Department of Energy Web site, accessed July 30, 2008, at http://
www.eere.energy.gov/afdc/fuels/biodiesel_laws.html. Information on
feedstock and BQ-9000 status was taken from Biodiesel Board fact
sheet, accessed July 30, 2008.

Table IV.B.4-2--Summary of Projected Biodiesel Industry Characterization
                       Used in Our Analyses \113\
------------------------------------------------------------------------
                                                          2008     2022
------------------------------------------------------------------------
Total production capacity on-line (million gal/yr)....    2,610    1,968
Number of operating plants............................      176      121
Median plant size (million gal/yr)....................        5        5
Total biodiesel production (million gal)..............      776    1,670
Average plant utilization.............................     0.30     0.85
------------------------------------------------------------------------

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

    \113\ 2008 capacity data taken from National Biodiesel Board;
production figures taken from EIA Monthly Energy Review, Table 10.4
as of October 2009.
---------------------------------------------------------------------------

    As a result of the oxygen and olefins in the feedstock being
removed, renewable diesel has storage, stability, and shipping
properties equivalent to petroleum diesel. This allows renewable diesel
fuel to be shipped in existing petroleum pipelines used for
transporting fuels, thus avoiding a significant issue with distribution
of biodiesel. For more on fuel distribution, refer to Section IV.C.
    Considering that this industry is still in development and that
there are no long-term projections of production volume, we base our
volume estimate of 150 MMgal/yr primarily on recent industry project
announcements involving proven technology. Due to the current status of
tax incentives, we project all of this fuel will be produced at stand-
alone facilities.
b. Feedstock Availability
    Publically available industry information along with agricultural
commodity modeling we have done for this rule (see Section VIII.A)
suggests that the three largest sources of feedstock for biodiesel will
be rendered animal fats, soy oil, and corn oil extracted from dry mill
ethanol facilities. Renewable diesel plants are expected to use solely
animal fats due to the fact that these feedstocks are cheaper than
vegetable oils and the process can handle them without issue. Comments
we have received from a large rendering company suggest there will be
adequate fats and greases feedstocks to supply biofuels as well as
other historical uses. Table IV.B.4-3 summarizes the feedstock types,
process types, and volumes projected to be used in 2022 for biodiesel
and renewable diesel. More details on feedstock sources and volumes are
presented in Section 1.1.3 of the RIA.

            Table IV.B.4-3--Summary of Projected Biodiesel and Renewable Diesel Feedstock Use in 2022
                                                     [MMgal]
----------------------------------------------------------------------------------------------------------------
                                                                                Acid-
                         Feedstock type                           Base catalyzed   pretreatment      Renewable
                                                                     biodiesel       biodiesel        diesel
----------------------------------------------------------------------------------------------------------------
Virgin vegetable oil............................................             660  ..............  ..............
Corn oil from ethanol production................................  ..............             680  ..............
Rendered animal fats and greases................................  ..............             230             150
Algae oil or other advanced source..............................             100  ..............  ..............
----------------------------------------------------------------------------------------------------------------

C. Biofuel Distribution

    The current motor fuel distribution infrastructure has been
optimized to facilitate the movement of petroleum-based fuels.
Consequently, there are very efficient pipeline-terminal networks that
move large volumes of petroleum-based fuels from production/import
centers on the Gulf Coast and the Northeast into the heartland of the
country. In contrast, most biofuel is produced in the heartland of the
country and needs to be shipped to the coasts, flowing roughly in the
opposite direction of petroleum-based fuels. In addition, while some
renewable fuels such as hydrocarbons may be transparent to the
distribution system, the physical/chemical nature of other renewable
fuels may limit the extent to which they can be shipped/stored fungibly
with petroleum-based fuels. The vast majority of biofuels are currently
shipped by rail, barge and tank truck to petroleum terminals. All
biofuels are currently blended with petroleum-based fuels prior to
use.\114\ Most biofuel blends can be used in conventional vehicles.
However, E85 can only be used in flex-fuel vehicles, requires specially
constructed retail dispensing/storage equipment, and may require
special blendstocks at terminals. These factors limit the ability of
biofuels to utilize the existing petroleum fuel distribution
infrastructure. Hence, the distribution of renewable fuels raises
unique concerns and in many instances requires the addition of new
transportation, storage, blending, and retail equipment.
---------------------------------------------------------------------------

    \114\ The prescribed blending ratio for a given biofuel is based
on vehicle compatibility and emissions considerations. Some biofuels
may be found to be suitable for use without the need for blending
with petroleum-based fuel.
---------------------------------------------------------------------------

1. Biofuel Shipment to Petroleum Terminals
    Ethanol currently is not commonly shipped by pipeline because it
can cause stress corrosion cracking in pipeline walls and its affinity
for water and solvency can result in product contamination concerns. A
short gasoline pipeline in Florida is currently shipping batches of
ethanol, and other more extensive pipeline systems have feasibility
studies underway.\115\ Thus, existing petroleum pipelines in some areas
of the country may play an increasing role in the shipment of ethanol.
Evaluations are also currently underway regarding the feasibility of
constructing a new dedicated ethanol pipeline from the Midwest to the
East coast. We expect that cellulosic distillate fuels will not have
materials compatibility issues with the existing petroleum fuel
distribution infrastructure. Thus, there may be more opportunity for
cellulosic distillate fuel to be shipped by pipeline. However, the
location of both ethanol and cellulosic distillate production
facilities relative to the origination points for existing petroleum
pipelines will be a limiting factor regarding the extent to which
pipelines can be used.
---------------------------------------------------------------------------

    \115\ Shipment of ethanol in pipelines that carry distillate
fuels as well as gasoline presents additional challenges.
---------------------------------------------------------------------------

    Our analysis of the shipment of ethanol and cellulosic distillate
fuels to petroleum terminals is based on the projections of the
location of biofuel production facilities and end use areas contained
in the NPRM. We assume that the majority of ethanol and cellulosic
distillate fuel would be produced in the Midwest, and that both fuels
would be shipped to petroleum terminals in a similar fashion (by rail,
barge, and tank truck). To the extent which new biofuel production
facilities are more dispersed than projected in the NPRM, there may be
more opportunity for both fuels to be used closer to their point of
manufacture. This potential benefit would primarily apply to cellulosic
ethanol and distillate production facilities given that such facilities
have yet to be constructed, whereas most corn-ethanol production
facilities have already been constructed in the Midwest.
    Biodiesel is currently not typically shipped by pipeline due to
concerns that it may contaminate jet fuel that is shipped on the same
pipeline and potential incompatibility with pipeline gaskets and seals.
Kinder Morgan's Plantation pipeline is currently shipping B5 blends on
segments of its system that do not handle jet fuel. The shipment of
biodiesel by pipeline may become more widespread and might be expanded
to systems that handle jet fuel. However, the relatively small
production volumes from individual biodiesel plants and the widespread
location of such production facilities will tend to limit the extent to
which biodiesel may be shipped by pipeline.
    Due to the uncertainties regarding the extent to which pipelines
might participate in the transportation of biofuels in the future, we
assumed that biofuels will continue to be transported by rail, barge,
and truck to petroleum terminals as the vast majority of biofuel
volumes are today. To the extent that pipelines do play an increasing
role in the distribution of ethanol, this may improve reliability in
supply and reduce distribution costs. Apart from increased shipment by
pipeline, biofuel distribution, and in particular ethanol distribution
can be further optimized primarily through the expanded use of unit
trains.\116\ We anticipate that the vast majority of ethanol and
cellulosic distillate facilities will be sized to facilitate unit train
service.\117\ We do not expect that biodiesel facilities will be of
sufficient size to justify shipment by unit train. In the NPRM, we
projected that unit train receipt facilities would be located at
petroleum terminals and existing rail terminals. Based on industry
input regarding the logistical hurdles in locating unit train receipt
facilities at petroleum/existing rail terminals, we expect that such
facilities will be constructed on dedicated property with rail access
that is as close to petroleum terminals as practicable.\118\
---------------------------------------------------------------------------

    \116\ Unit trains are composed of 70 to 100 rail cars that are
dedicated to shuttle back and forth from production facilities
downstream receipt facilities near petroleum terminals.
    \117\ A facility exists in Iowa to consolidate rail cars of
ethanol from some ethanol plants that are not large enough to
support unit train service by themselves.
    \118\ Existing unit train receipt facilities have primarily
followed this model.
---------------------------------------------------------------------------

    Shipment of biofuels by manifest rail to existing rail terminals
will continue to be an important means of supplying biofuels to distant
markets where the volume of the production facility and/or the local
demand is not sufficient to justify shipment by unit train.\119\
Shipments by barge will also play an important role in those instances
where production and demand centers have water access and in some cases
as the final link from a unit train receipt facility to a petroleum
terminal. Direct shipment by tank truck from production facilities to
petroleum terminals will also continue for shipment over distances
shorter than 200 miles.
---------------------------------------------------------------------------

    \119\ Manifest rail shipment refers to the shipment of rail cars
of biofuels in trains that also carry other products.
---------------------------------------------------------------------------

    We project that most biofuel volumes shipped by rail will be
delivered to petroleum terminals by tank truck.\120\ We expect that
this will always be the case for manifest rail shipments. In the NPRM,
we projected that trans-loading of biofuels from rail cars to tank
trucks would be an interim measure until biofuel storage tanks were
constructed.\121\ Based on industry input, we now expect trans-loading
will be a long-term means of transferring manifest rail car shipments
of biofuels received at

existing rail terminals to tank trucks for delivery to petroleum
terminals. We also anticipate that trans-loading will be used at some
unit train receipt facilities, although we expect that most of these
facilities will install biofuel storage tanks from which tank trucks
will be filled for delivery to petroleum terminals. Imported biofuels
will typically be received and be further distributed by tank truck
from petroleum terminals that already have receipt facilities for
waterborne fuel shipments.
---------------------------------------------------------------------------

    \120\ At least one current ethanol unit train receipt facility
has a pipeline link to a nearby terminal. To the extent that
additional unit train receipt facilities could accomplish the final
link to petroleum terminals by pipeline, this would significantly
reduce the need for shipment by tank truck.
    \121\ Trans-loading refers to the direct transfer of the
contents of a rail car to a tank truck without the intervening
delivery into a storage tank.
---------------------------------------------------------------------------

    We anticipate that the deployment of the necessary distribution
infrastructure to accommodate the shipment of biofuels to petroleum
terminals is achievable.\122\ We believe that construction of the
requisite rail cars, barges, tank trucks, tank truck and rail/barge/
truck receipt facilities is within the reach of corresponding
construction firms.\123\ Although shipment of biofuels by rail
represents a major fraction of all biofuel ton-miles, it is projected
to account for approximately 0.4% of all rail freight by 2022. Many
improvements to the freight rail system will be required in the next 15
years to keep pace with the large increase in the overall freight
demand. Given the broad importance to the U.S. economy of meeting the
anticipated increase in freight rail demand, and the substantial
resources that seem likely to be focused on this cause, we believe that
overall freight rail capacity would not be a limiting factor to the
successful implementation of the biofuel requirements under EISA.
---------------------------------------------------------------------------

    \122\ See Section 1.6 of the RIA for additional discussion of
the challenges in distributing biofuels from the production/import
facility to the end user.
    \123\ Vessels that transport biodiesel will need to be heated/
insulated in cold climates to prevent gelling.
---------------------------------------------------------------------------

2. Petroleum Terminal Accommodations
    Terminals will need to install additional storage capacity to
accommodate the volume of biofuels that we anticipate will be used in
response to the RFS2 standards. Petroleum terminals will also need to
install truck receipt facilities for biofuels and equipment to blend
biofuels into petroleum-based fuels. Upgrades to barge receipt
facilities to handle deliveries of biofuels may also be needed at
petroleum terminals with water access. Biodiesel storage and blending
facilities will need to be insulated/heated in cold climates to prevent
biodiesel from gelling.\124\ Questions have been raised about the
ability of some terminals to install the needed storage capacity due to
space constraints and difficulties in securing permits.\125\ Overall
demand for fuel used in motor vehicles is expected to remain relatively
constant through 2022. Thus, much of the increased demand for biofuel
storage could be accommodated by modifying storage tanks previously
used for the gasoline and petroleum-based diesel fuels that would
displaced by biofuels. The areas served by existing terminals also
often overlap. In such cases, one terminal might be space constrained
while another serving the same area may be able to install the
additional capacity to meet the increase in demand. In cases where it
is impossible for existing terminals to expand their storage capacity
due to a lack of adjacent available land or difficulties in securing
the necessary permits, new satellite storage or new separate terminal
facilities may be needed for additional storage of biofuels. However,
we believe that there would be few such situations.
---------------------------------------------------------------------------

