergy
research centers dedicated to accelerating research and development of
cellulosic ethanol and other biofuels. The centers, which will each
focus on different feedstocks and biological research challenges, will
be located in Oak Ridge, TN, Madison, WI, and Berkeley, CA. In December
2007, DOE awarded $7.7 million to one company, one university, and two
research centers to demonstrate the thermochemical conversion process
of turning grasses, stover, and other cellulosic materials into
biofuel. In February 2008, DOE awarded another $33.8 million to three
companies and one research center to support the development of
commercially-viable enzymes to support cellulose hydrolysis, a critical
step in the biochemical breakdown of cellulosic feedstocks. Finally, in
March 2008, DOE and USDA awarded $18 million to 18 universities and
research institutes to conduct research and development of biomass-
based products, biofuels, bioenergy, and related processes. Since 2007,
DOE has announced more than $1 billion and since 2006, USDA has
invested almost $600 million for the research, development, and
demonstration of new biofuel technology.
    Numerous states are also offering grants, tax incentives, and loan
guarantees to help encourage biofuel production. The majority of
efforts are centered on expanding ethanol production, and more
recently, cellulosic ethanol production.\84\ According to a July 2008
assessment of DOE's Energy Efficiency and Renewable Energy (EERE) Web
site,\85\ 33 states currently offer some form of ethanol production
incentive. The incentives range from support for ethanol producers to
support for research and development companies to support for feedstock
suppliers. Kansas, Maryland, and South Carolina each offer specific
incentives towards cellulosic ethanol production. Kansas offers revenue
bonds through the Kansas Development Finance Authority to help fund
construction or expansion of a cellulosic ethanol plant. Additionally,
these newly-built or expanded facilities are exempt from state property
tax for 10 years. Maryland offers a credit towards state income tax for
10% of cellulosic ethanol research and development expenses. They also
have a $0.20 per gallon production credit for cellulosic ethanol. South
Carolina gives a $0.30 per gallon production credit to cellulosic
ethanol producers that meet certain requirements.
---------------------------------------------------------------------------

    \84\ For more on state-level biodiesel production incentives,
refer to Section 1.5.4 of the DRIA.
    \85\ The database of ethanol incentives and laws by state is
available at: http://www.eere.energy.gov/afdc/ethanol/incentives_
laws.html.
---------------------------------------------------------------------------

    In addition to individual state incentives, a group of states in
the Midwest have joined together to pursue ethanol and other biofuel
production and usage goals as part of the Midwest Energy Security and
Climate Stewardship Platform.\86\ As of June 2008, Indiana, Iowa,
Kansas, Michigan, Minnesota, North Dakota, Ohio, South Dakota, and
Wisconsin had all committed to these goals which emphasize energy
independence through the growth of cellulosic ethanol production and
availability of E85. The Platform goals are to produce cellulosic
ethanol on a commercial level by 2012 and to have E85 offered at one-
third of refueling stations by 2025. They also want to reduce the
energy intensity of ethanol production and supply 50% of their
transportation fuel needs by regionally produced biofuels by 2025.
---------------------------------------------------------------------------

    \86\ Midwest Governors Association, ``Energy Security and
Climate Stewardship Platform for the Midwest 2007'' (http://
www.midwesterngovernors.org/resolutions/Platform.pdf )
---------------------------------------------------------------------------

    Finally, the passage of the Food, Conservation, and Energy Act of
2008 (also known as the ``2008 Farm Bill'') is also helping to spur
cellulosic ethanol production and use.\87\ The 2008 Farm Bill modified
the existing $0.51 per gallon alcohol blender credit to give preference
to ethanol and other biofuels produced from cellulosic feedstocks. Corn
ethanol now receives a reduced credit of $0.45/gal while cellulosic
biofuel earns a credit of $1.01/gal.\88\ The 2008 Farm Bill also has
provisions that enable USDA to assist with the commercialization of
second-generation biofuels. Section 9003 authorizes loan guarantees for
the development, construction and retrofitting of commercial scale
biorefineries. Section 9004 provides payments to biorefineries to
replace fossil fuels with renewable biomass. Section 9005 provides
payments to producers to support and ensure production of advanced
biofuels. And finally, Section 9008 provides competitive grants,
contracts and financial assistance to enable eligible entities to carry
out research, development, and demonstration of biofuels and biomass-
based based products. For more information on the Federal and state
production incentives outlined in this subsection, refer to Section
1.5.3.2 of the DRIA.
---------------------------------------------------------------------------

    \87\ The Food, Conservation, and Energy Act of 2008 (http://
www.usda.gov/documents/Bill_6124.pdf)
    \88\ Refer to Part II, Subparts A and B (Sections 15321 and
15331).
---------------------------------------------------------------------------

c. Feedstock Availability
    A wide variety of feedstocks can be used for cellulosic ethanol
production, including: Agricultural residues,

[[Page 24992]]

forestry biomass, municipal solid waste, construction and demolition
waste, and energy crops. These feedstocks are much more difficult to
convert into ethanol than traditional starch/corn crops or at least
require new and different processes because of the more complex
structure of cellulosic material.
    One potential barrier to commercially viable cellulosic biofuel
production is high feedstock cost. As such, fuel producers will seek to
acquire inexpensive feedstocks in sufficient quantities to lower their
production costs and the risk of feedstock supply shortages. At least
initially, the focus will be on feedstocks that are readily available,
already produced or collected for other reasons, and even waste biomass
which currently incurs a disposal fee. Consequently, initial volumes of
cellulosic biofuels may benefit from low-cost feedstocks. However, to
reach 16 Bgal will likely require reliance on more expensive feedstock
sources purposely grown and or harvested for conversion into cellulosic biofuel.
    To determine the likely cellulosic feedstocks for production of 16
billion gallons cellulosic biofuel by 2022, we analyzed the data and
results from various sources. Sources include agricultural modeling
from the Forestry Agriculture Sector Optimization Model (FASOM) to
establish the most economical agriculture residues and energy crops
(see Section IX for more details on the FASOM), consultation with USDA-
Forestry Sector experts for forestry biomass supply curves, and
feedstock assessment estimates for urban waste.\89\
---------------------------------------------------------------------------

    \89\ It is important to note that our plant siting analysis for
cellulosic ethanol facilities used the most current version of
outputs from FASOM at the time, which was from April 2008. Since
then, FASOM has been updated to reflect better assumptions.
Therefore, the version used for the NPRM in Section IX on economic
impacts is slightly different than the one we used here. We do not
believe that the differences between the two versions are enough to
have a major impact on the plant siting analysis.
---------------------------------------------------------------------------

    An important assumption in our analysis projecting which feedstocks
will be used for producing cellulosic ethanol is that an excess of
feedstock would have to be available for producing the biofuel. Banks
are anticipated to require excess feedstock supply as a safety factor
to ensure that the plant will have adequate feedstock available for the
plant, despite any feedstock emergency, such as a fire, drought,
infestation of pests etc. For our analysis we assumed that twice the
feedstock of MSW, C&D waste, and forest residue would have to be
available to justify the building of a cellulosic ethanol plant. For
corn stover, we assumed 50% more feedstock than necessary. We used a
lower safety factor for corn stover because it could be possible to
remove a larger percentage of the corn stover in any given year
(usually only 50% or less of corn stover is assumed to be sustainably
removed in any one year).\90\ As a result, our projected cellulosic
facilities only consume a portion of the total supply of feedstock
available. After a cellulosic facility is fully established and certain
risks are reduced, it is entirely possible that the facility may choose
to consume excess feedstock in order to expand production. In addition,
more facilities could potentially be built if financial investors
required less excess supply. Since we are assessing the impact of
producing 16 Bgal of cellulosic biofuel by 2022, this analysis does not
project the construction of more facilities or more feedstocks consumed
than necessary.
---------------------------------------------------------------------------

    \90\ The FASOM results do not take into consideration these
feedstock safety margins. Safety margins were used, however, for the
plant siting analysis described in Section V.B.2.c.v.
---------------------------------------------------------------------------

    Another assumption that we made is that if multiple feedstocks are
available in an area, each would be used as feedstocks for a
prospective cellulosic ethanol plant. For example, a particular area
might comprise a small or medium sized city, some forest and some
agricultural land. We would include the MSW and C&D wastes available
from the city along with the corn stover and forest residue for
projecting the feedstock that would be processed by the particular
cellulosic ethanol plant.
    The following subsections describe the availability of various
cellulosic feedstocks and the estimated amounts from each feedstock
needed to meet the EISA requirement of 16 Bgal of cellulosic biofuel by
2022. Refer to Section V.B.2.c.iv for the summarized results of the
types and volumes of cellulosic feedstocks chosen based on our analyses.
i Urban Waste
    Cellulosic feedstocks available at the lowest cost to the ethanol
producer will likely be chosen first. This suggests that urban waste
which is already being gathered today and which incurs a fee for its
disposal may be among the first to be used. Urban wood wastes are used
in a variety of ways. Most commonly, wastes are ground into mulch,
dumped into land-fills, or incinerated with other municipal solid waste
(MSW) or construction and demolition (C&D) debris. Urban wood wastes
include a variety of wood resources such as wood-based municipal solid
waste and wood debris from construction and demolition.
    MSW consists of paper, glass, metals, plastics, wood, yard
trimmings, food scraps, rubber, leather, textiles, etc. The portion of
MSW containing cellulosic material and typically the focus for biofuel
production is wood and yard trimmings. In addition, paper, which made
up approximately 34% of the total MSW generated in 2006, could
potentially be converted to cellulosic biofuel.\91\ Food scraps could
also be converted to cellulosic biofuel, however, it was noted by an
industry group that this feedstock could be more difficult to convert
to biofuel due to challenges with separation, storage, transport, and
degradation of the materials. Although recycling/recovery rates are
increasing over time, there appears to still be a large fraction of
biogenic material that ends up unused and in land-fills. C&D debris is
typically not available in wood waste assessments, although some have
estimated this feedstock based on population. In 1996, this was
estimated to be approximately 124 million metric tons of C&D
debris.\92\ Only a portion of this, however, would be made of woody
material. Utilization of such feedstocks could help generate energy or
biofuels for transportation. However, despite various assessments on
urban waste resources, there is still a general lack of reliable data
on delivered prices, issues of quality (potential for contamination),
and lack of understanding of potential competition with other
alternative uses (e.g. recycling, burning for electricity).
---------------------------------------------------------------------------

