Industrial Crops and Products 23 (2006) 288-296.
    \436\ Shapouri, H., Gallagher, P.; USDA's 2002 Ethanol Cost-of-
Production Survey (published July 2005).
---------------------------------------------------------------------------

    For our policy case scenario, we used corn prices of $3.34/bu in
2022 with corresponding DDGS prices of $139.78/ton (all 2006$). These
estimates are taken from agricultural economics modeling work done for
this proposal using the Forestry and Agricultural Sector Optimization
Model (see Section IX.A).
    For natural gas-fired ethanol production producing dried co-product
(currently describes the largest fraction of the industry), in the
policy case corn feedstock minus DDGS sale credit represents about 57%
of the final per-gallon cost, while utilities, facility, and labor
comprise about 22%, 11%, and 4%, respectively. Thus, the cost of
ethanol production is most sensitive to the prices of corn and the
primary co-product, DDGS, and relatively insensitive to economy of
scale over the range of plant sizes typically seen (40-100 MMgal/yr).
    We expect that several process fuels will be used to produce corn
ethanol (see DRIA Section 1.4), which are presented by their projected
2022 volume production share in Table VIII.A.1-1a and cost impacts for
each in Table VIII.A.1-1b.\437\ We request comment on the projected mix
of plant fuel sources in the future as well as the cost impacts of
various technologies.
---------------------------------------------------------------------------

    \437\ Projected fuel mix was taken from Mueller, S., Energy
Research Center at the University of Chicago; An Analysis of the
Projected Energy Use of Future Dry Mill Corn Ethanol Plants (2010-
2030); cost estimates were derived from modifications to the USDA
process models. We are aware that the cost impacts of CHP are likely
overestimated here and will be revised in the final rulemaking.

   Table VIII.A.1-1a--Projected 2022 Breakdown of Fuel Types Used To Estimate Production Cost of Corn Ethanol,
                                    Percent Share of Total Production Volume
----------------------------------------------------------------------------------------------------------------
                                                             Fuel type                            Total by plant
                                 ----------------------------------------------------------------      type
           Plant type                                                                            ---------------
                                      Biomass     Coal (percent)    Natural gas       Biogas         All fuels
                                     (percent)                       (percent)       (percent)       (percent)
----------------------------------------------------------------------------------------------------------------
Coal/Biomass Boiler.............              11               0  ..............  ..............              11
Coal/Biomass Boiler + CHP.......              10               4  ..............  ..............              14
Natural Gas Boiler..............  ..............  ..............              49              14              63
Natural Gas Boiler + CHP........  ..............  ..............              12  ..............              12
                                 -------------------------------------------------------------------------------
    Total by Fuel Type..........              21               4              61              14             100
----------------------------------------------------------------------------------------------------------------

 Table VIII.A.1-1b--Projected 2022 Breakdown of Cost Impacts by Fuel Type Used in Estimating Production Cost of
                        Corn Ethanol, Dollars per Gallon Relative to Natural Gas Baseline
----------------------------------------------------------------------------------------------------------------
                                                             Fuel type                            Total by plant
                                 ----------------------------------------------------------------      type
           Plant type                                                                            ---------------
                                    Biomass \a\        Coal         Natural gas     Biogas \b\       All fuels
----------------------------------------------------------------------------------------------------------------
Coal/Biomass Boiler.............          -$0.02          -$0.02  ..............  ..............  ..............
Coal/Biomass Boiler + CHP.......          +$0.14          +$0.14  ..............  ..............  ..............
Natural Gas Boiler..............  ..............  ..............        baseline          +$0.00  ..............

Natural Gas Boiler + CHP........  ..............  ..............          +$0.16  ..............  ..............
                                 -------------------------------------------------------------------------------
    Total by Fuel Type..........  ..............  ..............  ..............  ..............           $0.04
----------------------------------------------------------------------------------------------------------------
\a\ Assumes biomass has same plant-delivered cost as coal.
\b\ Assumes biogas has same plant-delivered cost as natural gas.

    Based on energy prices from EIA's Annual Energy Outlook (AEO) 2008
baseline case ($53/bbl crude oil), we arrive at a production cost of
$1.49/gal. In the case of EIA's high price scenario ($92/bbl crude),
this figure increases by 6 cents per gallon. More details on the
ethanol production cost estimates can be found in Chapter 4 of the
DRIA. This estimate represents the full cost to the plant operator,
including purchase of feedstocks, energy required for operations,
capital depreciation, labor, overhead, and denaturant, minus revenue
from sale of co-products. The capital cost for a 65 MMgal/yr natural
gas fired dry mill plant is estimated at $89MM (this the projected
average size of such plants in 2022). Similarly, coal and biomass fired
plants were assumed to be 110 MGY in capacity, with an estimated
capital cost of $200MM.\438\ On average, ethanol produced in a facility
using coal or biomass as a primary energy source results in a per-
gallon cost $0.02/gal lower compared to production using natural gas.
---------------------------------------------------------------------------

    \438\ Capital costs for a natural gas fired plant were taken
from USDA cost model; incremental costs to use coal as the primary
energy source were derived from conversations with ethanol plant
construction contractors.
---------------------------------------------------------------------------

    In this cost estimation work, we did not assume any pelletizing of
DDGS. Pelletizing is expected to improve ease of shipment to more
distant markets, which may become more important at the larger volumes
projected for the future. However, while many in industry are aware of
this technology, those we spoke with are not employing it in their
plants, and do not expect widespread use in the foreseeable future.
According to USDA's model, pelletizing adds $0.035/gal to the ethanol
production cost. We request comment on whether pelletizing should be
included in our program cost estimates.
    In support of our biodiesel and renewable diesel volume feasibility
estimates, we included recovery of corn oil from distillers' grains
streams in our ethanol production cost estimates at a rate of 37% of
ethanol production by 2022.\439\ According to economic analyses done by
USDA based on the GS Cleantech corn oil extraction process, the capital
cost to install the system for a 50 MMgal/yr ethanol plant is
approximately $6 million. The system is capable of extracting about one
third of the corn oil entering the plant, and produces a low-quality
corn oil co-product stream. In our analysis, we assumed the value of
this additional co-product to be 70% that of soy oil (the same as
yellow grease, $0.27/lb), resulting in a credit per gallon of ethanol
of $0.04 for a 50 MMgal/yr plant operating such a system.
---------------------------------------------------------------------------

    \439\ Although some oil extraction may be done as front-end
fractionation of the kernel, we believe the majority will be
produced via separation from distillers' grains streams. For more
discussion of corn oil extraction and fractionation, see Chapter 4
of the DRIA.
---------------------------------------------------------------------------

    Note that the ethanol production cost given here does not account
for any subsidies on production or sale of ethanol, and is independent
of the market price of ethanol.
b. Cellulosic Ethanol
i. Feedstock Costs
Cellulosic Feedstock Costs
    To estimate the cost of producing cellulosic biofuels, it was first
necessary to estimate the cost of harvesting, storing, processing and
transporting the feedstocks to the biofuel production facilities.
Ethanol or other cellulosic biofuels can be produced from crop residues
such as corn stover, wheat, rice, oat, and barley straw, sugar cane
bagasse, and sorghum, from other cellulosic plant matter such as forest
thinnings and forest-fuel removal, pulping residues, and from the
cellulosic portions of municipal solid waste (MSW). Currently, there
are no energy crops such as switchgrass nor short rotation woody crops
(SRWC poplars, etc.) grown specifically for energy production.
    Our feedstock supply analysis projected that crop residue,
primarily corn stover, will be the most abundant of the cellulosic
feedstocks, comprising about 61% of the total biomass feedstock
inventory. Forest residues make up about 25% of the total, and MSW
makes up the remaining 14%. At present, there are no commercial sized
cellulosic ethanol plants in the U.S. Likewise, there are no
commercially proven, fully-integrated feedstock supply systems
dedicated to providing any of the feedstocks we mentioned to ethanol
facilities of any size, although certain biomass is harvested for other
purposes. For this reason, our feedstock cost estimates are projections
and not based on any existing market data.
    Our feedstock costs include an additional preprocessing cost that
many other feedstock cost estimates do not include--thus our costs may
seem higher. We used biofuel plant cost estimates provided by NREL
which no longer includes the cost for finely grinding the feedstock
prior to feeding it to the biofuel plant. Thus, our feedstock costs
include an $11 per dry ton cost to account for the costs of this
grinding operation, regardless of whether this operation occurs in the
field or at the plant gate.
Crop Residue and Energy Crops
    Crop residue harvest is currently a secondary harvest; that is they
are harvested or gathered only after the prime crop has been harvested.
In most northern areas, the harvest periods will be short due to the
onset of winter weather. In some cases, it may be necessary to gather a
full year's worth of residue within just a few weeks. Consequently, to
accomplish this hundreds of pieces of farm equipment will be required
for a few weeks each year to complete a harvest. Winter conditions in
the South make it somewhat easier to extend the harvest periods; in
some cases, it may be possible to harvest a residue on an as needed
basis.
    During the corn grain harvest, generally only the cob and the
leaves above the cob are taken into the harvester. Thus, the stover
harvest would likely require some portion of the

standing-stalks be mowed or shredded, following which the entire
residue, including that discharged from the combine residue-spreader,
would need to be raked. Balers, likely a mix of large round and large
square balers, would follow the rakes. The bales would then be removed
from the field, usually to the field-side in the first operation of the
actual harvest, following which they would then be hauled to a
satellite facility for intermediate storage. For our analysis we
assumed that bales would then be hauled by truck and trailer to the
processing plant on an as needed basis.
    The small grain straws (wheat, rice, oats, barley, sorghum) are cut
near the ground at the time of grain harvest and thus likely won't
require further mowing or shredding. They will likely need to be raked
into a windrow prior to baling. Because small grain straws have been
baled and stored for many years, we don't expect unusual requirements
for handling these residues. Their harvest and storage costs will
likely be less than those for corn stover, but their overall quantity
is much less than corn stover (corn stover makes up about 71% of all
the crop residues), so we don't expect their lower costs to have,
individually or collectively, a huge effect on the overall feedstock
costs. Thus, we project that for several years, the feedstock costs
will be largely a function of the cost to harvest, store, and haul corn
stover.
    For the crop residues, we relied on the FASOM agricultural cost
model for farm harvesting and collection costs. FASOM estimates it
would cost $33 per dry ton to mow, rake, bale, and field haul the bales
and replace nutrients. We added $10 per dry ton as a farmer payment,
which we believe is a necessary reimbursement to farmers to cover their
costs associated with this additional harvest. Thus, $43 per dry ton
covers the cost of making the crop residue available at the farm gate.
This farm gate cost could be lower if new equipment is developed that
would allow the farmer to harvest the corn stover at the same time as
the corn. We also conducted our own independent analysis of the farm
gate feedstock costs for corn stover, and our farm gate cost estimate
for stover feedstock is very similar to FASOM's. For the steps involved
in moving the corn stover from the farm gate to the cellulosic ethanol
plant, we relied upon our own cost analysis. Our cost analysis
estimates that an additional $32 per dry ton would be required to haul
the bales to satellite storage, pay for the storage facilities, and
grind the residue. Because of the low density of corn stover and other
crop residues, we estimate that 60 or more secondary storage sites
would be necessary to minimize the combined transportation and storage
costs for a 100 million gallon per year plant. We estimated it would
cost about $14 per dry ton to haul the feedstock from the satellite
storage to the processing plant. Adding up all the costs, corn stover
is estimated to cost $88 per dry ton delivered to the cellulosic
biofuel plant. A more detailed discussion of our corn stover feedstock
cost analysis is contained in Chapter 4.1 of the DRIA.
    Energy crops such as switchgrass and miscanthus would be harvested,
baled, stored and transported very similar to crop residues. Because of
their higher production density per acre, though, we would expect that
the ``farm gate'' costs to be slightly lower than crop residues (we
estimate the costs to be about $1 per dry ton lower). Also, the higher
production density would allow for fewer secondary storage facilities
compared to crop residue and a shorter transportation distance. For
example, we estimate that switchgrass would require less than 30
secondary storage facilities which would help to lower the feedstock
costs for a 100 million gallon per year plant compared to crop
residues. As a result the secondary storage and transportation costs
are estimated to be $9 per ton lower than crop residue such as corn
stover. Thus, we estimate that cellulosic feedstock costs sourced from
switchgrass would be about $78 per dry ton. Chapter 4.1 of the DRIA
contains a more in-depth discussion of the feedstock costs for energy
crops such as switchgrass.
Forestry Residue
    Harvest and transport costs for woody biomass in its different
forms vary due to tract size, tree species, volumes removed, distance
to the wood-using/storage facility, terrain, road condition, and other
many other considerations. There is a significant variation in these
factors within the United States, so timber harvest and delivery
systems must be designed to meet constraints at the local level.
Harvesting costs also depend on the type of equipment used, season in
which the operation occurs, along with a host of other factors. Much of
the forest residue is already being harvested by logging operations, or
is available from milling operations. However, the smaller branches and
smaller trees proposed to be used for biofuel production are not
collected for their lumber so they are normally left behind. Thus, this
forest residue would have to be collected and transported out of the
forest, and then most likely chipped before transport to the biofuel
plant.
    In general, most operators in the near future would be expected to
chip at roadside in the forest, blowing the chips directly into a chip
van. When the van is full it will be hauled to an end user's facility
and a new van will be moved into position at the chipper. The process
might change in the future as baling systems become economically
feasible or as roll-off containers are proven as a way to handle
logging slash. At present, most of the chipping for biomass production
is done in connection with forest thinning treatments as part of a
forest fire prevention strategy. The major problem associated with
collecting logging residues and biomass from small trees is handling
the material in the forest before it gets to the chipper. Specially-
built balers and roll-off containers offer some promise to reduce this
cost. Whether the material is collected from a forest thinning
operation or a commercial logging operation, chips from residues will
be dirty and will require screening or some type of filtration at the
end-user's facility.\440\
---------------------------------------------------------------------------