    \124\ Some terminals are avoiding the need for heated/insulated
biodiesel facilities by storing high biodiesel blends (e.g. B50) for
blending with petroleum-based diesel fuel.
    \125\ The Independent Fuel Terminal Operators Association
represents terminals in the Northeast.
---------------------------------------------------------------------------

    In the NPRM, we stated the current EPA policy that the RFG and
anti-dumping regulations currently require certified gasoline to be
blended with denatured ethanol to produce E85. We also stated that if
terminal operators add blendstocks to finished gasoline for use in
manufacturing E85, the terminal operator would need to register as a
refiner with EPA and meet all applicable standards for refiners.
Commenters questioned these statements. As we are not taking any action
in this final rule with respect to policies surrounding E85, we will
consider these comments outside the context of this rule.
3. Potential Need for Special Blendstocks at Petroleum Terminals for
E85
    ASTM International is considering a proposal to lower the minimum
ethanol concentration in E85 to facilitate meeting ASTM minimum
volatility specifications in cold climates and when only low vapor
pressure gasoline is available at terminals.\126\ Commenters have
stated that the current proposal to lower the minimum ethanol
concentration to 68 volume percent may not be sufficient for this
purpose. ASTM International may consider an additional proposal to
further decrease the minimum ethanol concentration. Absent such an
adjustment, a high-vapor pressure petroleum-based blendstock such as
butane would need to be supplied to most petroleum terminals to produce
E85 that meets minimum volatility specifications. In such a case,
butane would need to be transported by tank truck from petroleum
refineries to terminals and storage and blending equipment would be
needed at petroleum terminals.\127\
---------------------------------------------------------------------------

    \126\ Minimum volatility specifications were established by ASTM
to address safety and vehicle driveability considerations.
    \127\ See Section 1.6 of the RIA for a discussion of the
potential distribution of butane to petroleum terminals for blending
with E85 and Section 4.2 for the potential costs.
---------------------------------------------------------------------------

    Instead of lowering the minimum ethanol concentration of E85, some
stakeholders are discussing establishing a new high-ethanol blend for
use in flex-fuel vehicles. Such a fuel would have a minimum ethanol
concentration that would be sufficient to allow minimum volatility
specifications to be satisfied while using finished gasoline that is
already available at petroleum terminals.\128\ E85 would continue to be
marketed in addition to this new fuel for use in flex-fuel vehicles
when E85 minimum volatility considerations could be satisfied.
---------------------------------------------------------------------------

    \128\ Such a new fuel might have a lower ethanol concentration
of 60% and a maximum ethanol concentration of 85%.
---------------------------------------------------------------------------

    We believe that industry will resolve the concerns over the ability
to meet the minimum volatility needed for high-ethanol blends used in
flex-fuel vehicles in a manner that will not necessitate the use of
high-vapor pressure blendstocks in their manufacture. Nevertheless,
petroleum terminals may find it advantageous to blend butane into E85
because of the low cost of butane relative to gasoline provided that
the cost benefit outweighs the associated butane distribution
costs.\129\
---------------------------------------------------------------------------

    \129\ EPA may consider reevaluating its policies regarding the
blendstocks used in the manufacture of E85 to facilitate this
practice.
---------------------------------------------------------------------------

4. Need for Additional E85 Retail Facilities
    The number of additional E85 retail facilities needed to consume
the volume of ethanol used under EISA varies substantially depending on
the control case. Under our primary mid-ethanol scenario, we estimate
that by 2022 an additional 19,765 E85 retail facilities would be needed
relative to the AEO reference case to enable the consumption of the
ethanol that we project would be used in E85.\130\ Under

the high-ethanol scenario, we estimate that an additional 23,809 E85
facilities would be needed and that 4,500 E85 facilities that would
otherwise be in place would need to be upgraded to include more E85
dispensers by 2022. Whereas under the low-ethanol volume scenario, we
project that 11,677 additional E85 facilities would be needed by 2022.
---------------------------------------------------------------------------

    \130\ See Section 1.6 of the RIA for a discussion of the
projected number of E85 refueling facilities that would be needed.
There would need to be a total of 24,265 E85 retail facilities under
the primary scenario, 4,500 of which are projected to have been
placed in service absent the RFS2 standards under the AEO reference
case. Our analysis assumes the installation of new dispensers and
underground storage tank (UST) systems for E85. EPA's Office of
Underground Storage Tanks requires that UST systems must be
compatible with the fuel stored. Authorities who Have Jurisdiction
(such as local fire marshals) typically require that fuel dispensers
be listed by an organization such as Underwriters Laboratories.
---------------------------------------------------------------------------

    On average, approximately 1,520 additional E85 facilities will be
needed each year from 2010 through 2022 under our primary scenario.
Under the high and low ethanol scenarios, an additional 1,820 and 900
E85 retail facilities per year respectively would be needed. Under the
high ethanol case and to a lesser extent under the primary case, this
represents an aggressive timeline for the addition of new E85
facilities given that there are approximately 2,000 E85 retail
facilities in service today. Nevertheless, we believe the addition of
these new E85 facilities may be possible for the industries that
manufacture and install E85 retail equipment. Underwriters Laboratories
requires that E85 refueling dispenser systems must be certified as
complete units.\131\ To date, no complete E85 dispenser systems have
been certified by UL. We understand that all the fuel dispenser
components with the exception of the hoses that connect to the
refueling nozzle have successfully passed the necessary testing. There
does not appear to be a technical difficulty in finding hoses that can
pass the required testing. Therefore, we anticipate this situation will
be resolved once the demand for new E85 facilities is demonstrated.
Hence, we believe that the current lack of a UL certification for
complete E85 dispenser systems will not impede the installation of the
additional E85 facilities that we projected will be needed.
---------------------------------------------------------------------------

    \131\ See http://ulstandardsinfonet.ul.com/outscope/0087A.html.
---------------------------------------------------------------------------

    Petroleum retailers expressed concerns about their ability to bear
the cost installing the needed E85 refueling equipment given that most
retailers are small businesses and have limited capital resources. They
also expressed concern regarding their ability to discount the price of
E85 relative to E10 sufficiently to persuade flexible fuel vehicle
owners to choose E85 given the lower energy density of ethanol. Today's
rule does not contain a requirement for retailers to carry E85. We
understand that retailers will only install E85 facilities if they can
be assured of sufficient E85 throughput to recover their capital costs.
The current projections regarding the future cost of gasoline relative
to ethanol indicate that it may be possible to price E85 in a
competitive fashion to E10. Thus, demand for E85 may be sufficient to
encourage retailers to install the needed E85 refueling facilities.

D. Ethanol Consumption

1. Historic/Current Ethanol Consumption
    Ethanol and ethanol-gasoline blends have a long history as
automotive fuels. In fact, the well-known Model-T was capable of
running on both ethanol and gasoline.\132\ However, inexpensive crude
oil prices kept ethanol from making a significant presence in the
transportation sector until the end of the 20th century. Over the past
decade, ethanol use has grown rapidly due to oxygenated fuel
requirements, MTBE bans, tax incentives, state mandates, the first
federal renewable fuels standard (``RFS1''), and rising crude oil
prices. Although the cost of crude has come down since reaching record
levels in 2008, uncertainty surrounding pricing and the environmental
implications of fossil fuels continue to drive ethanol use.
---------------------------------------------------------------------------

    \132\ The Model T was also capable of running on kerosene.
---------------------------------------------------------------------------

    A record 9.5 billion gallons of ethanol were blended into U.S.
gasoline in 2008 and EIA is forecasting additional growth in the years
to come.\133\ According to their recently released Short-Term Energy
Outlook (STEO), EIA is forecasting 0.7 million barrels of daily ethanol
use in 2009, which equates to 10.7 billion gallons. The October 2009
STEO projects that total ethanol usage (domestic production plus
imports) will reach 12.1 billion gallons by 2010.\134\
---------------------------------------------------------------------------

    \133\ EIA, Monthly Energy Review, September 2009 (Table 10.2b).
    \134\ Letter from Richard Newell, EIA Administrator to Lisa
Jackson, EPA Administrator dated October 29, 2009 (Table 1).
---------------------------------------------------------------------------

    The National Petrochemical and Refiners Association (NPRA)
estimates that ethanol is currently blended into about 75 percent of
all gasoline sold in the United States.\135\ The vast majority is
blended as E10 or 10 volume percent ethanol, although a small amount is
blended as E85 for use in flexible fuel vehicles (FFVs).
---------------------------------------------------------------------------

    \135\ Based on comments provided by NPRA (EPA-HQ-OAR-2005-0161-
2124.1).
---------------------------------------------------------------------------

    Complete saturation of the gasoline market with E10 is referred to
as the ethanol ``blend wall.'' The height of the blend wall in any
given year is directly related to gasoline demand. In AEO 2009, EIA
projects that gasoline demand will peak around 2013 and then start to
taper off due to vehicle fuel economy improvements. Based on the
primary ethanol growth scenario we're forecasting under today's RFS2
program, the nation is expected to hit the 14-15 billion gallon blend
wall by around 2014 (refer ahead to Figure IV.D.2-1), although it could
be sooner if gasoline demand is lower than expected. It could also be
lower if projected volumes of non-ethanol renewables do not materialize
and ethanol usage is higher than expected.
    Over the years there have been several policy attempts to increase
FFV sales including Corporate Average Fuel Economy (CAFE) credits and
government fleet alternative-fuel vehicle requirements. As a result,
there are an estimated 8 million FFVs on the road today, up from just
over 7 million in 2008. While this is not insignificant in terms of
growth, FFVs continue to make up less than 4 percent of the total
gasoline vehicle fleet. In addition, E85 is only currently offered at
about 1 percent of gas stations nationwide. Ethanol consumption is
currently limited by the number of FFVs on the road and the number of
E85 outlets or, more specifically, the number of FFVs with access to
E85. Still many FFV owners with access to E85 are not choosing it
because it is currently priced almost 40 cents per gallon higher than
conventional gasoline on an energy equivalent basis.\136\ According to
EIA, only 12 million gallons of E85 were consumed in 2008.\137\
---------------------------------------------------------------------------

    \136\ Based on average E85 and regular unleaded gasoline prices
reported at http://www.fuelgaugereport.com/on November 23, 2009.
    \137\ EIA, Annual Energy Outlook 2009--ARRA Update (Table 2).
---------------------------------------------------------------------------

    To meet today's RFS2 requirements we are going to need to see
growth in FFV and E85 infrastructure as well as changes in retail
pricing and consumer behavior. However, the amount of change needed is
proportional to the amount of ethanol observed under the RFS2 program.
As explained in Section IV.A, EPA expects total ethanol demand could be
anywhere from 17.5 to 33.2 billion gallons in 2022, depending on the
amount of non-ethanol cellulosic biofuels that are realized. The low-
ethanol case would require only moderate changes in FFV/E85
infrastructure and refueling whereas the high-ethanol case would
require very dramatic changes and likely a mandate. For the final rule,
we have chosen to focus our impact analyses on the primary mid-ethanol
case of 22.2 billion gallons. A discussion of how this

volume of ethanol could be consumed in 2022 with expanded FFV/E85
infrastructure is presented below. As expected, the infrastructure
changes required under this FRM scenario are less extreme than those
highlighted in the proposal based on a predominant ethanol world (34.2
billion gallons of ethanol). However, there are additional
technological, logistical and financial barriers that will need to be
overcome with respect to commercialization of BTL and non-ethanol
cellulosic biofuels. For more on cellulosic diesel technologies,
distribution impacts, and production costs, refer to Sections 1.4, 1.6
and 4.1 of the RIA.
2. Increased Ethanol Use Under RFS2
    Under the primary ethanol growth scenario considered as part of
today's rule, ethanol consumption will need to be about three times
higher than RFS1 levels, more than twice as much as today's levels, and
9 billion gallons higher than the ethanol predicted to occur in 2022
absent RFS2 (according to AEO 2007). To get to 22.2 billion gallons of
ethanol use according to the potential ramp-up described in Section 1.2
of the RIA, the nation is predicted to hit the blend wall in 2014 as
shown below in Figure IV.D.2-1.
[GRAPHIC] [TIFF OMITTED] TR26MR10.422

