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

    We proposed labeling requirements for fuel dispensers that handle
greater than 10 volume percent ethanol blends which included the
following text: For use only in flexible-fuel vehicles, May damage non-
flexible-fuel vehicles, Federal law prohibits use in non-flexible-fuel
vehicles. This proposal was primarily meant to help address concerns
about the potential misfueling of non-flex-fuel vehicles with E85, in
light of the anticipated increase in E85 sales volumes in response to
the RFS2 program. All ethanol blends above 10 volume percent were
included due to the increasing industry focus on ethanol blender pumps
that are designed to dispense a variety of ethanol blends (e.g., E30,
and E40) for use in flex-fuel vehicles.
    Commenters stated that EPA should undertake additional analysis of
the potential impacts from misfueling and what preventative measures
might be appropriate before finalizing labeling requirements for >E10
blends. They also stated that EPA should coordinate any such labeling
provisions with those already in place by the Federal Trade Commission.
EPA is also currently evaluating a petition to allow the use of up to
15 volume percent ethanol in non-flex fuel vehicles. One potential
result of this evaluation might be for EPA to grant a partial waiver
that is applicable only for a subset of the current vehicle population.
Under such an approach, a label for E15 fuel dispensers would be needed
that identifies what vehicles are approved to use E15.
    Based on the public comments and the fact that EPA has not
completed its evaluation of the E15 waiver petition, we believe that it
is appropriate to defer finalizing labeling requirements for >E10
blends at this time. This will afford us the opportunity to complete
our analysis of what measures might be appropriate to prevent
misfueling with >E10 blends before this may become a concern in the
context of the RFS2 program.

G. Biodiesel Temperature Standardization

    The volume of a batch of renewable fuel can change under extreme
changes in temperature. The volume of a batch of renewable fuel can
experience expansion as the temperature increases, or can experience
contraction as temperature decreases. The Agency requires temperature
standardization of renewable fuels at 60[deg] Fahrenheit ([deg]F) so
renewable fuel volumes are accounted for on a uniform and consistent
basis over the entire fuels industry. In the May 1, 2007 Renewable
Fuels Standard (RFS) final rule the Agency required biodiesel
temperature standardization to be completed as follows:

Vs,b = Va,b x (-0.0008008 x T + 1.0480)

Where

Vs,b = Standard Volume of biodiesel at 60 degrees F, in
gallons;
Va,b = Actual volume of biodiesel, in gallons;
T = Actual temperature of batch, in degrees F.

    This equation was based on data from a published research paper by
Tate et al.\36\ Members of the petroleum industry have indicated that
the current biodiesel temperature standardization equation in the
regulations provides different results than that commonly used by both
the petroleum and biodiesel industry for commercial trading of
biodiesel. These commercial values are either based on American
Petroleum Institute (API) tables for petroleum products or on empirical
values from industry measurements at common temperatures and pressures
observed in bulk fuel facilities. The difference between RIN calculated
volumes and commercial sales volumes has created confusion within the
record keeping system of both the petroleum and biodiesel industry.
---------------------------------------------------------------------------

    \36\ Equation was derived from R.E. Tate et al. ``The Densities
of Three Biodiesel Fuels at Temperatures up to 300 [deg]C.'',
Department of Biological Engineering, Dalhousie University, April
2005. ``Fuel 85 (2006) 1004-1009, Table 1 for soy methyl ester.''
---------------------------------------------------------------------------

    In the RFS2 proposed rule, the Agency proposed the temperature
standardization of biodiesel remain unchanged from the RFS1
requirements.\37\ The Agency received comments from Archer Daniels
Midland Company (ADM), World Energy Alternatives, Marathon Petroleum
Company (Marathon) and the National Biodiesel Board (NBB) to revise the
biodiesel temperature standardization equation.
---------------------------------------------------------------------------

    \37\ 74 FR 24943, May 26, 2009.
---------------------------------------------------------------------------

    Both ADM and NBB agreed on the necessity for biodiesel temperature
standardization at 60 [deg]F. ADM and NBB commented on several
empirical calculations which have been developed specific to biodiesel
temperature standardization since the 2007 RFS1 final rule. These
include a 2004 data set developed by the Minnesota Department of
Commerce and the Renewable Energy Group and updated in 2008;
information embedded in the European Biodiesel Specification EN 14214;
and information from the Alberta Research Council. The table below
provides values from NBB for 1000 gallons of biodiesel standardized to
a temperature at 60 [deg]F for these empirical calculations, along with
the current EPA equation, and the American Petroleum Institute (API)
Refined Products Table 6.

 Table III.G-1--NBB Comparison of Biodiesel Temperature Standardization
  Calculations to 60 [deg]F for 1000 gallons of Biodiesel at 90 [deg]F
------------------------------------------------------------------------
                                                                Gallons
------------------------------------------------------------------------
2007 EPA Biodiesel Formula..................................     975.28
2008 Minnesota (Hedman) data................................     986.270
API Refined Products Table 6 (biodiesel density @ 7.359)....     986.625
Alberta Research Council....................................     986.238
EN 14214 data...............................................     986.401
2004 Minnesota Renewable Energy Group data..................     986.830
------------------------------------------------------------------------

    As illustrated by the results from the above table, the values for
the various biodiesel temperature standardization empirical
calculations are within 1 gallon of agreement of each other for a 1000
gallon biodiesel batch, except for the current biodiesel temperature
standardization equation in the regulations.
    To ensure consistency in RIN generation, ADM commented EPA should
adopt only one biodiesel temperature standardization calculation. ADM
commented that all biodiesel temperature standardization calculations
developed, including the API Refined Products Table 6, are in very
close agreement with each other and the differences between them all
are insignificant. They further commented the API Refined Products
Table 6 has provided a uniform measurement of volume for years for the
entire liquid fuels industry. Thus, ADM believes the API Refined
Products Table 6 should be adopted for biodiesel to be consistent with
the calculation of sales volumes.

Finally ADM comments adoption of the API Refined Products Table 6 would
allow for easier verification within the marketplace, eliminate the
need for calculating one volume for sales and trades and another for
RINs, and prevents the entire distribution network from facing the
financial burden of reprogramming existing meters that already are
based on the API Refined Products Table 6.
    NBB commented that earlier surveys from its members indicate a
fifty-fifty split between members using the API Refined Products Table
6 or some variation of the current EPA biodiesel formula for biodiesel
temperature standardization. Some NBB members indicated that the API
Refined Products Table 6 was more commonly used by the petroleum
industry and embedded into the meters, pumps and accounting systems of
the petroleum industry. Companies already using the API Refined
Products Table 6 would have a reduction in required paperwork with RIN
generation and tracking because already existing commercial documents
could serve that purpose and they thus could eliminate or reduce their
current dual tracking system. Other NBB members have already embedded
the current EPA biodiesel equation within their accounting and sales
systems and would like to continue using that type of biodiesel
temperature standardization approach rather than the API Refined
Products Table 6. The NBB recommended EPA revise its current equation
in the regulations to the 2008 Hedman biodiesel temperature
standardization equation. Thus, NBB commented EPA should provide
flexibility to their members by allowing the use of either the API
Refined Products Table 6 or the use of a biodiesel temperature
standardization equation.
    Marathon commented the regulations allow for the standardization of
volume for other renewable fuels to be determined by an appropriate
formula commonly accepted by the industry which may be reviewed by the
EPA for appropriateness. They recommended that EPA extend this courtesy
to biodiesel.
    The Agency acknowledges that the current biodiesel temperature
standardization equation is likely not correct for biodiesel
temperature standardization at ambient temperatures observed in the
fuel distribution system. Based on the comments received, the Agency is
amending the regulations to allow for two ways for biodiesel
temperature standardization: (1) The American Petroleum Institute
Refined Products Table 6B, as referenced in ASTM D1250-08, entitled,
``Standard Guide for Use of the Petroleum Measurement Tables'', and (2)
a biodiesel temperature standardization equation that utilizes the 2008
data generated by the Minnesota Department of Commerce and the
Renewable Energy Group. These two methods for biodiesel temperature
standardization are within one gallon of agreement of each other for a
1000 gallon biodiesel batch and thus in very close agreement. Both ADM
and NBB acknowledged that the differences between these two methods are
insignificant and the resulting corrected volumes from these two
methods of calculation are within accuracy tolerances of any metered
measurement. Thus, the Agency believes the allowance of both of these
methods for biodiesel temperature standardization will increase
flexibility while still providing for a consistent generation and
accounting of biodiesel RINs over the entire fuel delivery system.

IV. Renewable Fuel Production and Use

    An assessment of the impacts of increased volumes of renewable fuel
must begin with an analysis 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 an assessment of the
potential feedstocks and renewable fuels that could 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 cases
for analysis purposes. As new technologies, feedstocks, and fuels
continue to develop on a daily basis, markets may appear differently
from our projections. Although actual volumes and feedstocks may
differ, we believe the projections made for our control cases are
within the range of possible predictions for which the standards are
met and allow for an assessment of the potential impacts of the
increases in renewable fuel volumes that meet the requirements of EISA.

A. Overview of Renewable Fuel 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 reference and control cases from which subsequent
analyses are based. The reference cases are projections of renewable
fuel volumes without the enactment of EISA and are described in Section
IV.A.1. The control cases are projections of the volumes and types of
renewable fuel that might be used in the future to comply with the EISA
volume mandates. For the NPRM we had focused on one primary control
case (see Section IV.A.2) whereas for the final rule we have expanded
the analysis to include two additional sensitivity cases (see Section
IV.A.3). Based on the public comments received as well as new
information, we have updated the primary control case volumes from the
NPRM to reflect what we believe could be a more likely set of volumes
to analyze. We assume in each of the cases the same ethanol-equivalence
basis as was used in the RFS1 rulemaking to meet the standard. Volumes
are listed in tables for this section in both straight-gallons and
ethanol-equivalent gallons (i.e., times 1.5 for biodiesel or 1.7 for
cellulosic diesel and renewable diesel). The volumes included in this
section are for 2022. For intermediate years, refer to Section 1.2 of
the RIA.
1. Reference Cases
    Our primary reference case renewable fuel volumes are based on the
Energy Information Administration's (EIA) Annual Energy Outlook (AEO)
2007 reference case projections.\38\ While AEO 2007 is not as up-to-
date as AEO 2008 or AEO 2009, we chose to use AEO 2007 because later
versions of AEO already include the impact of increased renewable fuel
volumes under EISA as well as fuel economy improvements under CAFE as
required in EISA, whereas AEO 2007 did not.
---------------------------------------------------------------------------

    \38\ AEO 2007 was only used to derive renewable fuel volume
projections for the primary reference case. AEO 2009 was used for
future crude oil cost estimates and for estimating total
transportation fuel energy use.
---------------------------------------------------------------------------

    For the final rule we have also assessed a number of the impacts
relative to a reference case assuming the mandated renewable fuel
volumes under RFS1 from the Energy Policy Act of 2005 (EPAct). This
allows for a more complete assessment of the impacts of the EISA volume
mandates, especially when combined with the impacts assessment
conducted for the RFS1 rulemaking (though many factors have changed
since then). Table IV.A.1-1 summarizes the 2022 renewable fuel volumes
for the AEO 2007 and the RFS1 reference cases (listed in both straight
volumes and ethanol-equivalent volumes).