    \91\ EPA. Municipal Solid Waste Generation, Recycling, and
Disposal in the United States: Facts and Figures for 2006.
    \92\ Fehrs, J., ``Secondary Mill Residues and Urban Wood Waste
Quantities in the United States--Final Report,'' Northeast Regional
Biomass Program Washington, DC, December 1999.
---------------------------------------------------------------------------

    We estimated that 42 million dry tons of MSW (wood and yard
trimmings & paper) and C&D wood waste could be available for producing
biofuels after factoring in several assumptions (e.g. percent
contamination, percent recovered or combusted for other uses, and
percent moisture).93 94 We assumed that approximately 25
million dry tons (of the total 42 million dry tons) would be used.
However, many areas of the U.S. (e.g. much of the Rocky Mountain
States) have such sparse resources that a MSW and C&D cellulosic
facility would not likely be justifiable. We did assume that in areas
with other

[[Page 24993]]

cellulosic feedstocks (forest and agricultural residue), that the MSW
would be used even if the MSW could not justify the installation of a
plant on its own. Therefore, we have estimated that urban waste could
help contribute to the production of approximately 2.2 billion gallons
of ethanol.\95\ A more detailed discussion on this analysis is included
in the DRIA Chapter 1. Subsequent to initiating our analysis, however,
we realized that the revised renewable biomass definition in the
statute may preclude the use of most MSW. See Section III.B.4 for a
discussion of renewable biomass. When the definition of renewable
biomass is finalized, it could preclude the use of some of the lowest
cost potential feedstocks, including waste paper and C&D waste, for use
in producing cellulosic biofuel for use toward the RFS2 standard. If
this is the case, then our FRM analysis will be adjusted to reflect this.
---------------------------------------------------------------------------

    \93\ Wiltsee, G., ``Urban Wood Waste Resource Assessment,''
NREL/SR-570-25918, National Renewable Energy Laboratory, November 1998.
    \94\ Biocycle, ``The State of Garbage in America,'' Vol. 47, No.
4, 2006, p. 26.
    \95\ Assuming 90 gal/dry ton ethanol conversion yield for urban
waste in 2022.
---------------------------------------------------------------------------

    In addition to MSW and C&D waste generated from normal day-to-day
activities, there is also potential for renewable biomass to be
generated from natural disasters. This includes diseased trees, other
woody debris, and C&D debris. For instance, Hurricane Katrina was
estimated to have damaged approximately 320 million large trees.\96\
Katrina also generated over 100 million tons of residential debris, not
including the commercial sector. The material generated from these
situations could potentially be used to generate cellulosic biofuel.
While we acknowledge this material could provide a large source in the
short-term, natural disasters are highly variable, making it hard to
predict future volumes that could be generated. We seek comment on how
to take into account such estimates to be included in future feedstock
availability analyses.
---------------------------------------------------------------------------

    \96\ Chambers, J., ``Hurricane Katrina's Carbon Footprint on
U.S. Gulf Coast Forests'' Science Vol. 318, 2007.
---------------------------------------------------------------------------

ii. Agricultural and Forestry Residues
    The next category of feedstocks chosen will likely be those that
are readily produced but have not yet been commercially collected. This
includes both agricultural and forestry residues.
    Agricultural residues are expected to play an important role early
on in the development of the cellulosic ethanol industry due to the
fact that they are already being grown. Agricultural crop residues are
biomass that remains in the field after the harvest of agricultural
crops. The most common residue types include corn stover (the stalks,
leaves, and/or cobs), straw from wheat, rice, barley, or oats, and
bagasse from sugarcane. The eight leading U.S. crops produce more than
500 million tons of residues each year, although only a fraction can be
used for fuel and/or energy production due to sustainability and
conservation constraints.\97\ Crop residues can be found all over the
United States, but are primarily concentrated in the Midwest since corn
stover accounts for half of all available agricultural residues.
---------------------------------------------------------------------------

    \97\ Elbehri, Aziz. USDA, ERS. ``An Evaluation of the Economics
of Biomass Feedstocks: A Synthesis of the Literature. Prepared for
the Biomass Research and Development Board,'' 2007; Since 2007, a
final report has been released. Biomass Research and Development
Board, ``The Economics of Biomass Feedstocks in the United States: A
Review of the Literature,'' October 2008.
---------------------------------------------------------------------------

    Agricultural residues play an important role in maintaining and
improving soil quality, protecting the soil surface from water and wind
erosion, helping to maintain nutrient levels, and protecting water
quality. Thus, collection and removal of agricultural residues must
take into account concerns about the potential for increased erosion,
reduced crop productivity, depletion of soil carbon and nutrients, and
water pollution. Sustainable removal rates for agricultural residues
have been estimated in various studies, many showing tremendous
variability due to local differences in soil and erosion conditions,
soil type, landscape (slope), tillage practices, crop rotation
managements, and the use of cover crops. One of the most recent studies
by top experts in the field showed that under current rotation and
tillage practices, about 30% of stover (about 59 million metric tons)
produced in the U.S. could be collected, taking into consideration
erosion, soil moisture concerns, and nutrient replacement costs.\98\
The same study showed that if farmers chose to convert to no-till corn
management and total stover production did not change, then
approximately 50% of stover (100 million metric tons) could be
collected without causing erosion to exceed the tolerable soil loss.
This study, however, did not consider possible soil carbon loss which
other studies indicate may be a greater constraint to environmentally
sustainable feedstock harvest than that needed to control water and
wind erosion.\99\ Experts agree that additional studies are needed to
further evaluate how soil carbon and other factors affect sustainable
removal rates. Despite unclear guidelines for sustainable removal rates
due to the uncertainties explained above, our agricultural modeling
analysis assumes that 0% of stover is removable for conventional tilled
lands, 35% of stover is removable for conservation tilled lands, and
50% is removable for no-till lands. In general, these removal
guidelines are appropriate only for the Midwest, where the majority of
corn is currently grown.
---------------------------------------------------------------------------

    \98\ Graham, R.L., ``Current and Potential U.S. Corn Stover
Supplies,'' American Society of Agronomy 99:1-11, 2007.
    \99\ Wilhelm, W.W. et. al., ``Corn Stover to Sustain Soil
Organic Carbon Further Constrains Biomass Supply,'' Agron. J.
99:1665-1667, 2007.
---------------------------------------------------------------------------

    As already noted, removal rates will vary within regions due to
local differences. Given the current understanding of sustainable
removal rates, we believe that such assumptions are reasonably
justified. We invite comment on these assumptions. Based on our
research we also note that residue maintenance requirements for the
amount of biomass that must remain on the land to ensure soil quality
is another approach for modeling sustainable residue collection
quantities, therefore we also invite comment on this approach. This
approach would likely be more accurate for all landscapes as site
specific conditions such as soil type, topography, etc. could be taken
into account. This would prevent site specific soil erosion and soil
quality concerns that would inevitably exist when using average values
for residue removal rates across all soils and landscapes. At the time
of our analyses we had limited data on which to accurately apply this
approach and therefore assumed the removal guidelines based on tillage
practices. Refer to the Section 1.1 of the DRIA for more discussion on
sustainable removal rates.
    Some of the challenges of relying on agricultural residues to
produce biofuels include the development of the technology and
infrastructure for the harvesting of biomass crops. For example, it may
be possible to reduce costs by harvesting the corn stover at the same
time that the corn is harvested, in a single pass operation, as opposed
to two separate harvests. In addition, because agricultural residues
are usually harvested only one time per year, but cellulosic ethanol
plants must receive the feedstock throughout the year, agricultural
residues would likely need to be stored at a secondary storage
facility. The transportation and storage issues and costs associated
with this secondary storage will add additional costs to using
agricultural residue as cellulosic plant feedstock. These significant
transportation and storage issues need to be resolved and the
infrastructure built before agricultural

[[Page 24994]]

residues can supply a steady stream of feedstock to the biorefinery. We
discuss these harvesting and storage challenges in Section 1.3 of the DRIA.
    Our agricultural modeling (FASOM) suggests that corn stover will
make up the majority of agricultural residues used by 2022 to meet the
EISA cellulosic biofuel standard (approximately 83 million dry tons
used to produce 7.8 billion gallons of cellulosic ethanol).\100\
Smaller contributions are expected to come from other crop residues,
including bagasse (1.2 Bgal ethanol) and sweet sorghum pulp (0.1 Bgal
ethanol).\101\ At the time of this proposal, FASOM was able to model
agricultural residues but not forestry biomass as potential feedstocks.
As a result, we relied on USDA-Forest Service (FS) for information on
the forestry sector.
---------------------------------------------------------------------------

