documents. However, in the case of attest engagements applied to RIN
generation by producers or importers of renewable fuel, or the use of
RINs for compliance purposes by obligated parties or exporters, the
auditor must examine documentation for all RINs generated or used. We
believe this requirement is necessary to ensure that obligated parties
and exporters are meeting their RFS obligation and that ethanol
producers and importers are assigning RINs to each batch of renewable
fuel produced or imported as required under the regulations.
    The proposed attest engagement regulations at Sec.  80.1164(b) did
not include importers of renewable fuels. One commenter pointed out
these procedures should apply to both renewable fuels producers and
importers. Renewable fuel importers have the same reporting
requirements as renewable fuel producers, and, therefore, there is the
same need for verification of the information given on the reports
through attest engagements. It was an inadvertent oversight that
renewable fuel importers were not included in the parties required to

comply with the attest engagement procedures in proposed Sec.
80.1164(b), and that applying the requirements in Sec.  80.1164(b) to
renewable fuel importers is a logical outgrowth of the proposed
regulations. As a result, the regulations have been modified to include
renewable fuel importers in the parties required to comply with the
attest procedures in Sec.  80.1164(b).
    In addition to obligated parties, exporters and renewable fuel
producers and importers, we believe that an attest engagement
requirement is necessary for any party who takes ownership of a RIN. As
discussed above, attest engagements provide an appropriate and useful
tool for verifying the accuracy of the information reported to us. Like
obligated parties and renewable fuel producers and importers, the final
rule requires RIN owners to submit information regarding RIN
transaction activity to us. We believe that attest engagement audits
are necessary to verify the accuracy of the information included in
these reports. Therefore, this final rule includes an attest engagement
requirement for RIN owners who are not obligated parties or renewable
fuel producers or importers. We believe that inclusion of the
requirement in the final rule is a logical outgrowth of the proposed
attest engagement requirements for other parties who are required to
submit similar information regarding RIN transaction activity to us.

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

    The prohibition and liability provisions applicable to the RFS
program are similar to those of other gasoline programs. The final rule
identifies certain prohibited acts, such as a failure to acquire
sufficient RINs to meet a party's renewable fuel obligation (RVO),
producing or importing a renewable fuel without properly assigning a
RIN, creating, transferring or using invalid RINs, improperly
transferring renewable fuel volumes without RINs, improperly separating
RINs from renewable fuel, retaining more RINs during a quarter than the
party's inventory of renewable fuel, or transferring RINs that are not
identified by proper RIN numbers. Any person subject to a prohibition
will be held liable for violating that prohibition. Thus, for example,
an obligated party will be liable if the party fails to acquire
sufficient RINs to meet its RVO. A party who produces or imports
renewable fuels will be liable for a failure to properly assign RINs to
batches of renewable fuel produced or imported. A renewable fuels
marketer will be liable for improperly transferring renewable fuel
volumes without RINs or retaining more RINs during a quarter than the
party's inventory of renewable fuels. Any party may be liable for
creating, transferring, or using an invalid RIN, or transferring a RIN
that is not properly identified.
    In addition, any person who is subject to an affirmative
requirement under the RFS program will be liable for a failure to
comply with the requirement. For example, an obligated party will be
liable for a failure to comply with the annual compliance reporting
requirements. A renewable fuel producer or importer will be liable for
a failure to comply with the applicable renewable fuel batch reporting
requirements. Any party subject to recordkeeping or product transfer
document requirements would be liable for a failure to comply with
these requirements. Like other EPA fuels programs, the final rule
provides that a party who causes another party to violate a prohibition
or fail to comply with a requirement may be found liable for the
violation.
    The Energy Act amended the penalty and injunction provisions in
section 211(d) of the Clean Air Act to apply to violations of the
renewable fuels requirements in section 211(o).\42\ Accordingly, under
the final rule, any person who violates any prohibition or requirement
of the RFS program may be subject to civil penalties for every day of
each such violation and the amount of economic benefit or savings
resulting from the violation. Under the final rule, a failure to
acquire sufficient RINs to meet a party's renewable fuels obligation
will constitute a separate day of violation for each day the violation
occurred during the annual averaging period.
---------------------------------------------------------------------------

    \42\ Section 1501(b) of the Energy Policy Act of 2005.
---------------------------------------------------------------------------

    Because there are no standards under the RFS rule that may be
measured downstream, we believe that a presumptive liability scheme,
i.e., a scheme in which parties upstream from the facility where the
violation is found are presumed liable for the violation, would not be
applicable under the RFS program. As a result, the RFS rule does not
contain such a scheme.
    The regulations prohibit any party from creating, transferring or
using invalid RINs. These invalid RIN provisions apply regardless of
the good faith belief of a party that the RINs are valid. These
enforcement provisions are necessary to ensure the RFS program goals
are not compromised by illegal conduct in the creation and transfer of
RINs.
    Any obligated party that reports the use of invalid RINs to meet
its renewable fuels obligation may be liable for a regulatory violation
for use of invalid RINs. If the obligated party fails to meet its
renewable fuels obligation without the invalid RINs, the party may also
be liable for not meeting its renewable fuels obligation. In addition,
the transfer of invalid RINs is prohibited, so that any party or
parties that transfer invalid RINs may be liable for a regulatory
violation for transferring the invalid RINs. In a case where invalid
RINs are transferred and used, EPA normally will hold each party that
committed a violation responsible, including both the user and the
transferor of the invalid RINs. For this reason, obligated parties and
RIN brokers should use good business judgment when deciding whether to
purchase RINs from any particular seller and should consider including
prudent business safeguards in RIN transactions, such as requiring RIN
sellers to sign contracts with indemnity provisions to protect the
purchaser in the event penalties are assessed because we find the RINs
are invalid. Similarly, parties that sell RINs should take steps to
ensure any RINs that are sold were properly created to avoid penalties
that result from the transfer of invalid RINs.
    As in other motor vehicle fuel credit programs, the regulations
address the consequences if an obligated party is found to have used
invalid RINs to demonstrate compliance with its RVO. In this situation,
the obligated party that used the invalid RINs will be required to
deduct any invalid RINs from its compliance calculations. As discussed
above, the obligated party will be liable for not meeting its renewable
fuels obligation if the remaining number of valid RINs is insufficient
to meet its RVO, and the obligated party may be subject to monetary
penalties if it used invalid RINs in its compliance demonstration. In
determining an appropriate penalty, EPA will consider a number of
factors, including whether the obligated party did in fact procure
sufficient valid RINs to cover the deficit created by the invalid RINs.
A penalty may include both the economic benefit of using invalid RINs
and a gravity component.
    Although an obligated party may be liable for a violation if it
uses invalid RINs for compliance purposes, we normally will look first
to the generator or seller of the invalid RINs both for payment of
penalty and to procure sufficient valid RINs to offset the invalid
RINs. However, if EPA is unable to

obtain relief from that party, attention will turn to the obligated
party who may then be required to obtain sufficient valid RINs to
offset the invalid RINs.
    We received several comments on the prohibition regarding use of
invalid RINs. Some commenters believe that an obligated party that uses
RINs which are later found to be invalid should be given an opportunity
to ``cure'' the shortfall caused by the invalid RINs without penalty.
As indicated above, a penalty for a good faith purchaser is not
automatic. Where an invalid RIN was created by another party, such as
the producer or marketer of the renewable fuel, the party responsible
for the existence of the invalid RIN would be liable and would be
required to purchase a RIN to make up for the invalid RIN and pay an
appropriate penalty. If the responsible party cannot be identified or
is out of business, or if EPA is otherwise unable to obtain relief from
the party, then the obligated party that used the RIN would be required
to purchase a RIN to make up for the invalid RIN. However, any penalty
for a good faith purchaser would likely be small, particularly where
EPA is able to obtain relief from the party that was responsible for
the invalid RIN. Where a RIN was originally believed to be valid but is
later found to be invalid, whether a current year RIN may be used to
make up for the prior-year invalid RIN would be determined in the
context of the enforcement action.
    Another commenter suggested that an obligated party should not be
liable for a violation unless the party knowingly used the invalid RINs
to demonstrate compliance. Where the suspect RINs are later proved to
be valid, the party should be able to use the RINs in the subsequent
year regardless of the year of generation or any rollover cap. For the
reasons stated above, we believe that it is appropriate to hold an
obligated party responsible for using invalid RINs even where the party
in good faith believed the RINs to be valid. Normally, suspect RINs
will be not be replaced until the RINs are proved to be invalid. In the
unlikely circumstance that a RIN is first determined to be invalid and
then later found to be valid, the ability to use the RIN in a
subsequent year would be determined in the context of the enforcement
action.
    Finally, parties that are predominately renewable fuel producers or
importers, but which must be designated as obligated parties due to the
production or importation of a small amount of gasoline, should not be
able to separate RINs from all renewable fuels that they own. To
address such circumstances, we are prohibiting obligated parties from
separating RINs that they generate from volumes of renewable fuel in
excess of their RVO. However, obligated parties must separate any RINs
generated by other parties from renewable fuel if they own the
renewable fuel.

VI. Current and Projected Renewable Fuel Production and Use

    While the definition of renewable fuel does not limit compliance
with the standard to any one particular type of renewable fuel, ethanol
is currently the most prevalent renewable fuel blended into gasoline
today. Biodiesel represents another renewable fuel which, while not as
widespread as ethanol use (in terms of volume), has been increasing in
production capacity and use over the last several years. This section
provides a brief overview of the ethanol and biodiesel industries today
and how they are projected to grow into the future.

A. Overview of U.S. Ethanol Industry and Future Production/Consumption

1. Current Ethanol Production
    As of October 2006, there were 110 ethanol production facilities
operating in the United States with a combined production capacity of
approximately 5.2 billion gallons per year.\43\ All of the ethanol
currently produced comes from grain or starch-based feedstocks that can
easily be broken down into ethanol via traditional fermentation
processes. The majority of ethanol (almost 92 percent by volume) is
produced exclusively from corn. Another 7 percent comes from a blend of
corn and/or similarly processed grains (milo, wheat, or barley) and
less than 1 percent is produced from waste beverages, cheese whey, and
sugars/starches combined. A summary of ethanol production by feedstock
is presented in Table VI.A.1-1.
---------------------------------------------------------------------------

    \43\ The October 2006 ethanol production capacity baseline was
generated based on the June 2006 NPRM plant list and updated on
October 18, 2006 based on a variety of data sources including:
Renewable Fuels Association (RFA), Ethanol Biorefinery Locations
(updated October 16, 2006); Ethanol Producer Magazine (EPM), plant
list (downloaded October 18, 2006) and monthly publications (June
2006 through October 2006); ICF International, Ethanol Industry
Profile (September 30, 2006); BioFuels Journal, News & Information
for the Ethanol and BioFuels Industries (breaking news posted June
16, 2006 through October 18, 2006); and ethanol producer Web sites.
The baseline includes small-scale ethanol production facilities as
well as former food-grade ethanol plants that have since
transitioned into the fuel-grade ethanol market. Where applicable,
current ethanol plant production levels have been used to represent
plant capacity, as nameplate capacities are often underestimated.
This analysis does not consider ethanol plants that may be located
in the Virgin Islands or U.S. territories.

       Table VI.A.1-1.--2006 U.S. Ethanol Production by Feedstock
------------------------------------------------------------------------
                                          Percent
       Plant feedstock         Capacity      of     Number of   Percent
                                 MMgy     capacity    plants   of plants
------------------------------------------------------------------------
Cheese Whey.................          8        0.1          2        1.8
Corn a......................      4,780       91.6         90       81.8
Corn, Barley................         40        0.8          1        0.9
Corn, Milo b................        244        4.7          8        7.3
Corn, Wheat.................         90        1.7          2        1.8
Milo, Wheat.................         40        0.8          1        0.9
Sugars, Starches............          2        0.0          1        0.9
Waste Beverages c...........         16        0.3          5        4.5
                             -------------------------------------------
    Total...................      5,218      100.0        110      100.0
------------------------------------------------------------------------
a Includes two facilities processing seed corn and another facility
  processing corn which intends to transition to corn stalks,
  switchgrass, and biomass in the future.
b Includes one facility procesisng small amounts of molasses in addition
  to corn and milo.
c Includes two facilities processing brewery waste.