    \440\ Personal Communication, Eini C. Lowell, Research
Scientist, USDA Forest Service.
---------------------------------------------------------------------------

    Results from a study in South Georgia show that under the right
conditions, a small chipper could be added to a larger operation to
obtain additional chip production without adversely impacting roundwood
production, and that the chips could be produced from limbs and tops of
harvested trees at costs ranging from $11 per ton and up. Harvesting
understory (the layer formed by grasses, shrubs, and small trees under
the canopy of larger trees and plants) for use in making fuel chips was
estimated to be about $1 per ton more expensive.
    Per-ton costs decrease as the volume chipped increases per acre.
Some estimates suggest that if no more than 10 loads of roundwood are
produced before a load of chips is made, that chipper-modified system
could break even. Cost projections suggest that removing only limbs and
tops may be marginal in terms of cost since one load of chips is
produced for about every 15 loads of roundwood.
    Instead of conducting our own detailed cost estimate for making
forest residue chips available at the edge of the harvested forests, we
instead relied upon the expertise of the U.S. Forest Service. The U.S.
Forest Service provided us a cost curve for different categories of
forest residue, including logging residue, other removals (i.e.,
clearing trees for new building construction), timberland trimmings

(forest fire prevention strategy) and mill residues. They recommended
that we choose $45 per dry ton as the price point for our cost
analysis. This seemed reasonable since this price point was roughly the
same as the farm gate crop residue discussed above, and so we used this
price point for our analysis. Assuming that the wood chips would be
ground further in the field adds an additional $11 per dry ton to the
feedstock cost.
    Delivery of woody biomass from the harvesting site to a conversion
facility, like delivery of more conventional forest products, accounts
for a significant portion of the delivered cost. In fact,
transportation of wood fiber (including hauling within the forest)
accounts for about 25 to 50% of the total delivered costs and highly
depends on fuel prices, haul distance, material moisture content, and
vehicle capacity and utilization. Also, beyond a certain distance,
transportation becomes the limiting factor and the costs become
directly proportional to haul distance.\441\ Based on our own cost
analysis, we anticipate that hauling woody biomass to plant will cost
about $14 per ton, for a total delivered price of about $70 per dry
ton. Chapter 4.1 of the DRIA contains a more detailed discussion on the
feedstock costs for forest residue.
---------------------------------------------------------------------------

    \441\ Ashton, S.; B. Jackson; R. Schroeder. Cost Factors in
Harvesting and Transporting Woody Biomass, 2007. Module 4:
Introduction to Harvesting, Transportation, and Processing:: Fact
Sheet 4.7.
---------------------------------------------------------------------------

Municipal Solid Waste
    Millions of tons of municipal solid waste (MSW) continue to be
disposed of in landfills across the country, despite recent large gains
in waste reduction and diversion. The biomass fraction of this total
stream represents a potentially significant resource for renewable
energy (including electricity and biofuels). Because this waste
material is already being generated, collected and transported (it
would only need to be transported to a different location), its use is
likely to be less expensive than other cellulosic feedstocks. One
important difficulty facing those who plan to use MSW fractions for
fuel production is that in many places, even today, MSW is a mixture of
all types of wastes, including biomaterials such as animal fats and
grease, tin, iron, aluminum, and other metals, painted woods, plastics,
and glass. Many of these materials can't be used in biochemical and
thermochemical ethanol production, and, in fact, would inflate the
transportation costs, impede the operations at the cellulosic ethanol
plant and cause an expensive waste stream for biofuel producers.
    Thus, accessing sorted MSW would likely be a requirement for firms
planning on using MSW for producing cellulosic biofuels. In a
confidential conversation, a potential producer who plans to use MSW to
produce ethanol indicated that their plant plans are based on obtaining
cellulosic biowaste which has already been sorted at the waste source
(e.g., at the curbside, where the refuse hauler picks up waste already
sorted by the generating home-owner or business). For example, in a
tract of homes, one refuse truck would pick up glass, plastic, and
perhaps other types of waste destined for a specific disposal depot,
whereas a different truck would follow to pick up wood, paper, and
other cellulosic materials to be hauled to a depot that supplies an
ethanol plant. However, only a small fraction of the MSW generated
today is sorted at the curbside.
    Another alternative would be to sort the waste either at a sorting
facility, or at the landfill, prior to dumping. There are two prominent
options here. The first is that there is no sorting at the waste
creation site, the home or business, and thus a single waste stream
must be sorted at the facility. This operation would likely be done by
hand or by automated equipment at the facility. To do so by hand is
very labor intensive and somewhat slower than using an automated
system. In most cases the `by-hand' system produces a slightly cleaner
stream, but the high cost of labor usually makes the automated system
more cost-effective. Perhaps the best approach for low cost and a clean
stream is the combination of hand sorting with automated sorting.
    The third option is a combination of the two which requires that
there is at least some sorting at the home or business which helps to
prevent contamination of the waste material, but then the final sorting
occurs downstream at a sorting site, or at the landfill.
    We have little data and few estimates for the cost to sort MSW. One
estimate generated by our Office of Solid Waste for a combination of
mechanically and manually sorting a single waste stream downstream of
where the waste is generated puts the cost in the $20 to $30 per ton
range. There is a risk, though, that the waste stream could still be
contaminated and this would increase the cost of both transporting the
material and using this material at the biofuel plant due to the toxic
ash produced which would require disposal at a toxic waste facility. If
a less contaminated stream is desired it would probably require sorting
at the generation site--the home or business--which would likely be
more costly since many more people in society would then have to be
involved and special trucks would need to be used. Also, widespread
participation is difficult when a change in human behavior is required
as some may not be so willing to participate. Offering incentives could
help to speed the transition to curbside recycling (i.e., charging a
fee for nonsorted waste, or paying a small amount for sorted tree
trimmings and construction and demolition waste). Assuming that
curbside sorting is involved, at least in a minor way, total sorting
costs might be in the $30 to $40 per ton range. We request comment on
the costs incurred for sorting cellulosic material from the rest of MSW
waste.
    These sorting costs would be offset by the cost savings for not
disposing of the waste material. Most landfills charge tipping fees,
the cost to dump a load of waste into a landfill. In the United States,
the national average nominal tipping fee increased fourfold from 1985
to 2000. The real tipping fee almost doubled, up from a national
average (in 1997 dollars) of about $12 per ton in 1985 to just over $30
in 2000. Equally important, it is apparent that the tipping fees are
much higher in densely populated regions and for areas along the U.S.
coast. For example, in 2004, the tipping fees were $9 per ton in Denver
and $97 per ton in Spokane. Statewide averages also varied widely, from
$8 a ton in New Mexico to $75 in New Jersey. Tipping fees ranged from
$21 to 98 per ton in 2006 for MSW and $18/ton to $120/ton for
construction and demolition waste. It is likely that the tipping fees
are highest for contaminated waste that requires the disposal of the
waste in more expensive waste sites that can accept the contaminated
waste as opposed to a composting site. However, this same contaminated
material would probably not be desirable to biofuel producers.
Presuming that only the noncontaminated cellulosic waste (yard
trimmings, building construction and demolition waste and some paper)
is collected as feedstocks for biofuel plants, the handling and tipping
fees are likely much lower, in the $30 per ton range.\442\
---------------------------------------------------------------------------

    \442\ We plan on conducting a more thorough analysis of tipping
fees by waste type for the final rulemaking.
---------------------------------------------------------------------------

    The avoidance of tipping fees, however, is a complex issue since
landfills are generally not owned by municipalities anymore. Both large
and small municipalities recognized their

inability to handle the new and complex solid waste regulations at a
reasonable cost. Only 38 out of the 100 largest cities own their own
landfills. To deal with the solid waste, large private companies built
massive amounts of landfill capacity. The economic incentive is for
private landfill operators to fill their landfills with garbage as
early as possible to pay off their capital investment (landfill site)
quickly. Also, the longer the landfill is operating the greater is its
exposure to liability due to leakages and leaching. Furthermore,
landfills can more cost-effectively manage the waste as the scale of
the landfill is enlarged. As a result, there are fewer landfills and
landfill owners, and an expansion of market share by large private
waste management firms, thus decreasing the leverage a biofuel producer
may have.\443\ Many waste management firms have been proactive by using
the waste material to produce biogas, another fuel type that would
qualify under RFS2. Yet other parties interested in procuring MSW are
waste-to-energy (WTE) facilities, which burn as much waste material as
possible to produce electricity. These three different interests may
compete for MSW for producing biofuels. This competition is desirable,
resulting in lower overall cost and the production of the most cost-
effective types of biofuels. We request comment on the costs avoided
for diverting cellulosic material from landfills.
---------------------------------------------------------------------------

    \443\ Osamu Sakamoto, The Financial Feasibility Analysis of
Municipal Solid Waste to Ethanol Conversion, Michigan State
University, Plan B Master Research Paper in partial fulfillment of
the requirement for the degree of Master of Science, Department of
Agricultural Economics, 2004
---------------------------------------------------------------------------

    Once the cellulosic biomass has been sorted from the rest of MSW,
it would have to be transported to the biofuels plant. Transporting is
different for MSW biomass compared to forest and crop residues. Forest
and crop residues are collected from forests and farms, which are both
rural sites, and transported to the biofuel plant which likely is
located at a rural site. The trucks which transport the forest and crop
residues can be large over-the-road trucks which can average moderate
speeds because of the lower amount of traffic that they experience.
Conversely, MSW is being collected throughout urban areas and would
have to transported through those urban areas to the plant site. If the
cellulosic biomass is being collected at curbside, it would likely be
collected in more conventional refuse trucks. If the plant is nearby,
then the refuse trucks could transport the cellulosic biomass directly
to the plant. However, if the plant is located far away from a portion
of the urban area, then the refuse trucks would probably have to be
offloaded to more conventional over-the-road trucks with sizable
trailers to make transport more cost-effective. We estimate that the
cost to transport the cellulosic biomass sourced from MSW to the
biofuel plant be $15 per ton.
    A significant advantage of MSW over other cellulosic biomass is
that it can be generated year-round in many parts of the U.S. If a
steady enough stream of this material is available, then secondary
storage would not be necessary, thus avoiding the need to install
secondary storage. We assumed that no secondary storage costs would be
incurred for MSW-sourced cellulosic biomass.
    The total costs for MSW-sourced cellulosic biomass is estimated to
be $30 -$40 per ton for sorting costs, a savings of $30 per ton for
tipping costs avoided, $15 per ton for transportation costs and $11 per
ton for grinding the cellulose to prepare it as a feedstock--resulting
in a total feedstock cost of $26 to $36 per ton. In our cost analysis,
we assumed an average cost of $31 per ton. Chapter 4.1 of the DRIA
contains a more detailed discussion of the feedstock costs for MSW.
    Table VIII.A.1-2 below summarizes major cost components for each
cellulosic feedstock.