    \100\ Assuming 94 gal/dry ton ethanol conversion yield for corn
stover in 2022.
    \101\ Bagasse is a byproduct of sugarcane crushing and not
technically an agricultural residue. Sweet sorghum pulp is also a
byproduct of sweet sorghum processing. We have included it under
this heading for simplification due to sugarcane being an
agricultural feedstock.
---------------------------------------------------------------------------

    The U.S. has vast amounts of forest resources that could
potentially provide feedstock for the production of cellulosic biofuel.
One of the major sources of woody biomass could come from logging
residues. The U.S. timber industry harvests over 235 million dry tons
annually and produces large volumes of non-merchantable wood and
residues during the process.\102\ Logging residues are produced in
conventional harvest operations, forest management activities, and
clearing operations. In 2004, these operations generated approximately
67 million dry tons/year of forest residues that were left uncollected
at harvest sites.\103\ Other feedstocks include those from other
removal residues, thinnings from timberland, and primary mill residues.
---------------------------------------------------------------------------

    \102\ Smith, W. Brad et. al., ``Forest Resources of the United
States, 2002 General Technical Report NC-241,'' St. Paul, MN: U.S.
Dept. of Agriculture, Forest Service, North Central Research Station, 2004.
    \103\ USDA-Forest Service. ``Timber Products Output Mapmaker
Version 1.0.'' 2004.
---------------------------------------------------------------------------

    Harvesting of forestry residue and other woody material can be
conducted throughout the year. Thus, unlike agricultural residue which
must be moved to secondary storage, forest material could be ``stored
on the stump.'' Avoiding the need for secondary storage and the
transportation costs for moving the feedstock there potentially
provides a significant cost advantage for forest residue over
agricultural residue. This could allow forest residue to be transported
from further distances away from the cellulosic plant compared to
agricultural residue at the same feedstock price. Section 1.1 of the
DRIA further details some of challenges with using forestry biomass as
a feedstock.
    EISA does not allow forestry material from national forests and
virgin forests that could be used to produce biofuels to count towards
the renewable fuels requirement under EISA. Therefore, we required
forestry residue estimates that excluded such material. Most recently,
the USDA-FS provided forestry biomass supply curves for various sources
(i.e., logging residues, other removal residues, thinnings from
timberland, etc.). This information suggested that a total of 76
million dry tons of forest material could be available for producing
biofuels (excluding forest biomass material contained in national
forests as required under EISA). However, much of the forest material
is in small pockets of forest which because of its regional low
density, could not help to justify the establishment of a cellulosic
ethanol plant. After conducting our feedstock availability analysis, we
estimated that approximately 44 million dry tons of forest material
could be used, which would make up approximately one fourth, or 3.8
billion gallons, of the 16 billion gallons of cellulosic biofuel
required to meet EISA.
iii Dedicated Energy Crops
    While urban waste, agricultural residues, and forest residues will
likely be the first feedstocks used in the production of cellulosic
biofuel, there may be limitations to their use due to land availability
and sustainable removal rates. Energy crops which are not yet grown
commercially but have the potential for high yields and a series of
environmental benefits could help provide additional feedstocks in the
future. Dedicated energy crops are plant species grown specifically as
renewable fuel feedstocks. Various perennial plants have been
researched as potential dedicated feedstocks. These include switchgrass,
mixed prairie grasses, hybrid poplar, miscanthus, and willow trees.
    Perennials have several benefits over many major agricultural crops
(the majority of which are annual plants). First, energy crops based on
perennial species are grown from roots or rhizomes that remain in the
soil after harvests. This reduces annual field preparation and
fertilization costs. Second, perennial crops in temperate zones may
also have significantly higher total biomass yield per unit of land
area compared to annual species because of higher rates of net
photosynthetic CO₂ fixation into sugars. Third, lower
fertilizer runoff, lower soil erosion, and increased habitat diversity
are also attributes that make perennial crops more attractive than
annual crops.\104\ Finally, energy crops tend to store more carbon in
the soil compared to agricultural crops such as corn.\105\
---------------------------------------------------------------------------

    \104\ DOE., ``Breaking the Biological Barriers to Cellulosic
Ethanol: A Joint Research Agenda,'' 2006.
    \105\ Tolbert, V.R., et al., ``Biomass Crop Production: Benefits
for Soil Quality and Carbon Sequestration,'' March 1999.
---------------------------------------------------------------------------

    The introduction of dedicated energy crops could present some
potential risks, however. Dedicated energy crops for cellulosic
biofuels can be non-native to the region where their production is
proposed.\106\ As a result, these species may potentially escape
cultivation and damage surrounding ecosystems.\107\ In addition
breeding and genetic engineering to increase environmental tolerance,
increase harvestable biomass production, and enhance energy conversion
may have unexpected ecological consequences. To minimize such risks,
non-native species and non-wild-type native species (i.e. native
species after genetic modification) should be introduced in a
responsible manner and evaluated carefully in order to weigh the
potential risks against the benefits.
---------------------------------------------------------------------------

    \106\ Lewandowski, I., J. M. O. Scurlock, E. Lindvall, and M.
Chistou, ``The development and current status of perennial
rhizomatous grasses as energy crops in the U.S. and Europe,''
Biomass Bioenergy 25:335-361, 2003.
    \107\ The Council for Agricultural Science and Technology
(CAST), ``Biofuel Feedstocks: The Risk of Future Invasions,'' CAST
Commentary QTA2007-1. November 2007. Accessed at:
http://pdf.cast-science.org/websiteUploads/publicationPDFs/
Biofuels%20Commentary%20Web%20version%20with%20color%20%207927146.pdf

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

    Currently, an energy crop receiving much attention is switchgrass.
Switchgrass has many qualities that make it a prime cellulosic
feedstock option. However, switchgrass and other energy crops are not
currently harvested on a large scale. Switchgrass would likely be grown
on a 10-year crop rotation basis, with harvest beginning in year 1 or
2, depending on location. Because switchgrass and other dedicated
energy crops would not be harvested annually, there will be some
economic challenges in terms of price forecasting and contracts.
Accordingly, 10- to 15-year arrangements may be needed to stabilize the
market for energy crops.\108\ Despite these challenges, dedicated
energy crops are still projected to be needed in 2022 in order to meet
the aggressive goal of 16 Bgal of

[[Page 24995]]

cellulosic biofuel by 2022 as outlined in EISA.
---------------------------------------------------------------------------

    \108\ Zeman, N., ``Feedstock: Potential Players,'' Ethanol
Producer Magazine, October 2006.
---------------------------------------------------------------------------

    Since energy crops are not being grown today to make fuels, their
production and use depends on the development of a successful strategy.
One issue is that if they were to be grown on farmland currently used
to grow crops, the growth of switchgrass would have an opportunity cost
associated with the loss of agricultural production. For this reason,
energy crops may instead be grown on more marginal farm land such as
fallow farmland and farmland which has been converted over to prairie
grass. A study by Stanford and the Carnegie Institution found that 58
million hectares (145 million acres) of abandoned farmland would
potentially be available for growing energy crops here in the U.S.\109\
However, they also concluded that this land is marginal in quality and
thus the production per acre would be much lower compared to prime farm
land. Additionally, a substantial amount of this abandoned farm land is
a part of the Conservation Reserve Program (CRP). The CRP is the U.S.
Department of Agriculture's voluntary program that was established by
the Food Security Act of 1985 to provide farmers with a dependable
source of income, reduce erosion on unused farmland, and serve to
preserve wildlife and water quality.\110\ A large portion of the 36
million acres in the CRP land is currently planted with switchgrass and
mixed prairie grasses.\111\ However, the 2008 Farm Bill capped the
number of CRP acres at 32 million acres for 2010-2012, and we expect
that some of the CRP acres that are not re-enrolled will go into crop
production. While it may be possible to use some of the CRP acres to
produce biofuels from switchgrass and prairie grass, the potential loss
of the wildlife habitat and water quality benefits of CRP land would
have to be weighed against the potential use for this land for growing
energy crops. Also, a significant portion of the CRP land is wetlands
and likely could not be used for growing energy crops without impacting
water quality and wildlife.
---------------------------------------------------------------------------

    \109\ Campbell, J.E. at al., ``The global potential of bioenergy
on abandoned agriculture lands,'' Environ. Sci. Technology, 2008.
    \110\ Charles, Dan; ``The CRP: Paying Farmers not to Farm,''
National Public Radio, May 5, 2008.
    \111\ Farm Service Agency, ``Conservation Reserve Program,
Summary and Enrollment Statistics FY2006,'' May 2007.
---------------------------------------------------------------------------

    In addition to estimating the extent that agricultural residues
might contribute to cellulosic ethanol production, FASOM also estimated
the contribution that energy crops might provide.\112\ FASOM covers all
cropland and pastureland in production in the 48 conterminous United
States, however it does not contain all categories of grassland and
rangeland captured in USDA's Major Land Use data sets. Therefore, it is
possible there is land appropriate for growing dedicated energy crops
that is not currently modeled in FASOM. Furthermore, we constrained
FASOM to be consistent with the 2008 Farm Bill and assumed 32 million
acres would stay in CRP.\113\ These constraints on land availability
may have contributed to the model choosing a substantial amount of
agricultural residues mostly as corn stover and a relatively small
portion of energy crops as being economically viable feedstocks. The
use of other models, such as USDA's Regional Environment and
Agriculture Programming (REAP) model and University of Tennessee's
POLYSYS model, have shown that the use of energy crops in order to meet
EISA may be more significant than our current FASOM modeling
results.\114\ As such, we plan to revisit these land availability
assumptions in order to arrive at a more consistent basis for the FRM.
We request comment on these assumptions, in addition to all the
cellulosic yield assumptions that are contained in DRIA Chapter 1.
---------------------------------------------------------------------------