                                              Table IV.A.1-1--Reference Case Renewable Fuel Volumes in 2022
                                                                    [Billion gallons]
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                Advanced biofuel                      Non-advanced
                                                               ------------------------------------------------------      biofuel
                                                                   Cellulosic       Biomass-based    Other advanced  ------------------
                      Source/volume type                             biofuel          diesel a           biofuel                         Total renewable
                                                               ------------------------------------------------------                         fuel
                                                                   Cellulosic                                           Corn ethanol
                                                                    ethanol c     FAME biodiesel b  Imported ethanol
--------------------------------------------------------------------------------------------------------------------------------------------------------
AEO 2007 Straight Volume......................................              0.25              0.38              0.64             12.29             13.56
AEO 2007 Ethanol-Equivalent...................................              0.25              0.58              0.64             12.29             13.76
RFS 1 Straight Volume.........................................              0.00              0.30              0.00              7.05              7.35
RFS 1 Ethanol-Equivalent......................................              0.00              0.45              0.00              7.05              7.50
--------------------------------------------------------------------------------------------------------------------------------------------------------
a Biomass-Based Diesel could include FAME biodiesel, cellulosic diesel, and non-co-processed renewable diesel.
b Only fatty acid methyl ester (FAME) biodiesel volumes were considered.
c Under the RFS1 reference case, we assumed the 250-million gallon cellulosic standard set by EPAct would be met primarily by corn ethanol plants
  utilizing 90% biomass for energy, thus actual production of cellulosic biofuel is zero. AEO 2007 reference case assumes actual production of
  cellulosic biofuel and therefore assumed to be 0.25 billion gallons.

2. Primary Control Case
    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 increased volumes of renewable fuel, we
projected a set of reasonable renewable fuel volumes based on our
projection of fuels that could come to market.
    Although actual volumes and feedstocks will be different, we
believe the projections made for our control cases are within the range
of possible predictions for which the standards are met and allow for
an assessment of the potential impacts of increased volumes of
renewable fuel. Table IV.A.2-1 summarizes the fuel types used for the
primary control case and their corresponding volumes for the year 2022.

                                      Table IV.A.2-1--Primary Control Case Projected Renewable Fuel Volumes in 2022
                                                                    [Billion gallons]
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                Advanced biofuel                                    Non-
                                                 ------------------------------------------------------------------------------   advanced
                                                     Cellulosic biofuel     Biomass-based diesel \a\   Other advanced biofuel     biofuel       Total
                   Volume type                   -------------------------------------------------------------------------------------------  renewable
                                                                                Other                                   fuel
                                                   Cellulosic   Cellulosic    FAME \c\     NCRD \d\    biodiesel     Imported       Corn
                                                    ethanol     diesel \b\   biodiesel                    \e\        ethanol      ethanol
--------------------------------------------------------------------------------------------------------------------------------------------------------
Straight Volume.................................         4.92         6.52         0.85         0.15         0.82         2.24        15.00        30.50
Ethanol-Equivalent..............................         4.92        11.08         1.28         0.26         1.23         2.24        15.00        36.00
--------------------------------------------------------------------------------------------------------------------------------------------------------
\a\ Biomass-Based Diesel could include FAME biodiesel, cellulosic diesel, and non-co-processed renewable diesel.
\b\ Cellulosic Diesel includes at least 1.96 billion gallons (3.33 billion ethanol-equivalent gallons) from Fischer-Tropsch Biomass-to-Liquids (BTL)
  processes based on EIA's forecast and an additional 4.56 billion gallons (7.75 billion ethanol-equivalent gallons) from this or other types of
  cellulosic diesel processes.
\c\ Fatty acid methyl ester (FAME) biodiesel.
\d\ Non-Co-processed Renewable Diesel (NCRD).
\e\ Other Biodiesel is biodiesel that could be produced in addition to the amount needed to meet the biomass-based diesel standard.

    The following subsections detail our rationale for projecting the
amount and type of fuels needed to meet EISA as shown in Table IV.A.2-
1. For cellulosic biofuel we have assumed that by 2022 on a straight-
volume basis about half would come from cellulosic ethanol and the
other half from cellulosic diesel. On an ethanol-equivalent volume
basis, cellulosic diesel would make up almost 70% of the 16 billion
gallons cellulosic biofuel standard. 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 by cellulosic biofuel and
biomass-based diesel is assumed to come mainly from imported sugarcane
ethanol with a smaller amount from additional biodiesel sources. The
total renewable fuel volume not required to be comprised of advanced
biofuels is assumed to be met with corn ethanol with small amounts of
other grain starches and waste sugars.
    The main difference between the volumes used for the NPRM and the
volumes used for the FRM is the inclusion of cellulosic diesel for the
FRM. The NPRM made the simplifying assumption that the cellulosic
biofuel standard would be met entirely with cellulosic ethanol.
However, due to growing interest and recent developments in
hydrocarbon-based or so-called ``drop-in'' renewable fuels as well as
butanol, and marketplace challenges for consuming high volumes of
ethanol, we have included projections of more non-ethanol renewables in
our primary control case for the final rule.\39\ In the future, this
could include various forms of ``green hydrocarbons'' (i.e., cellulosic
gasoline, diesel and jet) and higher alcohols, but

for analysis purposes, we have modeled it as cellulosic diesel fuel. We
describe these fuels in greater detail in Section IV.B-D. We have also
included some algae-derived biofuels in our FRM analyses given the
large interest and potential for such fuels. We have continued to
assume zero volume for renewable fuels or blendstocks such as biogas,
jatropha, palm, imported cellulosic biofuel, and other alcohols or
ethers in our control cases. Although we have not included these
renewable fuels and blendstocks in our impact analyses, it is important
to note that they can still be counted under our program if they meet
the lifecycle thresholds and definitions for renewable biomass, and
recent information suggests that some of them may be likely.
---------------------------------------------------------------------------

    \39\ Comments received from Advanced Biofuels Association,
Testimony on June 9, 2009 suggesting a number of advanced biofuel
technologies will be able to produce renewable diesel, jet fuels,
gasoline, and gasoline component fuels (e.g. butanol, iso-octane).
Similar comments were received from the New York State Department of
Environmental Conservation (Docket EPA-HQ-OAR-2005-0161-2143), OPEI
and AllSAFE (Docket EPA-HQ-OAR-2005-0161-2241), and the Low Carbon
Synthetic Fuels Association (Docket EPA-HQ-OAR-2005-0161-2310).
---------------------------------------------------------------------------

a. Cellulosic Biofuel
    As discussed in our NPRM, whether cellulosic biofuel is ethanol
will depend on a number of factors, including production costs, the
form of tax subsidies, credit programs, and factors influencing the
blending of biofuel into the fuel pool. It will also depend on the
relative demand for gasoline and diesel fuel. As a result of our
analyses on ethanol consumption (see Section IV.D) and continual
tracking of the industry's interest in hydrocarbon-based renewables
(see Section IV.B), we have decided to analyze a cellulosic biofuel
standard made up of both cellulosic ethanol and cellulosic diesel
fuels.
    For assessing the impacts of the RFS2 standards, we used AEO 2009
(April release) cellulosic ethanol volumes (4.92 billion gallons), as
well as the cellulosic biomass-to-liquids (BTL) diesel volumes (1.96
billion gallons) using Fischer-Tropsch (FT) processes. We consider BTL
diesel from FT processes as a subset of cellulosic diesel. In order to
reach a total of 16 billion ethanol-equivalent gallons, we assumed that
an additional 4.56 billion gallons of cellulosic diesel could be
produced from other cellulosic diesel processes. Refer to Section 1.2
of the RIA for more discussion.
b. Biomass-Based Diesel
    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 could potentially contribute to the biomass-based diesel
category, we have assumed for our analyses that the fuel produced
through Fischer-Tropsch (F-T) or other processes and its corresponding
feedstocks (cellulosic biomass) are already accounted for in the
cellulosic biofuel category discussed previously in Section IV.A.2.a.
    FAME and RD processes can both utilize vegetable oils, rendered
fats, and greases, and thus will generally compete for the same
feedstock pool. We have based RD volumes on our forecast of industry
plans, and expect these plants to use rendered fats as feedstock. Most
biodiesel plants now have the capability to use vegetable or animal
fats as feedstock, and thus our analysis assumes biodiesel will be made
from a mix of inputs, depending on local availability, economics, and
season. Refer to Section 1.1 of the RIA for more detail on FAME and RD
feedstocks
    Renewable diesel production can be further classified as co-
processed or non-co-processed, depending on whether the renewable
material is mixed with petroleum during the hydrotreating operations.
EISA specifically forbids co-processed RD from being counted as
biomass-based diesel, but it can still count toward the total advanced
biofuel requirement. At this time, based on current industry plans, we
expect most, if not all, RD will be non-co-processed (that is, non-
refinery operations).
    Perhaps the feedstock with the greatest potential for providing
large volumes of oil for the production of biomass-based diesel is
algae. 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 feedstocks. For
all three control cases, we have chosen to include 100 million gallons
of algae-based biodiesel by 2022. We believe this is reasonable given
several announcements from the algae industry about their production
plans.\40\ Although algae to biofuel companies can focus 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. For more detail on algae as a feedstock, refer to
Section 1.1 of the RIA.
---------------------------------------------------------------------------

    \40\ Sapphire Energy plans for 135 MMgal by 2018 and 1 Bgal by
2025; Petrosun plans for 30 MMgal/yr facility; Solazyme plans for
100 MMgal by 2012/13; U.S. Biofuels plans for 4 MMgal by 2010 and 50
MMgal by full scale. Only several companies have thus far revealed
production plans, and more are announced each day. It is important
to realize that future projections are highly uncertain, and we have
taken into account the best information we could acquire at the
time.
---------------------------------------------------------------------------