                             Table VIII.A.1-2--Summary of Cellulosic Feedstock Costs
                                            [$53/ton crude oil costs]
----------------------------------------------------------------------------------------------------------------
              Ag residue                     Switchgrass             Forest residue                MSW
----------------------------------------------------------------------------------------------------------------
        60% of total feedstock          1% of total feedstock    25% of total feedstock   14% of total feedstock
----------------------------------------------------------------------------------------------------------------
Mowing, Raking, Baling, Hauling,       Mowing, Raking, Baling,  Harvesting, Hauling to   Sorting, Contaminant
 Nutrients and Farmer Payment $43/ton.  Hauling, Nutrients and   Forest Edge, Chipping    Removal, Tipping Fees
                                        Farmer Payment $42/ton.  $45/ton.                 Avoided $0-$10/ton.
Hauling to Secondary Storage,          Hauling to Secondary     Grinding, Hauling to     Grinding, Hauling to
 Secondary Storage, Hauling to Plant    Storage, Secondary       Plant $25/ton.           Plant $26/ton.
 $45/ton.                               Storage, Hauling to
                                        Plant $37/ton.
----------------------------------------------------------------------------------------------------------------
    Total $88/ton....................  Total $77/ton..........  Total $70/ton..........  Total Avg $31/ton.
----------------------------------------------------------------------------------------------------------------

    Weighting the cellulosic feedstock costs by their supply quantities
results in an average cellulosic feedstock cost of $71 per ton which we
used at the reference crude oil price of $53/bbl. We estimate that this
average cost increases to $76 per ton at the high crude oil price of
$92/bbl due to more expensive harvesting and transportation costs.
ii. Production Costs
    In this section, we discuss the cost to biochemically and
thermochemically convert cellulosic feedstocks into fuel ethanol. At a
DOE sponsored workshop in 2005, a DOE biochemical expert commented that
the challenges of converting cellulosic biomass to ethanol are very
closely linked to solving the problems associated with both the
hydrolysis and the fermentation of the carbohydrates in the feedstocks.
He then stated that the resistance of cellulosic feedstock to
bioprocessing will remain the central problem and will likely be the
limiting factor in creating an economy based on cellulosic ethanol
production.\444\
---------------------------------------------------------------------------

    \444\ Breaking the Biological Barriers to Cellulosic Ethanol: A
Joint Research Agenda, A Research Roadmap Resulting from the Biomass
to Biofuels Workshop Sponsored by the U.S. Department of Energy,
December 7-9, 2005, Rockville, Maryland; DOE/SC-0095, Publication
Date: June 2006
---------------------------------------------------------------------------

    Notwithstanding the fact that all cellulosic biomass is made up of
some combination of cellulose, hemicellulose, lignin, and trace amounts
of other organic and inorganic chemicals and minerals, there are
significant differences among the molecular structures of different
plants. For example, a corn stalk is relatively lighter, more porous,
and much more flexible than a tree branch of similar diameter. The tree
branch (in most cases) is harder or denser and less porous throughout
the stem and the

outside or bark is less permeable and flexible.
    These differences among the cellulosic feedstock plant structures,
e.g., density, rigidity, hardness, etc., suggest that different
conversion processes, namely biochemical and thermochemical may be
necessary to convert into ethanol as much of the available plant
material as possible. For example, if wood chips, e.g., poplar trees,
are to be treated biochemically, the chips must be reduced in size to
1-mm or less in order to increase the surface area for contact with
acid, enzymes, etc. Breaking up a 5-in stem to such small pieces would
consume a large amount of energy. On the other hand, processing corn
stover into cellulosic ethanol has a maximum size of up to 1.5 inches
(28 millimeters) in length because corn stover is so thin.\445\ By
comparison, the particle size requirement for a thermochemical process
is around 10-mm to 100-mm in diameter.\446\ Because of this, we believe
feedstocks such as corn stover, wheat and rice straw, and switchgrass
will likely be feedstocks for biochemical processes. Biochemical plants
will likely be constructed in those areas of the country where these
feedstocks are most abundant, e.g., the corn belt and upper Midwest. On
the other hand, thermochemical plants will likely be constructed in
those areas of the country where forest thinnings, forest fuel-removal
operations, lumber production, and paper mills are most predominant,
e.g., the South. Thermochemical or gasification units could be
constructed near starch or biochemical cellulosic plants in order to
take advantage of byproduct streams. We expect switchgrass (SG) will
preferentially be fed to biochemical units since it is similar to
straw, whereas short-rotation woody crops (SRWC) such as willows or
poplars will preferentially be fed to thermochemical units.
---------------------------------------------------------------------------

    \445\ A. Aden, M. Ruth, K. Ibsen, J. Jechura, K. Neeves, J.
Sheehan, and B. Wallace, National Renewable Energy Laboratory
(NREL); L. Montague, A. Slayton, and J. Lukas Harris Group, Seattle,
Washington, Ethanol Process Design and Economics Utilizing Co-
Current Dilute Acid Prehydrolysis and Enzymatic Hydrolysis for Corn
Stover; June 2002; NREL is a U.S. Department of Energy Laboratory
operated by Midwest Research Institute  Battelle
Bechtel; Contract No. DE-AC36-99-GO10337.
    \446\ Lin Wei, Graduate Research Assistant, Lester O. Pordesimo,
Assistant Professor, Willam D. Batchelor, Professor, Department of
Agricultural and Biological Engineering, Mississippi State
University, MS 39762, USA, Ethanol Production from Wood: Comparison
of Hydrolysis Fermentation and Gasification Biosynthesis, Paper
Number: 076036, Written for presentation at the 2007 ASABE Annual
International Meeting. Minneapolis Convention Center, Minneapolis,
MN, 17-20 June 2007.
---------------------------------------------------------------------------

    Biochemically, it is much more difficult to convert cellulosic
plant matter into ethanol than it is to convert the starch from corn
grain into ethanol. Corn starch consists of long polysaccharide chains
that are weakly attracted to each other, quite flexible, and tend to
curl up to form tiny particle-like bundles. This loose, flexible
structure permits water and water-borne hydrolyzing enzymes to easily
penetrate the polymer during the process stage known as hydrolysis.
Once hydrolyzed, the corn starch sugar residues are easily fermentable.
    The hydrolysis of cellulosic biomass is much more challenging.
Unlike starch, cellulosic plant matter is made up of three main
constituents: Cellulose, hemicellulose, lignin, and minor amounts of
various other organic and inorganic chemicals.
    Cellulose, the major constituent, is a polymer made up of only
[beta]-linked glucose monosaccharides. This molecular arrangement
allows intra-molecular hydrogen bonds to develop within each monomer
and inter-molecular hydrogen bonds to develop between adjacent polymers
to form tight, rigid, strong, mostly straight polymer bundles that are
insoluble in water and resistant to chemical attack. The net result of
the structural characteristics makes cellulose much more difficult to
hydrolyze than is hemicellulose.
    Hemicellulose contributes significantly to the total fermentable
sugars of the lignocellulosic biomass. Unlike cellulose, hemicellulose
is chemically heterogeneous and highly substituted. Compared to
cellulose, this branching renders it amorphous and relatively easy to
hydrolyze to its constituent sugars.\447\
---------------------------------------------------------------------------

    \447\ Hans P. Blaschek, Professor and Thaddeus C. Ezeji,
Research Assistant, Department of Food Science and Human Nutrition,
University of Illinois, Urbana-Champaign. Science of Alternative
Feedstocks.
---------------------------------------------------------------------------

    Lignin, the third principle component, is a complex, cross-linked
polymeric, high molecular weight substance derived principally from
coniferyl alcohol by extensive condensation polymerization. While
cellulose and hemicellulose contribute to the amount of fermentable
sugars for ethanol production, lignin is not so readily digestable, but
can be combusted to provide process energy in a biochemical plant or
used as feedstock to a thermochemical process.\448\
---------------------------------------------------------------------------

    \448\ Glossary of Biomass Terms, National Renewable Energy
Laboratory, Golden, CO. http://www.nrel.gov/biomass/glossary.html.
---------------------------------------------------------------------------

    Because of the complexities in digesting cellulosic biomass, the
residence time is longer to digest the cellulose and perform the
fermentation. Thus, the cellulosic plant capital costs are higher than
those of corn (starch) ethanol plants. However, because corn is a food
source with an intrinsic food value, corn ethanol's feedstock costs are
almost two times higher per ton (more than two times higher in the case
for cellulose from MSW) than the feedstocks of a cellulosic ethanol
plant. It is conceivable that depending on the cellulosic plant
technology which drives its capital and operating costs that cellulosic
ethanol plants' lower feedstock costs could offset its higher capital
costs resulting in lower production costs than corn-based ethanol.
    The National Renewable Energy Laboratory has been evaluating the
state of biochemical cellulosic plant technology over the past decade
or so, and it has identified principal areas for improvement. In 1999,
it released its first report on the likely design concept for an nth
generation biochemical cellulosic ethanol plant which projected the
state of technology in some future year after the improvements were
adopted. In 2002, NREL released a follow-up report which delved deeper
into biochemical plant design in areas that it had identified in the
1999 report as deserving for additional research. Again, the 2002
report estimated the ethanol production cost for an nth generation
biochemical cellulosic ethanol plant. These reports not only helped to
inform policy makers on the likely capability and cost for
biochemically converting cellulose to ethanol, but it helped to inform
biochemical technology researchers on the most likely technology
improvements that could be incorporated into these plant designs.
    To comply with the RFS 2 requirements, NREL assessed the likely
state of biochemical cellulosic plant technology over the years that
the RFS standard is being phased in. The specific years assessed by
NREL were 2010, 2015 and 2022. The year 2010 technology essentially
represents the status of today's biochemical cellulosic plants. The
year 2015 technology captures the expected near-term improvements
including the rapid improvements being made in enzyme technology. The
year 2022 technology captures the cost of mature biochemical cellulosic
plant technology. Table VIII.A.1-3 summarizes NREL's estimated and
projected production costs for biochemical cellulosic ethanol plant
technology in these three years

reflecting our average feedstock costs and adjusting the capital costs
to a 7 percent before tax rate of return.

               Table VIII.A.1-3--Biochemical Cellulosic Ethanol Production Costs Provided by NREL
----------------------------------------------------------------------------------------------------------------

----------------------------------------------------------------------------------------------------------------
Year technology...................            2010
                                              2015
                                              2022
Plant Size MMgal/yr...............              56
                                                69
                                                71
Capital Cost $MM..................             232
                                               220
                                               199
----------------------------------------------------------------------------------------------------------------
                                       $MM/yr       c/gal        $MM/yr       c/gal        $MM/yr       c/gal
----------------------------------------------------------------------------------------------------------------
Capital Cost 7% ROI before taxes..           25           46           24           35           22           31
Fixed Costs.......................            9           16            9           12            8           12
Feedstock Cost....................           55           99           55           79           55           77
Other raw matl. costs.............           17           30            4            5           16           16
Enzyme Cost.......................           18           32            7           10            5            8
Enzyme nutrients..................            8           14            2            3            2            2
Electricity.......................           -6          -10           -7           -9          -12          -16
Waste disposal....................            1            2            3            4            1            1
                                   -----------------------------------------------------------------------------
    Total Costs...................          127          229           96          139           84          131
----------------------------------------------------------------------------------------------------------------

    NREL's projected improvements in production costs over time are
based on improved reaction biochemistry. Before discussing the expected
improvements in the reaction biochemistry, we will discuss the reaction
pathway for cellulosic biochemical.
    There are two primary reaction steps in a biochemical cellulosic
ethanol plant. The first is hydrolysis. Hydrolysis breaks the
polysaccharides into their sugar residues. The pretreated slurry is fed
to a hydrolysis reactor; there may be multiple reactors, depending on
the desired production rate. Dilute sulfuric acid is used to hydrolyze,
primarily, the hemicellulose polysaccharides, xylan, mannan, arabinan,
and galactan, to produce the mixed sugars. Very little of the cellulose
polysaccharide, glucan, is hydrolyzed.
    The second is saccharification and co-fermentation. Using a
cellulase enzyme cocktail, saccharification of the cellulose to glucose
occurs first at an elevated temperature to take advantage of increased
enzyme activity, which reduces the quantity of required enzyme as well
as the reaction time. Following cellulose saccharification, both the
glucose and xylose sugars are co-fermented. Although xylan, the
hemicellulose polysaccharide, is more easily hydrolyzed than glucan
(cellulose polysaccharides), the xylose sugar is more difficult to
ferment than the glucose sugar. Different microbes as well as different
residence times and process conditions are required for each.
Therefore, it may be necessary to separate the glucose and xylose
monomers before fermentation.
    Because xylan can make up as much as 25% of plant matter it is
imperative that most of be available for ethanol production; the
economic viability of biochemically produced ethanol depends heavily
it. Good progress has been toward that end during the past few
years.\449\
---------------------------------------------------------------------------