    \112\ Assuming 16 Bgal cellulosic biofuel total, 2.2 Bgal from
Urban Waste, and 3.8 Bgal from Forestry Biomass; 10 Bgal of
cellulosic biofuel for ag residues and/or energy crops would be needed.
    \113\ Beside the economic incentive of a farmer payment to keep
land in CRP, local environmental interests may also fight to
maintain CRP land for wildlife preservation. Also, we did not know
what portion of the CRP is wetlands which likely could not support
harvesting equipment.
    \114\ Biomass Research and Development Initiative (BR&DI),
``Increasing Feedstock Production for Biofuels: Economic Drivers,
Environmental Implications, and the Role of Research,'' 
http://www.brdisolutions.com  December 2008.
---------------------------------------------------------------------------

iv. Summary of Cellulosic Feedstocks for 2022
    Table V.B.2-4 summarizes our internal estimate of cellulosic
feedstocks and their corresponding volume contribution to 16 billion
gallons cellulosic biofuel by 2022 for the purposes of our impacts assessment.

    Table V.B.2-4--Cellulosic Feedstocks Assumed To Meet EISA in 2022
------------------------------------------------------------------------
                                                                 Volume
                          Feedstock                              (Bgal)
------------------------------------------------------------------------
Agricultural Residues........................................        9.1
    Corn Stover..............................................        7.8
    Sugarcane Bagasse........................................        1.2
    Sweet Sorghum Pulp.......................................        0.1
Forestry Biomass.............................................        3.8
Urban Waste..................................................        2.2
Dedicated Energy Crops (Switchgrass).........................        0.9
                                                              ----------
        Total................................................       16.0
------------------------------------------------------------------------

v. Cellulosic Plant Siting
    Future cellulosic biofuel plant siting was based on the types of
feedstocks that would be most economical as shown in Table V.B.2-4,
above. As cellulosic biofuel refineries will likely be located close to
biomass resources in order to take advantage of lower transportation
costs, we've assessed the potential areas in the U.S. that grow the
various feedstocks chosen. To do this, we used data on harvested acres
by county for crops that are currently grown today, such as corn stover
and sugarcane (for bagasse).\115\ In some cases, crops are not
currently grown, but have the potential to replace other crops or
pastureland (e.g. dedicated energy crops). We used the output from our
economic modeling (FASOM) to help us determine which types of land are
likely to be replaced by newly grown crops. For forestry biomass, USDA-
Forestry Service provided supply curve data by county showing the
available tons produced. Urban waste (MSW wood, paper, and C&D debris)
was estimated to be located near large population centers.
---------------------------------------------------------------------------

    \115\ NASS database. http://www.nass.usda.gov/.
---------------------------------------------------------------------------

    Using feedstock availability data by county/city, we located
potential cellulosic sites across the U.S. that could justify the
construction of a cellulosic plant facility. For more details on this
analysis, refer to Section 1.5 of the DRIA. Table V.B.2-5 shows the
volume of cellulosic facilities by feedstock by state projected for
2022. The total volumes given in Table V.B.2-5 match the total volumes
given in Table V.B.2-4 within a couple hundred million gallons. As
these differences are relatively small, we believe the cellulosic
facilities sited are a good estimate of potential locations.

[[Page 24996]]

                          Table V.B.2-5--Projected Cellulosic Ethanol Volumes by State
                                            [Million gallons in 2022]
----------------------------------------------------------------------------------------------------------------
                                                             Agricultural     Energy     Urban
                     State                         Total        residue        crop      waste       Forestry
                                                   volume       volume        volume     volume       volume
----------------------------------------------------------------------------------------------------------------
Alabama........................................        532               0          0        140             392
Arkansas.......................................        298               0          0          0             298
California.....................................        450               0          0        221             229
Colorado.......................................         28               0          0         28               0
Florida........................................        421             390          0         31               0
Georgia........................................        437               0          0         67             370
Illinois.......................................      1,525           1,270          0        198              58
Indiana........................................      1,109             948          0        101              60
Iowa...........................................      1,697           1,635          0         32              30
Kansas.........................................        310             250          0         29              32
Kentucky.......................................         70              70          0          0               0
Louisiana......................................      1,001             590          0        103             308
Maine..........................................        191               0          0          2             189
Michigan.......................................        505             283          0        171              51
Minnesota......................................        876             750          0         50              76
Mississippi....................................        214               0          0         22             192
Missouri.......................................        654             504          0         78              72
Montana........................................         92               0          0          9              83
Nebraska.......................................        956             851          0         31              75
Nevada.........................................         17               0          0         17               0
New Hampshire..................................        171               0         35         29             107
New York.......................................         72               0          0         72               0
North Carolina.................................        315               0          0         98             217
Ohio...........................................        598             410          0        156              32
Oklahoma.......................................        793               0        777          0              16
Oregon.........................................        244               0          0         44             200
Pennsylvania...................................         42               0          0         42               0
South Carolina.................................        213               0          0         57             156
South Dakota...................................        434             350          0          6              78
Tennessee......................................         97               0          0         19              78
Texas..........................................        576             300          0        131             145
Virginia.......................................        197               0          0         95             102
Washington.....................................        175               0          0         17             158
West Virginia..................................        149               0        101          0              48
Wisconsin......................................        581             432          0         43             106
                                                ----------------------------------------------------------------
    Total Volume...............................     16,039           9,034        913      2,139           3,955
----------------------------------------------------------------------------------------------------------------

    It is important to note, however, that there are many more factors
other than feedstock availability to consider when eventually siting a
plant. We have not taken into account, for example, water constraints,
availability of permits, and sufficient personnel for specific
locations. As many of the corn stover facilities are projected to be
located close to corn starch facilities, there is the potential for
competition for clean water supplies. Therefore, as more and more
facilities draw on limited resources, it may become apparent that
various locations are infeasible. Nevertheless, our plant siting
analysis provides a reasonable approximation for analysis purposes
since it is not intended to predict precisely where actual plants will
be located. Other work is currently being done that will help address
some of these issues, but at the time of this proposal, was not yet
available.\116\
---------------------------------------------------------------------------

    \116\ USDA, WGA, Bioenergy Strategic Assessment project findings
upcoming as noted in report WGA. Transportation Fuels for the Future
Biofuels: Part I. 2008.
---------------------------------------------------------------------------

    As we are projecting the location of cellulosic plants in 2022, it
is important to keep in mind the various uncertainties in the analysis.
For example, future analyses could determine better recommendations for
sustainable removal rates. In the case where lower removal rates are
recommended, agricultural residues may be more limited and could
require more growth in dedicated energy crops. Also, the feedstocks
could be processed in the field to a liquid by a pyrolysis process,
facilitating the ability to ship the preprocessed biomass to plants
located further away from the feedstock source. Given the information
we have to date, we believe our projected locations for cellulosic
facilities represent a reasonable forecast for estimating the impacts
of this rule.
3. Imported Ethanol
a. Historic World Ethanol Production and Consumption
    Although ethanol can be used for multiple purposes (fuel,
industrial, and beverage), fuel ethanol is by far the largest market,
accounting for about two-thirds of the total world ethanol consumed.
According to forecasts, fuel ethanol might even exceed 80% of the
market share by the end of the decade.\117\ In 2008, the top three fuel
ethanol producers were the U.S., Brazil, and the European Union (EU),
producing 9.0, 6.5, and 0.7 billion gallons, respectively.\118\ Other
countries that have produced ethanol include

[[Page 24997]]

China, Canada, Thailand, Colombia, and India.
---------------------------------------------------------------------------

    \117\ F.O. Licht., ``World Ethanol Markets: The Outlook to
2015'', 2006, pg. 21.
    \118\ Renewable Fuels Association (RFA), ``2007 World Fuel
Ethanol Production,'' http://www.ethanolrfa.org/industry/statistics/
#E,  March 31, 2009.
---------------------------------------------------------------------------

    Consumption of fuel ethanol, like production, is also dominated by
the United States and Brazil. The U.S. dominates world fuel ethanol
consumption, with 9.6 billion gallons consumed in 2008 (domestic
production plus imports).\119\ Brazil is second in consumption, with
about 4.9 billion gallons projected to be consumed in 2007/2008.\120\
The EU is also a significant consumer of ethanol; however, consumption
for the EU countries was only approximately 0.7 billion gallons in 2007.\121\
---------------------------------------------------------------------------