    During the comment period, we received information from
stakeholders on alternative biodiesel feedstocks such as camelina and
pennycress, to name a few. These feedstocks are currently being
researched due to their potential for lower agricultural inputs and
higher oil yields than traditional vegetable oil feedstocks as well as
their use in additional crop rotations (i.e., winter cover crops) on a
given area of land. We acknowledge that as we learn more about the
challenges and benefits to the use of newer feedstocks, these could be
used in the future towards meeting the biomass-based diesel standard
under the RFS2 program provided they meet the lifecycle thresholds and
definitions for renewable biomass. For the purpose of our impacts
analysis, however, we have chosen not to include these feedstocks in
our analyses at this time.
c. Other Advanced Biofuel
    As defined in EISA, advanced biofuel includes the cellulosic
biofuel and biomass-based diesel categories that were mentioned in
Sections IV.A.2.a and IV.A.2.b above. However, EISA requires greater
volumes of advanced biofuel than just the volumes required of these
fuels. It is entirely possible that greater volumes of cellulosic
biofuel and biomass-based diesel than required by EISA could be
produced in the future. Our control case assumes that the cellulosic
biofuel volumes will not exceed those required under EISA. We do
assume, however, that additional biodiesel than that needed to meet the
biomass-based diesel volume will be used to meet the total advanced
biofuel volume. Despite additional volumes assumed from biodiesel, to
fully meet the total advanced biofuel volume required under EISA, other
types of advanced biofuel are necessary through 2022.
    We have assumed for our control case that the most likely sources
of advanced fuel other than cellulosic biofuel and biomass-based diesel
would be from imported sugarcane ethanol and perhaps limited amounts of
co-processed renewable diesel. 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
advanced biofuel standards, we assumed it would make up the difference
not met by cellulosic biofuel, biomass-based diesel and additional
biodiesel categories (see Table IV.A.2-1). The amount of imported
ethanol required by 2022 is approximately 2.2 Bgal.

    As discussed in the NPRM, other potential advanced biofuels could
include for example, U.S. domestically produced sugarcane ethanol,
biobutanol, and biogas. While we have not chosen to reflect these fuels
in our control case, they can still be counted under our program
assuming they meet the lifecycle thresholds and other definitions under
the program.
d. Other Renewable Fuel
    The remaining portion of total renewable fuel not met with advanced
biofuel was assumed to come from corn-based ethanol (including small
amounts from other grains and waste sugars). EISA effectively sets a
limit for participation in the RFS program of 15 Bgal of corn ethanol,
and we are assuming for our analysis that sufficient corn ethanol will
be produced to meet the 15-Bgal limit that either meets the 20% GHG
threshold or is grandfathered. 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 (2010-2015) in which we project that some
fuels could compete favorably with corn ethanol (e.g., biodiesel and
imported ethanol). Refer to Section 1.2 of the RIA for more details on
interim years. Beginning around 2016, fuels qualifying as advanced
biofuels likely will be devoted to meeting the increasingly stringent
volume mandates for advanced biofuel. It is also important to note that
more than 15 Bgal of corn ethanol could be produced and RINs generated
for that volume under the RFS2 regulations. However, obligated parties
would not be required to purchase more than 15 Bgal worth of non-
advanced biofuel RINs, e.g. corn ethanol RINs.
3. Additional Control Cases Considered
    Since there is significant uncertainty surrounding what fuels will
be produced to meet the 16 billion gallon cellulosic biofuel standard,
we have decided to investigate two other sensitivity cases for our cost
and emission impact analyses conducted for the rule. The first case, we
refer to as the ``low-ethanol'' control case and assume only 250
million gallons of cellulosic ethanol (from AEO 2007 reference case).
The rest of the 16 billion gallon cellulosic biofuel standard is made
up of cellulosic diesel as shown in Table IV.A.3-1. The second case, we
refer to as the ``high-ethanol'' control case and assume the entire 16
billion gallon cellulosic biofuel standard is met with cellulosic
ethanol, also shown in Table IV.A.3-1.

                                          Table IV.A.3-1--Control Case Projected Renewable Fuel Volumes in 2022
                                                                    [Billion gallons]
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                Advanced biofuel                                    Non-
                                                 ------------------------------------------------------------------------------   advanced
                                                     Cellulosic biofuel     Biomass-based diesel \a\   Other advanced biofuel     biofuel       Total
                Case/volume type                 -------------------------------------------------------------------------------------------  renewable
                                                                                Other                                   fuel
                                                   Cellulosic   Cellulosic    FAME \c\     NCRD \d\    biodiesel     Imported       Corn
                                                    ethanol     diesel \b\   biodiesel                    \e\        ethanol      ethanol
--------------------------------------------------------------------------------------------------------------------------------------------------------
Low-Ethanol Straight Volume.....................         0.25         9.26         0.85         0.15         0.82         2.24        15.00        28.57
Low-Ethanol Ethanol-Equivalent..................         0.25        15.75         1.28         0.26         1.23         2.24        15.00        36.00
High-Ethanol Straight Volume....................        16.00         0.00         0.85         0.15         0.82         2.24        15.00        35.06
High-Ethanol Ethanol-Equivalent.................        16.00         0.00         1.28         0.26         1.23         2.24        15.00        36.00
--------------------------------------------------------------------------------------------------------------------------------------------------------
\a\ Biomass-Based Diesel could include FAME biodiesel, cellulosic diesel, and non-co-processed renewable diesel.
\b\ Cellulosic Diesel includes 1.96 billion gallons (3.33 ethanol-equivalent billion gallons) from Fischer-Tropsch Biomass-to-Liquids (BTL) processes
  and 7.30 billion gallons (12.42 ethanol-equivalent billion gallons) from other types of cellulosic diesel processes for the Low-Ethanol case and zero
  cellulosic diesel in the High-Ethanol Case.
\c\ Fatty acid methyl ester (FAME) biodiesel.
\d\ Non-Co-processed Renewable Diesel (NCRD).
\e\ Other Biodiesel is biodiesel that could be produced in addition to the amount needed to meet the biomass-based diesel standard.

    In comparison, our primary control case described in Section
IV.A.2, could be considered a ``mid-ethanol'' control case, as the
cellulosic ethanol and diesel volumes analyzed are in between the low-
ethanol and high-ethanol cases described in this section. We believe
the addition of these sensitivity cases is useful in understanding the
potential impacts of the renewable fuels standards. Refer to Section
1.2 of the RIA for more detail on three control cases analyzed as part
of this rule.

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 summarize the present state of the
corn/starch ethanol industry and discuss how we expect things to change
in the future under the RFS2 program.
a. Historic/Current Production
    The United States is currently the largest ethanol producer in the
world. In 2008, the U.S. produced nine billion gallons of fuel ethanol
for domestic consumption, the majority of which came from locally grown
corn.\41\ The nation is currently on track for producing over 10
billion gallons by the end of 2009.\42\ Although the U.S. ethanol
industry has been in existence since the 1970s, it has rapidly expanded
in recent years due to the phase-out of methyl tertiary butyl ether
(MTBE), elevated crude oil prices, state mandates and tax incentives,
the introduction of the Federal Volume Ethanol Excise Tax

Credit (VEETC),\43\ the implementation of the existing RFS1
program,\44\ and the new volume requirements established under EISA. As
shown in Figure IV.B.1-1, U.S. ethanol production has grown
exponentially over the past decade.
---------------------------------------------------------------------------

    \41\ Based on total transportation ethanol reported in EIA's
September 2009 Monthly Energy Review (Table 10.2) less imports
(http://tonto.eia.doe.gov/dnav/pet/hist/mfeimus1a.htm).
    \42\ Based on ethanol projected in EIA's October 2009 Short Term
Energy Outlook less projected imports. Actual year-end data for 2009
was unavailable at the time of this FRM assessment.
    \43\ 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 ethanol blender credit replaced the former fuel excise tax
exemption, blender's credit, and pure ethanol fuel credit. However,
the 2008 Farm Bill modified the alcohol credit so that corn ethanol
gets a reduced credit of $0.45/gal and cellulosic biofuel gets a
credit of $1.01/gal.
    \44\ On May 1, 2007, EPA published a final rule (72 FR 23900)
implementing the Renewable Fuel Standard required by EPAct (also
known as RFS1). RFS1 requires that 4.0 billion gallons of renewable
fuel be blended into gasoline/diesel by 2006, growing to 7.5 billion
gallons by 2012.
[GRAPHIC] [TIFF OMITTED] TR26MR10.419

    As of November 2009 there were 180 corn/starch ethanol plants
operating in the U.S. with a combined production capacity of
approximately 12 billion gallons per year.\46\ This does not include
idled ethanol plants, discussed later in this subsection. The majority
of today's ethanol production (91.5% by volume) comes from 155 plants
relying exclusively on corn. Another 8.3% comes from 18 plants
processing a blend of corn and/or similarly processed grains (milo,
wheat, or barley). The remainder comes from seven small plants
processing waste beverages or other waste sugars and starches.
---------------------------------------------------------------------------

    \45\ Based on total transportation ethanol reported in EIA's
September 2009 Monthly Energy Review (Table 10.2) less imports
(http://tonto.eia.doe.gov/dnav/pet/hist/mfeimus1a.htm).
    \46\ Our November 2009 corn/starch ethanol industry
characterization was based on a variety of sources including plant
lists published online by the Renewable Fuels Association and
Ethanol Producer Magazine (updated October 22, 2009), information
from ethanol producer Web sites including press releases, and
follow-up correspondence with producers. 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.
---------------------------------------------------------------------------

    Of the 173 plants processing corn and/or other similarly processed
grains, 162 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 plants using front-end
fractionation to produce food-grade corn oil or back-end extraction to
produce fuel-grade corn oil for the biodiesel industry. A company
called GreenShift has corn oil extraction facilities located at five
ethanol plants in Michigan, Indiana, New York and Wisconsin.\47\
Collectively, these facilities are designed to extract in excess of 7.3
million gallons of corn oil per year. Primafuel Solutions is another
company offering corn oil extraction technologies to make existing
ethanol plants more sustainable. For more information on corn oil
extraction and other advanced technologies being pursued by today's
corn ethanol industry, refer to Section 1.4.1 of the RIA.
---------------------------------------------------------------------------

    \47\ Two plants in Michigan and one in each of the other three
states. All company information based on GreenShift's Q2 2009 SEC
filing available at http://www.greenshift.com/pdf/GERS_Form10Q_
Q209_FINAL.pdf.
---------------------------------------------------------------------------

    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.\48\ As such, 11.4% of the current grain ethanol production
comes from the 11 previously mentioned wet mill facilities.
---------------------------------------------------------------------------

    \48\ According to our November 2009 corn ethanol plant
assessment, the average wet mill plant capacity is 125 million
gallons per year--almost twice that of the average dry mill plant
capacity (65 million gallons per year). For more on average plant
sizes, refer to Section 1.5 of the RIA.
---------------------------------------------------------------------------