    As shown above, we are anticipating almost 14 billion gallons of
non-ethanol advanced biofuels under today's RFS2 program. But overall,
ethanol is expected to continue to be the nation's primary biofuel with
over 22 billion gallons in 2022. To get beyond the blend wall and
consume more than 14-15 billion gallons of ethanol, we are going to
need to see increases in the number FFVs on the road, the number of E85
retailers, and the FFV E85 refueling frequency.
    It is possible that conventional gasoline (E0) could continue to
co-exist with E10 and E85 for quite some time. However, for analysis
purposes, we have assumed that E10 would replace E0 as expeditiously as
possible and that all subsequent ethanol growth would come from E85.
Furthermore, we assumed that no ethanol consumption would come from the
mid-level ethanol blends (e.g., E15) under our primary control case
since they are not currently approved for use in non-FFVs. However, as
a sensitivity analysis, we have examined the impacts that E15 would
have on ethanol consumption (refer to Section IV.D.3).
a. Projected Gasoline Energy Demand
    The maximum amount of ethanol our country is capable of consuming
in any given year is a function of the total gasoline energy demanded
by the transportation sector. Our nation's gasoline energy demand is
dependent on the number of gasoline-powered vehicles on the road, their
average fuel economy, vehicle miles traveled (VMT), and driving
patterns. For analysis purposes, we relied on the gasoline energy
projections provided by EIA in the AEO 2009 final release.\138\ AEO
2009 takes the fuel economy improvements set by EISA into consideration
and also assumes a slight dieselization of the light-duty vehicle
fleet.\139\ It also takes the recession's impacts on driving patterns
into consideration. The result is a 25% reduction in the projected 2022
gasoline

energy demand from AEO 2007 (a pre-EISA world) to AEO 2009.\140\ EIA
essentially has total gasoline energy demand (petroleum-based gasoline
plus ethanol) flattening out, and even slightly decreasing, as we move
into the future.
---------------------------------------------------------------------------

    \138\ EIA, Annual Energy Outlook 2009--ARRA Update (Table 2).
    \139\ The gasoline energy demand forecast provided in AEO 2009--
ARRA Update is reasonably consistent with the recently Proposed
Rulemaking To Establish Light-Duty Vehicle Greenhouse Gas Emission
Standards and Corporate Average Fuel Economy Standards (referred to
hereafter as the ``Light-Duty Vehicle GHG Rule.'' For more
information on the Light-Duty Vehicle GHG Rule, refer to 74 FR 49454
(September 28, 2009).
    \140\ EIA, Annual Energy Outlooks 2007 & 2009--ARRA Update
(Table 2).
---------------------------------------------------------------------------

b. Projected Growth in Flexible Fuel Vehicles
    Over one million FFVs were sold in both 2008 and 2009 according to
EPA certification data. Despite the recession and current state of the
auto industry, automakers are incorporating more and more FFVs into
their light-duty production plans. While the FFV system (i.e., fuel
tank, sensor, delivery system, etc.) used to be an option on some
vehicles, most automakers are moving in the direction of converting
entire product lines over to E85-capable systems. Still, the number of
FFVs that will be manufactured and purchased in future years is
uncertain.
    To measure the impacts of increased volumes of renewable fuel, we
considered three different FFV production scenarios that might
correspond to the three biofuel control cases analyzed for the final
rule. For all three cases, we assumed that total light-duty vehicle
sales would follow AEO 2009 trends. The latest EIA report suggests
lower than average sales in 2008-2013 (less than 16 million vehicles
per year) before rebounding and growing to over 17 million vehicles by
2019.\141\ These vehicle projections are consistent with EPA's recently
proposed Light-Duty Vehicle GHG Rule.\142\
---------------------------------------------------------------------------

    \141\ EIA, Annual Energy Outlook 2009--ARRA Update (Table 47).
    \142\ Rulemaking to Establish Light-Duty Vehicle GHG Emission
Standards and Corporate Average Fuel Economy Standards, 74 FR 49454
(September 28, 2009).
---------------------------------------------------------------------------

    Although we assumed total vehicle and car/truck sales would be the
same in all three cases, we assumed varying levels of FFV production.
For our low-ethanol control case, we assumed steady business-as-usual
FFV growth according to AEO 2009 predictions.\143\ For our primary mid-
ethanol control case, we assumed increased FFV sales under the
presumption that GM, Ford and Chrysler (referred to hereafter as the
``Detroit 3'') would follow through with their commitment to produce
50% FFVs by 2012. Despite the current state of the economy and the
hardships facing the auto industry (GM and Chrysler filed for
bankruptcy earlier this year), the Detroit 3 appear to still be moving
forward with their voluntary FFV commitment.\144\ Under our primary
control case, we assumed that non-domestic FFVs sales would track
around 2%, consistent with today's production/plans.\145\ Finally, for
our high-ethanol control case, we assumed a theoretical 80% FFV mandate
based on the Open Fuel Standard Act of 2009 that was reintroduced in
Congress on March 12, 2009.\146\ Given today's reduced vehicle sales
and gasoline demand, we believe a mandate would be the only viable
means for consuming 32.2 billion gallons of ethanol in 2022.
---------------------------------------------------------------------------

    \143\ EIA, Annual Energy Outlook 2009--ARRA Update (Table 47).
    \144\ Ethanol Producer Magazine, ``Automakers Maintain FFV
Targets in Bailout Plans.'' February 2009. This is consistent with
information provided in GM and Chrysler's restructuring plans
submitted to the U.S. Department of Treasury on February 17, 2009.
    \145\ Based on 2008 FFV certification data and 2009 projections
based on the National Ethanol Vehicle Coalition, 2009 FFV Purchasing
Guide.
    \146\ A copy of H.R. 1476 can be found at: http://
www.opencongress.org/bill/111-h1476/text.
---------------------------------------------------------------------------

    Under our primary mid-ethanol control case, total FFV sales are
estimated at just over 4 million vehicles per year in 2017 and beyond.
This is less aggressive than the assumptions made in the NPRM. At that
time, we were expecting more cellulosic ethanol which could justify
higher FFV production assumptions. We assumed that not only would the
Detroit 3 fulfill their 50% by 2012 FFV production commitment, non-
domestic automakers might follow suit and produce 25% FFV in 2017 and
beyond. We also assumed that annual light-duty vehicle sales would
continue around the historical 16 million vehicle mark resulting in 6
million FFVs in 2017 and beyond.
    Based on our revised vehicle/FFV production assumptions coupled
with vehicle survival rates, VMT, and fuel economy estimates applied in
the recently proposed Light-Duty Vehicle GHG Rule, the maximum
percentage of fuel (gasoline/ethanol mix) that could feasibly be
consumed by FFVs in 2022 would be about 20% (down from 30% in the
NPRM). For more information on our FFV production assumptions and fuel
fraction calculations, refer to Section 1.7.2 of the RIA.
c. Projected Growth in E85 Access
    According to the National Ethanol Vehicle Coalition (NEVC), there
are currently 2,100 gas stations offering E85 in 44 states plus the
District of Columbia.\147\ While this represents significant industry
growth, it still only translates to 1.3% of U.S. retail stations
nationwide carrying the fuel.\148\ As a result, most FFV owners clearly
do not have reasonable access to E85. For our FFV/E85 analysis, we have
defined ``reasonable access'' as one-in-four pumps offering E85 in a
given area.\149\ Accordingly, just over 5% of the nation currently has
reasonable access to E85, up from 4% in 2008 (based on a mid-year NEVC
pump estimate).\150\
---------------------------------------------------------------------------

    \147\ NEVC Web site, accessed on November 23, 2009.
    \148\ Based on National Petroleum News gasoline station estimate
of 161,768 in 2008.
    \149\ For a more detailed discussion on how we derived our one-
in-four reasonable access assumption, refer to Section 1.6 of the
RIA. For the distribution cost implications as well as the cost
impacts of assuming reasonable access is greater than one-in-four
pumps, refer to Section 4.2 of the RIA.
    \150\ Computed as percent of stations with E85 (2,101/161,768 as
of November 2009 or 1,733/161,768 as of August 2008) divided by 25%
(one-in-four stations).
---------------------------------------------------------------------------

    There are a number of states promoting E85 usage by offering FFV/
E85 awareness programs and/or retail pump incentives. A growing number
of states are also offering infrastructure grants to help expand E85
availability. Currently, 10 Midwest states have adopted a progressive
Energy Security and Climate Stewardship Platform.\151\ The platform
includes a Regional Biofuels Promotion Plan with a goal of making E85
available at one third of all stations by 2025. In addition, the
American Recovery and Reinvestment Act of 2009 (ARRA or Recovery Act)
recently increased the existing federal income tax credit from $30,000
or 30% of the total cost of improvements to $100,000 or 50% of the
total cost of needed alternative fuel equipment and dispensing
improvements.\152\
---------------------------------------------------------------------------

    \151\ The following states have adopted the plan: Illinois,
Indiana, Iowa, Kansas, Michigan, Minnesota, Missouri, Ohio, South
Dakota and Wisconsin. For more information, visit: http://
www.midwesterngovernors.org/resolutions/Platform.pdf.
    \152\ http://frwebgate.access.gpo.gov/cgi-bin/
getdoc.cgi?dbname=111_cong_bills&docid=f:h1enr.pdf.
---------------------------------------------------------------------------

    Given the growing number of subsidies, it is clear that E85
infrastructure will continue to expand in the future. However, like
FFVs, we expect that E85 station growth will be somewhat proportional
to the amount of ethanol realized under the RFS2 program. As such, we
analyzed three different E85 growth scenarios for the final rule that
could correspond to the three different RFS2 control cases. As an upper
bound for our high-ethanol control case, we maintained the 70% access
assumption we applied for the NPRM. This is roughly equivalent to all
urban areas in the United States offering reasonable (one-in-four-
station) access

to E85.\153\ For our other control cases we assumed access to E85 would
be lower with the logic that retail stations (the majority of which are
independently owned and operated and net around $30,000 per year) would
not invest in more E85 infrastructure than what was necessary to meet
the RFS2 requirements. For our primary mid-ethanol control case we
assumed reasonable access would grow from 4% in 2008 to 60% in 2022 and
for our low-ethanol control case we assumed that access would only grow
to 40% by 2022. As discussed in Section IV.C, we believe these E85
growth scenarios are possible based on our assessment of distribution
infrastructure capabilities.
---------------------------------------------------------------------------

    \153\ For this analysis, we've defined ``urban'' as the top 150
metropolitan statistical areas according to the U.S. census and/or
counties with the highest VMT projections according the EPA MOVES
model, all RFG areas, winter oxy-fuel areas, low-RVP areas, and
other relatively populated cities in the Midwest.
---------------------------------------------------------------------------

d. Required Increase in E85 Refueling Rates
    As mentioned earlier, there were just over 7 million FFVs on the
road in 2008. If all FFVs refueled on E85 100% of the time, this would
translate to about 8.3 billion gallons of E85 use.\154\ However, E85
usage was only around 12 million gallons in 2008.\155\ This means that,
on average, FFV owners were only tapping into about 0.15% of their
vehicles' E85/ethanol usage potential last year. Assuming that only 4%
of the nation had reasonable one-in-four access to E85 in 2008 (as
discussed above), this equates to an estimated 4% E85 refueling
frequency for those FFVs that had reasonable access to the fuel.
---------------------------------------------------------------------------

    \154\ Based on average vehicle miles traveled (VMT) and in-use
fuel economy (MPG) for FFVs in the fleet in 2008. For more
information on FFV E85 fuel consumption calculations, refer to
Section 1.7.4 of the RIA.
    \155\ EIA, Annual Energy Outlook 2009--ARRA Update (Table 17).
---------------------------------------------------------------------------

    There are several reasons behind today's low E85 refueling
frequency. For starters, many FFV owners may not know they are driving
a vehicle that is capable of handling E85. As mentioned earlier, more
and more automakers are starting to produce FFVs by engine/product
line, e.g., all 2008 Chevy Impalas are FFVs.\156\ Consequently,
consumers (especially brand loyal consumers) may inadvertently buy a
flexible fuel vehicle without making a conscious decision to do so. And
without effective consumer awareness programs in place, these FFV
owners may never think to refuel on E85. In addition, FFV owners with
reasonable access to E85 and knowledge of their vehicle's E85
capabilities may still not choose to refuel on E85. They may feel
inconvenienced by the increased refueling requirements. Based on its
lower energy density, FFV owners will need to stop to refuel 21% more
often when filling up on E85 over E10 (and likewise, 24% more often
when refueling on E85 over conventional gasoline).\157\ In addition,
some FFV owners may be deterred from refueling on E85 out of fear of
reduced vehicle performance or just plain unfamiliarity with the new
motor vehicle fuel. However, as we move into the future, we believe the
biggest determinant will be price--whether E85 is priced competitively
with gasoline based on its reduced energy density (discussed in more
detail in the subsection that follows).
---------------------------------------------------------------------------