    \119\ Ibid.
    \120\ UNICA, ``Sugarcane Industry in Brazil: Ethanol Sugar,
Bioelectricity'' Brochure, 2008.
    \121\ European Bioethanol Fuel Association (eBio), ``The EU
Market: Production and Consumption,'' http://www.ebio.org/
EUmarket.php,  March 31, 2009.
---------------------------------------------------------------------------

b. Historic/Current Domestic Imports
    Ethanol imports have traditionally played a relatively small role
in the U.S. transportation fuel market due to historically low crude
prices and the tariff on imported ethanol. While low crude prices made
it difficult for both domestic and imported ethanol to compete with
gasoline, the addition of the federal excise tax credit made it
possible for domestic ethanol to be economically competitive.
    Between 2000 and 2003, the total volume of fuel ethanol imports
into the United States remained relatively stable at 46-68 million
gallons.\122\ During this period of time, mostly Brazilian-based
ethanol entered the U.S. primarily through the Caribbean Basin
Initiative (CBI) countries where it could avoid the tariff. From 2004-
2005, with rising crude oil prices, most estimates show U.S. fuel
ethanol imports increased slightly to 135-164 million gallons, or about
4% of the total U.S. fuel ethanol consumption (3.5 to 4.0 billion
gallons). The volume of imports rose dramatically in 2006 to 654-720
million gallons, or about 13% of the 2006 total ethanol consumption of
5.4 billion gallons. The largest volume of imports in 2006 was from
direct Brazilian imports. This increase in ethanol imports was mainly
due to the withdrawal of MTBE from the fuel pool which increased the
price of ethanol. MTBE was used in gasoline to fulfill the oxygenate
requirements set by Congress in the 1990 Clean Air Act Amendments.
EPAct further accelerated the withdrawal of MTBE because gasoline
marketers were no longer required to use an oxygenate and gasoline
marketers did not receive the MTBE liability protection that they had
petitioned for. Refiners responded by removing MTBE and replacing its
use with ethanol. As a result, the demand for ethanol increased at
unprecedented rates as most refiners replaced MTBE with ethanol. The
dramatic increase in crude oil costs at this time also made ethanol
more economical by comparison.
---------------------------------------------------------------------------

    \122\ Values given report USITC and RFA data, however, EIA
reports slightly lower numbers prior to 2004.
---------------------------------------------------------------------------

    By the end of 2006, almost all MTBE was phased out of gasoline.
However, crude oil prices remained high, allowing ethanol imports to
the U.S. to remain economical in comparison to the past. Although not
as high as the volume of ethanol imported in 2006, the U.S. continued
to import ethanol in 2007 (425-450 million gallons). In 2008, the U.S.
imported 519-556 million gallons.\123\ As the data show, the volume of
imported ethanol can fluctuate greatly. By looking at historical import
data it is difficult to project the potential volume of future imports
to the U.S. Rather, it is necessary to assess future import potential
by analyzing the major players for foreign biofuels production and consumption.
---------------------------------------------------------------------------

    \123\ USITC and EIA import data reported.
---------------------------------------------------------------------------

c. Projected Domestic Imports
    In our assessment of foreign ethanol production and consumption, we
analyzed the following countries or group of countries: Brazil, the EU,
Japan, India, and China. Our analyses indicate that Brazil would likely
be the only nation able to supply any meaningful amount of ethanol to
the U.S. in the future. Depending on whether the mandates and goals of
the EU, Japan, India, and China are enacted or met in the future, it is
likely that this group of countries would consume any growth in their
own production and be net importers of ethanol, thus competing with the
U.S. for Brazilian ethanol exports.
    Brazil is expected to supply the majority of future ethanol demand
and to expand their capacity for several reasons. First, Brazil has
over 30 years experience in developing the research and technologies
for producing sugarcane ethanol. As a result, Brazilians have been able
to improve agricultural and conversion processes so that sugarcane
ethanol is currently the least costly method for producing biofuels.
See Section VIII for further discussion on the production costs for
sugarcane ethanol.
    Second, it is believed that domestic demand for ethanol in Brazil
will begin to slow as most of the national fleet of vehicles will have
transitioned to flex-fuel within the next few years.\124\ Thus, as
domestic demand begins to level off, some experts see a significant
possibility that exports will become more relevant in market share terms.
---------------------------------------------------------------------------

    \124\ Agra FNP, ``Sugar and Ethanol in Brazil: A Study of the
Brazilian Sugar Cane, Sugar and Ethanol Industries,'' 2007.
---------------------------------------------------------------------------

    Lastly, Brazil has large land areas for potential expansion for
sugarcane. A study commissioned by the Brazilian government produced an
analysis in which Brazil's arable land was evaluated for its
suitability for cane.\125\ Setting aside areas protected by
environmental regulations and those with a slope greater than 12%
(those not suitable for mechanized farming), tripling ethanol
production (a goal set by the Brazilian government by 2020) would
require only an additional 14 million acres. This additional acreage
would only be about 2% of suitable land for sugarcane production. Refer
to Section 1.5 of the DRIA for more details.
---------------------------------------------------------------------------

    \125\ CGEE, ABDI, Unicamp, and NIPE, Scaling Up the Ethanol
Program in Brazil, n.d. as quoted in Rothkopf, Garten, ``A Blueprint
for Green Energy in the Americas,'' 2006.
---------------------------------------------------------------------------

    Although Brazil is in an excellent position to help meet the
growing global demand for ethanol, several constraints could limit the
expansion of ethanol production. As Brazil's government has adopted
plans to meet global demand by tripling production by 2020,\126\ this
would mean a total capacity of about 12.7 billion gallons, to be
achieved through a combination of efficiency gains, greenfield
projects, and infrastructure expansions. Estimates for the investment
required tend to range from $2 to $4 billion a year.\127\ In addition,
Brazil will need to improve its current ethanol infrastructure (i.e.
improvements in power, transportation, storage, distribution logistics,
and communications). It is estimated that Brazil will need to invest $1
billion each year for the next 15 years in infrastructure to keep pace
with capacity expansion and export demand.\128\ Refer to Section 1.5 of
the DRIA for further details on the improvements needed for Brazil to
increase ethanol production capacity.
---------------------------------------------------------------------------

    \126\ Rothkopf, Garten, ``A Blueprint for Green Energy in the Americas,'' 2006.
    \127\ Ibid.
    \128\ Ibid.
---------------------------------------------------------------------------

    Due to uncertainties in the future demand for ethanol domestically
and internationally as well as uncertainties in the actual investments
made in the Brazilian ethanol industry, there appears to be a wide
range of Brazilian production and domestic consumption estimates. The
most current and complete estimates indicate that total

[[Page 24998]]

Brazilian ethanol exports will likely reach 3.8-4.2 billion gallons by
2022.129 130 131 As this volume of ethanol export is
available to countries around the world, only a portion of this will be
available exclusively to the United States. If the balance of the EISA
advanced biofuel requirement not met with cellulosic biofuel and
biomass-based diesel were to be met with imported sugarcane ethanol
alone, it would require 3.2 billion gallons (see Table V.A.2-1), or
approximately 80% of total Brazilian ethanol export estimates.
---------------------------------------------------------------------------

    \129\ EPE, ``Plano Nacional de Energia 2030,'' Presentation from
Mauricio Tolmasquim, 2007.
    \130\ UNICA, ``Sugarcane Industry in Brazil: Ethanol, Sugar,
Bioelectricity,'' 2008.
    \131\ USEPA International Visitors Program Meeting October 30,
2007, correspondence with Mr. Rodrigues, Technical Director from
UNICA Sao Paulo Sugarcane Agro-industry Union, stated approximately
3.7 billion gallons probable by 2017/2020; Consistent with brochure
``Sugarcane Industry in Brazil: Ethanol Sugar, Bioelectricity'' from
UNICA (3.25 Bgal export in 2015 and 4.15 Bgal export in 2020).
---------------------------------------------------------------------------

    The amount of Brazilian ethanol available for shipment to the U.S.
will be dependent on the biofuels mandates and goals set by other
foreign countries (i.e., the EU, Japan, India, and China) in addition
to U.S. policies to promote the use of renewable fuels. Our estimates
show that there could be a potential demand for imported ethanol of
4.6-14.6 billion gallons by 2020/2022 from these countries. This is due
to the fact that some countries are unable to produce large volumes of
ethanol because of land constraints or low production capacity. As
such, foreign countries may have limited domestic biofuel production
capability and may therefore require importation of biofuels in order
to meet their mandates and goals. Refer to Section 1.5 of the DRIA for
further details. Therefore, if other foreign country mandates and goals
are to be met, then Brazil may need to either increase production much
more than its government projects or export less ethanol to the U.S.
This suggests that the U.S. may be competing for Brazilian ethanol
exports if supplies are limited in the future. For our analysis we
assumed that the U.S. would consume the majority of Brazilian exports
(i.e. 80% of export estimates in 2022). This is aggressive, yet within
the bounds of reason, therefore, we have made this simplifying
assumption for the purposes of further analysis. We seek comment on the
legitimacy of this assumption given the ethanol export deals and
commitments that Brazil has made or may potentially make with other
nations in the future.
    Generally speaking, Brazilian ethanol exporters will seek routes to
countries with the lowest transportation costs, taxes, and tariffs.
With respect to the U.S., the most likely route is through the
Caribbean Basin Initiative (CBI).\132\ Brazilian ethanol entering the
U.S. through the CBI countries is not currently subject to the 54 cent
imported ethanol tariff and yet receives the 45 cent ethanol blender
tax subsidy. Due to the economic incentive of transporting ethanol
through the CBI, we expect the majority of the tariff rate quota (TRQ)
to be met or exceeded, perhaps 90% or more. The TRQ is set each year as
7% of the total domestic ethanol consumed in the prior year. If we
assume that 90% of the TRQ is met and that total domestic ethanol (corn
and cellulosic ethanol) consumed in the prior year was 28.5 Bgal, then
approximately 1.8 Bgal of ethanol could enter the U.S. through CBI
countries. The rest of the Brazilian ethanol exports not entering the
CBI will compete on the open market with the rest of the world
demanding some portion of direct Brazilian ethanol. We calculated the
amount of direct Brazilian ethanol exports in 2022 to the U.S. as the
total imported ethanol required (3.14 billion gallons) to meet the RFS2
volume requirements subtracted by imported ethanol from CBI countries
(1.8 billion gallons), or equal to 1.34 billion gallons.
---------------------------------------------------------------------------