    The remaining seven ethanol plants process waste beverages or waste
sugars/starches and operate differently than their grain-based
counterparts. These small production facilities do not require milling
and operate simpler enzymatic fermentation processes.
    Ethanol production is a relatively resource-intensive process that
requires the use of water, electricity, and steam. Steam needed to heat
the process is generally produced on-site or by other dedicated
boilers.\49\ The ethanol industry relies primarily on natural gas. Of
today's 180 ethanol production facilities, an estimated 151 burn
natural gas \50\ (exclusively), three burn a combination of natural gas
and biomass, one burns natural gas and coal (although natural gas is
the primary fuel), one burns a combination of natural gas, landfill
biogas and wood, and two burn natural gas and syrup from the process.
We are aware of 17 plants that burn coal as their primary fuel and one
that burns a combination of coal and biomass.\51\ Our research suggests
that three corn ethanol plants rely on a combination of waste heat and
natural gas and one plant does not have a boiler and relies solely on
waste heat from a nearby power plant. Overall, our research suggests
that 27 plants currently utilize cogeneration or combined heat and
power (CHP) technology, although others may exist.\52\ 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.\53\
---------------------------------------------------------------------------

    \49\ Some plants pull steam directly from a nearby utility.
    \50\ Facilities were assumed to burn natural gas if the plant
boiler fuel was unspecified or unavailable on the public domain.
    \51\ Includes corrections from NPRM based on new information
obtained on Cargill plants and Blue Flint ethanol plant.
    \52\ CHP assessment based on information provided by EPA's
Combined Heat and Power Partnership, literature searches and
correspondence with ethanol producers.
    \53\ For more on CHP technology, refer to Section <IP_ADDRESS> of the
RIA.
---------------------------------------------------------------------------

    During the ethanol fermentation process, large amounts of carbon
dioxide (CO2) gas are released. In some plants the
CO2 is vented into the atmosphere, but where local markets
exist, it is captured, purified, and sold to the food processing
industry for use in carbonated beverages and flash-freezing
applications. We are currently aware of 40 fuel ethanol plants that
recover CO2 or have facilities in place to do so. According
to Airgas, a leading gas distributor, the U.S. ethanol industry
currently recovers 2 to 2.5 million tons of CO2 per year
which translates to about 5-7% of all the CO2 produced by
the industry.\54\
---------------------------------------------------------------------------

    \54\ Based on information provided by Bruce Woerner at Airgas on
August 14, 2009.
---------------------------------------------------------------------------

    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 180 ethanol production facilities, 163 are located in the 15
states comprising PADD 2. For a map of the government's Petroleum
Administration for Defense Districts or PADDs, refer to Figure IV.B.1-
2.
[GRAPHIC] [TIFF OMITTED] TR26MR10.420

    As a region, PADD 2 accounts for over 94% (or 11.3 billion gallons)
of today's estimated ethanol production capacity, followed by PADD 3
(2.4%), PADDs 4 and 1 (each with 1.3%) and PADD 5 (0.8%). For more
information on today's ethanol plant locations, refer to Section 1.5.1
of the RIA.
    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, these facilities account for about 80% of today's
online ethanol production capacity.\55\ Furthermore, nearly 30% of the
total domestic product comes from 40 plants owned by just three
different companies--POET Biorefining, Archer Daniels Midland (ADM),
and Valero Renewables. Valero entered the ethanol industry in March of
2009 when it acquired seven ethanol plants from

former ethanol giant, Verasun. The oil company currently has agreements
in place to purchase three more ethanol plants that would bring the
company's ethanol production capacity to 1.1 billion gallons per
year.\56\ However, ethanol plants are much smaller than petroleum
refineries. Valero's smallest petroleum refinery in Ardmore, OK has
about twice the throughput of all its ethanol plants combined.\57\
Still, as obligated parties under RFS1 and RFS2, the refining industry
continues to show increased interest in biofuels. Suncor and Murphy Oil
recently joined Valero as the second and third oil companies to
purchase idled U.S. ethanol plants. Many refiners are also supporting
the development of cellulosic biofuels and algae-based biodiesel.
---------------------------------------------------------------------------

    \55\ Company-owned plants were assumed to be all those companies
not denoted as locally-owned based on Renewable Fuels Association
(RFA), Ethanol Biorefinery Locations (updated October 22, 2009). For
more on average plant sizes, refer to Section 1.5.1 of the RIA.
    \56\ Valero recently announced that it has purchase agreements
in place to acquire the last two Verasun plants in Linden, IN and
Bloomington, OH and the former Renew Energy plant in Jefferson
Junction, WI.
    \57\ Based on refinery information provided at http://
www.valero.com/OurBusiness/OurLocations/.
---------------------------------------------------------------------------

b. Forecasted Production Under RFS2
    As highlighted earlier, domestic ethanol production is projected to
grow to over 10 billion gallons in 2009. And with over 12 billion
gallons of capacity online as of November 2009, ethanol production
should continue to grow in 2010, provided plants continue to produce at
or above today's production levels. In addition, despite current market
conditions (i.e., poor ethanol margins), the ethanol industry is
expected to grow in the future under the RFS2 program. Although there
is not a set corn ethanol requirement, EISA allows for 15 billion
gallons of the 36-billion gallon renewable fuel standard to be met by
conventional biofuels. We expect that corn ethanol will fulfill this
requirement, provided it is more cost competitive than imported ethanol
or cellulosic biofuel in the marketplace.
    In addition to the 180 aforementioned corn/starch ethanol plants
currently online, 27 plants are presently idled.\58\ Some of these are
smaller ethanol plants that have been idled for quite some time,
whereas others are in a more temporary ``hot idle'' mode, ready to be
restarted. In response to the economic downturn, a number of ethanol
producers have idled production, halted construction projects, sold off
plants and even filed for Chapter 11 bankruptcy protection. Some corn
ethanol companies have exited the industry all together (e.g., Verasun)
whereas others are using bankruptcy as a means to protect themselves
from creditors as they restructure their finances with the goal of
becoming sustainable.
---------------------------------------------------------------------------

    \58\ Based on our November 2009 corn/starch ethanol industry
characterization. We are aware of at least one plant that has come
back online since then.
---------------------------------------------------------------------------

    Crude oil prices are expected to increase in the future making corn
ethanol more economically viable. According to EIA's AEO 2009, crude
oil prices are projected to increase from about $80/barrel (today's
price) to $116/barrel by 2022.\59\ As oil and gas prices rebound, we
expect that the biofuels industry will as well. Since our April 2009
industry assessment used for the NPRM, at least nine corn ethanol
plants have come back online.
---------------------------------------------------------------------------

    \59\ EIA, Annual Energy Outlook 2009--ARRA Update (Table 12).
---------------------------------------------------------------------------

    For analysis purposes, we assumed that all 27 idled corn/starch
ethanol plants would resume operations by 2022 under the RFS2 program.
We also assumed that a total of 11 new ethanol plants and two expansion
projects currently under construction or in advanced stages of planning
would come online.\60\ This includes two large dry mill expansion
projects currently underway at existing ADM wet mill plants and two
planned combination corn/cellulosic ethanol plants that received
funding from DOE. While several of these projects are delayed or on
hold at the moment, we expect that these facilities (or comparable
replacement projects) would eventually come online to get the nation to
approximately 15 billion gallons of corn ethanol production capacity.
---------------------------------------------------------------------------

    \60\ Sources include Renewable Fuels Association, Ethanol
Biorefinery Locations (updated October 22, 2009) and Ethanol
Producer Magazine, Producing, Not Producing, Under Construction, and
Expansions lists (last modified on October 22, 2009) in addition to
information gathered from producer Web sites and follow-up
correspondence.
---------------------------------------------------------------------------

    Almost 100% of conventional ethanol plant growth is expected to
come from facilities processing corn or other similarly processed
grains. And not surprisingly, the majority of growth (approximately 70%
by volume) is expected to originate from PADD 2. However, growth is
expected to occur in all PADDs. With the exception of one facility,\61\
all new corn/grain ethanol plants are expected to utilize dry milling
technologies and the majority of new production is expected to come
from plants burning natural gas. However, we anticipate that two manure
biogas plants,\62\ one biomass-fired plant, and two coal-fired ethanol
plants will be added to the mix.\63\ Of these new and returning idled
plants, we're aware of five facilities currently planning to use CHP
technology, bringing the U.S. total to 32.
---------------------------------------------------------------------------

    \61\ Tate and Lyle is currently in the process of building a 115
MGY wet mill corn ethanol plant in Fort Dodge, IA.
    \62\ One manure biogas plant that is currently idled and another
that was under construction but is now on hold.
    \63\ The two coal fired plants are the aforementioned dry mill
expansion projects currently underway at existing ADM sites. These
projects commenced construction on or before December 19, 2007 and
would therefore should likely be grandfathered under the RFS2 rule.
For more on our grandfathering assessment, refer to Section <IP_ADDRESS>
of the RIA.
---------------------------------------------------------------------------

    The above predictions are based on the industry's current near-term
production plans. However, we anticipate additional growth in advanced
ethanol production technologies under the RFS2 program. Forecasted fuel
prices are projected to drive corn ethanol producers to transition from
conventional boiler fuels to biomass feedstocks. In addition, fossil
fuel/electricity prices will likely 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 <IP_ADDRESS> of
the RIA.
2. Imported Ethanol
    As discussed in the proposal, 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. Between years 2000 and 2008, the volume of ethanol imported
into the U.S. has ranged from 46-720 million gallons per year. So far
this year, from January through November 2009, imported ethanol has
only reached 197 million gallons.\64\ As the data show, the volume of
imported ethanol can fluctuate greatly.
---------------------------------------------------------------------------

    \64\ Official Statistics of the U.S. Department of Commerce,
U.S. ITC.
---------------------------------------------------------------------------

    In the past, the majority of volume has originated from countries
that are part of the Caribbean Basin Initiative. Direct Brazilian
imports have also made up a sizeable portion of total ethanol imported
into the U.S. However, recently there have been relatively small
amounts of direct imports of ethanol from Brazil.\65\ This indicates
that current market conditions have made importing Brazilian ethanol
directly to the U.S. uneconomical. Part of the reason for this decline
in imports is the cessation of the duty drawback that became effective
on October 1, 2008, but also changes in world sugar prices.\66\
---------------------------------------------------------------------------

    \65\ Approximately 19,000 gallons directly from Brazil in the
month of June 2009 and 4 million gallons from Brazil in the month of
November 2009, zero gallons reported from November 2008-May 2009 and
July 2009-October 2009.
    \66\ Lundell, Drake, ``Brazilian Ethanol Export Surge to End;
U.S. Customs Loophole Closed Oct. 1,'' Ethanol and Biodiesel News,
Issue 45, November 4, 2008.