    There are a total of 102 plants processing corn and/or other
similarly processed grains. Of these facilities, 92 utilize dry-milling
technologies and the remaining 10 plants rely on wet-milling processes.
Dry mill ethanol plants grind the entire kernel and produce only one
primary co-product: Distillers' grains with solubles (DGS). The co-
product is sold wet (WDGS) or dried (DDGS) to the agricultural market
as animal feed. In contrast to dry mill plants, wet mill facilities
separate the kernel prior to processing and in turn produce other co-
products (usually gluten feed, gluten meal, and oil) in addition to
DGS. Wet mill plants are generally more costly to build but are larger
in size on average. As such, nearly 22 percent of the current overall
ethanol production comes from the 10 previously-mentioned wet mill
facilities.
    The remaining 8 plants which process waste beverages, cheese whey,
or sugars/starches, operate differently than their grain-based
counterparts. These facilities do not require milling and instead
operate a simpler enzymatic fermentation process.
    In addition to grain and starch-to-ethanol production, another
method exists for producing ethanol from a more diverse feedstock base.
This process involves converting cellulosic materials such as bagasse,
wood, straw, switchgrass, and other biomass into ethanol. Cellulose
consists of tightly-linked polymers of starch, and production of
ethanol from it requires additional steps to convert these polymers
into fermentable sugars. Scientists are actively pursuing acid and
enzyme hydrolysis as well as gasification to achieve this goal, but the
technologies are still not fully developed for large-scale commercial
production. As of October 2006, the only known cellulose-to-ethanol
plant in North America was Iogen in Canada, which produces
approximately one million gallons of ethanol per year from wood chips.
Several companies have announced plans to build cellulose-to-ethanol
plants in the U.S., but most are still in the research and development
or pre-construction planning phases. The majority of the plans involve
converting bagasse, rice hulls, wood, switchgrass, corn stalks, and
other agricultural waste or biomass into ethanol. For a more detailed
discussion on future cellulosic ethanol plants and production
technologies, refer to RIA Sections <IP_ADDRESS> and 7.1.2, respectively.
    Ethanol production is a relatively resource-intensive process that
requires the use of water, electricity, and steam. Steam needed to heat
the process is generally produced onsite or by other dedicated boilers.
Of today's 110 ethanol production facilities, 101 burn natural gas, 7
burn coal, 1 burns coal and biomass, and 1 burns syrup from the process
to produce steam.\44\ Our research suggests that 11 plants currently
utilize cogeneration or combined heat and power (CHP) technology,
although others may exist. CHP is a mechanism for improving overall
plant efficiency. Whether owned by the ethanol facility, their local
utility, or a third party; CHP facilities produce their own electricity
and use the waste heat from power production for process steam,
reducing the energy intensity of ethanol production. A summary of the
energy sources and CHP technology utilized by today's ethanol plants is
found in Table VI.A.1-2.
---------------------------------------------------------------------------

    \44\ Facilities were assumed to burn natural gas if the plant
fuel type was not mentioned or unavailable.

                         Table VI.A.1-2.--2006 U.S. Ethanol Production by Energy Source
----------------------------------------------------------------------------------------------------------------
                                                                       Percent
                   Plant energy source                      Capacity      of     Number of   Percent   CHP tech.
                                                              MMgy     capacity    plants   of plants
----------------------------------------------------------------------------------------------------------------
Coal.....................................................      1,042       20.0          7        6.3          2
Coal, Biomass............................................         50        1.0          1        0.9          0
Natural Gas \a\..........................................      4,077       78.1        101       91.8          9
Syrup....................................................         48        0.9          1        0.9          0
                                                          ------------------------------------------------------
    Total................................................      5,218      100.0        110      100.0         11
----------------------------------------------------------------------------------------------------------------
\a\ Includes three facilities burning natural gas which intend to transition to coal or biomass in the future.

    The majority of domestic ethanol is currently produced in the
Midwest within PADD 2--where most of the corn is grown. Of the 110 U.S.
ethanol production facilities, 100 are located in PADD 2. As a region,
PADD 2 accounts for 96 percent (or over five billion gallons) of the
annual domestic ethanol production, as shown in Table VI.A.1-3.

          Table VI.A.1-3.--2006 U.S. Ethanol Production by PADD
------------------------------------------------------------------------
                                          Percent
            PADD               Capacity      of     Number of   Percent
                                 MMgy     capacity    plants   of plants
------------------------------------------------------------------------
PADD 1......................        0.4        0.0          1        0.9
PADD 2......................      5,012       96.0        100       90.9
PADD 3......................         30        0.6          1        0.9
PADD 4......................        105        2.0          4        3.6
PADD 5......................         71        1.4          4        3.6
                             -------------------------------------------
    Total...................      5,218      100.0        110      100.0
------------------------------------------------------------------------

    Leading the Midwest in ethanol production are Iowa, Illinois,
Nebraska, Minnesota, and South Dakota with a combined capacity of
nearly four billion gallons per year. Together, these five states' 70
ethanol plants account for 76 percent of the total domestic product.
However, although the majority of ethanol production comes from PADD 2,
there are a growing number of plants located outside the traditional
corn belt. In addition to the 15 states comprising PADD 2, ethanol
plants are currently located in California, Colorado, Georgia, New
Mexico, and Wyoming. Some of these facilities ship in feedstocks
(namely corn) from the Midwest, others rely on locally grown/produced
feedstocks, while others rely on a combination of both.
    The U.S. ethanol industry is currently comprised of a mixture of
corporations and farmer-owned cooperatives (co-ops). More than half (or
60) of today's plants are owned by corporations and, on average, these
plants are larger in size than farmer-owned co-ops. Accordingly,
company-owned plants account for almost 64 percent of the total U.S.
ethanol production capacity. Further, more than 50 percent of the total
domestic product comes from plants owned by just 6 different
companies--Archer Daniels Midland, Broin, VeraSun, Hawkeye Renewables,
Global/MGP Ingredients, and Aventine Renewable Energy.\45\
---------------------------------------------------------------------------

    \45\ Includes Broin's minority ownership in 18 U.S. ethanol
plants.
---------------------------------------------------------------------------

2. Expected Growth in Ethanol Production
    Over the past 25 years, domestic fuel ethanol production has
steadily increased due to environmental regulation, federal and state
tax incentives, and market demand. More recently, ethanol production
has soared due to the phase out of MTBE, an increasing number of state
ethanol mandates, and elevated crude oil prices. As shown in Figure
VI.A.2-1, over the past three years, domestic ethanol production has
nearly doubled from 2.1 billion gallons in 2002 to 4.0 billion gallons
in 2005. For 2006, the Renewable Fuels Association is anticipating
about 4.7 billion gallons of domestic ethanol production.\46\
---------------------------------------------------------------------------

    \46\ Based on RFA comments received in response to the proposed
rulemaking, 71 FR 55552 (September 22, 2006).
[GRAPHIC] [TIFF OMITTED] TR01MY07.047

    EPA forecasts that domestic ethanol production will continue to
grow into the future. In addition to the past impacts of federal and
state tax incentives, as well as the more recent impacts of state
ethanol mandates and the removal of MTBE from all U.S. gasoline, crude
oil prices are expected to continue to drive up demand for

ethanol. As a result, the nation is on track to exceed the renewable
fuel volume requirements contained in the Act. Today's ethanol
production capacity (5.2 billion gallons) is already exceeding the 2007
renewable fuel requirement (4.7 billion gallons). In addition, there is
another 3.4 billion gallons of ethanol production capacity currently
under construction.\47\ A summary of the new construction and plant
expansion projects currently underway (as of October 2006) is found in
Table VI.A.2-1.
---------------------------------------------------------------------------

    \47\ Under construction plant locatons, capacities, feedstocks,
and energy sources as well as planned/proposed plant locations and
capacities were derived from a variety of data soruces including
Renewable Fuels Association (RFA), Ethanol Biorefinery Locations
(updated October 16, 2006); Ethanol Producer Magazine (EPM), under
construction plant list (downloaded October 18, 2006) and monthly
publications (June 2006 through October 2006); ICF International,
Ethanol Industry Profile (September 30, 2006); BioFuels Journal,
News & Information for the Ethanol and BioFuels Industries (breaking
news posted June 16, 2006 through October 18, 2006); and ethanol
producer Web sites. This analysis does not consider ethanol plants
under construction or planned for the Virgin Islands or U.S.
territories.

                      Table VI.A.2-1.--Under Construction U.S. Ethanol Production Capacity
----------------------------------------------------------------------------------------------------------------
                                       Oct. 2006 baseline           Under const.           Base + under const.
               PADD               ------------------------------------------------------------------------------
                                       MMgy         Plants       MMgy a       Plants       MMgy a       Plants
----------------------------------------------------------------------------------------------------------------
PADD 1...........................           0.4            1          115            1          115            2
PADD 2...........................       5,012            100        2,764           39        7,776          139
PADD 3...........................          30              1          230            3          260            4
PADD 4...........................         105              4           50            1          155            5
PADD 5...........................          71              4          198            3          269            7
                                  ------------------------------------------------------------------------------
    Total........................       5,218            110        3,357           47        8,575         157
----------------------------------------------------------------------------------------------------------------
a Includes plant expansions.

    A select group of builders, technology providers, and construction
contractors are completing the majority of the construction projects
described in Table VI.A.2-1. As such, the completion dates of these
projects are staggered over approximately 18 months, resulting in the
gradual phase-in of ethanol production shown in Figure VI.A.2-2.\48\
---------------------------------------------------------------------------

    \48\ Construction timelines based on information obtained from
press releases and ethanol producer Web sites.

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

[GRAPHIC] [TIFF OMITTED] TR01MY07.048

    As shown in Table VI.A.2-1 and Figure VI.A.2-2, once all the
construction projects currently underway are complete (estimated by
March 2008), the resulting U.S. ethanol production capacity would be
about 8.6 billion gallons. Without even considering forecasted
biodiesel production (described below in Section VI.B.1), this would be
more than enough renewable fuel to satisfy the 2012 RFS requirements
(7.5 billion gallons). However, ethanol production is expected to
continue to grow. There are more and more ethanol projects being
announced each day. These potential projects are at various stages of
planning from conducting feasibility studies to gaining local approval
to applying for permits to financing/fundraising to obtaining
contractor agreements. Together these potential projects could result
in an additional 21 billion gallons of ethanol production capacity as
shown in Table VI.A.2-2.

                        Table VI.A.2-2.--Other Potential U.S. Ethanol Production Capacity
----------------------------------------------------------------------------------------------------------------
                                                 Base + under const.         Planned              Proposed
                     PADD                      -----------------------------------------------------------------
                                                 MMgy \a\    Plants    MMgy \a\    Plants    MMgy \a\    Plants
----------------------------------------------------------------------------------------------------------------
PADD 1........................................        115          2      548.0          8        934         21
PADD 2........................................      7,776        139      4,633         44     11,722        136
PADD 3........................................        260          4        250          4        876         14
PADD 4........................................        155          5        100          1        783         14
PADD 5........................................        269          7        232          8        775         23
                                               -----------------------------------------------------------------
        Subtotal..............................      8,575        157      5,763         65     15,090        208
                                               -----------------------------------------------------------------
        Total \b\.............................  .........  .........     14,339        222     29,428        430
----------------------------------------------------------------------------------------------------------------
\a\ Includes plant expansions.
\b\ Total including existing plus under construction plants.