    \132\ Other preferential trade agreements include the North
American Free Trade Agreement (NAFTA) which permits tariff-free
ethanol imports from Canada and Mexico and the Andean Trade
Promotion and Drug Eradication Act (ATPDEA) which allows the
countries of Columbia, Ecuador, Bolivia, and Peru to import ethanol
duty-free. Currently, these countries export or produce relatively
small amounts of ethanol, and thus we have not assumed that the U.S.
will receive any substantial amounts from these countries in the
future for our analyses.
---------------------------------------------------------------------------

    In the past, companies have also avoided the ethanol import tariff
through a duty drawback.\133\ The drawback is a loophole in the tax
rules which allowed companies to import ethanol and then receive a
rebate on taxes paid on the ethanol when jet fuel is sold for export
within three years. The drawback considered ethanol and jet fuel as
similar commodities (finished petroleum derivatives).134 135
Most recently, however, Senate Representative Charles Grassley from
Iowa included a provision into the Farm Bill of 2008 that ended such
refunds. The provision states that ``any duty paid under subheading
9901.00.50 of the Harmonized Tariff Schedule of the United States on
imports of ethyl alcohol or a mixture of ethyl alcohol may not be
refunded if the exported article upon which a drawback claim is based
does not contain ethyl alcohol or a mixture of ethyl alcohol.'' \136\
The provision is effective on or after October 1, 2008 and companies
have until October 1, 2010 to apply for a duty drawback on prior
transactions. With the loophole closed, it is anticipated that there
may be less ethanol directly exported from Brazil in the future.\137\
---------------------------------------------------------------------------

    \133\ Rapoza, Kenneth, ``UPDATE: Tax Loophole Helps US Import
Ethanol `Duty Free'--ED&F,'' INO News, Dow Jones Newswires, March
2008. http://news.ino.com/. 
    \134\ Peter Rhode, ``Senate Finance May Take Up Drawback
Loophole As Part of Energy Bill,'' EnergyWashington Week, April 18,
2007. As sited in Yacobucci, Brent, ``Ethanol Imports and the
Caribbean Basin Initiative,'' CRS Report for Congress, Order Code
RS21930, Updated March 18, 2008.
    \135\ Perkins, Jerry, ``BRAZIL: Loophole Hurt U.S. Ethanol
Prices,'' DesMoinesRegister.com, October 18, 2007.
    \136\ Public Law Version 6124 of the Farm Bill. 2008. http://
www.usda.gov/documents/Bill_6124.pdf.
    \137\ Lundell, Drake, ``Brazilian Ethanol Export Surge to End;
U.S. Customs Loophole Closed Oct. 1,'' Ethanol and Biodiesel News,
Issue 45, November 4, 2008.
---------------------------------------------------------------------------

    For our distribution and air quality analyses, we had to make a
determination as to where the projected imported ethanol would likely
enter the United States. To do so, we started by looking at 2006
ethanol import data and made assumptions as to which countries would
likely contribute to the CBI ethanol volumes in Table V.B.3-1, and to
what extent.\138\ We estimated that, on average, in future years, 30%
would come from Jamaica, 20% each would come from El Salvador and Costa
Rica, and 15% each would originate from Trinidad & Tobago and the
Virgin Islands. Even though to date there have not been a lot of
ethanol imports from the Virgin Islands, we believe that they could
become a comparable importer to Trinidad & Tobago in the future under
the proposed RFS2 program.
---------------------------------------------------------------------------

    \138\ Source: EIA data on company-level imports (http://
www.eia.doe.gov/oil_gas/petroleum/data_publications/company_
level_imports/cli_historical.html).
---------------------------------------------------------------------------

    From there, we looked at 2006-2007 import data and estimated the
general destination of Brazilian ethanol and the five contributing CBI
countries' domestic imports. Based on these countries' geographic
locations and import histories, we estimated that in 2022 about 75% of
the ethanol would be imported to the East and Gulf Coasts and the
remainder would go to the West Coast and Hawaii. To estimate import
locations, we considered coastal port cities that had received ethanol
or finished gasoline imports in 2006 and distributed the ethanol
accordingly based on ethanol demand. For more information on this
analysis, refer to Section 1.5 of the DRIA.

[[Page 24999]]

4. Biodiesel & Renewable Diesel
    Biodiesel and renewable diesel are replacements for petroleum
diesel that are made from plant or animal fats. Biodiesel consists of
fatty acid methyl esters (FAME) and can be used in low-concentration
blends in most types of diesel engines and other combustion equipment
with no modifications. The term renewable diesel covers fuels made by
hydrotreating plant or animal fats in processes similar to those used
in refining petroleum. Renewable diesel is chemically analogous to
blendstocks already used in petroleum diesel, thus its use can be
transparent and its blend level essentially unlimited. The goal of both
biodiesel and renewable diesel conversion processes is to change the
properties of a variety of feedstocks to more closely match those of
petroleum diesel (such as its density, viscosity, and energy content)
for which the engines and distribution system have been designed. Both
processes can produce suitable fuels from biogenic sources, though we
believe some feedstocks lend themselves better to one process or the
other. The definition of biodiesel given in applicable regulations is
sufficiently broad to be inclusive of both fuels.\139\ However, the
EISA stipulates that renewable diesel that is co-processed with
petroleum diesel cannot be counted as ``biomass-based diesel'' for
purposes of complying with its volume mandates.\140\
---------------------------------------------------------------------------

    \139\ See Section 1515 of the Energy Policy Act of 2005. More
discussion of the definitions of biodiesel and renewable diesel are
given in the preamble of the Renewable Fuel Standard rulemaking,
Section III.B.2, as published in the Federal Register Vol. 72, No.
83, p. 23917.
    \140\ For more detailed discussion of the definition of
coprocessing and its implications for compliance with EISA, see
Section III.B.1 of this preamble.
---------------------------------------------------------------------------

    In general, plant and animal oils are valuable commodities with
many uses other than transportation fuel. Therefore we expect the
primary limiting factor in the supply of both biodiesel and renewable
diesel to be feedstock availability and price. Expansion of their
market volumes is dependent on being able to compete on price with the
petroleum diesel they are displacing, which will depend largely on
continuation of current subsidies and other incentives.
    Other biomass-based diesel fuel plants are either already built or
being considered for construction. Cello Energy has already started up
a 20 million gallon per year catalytic depolymerization plant that is
producing diesel fuel from cellulose and other feedstocks, and Cello
intends on building several 50 million gallon per year plants to be
started up in 2010. Also, numerous other companies are planning on
building biomass to liquids (BTL) plants that produce diesel fuel
through the syngas and Fischer Tropsch pathway. However, for our
analysis for this proposed rulemaking, we did not project that biomass-
based diesel fuel would be produced from these processes.
a. Historic and Projected Production
i. Biodiesel
    As of September 2008, the aggregate production capacity of
biodiesel plants in the U.S. was estimated at 2.6 billion gallons per
year across approximately 176 facilities.\141\ Biodiesel plants exist
in nearly all states, with the largest density of plants in the Midwest
and Southeast where agricultural feedstocks are most plentiful.
---------------------------------------------------------------------------

    \141\ Figures here were taken from National Biodiesel Board fact
sheet dated September 29, 2008 (http://biodiesel.org/pdf_files/
fuelfactsheets/Producers%20Map%20-%20existing.pdf). This information
was current at the time these analyses were being done. More recent
data maintained by Biodiesel Magazine suggests that by April 2009
the industry had contracted to approximately 137 plants with
aggregate capacity of 2.3 billion gal/yr (see http://
www.biodieselmagazine.com/plant-list.jsp ).
---------------------------------------------------------------------------

    Table V.B.4-1 gives U.S. biodiesel production capacity, sales, and
capacity utilization in recent years. The figures suggest that the
industry has grown out of proportion with actual biodiesel demand.
Reasons for this include various state incentives to build plants,
along with state and federal incentives to blend biodiesel, which have
given rise to an optimistic industry outlook over the past several
years. Since the cost of capital is relatively low for the biodiesel
production process (typically four to six percent of the total per-
gallon cost), this industry developed a more grassroots profile in
comparison to the ethanol industry, and, with median size less than 10
million gallons/yr, consists of a large number of small plants.\142\
These small plants, with relatively low operating costs other than
feedstock, have generally been able to survive producing below their
nameplate capacities.
---------------------------------------------------------------------------

    \142\ Capital figures derived from USDA production cost models.
A publication describing USDA modeling of biodiesel production costs
can be found in Bioresource Technology 97(2006) 671-8.
    \143\ Capacity data taken from National Biodiesel Board.
Production figures taken from F.O. Licht World Ethanol and Biofuels
Report, vol. 6, no. 11, p S271, except 2008, which is an estimate
taken from National Biodiesel Board (http://www.biodiesel.org/pdf_
files/fuelfactsheets/Production_graph_slide.pdf ).