    \156\ NEVC, ``2008 Purchasing Guide for Flexible Fuel
Vehicles.'' Refers to all mass produced 3.5 and 3.9L Impalas.
However, it is our understanding that consumers may still place
special orders for non-FFVs.
    \157\ Based on our assumption that denatured ethanol has an
average lower heating value of 77,012 BTU/gal and conventional
gasoline (E0) has average lower heating value of 115,000 BTU/gal.
For analysis purposes, E10 was assumed to contain 10 vol% ethanol
and 90 vol% gasoline. Based on EIA's AEO 2009 assumption, E85 was
assumed to contain 74 vol% ethanol and 26 vol% gasoline on average.
---------------------------------------------------------------------------

    To comply with the RFS2 program and consume 22.2 billion gallons of
ethanol by 2022 (under our primary ethanol control case), not only
would we need more FFVs and more E85 retailers, we would need to see a
significant increase in the current FFV E85 refueling frequency. Based
on the FFV and retail assumptions described above in subsections (b)
and (c), our analysis suggests that FFV owners with reasonable access
to E85 would need to fill up on it as often as 58% of the time, a
significant increase from today's estimated 4% refueling frequency. In
order for this to be possible, there will need to be an improvement in
the current E85/gasoline price relationship.
e. Market Pricing of E85 Versus Gasoline
    According to an online fuel price survey, E85 is currently priced
almost 40 cents per gallon or about 15% lower than regular grade
conventional gasoline.\158\ But this is still about 30 cents per gallon
higher than conventional gasoline on an energy-equivalent basis. To
increase our nation's E85 refueling frequency to the levels described
above, E85 needs to be priced competitively with (if not lower than)
conventional gasoline based on its reduced energy content, increased
time spent at the pump, and limited availability. Overall, we estimate
that E85 would need to be priced about 25% lower than E10 at retail in
2022 in order for it to make sense to consumers.
---------------------------------------------------------------------------

    \158\ Based on average E85 and regular unleaded gasoline prices
reported at http://www.fuelgaugereport.com/ on November 23, 2009.
---------------------------------------------------------------------------

    However, ultimately it comes down to what refiners are willing to
pay for ethanol blended as E85. The more ethanol you try to blend as
E85, the more devalued ethanol becomes as a gasoline blendstock.
Changes to state and Federal excise tax structures could help promote
ethanol blending as E85. Similarly, high crude prices make E85 look
more attractive. According to EIA's AEO 2009, crude oil prices are
expected to increase from about $80 per barrel (today's price) to $116/
barrel by 2022.\159\ Based on our retail cost calculations, ethanol
would have to be priced around $2/gallon or less in order to be
attractive to refiners for E85 blending in 2022. According to the DTN
Ethanol Center, the current rack price for ethanol is around $2.20/
gallon.\160\ However, as explained in Section 4.4 of the RIA, we
project that the average ethanol delivered price will come down in the
future under the RFS2 program. Therefore, while gasoline refiners and
markets will always have a greater profit margin selling ethanol in
low-level blends to consumers based on volume, they should be able to
maintain a profit selling it as E85 based on energy content in the
future.
---------------------------------------------------------------------------

    \159\ EIA, Annual Energy Outlook 2009--ARRA Update (Table 12).
    \160\ http://www.dtnethanolcenter.com/index.cfm?show=10∣=32.
---------------------------------------------------------------------------

    Once the nation gets past the blend wall, more ethanol will need to
be blended as E85 and less as E10. FFV owners who were formerly
refueling on gasoline will need to start filling up on E85. Under our
primary control case, we expect that 12.9 billion gallons of ethanol
would be blended as E10 and 9.3 billion gallons would be blended as E85
to reach the 22.2 billion gallons in 2022. For more on our ethanol
consumption feasibility and retail cost calculations, including
discussion of the other two control cases, refer to Section 1.7 of the
RIA.
3. Consideration of >10% Ethanol Blends
    On March 6, 2009, Growth Energy and 54 ethanol manufacturers
submitted an application for a waiver of the prohibition of the
introduction into commerce of certain fuels and fuel additives set
forth in section 211(f) of the Act. This application seeks a waiver for
ethanol-gasoline blends of up to 15 percent ethanol by volume.\161\ On
April

21, 2009, EPA issued a Federal Register notice announcing receipt of
the Growth Energy waiver application and soliciting comment on all
aspects of it.\162\ On May 20, 2009, EPA issued an additional Federal
Register notice extending the public comment period by an additional 60
days.\163\ The comment period ended on July 20, 2009, and EPA is now
evaluating the waiver application and considering the comments which
were submitted.
---------------------------------------------------------------------------

    \161\ http://www.growthenergy.org/2009/e15/
Waiver%20Cover%20Letter.pdf. Additional supporting documents are
available on the Growth Energy Web site.
    \162\ Refer to 74 FR 18228 (April 21, 2009).
    \163\ Refer to 74 FR 23704 (May 20, 2009).
---------------------------------------------------------------------------

    In a letter dated November 30, 2009, EPA notified the applicant
that, because crucial vehicle durability information being developed by
the Department of Energy would not be available until mid-2010, EPA
would be delaying its decision on the application until a sufficient
amount of this information could be included in its analysis so that
the most scientifically supportable decision could be made.\164\ As the
current Growth Energy waiver application is still under review, EPA
believes it is appropriate to address aspects of the mid-level blend
waiver in its decision announcement on the waiver application as
opposed to dealing with the comments and evaluation of the potential
waiver in the preamble of today's final rule.
---------------------------------------------------------------------------

    \164\ http://www.epa.gov/OMS/regs/fuels/additive/
lettertogrowthenergy11-30-09.pdf.
---------------------------------------------------------------------------

    Although EPA has yet to make a waiver decision, since its approval
could have a significant impact on our analyses that are based on the
use of E85, as a sensitivity analysis, we have evaluated the impacts
that E15 could have on ethanol consumption feasibility. More
specifically, we have assessed the impacts of a partial waiver for
newer technology vehicles consistent with the direction of EPA's
November 30, 2009 letter. We assumed that E10 would need to continue to
co-exist for legacy and non-road equipment based on consumer demand
regardless of any waiver decision. For analysis purposes, we assumed
E10 would be marketed as premium-grade gasoline (the universal fuel),
E15 would be marketed as regular-grade gasoline (to maximize ethanol
throughput) and, like today, midgrade would be blended from the two
fuels to make a 12.5 vol% blend (E12.5). In addition, we assumed that
some E15-capable vehicles would continue to choose E10 or E12.5 based
on our knowledge of today's premium and midgrade sales.\165\
---------------------------------------------------------------------------

    \165\ According to EIA's 2008 Petroleum Annual Outlook (Table
45), midgrade and premium comprise 13.5% of total gasoline sales.
---------------------------------------------------------------------------

    In the event of a partial waiver, it is unclear how long it would
take for E15 to be fully deployed or whether it would ever be available
nationwide. For analysis purposes, we assumed that E15 would be fully
phased in and available at all retail stations nationwide by the time
the nation hit the blend wall, or around 2014 for our primary control
case shown in Figure IV.D.3-1.
[GRAPHIC] [TIFF OMITTED] TR26MR10.423

    As modeled, a partial waiver for E15 could increase the ethanol
consumption potential from conventional vehicles to about 19 billion
gallons. Under our primary control case (shown in Figure IV.D.3-1), E15
could postpone the blend wall by up to five years, or to 2019. Although
E15 would fall short of meeting the RFS2 requirements under this
scenario, it could provide interim relief while the county ramps up
non-ethanol cellulosic biofuel production and expands E85/FFV
infrastructure. Under our high-ethanol control case, a partial waiver
for E15 could eliminate

the need for FFV or E85 infrastructure mandates. Under our low-ethanol
control case, E15 could eliminate the need for additional FFV/E85
infrastructure all together. For more information, refer to Section
1.7.6 of the RIA.

V. Lifecycle Analysis of Greenhouse Gas Emissions

A. Introduction

    As recognized earlier in this preamble, a significant aspect of the
RFS2 program is the requirement that a fuel meet a specific lifecycle
greenhouse gas (GHG) emissions threshold for compliance for each of
four types of renewable fuels. This section describes the methodology
used by EPA to determine the lifecycle GHG emissions of biofuels, and
the petroleum-based transportation fuels that they replace. EPA
recognizes that this aspect of the RFS2 regulatory program has received
particular attention and comment throughout the public comment period.
Therefore, this section also will describe the enhancements made to our
approach in conducting the lifecycle analysis for the final rule. This
section will highlight areas where we have incorporated new scientific
data that has become available since the proposal as well as the
approach the Agency has taken to recognize and quantify, where
appropriate, the uncertainty inherent in this analysis.
1. Open and Science-Based Approach to EPA's Analysis
    Throughout the development of EPA's lifecycle analysis, the Agency
has employed a collaborative, transparent, and science-based approach.
EPA's lifecycle methodology, as developed for the RFS2 proposal,
required breaking new scientific ground and using analytical tools in
new ways. The work was generally recognized as state of the art and an
advance on lifecycle thinking, specifically regarding the indirect
impacts of biofuels.
    However, the complexity and uncertainty inherent in this work made
it extremely important that we seek the advice and input of a broad
group of stakeholders. In order to maximize stakeholder outreach
opportunities, the comment period for the proposed rule was extended to
120 days. In addition to this formal comment period, EPA made multiple
efforts to solicit public and expert feedback on our approach.
Beginning early in the NPRM process and continuing throughout the
development of this final rule, EPA held hundreds of meetings with
stakeholders, including government, academia, industry, and non-profit
organizations, to gather expert technical input. Our work was also
informed heavily by consultation with other federal agencies. For
example, we have relied on the expert advice of USDA and DOE, as well
as incorporating the most recent inputs and models provided by these
Agencies. Dialogue with the State of California and the European Union
on their parallel, on-going efforts in GHG lifecycle analysis also
helped inform EPA's methodology. As described below, formal technical
exchanges and an independent, formal peer review of the methodology
were also significant components of the Agency's outreach. A key result
of our outreach effort has been awareness of new studies and data that
have been incorporated into our final rule analysis.
    Technology Exchanges: Immediately following publication of the
proposed rule, EPA held a two-day public workshop focused specifically
on lifecycle analysis to assure full understanding of the analyses
conducted, the issues addressed, and the options discussed. The
workshop featured EPA presentations on each component of the
methodology as well as presentations and discussions by stakeholders
from the renewable fuel community, federal agencies, universities, and
environmental groups. The Agency also took advantage of opportunities
to meet in the field with key, affected stakeholders. For example, the
Agency was able to twice participate in meetings and tours in Iowa
hosted by the local renewable fuel and agricultural community. As
described in this section, one of the many outcomes of these meetings
was an improved understanding of agricultural and biofuel production
practices.
    As indicated in the proposal, our lifecycle results were
particularly impacted by assumptions about land use patterns and
emissions in Brazil. During the public comment process we were able to
update and refine these assumptions, including the incorporation of
new, improved sources of data based on Brazil-specific data and
programs. In addition, the Agency received more recent trends on
Brazilian crop productivity, areas of crop expansion, and regional
differences in costs of crop production and land availability. Lastly,
we received new information on efforts to curb deforestation allowing
the Agency to better predict this impact through 2022.
    Peer Review: To ensure the Agency made its decisions for this final
rule on the best science available, EPA conducted a formal, independent
peer review of key components of the analysis. The reviews were
conducted following the Office of Management and Budget's peer review
guidance that ensures consistent, independent government-wide
implementation of peer review, and according to EPA's longstanding and
rigorous peer review policies. In accordance with these guidelines, EPA
used independent, third-party contractors to select highly qualified
peer reviewers. The reviewers selected are leading experts in their
respective fields, including lifecycle assessment, economic modeling,
remote sensing imagery, biofuel technologies, soil science,
agricultural economics, and climate science. They were asked to
evaluate four key components of EPA's methodology: (1) Land use
modeling, specifically the use of satellite data and EPA's proposed
land conversion GHG emission factors; (2) methods to account for the
variable timing of GHG emissions; (3) GHG emissions from foreign crop
production (both the modeling and data used); and (4) how the models
EPA relied upon are used together to provide overall lifecycle
estimates.
    The advice and information received through this peer review are
reflected throughout this section. EPA's use of higher resolution
satellite data is one example of a direct outcome of the peer review,
as is the Agency's decision to retain its reliance upon this data. The
reviewers also provided recommendations that have helped to inform the
larger methodological decisions presented in this final rule. For
example, the reviewers in general supported the importance of assessing
indirect land use change and determined that EPA used the best
available tools and approaches for this work. However, the review also
recognized that no existing model comprehensively simulates the direct
and indirect effects of biofuel production both domestically and
internationally, and therefore model development is still evolving. The
uncertainty associated with estimating indirect impacts and the
difficulty in developing precise results also were reflected in the
comments. In the long term, this peer review will help focus EPA's
ongoing lifecycle analysis work as well as our future interactions with
the National Academy of Science and other experts.
    Altogether, the many and extensive public comments we received to
the rule docket, the numerous meetings, workshops and technical
exchanges, and the scientific peer review have all been instrumental to
EPA's ability to advance our analysis between proposal and final and to
develop the