    Although there is clearly a great potential for ethanol production
growth, it is highly unlikely that all the announced projects would
actually reach completion in a reasonable amount of time, or at all,
considering the large number of projects moving forward. Since there is
no precise way to know exactly which plants will come

to fruition in the future, we have chosen to focus our subsequent
discussion on forecasted ethanol production on plants which are likely
to be online by 2012.\49\ This includes existing plants as well as
projects which are under construction (refer to Table VI.A.2-1) or in
the final planning stages (denoted as ``planned'' in Table VI.A.2-2).
The distinction between ``planned'' versus ``proposed'' is that as of
October 2006 planned projects had completed permitting, fundraising/
financing, and had builders assigned with definitive construction
timelines whereas proposed projects did not.
---------------------------------------------------------------------------

    \49\ A more detailed summary of the plants we considered is
found in a March 5, 2007 note to the docket titled: RFS Industry
Characterization--Ethanol Production.

       Table VI.A.2-3.--Forecasted 2012 Ethanol Production by PADD
------------------------------------------------------------------------
                                          Percent
            PADD               Capacity      of     Number of   Percent
                                 MMgy     capacity    plants   of plants
------------------------------------------------------------------------
PADD 1......................        663        4.6         10        4.5
PADD 2......................     12,409       86.5        183       82.4
PADD 3......................        510        3.6          8        3.6
PADD 4......................        255        1.8          6        2.7
PADD 5......................        501        3.5         15        6.8
                             -------------------------------------------
    Total...................     14,339      100.0        222      100.0
------------------------------------------------------------------------

    As shown above in Table VI.A.2-3, once all the under construction
and planned projects are complete the resulting ethanol production
capacity would be 14.3 billion gallons. The majority of which would
still originate from PADD 2. This volume, expected to be online by
2012, exceeds the EIA AEO 2006 demand estimate (9.6 billion gallons by
2012, discussed more in RIA Section 2.1). The forecasted growth would
nearly triple today's production capacity and greatly exceed the 2012
RFS requirement (7.5 billion gallons). While our forecast represents
ethanol production capacity (actual production could be lower), we
believe it is still a good indicator of what domestic ethanol
production could look like in the future. In addition, we predict that
domestic ethanol production will continue to be supplemented by imports
in the future. According to a current report by F.O. Licht, U.S. net
import demand is estimated to be around 300 million gallons per year by
2012, being supplied primarily through the Caribbean Basin Initiative
(CBI), with some direct imports from Brazil during times of shortfall
or high price. For more information on ethanol imports, refer to RIA
Section 1.5.
    Of the 112 forecasted new ethanol plants (47 under construction and
65 planned), 106 would rely on grain-based feedstocks. More
specifically, 89 would rely exclusively on corn, 13 would process a
blend of corn and/or similarly processed grains (milo or wheat), 3
would process molasses, and 1 would process a combination of molasses
and sweet sorghum (milo). Of the remaining six plants (all in the
planned stage), four would process cellulosic biomass feedstocks and
two would start off processing corn and later transition to cellulosic
materials. Of the four dedicated cellulosic plants, one would process
bagasse, one would process a combination of bagasse and wood, and two
would process biomass. Of the two transitional corn/cellulosic plants,
one would ultimately process a combination of bagasse, rice hulls, and
wood and the other would ultimately process wood and other agricultural
residues. In addition to the forecasted new plants, an existing corn
ethanol plant plans to expand production and transition to corn stalks,
switchgrass, and biomass in the future. A summary of the resulting
overall feedstock usage (including current, under construction, and
planned projects) is found in Table VI.A.2-4.

  Table VI.A.2-4.--Forecasted 2012 U.S. Ethanol Production by Feedstock
------------------------------------------------------------------------
                                          Percent
       Plant feedstock         Capacity      of     Number of   Percent
                                 MMgy     capacity    plants   of plants
------------------------------------------------------------------------
Bagasse.....................          7        0.1          1        0.5
Bagasse, Wood...............          2        0.0          1        0.5
Bagasse, Wood, Rice Hulls           108        0.8          1        0.5
 \a\........................
Biomass.....................         55        0.4          2        0.9
Cheese Whey.................          8        0.1          2        0.9
Corn \b\....................     12,495       87.1        178       80.2
Corn, Barley................         40        0.3          1        0.5
Corn, Milo \c\..............      1,132        7.9         20        9.0
Corn, Wheat.................        235        1.6          3        1.4
Corn Stalks, Switchgrass,            40        0.3          1        0.5
 Biomass \a\................
Milo, Wheat.................         40        0.3          1        0.5
Molasses \d\................         52        0.4          4        1.8
Sugars, Starches............          2        0.0          1        0.5
Waste Beverages \e\.........         16        0.1          5        2.3
Wood Agricultural Residues          108        0.8          1        0.5
 \a\........................
                             -------------------------------------------
    Total...................     14,339      100.0        222      100.0
------------------------------------------------------------------------
\a\ Facilities plan to start off processing corn.

\b\ Includes two facilities processing seed corn.
\c\ Includes one facility processing small amounts of molasses in
  addition to corn and milo.
\d\ Includes one facility planning to process sweet sorghum (milo) in
  addition to molasses.
\e\ Includes two facilities processing brewery waste.

    Of the 112 forecasted new plants, 100 would burn some amount of
natural gas--at least initially. More specifically, 91 plants would
rely exclusively on natural gas; 2 would rely on a combination of
natural gas, bran and biomass; 1 would burn a combination of natural
gas, distillers' grains and syrup; and 6 would start off burning
natural gas and later transition to coal. As for the remaining 12
plants, 3 would burn manure-derived methane (biogas); 7 would rely
exclusively on coal; 1 would burn a combination of coal and biomass;
and 1 would burn a combination of coal, tires and biomass. In addition
to the new ethanol plants, three existing plants currently burning
natural gas are predicted to transition to alternate boiler fuels in
the future. More specifically, two plants plan to transition to biomass
and one plans to start burning coal. Our research suggests that 7 of
the new plants would utilize combined heat and power (CHP) technology,
although others may exist. Three of the new CHP plants would burn
natural gas, three would burn coal, and one would burn a combination of
coal, tires, and biomass. Among the existing CHP plants, two are
predicted to transition from natural gas to coal or biomass at this
time. Overall, the net number of CHP ethanol plants would increase from
11 to 18. A summary of the resulting overall plant energy source
utilization is found below in Table VI.A.2-5.

                    Table VI.A.2-5.--Forecasted 2012 U.S. Ethanol Production by Energy Source
----------------------------------------------------------------------------------------------------------------
                                                                       Percent
                   Plant energy source                      Capacity      of     Number of   Percent   CHP tech.
                                                              MMgy     capacity    plants   of plants
----------------------------------------------------------------------------------------------------------------
Biomass \a\..............................................        112        0.8          2        0.9          1
Coal \b\.................................................      2,095       14.6         21        9.5          6
Coal, Biomass............................................         75        0.5          2        0.9          0
Coal, Biomass, Tires.....................................        275        1.9          1        0.5          1
Manure Biogas \c\........................................        144        1.0          3        1.4          0
Natural Gas..............................................     11,275       78.6        189       85.1         10
Natural Gas, Bran, Biomass...............................        264        1.8          2        0.9          0
Natural Gas, Distiller's Grain, Syrup....................         50        0.3          1        0.5          0
Syrup....................................................         49        0.3          1        0.5          0
                                                          ------------------------------------------------------
    Total................................................     14,339      100.0        222      100.0         18
----------------------------------------------------------------------------------------------------------------
\a\ Represents two existing natural gas-fired plants that plan to transition to biomass.
\b\ Includes two plants planning on burning lignite coal or coal lines. Includes one existing plant currently
  burning natural gas that plans to transition to coal. Includes six new plants that will start off burning
  natural gas and later transition to coal.
\c\ Includes one facility planning on burning cotton gin in addition to manure biogas.

    The Energy Policy Act of 2005 requires that 250 million gallons of
the renewable fuel consumed in 2013 and beyond meet the definition of
cellulosic biomass ethanol. The Act defines cellulosic biomass ethanol
as ethanol derived from any lignocellulosic or hemicellulosic matter
that is available on a renewable or recurring basis including dedicated
energy crops and trees, wood and wood residues, plants, grasses,
agricultural residues, fibers, animal wastes and other waste materials,
and municipal solid waste. The term also includes any ethanol produced
in facilities where animal or other waste materials are digested or
otherwise used to displace 90 percent of more of the fossil fuel
normally used in the production of ethanol.
    As shown in Table VI.A.2-4, there are seven ethanol plants planning
to utilize cellulosic feedstocks in the future. These facilities have a
combined ethanol production capacity of 320 million gallons per year.
It is unclear whether these plants would be online and capable of
producing 250 million gallons of ethanol by 2013 to meet the Act's
cellulosic biomass ethanol requirement. However, as shown in Table
VI.A.2-5, there are 12 facilities that burn or plan to burn waste
materials to power their ethanol plants. Depending on how much fossil
fuel is displaced, these facilities (with a combined ethanol production
capacity of 969 million gallons per year) could also meet the
definition of cellulosic biomass ethanol under the Act. Considering
both feedstock and waste energy plants, the total cellulosic ethanol
potential could be as high as 1.3 billion gallons. Even if only one
fifth of this ethanol were to end up qualifying as cellulosic biomass
ethanol or come to fruition by 2013, it would be more than enough to
satisfy the 250 million gallon requirement specified in the Act.\50\
---------------------------------------------------------------------------

    \50\ We anticipate a ramp-up in cellulosic ethanol production in
the years to come so that capacity exists to satisfy the Act's 2013
requirement (250 million gallons of cellulosic biomass ethanol).
Therefore, for subsequent analysis purposes, we have assumed that
250 million gallons of ethanol would come from cellulosic biomass
sources by 2012.
---------------------------------------------------------------------------

3. Current Ethanol and MTBE Consumption
    To understand the impact of the increased ethanol production/use on
gasoline properties and in turn overall air quality, we first need to
gain a better understanding of where ethanol is used today and how the
picture is going to change in the future. As such, in addition to the
production analysis presented above, we have completed a parallel
consumption analysis comparing current ethanol consumption to future
predictions.
    In the 2004 base case, 3.5 billion gallons of ethanol \51\ and 1.9
billion gallons of MTBE \52\ were blended into gasoline to supply the
transportation sector with a total of 136 billion gallons of
gasoline.\53\ A breakdown of the 2004

gasoline and oxygenate consumption by PADD is found below in Table VI-
A.3-1.
---------------------------------------------------------------------------

    \51\ EIA Monthly Energy Review, June 2006 (Table 10.1: Renewable
Energy Consumption by Source, Appendix A: Thermal Conversion
Factors).
    \52\ File containing historical RFG MTBE usage obtained from EIA
representative on March 9, 2006.
    \53\ EIA 2004 Petroleum Marketing Annually (Table 48: Prime
Supplier Sales Volumes of Motor Gasoline by Grade, Formulation, PAD
District, and State).

                       Table VI.A.3-1.--2004 U.S. Gasoline & Oxygenate Consumption by PADD
----------------------------------------------------------------------------------------------------------------
                                                                       Ethanol                  MTBE \a\
                                                   Gasoline  ---------------------------------------------------
                      PADD                          MMgal                   Percent of                Percent of
                                                                 MMgal       gasoline      MMgal       gasoline
----------------------------------------------------------------------------------------------------------------
PADD 1.........................................       49,193          660          1.3        1,360          2.8
PADD 2.........................................       38,789        1,616          4.2            1          0.0
PADD 3.........................................       20,615           79          0.4          498          2.4
PADD 4.........................................        4,542           83          1.8            0          0.0
PADD 5 \b\.....................................        7,918          209          2.6           19          0.2
California.....................................       14,836          853          5.8            0          0.0
                                                ----------------------------------------------------------------
    Total......................................      135,893        3,500          2.6        1,878         1.4
----------------------------------------------------------------------------------------------------------------
\a\ MTBE blended into RFG.
\b\ PADD 5 excluding California.