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

    It is difficult to project the potential volume of future ethanol
imports to the U.S. based purely on historical data. Rather, it is
necessary to assess future import potential by analyzing the major
players for foreign ethanol production and consumption. 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.\67\ Consumption of fuel ethanol is also dominated by the
United States and Brazil with approximately 9.6 and 4.9 billion gallons
consumed in each country, respectively.68 69 The EU consumed
approximately 0.9 billion gallons of fuel ethanol in 2008.\70\
---------------------------------------------------------------------------

    \67\ Renewable Fuels Association (RFA), ``2008 World Fuel
Ethanol Production, '' http://www.ethanolrfa.org/industry/
statistics/#E, March 31, 2009.
    \68\ Ibid.
    \69\ UNICA, ``Sugarcane Industry in Brazil: Ethanol Sugar,
Bioelectricity'' Brochure, 2008.
    \70\ EurObserv'ER, ``Biofuels Barometer'' July 2009, http://
www.eurobserv-er.org/pdf/baro192.pdf.
---------------------------------------------------------------------------

    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.
    Due to uncertainties in the future demand for ethanol domestically
and internationally, uncertainties in the actual investments made in
the Brazilian ethanol industry, as well as uncertainties in future
sugar prices, there appears to be a wide range of Brazilian production
and domestic consumption estimates. The most current and complete
estimates indicate that total Brazilian ethanol exports will likely
reach 3.8-4.2 billion gallons by 2022.71 72 73 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 about 2.2 billion
gallons (see Table IV.A.2-1), or approximately 55% of total Brazilian
ethanol export estimates. This is aggressive, yet within the bounds of
reason, therefore, we have made this simplifying assumption for the
purposes of further analysis.
---------------------------------------------------------------------------

    \71\ EPE, ``Plano Nacional de Energia 2030,'' Presentation from
Mauricio Tolmasquim, 2007.
    \72\ UNICA, ``Sugarcane Industry in Brazil: Ethanol, Sugar,
Bioelectricity,'' 2008.
    \73\ 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).
---------------------------------------------------------------------------

    Generally speaking, Brazilian ethanol exporters will seek routes to
countries with the lowest costs for transportation, taxes, and tariffs.
With respect to the U.S., the most likely route is through the
Caribbean Basin Initiative (CBI).\74\ Brazilian ethanol entering the
U.S. through CBI countries is not currently subject to the 54 cent/gal
imported ethanol tariff and yet receives the 45 cent/gal ethanol
blender credit. In addition to the U.S., other countries also have
similar tariffs on imported ethanol. Refer to Section 1.5.2 of the RIA
for more details. 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 2021 was 19.2 Bgal (under the
primary control case), then approximately 1.21 Bgal of ethanol could
enter the U.S. through CBI countries in 2022. 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. To meet our advanced biofuel standard, we assumed 1.03 Bgal of
sugarcane ethanol would be imported directly to the U.S. in 2022.
---------------------------------------------------------------------------

    \74\ 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.
---------------------------------------------------------------------------

3. Cellulosic Biofuel
    The majority of the biofuel currently produced in the United States
comes from plants processing first-generation feedstocks like corn,
plant oils, sugarcane, etc. Non-edible cellulosic feedstocks have the
potential to greatly expand biofuel production, both volumetrically and
geographically. Research and development on cellulosic biofuel
technologies has exploded over the last few years, and plants to
commercialize a number of these technologies are already beginning to
materialize. The $1.01/gallon tax credit for cellulosic biofuel that
was introduced in the 2008 Farm Bill and recently became effective, is
also offering much incentive to this developing industry. In addition
to today's RFS2 program which sets aggressive goals for cellulosic
biofuel production, the Department of Energy (DOE), Department of
Agriculture (USDA), Department of Defense (DOD) and state agencies are
helping to spur industry growth.
a. Current State of the Industry
    There are a growing number of biofuel producers, biotechnology
companies, universities and research institutes, start-up companies as
well as refiners investigating cellulosic biofuel production. The
industry is currently pursuing a wide range of feedstocks, conversion
technologies and fuels. There is much optimism surrounding the long-
term viability of cellulosic ethanol and other alcohols for gasoline
blending. There is also great promise and growing interest in synthetic
hydrocarbons like gasoline, diesel and jet fuel as ``drop in''
petroleum replacements. Some companies intend to start by processing
corn or sugarcane and then transition to cellulosic feedstocks while
others are focusing entirely on cellulosic materials. Regardless,
cellulosic biofuel production is beginning to materialize.
    We are currently aware of over 35 small pilot- and demonstration-
level plants operating in North America. However, the main focus at
these facilities is research and development, not commercial
production. Most of the plants are rated at less than 250,000 gallons
per year and that's if they were operated at capacity. Most only
operate intermittently for the purpose of demonstrating that the
technologies can be used to produce transportation fuels. The industry
as a whole is still working to increase efficiency, improve yields,
reduce costs and prove to the public, as well as investors, that
cellulosic biofuel is both technologically and economically feasible.
    As mentioned above, a variety of feedstocks are being investigated
for cellulosic biofuel production. There is a great deal of interest in
urban waste (MSW and C&D debris) because it is

virtually free and abundant in many parts of the country, including
large metropolitan areas where the bulk of fuel is consumed. There is
also a lot of interest in agricultural residues (corn stover, rice and
other cereal straws) and wood (forest thinnings, wood chips, pulp and
paper mill waste and yard waste). However, researchers are still
working to find viable harvesting and storage solutions. Others are
investigating the possibility of growing dedicated energy crops for
cellulosic biofuel production, e.g., switchgrass, energy cane, sorghum,
poplar, miscanthus and other fast-growing trees. While these crops have
tremendous potential, many are starting with the feedstocks that are
available today with the mentality that once the industry has proven
itself, it will be easier to secure growing contracts and start
producing energy crops. For more information on cellulosic feedstock
availability, refer to preamble Section IV.B.3.d and Section 1.1.2 of
the RIA.
    The industry is also pursuing a number of different cellulosic
conversion technologies and biofuels. Most of the technologies fall
into one of two categories: biochemical or thermochemical. Biochemical
conversion involves the use of acids and/or enzymes to hydrolyze
cellulosic materials into fermentable sugars and lignin. Thermochemical
conversion involves the use of heat to convert biomass into synthesis
gas or pyrolysis oil for upgrading. A third technology pathway is
emerging that involves the use of catalysts to depolymerize or reform
the feedstocks into fuel. The technologies currently being considered
are capable of producing cellulosic alcohols or hydrocarbons for the
transportation fuel market. Many companies are also researching the
potential of co-firing biomass to produce plant energy in addition to
biofuels. For a more in-depth discussion on cellulosic technologies,
refer to Section 1.4.3 of the RIA.
b. Setting the 2010 Cellulosic Biofuel Standard
    The Energy Independence and Security Act (EISA) set aggressive
cellulosic biofuel targets beginning with 100 million gallons in 2010.
However, EISA also supplied EPA with cellulosic biofuel waiver
authority. For any calendar year in which the projected cellulosic
biofuel production is less than the minimum applicable volume, EPA can
reduce the standard based on the volume expected to be available that
year. EPA is required to set the annual cellulosic standard by November
30th each year and should consider the annual estimate made by EIA by
October 31st of each year. We are setting the 2010 standard as part of
this final rule.
    Setting the cellulosic biofuel standard for 2010 represents a
unique challenge. As discussed above, the industry is currently
characterized by a wide range of companies mostly focused on research,
development, demonstration, and financing their developing
technologies. In addition, while we are finalizing a requirement that
producers and importers of renewable fuel provide us with production
outlook reports detailing future supply estimates (refer to Sec.
80.1449), we do not have the benefit of this valuable cellulosic supply
information for setting the 2010 standard. Finally, since today's
cellulosic biofuel production potential is relatively small, and the
number of potential producers few (as described in more detail below),
the overall volume for 2010 can be heavily influenced by new
developments, either positive or negative associated with even a single
company, which can be very difficult to predict. This is evidenced by
the magnitude of changes in cellulosic biofuel projections and the
potential suppliers of these fuels since the proposal.
    In the proposal, we did a preliminary assessment of the cellulosic
biofuel industry to arrive at the conclusion that it was possible to
uphold the 100 million gallon standard in 2010 based on anticipated
production. At the time of our April 2009 NPRM assessment, we were
aware of a handful of small pilot and demonstration plants that could
help meet the 2010 standard, but the largest volume contributions were
expected to come from Cello Energy and Range Fuels.
    Cello Energy had just started up a 20 million gallon per year (MGY)
cellulosic diesel plant in Bay Minette, AL. EPA staff visited the
facility twice in 2009 to confirm that the first-of-its-kind commercial
plant was mechanically complete and poised to produce cellulosic
biofuel. It was assumed that start-up operations would go as planned
and that the facility would be operating at full capacity by the end of
2009 and that three more 50 MGY cellulosic diesel plants planned for
the Southeast could be brought online by the end of 2010.
    At the time of our assessment, we were also anticipating cellulosic
biofuel production from Range Fuels' first commercial-scale plant in
Soperton, GA. The company received a $76 million grant from DOE to help
build a 40 MGY wood-based ethanol plant and they broke ground in
November 2007. In January 2009, Range was awarded an $80 million loan
guarantee from USDA.\75\ With the addition of this latest capital, the
company seemed well on its way to completing construction of its first
10 MGY phase by the end of 2009 and beginning production in 2010.
---------------------------------------------------------------------------

    \75\ For more information on federal support for biofuels, refer
to Section <IP_ADDRESS> of the RIA.
---------------------------------------------------------------------------

    Since our April 2009 industry assessment there have been a number
of changes and delays in production plans due to technological,
contractual, financial and other reasons. Cello Energy and Range Fuels
have delayed or reduced their production plans for 2010. Some of the
small plants expected to come online in 2010 have pushed back
production to the 2011-2012 timeframe, e.g., Clearfuels Technology,
Fulcrum River Biofuels, and ZeaChem. Alltech/Ecofin and RSE Pulp &
Chemical, two companies that were awarded DOE funding back in 2008 to
build small-scale biorefineries appear to be permanently on hold or off
the table. In addition, Bell Bio-Energy, a company that received DOD
funding has since abandoned plans to produce cellulosic diesel from MSW
at U.S. military bases.\76\
---------------------------------------------------------------------------

    \76\ Bell Bio-Energy is currently investigating other locations
for turning MSW into diesel fuel according to an October 14, 2009
conversation with JC Bell.
---------------------------------------------------------------------------

    At the same time, there has also been an explosion of new
companies, new business relationships, and new advances in the
cellulosic biofuel industry. Keeping track of all of them is a
challenge in and of it self as the situation can change on a daily
basis. EIA recently provided EPA with their first cellulosic biofuel
supply estimate required under CAA section 211(o)(7)(D)(i). In a letter
to the Administrator dated October 29, 2009, they arrived at a 5.04
million gallon estimate for 2010 based on publicly available
information and assumptions made with respect production capacity
utilization.\77\ A summary of the plants they considered is shown below
in Table IV.B.3-1.
---------------------------------------------------------------------------

    \77\ Letter from Richard Newell, EIA Administrator to Lisa
Jackson, EPA Administrator dated October 29, 2009 (Table 2).