methodological and regulatory approach described in this section.
2. Addressing Uncertainty
    The peer review, the public comments we have received, and the
analysis conducted for the proposal and updated here for the final
rule, indicate that it is important to take into account indirect
emissions when looking at lifecycle emissions from biofuels. It is
clear that, especially when considering commodity feedstocks, including
the market interactions of biofuel demand on feedstock and agricultural
markets is a more accurate representation of the impacts of an increase
in biofuels production on GHG emissions than if these market
interactions are not considered.
    However, it is also clear that there are significant uncertainties
associated with these estimates, particularly with regard to indirect
land use change and the use of economic models to project future market
interactions. Reviewers highlighted the uncertainty associated with our
lifecycle GHG analysis and pointed to the inherent uncertainty of the
economic modeling.
    In the proposal, we asked for comment on whether and how to conduct
an uncertainty analysis to help quantify the magnitude of this
uncertainty and its relative impact on the resulting lifecycle
emissions estimates. The results of the peer review, and the feedback
we have received from the comment process, supported the value of
conducting such an analysis. Therefore, working closely with other
government agencies as well as incorporating feedback from experts who
commented on the rule, we have quantified the uncertainty associated
specifically with the international indirect land use change emissions
associated with increased biofuel production.
    Although there is uncertainty in all portions of the lifecycle
modeling, we focused our uncertainty analysis on the factors that are
the most uncertain and have the biggest impact on the results. For
example, the energy and GHG emissions used by a natural gas-fired
ethanol plant to produce one gallon of ethanol can be calculated
through direct observations, though this will vary somewhat between
individual facilities. The indirect domestic emissions are also fairly
well understood, however these results are sensitive to a number of key
assumptions (e.g., current and future corn yields). The indirect,
international emissions are the component of our analysis with the
highest level of uncertainty. For example, identifying what type of
land is converted internationally and the emissions associated with
this land conversion are critical issues that have a large impact on
the GHG emissions estimates.
    Therefore, we focused our efforts on the international indirect
land use change emissions and worked to manage the uncertainty around
those impacts in three ways: (1) Getting the best information possible
and updating our analysis to narrow the uncertainty, (2) performing
sensitivity analysis around key factors to test the impact on the
results, and (3) establishing reasonable ranges of uncertainty and
using probability distributions within these ranges in threshold
assessment. The following sections outline how we have incorporated
these three approaches into our analysis.
    EPA recognizes that as the state of scientific knowledge continues
to evolve in this area, the lifecycle GHG assessments for a variety of
fuel pathways will continue to change. Therefore, while EPA is using
its current lifecycle assessments to inform the regulatory
determinations for fuel pathways in this final rule, as required by the
statute, the Agency is also committing to further reassess these
determinations and lifecycle estimates. As part of this ongoing effort,
we will ask for the expert advice of the National Academy of Sciences,
as well as other experts, and incorporate their advice and any updated
information we receive into a new assessment of the lifecycle GHG
emissions performance of the biofuels being evaluated in this final
rule. EPA will request that the National Academy of Sciences over the
next two years evaluate the approach taken in this rule, the underlying
science of lifecycle assessment, and in particular indirect land use
change, and make recommendations for subsequent rulemakings on this
subject. This new assessment could result in new determinations of
threshold compliance compared to those included in this rule that would
apply to future production (from plants that are constructed after each
subsequent rule).

B. Methodology

    The regulatory purpose of this analysis is to determine which
biofuels (both domestic and imported) qualify for the four different
GHG reduction thresholds and renewable fuel categories established in
EISA (see Section I.A). This threshold assessment compares the
lifecycle emissions of a particular biofuel against the lifecycle
emissions of the petroleum-based fuel it is replacing (e.g., ethanol
replacing gasoline or biodiesel replacing diesel). This section
discusses the Agency's approach both for assessing the lifecycle GHG
emissions from biofuels as well as for the petroleum-based fuels
replaced by the biofuels.
    As described in detail below, EPA has received a number of comments
on the different pieces of this analysis and has thoroughly considered
those comments as well as feedback from our peer review process. In
each section below we will discuss comments received and how they
impacted our analysis.
1. Scope of Analysis
    As stated in the proposal, the definition of lifecycle GHG
emissions established by Congress in EISA is critical to establishing
the scope of our analysis. Congress specified that:

    The term ``lifecycle greenhouse gas emissions'' means the
aggregate quantity of greenhouse gas emissions (including direct
emissions and significant indirect emissions such as significant
emissions from land use changes), as determined by the
Administrator, related to the full fuel lifecycle, including all
stages of fuel and feedstock production and distribution, from
feedstock generation or extraction through the distribution and
delivery and use of the finished fuel to the ultimate consumer,
where the mass values for all greenhouse gases are adjusted to
account for their relative global warming potential.\166\
---------------------------------------------------------------------------

    \166\ Clean Air Act Section 211(o)(1).

    This definition forms the basis of defining the goal and scope of
our lifecycle GHG analysis and in determining to what extent changes
should be made to the analytical approach outlined in our proposed
rulemaking.
a. Inclusion of Indirect Land Use Change
    EPA notes that it received significant comment on including
international indirect emissions in its lifecycle calculations. Most of
the comments suggested that the science of international indirect land
use change was too new, or that the uncertainty involved was too great,
to be included in a regulatory analysis. EPA continues to believe that
compliance with the EISA mandate--determining ``the aggregate GHG
emissions related to the full fuel lifecycle, including both direct
emissions and significant indirect emissions such as land use
changes''--makes it necessary to assess those direct and significant
indirect impacts that occur not just within the United States, but also
those that occur in other countries.
    Some commenters strongly supported EPA's proposal to include
significant GHG emissions that occur overseas and

are related to the lifecycle of renewable fuels or baseline fuels used
in the United States. These commenters agreed that the text of the
statute supports EPA's proposed approach, and that the alternative of
ignoring such emissions would result in grossly inaccurate assessments,
and would be inconsistent with the international nature of GHG
pollution and the fact that overseas emissions have domestic impacts.
    Other commenters argued that the presumption against
extraterritorial application of domestic laws carries with it the
presumption that Congress is concerned with domestic effects and
domestic impacts only. They assert further that Congress intended to
benefit domestic agriculture through EISA enactment, and that the
statute's ambiguous terms should not be interpreted in a manner that
could harm domestic agriculture in general or, for one commenter, the
biodiesel industry in particular. Although considering international
emissions in its analyses could result in different implications under
the statute for various fuels and fuel pathways as compared to ignoring
these emissions, EPA believes that this is precisely the outcome that
Congress intended. Implementation of EISA will undoubtedly benefit the
domestic agricultural sector as a whole, with some components
benefiting more than others depending in part on the lifecycle GHG
emissions associated with the products to be made from individual
feedstocks. If Congress had sought to promote all biofuel production
without regard to GHG emissions related to the full lifecycle of those
fuels, it would not have specified GHG reduction thresholds for each
category of renewable fuel for which volume targets are specified in
the Act.
    It is also important to note that including international indirect
emissions in EPA's lifecycle analysis does not exercise regulatory
authority over activities that occur solely outside the U.S., nor does
it raise questions of extra-territorial jurisdiction. EPA's regulatory
action involves an assessment of products either produced in the U.S.
or imported into the U.S. EPA is simply assessing whether the use of
these products in the U.S. satisfies requirements under EISA for the
use of designated volumes of renewable fuel, cellulosic biofuel,
biomass-based diesel, and advanced biofuel. Considering international
emissions in determining the lifecycle GHG emissions of the
domestically-produced or imported fuel does not change the fact that
the actual regulation of the product involves its use solely inside the
U.S.
    A number of commenters pointed to the text and structure of the
definition of ``lifecycle greenhouse gas emissions'' to argue that EPA
either is not authorized to consider GHG emissions related to
international land use change, or that it is not required to do so. One
commenter suggested that the reference in the definition of ``lifecycle
greenhouse gas emissions'' to ``all stages'' of the lifecycle ``from''
feedstock generation ``through'' use of the fuel by the ultimate
consumer does not include indirect emissions that result from decisions
to place more land in acreage overseas for such non-fuel purposes as
cattle feed. Another commenter stated that EPA's approach does not give
any meaning to the terms ``significant'' and ``fuel lifecycle'' in the
definition, but instead focuses on the words such as ``full'' to arrive
at an expansive meaning. This commenter also noted the lack of any
specific reference to international considerations in Section 211(o),
as opposed to other provisions in the CAA, such as Section 115.
    EPA believes that a complete analysis of the aggregate GHG
emissions related to the full lifecycle of renewable fuels includes the
significant indirect emissions from international land use change that
are predicted to result from increased domestic use of agricultural
feedstocks to produce renewable fuel. The statute specifically directs
EPA to include in its analyses significant indirect emissions such as
significant emissions from land use changes. EPA has not ignored either
the terms ``significant'' or ``life cycle.'' It is clear from EPA's
assessments that the modeled indirect emissions from land use changes
are ``significant'' in terms of their relationship to total GHG
emissions for given fuel pathways. Therefore, they are appropriately
considered in the total GHG emissions profile for the fuels in
question. EPA has not ignored the term ``life cycle.'' The entire
approach used by EPA is directed to fully analyzing emissions related
to the complete lifecycle of renewable and baseline fuels.
    Although the definition of lifecycle greenhouse gas emissions in
Section 211(o) does not specifically mention international emissions,
it would be inconsistent with the intent of this section of the amended
Act to exclude them. A large variety of activities outside the U.S.
play a major part in the full fuel lifecycle of both baseline (gasoline
and diesel fuel used as transportation fuel in 2005) and renewable
fuels. For example, several stages of the lifecycle process for
gasoline and diesel can occur overseas, including extraction and
delivery of imported crude oil, and for imported gasoline and diesel
products, emissions associated with refining and distribution of the
finished product to the U.S. For imported renewable fuel, all of the
emissions associated with feedstock production and distribution, fuel
processing, and delivery of the finished renewable fuel to the U.S.
occur overseas. The definition of lifecycle GHG emissions makes it
clear that EPA is to determine the aggregate emissions related to the
``full'' fuel lifecycle, including ``all stages of fuel and feedstock
production and distribution.'' Thus, EPA could not, as a legal matter,
ignore those parts of a fuel lifecycle that occur overseas.
    Drawing a distinction between GHG emissions that occur inside the
U.S. as compared to emissions that occur outside the U.S. would result
in a lifecycle analysis that bears no apparent relationship to the
purpose of this provision. The purpose of the thresholds in EISA is to
require the use of renewable fuels that achieve reductions in GHG
emissions compared to the baseline. Ignoring international emissions, a
large part of the GHG emission associated with the different fuels,
would result in a GHG analysis that bears no relationship to the real
world emissions impact of transportation fuels. The baseline would be
significantly understated, given the large amount of imported crude and
imported finished gasoline and diesel used in 2005. Likewise, the
emissions estimates for imported renewable fuel would be grossly
reduced in comparison to the aggregate emissions estimates for fuels
made domestically with domestically-grown feedstocks, simply because
the impacts of domestically produced fuels occurred within the U.S. EPA
does not believe that Congress intended such a result.
    Excluding international impacts means large percentages of GHG
emissions would be ignored. This would take place in a context where
the global warming impact of emissions is irrespective of where the
emissions occur. If the purpose of thresholds is to achieve some
reduction in GHG emissions in order to help address climate change,
then ignoring emissions outside our borders interferes with the ability
to achieve this objective. Such an approach would essentially undermine
the purpose of the provision, and would be an arbitrary interpretation
of the broadly phrased text used by Congress.
    One commenter stated that matters that could appropriately be
considered part of a food lifecycle (new land clearing for overseas
grain production as a result of decreased U.S. grain exports)