    As shown above, nearly half (or about 45 percent) of the ethanol
was consumed in PADD 2 gasoline, where the majority of ethanol was
produced. The next highest region of use was the State of California
which accounted for about 25 percent of domestic ethanol consumption.
This is reasonable because California alone accounts for over 10
percent of the nation's total gasoline consumption and all the fuel
(both Federal RFG and California Phase 3 RFG) has been assumed to
contain ethanol (following their recent MTBE ban) at 5.7 volume
percent.\54\ The bulk of the remaining ethanol was used in reformulated
gasoline (RFG) and winter oxy-fuel areas requiring oxygenated gasoline.
Overall, 62 percent of ethanol was used in RFG, 33 percent was used in
CG, and 5 percent was used in winter oxy-fuel.\55\
---------------------------------------------------------------------------

    \54\ Current California gasoline regualtions make it very
difficult to meet the NOX emissions performance standard
with ethanol content higher than about 6 vol%. For our analysis, all
California RFG was assumed to contain 5.7 volume percent ethanol
based on a conversation with Dean Simeroth at California Air
Resources Board (CARB).
    \55\ For the purpose of this analysis, except where noted, the
term ``RFG'' pertains to Federal RFG plus California Phase 3 RFG
(CaRFG3) and Arizona Clean Burning Gasoline (CBG).
---------------------------------------------------------------------------

    As shown above in Table VI.A.3-1, 99 percent of MTBE use occurred
in PADDs 1 and 3. This reflects the high concentration of RFG areas in
the northeast (PADD 1) and the local production of MTBE in the gulf
coast (PADD 3). PADD 1 receives a large portion of its gasoline from
PADD 3 refineries who either produce the fossil-fuel based oxygenate or
are closely affiliated with MTBE-producing petrochemical facilities in
the area. Overall, 100 percent of MTBE in 2004 was assumed to be used
in reformulated gasoline.\56\
---------------------------------------------------------------------------

    \56\ 2004 MTBE consumption was obtained from EIA. The data
received was limited to states with RFG programs, thus MTBE use was
assumed to be limited to RFG areas for the purpose of this analysis.
---------------------------------------------------------------------------

    In 2004, total ethanol use exceeded MTBE use. Ethanol's lead
oxygenate role is relatively new, however the trend has been a
progression over the past few years. From 2001 to 2004, ethanol
consumption more than doubled (from 1.7 to 3.5 billion gallons), while
MTBE use (in RFG) was virtually cut in half (from 3.7 to 1.9 billion
gallons). A plot of oxygenate use over the past decade is provided
below in Figure VI.A.3-1.
    The nation's transition to ethanol is linked to states' responses
to recent environmental concerns surrounding MTBE groundwater
contamination. Resulting concerns over drinking water quality have
prompted several states to significantly restrict or completely ban
MTBE use in gasoline. At the time of this analysis, 19 states had
adopted MTBE bans. A list of the states with MTBE bans is provided in
RIA Table 2.1-4.

[GRAPHIC] [TIFF OMITTED] TR01MY07.049

4. Expected Growth in Ethanol Consumption
    As mentioned above, ethanol demand is expected to increase well
beyond the levels contained in the renewable fuels standard (RFS) under
the Act. With the removal of the RFG oxygenate mandate,\57\ all U.S.
refiners are taking steps to eliminate the use of MTBE as quickly as
possible. In order to complete this transition quickly (by 2007 at the
latest) while maintaining gasoline volume, octane, and mobile source
air toxics emission performance standards, refiners have elected to
blend ethanol into virtually all of their RFG.\58\ This has caused a
dramatic increase in demand for ethanol which, in 2006, was met by
temporarily shifting large volumes of ethanol out of conventional
gasoline and into RFG areas. By 2012, however, ethanol production will
have grown to accommodate the removal of MTBE without the need for such
a shift from conventional gasoline. More important than the removal of
MTBE over the long term, however, is the impact that the rise in crude
oil price is having on demand for renewable fuels, both ethanol and
biodiesel. This has dramatically improved the economics for renewable
fuel use, leading to a surge in demand that is expected to continue. In
the Annual Energy Outlook (AEO) 2006, EIA forecasted that by 2012,
total ethanol use (corn, cellulosic, and imports) would be about 9.6
billion gallons and biodiesel use would be about 0.3 billion gallons at
a crude oil price forecast of $48 per barrel.\59\ This ethanol
projection was not based on what amount the market would demand (which
could be higher), but rather on the amount that could be produced by
2012. Others are making similar predictions, and as discussed above in
VI.A.2, production capacity would be sufficient.
---------------------------------------------------------------------------

    \57\ Energy Act Section 1504, promulgated on May 8, 2006 at 71
FR 26691.
    \58\ Based on discussions with the refining industry.
    \59\ In AEO 2007, EIA is forecasted an even higher ethanol
consumption of 11.2 billion gallons by 2012. The draft report was
issued on December 5, 2006 and we could not incorporate it into the
refinery modeling used to conduct our analyses.
---------------------------------------------------------------------------

    In assessing the impacts of expanded renewable fuel use, we have
chosen to evaluate two different future ethanol consumption levels, one
reflecting the statutory required minimum, and one reflecting the
higher levels projected by EIA. For the statutory consumption scenario
we assumed 6.7 billion gallons of ethanol use (0.25 billion gallons of
which was assumed to be cellulosic) and 0.3 billion gallons of
biodiesel. This figure is lower than the 7.2 billion gallons of ethanol
we modeled in the proposal because it considers the renewable fuel
equivalence values we are finalizing for corn ethanol (1), biodiesel
(1.5) and cellulosic ethanol (2.5). For the higher projected renewable
fuel consumption scenario, we assumed 9.6 billion gallons of ethanol
(0.25 billion gallons of which was assumed to be cellulosic) and 0.3
billion gallons of biodiesel. Although the actual renewable fuel
volumes consumed in 2012 may differ from both the required and
projected volumes, we believe that

these two scenarios provide a reasonable range for analysis purposes.
For more information on how the renewable fuel usage scenarios we
considered, refer to RIA Section 2.1.
    To estimate where ethanol would be consumed in 2012, we used a
linear programming (LP) refinery cost model (discussed in more detail
in Section VII). For both future ethanol consumption scenarios
discussed above, the modeling provided us with a summary of ethanol
usage by PADD, fuel type, and season. There was some post-processing
involved to ensure that all state ethanol mandates and winter oxy-fuel
requirements were satisfied. The adjusted results for the 6.7 Bgal RFS
case and the 9.6 Bgal EIA case are presented below in Tables VI.A.4-1
and VI.A.4-2, respectively.

               Table VI.A.4-1.--Forecasted 2012 U.S. Ethanol Consumption (MMgal) 6.7 Bgal RFS Case
----------------------------------------------------------------------------------------------------------------
                                            Summer ethanol use               Winter ethanol use
                PADD                ------------------------------------------------------------------   Total
                                       CG \a\    RFG \b\     Total      CG \a\    RFG \b\     Total     ethanol
----------------------------------------------------------------------------------------------------------------
PADD 1.............................        399        679      1,078        350        706      1,057      2,134
PADD 2.............................      1,667         59      1,726      1,082        288      1,370      3,096
PADD 3.............................        161         47        208        146          0        146        354
PADDs 4/5 c........................        135          0        135        138          0        138        274
California.........................          0        414        414          0        398        398        813
                                    ----------------------------------------------------------------------------
    Total..........................      2,362      1,200      3,562      1,717      1,392      3,109      6,671
----------------------------------------------------------------------------------------------------------------
\a\ Includes Arizona CBG and winter oxy-fuel.
\b\ Federal RFG and California Phase 3 RFG.
\c\ PADDS 4 and 5 excluding California.

          Table VI.A.4-1.--Forecasted 2012 U.S. Ethanol Consumption by Season (MMgal) 9.6 Bgal EIA Case
----------------------------------------------------------------------------------------------------------------
                                            Summer ethanol use               Winter ethanol use
                PADD                ------------------------------------------------------------------   Total
                                       CG \a\    RFG \b\     Total      CG \a\    RFG \b\     Total     ethanol
----------------------------------------------------------------------------------------------------------------
PADD1..............................        610        630      1,240        267        973      1,240      2,481
PADD2..............................      1,735        185      1,919      1,631        366      1,998      3,917
PADD3..............................        901         47        949        856          0        856      1,805
PADD 4/5 \c\.......................        339          0        339        154          0        154        492
California.........................          0        435        435          0        470        470        905
                                    ----------------------------------------------------------------------------
    Total..........................      3,584      1,298      4,882      2,908      1,809      4,718      9,600
----------------------------------------------------------------------------------------------------------------
\a\ Includes Arizona CBG and winter oxy-fuel.
\b\ Federal RFG and California Phase 3 RFG.
\c\ PADDs 4 and 5 excluding California.

    As shown above, the LP modeling predicts that the majority of
ethanol will be consumed in PADD 2, where most of the ethanol is
produced. The results show varying levels of ethanol usage in RFG in
response to the removal of the oxygenate requirement. For the higher
ethanol consumption scenario, the modeling suggests that the majority
of additional ethanol would be absorbed in PADD 3 conventional
gasoline. With respect to seasonality, in both cases, the modeling
predicts that a greater fraction of ethanol use would occur in the
summertime due to the 1psi RVP waiver. For a more detailed discussion
on future ethanol consumption, refer to Chapter 2 of the RIA.

B. Overview of Biodiesel Industry and Future Production/Consumption

1. Characterization of U.S. Biodiesel Production/Consumption
    Historically, the cost to make biodiesel was an inhibiting factor
to production in the U.S. The cost to produce biodiesel was high
compared to the price of petroleum derived diesel fuel, even with the
subsidies and credits provided by federal and state programs. Much of
the demand occurred as a result of mandates from states and local
municipalities, that required the use of biodiesel. However, over the
past couple of years biodiesel production has been increasing rapidly.
The combination of higher crude oil prices and greater federal tax
subsidies has created a favorable economic situation. The Biodiesel
Blenders Tax Credit programs and the Commodity Credit Commission Bio-
energy Program, both subsidize producers and offset production costs.
The Energy Policy Act extended the Biodiesel Blenders Tax Credit
program to 2008. This credit provides about one dollar per gallon in
the form of a federal excise tax credit to biodiesel blenders from
virgin vegetable oil feedstocks and 50 cents per gallon to biodiesel
produced from recycled grease and animal fats. The program was started
in 2004 under the American Jobs Act, spurring the expansion of
biodiesel production and demand. Historical estimates and future
forecasts of biodiesel production in the U.S. are presented in Table
VI.B.1-1 below.

             Table VI.B.1-1.--Estimated Biodiesel Production
------------------------------------------------------------------------
                                                                Million
                             Year                               gallons
                                                                per year
------------------------------------------------------------------------
2001.........................................................          5
2002.........................................................         15
2003.........................................................         20
2004.........................................................         25
2005.........................................................         91
2006.........................................................        150
2007.........................................................        414
2012.........................................................       303
------------------------------------------------------------------------
Source: Historical data from 2001-2004 obtained from estimates from John
  Baize `` The Outlook and Impact of Biodiesel on the Oilseeds Sector''
  USDA Outlook Conference 06. Year 2005 data from USDA Bioenergy Program
  http://www.fsa.usda.gov/daco/bioenergy/2005/FY2005ProductPayments,

  Year 2006 data from verbal quote based on projection by NBB in June of
  2006. Production data for years 2007 and higher are from EIA's AEO
  2006.

    With the increase in biodiesel production, there has also been a

corresponding rapid expansion in biodiesel production capacity.
Presently, there are 85 biodiesel plants in operation with an annual
production capacity of 580 million gallons per year.\60\ The majority
of the current production capacity was built in 2005 and 2006, and was
first available to produce fuel in the later part of 2005 and in 2006.
Though the capacity has grown, historically the biodiesel production
capacity has far exceeded actual production with only 10-30 percent of
this being utilized to make biodiesel. The excess capacity, though, may
be from biodiesel plants that do not operate full time and from
production capacity that is primarily devoted to making esters for the
ole-chemical markets, see Table VI.B.1-2.
---------------------------------------------------------------------------

    \60\ NBB Survey September 13, 2006 ``U.S. Biodiesel Production
Capacity''.
    \61\ From Presentation ``Biodiesel Production Capacity,'' by
Leland Tong, National Biodiesel Conference and Expo, February 7,
2006.