    \449\ Purdue yeast makes ethanol from agricultural waste more
effectively, Purdue News, June 28, 2004 http://www.purdue.edu/UNS/html4ever/2004/040628.Ho.ethanol.html.
---------------------------------------------------------------------------

    Also during the past few years, researchers have been developing
ways to combine saccharification and fermentation into a single step
through the use of enzyme/microbe cocktails. DOE and the National
Renewable Energy Laboratory (NREL) have also supported research into
more efficient, less costly enzymes for SSF. With their support, a less
expensive, more efficient enzyme cocktail for cellulosic biomass
fermentation has been developed.\450\ Others have also reported some
success in co-fermenting glucose and xylose.\451\
---------------------------------------------------------------------------

    \450\ GENENCOR LAUNCHES FIRST EVER COMMERCIAL ENZYME PRODUCT FOR
CELLULOSIC ETHANOL, ROCHESTER, NY, World-Wire, October 22, 2007
Copyright[sscopy] 2007. All rights reserved. World-Wire is a
resource provided by Environment News Service. http://world-wire.com/news/0710220001.html.
    \451\ Ali Mohagheghi, Kent Evans, Yat-Chen Chou, and Min Zhang,
Biotechnology Division for Fuels and Chemicals, National Renewable
Energy Laboratory, Golden, CO 80401, Co-fermentation of Glucose,
Xylose, and Arabinose by Genomic DNA-Integrated Xylose/Arabinose
Fermenting Strain of Zymomonas mobilis AX101, Applied Biochemistry
and Biotechnology Vols. 98-100, 2002, Copyright[sscopy] 2002 by
Humana Press Inc., All rights of any nature whatsoever reserved.
---------------------------------------------------------------------------

    As the biochemical enzymatic pathway is streamlined using more
cost-effective enzymes, and as these enzymes can more comprehensively
saccarify and ferment the cellulose, the conversion fraction of the
cellulose to ethanol will increase and the conversion time will
decrease. An important benefit for these efficiency improvements is
that the number and size of reaction vessels decrease, leading to lower
capital costs and lower fixed operating costs. It is also estimated
that less nutrients would be needed to maintain the enzymes reactivity.
Because the production volume of ethanol will increase relative to the
quantity of feedstock, it lowers the operating costs per gallon of
ethanol. Between these various effects, the per-gallon costs for
producing cellulosic ethanol through the biochemical pathway are
expected to decrease dramatically. It is through these expected
improvements that NREL has estimated reduced production costs for
biochemical cellulosic ethanol plants.
    Thermochemical conversion is another reaction pathway which exists
for converting cellulose to ethanol. Thermochemical technology is based
on the heat and pressure-based gasification or pyrolysis of nearly any
biomass feedstock, including those we've highlighted as likely
biochemical feedstocks. The syngas is converted into mixed alcohols,
hydrocarbon fuels, chemicals, and power. A thermochemical unit can also
complement a biochemical processing plant to enhance the economics of
an integrated biorefinery by converting lignin-rich, non-fermentable
material left over from high-starch or cellulosic. NREL has not yet
estimated the cost of thermochemically converting cellulose to ethanol,
so we did not include a cost estimate using this potential conversion
pathway in our analysis and based our cost analysis entirely on the
biochemical route.\452\ However, one

report estimated that the costs are similar for converting cellulose to
ethanol either through either the biochemical or thermochemical routes.
Thus, we believe that our cellulosic ethanol costs are representative
of both technologies. In Section VIII.A.3 below, we discuss the costs
for a thermochemical route for producing diesel fuel, often referred to
as biomass-to-liquids (BTL) process.
---------------------------------------------------------------------------

    \452\ NREL has authored a thermochemical report: Phillips, S
Thermochemical Ethanol via Indirect Gasification and Mixed Alcohol
Synthesis of Lignocellulosic Biomass; April, 2007, which does
provide a cost estimate. However, this report only hypothesized how
a thermochemical ethanol plant could achieve production costs at $1
per gallon, and thus it could not be relied upon for any part of our
real-world program cost analysis.
---------------------------------------------------------------------------

c. Imported Sugarcane Ethanol
    We based our imported ethanol fuel costs on cost estimates of
sugarcane ethanol in Brazil. Generally, ethanol from sugarcane produced
in developing countries with warm climates is much cheaper to produce
than ethanol from grain or sugar beets. This is due to favorable
growing conditions, relatively low cost feedstock and energy inputs,
and other cost reductions gained from years of experience.
    As discussed in Chapter 4 of the DRIA, our literature search of
production costs for sugar cane ethanol in Brazil indicates that
production costs tend to range from as low as $0.57 per gallon of
ethanol to as high as $1.48 per gallon of ethanol. This large range for
estimating production costs is partly due to the significant variations
over time in exchange rates, costs of sugarcane and oil products, etc.
For example, earlier estimates may underestimate current crude and
natural gas costs which influence the cost of feedstock as well as
energy costs at the plant. Another possible difference in production
cost estimates is whether or not the estimates are referring to hydrous
or anhydrous ethanol. Costs for anhydrous ethanol (for blending with
gasoline) are typically several cents per gallon higher than hydrous
ethanol (for use in dedicated ethanol vehicles in Brazil).\453\ It is
not entirely clear from the majority of studies whether reported costs
are for hydrous or anhydrous ethanol. Yet another difference could be
the slate of products the plant is producing, for example, future
plants may be dedicated ethanol facilities while others involve the
production of both sugar and ethanol in the same facility. Due to
economies of scale, production costs are also typically smaller per
gallon for larger facilities.
---------------------------------------------------------------------------

    \453\ International Energy Agency (IEA), ``Biofuels for
Transport: An International Perspective,'' 2004.
---------------------------------------------------------------------------

    The study by OECD (2008) entitled ``Biofuels: Linking Support to
Performance'', appears to provide the most recent and detailed set of
assumptions and production costs. As such, our estimate of sugarcane
production costs primarily relies on the assumptions made for the
study, which are shown in Table VIII.A.1-4. The estimate assumes an
ethanol-dedicated mill and is based off an internal rate of return of
12%, a debt/equity ratio of 50% with an 8% interest rate and a selling
of surplus power at $57 per MWh.

                  Table VIII.A.1-4--Cost of Production in a Standard Ethanol Project in Brazil
----------------------------------------------------------------------------------------------------------------

----------------------------------------------------------------------------------------------------------------
Sugarcane Productivity......................  71.5 t/ha.
Sugarcane Consumption.......................  2 million tons/year.
Harvesting days.............................  167.
Ethanol productivity........................  85 liters/ton (22.5 gal/ton).
Ethanol production..........................  170 million liters/year (45 MGY).
Surplus power produced......................  40 kWh/ton sugarcane.
Investment cost in mill.....................  USD 97 million.
Investment cost for sugarcane production....  USD 36 million.
O & M (Operating & Maintenance) costs.......  $0.26/gal.
Sugarcane costs.............................  $0.64/gal.
Capital costs...............................  $0.49/gal.
                                             -------------------------------------------------------------------
    Total production costs..................  $1.40/gal.
----------------------------------------------------------------------------------------------------------------

    The estimate above is based on the costs of producing ethanol in
Brazil on average, today. However, we are interested in how the costs
of producing ethanol will change by the year 2022. Although various
cost estimates exist, analysis of the cost trends over time shows that
the cost of producing ethanol in Brazil has been steadily declining due
to efficiency improvements in cane production and ethanol conversion
processes. Between 1980 and 1998 (total span of 19 years) ethanol cost
declined by approximately 30.8%.\454\ This change in the cost of
production over time in Brazil is known as the ethanol cost ``Learning
Curve''.
---------------------------------------------------------------------------

    \454\ Goldemberg, J. as sited in Rothkopf, Garten, ``A Blueprint
for Green Energy in the Americas,'' 2006.
---------------------------------------------------------------------------

    The change in ethanol costs will depend on the likely productivity
gains and technological innovations that can be made in the future. As
the majority of learning may have already occurred, it is likely that
the decline in sugarcane ethanol costs will be less drastic as the
production process and cane practices have matured. This is in contrast
to younger technologies such as those used to produce cellulosic
biofuels which could likely have larger cost reductions over the same
period of time. In fact, there are few perspectives for substantial
efficiency gains with the sugarcane processing technology. Industrial
efficiency gains are already at about 85% and are expected to increase
to 90% in 2015.\455\ Most of the productivity growth is expected to
come from sugarcane production, where yields are expected to grow from
the current 70 tons/ha, to 96 tons/ha in 2025.\456\ Sugarcane quality
is also expected to improve, with sucrose content growing from 14.5% to
17.3% in 2025.\457\ All productivity gains together could allow the
increase in the production of ethanol from 6,000 liters/ha (at 85
liters/ton sugarcane in 2005) to 10,400 liters/ha (at 109 liters/ton
sugarcane) by 2025.\458\ Although not reflected here, there could also
be cost and efficiency improvements related to feedstock collection,
storage, and distribution.
---------------------------------------------------------------------------

    \455\ Unicamp ``A Expans[amacr]o do Proalcool como Programa de
Desenvolvimento Nacional''. Powerpoint presentation at Ethanol
Seminar in BNDES, 2006. As sited in OECD, ``Biofuels: Linking
Support to Performance,'' ITF Round Tables No. 138, March 2008.
    \456\ Ibid.
    \457\ Ibid.
    \458\ Ibid.
---------------------------------------------------------------------------

    Assuming that ethanol productivity increases to 100 liters/ton by
2015 and 109 liters/ton by 2025, sugarcane costs are be expected to
decrease to approximately $0.51/gal from $0.64/gal since less feedstock
is needed to produce the same volume of ethanol

using the estimates from Table VIII.A.1-4, above. We assumed a linear
decrease between data points for 2005, 2015, and 2025. Adding operating
($0.26/gal) and capital costs ($0.49/gal) from Table VIII.A.1-4, to a
sugarcane cost of $0.51/gal, total production costs are $1.26/gal in
2022.
    Brazil sugarcane producers are also expected to move from burned
cane manual harvesting to mechanical harvesting. As a result, large
amounts of straw are expected to be available. Costs of mechanical
harvesting are lower compared to manually harvesting, therefore, we
would expect costs for sugarcane to decline as greater sugarcane
producers move to mechanical harvesting. However, it is important to
note that diesel use increases with mechanical harvesting, and with
diesel fuel prices expected to increase in the future, costs may be
higher than expected. Therefore, we have not assumed any changes to
harvesting costs due to the switchover from manual harvesting to
mechanical harvesting.
    As more straw is expected to be collected at future sugarcane
ethanol facilities, there is greater potential for production of excess
electricity. The production costs estimates in the OECD study assumes
an excess of 40kWh per ton sugarcane, however, future sugarcane plants
are expected to produce 135 kWh per ton sugarcane.\459\ Assuming excess
electricity is sold for $57 per MWh, the production of 95 kWh per ton
would be equivalent to a credit of $0.22 per gallon ethanol produced.
We did not include this potential additional credit from greater use of
bagasse and straw in our estimates at this time. Our cost estimates do
include, however, the excess electricity produced from bagasse that is
currently used today (40 kWh/ton). We are asking for comment on whether
such a credit should be included in our production cost estimates.
---------------------------------------------------------------------------

    \459\ Macedo. I.C., ``Green house gases emissions in the
production and use of ethanol from sugarcane in Brazil: The 2005/
2006 Averages and a Prediction for 2020,'' Biomass and Bioenergy,
2008.
---------------------------------------------------------------------------

    It is also important to note that ethanol production costs can
increase if the costs of compliance with various sustainability
criteria are taken into account. For instance, using organic or green
cane production, adopting higher wages, etc. could increase production
costs for sugarcane ethanol.\460\ Such sustainability criteria could
also be applicable to other feedstocks, for example, those used in
corn- or soy-based biofuel production. If these measures are adopted in
the future, production costs will be higher than we have projected.
---------------------------------------------------------------------------

    \460\ Smeets E, Junginger M, Faaij A, Walter A, Dolzan P,
Turkenburg W, ``The sustainability of Brazilian ethanol--An
Assessment of the possibilities of certified production,'' Biomass
and Bioenergy, 2008.
---------------------------------------------------------------------------

    In addition to production costs, there are also logistical and port
costs. We used the report from AgraFNP to estimate such costs since it
was the only resource that included both logistical and port costs. The
total average logistical and port cost for sugarcane ethanol is $0.19/
gal and $0.09/gal, respectively, as shown in Table VIII.A.1-5.