should not be considered part of a renewable fuel lifecycle. However,
the suggested approach would mean that EPA would fail to account for
the significant indirect emissions that relate to renewable fuel
production. EPA believes this would be counter to Congressional intent.
Although a life cycle analysis of foreign food production may also take
into account a given land use change, that does not mean that the same
land use change should not be considered in evaluating its ultimate
cause, which may be renewable fuel production in the United States.
    Some comments asserted that significant GHG gas emissions from
international land use change should not be considered if the only
available models for doing so are not generally accepted or valid
considering economics or science, or where the approach is new and
untested, or where the data are faulty and EPA models unrealistic
scenarios. As described in this rulemaking, EPA has used the best
available models and substantially modified key inputs to those models
to reflect comments by peer reviewers, the public, and emerging
science. EPA has also modeled additional scenarios from those described
in the NPRM. EPA recognizes that uncertainty exists with respect to the
results, and has attempted to quantify the range of uncertainty. While
EPA agrees that application of the models it has used in the context of
assessing GHG emissions represents changes from previous biofuel
lifecycle modeling, EPA disagrees that it has used faulty data, modeled
unrealistic scenarios, or that its approach is otherwise scientifically
indefensible. Although the results of modeling GHG emissions associated
with international land use change are uncertain, EPA has attempted to
quantify that uncertainty and is now in a better position to consider
the uncertainty inherent in its approach.
    One commenter asserted that by considering international land use
changes, EPA is seeking to penalize domestic renewable fuel producers
for impacts over which they have no control. In response, EPA disagrees
that it is seeking to penalize anyone at all. EPA is simply attempting
to account for all GHG emissions related to the full fuel lifecycle.
Domestic renewable fuel producers may have no direct control over land
use changes that occur overseas as a result of renewable fuel
production and use here, but their choice of feedstock can and does
influence oversees activities, and EPA believes it is appropriate to
consider the GHG emissions from those activities in its analyses.
    Some commenters noted that a finding of causation is built into the
definitions of ``indirect effects'' in the Endangered Species Act and
the National Environmental Policy Act, and that EPA should interpret
the reference to ``indirect emissions' in EISA as requiring similar
findings of causation. Specifically, they argue that for EPA to count
GHG emissions from international land use change in its assessments,
EPA must find that renewable fuel production ``caused'' the land use
change. In response, without addressing the commenter's claims
regarding the requirements of NEPA or the ESA, EPA notes that Congress
has specified in Section 211(o) the required causal link between a fuel
and indirect emissions. The indirect emissions must be ``related to''
the full fuel lifecycle. EPA believes that it has demonstrated this
link through its modeling efforts. Specifically, the models predict
that increased demand for feedstocks to produce renewable fuel that
satisfies EISA mandates will likely result in international land use
change. Such change is, then, ``related to'' the full fuel lifecycle of
these fuels. EPA does not believe that the statute requires EPA to wait
until these effects occur to establish the required linkage, but
instead believes that it is authorized to use predictive models to
demonstrate likely results.
    The term ``related to'' is generally interpreted broadly as meaning
to have a connection to or refer to a matter. To determine whether an
indirect emission has the appropriate connection to the full fuel
lifecycle, we must look at both the objectives of this provision as
well as the nature of the relationship. EPA has used a suite of global
models to project a variety of agricultural impacts of the RFS program,
including changes in the types of crops and number of acres planted
world-wide. These shifts in the agricultural market are a direct
consequence of the increased demand for biofuels in the U.S. This
increased demand diverts biofuel feedstocks from other competing uses,
and also increases the price of the feedstock, thus spurring additional
international production. Our analysis uses country-specific
information to determine the amount, location, and type of land use
change that would occur to meet these changes in production patterns.
The linkages of these changes to increased U.S. biofuel demand in our
analysis are generally close, and are not extended or overly complex.
    Overall, EPA is confident that it is appropriate to consider
indirect emissions, including those from both domestic and
international land use changes, as ``related to'' the full fuel
lifecycle, based on the results of our modeling. These results form a
reasonable technical basis for the linkage between the full fuel
lifecycle of transportation fuels and indirect emissions, as well as
for the determination that these emissions are significant. EPA
believes that while uncertainty in the resulting aggregate GHG
estimates should be taken into consideration, it would be inappropriate
to exclude indirect emissions estimates from this analysis. The use of
reasonable estimates of these kinds of indirect emissions allows EPA to
conduct a reasoned evaluation of total GHG impacts, which is needed to
promote the objectives of this provision, as compared to ignoring or
not accounting for these indirect emissions.
    EPA understands that including international indirect land use
change is a key decision and that there is significant uncertainty
associated with it. That is why we have taken an approach that
quantifies that uncertainty and presents the weight of currently
available evidence in making our threshold determinations.
b. Models Used
    As described in the proposal, to estimate lifecycle indirect
impacts of biofuel production requires the use of economic modeling to
determine the market impacts of using agricultural commodity feedstocks
for biofuels. The use of economic models and the uncertainty of those
models to accurately predict future agricultural sector scenarios was
one of the main comments we received on our analysis. While the
comments and specifically the peer review supported our need to use
economic models to incorporate and measure indirect impacts of biofuel
production, they also highlighted the uncertainty with that modeling
approach, especially in projecting out to the future.
    However, it is important to note that while there are many factors
that impact the uncertainty in predicting total land used for crop
production, making accurate predictions of many of these factors are
not relevant to our analysis. For example different assumptions about
economic growth rates, weather, and exchange rates will all impact
future agricultural projections including amount of land use for crops.
However, we are interested only in the difference between two biofuel
scenarios holding all other changes constant. So the absolute values
and projections for crops and other variables in the model

projections are not as important as the difference the model is
projecting due to an increase in biofuels production. This limits the
uncertainty of using the economic models for our analysis.
    Furthermore, one of the key uncertainties associated with our
agricultural sector economic modeling that has the biggest impact on
land use change results is the assumptions around crop yields. As
discussed in Section V.A.2, we are conducting sensitivity analysis
around different yield assumptions in our analysis.
    Therefore, because of the fact that we are only using the economic
models to determine the difference between two projected scenarios and
the fact that we are conducting sensitivity analysis around the yield
assumptions we feel it is appropriate and acceptable to use economic
models in our analysis of determining GHG thresholds in our final rule
analysis.
    As was the case in the proposed analysis, to estimate the changes
in the domestic agricultural sector (e.g., changes in crop acres
resulting from increased demand for biofuel feedstock or changes in the
number of livestock due to higher corn prices) and their associated
emissions, EPA uses the Forestry and Agricultural Sector Optimization
Model (FASOM), developed by Texas A&M University and others. To
estimate the impacts of biofuels feedstock production on international
agricultural and livestock production, we used the integrated Food and
Agricultural Policy and Research Institute international models, as
maintained by the Center for Agricultural and Rural Development (FAPRI-
CARD) at Iowa State University.
    One of the main comments we received on our choice of models was
the issue of transparency. Several comments were concerned that the
results of EPA's modeling efforts can not be duplicated outside the
experts who developed the models and conducted the analysis used by EPA
in the proposal. Upon the release of the proposal, EPA requested
comment on the use of these various models. EPA conducted a number of
measures to gather comments, including the public comment period upon
release of the NPRM analysis, holding a public workshop on the
lifecycle methodology, and conducting a peer review of the lifecycle
methodology. Specifically, one of the major tasks of the peer review of
EPA's lifecycle GHG methodology was to review and comment on the use of
the various models and their linkages. The response we received through
the peer review is supportive of our use of the FASOM and FAPRI-CARD
models, affirming that they are the strong and appropriate tools for
the task of estimating land use changes stemming from agricultural
economic impacts due to changes in biofuel policy.
    In addition, in an effort to garner as useful comments as possible
and to be as transparent as possible about the modeling process, EPA
supplied in the docket technical documents for the FASOM and FAPRI-CARD
models, the output received by EPA from each model, and the models
themselves such that the public and commenters could learn and examine
how each model operates.
    Building upon the support for the use of the FASOM and FAPRI-CARD
models, a number of important enhancements were made to both models in
response to comments received through the public comment system and
through the peer review, and in consultation with various experts on
domestic and international agronomics. These enhancements include
updated substitution rates of corn and soybean meal for distillers
grains (DG) based on recent scientific research by Argonne National
Laboratory, the addition of a corn oil from the dry mill ethanol
extraction process as a source of biodiesel, the full incorporation of
FASOM's forestry model that dynamically interacts with the agriculture
sector model in the U.S., as well as the addition of a Brazil regional
model to the FAPRI-CARD modeling system. All of these enhancements are
discussed in more detail below and in the RIA (Chapter 2 and 5). In
addition to the model enhancements we also conducted a sensitivity
analysis on yields as part of our final rule analysis. These updates to
our modeling and the sensitivity analysis was done in response to
public comments specifically asking for this to add transparency to the
modeling and modeling results.
    We also received comments on the combined use of FASOM and FAPRI-
CARD. Several comments and peer reviewers questioned the benefit of
using two agricultural sector models. Specifically reviewers pointed to
some of the inconsistencies in the FASOM and FAPRI-CARD domestic
results. For the final rule analysis we worked to reconcile the two
model results. We apply the same set of scenarios and key input
assumptions in both models. For example, both models were updated to
apply consistent treatment of DGs in domestic livestock feed
replacement and consistent assumptions regarding DG export.
    Some reviewers questioned the benefits of using FASOM and suggested
we rely entirely on the FAPRI-CARD model for the analysis. However, we
continue to believe there are benefits to the use of FASOM.
Specifically, the fact that FASOM has domestic land use change
interactions between crop, pasture, and forest integrated into the
modeling is an advantage over using the domestic FAPRI-CARD model that
only tracks cropland.
c. Scenarios Modeled
    As was done for the proposal, to quantify the lifecycle GHG
emissions associated with the increase in renewable fuel mandated by
EISA, we compared the differences in total GHG emissions between two
future volume scenarios in our economic models. For each individual
biofuel, we analyzed the incremental GHG emission impacts of increasing
the volume of that fuel to the total mix of biofuels needed to meet the
EISA requirements. Rather than focus on the impacts associated with a
specific gallon of fuel and tracking inputs and outputs across
different lifecycle stages, we determined the overall aggregate impacts
across sectors of the economy in response to a given volume change in
the amount of biofuel produced.
    Volume Scenarios: The two future scenarios considered included a
``business as usual'' volume of a particular renewable fuel based on
what would likely be in the fuel pool in 2022 without EISA, as
predicted by the Energy Information Agency's Annual Energy Outlook
(AEO) for 2007 (which took into account the economic and policy factors
in existence in 2007 before EISA). The second scenario assumed a higher
volume of renewable fuels as mandated by EISA for 2022.
    We project our analysis and economic modeling through the life of
the program. We then consider the impacts of an increase of biofuels on
the agricultural sector in 2022 as the basis for our threshold
analysis. This was an area that we received numerous comments on
highlighting that this approach adds uncertainty to our results because
we are projecting uncertain technology and other changes out into the
future. One of the recommendations was to base the lifecycle GHG
assessments on a near term time frame and update the analysis every few
years to capture actual technology changes.
    We continue to focus our final rule analyses on 2022 results for
two main reasons. First, it would require an extremely complex
assessment and administratively difficult implementation program to
track how biofuel production might continuously change from month to
month or year to