           Table VI.B.1-2.--U.S. Production Capacity History a
------------------------------------------------------------------------
                                 2001   2002   2003   2004   2005   2006
------------------------------------------------------------------------
Plants........................      9     11     16     22     45     85
Capacity (million gal/yr).....     50     54     85    157    290   580
------------------------------------------------------------------------
\a\ Capacity Data based on surveys conducted around the month of
  September for most years, though the 2006 information is based on a
  survey conducted in January 2006.\61\

2. Expected Growth in U.S. Biodiesel Production/Consumption
    In addition to the 85 biodiesel plants already in production, as of
early 2006, there were 65 plants in the construction phase and 13
existing plants that are expanding their capacity, which when completed
would increase total biodiesel production capacity to over one billion
gallons per year. Most of these plants should be completed by late
2007. As shown in Table VI.B.2-1 if all of this capacity came to
fruition, U.S. biodiesel capacity would exceed 1.4 billion gallons.

        Table VI.B.2-1.--Projected Biodiesel Production Capacity
------------------------------------------------------------------------
                                             Existing      Construction
                                              plants           phase
------------------------------------------------------------------------
Number of plants........................              85              78
Total Plant Capacity, (MM Gallon/year)..             580           1,400
------------------------------------------------------------------------

    For cost and emission analysis purposes, three biodiesel usage
cases were considered: A 2004 base case, a 2012 reference case, and a
2012 control case. The 2004 base case was formed based on historical
biodiesel usage (25 million gallons as summarized in Table VI.B.1.1).
The reference case was computed by taking the 2004 base case and
growing it out to 2012 by applying the 2004-2012 EIA diesel fuel growth
rate.\62\ The resulting 2012 reference case consisted of 30 million
gallons of biodiesel. Finally, for the 2012 control case, forecasted
biodiesel use was assumed to be 300 million gallons based on EIA's AEO
2006 report (rounded value from Table VI.B.1.1). Unlike forecasted
ethanol use, biodiesel use was assumed to be constant at 300 million
gallons under both the statutory and higher projected renewable fuel
consumption scenarios described in VI.A.4. EIA's projection is based on
the assumption that the blender's tax credit is not renewed beyond
2008. If the tax credit is renewed, the projection for biodiesel demand
would increase.
---------------------------------------------------------------------------

    \62\ EIA Annual Energy Outlook 2006, Table 1.
---------------------------------------------------------------------------

C. Feasibility of the RFS Program Volume Obligations

    This section examines whether there are any feasibility issues
associated with the meeting the minimum renewable fuel requirements of
the Energy Act. Issues are examined with respect to renewable
production capacity, cellulosic ethanol production capacity, and
distribution system capability. Land resource requirements are
discussed in Chapter 7 of the RIA.
1. Production Capacity of Ethanol and Biodiesel
    As shown in Sections VI.A. and VI.B., increases in renewable fuel
production capacity are already proceeding at a pace significantly
faster than required to meet the 2012 mandate in the Act of 7.5 billion
gallons as well as the mandate (starting in 2013) of a minimum of 250
million gallons of cellulosic ethanol. The combination of ethanol and
biodiesel plants in existence and planned or under construction is
expected to provide a total renewable fuel production capacity of over
9.6 billion gallons by the end of 2012. Production capacity is expected
to continue to increase in response to strong demand. We estimate that
this will require a maximum of 2,100 construction workers and 90
engineers on a monthly basis through 2012.
2. Technology Available To Produce Cellulosic Ethanol
    There are a wide variety of government and renewable fuels industry
research and development programs dedicated to improving our ability to
produce renewable fuels from cellulosic feedstocks. In this discussion,
we deal with at least three completely different approaches to
producing ethanol from cellulosic biomass. The first is based on what
NREL refers to as the ``sugar platform,'' \63\ which refers to
pretreating the biomass, then hydrolyzing the cellulosic and
hemicellulosic components into sugars, and then fermenting the sugars
into ethanol.
---------------------------------------------------------------------------

    \63\ Enzyme Sugar Platform (ESP), Project Next Steps National
Renewable Energy, Dan Schell, FY03 Review Meeting; Laboratory
Operated for the U.S. Department of Energy by Midwest Research
Institute  B NREL, Golden, Colorado, May 1-2, 2003; U.S.
Department of Energy by Midwest Research Institute  Battelle
 Bechtel.
---------------------------------------------------------------------------

    Corn grain is a nearly ideal feedstock for producing ethanol by
fermentation, especially when compared with cellulosic biomass
feedstocks. Corn grain is easily ground into small particles, following
which the exposed starch which has [alpha]-linked saccharide polymers
is easily hydrolyzed into

simple, single component sugar which can then be easily fermented into
ethanol. By comparison, the biomass lignin structure must be either
mechanically or chemically broken down to permit hydrolyzing chemicals
and enzymes access to the saccharide polymers. The central problem is
that the cellulose/hemicellulose saccharide polymers are [beta]-linked
which makes hydrolysis much more difficult. Simple microbial
fermentation used in corn sugar fermentation is also not possible,
since the cellulose and hemicellulose (6 & 5 carbon molecules,
respectively) have not been able to be fermented by the same microbe.
We discuss various pretreatment, hydrolysis and fermentation
technologies, below. The second and third approaches have nothing to do
with pretreatment, acids, enzymes, or fermentation. The second is
sometimes referred to as the ``syngas'' or ``gas-to-liquid'' approach;
we will call it the ``Syngas Platform.'' Briefly, the cellulosic
biomass feedstock is steam-reformed to produce syngas which is then
converted to ethanol over a Fischer-Tropsch catalyst. The third
approach uses plasma technology.
a. Sugar Platform
    Plant cell walls are made up of cellulose and hemicellulose
polymers embedded in a lignin matrix. This complex structure prevents
both the first step, hydrolyzation of the cellulose and hemicellulose
polymers, and the second step, fermentation of the hydrolyzed sugars
into ethanol.
i. Pretreatment
    Those who wish to use cellulosic biomass feedstocks to produce
ethanol face several, difficult problems. The lignin sheath, present in
all cellulosic materials, prevents, or at the very least, severely
restricts hydrolysis. To produce ethanol from cellulosic biomass
feedstocks by fermentation, some type of thermo-mechanical, mechanical,
chemical or a combination of these pretreatments is always necessary
before the cellulosic and hemicellulosic polymers can be hydrolyzed. In
effect, the lignin structure must be ``opened'' to allow efficient and
effective strong acid hydrolysis, weak acid hydrolysis, or weak acid
enzymatic hydrolysis of the cellulose/hemicellulose to their glucose
and xylose sugar components. Over time, many pretreatment methods or
combinations of methods have been tried, some with more success than
others. Usually, intense physical pretreatments such as steam explosion
are required; grasses and forest thinnings usually need to be chipped,
prior to chemical or enzymatic hydrolysis. The most common chemical
pretreatments for cellulosic feedstocks are strong acid, dilute acid,
caustic, organic solvents, ammonia, sulfur dioxide, carbon dioxide or
other chemicals which make the biomass more accessible to the enzymes.
Following pretreatment, acidic (dilute and concentrated) and enzymatic
hydrolysis are the two process types commonly used to hydrolyze
cellulosic feedstocks before fermentation into ethanol.\64\
---------------------------------------------------------------------------

    \64\ Appendix B, Overview of Cellulose-Ethanol Production
Technology; OREGON CELLULOSE-ETHANOL STUDY, An evaluation of the
potential for ethanol production in Oregon using cellulose-based
feedstocks; Prepared by: Angela Graf, Bryan & Bryan Inc., 5015 Red
Gulch, Cotopaxi, Colorado 81223; Tom Koehler, Celilo Group, 2208
S.W. First Ave, 320, Portland, Oregon 97204; For submission
to: The Oregon Office of Energy.
---------------------------------------------------------------------------

ii. Dilute Acid Hydrolysis
    Dilute acid hydrolysis is the oldest technology for converting
cellulose biomass to ethanol. The dilute acid process uses a 1-percent
sulfuric acid in a continuous flow reactor at about 420 [deg]F;
reaction times are measured in seconds and minutes, which facilitates
continuous processing. The process involves two reactions with a sugar
conversion efficiency of about 50 percent. The process conditions at
which the cellulosic molecules are converted into sugar are also those
at which the sugar is almost immediately converted into other
chemicals, principally furfural. The rapid conversion to furfural
reduces the sugar yield, which along with other by-products inhibits
the fermentation process. One way to decrease sugar degradation is to
use a two-stage process which takes advantage of the fact that
hemicellulose (5-carbon) sugars degrade more rapidly than cellulose (6-
carbon) sugars. The first stage is conducted under mild process
conditions to recover the 5-carbon sugars, while the second stage is
conducted under harsher conditions to recover the 6-carbon sugars. Both
hydrolyzed solutions are then fermented to ethanol. Lime is used to
neutralize the residual acid before the fermentation stage. Regardless,
some sugar degrades to furfural, which naturally limits the net yield
of ethanol. The residual cellulose and lignin are used as boiler fuel
for electricity or steam production.\65\
---------------------------------------------------------------------------

    \65\ Ibid.
---------------------------------------------------------------------------

iii. Concentrated acid hydrolysis
    Concentrated acid hydrolysis uses a 70-percent sulfuric acid
solution, followed by water hydrolysis to convert the cellulose into
sugar. The process rapidly, and nearly completely, converts cellulose
to glucose (6-carbon) and hemicellulose to xylose (5-carbon) sugar,
with little degradation to furfural; the reaction times are typically
slower than those of the dilute acid process. The critical factors
needed to make this process economically viable are to optimize sugar
recovery and cost effectively recover the acid for recycling. The
concentrated acid process is somewhat more complicated and requires
more time, but it has the primary advantage of yielding up to about 90%
of both hemicellulosic and cellulosic sugars.\66\ In addition, a
significant advantage of the concentrated acid process is that it is
carried out at relatively low temperatures, about 212 [deg]F, and low
pressure, such that fiberglass reactors and piping can be used.
---------------------------------------------------------------------------

    \66\ Ibid.
---------------------------------------------------------------------------

iv. Enzymatic hydrolysis
    Enzymatic hydrolysis is not necessarily a recent discovery. We
found reports of research conducted by a variety of companies and
government agencies going back to at least 1991. 67 68 69
The enzymatic hydrolysis of cellulose was reportedly discovered when a
fungus, trichoderma reesei, was identified which produced cellulase
enzymes that broke down cotton clothing and tents in the South Pacific
during World War II. Since then, generations of cellulases have been
developed through genetic modifications of the fungus strain. As in
acid hydrolysis, the hydrolyzing enzymes must have access to the
cellulose and hemicellulose in order to work efficiently. Although
enzymatic hydrolysis requires some kind of pretreatment, purely
physical pretreatments are typically not adequate. Furthermore, the
chemical method uses dilute sulfuric acid, which is poisonous to the
fermentation

microorganisms and must be detoxified. While original enzymatic
hydrolysis processes used separate hydrolysis and fermentation steps,
recent process improvements integrate saccharification and fermentation
by combining the cellulase enzymes and fermenting microbes in one
vessel. This results in a one-step process of sugar production and
fermentation, referred to as the simultaneous saccharification and
fermentation (SSF) process. One disadvantage is that the cellulase
enzyme and fermentation organism must operate under the same process
conditions, which could decrease the sugar and, ultimately, the ethanol
yields. An alternative to the SSF technology is the sequential
hydrolysis and fermentation (SHF) process. The separation of hydrolysis
and fermentation enables enzymes to operate at higher temperatures in
the hydrolysis step to increase sugar production and more moderate
temperatures in the fermentation step to optimize the conversion of
sugar into ethanol.
---------------------------------------------------------------------------