                                 Table IV.B.3-1--EIA's Projected Cellulosic Biofuel Plant Production Capacities for 2010
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                Capacity        Expected       Production
               Online                       Company                Location               Product            (million       utilization      (million
                                                                                gallons)           (%)        gallons) \3\
--------------------------------------------------------------------------------------------------------------------------------------------------------
2007...............................  KL Process Design....  Upton, WY............  Ethanol..............             1.5              10            0.15
2008...............................  Verenium.............  Jennings, LA.........  Ethanol..............             1.4              10            0.14
2008...............................  Terrabon.............  Bryan, TX............  Bio-Crude............            0.93              10            0.09
2010...............................  Zeachem..............  Boardman, OR.........  Ethanol..............             1.5              10            0.15
2010...............................  Cello Energy.........  Bay Minette, AL......  Diesel...............            20.0          10 \1\            2.00
2010...............................  Range Fuels..........  Soperton, GA.........  Ethanol..............         5.0 \2\              50             2.5
                                                                                -----------------------------------------------
    Total..........................  .....................  .....................  .....................           30.35  ..............            5.04
--------------------------------------------------------------------------------------------------------------------------------------------------------
Notes: 1. Cello Energy is assigned a 10-percent utilization factor as they have not been able to run on a continuous basis long enough to apply for a
  Synthetic Minor Operating Permit or produce significant amounts of fuel during 2009. 2. It is estimated that only half the 2010 projected capacity (10
  million gallons per year) will be a qualified fuel. 3. The production from these facilities in 2009 is not surveyed by EIA or EPA.

    In addition to receiving EIA's information and coordinating with
them and other offices in DOE, we have initiated meetings and
conversations with over 30 up-and-coming advanced biofuel companies to
verify publicly available information, obtain confidential business
information, and better assess the near-term cellulosic biofuel
production potential for use in setting the 2010 standard. What we have
found is that the cellulosic biofuel landscape has continued to evolve.
Based on information obtained, not only do we project significantly
different production volumes on a company-by-company basis, but the
list of potential producers of cellulosic biofuel in 2010 is also
significantly different than that identified by EIA.
    Overall, our industry assessment suggests that it is difficult to
rely on commercial production from small pilot or demonstration-level
plants. The primary purpose of these facilities is to prove that a
technology works and demonstrate to investors that the process is
capable of being scaled up to support a larger commercial plant. Small
plants are cheaper to build to demonstrate technology than larger
plants, but the operating costs ($/gal) are higher due to their small
scale. As a result, it's not economical for most of these facilities to
operate continuously. Most of these plants are regularly shut down and
restarted as needed as part of the research and development process.
Due to their intermittent nature, most of these plants operate at a
fraction of their rated capacity, some less than the 10% utilization
rate assumed by EIA. In addition, few companies plan on making their
biofuel available for commercial sale.
    However, there are at least two cellulosic biofuel companies
currently operating demonstration plants in the U.S. and Canada that
could produce fuel commercially in 2010. The first is KL Energy
Corporation, a company we considered for the NPRM with a 1.5 MGY
cellulosic ethanol plant in Upton, WY. This plant was considered by EIA
and is included in Table IV.B.3-1. The second is Iogen's cellulosic
ethanol plant in Ottawa, Canada with a 0.5 MGY capacity. Iogen's
commercial demonstration plant was referenced by EIA as a potential
foreign source for cellulosic biofuel but was not included in their
final table. In addition to these online demonstration plants, there
are three additional companies not on EIA's list that are currently
building demonstration-level cellulosic biofuel plants in North America
that are scheduled to come online in 2010. This includes DuPont Danisco
Cellulosic Ethanol and Fiberight, companies building demonstration
plants in the U.S. and Enerkem, a company building a demonstration
plant in Canada. Cello Energy's plant in Bay Minette, AL continues to
offer additional potential for cellulosic biofuel in 2010. And finally,
Dynamotive, a company that currently has two biomass-based pyrolysis
oil production plants in Canada is another potential source of
cellulosic biofuel in 2010. All seven aforementioned companies are
discussed in greater detail below along with Range Fuels.
    KL Energy Corporation (KL Energy), through its majority-owned
Western Biomass Energy, LLC (WBE) located in Upton, WY, is designed to
convert wood products and wood waste products into ethanol. Since the
end of construction in September 2007, equipment commissioning and
process revisions continued until the October 2009 startup. The plant
was built as a 1.5 MGY demonstration plant and was designed to both
facilitate research and operate commercially. It is KL Energy's intent
that WBE's future use will involve the production and sale of small but
commercial-quality volumes of ethanol and lignin co-product. The
company's current 2010 goal is for WBE to generate RINs under the RFS2
program.\78\
---------------------------------------------------------------------------

    \78\ Based on information provided by Lori Litzen, Environmental
Permit Engineer at KL Energy on December 10, 2009.
---------------------------------------------------------------------------

    Iogen is responsible for opening the first commercial demonstration
cellulosic ethanol plant in North America. Iogen's plant located in
Ottawa, Canada has been producing cellulosic ethanol from wheat straw
since 2004. Like KL Energy, Iogen has slowly been ramping up production
at its 0.5 MGY plant. According to the company's Web site, they
produced approximately 24,000 gallons in 2004 and 34,000 gallons in
2005. Production dropped dramatically in 2006 and 2007 but came back
strong with 55,000 gallons in 2008. Iogen recently produced over
150,000 gallons of ethanol from the demonstration plant in 2009. Iogen
also recently became the first cellulosic ethanol producer to sell its
advanced biofuel at a retail service station in Canada. Their
cellulosic ethanol was blended to make E10 available for sale to
consumers at an Ottawa Shell station. Iogen also recently announced
plans to build its first commercial scale plant in Prince Albert,
Saskatchewan in the 2011/2012 timeframe. Based on the company's
location and operating status, Iogen certainly has the potential to
participate in the RFS2 program. However, at this time, we are not
expecting them to import any cellulosic ethanol into the U.S. in
2010.\79\
---------------------------------------------------------------------------

    \79\ Based on Web site information, comments submitted in
response to our proposal, and a follow-up phone call with Iogen
Executive VP, Jeff Passmore on December 17, 2009.
---------------------------------------------------------------------------

    DuPont Danisco Cellulosic Ethanol, LLC (DDCE), a joint venture
between DuPont and Danisco, is another potential source for cellulosic
biofuel in 2010. DDCE received funding from the State of Tennessee and
the University of Tennessee to build a small 0.25 MGY demonstration
plant in Vonore, TN to

pursue switchgrass-to-ethanol production. According to DDCE,
construction commenced in October 2008 and the plant is now
mechanically complete and undergoing start-up operations. The facility
is scheduled to come online by the end of January and the company hopes
to operate at or around 50% of production capacity in 2010. According
to the DDCE, the objective in Vonore is to validate processes and data
for commercial scale-up, not to make profits. However, the company does
plan to sell the cellulosic ethanol it produces.\80\
---------------------------------------------------------------------------

    \80\ Based on a December 16, 2009 telephone conversation with
DDCE Director of Corporate Communications, Jennifer Hutchins and
follow-up e-mail correspondence.
---------------------------------------------------------------------------

    Enerkem is another company pursuing cellulosic ethanol production.
The Canadian-based company was recently announced as a recipient of a
joint $50 million grant from DOE and USDA to build a 10 MGY woody
biomass-to-ethanol plant in Pontotoc, MS.\81\ The U.S. plant is not
scheduled to come online until 2012, but Enerkem is currently building
a 1.3 MGY demonstration plant in Westbury, Quebec. According to the
company, plant construction in Westbury started in October 2007 and the
facility is currently scheduled to come online around the middle of
2010. While it's unclear at this time whether the cellulosic ethanol
produced will be exported to the United States, Enerkem has expressed
interest in selling its fuel commercially.\82\
---------------------------------------------------------------------------

    \81\ Refer to December 4, 2009 DOE press release entitled,
``Recovery Act Announcement: Secretaries Chu and Vilsack Announce
More Than $600 Million Investment in Advanced Biorefinery
Projects.''
    \82\ Based on an October 14, 2009 meeting with Enerkem and
follow-up telephone conversation with VP of Government Affairs,
Marie-Helene Labrie on December 14, 2009.
---------------------------------------------------------------------------

    Additional cellulosic biofuel could come from Fiberight, LLC
(Fiberight) in 2010. We recently became aware of this start-up company
and contacted them to learn more about their process and cellulosic
biofuel production plans. According to Fiberight, they have been
operating a pilot-scale facility in Lawrenceville, VA for three years.
They have developed a proprietary process that not only fractionates
MSW but biologically converts the non-recyclable portion into
cellulosic ethanol and biochemicals. Fiberight recently purchased a
shut down corn ethanol plant in Blairstown, IA and plans to convert it
to become MSW-to-ethanol capable. According to the company,
construction is currently underway and the goal is to bring the 2 MGY
demonstration plant online by February or March, 2010. If the plant
starts up according to plan, the company intends on making cellulosic
ethanol commercially available in 2010 and generating RINS under the
RFS2 program. Fiberight's long-term goal is to expand the Blairstown
plant to a 5-8 MGY capacity and build other small commercial plants
around the country that could convert MSW into fuel.\83\
---------------------------------------------------------------------------

    \83\ Based on a December 15, 2009 telephone conversation with
Fiberight CEO, Craig Stuart-Paul and follow-up e-mail
correspondence.
---------------------------------------------------------------------------

    Cello Energy, a company considered in the proposal, continues to be
another viable source for cellulosic biofuel in 2010. Despite recent
legal issues which have constrained the company's capital, Cello Energy
is still pursuing cellulosic diesel production. According to the
company, they are currently working to resolve materials handling and
processing issues that surfaced when they attempted to scale up
production to 20 MGY from a previously operated demonstration plant. As
of November 2009, they were waiting for new equipment to be ordered and
installed which they hoped would allow for operations to be restarted
as early as February or March, 2010. Cello's other planned commercial
facilities are currently on hold until the Bay Minette plant is
operational.\84\
---------------------------------------------------------------------------