   Table VIII.A.1-5--Imported Ethanol Cost at Port in Brazil (2006 $)
------------------------------------------------------------------------
                                            Logistical
                 Region                   costs U.S.  ($/ Port cost U.S.
                                               gal)           ($/gal)
------------------------------------------------------------------------
NE Sao Paulo............................           0.146           0.094
W Sao Paulo.............................           0.204           0.094
SE Sao Paulo............................           0.100           0.094
S Sao Paulo.............................           0.170           0.094
N Parana................................           0.232           0.094
S Goias.................................           0.328           0.094
E Mato Grosso do sul....................           0.322           0.094
Triangulo mineiro.......................           0.201           0.094
NE Cost.................................           0.026           0.058
Sao Francisco Valley....................           0.188           0.058
                                         -------------------------------
    Average.............................           0.192           0.087
------------------------------------------------------------------------

    Total fuel costs must also include the cost to ship ethanol from
Brazil to the U.S. In 2006, this cost was estimated to be approximately
$0.15 per gallon of ethanol.\461\ Costs were estimated as the
difference between the unit value cost of insurance and freight (CIF)
and the unit value customs price. The average cost to ship ethanol from
Caribbean countries (e.g., El Salvador, Jamaica, etc.) to the U.S. in
2006 was approximately $0.12 per gallon of ethanol. Although this may
seem to be an advantage for Caribbean countries, it should be noted
that there would be some additional cost for shipping ethanol from
Brazil to the Caribbean country. Therefore, we assume all costs for
shipping ethanol to be $0.15 per gallon regardless of the country
importing ethanol to the U.S.
---------------------------------------------------------------------------

    \461\ Official Statistics of the U.S. Department of Commerce,
USITC.
---------------------------------------------------------------------------

    Total imported ethanol fuel costs (at U.S. ports) prior to tariff
and tax for 2022 is shown in Table VIII.A.1-6, at $1.69/gallon. Direct
Brazilian imports are also subject to an additional $0.54 per gallon
tariff, whereas those imports arriving in the U.S. from Caribbean Basin
Initiative (CBI) countries are exempt from the tariff. In addition, all
imports are given an ad valorem tax of 2.5% for undenatured ethanol and
a 1.9% tax for denatured ethanol. We assumed an ad valorem tax of 2.5%
for all ethanol. Thus, including tariffs and ad valorem taxes, the
average cost of imported ethanol is shown in Table VIII.A.1-7 in the
``Brazil Direct w/Tax & Tariff'' and ``CBI w/Tax'' columns for 2022.

                                   Table VIII.A.1-6--Average Imported Ethanol Costs Prior to Tariff and Taxes in 2022
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                Transport cost
           Sugarcane production cost  ($/gal)             Operating cost   Capital cost     Logistical    Port cost  ($/   from port to   Total cost  ($/
                                                              ($/gal)         ($/gal)      cost ($/gal)        gal)        U.S.  ($/gal)       gal)
--------------------------------------------------------------------------------------------------------------------------------------------------------
0.51....................................................            0.26            0.49            0.19            0.09            0.15            1.69
--------------------------------------------------------------------------------------------------------------------------------------------------------

                                                Table VIII.A.1-7--Average Imported Ethanol Costs in 2022
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                Brazil direct w/tax & tariff
                     Brazil direct ($/gal)                                 ($/gal)                     CBI ($/gal)                CBI w/tax ($/gal)
--------------------------------------------------------------------------------------------------------------------------------------------------------
1.69..........................................................                          2.27                          1.69                          1.73
--------------------------------------------------------------------------------------------------------------------------------------------------------

2. Biodiesel and Renewable Diesel Production Costs
    Biodiesel and renewable diesel production costs are primarily a
function of the feedstock cost, and to a much lesser extent, the
capital and other operating costs of the facility.
a. Biodiesel
    Biodiesel production costs for this rule were estimated using two
versions of a biodiesel production facility model obtained from USDA,
one using degummed soy oil as a feedstock and the other using yellow
grease. The biodiesel from yellow grease model includes the acid pre-
treatment steps required to utilize feedstocks with high free fatty
acid content.
    This production model simulates a 10 million gallon per year plant
operating a continuous flow transesterification process. USDA used the
SuperPro Designer chemical process simulation software to estimate heat
and material flowrates and equipment sizing. Outputs from this software
were then combined in a spreadsheet with equipment, energy, labor, and
chemical costs to generate a final estimate of production cost. The
model is described in a 2006 publication in Bioresource Technology,
peer-reviewed scientific journal.\462\ Table VIII.A.2-1 shows the
production cost allocation for the soy oil-to-biodiesel facility as
modeled in the 2022 policy case.
---------------------------------------------------------------------------

    \462\ Haas, M.J., A process model to estimate biodiesel
production costs, Bioresource Technology 97 (2006) 671-678.

 Table VIII.A.2-1--Production Cost Allocation for Soy Biodiesel Derived
                           From This Analysis
------------------------------------------------------------------------
                                                Contribution to cost
               Cost category                          (percent)
------------------------------------------------------------------------
Soy Oil...................................  87
Other Materials \a\.......................  5
Capital & Facility........................  4
Labor.....................................  3
Utilities.................................  1
------------------------------------------------------------------------
\a\ Includes acids, bases, methanol, catalyst.

    Soy oil costs were generated by the FASOM agricultural model
(described in more detail in Section IX.A). Historically, the majority
of biodiesel production in the U.S. has used soy oil, a relatively
high-value feedstock, but a growing fraction of biodiesel is being made
from yellow grease, the name given to reclaimed or highly-processed oil
(including corn oil extracted from distillers' grains) that is not
suitable for use in food products. This material typically sells for
about 70% of the value of virgin soy oil. Conversion of yellow grease
into biodiesel requires an additional acid pretreatment step, and
therefore the processing costs are higher than for virgin soy oil
(about $0.40/gal at equal feedstock costs). Table VIII.A.2-2 shows the
feedstock and biodiesel costs used in our cost analysis.

 Table VIII.A.2-2--Biodiesel Feedstock and Production Costs Used in This
                            Analysis (2006$)
------------------------------------------------------------------------
                                                           Yellow grease
                                              Soy oil           \a\
------------------------------------------------------------------------
Reference Case..........................  ..............  ..............
    Feedstock $/lb......................           $0.23           $0.16
    Bio- diesel $/gal...................           $2.11           $1.99
Policy Case.............................  ..............  ..............
    Feedstock $/lb......................           $0.32           $0.22
    Bio- diesel $/gal...................           $2.75           $2.47
------------------------------------------------------------------------
\a\ Includes corn oil extracted from thin stillage/DGS, rendered fats,
  recycled greases, etc.

    A co-product of transesterification is crude glycerin. With the
upswing in worldwide biodiesel production in recent years, its market
price is relatively low: In our modeling we assume its value to be
$0.03/lb. As a result, the sale of this material as a co-product only
reduces biodiesel production cost by about $0.02/gal.
b. Renewable Diesel
    Renewable diesel is produced in one of three general
configurations: (1) A new standalone unit located within a refinery,
(2) co-processing in an existing refinery diesel hydrotreater, or (3) a
standalone unit at a rendering plant or another location outside of a
refinery. We expect that the largest fraction of the capacity for
refinery installation will be produced using the co-processing method,
as the production costs are lower than those for a new standalone unit
in a refinery. Thus, we speculate that about 50% of renewable diesel
being produced by the refinery co-processing route, 17% from a new
stand alone unit at a refinery and 33% at rendering plants or as a new
site installation. Recent business partnership and construction
announcements related to renewable diesel production (such as involving
ConocoPhillips facilities in Texas, and

Tyson-Syntroleum facilities in Louisiana) generally support such a
split.
    We derived our production cost estimates from documents made
available publicly by UOP, Inc., to make renewable diesel in a grass
roots standalone production process inside a refinery.\463\ The process
has a pre-treating unit that removes alkali and acidic producing
compounds from feed streams, which removes the catalyst poisons. We
also used the UOP engineering estimate to derive costs for co-
processing renewable diesel in an existing refinery's diesel
hydrotreater. For this, we assumed that refiners will: (1) revamp their
existing diesel hydrotreater to add capacity and (2) add a pre-treater
to remove feedstock contaminants. Lastly, we derived costs for a
standalone unit at a location outside a refinery at a rendering plant
other facility, using a capital cost estimate from Syntroleum
Corp.\464\
---------------------------------------------------------------------------

    \463\ A New Development in Renewable Fuels: Green Diesel, AM-07-
10 Annual Meeting NPRA, March 18-20, 2007.
    \464\ From Securities and Exchange Commission Form 8-K for
Syntroleum Corp, June 25th 07.
---------------------------------------------------------------------------

    The extent of the depolymerization and hydrotreating reactions
depend on the process conditions, as some of the carbon backbone of the
oils can be cracked to naphtha and lighter products with higher
severity. For our analysis, we assume no such cracking and predict
yields resulting in ninety-nine percent diesel fuel with the balance as
propane (which could also be considered renewable fuel) and water. We
assume that all of the renewable diesel production will take place in
PADD 2, as feedstock shipping costs are reduced since most of the
sources for feedstock supply are located primarily in the Midwest.
Average processing cost per gallon (in addition to the feedstock) is 41
cents for making renewable diesel from yellow grease/animal fats, based
on our cost methodology.
    As with biodiesel, renewable diesel cost estimates were based on
soy oil feedstock prices taken from the FASOM modeling work, given in
Section IX.A. Our cost estimates for renewable diesel were focused on
use of yellow grease as a feedstock, given the project announcements
mentioned above, as well as the relative insensitivity of the
hydrotreating process to fatty acids and other contaminates relative to
the transesterification process. Oil from corn fractionation, yellow
grease, and animal fat prices were assumed to be 70% the price of soy
oil (consistent with historical market trends). For our 2022 policy
case, with a yellow grease price of $0.23/lb, the production cost is
$2.47/gal for biodiesel and $2.10/gal for renewable diesel (2006$).
Table VIII.A.2-3 shows the projected volume contribution to the
biodiesel and renewable diesel total volume, their production costs,
and the weighted average production cost used for biodiesel and
renewable diesel in this proposal. These results assume feedstock
prices are plant-gate and do not include any product transportation
costs. Note also that the volumes here include co-processed renewable
diesel which does not qualify as biomass-based diesel but which may be
counted as advanced biofuel.

 Table VIII.A.2-3--Projected Costs and Volume Contribution for Biodiesel
                          and Renewable Diesel
                [Policy case, 2006$ and million gallons]
------------------------------------------------------------------------
                  Fuel                         Cost           Volume
------------------------------------------------------------------------
Biodiesel from virgin plant oil.........            2.75             660
Biodiesel from oil extraction at ethanol            2.47             150
 plants, yellow grease..................
Renewable diesel from fat, oil, yellow              2.10             375
 grease.................................
Weighted average cost & total volume....            2.51           1,185
------------------------------------------------------------------------