                          Table V.B.4-1--U.S. Biodiesel Capacity and Production Volumes
                                             [Million gallons] \143\
----------------------------------------------------------------------------------------------------------------
                                                                                                    Utilization
                              Year                                   Capacity       Production       (percent)
----------------------------------------------------------------------------------------------------------------
2003............................................................             150              21             14%
2004............................................................             245              36              15
2005............................................................             395             115              29
2006............................................................             792             241              30
2007............................................................           1,809             499              28
2008............................................................           2,610             700              27
----------------------------------------------------------------------------------------------------------------

    Some of this industry capacity may not be dedicated specifically to
fuel production, instead being used to make oleochemical feedstocks for
further conversion into products such as surfactants, lubricants, and
soaps. These products do not show up in renewable fuel sales figures.
    In 2004-5, demand for biodiesel grew rapidly, but the trend of
increasing capacity utilization was quickly overwhelmed by additional
plant starts. Since then, high commodity prices followed by reduced
demand for transportation fuel have caused additional economic strain
beyond the overcapacity situation. According to a survey conducted by
Biodiesel Magazine staff, more than 1 in 5 plants were already idle or
defunct as of late 2007 (though this likely varies by

[[Page 25000]]

region).\144\ A significant portion of the 2007 and 2008 production was
exported to Europe or Asia where fuel prices and additional tax
subsidies on top of those provided in the U.S. help cover
transportation overseas and offset high feedstock costs. The Energy
Information Administration is beginning to collect data on biodiesel
imports and exports, but reports are not expected until later in 2009.
Therefore precise figures are not available on what fraction of
production was consumed domestically, but sources familiar with the
industry suggest exports may have been as much as 200 million gallons
in 2007 and likely more in 2008.\145\ We do not account for any
biodiesel exports in our analysis, though there will be sufficient
plant capacity to produce material beyond the volumes required in the
EISA should an export market exist.
---------------------------------------------------------------------------

    \144\ Derived from figures published in Biodiesel Magazine, May
2008, p. 39.
    \145\ Staff-level communication with National Biodiesel Board (April 2008).
---------------------------------------------------------------------------

    To perform our distribution and emission impacts analyses for this
proposal, it was necessary to forecast the state of the biodiesel
industry in the timeframe of the fully-phased-in RFS. In general, this
consisted of reducing the over-capacity to be much closer to the amount
demanded, which we assumed to be equal to the requirement under the
EISA given uncertainties about feedstock prices and changes in tax
incentives in the long term. This was accomplished by considering as
screening factors the current production and sales incentives in each
state as well as each plant's primary feedstock type and whether it was
BQ-9000 certified.\146\ Going forward producers will compete for
feedstocks and markets will consolidate. During this period the number
of operating plants is expected to shrink, with surviving plants adding
feedstock segregation and pre-treatment capabilities, giving them
flexibility to process any mix of feedstocks available in their area.
By the end of this period we project a mix of large regional plants and
some smaller plants taking advantage of local market niches, with an
overall average capacity utilization around 80% for dedicated fuel
plants. Table V.B.4-2 summarizes this forecast. See Section 1.5.4 of
the DRIA for more details.
---------------------------------------------------------------------------

    \146\ Information on state incentives was taken from U.S.
Department of Energy Web site, accessed July 30, 2008, at http://
www.eere.energy.gov/afdc/fuels/biodiesel_laws.html. Information on
feedstock and BQ-9000 status was taken from Biodiesel Board fact
sheet, accessed July 30, 2008, at http://biodiesel.org/pdf_files/
fuelfactsheets/Producers%20Map%20-%20existing.pdf.

 Table V.B.4-2--Summary of Projected Biodiesel Industry Characterization
                       Used in Our Analyses \147\
------------------------------------------------------------------------
                                                          2008     2022
------------------------------------------------------------------------
Total production capacity on-line (million gal/yr)....    2,610    1,050
Number of operating plants............................      176       35
Median plant size (million gal/yr)....................        5       30
Total biodiesel production (million gal)..............      700      810
Average plant utilization.............................     0.27     0.77
------------------------------------------------------------------------

ii. Renewable Diesel
    Renewable diesel is a fuel (or blendstock) produced from animal
fats, vegetable oils, and waste greases using chemical processes
similar to those employed in petroleum hydrotreating. These processes
remove oxygen and saturate olefins, converting the triglycerides and
fatty acids into paraffins. Renewable diesel typically has higher
cetane, lower nitrogen, and lower aromatics than petroleum diesel fuel,
while also meeting stringent sulfur standards.
---------------------------------------------------------------------------

    \147\ Industry data for 2008 taken from National Biodiesel Board
fact sheets at http://www.biodiesel.org/buyingbiodiesel/producers_
marketers/Producers%20Map-Existing.pdf  and http://www.biodiesel.org/
pdf_files/fuelfactsheets/Production_graph_slide.pdf  (both
accessed April 27, 2009).
---------------------------------------------------------------------------

    In comparison to biodiesel, renewable diesel has improved storage,
stability, and shipping properties as a result of the oxygen and
olefins in the feedstock being removed. This allows renewable diesel
fuel to be shipped in existing petroleum pipelines used for
transporting fuels, thus avoiding one significant issue with
distribution of biodiesel. For more on fuel distribution, refer to
Section V.C.
    Considering that this industry is still in development and that
there are no long-term projections of production volume, we base our
production estimates primarily on the potential volume of feedstocks
for this process, in the context of recent industry project
announcements involving proven technology. We project that
approximately two-thirds of renewable diesel will be produced at
existing petroleum refineries, and half will be co-processed with
petroleum (thus prohibiting it from counting as ``biomass-based
diesel'' under the EISA). Tables V.B.4-3 and V.B.4-4 summarize these volumes.

Table V.B.4-3--Projected Renewable Diesel Volumes by Production Category
                        [Million gallons in 2022]
------------------------------------------------------------------------
                                                  Existing       New
                                                  facility     facility
------------------------------------------------------------------------
Co-processed with petroleum...................          188           --
Not co-processed with petroleum...............           63          125
------------------------------------------------------------------------

b. Feedstock Availability
    The primary feedstock for domestic biodiesel production has
historically been soybean oil, with other plant and animal fats as well
as recycled greases making up a smaller but significant portion of the
biodiesel pool. Agricultural commodity modeling we have done for this
proposal (see Section IX.A) suggests that soybean oil production will
stay relatively flat in the future, causing supplies to tighten and
prices to rise as demand increases for biofuels and food uses
worldwide. The output of these models suggests that domestic soy oil
production could support about 550 million gallons per year in 2022.
This material is most likely to be processed by biodiesel plants due to
the large available capacity of these facilities and their proximity to
soybean production. Compared to other feedstocks, virgin plant oils are
more easily processed into biofuel via simple transesterification due
to their homogeneity of composition and lack of contaminants.
    Another source of feedstock which could provide increasing and
significant volume is oil extracted from corn or its co-products in the
dry mill ethanol production process. Sometimes referred to as corn
fractionation or dry separation, these processes get additional
products of value from the dry milling process. This idea is not

[[Page 25001]]

new, as existing wet mill plants create several product streams from
their corn input, including oil. Corn fractionation can be seen as a
way to get some of this added value without incurring the larger
capital costs and potentially lower ethanol yields associated with wet
mill plants. More detailed discussion of these processes and how they
affect the co-product stream(s) can be found in DRIA Section 1.4.1.3.
    The corn oil process on which we have chosen to focus for cost and
volume estimates in this proposal is one that extracts oil from the
thin stillage after fermentation (the non-ethanol liquid material that
typically becomes part of distillers' grains with solubles). We believe
installation of this type of equipment will be attractive to industry
because it can be added onto an existing dry mill plant and does not
impact ethanol yields since it does not process the corn prior to
fermentation. Depending on the configuration, such a system can extract
20-50% of the oil from the co-product streams, and produces a
distressed corn oil (non-food-grade, with some free fatty acids and/or
oxidation by-products) product stream which can be used as feedstock by
biodiesel facilities. Since it offers another stream of revenue, we
believe it is reasonable to expect about 40% of projected total ethanol
production to implement some type of oil extraction process by 2022,
generating approximately 150 million gallons per year of corn oil
biofuel feedstock.\148\ We expect this material to be processed in
biodiesel plants.
---------------------------------------------------------------------------

    \148\ See Table 3 in Mueller, Steffen. An analysis of the
projected energy use of future dry mill corn ethanol plants (2010-
2030). October 10, 2007. Available at http://www.chpcentermw.org/
pdfs/2007CornEthanolEnergySys.pdf. 
---------------------------------------------------------------------------

    Rendered animal fats and reclaimed cooking oils and greases are
another potentially significant source of biodiesel feedstock. We
estimate that just two to four percent of biodiesel in 2007 was
produced from waste cooking oils and greases, though this number is
likely higher more recently.\149\ Tyson Foods, in joint efforts with
ConocoPhilips and Syntroleum, announced construction plans in 2008 for
renewable diesel production facilities to begin operating in 2010 and
producing up to 175 million gallons annually (combined capacity). By
the end of our projection period, as much as 30% of rendered fats and
waste grease could be converted to biofuel while still supporting
production of pet food, soaps and detergents, and other
oleochemicals.\150\ We request comment from members of these industries
on any potential impacts of diversion of rendered materials to biofuel.
---------------------------------------------------------------------------