year. Instead, it seems appropriate that each biofuel be assessed a
level of GHG performance that is constant over the implementation of
this rule, allowing fuel providers to anticipate how these GHG
performance assessments should affect their production plans. Second,
it is appropriate to focus on 2022, the final year of ramp up in the
required volumes of renewable fuel as this year. Assessment in this
year allows the complete fuel volumes specified in EISA to be
incorporated. This also allows for the complete implementation of
technology changes and updates that were made to improve or modeling
efforts. For example, the inclusion of price induced yield increases
and the efficiency gains of DGs replacement are phased in over time.
Furthermore, these changes are in part driven by the changes in earlier
years of increased biofuel use.
    Crop Yield Scenarios: EPA received numerous comments to the effect
that we should consider a case in our economic models with higher
yields that what were projected for the proposed rule analysis. There
are many factors that go into the economic modeling but the yield
assumptions for different crops has one of the biggest impacts on land
use and land use change. Therefore, for this analysis we ran a base
yield case and a high yield case. This will provide two distinct model
results for key parameters like total amount of land converted by crop
by country.
    EPA's base yield projections are derived from extrapolating through
2022 long-term historical U.S. corn yields from 1985 to 2009. This
estimate, 183 bushels/acre for corn and 48 bushels/acre for soybeans,
is consistent with USDA's method of projecting future crop yields.
During the public comment process we learned that numerous technical
advancements-- including better farm practices, seed hybridization and
genetic modification--have led to more rapid gains in yields since
1995. In addition, commenters, including many leading seed companies,
provided data supporting more rapid improvements in future yields. For
example, commenters pointed to recent advancements in seed development
(including genetic modification) and the general accumulation of
knowledge of how to develop and bring to market seed varieties--factors
that would allow for a greater rate of development of seed varieties
requiring fewer inputs such as fertilizer and pest management
applications. This new information would suggest that the base yield
may be a conservative estimate of future yields in the U.S. Therefore,
in coordination with USDA experts, EPA has developed for this final
rule a high yield case scenario of 230 bushels/acre for corn and 60
bushels/acre for soybeans. These figures represent the 99% upper bound
confidence limit of variability in historical U.S. yields. This high
yield case represents a feasible high yield scenario for the purpose of
a sensitivity test of the impact on the results of higher yields.
    Feedback we received indicated that corn and soybean yields respond
in tandem and that a high yield corn case would also imply a higher
yield for soybeans as well. The high yield case is therefore based on
higher yield corn and soybeans in the U.S. as well as in the major corn
and soybean producing countries around the world. For international
yields, it is reasonable to assume the same percent increases from the
baseline yield assumptions could occur as we are estimating for the
U.S. Thus in the case of corn, 230 bushels per acre is approximately
25% higher than the U.S. baseline yield of 183 bushels per acre in
2022. This same 25% increase in yield can be expected for the top corn
producers in the rest of the world by 2022, as justified improvements
in seed varieties and, perhaps even more so than in the case of the
U.S., improvements in farming practices which can take more full
advantage of the seed varieties' potential. For example, seeds can be
more readily developed to perform well in the particular regions of
these countries and can be coupled with much improved farming practices
as farmers move away from historical practices such as saving seeds
from their crop for use the next year and better understand the
economic advantages of modern farming practices. So the high yield
scenarios would not have the same absolute yield values in other
countries as the U.S. but would have the same percent increase.
    While we modeled a high yield scenario for this analysis we
continue to rely primarily on the base yield estimates in our
assessments of different biofuel lifecycle GHG emissions recognizing
that the base yields could be conservative. The reasons outlined above
could lead to higher rates of yield growth in the future, however,
there are mitigating factors that could limit this yield growth or
potentially cause reductions in yield growth rates. For example, the
water requirements for both increased corn farming and ethanol
production could lead to future water constraints that may in some
regions limit yield growth potential. Furthermore, one of the long term
impacts of potential global climate change could be a reduction in
agricultural output of different impacted regions around the world,
including the U.S. This could also serve to reduce yield growth. As
with many aspects of this lifecycle modeling, as the science and data
evolves on crop yields, the Agency will update its factors accordingly.
2. Biofuel Modeling Framework & Methodology for Lifecycle Analysis
Components
    As discussed above, to account for the direct and indirect
emissions of biofuel production required the use of agricultural sector
economic models. The results of these models were combined with other
data sources to generate lifecycle GHG emissions for the different
fuels. The basic modeling framework involved the following steps and
modeling tools.
    To estimate the changes in the domestic agricultural sector we used
FASOM, developed by Texas A&M University and others. FASOM is a partial
equilibrium economic model of the U.S. forest and agricultural sectors
that tracks over 2,000 production possibilities for field crops,
livestock, and biofuels for private lands in the contiguous United
States. Because FASOM captures the impacts of all crop production, not
just biofuel feedstock, we are able to use it to determine secondary
agricultural sector impacts, such as crop shifting and reduced demand
due to higher prices.
    The output of the FASOM analysis includes changes in total domestic
agricultural sector fertilizer and energy use. These are calculated
based on the inputs required for all the different crops modeled and
changes in the amounts of the different crops produced due to increased
biofuel production. FASOM output also includes changes in the number
and type of livestock produced. These changes are due to the changes in
animal feed prices and make-up due to the increase in biofuel
production. The FASOM output changes in fertilizer, energy use, and
livestock are combined with GHG emission factors from those sources to
generate biofuel lifecycle impacts. The GHG emission factors for fuel
and fertilizer production come from the Greenhouse gases, Regulated
Emissions, and Energy use in Transportation (GREET) spreadsheet
analysis tool developed by Argonne National Laboratories, and livestock
GHG emission factors are from IPCC guidance.
    To estimate the domestic impacts of N2O emissions from
fertilizer application, we used the DAYCENT

model developed by Colorado State University. The DAYCENT model
simulates plant-soil systems and is capable of simulating detailed
daily soil water and temperature dynamics and trace gas fluxes
(CH4, N2O, and NOX). DAYCENT model
results for N2O emissions from different crop and land use
changes were combined with FASOM output to generate overall domestic
N2O emissions.
    FASOM output also provides changes in total land use required for
agriculture and land use shifting between crops, and interactions with
pasture, and forestry. This output is combined with emission factors
from land use change to generate domestic land use change GHG emissions
from increased biofuel production.
    To estimate the impacts of biofuels feedstock production on
international agricultural and livestock production, we used the
integrated FAPRI-CARD international models, developed by Iowa State
University. These worldwide agricultural sector economic models capture
the biological, technical, and economic relationships among key
variables within a particular commodity and across commodities.
    The output of the FAPRI-CARD model included changes in crop acres
and livestock production by type by country globally. Unlike FASOM, the
FAPRI-CARD output did not include changes in fertilizer or energy use
or have land type interactions built in. These were developed outside
the FAPRI-CARD model and combined with the FAPRI-CARD output to
generate GHG emission impacts.
    Crop input data by crop and country was developed and combined with
the FAPRI-CARD output crop acreage change data to generate overall
changes in fertilizer and energy use. These fertilizer and energy
changes along with the FAPRI-CARD output livestock changes were then
converted to GHG emissions based on the same basic approach used for
domestic sources, which involves combining with emission factors from
GREET and IPCC.
    International land use change emissions were determined based on
combining FAPRI-CARD output of crop acreage change with satellite data
to determine types of land impacted by the projected crop changes and
then applying emission factors of different land use conversions to
generate GHG impacts.
    Additional modeling and data sources used to determine the GHG
emissions of other stages in the biofuel lifecycle include studies and
data on the distance and modes of transport needed to ship feedstock
from the field to the biofuel processing facility and the finished
biofuel from the facility to end use. These distances and modes are
used to develop amount and type of energy used for transport which is
combined with GREET factors to generate GHG emissions. We also
calculate energy use needed in the biofuel processing facility from
industry sources, reports, and process modeling. This energy use is
combined with emissions factors from GREET to develop GHG impacts of
the biofuel production process
    The following sections outline how the modeling tools and
methodology discussed above were used in conducting the analysis for
the different lifecycle stages of biofuel production, including changes
made since the proposal. Lifecycle stages discussed include feedstock
production, land use change, feedstock and fuel transport, biofuel
production, and vehicle end use. The modeling of the petroleum fuels
baseline is discussed in Section V.B.3.
a. Feedstock Production
    Our analysis addresses the lifecycle GHG emissions from feedstock
production by capturing both the direct and indirect impacts of growing
corn, soybeans, and other renewable fuel feedstocks. For both domestic
and international agricultural feedstock production, we analyzed four
main sources of GHG emissions: agricultural inputs (e.g., fertilizer
and energy use), fertilizer N2O, livestock, and rice
methane. (Emissions related to land use change are discussed in the
next section).
i. Domestic Agricultural Sector Impacts
    Agricultural Sector Inputs: The proposal analysis calculated GHG
emissions from domestic agriculture fertilizer and energy use and
production change by applying rates of energy and fertilizer use by
crop by region to the FASOM acreage data and then multiplying by
default factors for GHG emissions from GREET. Fuel use emissions from
GREET include both the upstream emissions associated with production of
the fuel and downstream combustion emissions.
    In general commenters supported this approach as it captures all
indirect impacts of agricultural sector emissions and not just those
associated with the specific biofuel crop in question. However, we did
receive comments as part of our Model Linkages Peer Review that the
input data for some crops may be overestimating GHG emissions.
Specifically, the commenter highlighted that N2O emissions
from domestic hay production seemed to be over estimated. As part of
the final rule analysis EPA confirmed that input data was being used
correctly, however, the hay N2O emissions in the proposal
may have been overestimated based on the approach used in the proposal
to generate N2O emissions from nitrogen fixing crops. This
has been updated for the final rule analysis as discussed in the next
section which resulted in lower emissions from nitrogen fixing crops.
    Other comments indicated that we should be using the most up to
date data for our calculations of GHG emissions. Since the proposal
there has been a new release of the GREET model (Version 1.8C). EPA
reviewed the new version and concluded that this was an improvement
over the previous GREET release that was used in the proposal analysis
(Version 1.8B). Therefore, EPA updated the GHG emission factors for
fertilizer production used in our analysis to the values from the new
GREET version. This had the result of slightly increasing the GHG
emissions associated with fertilizer production and thus slightly
increasing the GHG emission impacts of domestic agriculture.
    As was the case in the proposal, we held the rates of domestic
fertilizer application constant over time. This is true for both of our
yield scenarios considered as well as for price induced yield
increases. This constant rate of application is justified based on USDA
data indicating that crops are becoming more efficient in their uptake
of fertilizer such that higher yields can be achieved based on the same
per acre fertilizer application rates.
    N2O Emissions: The proposal analysis calculated N2O
emissions from domestic fertilizer application and nitrogen fixing
crops based on the amount of fertilizer used and different regional
factors to represent the percent of nitrogen (N) fertilizer applied
that result in N2O emissions. The proposal analysis
N2O factors were based on existing DAYCENT modeling that was
developed using the 1996 IPCC guidance for calculating N2O
emissions from fertilizer applications and nitrogen fixing crops. We
identified in the proposal that this was an area we would be updating
for the final rule based on new analysis from Colorado State University
using the DAYCENT model. This update was not available at time of
proposal.
    We received a number of comments on our proposal results indicating
that the N2O emissions were overestimated from soybean and
other legume production (e.g., nitrogen fixing hay) in our analysis.
The main issue is that because the N2O emission factors used
in the proposal were based on the 1996