    Although the per-gallon cost for making renewable diesel from
yellow grease is significantly less than using the biodiesel process,
there are a number of reasons why we believe the latter will still be
used to process some yellow grease (and most of the virgin oil
feedstocks). The primary reason is that there is already sufficient
biodiesel capacity existing or under construction to cover the
projected volumes. Secondly, the per-gallon capital cost to build new
hydroprocessing capacity for renewable diesel is expected to be
significantly higher than for the biodiesel process. The low per-gallon
renewable diesel cost given here is based on the majority of the
production being done by co-processing at existing petroleum
refineries.
3. BTL Diesel Production Costs
    Biofuels-to-Liquids (BTL) processes, which are also thermochemical
processes, convert biomass to liquid fuels via a syngas route. The
primary product produced by this process is diesel fuel.
    There are many steps involved in a BTL process which makes this a
capital-intensive process. The first step, like all the cellulosic
processes, requires that the feedstocks be processed to be dried and
ground to a fine size. The second step is the syngas step, which
thermochemically reacts the biomass to carbon monoxide and hydrogen.
Since carbon monoxide production exceeds the stoichiometric ideal
fraction of the mixture, a water shift reaction must be carried out to
increase the relative balance of hydrogen. The syngas products must
then be cleaned to facilitate the following Fischer-Tropsch reaction.
The Fischer-Tropsch reaction reacts the syngas to a range of
hydrocarbon compounds--a type of synthetic crude oil. This hydrocarbon
mixture is then hydrocracked to maximize the production of high cetane
diesel fuel, although some low octane naphtha is also produced. The
many steps of the BTL process contribute to its high capital cost.
    One estimate made by Iowa State University estimates the total cost
for a cellulosic Fischer-Tropsch plant that produces 35 million gallons
per year diesel fuel at $2.37 per gallon. This cost estimated the
capital costs to be $341 million. These costs were estimated in the
year 2002. We adjusted the operating and capital costs to a 2006
investment environment and to 2006 dollars based the costs on our
average $71/dry ton feedstock costs which increases the total cost to
$2.85 per gallon of diesel fuel.
    Initially, the estimated cost of $2.85 per gallon seems high
relative to the projected cost for a year 2015 biochemical cellulosic
plant, which is $1.39 per gallon of ethanol in 2006 dollars. However,
ethanol provides about half the energy content as Fischer-Tropsch
diesel fuel. So if we double the biochemical cellulosic ethanol costs
to $2.78 per diesel fuel-equivalent gallon,

the estimated costs are very consistent between the two. The cellulosic
biofuel tax subsidy favors the biochemical ethanol plant, though,
because it is a per-gallon subsidy regardless of the energy content,
and it therefore offsets twice as much cost as the BTL plant producing
diesel fuel. There is one more issue worth considering and that is the
relative price of diesel fuel to that of E85. Recently diesel fuel has
been priced much higher than gasoline, and if this trend continues to
hold, it would provide a better market for selling the BTL diesel fuel
than for selling biochemical ethanol into the E85 market, which we
believe will be a challenging pricing market for refiners.
4. Catalytic Depolymerization Costs
    A new technology was developed by Cello Energy which catalytically
depolymerizes cellulose, and then repolymerizes it to produce synthetic
hydrocarbon fuels such as gasoline, jet fuel and diesel fuel The
company claims that they can produce diesel fuel for about $0.40 per
gallon by processing hay, wood chips and used tires. Based on our
projections of future cellulosic feedstock costs, their production
costs for using only cellulosic feedstocks and assuming the cellulosic
feedstock costs developed above would likely be about $1.00 per gallon.
In late 2008 the company started up a 20 million gallon per year
commercial demonstration plant as a first step towards commercializing
their process. We discuss this technology and its costs in more detail
in the DRIA.

B. Distribution Costs

    Our analysis of the costs associated with distributing the volumes
of renewable fuels that we project will be used under RFS2 focuses on:
(1) The capital cost of making the necessary upgrades to the fuel
distribution infrastructure system directly related to handling these
fuels, and (2) the ongoing additional freight costs associated with
shipping renewable fuels to the point where they are blended with
petroleum-based fuels.\465\ The following sections outline our
estimates of the distribution costs for the additional volumes of
ethanol, FAME biodiesel, and renewable diesel fuel that would be used
in response to the RFS2 standards.\466\
---------------------------------------------------------------------------

    \465\ The anticipated ways that the renewable fuels projected to
be used in response to the EISA will be distributed is discussed in
Section V.C. of today's preamble.
    \466\ Please refer to Section 4.2 of the DRIA for additional
discussion of how these estimates were derived.
---------------------------------------------------------------------------

    A discussion of the capability of the transportation system to
accommodate the volumes of renewable fuels projected to be used under
RFS2 is contained in Section V.C. of today's preamble. There will be
ancillary costs associated with upgrading the basic rail, marine, and
road transportation nets to handle the increase in freight volume due
to the RFS2. We have not sought to quantify these ancillary costs
because (1) the growth in freight traffic that is attributable to RFS2
represents a minimal fraction of the total anticipated increase in
freight tonnage (approximately 2% by 2022, see Section V.C.4.), and (2)
we do not believe there is an adequate way to estimate such non-direct
costs. We will continue to evaluate issues associated with the
expansion of the basic transportation net to accommodate the volumes of
renewable fuels projected under RFS2 and will update our analysis for
the final rule based on our findings.
1. Ethanol Distribution Costs
a. Capital Costs To Upgrade the Distribution System for Increased
Ethanol Volume
    Table VIII.B.1-1 contains our estimates of the infrastructure
changes and associated capital costs to support the use of the
additional 21 BGY of ethanol that we project will be used under RFS2 by
2022 relative to the AEO 2007 forecast of 13 BGY.\467\ The total
estimated capital costs are estimated at $12.1 billion which when
amortized equates to approximately 6.9 cents per gallon of this
additional ethanol volume.\468\
---------------------------------------------------------------------------

    \467\ See Section V.C. of today's preamble for discussion of the
upgrades we project will be needed to the distribution system to
handle the increase in ethanol volumes under EISA.
    \468\ These capital costs will be incurred incrementally through
2022 as ethanol volumes increase. Capital costs for tank trucks were
amortized over 10 years with a 7% cost of capital. Other capital
costs were amortized over 15 years with a 7% return on capital.

 Table VIII.B.1-1--Estimated Ethanol Distribution Infrastructure Capital
                                Costs \a\
------------------------------------------------------------------------
                                                              Million $
------------------------------------------------------------------------
Fixed Facilities:                                            ...........
Marine Import Facilities...................................           49
Ethanol Receipt Rail Hub Terminals:
  Rail Car Handling & Misc. Equipment......................        1,264
  Ethanol Storage Tanks....................................          354
Petroleum Terminals:                                         ...........
  Rail Receipt Facilities..................................        2,482
  Ethanol Storage Tanks....................................        1,611
  Ethanol Blending & Misc. Equipment.......................          545
Retail.....................................................        2,957
Mobile Facilities:
Rail Cars..................................................        2,938
Barges.....................................................          183
Tank Trucks................................................          223
                                                            ------------
  Total Capital Costs......................................       12,066
------------------------------------------------------------------------
\a\ Relative to a 13.18 BGY 2022 reference case.

    We request comment on our basis for these estimates as detailed in
chapter 4.2 of the DRIA. Comment is specifically requested on the
extent to which ethanol rail receipt would be accommodated within
petroleum terminals rather than being cited at rail hub terminals (to
be further shipped by tank truck to petroleum terminals). Our current
analysis estimated that half of the new ethanol rail receipt capability
needed to support the use of the projected ethanol volumes under the
EISA would be installed at petroleum terminals, and half would be
installed at rail terminals. A recently completed study by ORNL
estimated that all new ethanol rail receipt capability would be
installed at existing rail terminals given the limited ability to
install such capability at petroleum terminals.\469\
---------------------------------------------------------------------------

    \469\ ``Analysis of Fuel Ethanol Transportation Activity and
Potential Distribution Constraints'', prepared for EPA by Oak Ridge
National Laboratory, March 2009.
---------------------------------------------------------------------------

b. Ethanol Freight Costs
    We estimate that ethanol freight costs would be 11.3 cents per
gallon on a national average basis. Ethanol freight costs are based on
those we derived for the Renewable Fuel Standard final rule updated to
reflect the projected ethanol use patterns and effect on distribution
patterns of increased imports and more dispersed domestic ethanol
production locations.\470\ Specifically, we estimated freight costs by
assessing the location of production and import volumes, where ethanol
would be used, and the modes and distances for transportation between
production and use.\471\ We intend to update our estimate of ethanol
freight costs for the final rule based on a recently completed analysis
conducted for EPA by Oak Ridge National Laboratory (ORNL). The ORNL

analysis contains more detailed projections of which transportation
modes and combination of modes (e.g., unit train to barge) are best
suited for delivery of ethanol to specific markets considering ethanol
source and end use locations, the current configuration and projected
evolution of the distribution system, and cost considerations for the
different transportation modes.
---------------------------------------------------------------------------

    \470\ Please refer to Section 4.2 of the DRIA for additional
discussion of ethanol freight costs.
    \471\ Our projections regarding the location of ethanol
production/import volumes and where ethanol would be used is
discussed in Sections V.B. and V.D. of today's preamble
respectively.
---------------------------------------------------------------------------

2. Biodiesel and Renewable Diesel Distribution Costs
a. Capital Costs To Upgrade the Distribution System for Increased FAME
Biodiesel Volume
    Table VIII.B.2-1 contains our estimates of the infrastructure
changes and associated capital costs to support the use of the
additional 430 MGY of FAME biodiesel that we project will be used under
RFS2 by 2022.\472\ The total capital costs are estimated at $381
million which equates to approximately 9.8 cents per gallon of
additional biodiesel volume.\473\
---------------------------------------------------------------------------

    \472\ We project that by 2022 380 MGY of FAME biodiesel would be
used absent the requirements under EISA and that a total of 810 MGY
of FAME biodiesel would be used under the EISA.
    \473\ These capital costs will be incurred incrementally through
2022 as FAME biodiesel volumes increase. Capital costs for tank
trucks were amortized over 10 years with a 7% cost of capital. Other
capital costs were amortized over 15 years with a 7% return on
capital.

 Table VIII.B.2-1--Estimated FAME Biodiesel Distribution Infrastructure
                            Capital Costs \a\
------------------------------------------------------------------------
                                                              Million $
------------------------------------------------------------------------
Fixed Facilities:
Petroleum Terminals:
  Storage Tanks............................................          129
  Biodiesel Blending & Misc. Equipment.....................          192
Mobile Facilities:
Rail Cars..................................................           35
Barges.....................................................           17
Tank Trucks................................................            8
                                                            ------------
  Total Capital Costs......................................          381
------------------------------------------------------------------------
\a\ Relative to a 380 MGY 2022 reference case.

b. Biodiesel Freight Costs
    We estimate that biodiesel freight costs would be 9.3 cents per
gallons on a national average basis. Priority regional demand for
biodiesel was estimated by reviewing State biodiesel mandates/
incentives and assuming a demand for 2% biodiesel in most heating oil
used in the Northeast by 2022. This priority regional demand was
assumed to be filled first from local plants that could ship
economically by tank truck. The remaining fraction of priority regional
demand was assumed to be satisfied from more distant plants via
shipment by manifest rail car. Overall shipping distances were
minimized in selecting which plants would satisfy the demand for a
given area. The amount of biodiesel that we project would be consumed
which would not be directed to priority demand was assumed to be used
within trucking distance of the production plant to the extent possible
while maintaining biodiesel blend concentrations below 5%. The
remaining volume needed to match our estimated production volume was
assumed to be shipped via manifest rail car to the nearest areas where
diesel fuel use was not already saturated with biodiesel to the 5%
level.
c. Renewable Diesel Distribution System Capital and Freight Costs
    We project that there would be no additional costs associated with
distributing the 250 MGY of renewable diesel fuel that we estimate will
be produced at refineries by 2022.\474\ This renewable diesel fuel will
be blended into finished diesel fuel at the refinery and be distributed
to petroleum terminals in the same way 100% petroleum-based distillate
fuel is distributed. This is based on our belief that renewable diesel
will be confirmed to be sufficiently similar to petroleum-based diesel
with respect to distribution system compatibility.
---------------------------------------------------------------------------

    \474\ This includes co-processed renewable diesel fuel as well
as renewable diesel fuel produced in separate processing units
located at refineries.
---------------------------------------------------------------------------

    We project that 125 MGY of renewable diesel will be produced at
stand-alone facilities that are not connected to a refinery or
petroleum terminal. We estimate that such renewable diesel will be
trucked to nearby petroleum terminals at a cost of 5 cents per gallon.
We estimate that 8 additional tank trucks would be needed to carry this
renewable diesel to terminals at a total cost of approximately $1.3
million dollars. Amortized over 10 years with a 7% cost of capital, the
total capital costs equate to approximately 0.2 cents per gallon of
renewable diesel fuel produced at stand-alone facilities. We estimate
that no further capital costs would need to be incurred to handle
renewable diesel fuel. This is based on the assumption that renewable
diesel delivered to terminals from stand-alone production facilities
can be mixed directly into storage tanks that contain petroleum-based
diesel fuel or can be stored separately in existing storage tanks for
later blending with petroleum-based diesel fuel. We further estimate
the terminals that receive renewable diesel will not need to install
additional facilities to allow the receipt by tank truck.