    \84\ Based on a November 9, 2009 telephone conversation with
Cello Energy CEO, Jack Boykin.
---------------------------------------------------------------------------

    Another potential supplier of cellulosic biofuel is Dynamotive
Energy Systems (Dynamotive) headquartered in Vancouver, Canada.
Dynamotive currently has two plants in West Lorne and Guelph, Ontario
that produce biomass-based pyrolysis oil (also known as ``BioOil'') for
industrial applications. The BioOil production capacity between the two
plants is estimated at around 9 MGY, but both plants are currently
operating at a fraction of their rated capacity.\85\ However, according
to a recent press release, Dynamotive has contracts in place to supply
a U.S.-based client with at least nine shipments of BioOil in 2010. If
Dynamotive's BioOil is used as heating oil or upgraded to
transportation fuel, it could potentially count towards meeting the
cellulosic biofuel standard in 2010.
---------------------------------------------------------------------------

    \85\ According to Dynamotive's Web site, the Guelph plant has a
capacity to convert 200 tonnes of biomass into BioOil per day. If
all modules are fully operational, the plant has the ability to
process 66,000 dry tons of biomass per year with an energy output
equivalent to 130,000 barrels of oil. The West Lorne plant has a
capacity to convert 130 tonnes of biomass into BioOil per day which,
if proportional to the Guelph plant, translates to an energy-
equivalent of 84,500 barrels of oil. According to a November 3, 2009
press release, Dynamotive has contracts in place to supply a U.S.-
based client with at least nine shipments of BioOil in 2010.
---------------------------------------------------------------------------

    As for the Range Fuels plant, construction of phase one in
Soperton, GA is about 85% complete, with start-up planned for mid-2010.
However, there have been some changes to the scope of the project that
will limit the amount of cellulosic biofuel that can be produced in
2010. The initial capacity has been reduced from 10 to 4 million
gallons per year. In addition, since they plan to start up the plant
using a methanol catalyst they are not expected to produce qualifying
renewable fuel in 2010. During phase two of their project, currently
slated for mid-2012, Range plans to expand production at the Soperton
plant and transition from a methanol to a mixed alcohol catalyst. This
will allow for a greater alcohol production potential as well as a
greater cellulosic biofuel production potential.\86\
---------------------------------------------------------------------------

    \86\ Based on a November 5, 2009 telephone conversation with
Range Fuels VP of Government Affairs, Bill Schafer.
---------------------------------------------------------------------------

    Overall, our most recent industry assessment suggests that there
could potentially be over 30 MGY of cellulosic biofuel production
capacity online by the end of 2010.\87\ However, since most of the
plants are still under construction today, the amount of cellulosic
biofuel produced in 2010 will be contingent upon when and if these
plants come online and whether the projects get delayed due to funding
or other reasons. In addition, based on our discussions with the
developing industry, it is clear that we cannot count on demonstration
plants to produce at or near capacity in 2010, or in their first few
years of operation for that matter. The amount of cellulosic biofuel
actually realized will depend on whether the process works, the
efficiency of the process, and how regularly the plant is run. As
mentioned earlier, most small plants, including commercial
demonstration plants, are not operated continuously. As such, we cannot
base the standard on these plants running at capacity--at least until
the industry develops further and proves that such rates are
achievable. We currently estimate that production from first-of-its
kind plants could be somewhere in the 25-50% range in 2010. Together,
the implementation timelines and anticipated production levels of the
plants described above brings the cellulosic biofuel supply estimate to
somewhere in the 6-13 million gallon range for 2010.
---------------------------------------------------------------------------

    \87\ For more information, refer to Section <IP_ADDRESS> of the RIA.
---------------------------------------------------------------------------

    In addition, it is unclear how much we can rely on Canadian plants
for

cellulosic biofuel in 2010. Although we currently receive some
conventional biofuel imports from Canada and many of the aforementioned
Canadian companies have U.S. markets in mind, the country also has its
own renewable fuel initiatives that could keep much of the cellulosic
biofuel produced from coming to the United States, e.g., Iogen.
Finally, it's unclear whether all fuel produced by these facilities
will qualify as cellulosic biofuel under the RFS2 program. Several of
the companies are producing fuels or using feedstocks which may not in
fact qualify as cellulosic biofuel once we receive their detailed
registration information. Factoring in these considerations, the
cellulosic biofuel potential from the six more likely companies
described above could result in several different production scenarios
in the neighborhood of the recent EIA estimate. We believe this
estimate of 5 million gallons or 6.5 ethanol-equivalent million gallons
represents a reasonable yet achievable level for the cellulosic biofuel
standard in 2010 considering the degree of uncertainty involved with
setting the standard for the first year. As mentioned earlier, we
believe standard setting will be easier in future years once the
industry matures, we start receiving production outlook reports and
there is less uncertainty regarding feasibility of cellulosic biofuel
production.
c. Current Production Outlook for 2011 and Beyond
    Since the proposal, we have also learned about a number of other
cellulosic biofuel projects in addition to those described above. This
includes commercial U.S. production plans by Coskata, Enerkem and
Vercipia. However, production isn't slated to begin until 2011 or later
and the same is true for most of the other larger plants we're aware of
that are currently under development. Nonetheless, while cellulosic
biofuel production in 2010 may be limited, it is remarkable how much
progress the industry has made in such a short time, and there is a
tremendous growth opportunity for cellulosic biofuels over the next
several years.
    Most of the cellulosic biofuel companies we've talked to are in
different stages of proving their technologies. Regardless of where
they are at, many have fallen behind their original commercialization
schedules. As with any new technology, there have been delays
associated with scaling up capacity, i.e., bugs to work out going from
pilot to demonstration to commercialization. However, most are saying
it's not the technologies that are delaying commercialization, it is
lack of available funding. Obtaining capital has been very challenging
given the current recession and the banking sector's financial
difficulties. This is especially true for start-up companies that do
not have access to capital through existing investors, plant profits,
etc. From what we understand, banks are looking for cellulosic
companies to be able to show that their plants are easily ``scalable''
or expandable to commercial size. Many are only considering companies
that have built plants to one-tenth of commercial scale and have logged
many hours of continuous operation.
    The government is currently trying to help in this area. To date,
the Department of Energy (DOE) and the Department of Agriculture (USDA)
have allocated over $720 million in federal funding to help build pilot
and demonstration-scale biorefineries employing advanced technologies
in the United States. The largest installment from Recovery Act funding
was recently announced on December 4, 2009 and includes funding for a
series of larger commercial demonstration plants including cellulosic
ethanol projects by Enerkem and INEOS New Planet BioEnergy, LLC. DOE
has also issued grants to help fund some of the first commercial
cellulosic biofuel plants. Current recipients include Abengoa
Bioenergy, BlueFire Ethanol \88\ and POET Biorefining in addition to
Range Fuels. DOE and USDA are also issuing loan guarantees to help
support the up-and-coming cellulosic biofuels industry and funding
research and development. Many states are also providing assistance.
For more information on government support for biofuels, refer to
Section <IP_ADDRESS> of the RIA.
---------------------------------------------------------------------------

    \88\ Although BlueFire is still working on obtaining financing
to build its first demonstration plant, it has received two
installments of federal funding towards its first planned
commercial-scale plant. The 19 MGY plant planned for Fulton, MS
(originally planned for Southern California) was awarded $40 million
from DOE on February 28, 2008 and another $81.1 million from DOE and
USDA on December 4, 2009.
---------------------------------------------------------------------------

    The refining industry is also helping to fund cellulosic biofuel
R&D efforts and some of the first commercial plants. Many of the major
oil companies have invested in advanced second-generation biofuels over
the past 12-18 months. A few refiners (e.g., BP and Shell) have even
entered into joint ventures to become cellulosic biofuel producers.
General Motors and other vehicle/engine manufacturers are also
providing financial support to help with research and development.
    A summary of some of the cellulosic biofuel companies with near-
term commercialization plans in North America is provided in Table
IV.B.3-2. The capacities presented represent maximum annual average
throughput based on each company's current production plans. However,
as noted, capacity does not necessarily translate to production. Actual
production of cellulosic biofuel will likely be well below capacity,
especially in the early years of production. We will continue to track
these companies and the cellulosic biofuel industry as a whole
throughout the duration of the RFS2 program. In addition, we will
continue to collaborate with EIA in annual standard setting. A more
detailed discussion of the plants corresponding to these company
estimates is provided in Section 1.5.3 of the RIA.
BILLING CODE 6560-50-P

[GRAPHIC] [TIFF OMITTED] TR26MR10.421

BILLING CODE 6560-50-C

d. Feedstock Availability
    A wide variety of feedstocks can be used for cellulosic biofuel
production, including: Agricultural residues, forestry biomass, certain
renewable portions of municipal solid waste and construction and
demolition waste (i.e., separated food, yard and incidental, and post-
recycled paper and wood waste as discussed in Section II.B.4) and
energy crops. These feedstocks are currently much more difficult to
convert into biofuel than traditional corn/starch crops or at least
require new and different processes because of the more complex
structure of cellulosic material.
    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
determine the most economical volume of agriculture residues, energy
crops, and forestry resources (see Section VIII for more details on the
FASOM) used to meet the standard. We supplemented these estimates with
feedstock assessment estimates for the biomass portions of municipal
solid waste and construction and demolition waste.\89\
---------------------------------------------------------------------------

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

    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 IV.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 incurs a fee for its disposal
may be among the first to be used. Urban wastes are used in a variety
of ways. Most commonly, wastes are ground into mulch, dumped into land-
fills, or incinerated. We describe two components of urban waste,
municipal solid waste (MSW) and construction and demolition (C&D)
debris, below.
    MSW consists of paper, glass, metals, plastics, wood, yard
trimmings, food scraps, rubber, leather, textiles, etc. The portion of
MSW that can qualify as renewable biomass under the program is
discussed in Section II.B.4.d. The bulk of the biogenic portion of MSW
that can be converted into biofuel is cellulosic material such as wood,
yard trimmings, paper, and much of food wastes. Paper made up
approximately 31% of the total MSW generated in 2008.\90\ 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. 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).
---------------------------------------------------------------------------

    \90\ EPA. Municipal Solid Waste Generation, Recycling, and
Disposal in the United States: Facts and figures for 2008.
---------------------------------------------------------------------------