    \67\ Technical and Economic Analysis Of An Enzymatic Hydrolysis
Based Ethanol Plant, Fuels and Chemicals Research and Engineering
Division, Solar Energy Research Institute, Golden CO, 80401, June
1991  DRAFT  SERI Protected Proprietary Information
 Do Not Copy.
    \68\ Biomass to Ethanol Process Evaluation, A report prepared
for National Renewable Energy Laboratory, December 1994; Chem
Systems Inc. 303 South Broadway, Tarrytown, New York, 10591.
    \69\ Lignocellulosic Biomass to Ethanol Process Design and
Economics Utilizing Co-Current Dilute Acid Prehydrolysis and
Enzymatic Hydrolysis Current and Futuristic Scenarios, July 1999
 NREL/TP-580-26157; Robert Wooley, Mark Ruth, John Sheehan,
and Kelly Ibsen, Biotechnology Center for Fuels and Chemicals; Henry
Majdeski and Adrian Galvez, Delta-T Corporation; National Renewable
Energy Laboratory, 1617 Cole Boulevard, Golden, Colorado 80401-3393;
NREL is a U.S. Department of Energy Laboratory Operated by Midwest
Research Institute  Battelle  Bechtel; Contract No.
DE-AC36-98-GO10337.
---------------------------------------------------------------------------

    Cost-effective cellulase enzymes must also be developed for this
technology to be completely successful.\70\ Several companies are using
variations of these technologies to develop processes for converting
cellulosic biomass into ethanol by way of fermentation. A few groups,
using recently developed genome modifying technology, have been able to
produce a variety of new or modified enzymes and microbes that show
promise for use in weak- or dilute-acid enzymatic-prehydrolysis.
Another problem with cellulosic feedstocks is, as previously described,
that the hydrolysis reactions produce both glucose, the six-carbon
sugar, and xylose, the five-carbon sugar (pentose sugar,
C5H10O5; sometimes called ``wood
sugar''). Early conversion technology required different microbes to
ferment each sugar. Recent research has developed better fermenting
organisms. Now, glucose and xylose can be co-fermented--hence, the
present-day terminology: Weak-acid enzymatic hydrolysis and co-
fermentation.
---------------------------------------------------------------------------

    \70\ Ibid.
---------------------------------------------------------------------------

b. Syngas Platform
    The second platform for producing cellulosic ethanol is to convert
the biomass into a syngas which is then converted into ethanol. A
``generic'' syngas process is essentially a ``steam reformer,'' which
``gasifies'' biomass and other carbon based substances including
wastes, in a reduced-oxygen environment and reacts them with steam to
produce a synthesis gas or ``syngas'' consisting primarily of carbon
monoxide and hydrogen. The syngas is then passed over in a Fischer-
Tropsch catalyst to produce ethanol.
    The biomass feedstock is dried to about 15% moisture content and
ground small enough to be efficiently burned and reacted in the
reformer. The reformer, an important upstream element of the process,
is essentially a common solid-fuel gasifier, which with some
modification and steam injection becomes what is sometimes referred to
as the ``primary reformer.''
    When any fuel is completely burned, all of its potential energy is
released as heat which can be recovered for immediate use. In a common
gasification process, the partially burned fuel (wood or coal) releases
a small amount of heat, but leaves some uncombusted, gaseous products.
Ordinarily, the hot product gases are fed directly to a nearby boiler
or gas turbine, to do work; it has been reported that for a well-
designed system, the overall efficiency may approach that of a solid
fuel boiler. However, when steam is injected into the gasifier, it
reacts with the burning solid fuel to produce more gaseous product. The
primary reaction is between carbon and water which produces hydrogen
and carbon monoxide and an inorganic ash. The ash and heavy
hydrocarbon-tars are removed from the raw syngas before it is
compressed and passed over Fisher-Tropsch catalyst to produce ethanol.
Fisher-Tropsch technology has been used for many years in the chemical
and refining industries, most notably to produce gasoline and diesel
fuel from syngas produced by coal gasification. Whether the Fischer-
Tropsch reaction produces diesel or ethanol is primarily the result of
changes to process pressure, temperature and in some cases the use of
custom catalysts. In most cases, the Fischer-Tropsch process did not
produce pure ethanol in the first pass through the system. Rather, a
stream of mixed chemicals was produced, including gasoline, diesel, and
oxygenated hydrocarbons (alcohol).\71\
---------------------------------------------------------------------------

    \71\ Gridley Ethanol Demonstration Project Utilizing Biomass
Gasification Technology: Pilot Plant Gasifier and Syngas Conversion
Testing, August 2002-June 2004; February 2005  NREL/SR-510-
37581; TSS Consultants, For the City of Gridley, California, 1617
Cole Boulevard, Golden, Colorado 80401-3393,<PHONE_NUMBER>
http://www.nrel.gov; Operated for the U.S. Department of Energy

Office of Energy Efficiency and Renewable Energy by Midwest Research
Institute  Battelle Contract No. DE-AC36-99-GO10337.
---------------------------------------------------------------------------

c. Plasma Technology
    The development of another technology, called plasma, is also
underway for creating a syngas from which ethanol is produced. A plasma
``reactor,'' generates an ionized gas (plasma) which serves as an
electrical conductor to transfer intense radiant energy to a biomass or
waste material. This intense energy is said to actually breakdown the
various materials in the biomass or waste into their atomic components.
Anything present in the feed-mass that doesn't gasify, is essentially
``vitrified.'' This vitrified stream is reportedly inert and can be
used as aggregate in paving materials. Following gasification, the
syngas is cooled, impurities are removed, and the gas is sent to
ethanol production as with the syngas platform described above.\72\
---------------------------------------------------------------------------

    \72\ Ethanol From Tires Via Plasma Converter Plus Fischer
Tropsch, March 15, 2006; http://thefraserdomain.typepad.com/energy/2006/03/ethanol_from_ti.html
.

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

d. Feedstock Optimization
    Cellulosic biomass can come from a variety of sources. Because the
conversion of cellulosic biomass to ethanol has not yet been
commercially demonstrated, we cannot say at this time which feedstocks
are superior to others. A few of the many resources are: Post-sorted
municipal waste, rice and wheat straw,\73\ soft-woods, hardwood, switch
grass, and bagasse. Regardless, each feedstock requires a specific
combination of pretreatment methods and enzyme ``cocktails'' to
optimize the operation and maximize the ethanol yield. One of the many
challenges for the cellulose-ethanol industry is to find the best
feedstocks and then develop the most cost-effective ways for converting
them into ethanol.
---------------------------------------------------------------------------

    \73\ Wheat Straw for Ethanol Production in Washington: A
Resource, Technical, and Economic Assessment, September 2001,
WSUCEEP2001084; Prepared by: James D. Kerstetter, Ph.D., John Kim
Lyons, Washington State University Cooperative Extension Energy
Program, 925 Plum Street, SE., P.O. Box 43165, Olympia, WA 98504-
3165; Prepared for: Washington State Office of Trade and Economic
Development.
---------------------------------------------------------------------------

3. Renewable Fuel Distribution System Capability
    Ethanol and biodiesel blended fuels are currently not shipped by
petroleum product pipeline due to operational issues and additional
cost factors. Hence, a separate distribution system is needed for
ethanol and biodiesel up to the point where they are blended into
petroleum-based fuel as it is loaded into tank trucks for delivery to
retail and fleet operators. In cases where ethanol and biodiesel are
produced within 200 miles of a terminal, trucking is often the
preferred means of distribution. For longer shipping distances, the
preferred

method of bringing renewable fuels to terminals is by rail and barge.
    Modifications to the rail, barge, tank truck, and terminal
distribution systems will be needed to support the transport of the
anticipated increased volumes of renewable fuels. These modifications
include the addition of terminal blending systems for ethanol and
biodiesel, additional storage tanks at terminals, additional rail
delivery systems at terminals for ethanol and biodiesel, and additional
rail cars, barges, and tank trucks to distribute ethanol and biodiesel
to terminals. Terminal storage tanks for 100 percent biodiesel will
also need to be heated during cold months to prevent gelling. The most
comprehensive study of the infrastructure requirements for an expanded
fuel ethanol industry was conducted for the Department of Energy (DOE)
in 2002.\74\ The conclusions reached in that study indicate that the
changes needed to handle the anticipated increased volume of ethanol by
2012 will not represent a major obstacle to industry. While some
changes have taken place since this report was issued, including an
increased reliance on rail over marine transport, we continue to
believe that the rail and marine transportation industries can manage
the increased growth in demand in an orderly fashion. This belief is
supported by the demonstrated ability for the industry to handle the
rapid increases and redistribution of ethanol use across the country
over the last several years as MTBE was removed. The necessary facility
changes at terminals and at retail stations to dispense ethanol
containing fuels have been occurring at a record pace. Given that
future growth is expected to progress at a steadier pace and with
greater advance warning in response to economic drivers, we anticipate
that the distribution system will be able to respond appropriately. A
discussion of the costs associated making the changes discussed above
is contained in Section VII.B of today's preamble.
---------------------------------------------------------------------------

    \74\ ``Infrastructure Requirements for an Expanded Fuel Ethanol
Industry,'' Downstream Alternatives Inc., January 15, 2002.
---------------------------------------------------------------------------

VII. Impacts on Cost of Renewable Fuels and Gasoline

    This section examines the impact on fuel costs resulting from the
growth in renewable fuel use between a base year of 2004 and 2012. We
note that based on analyses conducted by the Energy Information
Administration (EIA), renewable fuels will be used in gasoline and
diesel fuel in excess of the RFS requirements. As such, the changes in
the use of renewable fuels and their related cost impacts are not
directly attributable to the RFS rule. Rather, our analysis assesses
the broader fuels impacts of the growth in renewable fuel use in the
context of corresponding changes to the makeup of gasoline. These fuel
impacts include the elimination of the reformulated gasoline (RFG)
oxygen standard which has resulted in the refiners ceasing to use the
gasoline blendstock methyl tertiary butyl ether (MTBE) and replacing it
with ethanol. Thus, in this analysis, we are assessing the impact on
the cost of gasoline and diesel fuel of increased use of renewable
fuels, the cost savings resulting from the phase out of MTBE and the
increased cost due to the other changes in fuel quality that result.
    As discussed in Section II, we chose to analyze a range of
renewable fuel use. In the case of ethanol's use in gasoline, the lower
end of this range is based on the minimum renewable fuel volume
requirements in the Act, (the RFS case) and the higher end is based on
AEO 2006 (the EIA case). At both ends of this range, we assume that
biodiesel consumption will be the level estimated in AEO 2006. We
analyzed the projected fuel consumption scenario and associated program
costs in 2012, the year that the RFS is fully phased-in. The volumes of
renewable fuels consumed in 2012 at the two ends of the range are
summarized in Table II.A.1-1.
    We have estimated an average corn ethanol production cost of $1.26
per gallon in 2012 (2004 dollars) for the RFS case and $1.32 per gallon
for the EIA case. For cellulosic ethanol, we estimate it will cost
approximately $1.65 in 2012 (2004 dollars) to produce a gallon of
ethanol using corn stover as a cellulosic feedstock. In this analysis,
however, we assume that the cellulosic requirement will be met by corn-
based ethanol produced by energy sourced from biomass (animal and other
waste materials as discussed in Section III.B of today's preamble) and
costing the same as corn based ethanol produced by conventional means.
    We estimated production costs for soy-derived biodiesel of $2.06
per gallon in 2004 and $1.89 per gallon in 2012. For yellow grease
derived biodiesel, we estimate an average production cost of $1.19 per
gallon in 2004 and $1.11 in 2012.
    For the proposed rule, we estimated the cost of increased use of
renewable fuel and other major cost impacts by developing our own cost
spreadsheet model. That analysis considered the production cost,
distribution cost as well as the cost for balancing the octane and RVP
caused by these fuel changes. That analysis, however, could not
properly balance octane and other gasoline qualities. For this final
rule, we have therefore used the services of Jacobs Consultancy to run
their refinery LP model to estimate the cost impacts of the RFS rule.
    The results from the refinery LP model indicate that the impacts on
overall gasoline costs from the increased use of ethanol and the
corresponding changes to the other aspects of gasoline would be 0.49
cents per gallon for the RFS case. The EIA case would result in
increased total cost of 1.03 cents per gallon. The actual cost at the
fuel pump, however, will be decreased due to the effect of State and
Federal tax subsidies for ethanol. Taking this into consideration
results in ``at the pump'' decreased costs (cost savings) of -0.47
cents per gallon for the RFS case and ``at the pump'' decreased cost of
-0.83 cents per gallon for the EIA case. Section 7 of the RIA contains
more detail on the cost analysis used to develop these costs.