IPCC guidance for N2O accounting they were overestimating
N2O emissions from nitrogen fixing crops. As an update in
2006, IPCC guidance was changed such that biological nitrogen fixation
was removed as a direct source of N2O because of the lack of
evidence of significant emissions arising from the fixation process
itself. IPCC concluded that the N2O emissions induced by the
growth of legume crops/forages may be estimated solely as a function of
the above-ground and below-ground nitrogen inputs from crop/forage
residue. This change effectively reduces the N2O emissions
from nitrogen fixing crops like soybeans and nitrogen fixing hay from
the 1996 to 2006 IPCC guidance.
    Therefore, as part of the update to new N2O emission
factors from DAYCENT used for our final rule analysis we have updated
to the 2006 IPCC guidance which reduces the N2O emissions
from soybean production. This has the effect of reducing lifecycle GHG
emissions for soybean biodiesel production. When we model corn
expansion as would result from increased production of corn-based
ethanol, one of the impacts is that the increase in corn acres
displaces some acres otherwise planted to soy beans. Since the GHG
emissions impact of this change in land use considers the
N2O emissions benefit from the displaced soy, the result of
this lower soy bean N2O assessment means that the benefits
for soy displacement are less, directionally increasing the net GHG
emissions for corn expansion.
    We also received comments on our approach that we should use IPCC
factors directly as opposed to relying on DAYCENT modeling. The
difference is that IPCC provides default factors by crop by country,
while DAYCENT models N2O emissions by crop but also by
region within the US, accounting for different soil types and weather
factors. For the final rule we still rely on the DAYCENT modeling
results as we believe them to be more accurate. For example, the
National Greenhouse Gas Inventory as reported annually by the US to the
Framework Convention on Climate Change uses the DAYCENT model to
determine N2O emissions from domestic fertilizer use as
opposed to using default IPCC factors as the DAYCENT modeling is
recognized to be a more accurate approach.
    Livestock Emissions: GHG emissions from livestock have two main
sources: enteric fermentation and manure management. For the proposal,
enteric fermentation methane emissions were determined by applying IPCC
default factors for different livestock types to herd values as
calculated by FASOM to get GHG emissions. Comments we received on this
approach were that the default IPCC factors do not account for the
beneficial use of distiller grains (DGs) as animal feed. Use of DGs has
been shown to decrease methane produced from enteric fermentation if
replacing corn as animal feed. This is due to the fact that the DGs are
a more efficient feed source. Consistent with our assumptions regarding
the efficiency of DGs as an animal feed in our agricultural sector
modeling, we have also included the enteric fermentation methane
reductions of DGs use in our final rule analysis. The reduction amount
was based on default factors in GREET that calculated this reduction
based on the same Argonne report used to determine DGs feed replacement
efficiency discussed in Section V.B.2.b.i. This resulted in a reduction
in the lifecycle GHG emissions for corn ethanol compared to the
proposal assumptions. More detail on the enteric fermentation methane
reductions of DGs use can be found in Chapter 2 of the RIA.
    The proposal analysis also included the methane and N2O
emissions of livestock manure management based on IPCC default factors
for emissions from the different types of livestock and management
methods combined with FASOM results for livestock changes. We received
comments that this was a good approach as it quantifies the indirect
impacts of emissions associated with biofuel production. The same
approach was used for the final rule analysis.
    Methane from Rice: For the proposal, methane emissions from rice
production were calculated by taking the FASOM output predicted changes
in rice acres, resulting from the increase in biofuel production, and
multiplying by default methane emission factors from IPCC to generate
GHG impacts. We received comments that this was a good approach as it
quantifies the indirect impacts of emissions associated with biofuel
production. The same approach was used for the final rule analysis.
ii. International Agricultural Sector Impacts
    Agricultural Sector Inputs: For the proposal we determined
international fertilizer and energy use emissions based on applying
input data collected by the Food and Agriculture Organization (FAO) of
the United Nations and the International Energy Agency (IEA) to the
FAPRI-CARD crop output data and then applied GREET defaults for
converting those inputs to GHG emissions.
    As part of our public comment and peer review process we had this
component of our analysis specifically peer reviewed. The main comment
we received was to update our input data with newer data sources.
Therefore, for the final rule analysis we updated fertilizer and
pesticide consumption projections from the incorporation of updates
made by the FAO to its Fertistat and FAOStat datasets, as well as the
incorporation of more up-to-date fertilizer consumption statistics
provided by a recent International Fertilizer Institute (IFA) report.
This update had varying impacts on the amount of fertilizer used on
different crops in different countries but in general increased the
amount of fertilizer assumed and thus international agriculture
lifecycle GHG emissions from fertilizer use for all biofuels.
    Another comment from the peer review was that we should include
lime use for some of the key crops modeled in our analysis. Lime use
was not included in the proposal because of lack of international data
on lime use by crop. Excluding lime used is an underestimate of
international agriculture GHG emissions. For our final rule analysis we
included lime use for sugarcane production in Brazil based on
information received from Brazilian agricultural experts provided as
part of the comment process. This led to an increase in GHG emissions
from sugarcane farming. We did not include lime use for other crops in
the final rule analysis because of lack of other data sources for other
crops.
    Other comments we received on our approach were that we were
potentially underestimating GHG emissions from international
agriculture energy use. Our proposal based international agriculture
energy use on factors from the International Energy Agency (IEA) that
included all energy use for agriculture that we divided by all
agricultural sector land by country to get a GHG emission per acre for
each country considered. The comment raised the issue that by using all
agricultural land this includes pasture land that would not have the
same energy input as crop production. Effectively, higher energy use
from crop production was getting averaged with lower energy use for
pasture and then this lower number was applied only to crop production.
We specifically asked as part of our peer review for guidance and
comment on our international agriculture energy use calculation. We did
not receive significant comments or data to suggest that we change our
approach and reviewers generally

agreed we were using the best data available. Furthermore, the energy
use values represent all agriculture including forestry and fishing
which could in some countries be overestimating energy use for crop
production. So for our final rule analysis we used the same approach as
for the proposal to calculate international agriculture energy use GHG
emissions.
    We also received comments on the applicability of applying GREET
defaults for fuel and fertilizer production to international fuel and
fertilizer use to generate GHG emissions. The comments noted that GREET
factors are developed for domestic US conditions and would not
necessarily apply internationally. Specifically on the issue of
nitrogen fertilizer production, the comments indicated that nitrogen
fertilizer production internationally could rely on coal as a fuel
source as opposed to natural gas used in the US, which would cause
international GHG emissions associated with fertilizer production and
hence biofuel production to be underestimated in our analysis. This was
also an area we asked peer reviewers for comment and guidance. The peer
review response generally supported our approach and did not offer
suggestions for other data sources. So for our final rule analysis we
used the same approach as for the proposal and applied GREET defaults
to calculate international fertilizer production GHG emissions.
    As was the case in the proposal and for domestic agriculture, we
held the rates of international fertilizer application constant over
time. This is true for both of our yield scenarios considered as well
as for price induced yield increases. This was an area that was
specifically addressed in our peer review of International Agricultural
Greenhouse Gas Emissions and Factors. The reviewers supported the
approach we have taken, for example indicating that generally crop
production as a unit of fertilizer application has increased over time,
therefore, crop yields have increased with the same or lower fertilizer
applications.
    N2O Emissions: For the proposal we included
N2O emissions from fertilizer application by applying IPCC
default factors for different crops in different countries. We use IPCC
default factors because we do not have the same level of regional
factors like we do in the US from the DAYCENT model. The IPCC guidance
has emission factors for four sources of N2O emissions from
crops, Direct N2O Emissions from Synthetic Fertilizer
Application, Indirect N2O Emissions from Synthetic
Fertilizer Application, Direct Emissions from Crop Residues, and
Indirect Emissions from Crop Residues. The proposal did not include
N2O emissions from the Direct and Indirect Emissions from
Crop Residues for cotton, palm oil, rapeseed, sugar beet, sugarcane, or
sunflower. These were not included for these crops because default
crop-specific IPCC factors used in the calculation were not available.
    Comments from our peer review process suggested that we include
proxy emissions from these crops based on similar crop types that do
have default factors. Therefore, for our final rule analysis we have
included crop residue N2O emissions from sugarcane
production based on perennial grass as a proxy. Perennial grass is
chosen as a proxy based on input from N2O modeling experts.
This change results in an increase in N2O emissions from
sugarcane and therefore sugarcane ethanol production compared to the
proposal.
    Livestock Emissions: Similar to domestic livestock impacts, enteric
fermentation and manure management GHG emissions were included in our
proposal analysis. The proposal calculated international livestock GHG
impacts based on activity data provided by the FAPRI-CARD model (e.g.,
number and type of livestock by country) multiplied by IPCC default
factors for GHG emissions.
    Based on the peer review of the methodology used for the proposal
it was determined that the calculations for manure management did not
include emissions from soil application. These emissions were included
for our final rule analysis but do not cause a significant change in
the livestock GHG emission results.
    Rice Emissions: To estimate rice emission impacts internationally,
the proposal used the FAPRI-CARD model to predict changes in
international rice production as a result of the increase in biofuels
demand in the U.S. We then applied IPCC default factors by country to
these predicted changes in rice acres to generate GHG emissions. We
received comments that this was a good approach as it quantifies the
indirect impacts of emissions associated with biofuel production. The
same approach was used for the final rule analysis.
b. Land Use Change
    The following sections discuss our final rulemaking assessment of
GHG emissions associated with land use changes that occur domestically
and internationally as a result of the increase in renewable fuels
demand in the U.S. There are four main methodology questions addressed
both domestically and internationally:
     Amount of Land Converted and Where.
     Type of Land Converted.
     GHG Emissions Associated with Conversion.
     Timeframe of Emission Analysis.
    Each of those methodology components are discussed as are the
comments we received as part of the comment and peer review process. We
also outline in addition to our main FASOM and FAPRI-CARD approach a
general equilibrium modeling approaches and its results.
i. Amount of Land Area Converted and Where
    Based on a number of modeling changes made to the FASOM and FAPRI-
CARD models since the NPRM, the amount of land use change resulting
from an increase in biofuel demand in the U.S. is significantly lower
in this FRM analysis for most renewable fuels. Many of the changes made
were a direct result of comments received through the notice-and-
comment period, comments received from the peer-reviewers, or as a
result of incorporating new science that has become available since the
analysis was conducted in the proposal. Some of the key changes that
had the largest impact on the land use change estimates are included in
this section. For additional information, see Chapter 2 of the RIA.
    As discussed in the NPRM, one of the key factors in determining the
amount of new land needed to meet an increase in biofuel demand is the
treatment of co-products of ethanol and biodiesel production. We
received many comments on this topic, particularly on the amount of
corn and soybean meal a pound of DGS, the byproduct of dry mill grain
ethanol production, can replace in animal feed. For the final rule, we
predict that distiller grains will be absorbed by livestock more
efficiently over time. We updated the displacement rate assumptions in
the FASOM and FAPRI-CARD models based on comments we received and on
the recent research conducted by Argonne National Laboratory and
others.\167\ According to this research, one pound of DGS replaces more
than a pound of corn and/or soybean meal in beef and dairy rations, in
part because cattle fed DGS show faster weight gain and increased milk
production compared to those fed a traditional diet. While this

study represents a significant increase over current DGS replacement
rates, we believe it is reasonable to assume that improvements will be
made in the use and efficiency of DGS over time as the DGS market
matures, the quality and consistency of DGS improves, and as livestock
producers learn to optimize DGS feed rations. As a result of this
modification, less land is needed to replace the amount of corn
diverted to ethanol production. Additional details on the DGS
assumptions are included in Chapters 2 and 5 of the RIA.
---------------------------------------------------------------------------

    \167\ Salil, A., M. Wu, and M. Wang. 2008. ``Update of
Distillers Grains Replacement Ratios for Corn Ethanol Life-Cycle
Analysis.'' Available at http://www.transportation.anl.gov/pdfs/AF/
527.pdf.
---------------------------------------------------------------------------

    A second factor that can have a significant impact on the amount of
land that may be converted as a result of increasing biofuel demand are
changes in crop yields over time. As discussed in the NPRM, our
proposal based domestic yields on USDA projections for both the
reference case and the control case. As discussed in Section V.B.1.c,
for this FRM we have also included scenarios that use higher yield
projections in both the reference case and the control case. However,
in the NPRM we also requested comment on whether the higher prices
caused by an increased in demand for biofuels would increase future
yield projections in the policy case beyond the yield trends in the
reference case (sometimes referred to as ``price induced yields''), or
whether these price induced yields would be offset by the reduction in
yields associated with expanding production onto new marginal acres
(sometimes referred to as extensification). Based on the comments we
received, along with additional historical trend analysis conducted by
FAPRI-CARD, the international agricultural modeling framework now
incorporates a price induced yield component.\168\ The new yield
adjustments are partially offset by the extensification factor,
however, the combined impact is that fewer new acres are needed for
agricultural production to meet world agricultural demands.
---------------------------------------------------------------------------

    \168\ Technical Report: An Analysis of EPA Renewable Fuel
Scenarios with the FAPRI-CARD International Models, CARD Staff,
January, 2010.
---------------------------------------------------------------------------

    One additional change we made to the yield assumptions was to
update the FASOM model with new analysis by Pacific Northwest National
Laboratories (PNNL) on switchgrass yields.\169\ We included this new
data for two reasons. First, we received several comments that our
assumptions on switchgrass yields were too low, based on more recent
field work. In addition, for out NPRM analysis, we did not have data
for switchgrass yields in certain regions of the US. Therefore, the
PNNL data helped to fill a pre-existing data gap. As a result of these
updates, less land is needed per gallon of switchgrass ethanol
produced. Additional details on switchgrass yields and other
agricultural sector modeling assumptions are included in RIA Chapter 5.
---------------------------------------------------------------------------

    \169\ Thomson, A.M., R.C. Izarrualde, T.O. West, D.J. Parrish,
D.D. Tyler, and J.R. Williams. 2009. Simulating Potential
Switchgrass Production in the United States. PNNL-19072. College
Park, MD: Pacific Northwest National Laboratory.
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    One of the major changes made to the FAPRI-CARD model between the
NPRM and FRM includes the more detailed representation of Brazil
through a new integrated module. The Brazil module was developed by
Iowa State with input from Brazilian agricultural sector experts and we
believe it is an improvement over the approach used in the proposal. In
the NPRM, we requested additional data for countries outside the U.S.
We received comments encouraging us to use regional and country
specific data where it was available. We also received comments
encouraging us to take into account the available supply of abandoned
pastureland in Brazil as a potential source of new crop land. The new