    We estimated that a total of 44.5 million dry tons of MSW (wood,
yard trimmings, paper, and food waste) 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.91 92 Between
the proposal and this final rule, we have updated the assumptions noted
above based on newer reports. It should be noted, however, that our
estimates of urban waste availability have not changed significantly
between the proposal and the final rule. We assumed that approximately
26 million dry tons (of the total 44.5 million dry tons) could be used
to produce biofuels. However, many areas of the U.S. (e.g., much of the
Rocky Mountains) have such sparse resources that an MSW and C&D
cellulosic facility would not likely be justifiable. We did assume that
in areas with other 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 2.3 ethanol-equivalent billion gallons of fuel.\93\ Note
that some processes are likely to also process other portions of MSW
(e.g., plastics, rubbers) into fuel, but we have only accounted for the
portion expected to qualify as renewable fuel and produce RINs.
---------------------------------------------------------------------------

    \91\ Wiltsee, G., ``Urban Wood Waste Resource Assessment,''
NREL/SR-570-25918, National Renewable Energy Laboratory, November
1998.
    \92\ Biocycle, ``The State of Garbage in America,'' Vol. 49, No.
12, December 2008, p. 22.
    \93\ 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.\94\
Katrina also generated over 100 million tons of residential debris, not
including the commercial sector. Much of this waste would likely be
disposed of and therefore go unused. Collection of this material for
the generation of biofuel could be a better alternative use for this
waste. While we acknowledge this material could provide a large source
in the short-term, natural disasters are highly variable, making it
hard to predict amounts of material available in the future. Thus, for
our analyses we have not included natural disaster renewable biomass in
our estimates.
---------------------------------------------------------------------------

    \94\ 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 residues are corn stover (the stalks, leaves,
and/or cobs) and straw from wheat, rice, barley, and oats. These U.S.
crops and others 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.\95\ 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.
---------------------------------------------------------------------------

    \95\ 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 raise
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 shows that under current rotation and tillage practices,
about 30% of corn 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.\96\ The same study
shows that if farmers convert to no-till corn management and total
stover production does 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.\97\ 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 no stover is removable on conventional tilled
lands, 35% of stover is removable on conservation tilled lands, and 50%
is removable on no-till lands. In general, these removal guidelines are
appropriate only for the Midwest, where the majority of corn is
currently grown.
---------------------------------------------------------------------------

    \96\ Graham, R.L., ``Current and Potential U.S. Corn Stover
Supplies,'' American Society of Agronomy 99:1-11, 2007.
    \97\ 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 by region due to local
differences. Given the current understanding of sustainable removal
rates, we believe that such assumptions are reasonably justified. Based
on our research, we also note that calculating 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. 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, however,
we had limited data on which to accurately apply this approach and
therefore assumed the removal guidelines based on tillage practices.
    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 (4.9 ethanol-equivalent Bgal).\98\
Smaller contributions are expected to come from other crop residues
including sugarcane bagasse (0.6 ethanol-equivalent Bgal), wheat
residues (0.1 ethanol-equivalent Bgal), and sweet sorghum pulp (0.1
ethanol-equivalent Bgal).\99\
---------------------------------------------------------------------------

    \98\ Assuming 92.3 gal/dry ton ethanol conversion yield for corn
stover in 2022.
    \99\ 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 and sorghum being
an agricultural feedstock.
---------------------------------------------------------------------------

    The U.S. also 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.\100\ Logging residues are produced in
conventional harvest operations, forest management activities, and
clearing operations. In 2004, these operations generated approximately
67 million dry tons of forest residues that were left uncollected at
harvest sites.\101\ Other feedstocks include those from other removal
residues, thinnings from timberland, and primary mill residues.
---------------------------------------------------------------------------

    \100\ 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.
    \101\ USDA-Forest Service. ``Timber Products Output Mapmaker
Version 1.0.'' 2004.
---------------------------------------------------------------------------

    For the NPRM, FASOM was not able to model forestry biomass as a
potential feedstock. As a result, we relied on USDA-Forest Service (FS)
for information on the forestry sector at the time. For the final rule,
we were able to incorporate the forestry sector model in FASOM. 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, our modeling of
forestry biomass excluded such material. The FASOM model estimated that
approximately 0.1 ethanol-equivalent billion gallons would be produced
from forestry biomass 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 for
energy purposes. Various perennial plants have been researched as
potential dedicated feedstocks, including switchgrass, mixed prairie
grasses, hybrid poplar, miscanthus, energy cane, energy sorghum, and
willow trees. Refer to Section <IP_ADDRESS> of the RIA for more information
on the benefits and challenges with using dedicated energy crops.
    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 (7.9 ethanol-
equivalent Bgal).\102\ FASOM covers all cropland and pastureland in
production in the 48 contiguous United States. For the NPRM, FASOM did
not contain all categories of grassland and rangeland captured in
USDA's Major Land Use data sets. For the final rule, FASOM accounts for
all major land categories, including forestland and rangeland. All crop
production, including dedicated energy crops, takes place on cropland.
Land categories that can be converted to cropland production include
cropland pasture, forest pasture, and forestland. More detail can be
found in Chapter VIII of this preamble. Furthermore, we constrained
FASOM to be consistent with the 2008 Farm Bill and assumed 32 million
acres would stay in Conservation Reserve Program (CRP).\103\ 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 to meet EISA could be significant, similar
to our FASOM modeling results for the final rule.\104\
---------------------------------------------------------------------------

    \102\ Assuming 16 Bgal cellulosic biofuel total, 2.3 Bgal from
Urban Waste; 13.7 Bgal of cellulosic biofuel for ag residues,
forestry biomass, and/or energy crops would be needed.
    \103\ 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.
    \104\ 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 IV.B.3-3 summarizes our internal estimate of the types of
cellulosic feedstocks projected to be used and their corresponding
volume contribution to 16 billion gallons cellulosic biofuel by 2022
for the purposes of our impacts assessment. The majority of feedstock
is projected to come from dedicated energy crops. Other feedstocks
include agricultural residues, forestry biomass, and urban waste.

Table IV.B.3-3--Cellulosic Feedstocks Assumed To Meet EISA in 2022 \105\
------------------------------------------------------------------------
                                                                Volume
                                                              (ethanol-
                         Feedstock                            equivalent
                                                                Bgal)
------------------------------------------------------------------------
Agricultural Residues......................................          5.7
    Corn Stover............................................          4.9
    Sugarcane Bagasse......................................          0.6
    Wheat Residue..........................................          0.1
    Sweet Sorghum Pulp.....................................          0.1
Forestry Biomass...........................................          0.1
Urban Waste................................................          2.3
Dedicated Energy Crops (Switchgrass).......................          7.9
                                                            ------------
  Total....................................................         16.0
------------------------------------------------------------------------

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 storage
stability) for which the engines have been designed. The definition of
biodiesel given in applicable regulations is sufficiently broad to be
inclusive of both fuels.\106\ 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 the RFS2
volume requirements.\107\
---------------------------------------------------------------------------

    \105\ Volumes are represented here as ethanol-equivalent
volumes, a mix of diesel and ethanol volumes as described in Section
IV.A, above.
    \106\ 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 II.B.2, as published in the Federal Register Vol. 72, No.
83, p. 23917.
    \107\ For more detailed discussion of the definition of
coprocessing and its implications for compliance with EISA, see
Section II.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 processes are at various stages of
development, but due to uncertainty on production timelines, we didn't
include these fuels in the biomass-based diesel impact assessments.
a. Historic and Projected Production
i. Biodiesel
    As of November 2009, the aggregate production capacity of biodiesel
plants in the U.S. was estimated at 2.8 billion gallons per year across
approximately 191 facilities.\108\ (However, at the time of this
writing it is anticipated that capacity utilization will be
approximately 17% for calendar year 2009.) Biodiesel plants exist in
nearly all states, with the largest density of plants in the Midwest
and Southeast where agricultural feedstocks are most plentiful.
---------------------------------------------------------------------------

    \108\ Capacity data taken from National Biodiesel Board as of
November 2009.
---------------------------------------------------------------------------

    Table IV.B.4-1 gives data on U.S. biodiesel production and use for
recent years, including net domestic use after accounting for imports
and exports. 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
along a path of more small, privately-owned plants in comparison to the
ethanol industry, with median size less than 10 million gallons/
yr.\109\ These small plants, with relatively low costs other than
feedstock, have generally been able to survive producing well below
their nameplate capacities.
---------------------------------------------------------------------------

    \109\ Assessment of plant capital cost based on USDA production
cost models. A publication describing USDA modeling of biodiesel
production costs can be found in Bioresource Technology 97(2006)
671-8.

                          Table IV.B.4-1--Summary of U.S. Biodiesel Production and Use
                                             [Million gallons] \110\
----------------------------------------------------------------------------------------------------------------
                                                                                Net
                                    Domestic                          Apparent                         domestic
              Year                 production     Domestic total      capacity      Net domestic        use as
                                    capacity        production      utilization     biodiesel use     percent of
                                                                     (percent)                        production
----------------------------------------------------------------------------------------------------------------
2004............................          245  28.................           11  27................           96
2005............................          395  91.................           23  91................          100
2006............................          792  250................           32  261...............          104
2007............................        1,809  490................           27  358...............           73
2008............................        2,610  776................           30  413...............           53
2009............................        2,806  475 (est.).........           17  296 (est.)........           62
----------------------------------------------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \110\ Capacity data taken from National Biodiesel Board as of
November 2009. Production, import, and export figures taken from EIA
Monthly Energy Review, Table 10.4 as of December 2009.
---------------------------------------------------------------------------

    During 2004-2006, demand for biodiesel grew rapidly, but the trend
of increasing sales was quickly surpassed by construction and start-up
of new plants Since then, periods of high commodity prices followed by
reduced demand for transportation fuel during

the economic downturn have caused additional strain on the industry
beyond the overcapacity situation. Biodiesel producers were able to
find additional markets overseas, and a significant portion of the 2007
and 2008 production was exported to Europe where fuel prices and
additional tax subsidies helped offset high feedstock costs. However,
the EU enacted a tariff to protect domestic producers early in 2009,
after which exports dropped to a small fraction of production.\111\ We
understand there may be some additional export markets developing
within North America, but given the uncertainty at this time, we do not
account for any biodiesel exports in our projections.
---------------------------------------------------------------------------

    \111\ Ibid.
---------------------------------------------------------------------------

    To perform our impacts analyses for this rule, 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
industry capacity to be much closer to 1.67 billion gallons per year by
2022 (based on the volume requirements to meet the standard; see
Section IV.A.2). 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.\112\ Going forward producers will compete for feedstocks and
markets may consolidate. During this period the number of operating
plants is expected to shrink, with surviving plants utilizing 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 85%. Table IV.B.4-2 summarizes this
forecast. See Section 1.5.4 of the RIA for more details.
---------------------------------------------------------------------------

    \112\ Information on state incentives was taken from U.S.