    \149\ Based on plant capacities reported by the National
Biodiesel Board and data reported by F.O. Licht.
    \150\ Based on statements from the National Renderer's Association.
---------------------------------------------------------------------------

    Under this assumption, this material could make approximately 500
million gallons of biofuel (though we have not chosen to allocate all
of it in our analyses here). We estimate this type of material could be
most economically made into renewable diesel in the long term, as that
process does not have the same sensitivities to free fatty acids and
other contaminates typically present in waste greases as the biodiesel
process; however, some amount of this material may continue to be
processed in biodiesel plants that have acid pretreatment capabilities
where it makes economic sense. Recent market shifts and changes in tax
subsidies enacted after analyses were done for this NPRM have affected
the relative economics of using waste fats and greases for biodiesel
versus renewable diesel. We will reevaluate our assumptions in the FRM.
    Our analysis of the countries with the most potential to produce
and consume biodiesel in the future suggests that supplies of finished
biodiesel will be tight, and prices of its feedstocks will remain high.
Supplies to the U.S. will be limited by biofuel mandates and targets of
other countries, preferential shipment of biodiesel to European and
Asian nations, and the speed at which non-traditional crops such as
jatropha can be developed. Thus, we cannot at this time project more
than negligible amounts of biodiesel or its feedstocks being available
for import into the U.S. in the future. For more discussion of
international movement of biodiesel and its feedstocks, refer to
Section 1.1 of the DRIA.
    Table V.B.4-4 shows the projected potential contribution of these
sources we have chosen to quantify. Other potential, but less certain,
sources for biodiesel feedstocks include conversion of some existing
croplands used for soybeans to higher-yielding oilseed crops.
Production of oil from algae farms is also being investigated by a
number of companies and universities as a source of biofuel feedstock.
For additional discussion of such sources, refer to Section 1.1 of the DRIA.

    Table V.B.4-4--Estimated Potential Biodiesel and Renewable Diesel
                             Volumes in 2022
                        [Million gallons of fuel]
------------------------------------------------------------------------
                                     Biomass-based diesel       Other
                                  --------------------------   advanced
                                                               biofuel
                                                 Renewable  ------------
                                    Biodiesel      diesel     Renewable
                                                                diesel
------------------------------------------------------------------------
Virgin plant oils................          660           --           --
Corn fractionation...............          150           --           --
Rendered fats and greases........           --          188          188
------------------------------------------------------------------------

C. Renewable Fuel Distribution

    The following discussion pertains to the distribution of biofuels.
A discussion of the distribution of biofuel feedstocks and co-products
is contained in Section 1.3.3 and 5.1 of the DRIA respectively. In
conducting our analysis of biofuel distribution, we took into account
the projected size and location of biofuel production facilities and
where we project biofuels would be used.\151\
---------------------------------------------------------------------------

    \151\ The location of biofuel production facilities and where
biofuels would be used is discussed in Sections 1.5 and 1.7 of the
DRIA respectively and earlier in this Section V of the preamble.
---------------------------------------------------------------------------

    The current motor fuel distribution infrastructure has been
optimized to facilitate the movement of petroleum-based fuels.
Consequently, there are very efficient pipeline-terminal networks that
move large volumes of petroleum-based fuels from production/import
centers on the Gulf Coast and the Northeast into the heartland of the

[[Page 25002]]

country. In contrast, the majority of renewable fuel is expected to be
produced in the heartland of the country and will need to be shipped to
the coasts, flowing roughly in the opposite direction of petroleum-
based fuels. This limits the ability of renewable fuels to utilize the
existing fuel distribution infrastructure.
    The modes of distributing renewable fuels to the end user vary
depending on constraints arising from their physical/chemical nature
and their point of origination. Some fuels are compatible with the
existing fuel distribution system, while others currently require
segregation from other fuels. The location of renewable fuel production
plants is also often dictated by the need to be close to the source of
the feedstocks used rather than to fuel demand centers or to take
advantage of the existing petroleum product distribution system. Hence,
the distribution of renewable fuels raises unique concerns and in many
instances requires the addition of new transportation, storage,
blending, and retail equipment.
    Significant challenges must be faced in reconfiguring the
distribution system to accommodate the large volumes of ethanol and to
a lesser extent biodiesel that we project will be used. While some
uncertainties remain, particularly with respect to the ability of the
market to support the use of the volume of E85 needed, no technical
barriers appear to be insurmountable. The response of the
transportation system to date to the unprecedented increase in ethanol
use is encouraging. A U.S. Department of Agriculture (USDA) report
concluded that logistical concerns have not hampered the growth in
ethanol production, but that concerns may arise about the adequacy of
transportation infrastructure as the growth in ethanol production continues.\152\
---------------------------------------------------------------------------

    \152\ ``Ethanol Transportation Backgrounder, Expansion of U.S.
Corn-based Ethanol from the Agricultural Transportation
Perspective'', USDA, September 2007, http://www.ams.usda.gov/tmd/
TSB/EthanolTransportationBackgrounder09-17-07.pdf.
---------------------------------------------------------------------------

    Considerable efforts are underway by individual companies in the
fuel distribution system, consortiums of such companies, industry
associations, independent study groups, and inter-agency governmental
organizations to evaluate what steps may be necessary to facilitate the
necessary upgrades to the distribution system to support compliance
with the RFS2 standards.\153\ EPA will continue to participate/monitor
these efforts as appropriate to keep abreast of potential problems in
the biofuel distribution system which might interfere with the use of
the volumes of biofuels that we project will be needed to comply with
the RFS2 standards. The 2008 Farm Act (Title IX) requires USDA, DOE,
DOT, and EPA to conduct a biofuels infrastructure study that will
assess infrastructure needs, analyze alternative development
approaches, and provide recommendations for specific infrastructure
development actions to be taken.\154\
---------------------------------------------------------------------------

    \153\ For example: (1) The Biomass Research and Development
Board, a government study group, has formed a task group on biofuels
distribution infrastructure that is composed of experts on biofuel
distribution from a broad range of governmental agencies. (2) The
National Commission on Energy Policy, an independent advisory group,
has formed a task group of fuel distribution experts to make
recommendations on the steps needed to facilitate the distribution
of biofuels. (3) The Association of Oil Pipelines is conducting
research to evaluate what steps are necessary to allow the
distribution of ethanol blends by pipeline.
    \154\ http://www.ers.usda.gov/FarmBill/2008/Titles/
TitleIXEnergy.htm#infrastructure.
---------------------------------------------------------------------------

    Considerations related to the distribution of ethanol, biodiesel,
and renewable diesel are discussed in the following sections as well as
the changes to each segment in the distribution system that would be
needed to support the volumes of these biofuels that we project would
be used to satisfy the RFS2 standards.\155\ We request comments on the
challenges that will be faced by the fuel distribution system under the
RFS2 standards and on what steps will be necessary to facilitate making
the necessary accommodations in a timely fashion.\156\
---------------------------------------------------------------------------

    \155\ Additional discussion can be found in Section 1.6 of the DRIA.
    \156\ The costs associated with making the necessary changes to
the fuel distribution infrastructure are discussed in Section VIII.B
of today's preamble.
---------------------------------------------------------------------------

    To the extent that biofuels other than ethanol and biodiesel are
produced in response to the RFS2 standards, this might lessen the need
for added segregation during distribution. Distillate fuel produced
from cellulosic feedstocks might be treated as petroleum-based diesel
fuel blendstocks or a finished distillate fuel in the distribution
system. Likewise, bio-gasoline or bio-butanol could potentially be
treated as petroleum-based gasoline blendstocks.\157\ This also might
open the possibility for additional transport by pipeline. However, the
location of plants that produce such biofuels relative to petroleum
pipeline origination points would continue to be an issue limiting the
usefulness of existing pipelines for biofuel distribution.\158\
---------------------------------------------------------------------------

    \157\ Biogasoline might also potentially be treated as finished fuel.
    \158\ The projected location of biofuel plants would not be
affected by the choice of whether they are designed to produce
ethanol, distillate fuel, bio-gasoline, or butanol. Proximity to the
feedstock would continue to be the predominate consideration. The
use of pipelines is being considered for the shipment of bio-oils
manufactured from cellulosic feedstocks to refineries where they
could be converted into renewable diesel fuel or renewable gasoline.
The distribution of biofuel feedstocks is discussed in Section 1.3
of the DRIA.
---------------------------------------------------------------------------

1. Overview of Ethanol Distribution
    Pipelines are the preferred method of shipping large volumes of
petroleum products over long distances because of the relative low cost
and reliability. Ethanol is currently not commonly shipped by pipeline
because it can cause stress corrosion cracking in pipeline walls and
its affinity for water and solvency can result in product contamination
concerns.\159\ Shipping ethanol in pipelines that carry distillate
fuels as well as gasoline also presents unique difficulties in coping
with the volumes of a distillate-ethanol mixture which would typically
result.\160\ It is not possible to re-process this mixture in the way
that diesel-gasoline mixtures resulting from pipeline shipment are
currently handled.\161\ Substantial testing and analysis is currently
underway to resolve these concerns so that ethanol may be shipped by
pipeline either in a batch mode or blended with petroleum-based
fuel.\162\ By the time of the publication of this proposal, results of
these evaluations may be available regarding what actions are necessary
by multi-product pipelines to overcome safety and product contamination
concerns associated with shipping 10% ethanol blends. A short gasoline
pipeline in Florida has begun shipping

[[Continued on page 25003]]
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