C. Reduced Refining Industry Costs

    As renewable and alternative fuel use increases, the volume of
petroleum-based products, such as gasoline and diesel fuel, would
decrease. This reduction in finished refinery petroleum products is
associated with reduced refinery industry costs. The reduced costs
would essentially be the volume of fuel displaced multiplied by the
cost for producing the fuel. There is also a reduction in capital costs
which is important because by not investing in new refinery capital,
more resources are freed up to build plants that produce renewable and
alternative fuels.
    Although we conducted refinery modeling for estimating the cost of
blending ethanol, we did not rely on the refinery model results for
estimating the volume of displaced petroleum. Instead we conducted an
energy balance around the increased use of renewable fuels, estimating
the energy-equivalent volume of gasoline or diesel fuel displaced. This
allowed us to more easily apply our best estimates for how much of the
petroleum would displace imports of finished products versus crude oil
for our energy security analysis which is discussed in Section IX.B of
this preamble.
    As part of this analysis we accounted for the change in petroleum
demanded by upstream processes related to additional production of the
renewable fuels as well as reduced production of petroleum fuels. For
example, growing corn used for ethanol production requires the use of
diesel fuel in tractors, which reduces the volume of petroleum
displaced by the ethanol. Similarly, the refining of crude oil uses by-
product hydrocarbons for heating within the refinery, therefore the
overall effect of reduced gasoline and diesel fuel consumption is
actually greater because of the additional upstream effect. We used the
lifecycle petroleum demand estimates provided for in GREET model to
account for the upstream consumption of petroleum for each of the
renewable and alternative fuels, as well as for gasoline and diesel
fuel. Although there may be some renewable fuel used for upstream
energy, we assumed that this entire volume is petroleum because the
volume of renewable and alternative fuels is fixed as described in
Section V above.
    For this proposed rule, we assumed that a portion of the gasoline
displaced

by ethanol is imported, while the other portion is produced from
domestic refineries. The assumption we made is that one half of the
ethanol market in the Northeast, which comprises about half of the
nation's gasoline demand, would displace imported gasoline or gasoline
blend stocks. Therefore, to derive the portion of the new renewable
fuels which would offset imports (and not impact domestic refinery
production), we multiplied the total volume of petroleum fuel displaced
by 50% to represent that portion of the ethanol which would be used in
the Northeast, and 50% again to only account for that which would
offset imports. The rest of the ethanol, including half of the ethanol
presumed to be used in the Northeast, is presumed to offset domestic
gasoline production. In the case of biodiesel and renewable diesel, all
of it is presumed to offset domestic diesel fuel production. For
ethanol, biodiesel and renewable diesel, the amount of petroleum fuel
displaced is estimated based on the relative energy contents of the
renewable fuels to the fuels which they are displacing. The savings due
to lower imported gasoline and diesel fuel is accounted for in the
energy security analysis contained in Section IX.B.
    For estimating the U.S. refinery industry cost reductions, we
multiplied the estimated volume of domestic gasoline and diesel fuel
displaced by the wholesale price for each of these fuels, which are
$157 per gallon for gasoline, and $161 per gallon for diesel fuel at
$53/bbl crude oil, and $267 per gallon for gasoline, and $335 per
gallon for diesel fuel at $92/bbl crude oil. For the volume of
petroleum displaced upstream, we valued it using the wholesale diesel
fuel price. Table VIII.C.1-1 shows the net volumetric impact on the
petroleum portion of gasoline and diesel fuel demand, as well as the
reduced refining industry costs for 2022.

               Table VIII.C.1-1--Reduced U.S. Refinery Industry Costs for the RFS2 Program in 2022
----------------------------------------------------------------------------------------------------------------

----------------------------------------------------------------------------------------------------------------
                                                            Total volume     Cost savings at    Cost savings at
                                                             displaced      $53/bbl crude oil  $92/bbl crude oil
                                                         (billion gallons)        price              price
                                                                            (billion dollars)  (billion dollars)
----------------------------------------------------------------------------------------------------------------
Upstream.........................  Petroleum...........                0.8              -$1.3              -$2.7
End Use..........................  Gasoline............               10.4               16.3               27.7
                                   Diesel Fuel.........                0.6                0.9                1.9
                                                        --------------------------------------------------------
                                      Total............  .................               15.9               26.9
----------------------------------------------------------------------------------------------------------------

D. Total Estimated Cost Impacts

    The previous sections of this chapter presented estimates of the
cost of producing and distributing corn-based and cellulosic-based
ethanol, imported ethanol, biodiesel, and renewable diesel. In this
section, we briefly summarize the methodology used and the results of
our analysis to estimate the cost and other implications for increased
use of renewable fuels to displace gasoline and diesel fuel. An
important aspect of this analysis is refinery modeling which primarily
was used to estimate the costs of blending ethanol into gasoline, as
well as the overall refinery industry impacts of the proposed fuel
program. The refinery modeling was conducted by Jacobs Consultancy
under subcontract to Southwest Research Institute. A detailed
discussion of how the renewable fuel volumes affect refinery gasoline
production volumes and cost is contained in Chapter 4 of the DRIA.
1. Refinery Modeling Methodology
    The refinery modeling was conducted in three distinct steps. The
first step involved the establishment of a 2004 base case which
calibrated the refinery model against 2004 volumes, gasoline quality,
and refinery capital in place. The EPA and ASTM fuel quality
constraints in effect by 2004 are imposed on the products.
    For the second step, we established a 2022 future year reference
case which represents a business-as-usual case as estimated by the
2007Annual Energy Outlook (AEO). The refinery model assumed that the
price of crude oil would average about $51 per barrel, though the
results were later adjusted to reflect $53 and $92 per barrel crude oil
prices. We also modeled the implementation of several new environmental
programs that will have required changes in fuel quality by 2022,
including the 30 part per million (ppm) average gasoline sulfur
standard, the 15 ppm cap standards on highway and nonroad diesel fuel,
the Mobile Source Air Toxics (MSAT) 0.62 volume percent benzene
standard. We modeled the implementation of EPAct of 2005, which by
rescinding the reformulated gasoline oxygenate standard, resulted in
the discontinued use of MTBE, and a large increase in the amount of
ethanol blended into reformulated gasoline. We also modeled the EISA
Energy Bill corporate average fuel economy (caf[eacute]) standards in
the reference case because it will be phasing-in, and affect the phase-
in of the RFS2. We modeled 13.2 billion gallons of ethanol in the
gasoline pool and 0.4 billion gallons of biodiesel in the diesel pool
for 2022, which is the ``business-as-usual'' volume as projected by AEO
2007.
    The third step, or the control case, involved the modeling of the
34 billion gallons of ethanol and 1 billion gallons of biodiesel and
renewable diesel in 2022 to comply with EISA when the proposed
renewable fuels program is fully phased-in. All the other environmental
and ASTM fuel quality constraints are assumed to apply to the control
case as well to solely model the impact of the RFS2 standards.
    The price of ethanol and E85 used in the refinery modeling is a
critical determinant of the overall economics of using ethanol. Ethanol
was priced initially based on the historical average price spread
between regular grade conventional gasoline and ethanol, but then
adjusted post-modeling to reflect the projected production cost for
both corn and cellulosic-based ethanol. The refinery modeling assumed
that all ethanol added to gasoline for E10 is match-blended for octane
by refiners in the reference and control cases, although splash
blending of ethanol was assumed to be appropriate for the conventional
gasoline for the base case based on EPA gasoline data. For the control
case, E85 was assumed to be priced much lower than gasoline to reflect
its lower energy content, longer refueling time and lower availability
(see Chapter 4 of the DRIA for a detailed discussion for how we
projected E85 prices). E85 is assumed to be blended

with gasoline blendstock designed for blending with E10, and a small
amount of butane to bring the RVP of E85 up to that of gasoline. Thus,
unlike current practices today where E85 is blended at 85% in the
summer and E70 in the winter, we assumed that E85 is blended at 85%
year-round. E85 use in any one market is limited to levels which we
estimated would reflect the ability of FFV vehicles in the area to
consume the E85 volume.
    The refinery model was provided some flexibility and also was
constrained with respect to the applicable gasoline volatility
standards for blending up E10. The refinery model allowed conventional
gasoline and most low RVP control programs to increase by 1.0 pounds
per square inch (psi) in Reid Vapor Pressure (RVP) waiver during the
summer. However, wintertime conventional gasoline was assumed to comply
with the wintertime ASTM RVP and Volume/Liquid (V/L) standards.
    The costs for producing, distributing and using biodiesel and
renewable diesel are accounted for outside the refinery modeling. Their
production and distribution costs are estimated first, compared to the
costs of producing diesel fuel, and then are added to the costs
estimated by the refinery cost model for blending the ethanol.
    The costs were adjusted to reflect the crude oil prices estimated
by EIA in its Annual Energy Outlook (AEO). The AEO 2008 reference case
projects that crude oil will be $53 per barrel in 2022, so we adjusted
our costs slightly to reflect that slightly higher crude oil price. We
also evaluated a higher crude oil price case. The high crude oil case
price modeled for the AEO projects that crude oil will be $92 per
barrel in 2022, so we adjusted our cost model to also estimate the
program costs based on this higher crude oil cost. We estimated the
program costs based on these different crude oil prices by adjusting
the gasoline and diesel fuel prices to reflect the cost of crude oil.
The crude oil costs also have a secondary impact on the production
costs of various renewable and alternative fuels (e.g., petroleum used
to grow corn which also has been reflected in our cost analysis).
2. Overall Impact on Fuel Cost
    Based on the refinery modeling conducted for today's proposed rule,
we calculated the costs for consuming the additional 22 billion gallons
of renewable fuels in 2022 relative to the reference case. The costs
are reported separately for blending ethanol into gasoline as E10 and
E85, and for blending biodiesel and renewable diesel with diesel fuel.
The costs are expressed two different ways. First, we express the full
``engineering'' cost of the program without the ethanol consumption tax
subsidies in which the costs are based on the total accumulated costs
of each of the fuels changes, at both reference case and high crude oil
prices. Second, we express the costs subtracting the ethanol and
biodiesel and renewable diesel consumption tax subsidies since some or
perhaps most of the cost of the tax subsidy may not be reflected in the
price consumers pay at retail. In all cases, the capital costs are
amortized at seven percent return on investment (ROI) before taxes, and
based on 2006 dollars.
a. Costs Without Federal Tax Subsidies
    Table VIII.D.2-1 summarizes the costs without ethanol tax subsidies
for each of the two control cases, including the cost for each aspect
of the fuels changes, and the aggregated total and the per-gallon costs
for all the fuel changes.\475\ This estimate of costs reflects the
changes in gasoline that are occurring with the expanded use of
renewable and alternative fuels. These costs include the labor, utility
and other operating costs, fixed costs and the capital costs for all
the fuel changes expected. The per-gallon costs are derived by dividing
the total costs over all U.S. gasoline and diesel fuel projected to be
consumed in 2022. Note that these costs are incremental only to the
reference case volumes of renewable fuels (costing out about 20 billion
gallons of new renewable fuels) and does not reflect the costs of the
renewable fuel volumes in the reference case.
---------------------------------------------------------------------------

    \475\ EPA typically assesses social benefits and costs of a
rulemaking. However, this analysis is more limited in its scope by
examining the average cost of production of ethanol and gasoline
without accounting for the effects of farm subsidies that tend to
distort the market price of agricultural commodities.

                          Table VIII.D.2-1--Estimated Costs of the RFS2 Program in 2022
                                       [2006 dollars, 7% ROI before taxes]
----------------------------------------------------------------------------------------------------------------
                                                                      $53 per barrel of      $92 per barrel of
                                                                    crude oil incremental  crude oil incremental
                                                                      to reference case      to reference case
----------------------------------------------------------------------------------------------------------------
Gasoline Impacts.......................  $billion/yr..............                  17.0                    4.1
                                         c/gal....................                  10.91                   2.65
Diesel Fuel Impacts....................  $billion/yr..............                   0.78                  -0.05
                                         c/gal....................                   1.20                  -0.07
                                                                   ---------------------------------------------
    Total Impact.......................  $billion/yr..............                  17.8                    4.1
----------------------------------------------------------------------------------------------------------------

    Our analysis shows, as expected, that the RFS2 program is more cost
effective at the higher assumed price of crude oil. At our assumed
crude oil price of $53 per barrel, the gasoline and diesel fuel costs
are projected to increase by $17.0 billion and $0.78 billion,
respectively, or $17.8 billion in total. Expressed as per-gallon costs,
these fuel changes would increase the cost of producing gasoline and
diesel fuel by 10.91 and 1.20 cents per gallon, respectively. At the
assumed crude oil price of $92 per barrel, the gasoline costs are
projected to increase by $4.1 billion and the diesel fuel costs are
projected to decrease by $0.05 billion, or increase by $4.1 billion in
total. Expressed as per-gallon costs, these fuel changes would increase
gasoline costs by 2.65 and decrease diesel fuel costs by 0.07 cents per
gallon at the higher crude oil price. Our analysis shows that at the
higher crude oil price, ethanol, biodiesel and renewable diesel fuel
use would be much less costly to use.
    The increased use of renewable and alternative fuels would require
capital investments in corn and cellulosic ethanol plants, and
renewable diesel fuel plants. In addition to producing the fuels,
storage and distribution facilities along the whole distribution chain,
including at retail, will have to be constructed for these new fuels.
Conversely, as these renewable and

alternative fuels are being produced, they supplant gasoline and diesel
fuel demand which results in less new investments in refineries
compared to business as usual. In Table VIII.D.2-2, we list the total
incremental capital investments that we project would be made for this
proposed RFS2 rulemaking incremental to the AEO 2007 reference case.