A. Renewable Fuel Production and Blending Costs

1. Ethanol Production Costs
a. Corn Ethanol
    A significant amount of work has been done in the last decade on
surveying and modeling the costs involved in producing ethanol from
corn to serve business and investment purposes as well as to try to
educate energy policy decisions. Corn ethanol costs for our work were
estimated using a model developed by USDA in the 1990s that has been
continuously updated by USDA. The most current version was documented
in a peer-reviewed journal paper on cost modeling of the dry-grind corn
ethanol process, and it produces results that compare well with cost
information found in surveys of existing plants.75 76 We
made some minor modifications to the USDA model to allow scaling of the
plant size, to allow consideration of plant energy sources other than
natural gas, and to adjust for energy prices in 2012, the year of our
analysis.
---------------------------------------------------------------------------

    \75\ Kwaitkowski, J.R., McAloon, A., Taylor, F., Johnston, D.B.,
Industrial Crops and Products 23 (2006) 288-296.
    \76\ Shapouri, H., Gallagher, P., USDA's 2002 Ethanol Cost-of-
Production Survey (published July 2005).
---------------------------------------------------------------------------

    The cost of ethanol production is most sensitive to the prices of
corn and the primary co-product, DDGS. Utilities, capital, and labor
expenses also have an impact, although to a lesser extent. Corn
feedstock minus DDGS sale credits

represents about 48% of the final per-gallon cost, while utilities,
capital and labor comprise about 19%, 9%, and 6%, respectively. For
this work, we used corn prices of $2.50/bu and $2.71/bu for the RFS and
EIA cases, respectively, with corresponding DDGS prices at $83.35/ton
and $85.16/ton (2004 dollars). These estimates are from modeling work
done for this rulemaking using the Forestry and Agricultural Sector
Optimization Model, which is described in more detail in Chapter 8 of
the RIA. Energy prices were derived from historical data and projected
to 2012 using EIA's AEO 2006. More details on how the ethanol
production cost estimates were made can be found in Chapter 7 of the
RIA.
    The estimated average corn ethanol production cost of $1.26 per
gallon in 2012 (2004 dollars) in the RFS case and $1.32 per gallon in
the EIA case 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. It assumes that 86% of new plants will use natural gas
as a thermal energy source, at a price of $6.16/MMBtu (2004
dollars).\77\ It does not account for any subsidies on production or
sale of ethanol. Note that the cost figure generated here is
independent of the market price of ethanol, which has been related
closely to the wholesale price of gasoline for the past
decade.78 79
---------------------------------------------------------------------------

    \77\ For more details on fuel sources and costs of production,
see RIA Chapter 1.2.2 and <IP_ADDRESS>.
    \78\ Whims, J., Sparks Companies, Inc. and Kansas State
University, ``Corn Based Ethanol Costs and Margins, Attachment 1''
(Published May 2002).
    \79\ Piel, W.J., Tier & Associates, Inc., March 9, 2006 report
on costs of ethanol production and alternatives.
---------------------------------------------------------------------------

    Under the Energy Act, starch-based ethanol can be counted as
cellulosic if at least 90% of the process energy is derived from
renewable feedstocks, which include plant cellulose, municipal solid
waste, and manure biogas.\80\ It is expected that the vast majority of
the 250 million gallons per year of cellulosic ethanol production
required by 2013 will be made using this provision. While we have been
unable to develop a detailed production cost estimate for corn ethanol
meeting cellulosic criteria, we assume that the costs will not be
significantly different from conventionally produced corn ethanol. We
believe this is reasonable because the costs of hauling, storing, and
processing this low or zero cost waste material in order to combust it
will be significant, thus making overall production costs at these
plants similar to gas-fired ethanol plants. As of the time of this
writing, we know of only a few operating plants of this type, and
expect the quantity of ethanol produced this way to remain a relatively
small fraction of the total ethanol demand. Thus, the sensitivity of
the overall analysis to this assumption is also very small.\81\ Based
on these factors, we have assigned starch ethanol made using this
cellulosic criteria the same cost as ethanol produced from corn using
conventional means.
---------------------------------------------------------------------------

    \80\ Energy Policy Act of 2005, Section 1501 amending Clean Air
Act Section 211(o)(1)(A).
    \81\ See Table VI.A.1-2 for more details on number of operating
ethanol plants and their fuel sources.
---------------------------------------------------------------------------

b. Cellulosic Ethanol
    In 1999, the National Renewable Energy Laboratory (NREL) published
a report outlining its work with the USDA to design a computer model of
a plant to produce ethanol from hard-wood chips.\82\ Although the model
was originally prepared for hardwood chips, it was meant to serve as a
modifiable-platform for ongoing research using cellulosic biomass as
feedstock to produce ethanol. Their long-term plan was that various
indices, costs, technologies, and other factors would be regularly
updated.
---------------------------------------------------------------------------

    \82\ Lignocellulosic Biomass to Ethanol Process Design and
Economics Utilizing Co-Current Dilute Acid Prehydrolysis and
Enzymatic Hydrolysis Current and Futuristic Scenarios, Robert
Wooley, Mark Ruth, John Sheehan, and Kelly Ibsen, Biotechnology
Center for Fuels and Chemicals, Henry Majdeski and Adrian Galvez,
Delta-T Corporation; National Renewable Energy Laboratory, Golden,
CO, July 1999, NREL/TP-580-26157.
---------------------------------------------------------------------------

    NREL and USDA used a modified version of the model to compare the
cost of using corn-grain with the cost of using corn stover to produce
ethanol. We used the corn stover model from the second NREL/USDA study
for the analysis for this rule. Because there were no operating plants
that could potentially provide real world process design, construction,
and operating data for processing cellulosic ethanol, NREL had
considered modeling the plant based on assumptions associated with a
first-of-a-kind or pioneer plant. The literature indicates that such
models often underestimate actual costs since the high performance
assumed for pioneer process plants is generally unrealistic.
    Instead, the NREL researchers assumed that the corn stover plant
was an Nth generation plant, e.g., not a pioneer plant or first-or-its
kind, built after the industry had been sufficiently established to
provide verified costs. The corn stover plant was normalized to the
corn kernel plant, e.g., placed on a similar basis.\83\ It is also
reasonable to expect that the cost of cellulosic ethanol would be
higher than corn ethanol because of the complexity of the cellulose
conversion process. Recently, process improvements and advancements in
corn production have considerably reduced the cost of producing corn
ethanol. We also believe it is realistic to assume that cellulose-
derived ethanol process improvements will be made and that one can
likewise reasonably expect that, as the industry matures, the cost of
producing ethanol from cellulose will also decrease.
---------------------------------------------------------------------------

    \83\ Determining the Cost of Producing Ethanol from Corn Starch
and Lignocellulosic Feedstocks; A Joint Study Sponsored by: USDA and
USDOE, October 2000  NREL/TP-580-28893  Andrew
McAloon, Frank Taylor, Winnie Yee, USDA, Eastern Regional Research
Center Agricultural Research Service; Kelly Ibsen, Robert Wooley,
National Renewable Energy Laboratory, Biotechnology Center for Fuels
and Chemicals, 1617 Cole Boulevard, Golden, CO, 80401-3393; NREL is
a USDOE Operated by Midwest Research Institute  Battelle
 Bechtel; Contract No. DE-AC36-99-GO10337.
---------------------------------------------------------------------------

    We calculated fixed and variable operating costs using percentages
of direct labor and total installed capital costs. Following this
methodology, we estimate that producing a gallon of ethanol using corn
stover as a cellulosic feedstock would cost $1.65 in 2012 (2004
dollars).
2. Biodiesel Production Costs
    We based our estimate for the cost to produce biodiesel on the use
of USDA's, NREL's and EIA's biodiesel computer models, along with
estimates from engineering vendors that design biodiesel plants.
Biodiesel fuel can be made from a wide variety of virgin vegetable oils
such as canola, corn oil, cottonseed, etc. though, the operating costs
(minus the costs of the feedstock oils) for these virgin vegetable oils
are similar to the costs based on using soy oil as a feedstock,
according to an analysis by NREL Biodiesel costs are therefore
determined based on the use of soy oil, since this is the most commonly
used virgin vegetable feedstock oil, and the use of recycled cooking
oil (yellow grease) as a feedstock. Production costs are based on the
process of continuous transesterification, which converts these
feedstock oils to esters, along with the ester finishing processes and
glycerol recovery. The models and vendors data are used to estimate the
capital, fixed and operating costs associated with the production of
biodiesel fuel, considering utility, labor, land and any other process
and operating requirements, along with the prices for

feedstock oils, methanol, chemicals and the byproduct glycerol.
    The USDA, NREL and EIA models are based on a medium sized biodiesel
plant that was designed to process raw degummed virgin soy oil as the
feedstock. Additionally, the EIA model also contains a representation
to estimate the biodiesel production cost for a plant that uses yellow
grease as a feedstock. In the USDA model, the equipment needs and
operating requirements for their biodiesel plant was estimated through
the use of process simulation software. This software determines the
biodiesel process requirements based on the use of established
engineering relationships, process operating conditions and reagent
needs. To substantiate the validity and accuracy of their model, USDA
solicited feedback from major biodiesel producers. Based on responses,
they then made adjustments to their model and updated their input
prices to year 2005. The NREL model is also based on process simulation
software, though the results are adjusted to reflect NREL's modeling
methods, using prices based on year 2002. The output for all of these
models was provided in spreadsheet format. We also use engineering
vendor estimates as another source to generate soy oil and yellow
grease biodiesel production costs. These firms are primarily engaged in
the business of designing biodiesel plants.
    The production costs are based on an average biodiesel plant
located in the Midwest using feedstock oils and methanol, which are
catalyzed into esters and glycerol by use of sodium hydroxide. Because
local feedstock costs, distribution costs, and biodiesel plant type
introduce some variability into cost estimates, we believe that using
an average plant to estimate production costs provides a reasonable
approach. Therefore, we simplified our analysis and used costs based on
an average plant and average feedstock prices since the total biodiesel
volumes forecasted are not large and represent a small fraction of the
total projected renewable volumes.
    The models and vendor estimates are further modified to use input
prices for feedstocks, byproducts and energy that reflect the effects
of the fuels provisions in the Energy Act. In order to capture a range
of production costs, we generated cost projections from all of the
models and vendors. We present the details on these estimates in
Chapter 7 of the RIA.
    For soy oil biodiesel production, we estimate a production cost
ranging from $1.89 to $2.15 per gallon in 2012 (in 2004 dollars) using
these different models and sources of information. For yellow grease
derived biodiesel, we used the EIA and vendor estimates to generate
total production costs which range from $1.11 to $1.56 for year 2012.
    With the current Biodiesel Blender Tax Credit Program, producers
using virgin vegetable oil stocks receive a one dollar per gallon tax
subsidy while yellow grease producers receive 50 cents per gallon,
reducing the net production cost to a range of 89 to 115 cents per
gallon for soy oil and 61 to 106 cents per gallon for yellow greased
derived biodiesel fuel in 2012. This compares favorably to the
projected wholesale diesel fuel prices of 138 cents per gallon in 2012,
signifying that the economics for biodiesel are positive under the
effects of the blender credit program, though the tax credit program
will expire in 2008 if it is not extended. Congress may later elect to
extend the blender credit program following the precedence used for
extending the ethanol blending subsidies. Additionally, the Small
Biodiesel Blenders Tax credit program and state tax and credit programs
offer some additional subsidies and credits, though the benefits are
modest in comparison to the Blender's Tax credit.
3. Diesel Fuel Costs
    Biodiesel fuel is blended into highway and nonroad diesel fuel,
which increases the volume and therefore the supply of diesel fuel and
thereby reduces the demand for refinery-produced diesel fuel. In this
section, we estimate the overall cost impact, considering how much
refinery based diesel fuel is displaced by the forecasted production
volume of biodiesel fuel. The cost impacts are evaluated considering
the production cost of biodiesel with and without the subsidy from the
Biodiesel Blenders Tax credit program. Additionally, the diesel cost
impacts are quantified with refinery diesel prices as forecasted by
Jacob's which is based on EIA's AEO 2006.
    We estimate the net effect that biodiesel production has on overall
cost for diesel fuel in year 2012 using total production costs for
biodiesel and diesel fuel. The costs are evaluated based on how much
refinery based diesel fuel is displaced by the biodiesel volumes as
forecasted by EIA, accounting for energy density differences between
the fuels. The cost impact is estimated from a 2004 year basis, by
multiplying the production costs of each fuel by the respective changes
in volumes for biodiesel and estimated displaced diesel fuel. We
further assume that all of the forecasted biodiesel volume is used as
transport fuel, neglecting minor uses in the heating oil market.
    For RFS cases, the net effect of biodiesel production on diesel
fuel costs, including the biodiesel blenders' subsidy, is a reduction
in the cost of transport diesel fuel costs by $114 million per year,
which equates to a reduction in fuel cost of about 0.20 cents per
gallon.\84\ Without the subsidy, the transport diesel fuel costs are
increased by $91 million per year, or an increase of 0.16 cents per
gallon for transport diesel fuel.
---------------------------------------------------------------------------