 Table VIII.D.2-2--Total Projected U.S. Capital Investments for the RFS2
                                 Program
                            [billion dollars]
------------------------------------------------------------------------
                                                               Capital
                        Plant Type                              Costs
------------------------------------------------------------------------
Corn Ethanol..............................................          4.0
Cellulosic Ethanol........................................         50.1
Ethanol Distribution......................................         12.4
Bio/Renew Diesel Fuel Production and Distribution.........          0.25
Refining..................................................         -7.9
                                                           -------------
  Total...................................................         58.9
------------------------------------------------------------------------

    Table VIII.D.2-2 shows that the total U.S. incremental capital
investments attributed to this program for 2022 are $58.9 billion. One
contributing reason why the capital investments made for renewable
fuels technologies is so much more than the decrease in refining
industry capital investments is that a large part of the decrease in
petroleum gasoline supply was from reduced imports. In addition,
renewable fuels technologies are more capital intensive per gallon of
fuel produced than incremental increases in gasoline and diesel fuel
production at refineries.
b. Gasoline and Diesel Costs Reflecting the Tax Subsidies
    Table VIII.D.2-3 below expresses the total and per-gallon gasoline
costs for the two control scenarios showing the effect of the Federal
tax subsidies. The Federal tax subsidy is 45 cents per gallon for each
gallon of new corn ethanol blended into gasoline and $1.01 per gallon
for each gallon of cellulosic ethanol. Imported ethanol also receives
the 45 cents per gallon Federal tax subsidy, although the portion of
imported ethanol which exceeds the volume of imported ethanol exempted
through the Caribbean Basin Initiative (CBI) would have to pay a 51
cents per gallon tariff. We estimate that in 2022 imported ethanol
would receive a net 23 cents per gallon subsidy after we account for
both the subsidy and projected volume of imported ethanol subjected to
the tariff. While there are also state ethanol tax subsidies we did not
consider those subsidies. A $1 per gallon subsidy currently applies to
biodiesel produced from virgin plant oils (i.e., soy) and a 50 cent per
gallon subsidy applies to biodiesel and renewable diesel fuel produced
from waste fats and oils; we assume that these subsidies continue.\476\
The subsidies, if passed along to the consumer, reduce the apparent
cost of the program to the consumer at retail since part of the program
cost is being paid through taxes. The cost reduction attributed to the
subsidies is estimated by multiplying the value of the subsidies times
the volume of new corn and cellulosic ethanol used in transportation
fuels.
---------------------------------------------------------------------------

    \476\ The recent economic bailout law increased the subsidy
provided to renewable diesel fuel to $1 per gallon, but we were not
able incorporate this change in time for this proposed rulemaking.

                          Table VIII.D.2-3--Estimated Costs of the RFS2 Program in 2022
                          [Reflecting Tax Subsidies, 2006 dollars, 7% ROI before taxes]
----------------------------------------------------------------------------------------------------------------
                                                                      $53 per barrel of      $93 per barrel of
                                                                    crude oil incremental  crude oil incremental
                                                                      to reference case      to reference case
----------------------------------------------------------------------------------------------------------------
Gasoline Impacts.......................  $billion/yr..............                  -0.74                 -13.6
                                         c/gal....................                  -0.48                  -8.74
Diesel Fuel Impacts....................  $billion/yr..............                   0.25                  -0.57
                                         c/gal....................                   0.39                  -0.88
                                                                   ---------------------------------------------
    Total Impact.......................  $billion/yr..............                  -0.49                 -14.2
----------------------------------------------------------------------------------------------------------------

    Our analysis shows, as expected, that the overall costs of the RFS2
program appears to be lower when considering the ethanol consumption
subsidies. At the assumed crude oil price of $53 per barrel, the
gasoline and diesel fuel costs are projected to decrease by $0.74
billion and increase $0.25 billion, respectively, or $-0.49 billion in
total. Expressed as per-gallon costs, these fuel changes would decrease
gasoline costs by -0.48 cents per gallon and increase diesel fuel costs
by 0.39 cents per gallon. At the assumed crude oil price of $92 per
barrel, the gasoline and diesel fuel costs are projected to decrease by
$13.6 billion and $0.57 billion, respectively, or $14.2 billion in
total. Expressed as per-gallon costs, these fuel changes would decrease
gasoline and diesel fuel by 8.74 and 0.88 cents per gallon,
respectively. Reducing the cost by the tax subsidies, which more
closely represents the prices paid by consumers at the pump, our
analysis shows that at lower crude oil prices that the cost of the
program would be very small. However, at the higher oil prices and
including the subsidies, the program's costs are very negative.

IX. Economic Impacts and Benefits of the Proposal

A. Agricultural Impacts

    EPA used two principal tools to model the potential domestic and
international impacts of the RFS2 on the U.S. and global agricultural
sectors. The Forest and Agricultural Sector Optimization Model (FASOM),
developed by Professor Bruce McCarl of Texas A&M University and others,
provides detailed information on domestic agricultural and greenhouse
gas impacts of renewable fuels. The Food and Agricultural Policy
Research Institute (FAPRI) at Iowa State University and the University
of Missouri-Columbia maintains a number of econometric models that are
capable of providing detailed information on impacts on international
agricultural markets from the wider use of renewable fuels in the U.S.
    FASOM is a long-term economic model of the U.S. agriculture sector
that attempts to maximize total revenues for producers while meeting
the demands of consumers. FASOM can be utilized to estimate which
crops, livestock, and processed agricultural products would be produced
in the U.S. given RFS2 biofuel requirements. In each model simulation,
crops compete for price sensitive inputs such as land and labor at the
regional level and the cost of

these and other inputs are used to determine the price and level of
production of primary commodities (e.g., field crops, livestock, and
biofuel products). FASOM also estimates prices using costs associated
with the processing of primary commodities into secondary products
(e.g., converting livestock to meat and dairy, crushing soybeans to
soybean meal and oil, etc.). FASOM does not capture short-term
fluctuations (i.e., month-to-month, annual) in prices and production,
however, as it is designed to identify long-term trends (i.e., five to
ten years). The domestic results provided throughout this analysis
incorporate the agricultural sector component of the FASOM model.
    The FASOM model also contains a forestry component. Running both
the forestry and agriculture components of the model would show the
interaction between these two sectors. However, the analysis for this
proposal only shows the results from the agriculture component with no
interaction from the forestry sector, as the forestry component of the
model is in the process of being updated. We plan to utilize a complete
version of the model for our analysis in the final rule, where
agricultural land use impacts also affect forestry land use, and
cellulosic ethanol produced from the forestry sector will affect
cellulosic ethanol production in the agriculture sector.
    The FAPRI models are econometric models covering many agricultural
commodities. These models capture the biological, technical, and
economic relationships among key variables within a particular
commodity and across commodities. They are based on historical data
analysis, current academic research, and a reliance on accepted
economic, agronomic, and biological relationships in agricultural
production and markets. The international modeling system includes
international grains, oilseeds, ethanol, sugar, and livestock models.
In general, for each commodity sector, the economic relationship that
supply equals demand is maintained by determining a market-clearing
price for the commodity. In countries where domestic prices are not
solved endogenously, these prices are modeled as a function of the
world price using a price transmission equation. Since econometric
models for each sector can be linked, changes in one commodity sector
will impact other sectors. Elasticity values for supply and demand
responses are based on econometric analysis and on consensus estimates.
Additional information on the FASOM and FAPRI models is included in the
Draft Regulatory Impact Analysis (DRIA Chapter 5).
    For the agricultural sector analysis using the FASOM and FAPRI
models of the RFS2 biofuel volumes, we assumed 15 billion gallons
(Bgal) of corn ethanol would be produced for use as transportation fuel
by 2022, an increase of 2.7 Bgal from the Reference Case. Also, we
modeled 1.0 Bgal of biodiesel used as fuel in 2022, an increase of 0.6
Bgal from the Reference Case. In addition, we modeled an increase of 10
Bgal of cellulosic ethanol in 2022. In FASOM, this volume consists of
7.5 billion gallons of cellulosic ethanol coming from corn residue in
2022, 1.3 billion gallons from switchgrass and 1.4 billion gallons from
sugarcane bagasse. Though these volumes differ slightly from those
analyzed in Section V.B.2.c.iv, we will work to align the volumes for
the final rulemaking.
    Given the short timeframe for conducting this analysis, some of the
projected sources of biofuels analyzed in the RFS2 proposal are not
currently modeled in FASOM and FAPRI. For example, biodiesel from corn
oil fractionation is not currently accounted for in FASOM. In addition,
since FASOM is a domestic agricultural sector model, it can't be
utilized to examine the impacts of the wider use of biofuel imports
into the U.S. Also, neither of the two models used for this analysis--
FASOM or FAPRI--include biofuels derived from domestic municipal solid
waste or from the U.S. forestry sector. Thus, for the RFS2 agricultural
sector analysis, these biofuel sources are analyzed outside of the
agricultural sector models.
    All the results presented in this section are relative to the AEO
2007 Reference Case renewable fuel volumes, which include 12.3 Bgal of
grain-based ethanol, 0.4 Bgal of biodiesel, and 0.3 Bgal of cellulosic
ethanol in 2022. The domestic figures are provided by FASOM, and all of
the international numbers are provided by FAPRI. The detailed FASOM
results, detailed FAPRI results, and additional sensitivity analyses
are described in more detail in the DRIA. We seek comment on this
analysis of the agricultural sector impacts resulting from the wider
use of renewable fuels.

                                 Table IX.A.1-1--Biofuel Volumes Modeled in 2022
                                              [Billions of Gallons]
----------------------------------------------------------------------------------------------------------------
                         Biofuel                             Reference Case     Control Case         Change
----------------------------------------------------------------------------------------------------------------
Corn Ethanol.............................................               12.3              15.0               2.7
Corn Residue Cellulosic Ethanol..........................                0                 7.5               7.5
Sugarcane Bagasse Cellulosic Ethanol.....................                0.3               1.4               1.1
Switchgrass Cellulosic Ethanol...........................                0                 1.3               1.3
Other Ethanol............................................                0                 0.2               0.2
Biodiesel................................................                0.4               1.0               0.6
----------------------------------------------------------------------------------------------------------------

1. Commodity Price Changes
    For the scenario modeled, FASOM predicts that in 2022 U.S. corn
prices would increase by $0.15 per bushel (4.6%) above the Reference
Case price of $3.19 per bushel. By 2022, U.S. soybean prices would
increase by $0.29 per bushel (2.9%) above the Reference Case price of
$9.97 per bushel. The price of sugarcane would increase $13.34/ton
(41%) above the Reference Case price of $32.49 per ton by 2022. In
2022, beef prices would increase $0.93 per hundred pounds (1.4%),
relative to the Reference Case price of $67.72 per hundred pounds.
Additional price impacts are included in Section 5.1.1 of the DRIA.

 Table IX.A.1-2--Change in U.S. Commodity Prices From the Reference Case
                                 [2006$]
------------------------------------------------------------------------
          Commodity                        Change               % Change
------------------------------------------------------------------------
Corn.........................  $0.15/bushel..................        4.6
Soybeans.....................  $0.29/bushel..................        2.9
Sugarcane....................  $13.34/ton....................         41

Fed Beef.....................  $0.93/hundred pounds..........        1.4
------------------------------------------------------------------------

    By 2022, the price of switchgrass is $30.18 per wet ton and the
farm gate feedstock price of corn stover is $32.74/wet ton. These
prices do not include the storage, handling, or delivery costs, which
would result in a delivered price to the ethanol facility of at least
twice the farm gate cost, depending on the region. We intend to update
the costs assumptions (described in more detail in Section 4.1.1 of the