    \84\ Based on EIA's AEO 2006, 58.9 billion gallons of highway
and off-road diesel fuel is projected to be consumed in 2012.
---------------------------------------------------------------------------

B. Distribution Costs

1. Ethanol Distribution Costs
    There are two components to the costs associated with distributing
the volumes of ethanol necessary to meet the requirements of the
Renewable Fuels Standard (RFS): (1) The capital cost of making the
necessary upgrades to the fuel distribution infrastructure system, and
(2) the ongoing additional freight costs associated with shipping
ethanol to terminals. The most comprehensive study of the
infrastructure requirements for an expanded fuel ethanol industry was
conducted for the Department of Energy (DOE) in 2002.\85\ That study
provided the foundation for our estimates of the capital costs
associated with upgrading the distribution infrastructure system as
well as the freight costs to handle the increased volume of ethanol
needed to meet the requirements of the RFS in 2012. Distribution costs
are evaluated here for both the RFS case and for the EIA case. The 2012
reference case against which we are estimating the cost of distributing
the additional volume of ethanol needed to meet the requirements of the
RFS is 3.9 billion gallons.
---------------------------------------------------------------------------

    \85\ Infrastructure Requirements for an Expanded Fuel Ethanol
Industry, Downstream Alternatives Inc., January 15, 2002.
---------------------------------------------------------------------------

a. Capital Costs To Upgrade Distribution System for Increased Ethanol
Volume
    The 2002 DOE study examined two cases regarding the use of
renewable fuels for estimating the capital costs for distributing
additional ethanol. The first assumed that 5.1 billion gal/yr of
ethanol would be used in 2010, and the second assumed that 10 billion
gal/yr of ethanol would be used in the 2015 timetable. We interpolated
between these two cases to provide the foundation for our estimate of
the capital costs to support the use of 6.7 billion gal/yr of ethanol
in 2012 for the

RFS case.\86\ The 10 billion gal/yr case examined in the DOE study was
used as the foundation in estimating the capital costs under the EIA
projected case examined in today's rule of 9.6 billion gal/yr of
ethanol.\87\ Our estimated capital costs in this final rule differ from
those in the proposed rule for several reasons. We adjusted our capital
costs from those in the proposal to reflect an increase in the cost of
tank cars and barges used to ship ethanol since the DOE study was
conducted. In addition, we are assuming an increased reliance on rail
transport over that projected in the DOE study.\88\
---------------------------------------------------------------------------

    \86\ See chapter 7.3 of the Regulatory Impact Analysis
associated with today's rule for additional discussion of how the
results of the DAI study were adjusted to reflect current conditions
in estimating the ethanol distribution infrastructure capital costs
under today's rule.
    \87\ For both the 6.7 bill gal/yr and 9.6 bill gal/yr cases, the
baseline from which the DOE study cases were projected was adjusted
to reflect a 3.9 bill gal/yr 2012 baseline.
    \88\ This increased reliance on rail transport was the subject
of a sensitivity analysis conducted for the proposed rule.
---------------------------------------------------------------------------

    Table VII.B.1.a-1contains our estimates of the infrastructure
changes and associated capital costs for the two ethanol use scenarios
examined in today's rule. Amortized over 15 years with a 7 percent cost
of capital, the total capital costs equate to approximately 1.4 cents
per gallon of ethanol under the RFS case and 1.2 cents per gallon under
the EIA case.\89\
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    \89\ These capital costs will be incurred incrementally during
the period of 2007-2012 as ethanol volumes increase. For the purpose
of this analysis, we assumed that all capital costs were incurred in
2007.

    Table VII.B.1.A-1.--Estimated Ethanol Distribution Infrastructure
                          Capital Costs ($M) *
------------------------------------------------------------------------
                                                  RFS case     EIA case
                                                6.7 Bgal/yr  9.6 Bgal/yr
------------------------------------------------------------------------
Fixed Facilities:
  Retail......................................           20           44
  Terminals...................................          115          241
Mobile Facilities:
  Transport Trucks............................           24           50
  Barges......................................           21           43
  Rail Cars...................................          172          297
                                               -------------------------
    Total Capital Costs.......................          352         675
------------------------------------------------------------------------
* Relative to a 3.9 billion gal/yr reference case.

b. Ethanol Freight Costs
    The Energy Information Administration (EIA) translated the ethanol
freight cost estimates in the DOE study to a census division basis.\90\
For this final rule, we translated the EIA projections into State-by-
State and national average freight costs to align with our State-by-
State ethanol use estimates. Not including capital recovery, we
estimate that the freight cost to transport ethanol to terminals would
range from 4 cents per gallon in the Midwest to 25 cents per gallon to
the West Coast. On a national basis, this averages to 11.3 cents per
gallon of ethanol under the RFS case and 11.9 cents per gallon under
the EIA case.\91\ We adjusted the estimated ethanol freight costs from
those in the proposal by increasing the cost of shipping ethanol to
satellite versus hub terminals, by increasing the cost of gathering
ethanol for large volume shipments to hub terminals, and by increasing
the percentage of ethanol delivered to large volume terminals versus
the volume delivered to lesser volume terminals.\92\
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    \90\ Petroleum Market Model of the National Energy Modeling
System, Part 2, March 2006, DOE/EIA-059 (2006), http://tonto.eia.doe.gov/FTPROOT/modeldoc/m059
(2006)-2.pdf.

    \91\ See Chapter 7.3 of the RIA.
    \92\ Hub terminals refer to those terminals where ethanol is
delivered in large volume shipments such as by unit train
(consisting of 70 tank cars or more) or marine barges/tanker.
Satellite terminals are those terminals that are either supplied
from a hub terminal or receive ethanol shipments in smaller
quantities directly from the producer. See Chapter 7 of the RIA
regarding how these estimates were adjusted from those in the
proposal and the check of our estimates against current ethanol
freight rates.
---------------------------------------------------------------------------

    Including the cost of capital recovery for the necessary
distribution facility changes, we estimate the national average cost of
distributing ethanol to be 12.7 cents per gallon under the RFS case and
13.1 cents per gallon under the EIA case.\93\ Thus, we estimate the
total cost for producing and distributing ethanol to be between $1.39
and $1.45 per gallon of ethanol, on a nationwide average basis. This
estimate includes both the capital costs to upgrade the distribution
system and freight costs.
---------------------------------------------------------------------------

    \93\ All capital costs were assumed to be incurred in 2007 and
were amortized over 15 years at a 7 percent cost of capital.
---------------------------------------------------------------------------

2. Biodiesel Distribution Costs
    The volume of biodiesel used by 2012 under the RFS is estimated at
300 million gallons per year. The 2012 baseline case against which we
are estimating the cost of distributing the additional volume of
biodiesel is 30 million gallons.\94\
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    \94\ 2004 baseline of 25 million gallons grown with diesel
demand to 2012.
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    The capital costs associated with distribution of biodiesel are
higher per gallon than those associated with the distribution of
ethanol due to the need for storage tanks, blending systems, barges,
tanker trucks and rail cars to be insulated and in many cases heated
during the winter months.\95\ In the proposal, we estimated that these
capital costs would be approximately $50,000,000. We adjusted our
estimate of these capital costs for this final rule based on additional
information regarding the cost to install necessary storage and
blending equipment at terminals and the need for additional rail tank
cars for biodiesel.\96\ As discussed in the RIA, we now estimate that
handling the increased biodiesel volume will require a total capital
cost investment of $145,500,000 which equates to about 6 cents per
gallon of new biodiesel volume.\97\
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    \95\ See Chapter 1.3 of the Regulatory Impact Analysis
associated with today's rule for a discussion of the special
handling requirements for biodiesel under cold conditions.
    \96\ Biodiesel rail tank cars typically have a capacity of
25,500 gallons as opposed to 30,000 gallons for an ethanol tank car.
Thus, additional tank cars are needed to transport a given volume of
biodiesel relative to the same volume of ethanol.
    \97\ Capital costs will be incurred incrementally over the
period of 2007-2012 as biodiesel volumes increase. For the purpose
of this analysis, all capital costs were assumed to be incurred in
2007 and were amortized over 15 years at a 7 percent cost of
capital.
---------------------------------------------------------------------------

    In the proposal, we estimated that the freight costs for ethanol
may adequately reflect those for biodiesel as well. In response to
comments, we sought additional information regarding the freight costs
for biodiesel. This information indicates that freight costs for
biodiesel are typically 30 percent higher than those for ethanol which
translates into an estimate of 15.5 cents per gallon for biodiesel
freight costs on a national average basis.\98\
---------------------------------------------------------------------------

    \98\ The estimated ethanol freight costs were increased by 30
percent to arrive at the estimate of biodiesel freight costs.
---------------------------------------------------------------------------

    Including the cost of capital recovery for the necessary
distribution facility changes, we estimate the cost of distributing
biodiesel to be 21.5 cents per gallon. Depending on whether the
feedstock is waste grease or virgin oil, we estimate the total cost for
producing and distributing biodiesel to be between $1.33 and $2.11 per
gallon of biodiesel, on a nationwide average basis.\99\ This estimate
includes both the capital costs to upgrade the distribution system and
freight costs, and the wide range reflects differences in different
types of production feedstocks.
---------------------------------------------------------------------------

    \99\ See Section VII.A.2. of this preamble regarding biodiesel
production costs. We estimated 2012 production costs of $1.89 per
gal for soy-derived biodiesel and $1.11 per gal for yellow grease
derived biodiesel.
---------------------------------------------------------------------------

C. Estimated Costs to Gasoline

    To estimate the cost of increased use of renewable fuels, the cost
savings from the phase out of MTBE and the production cost of alkylate,
we relied on

refinery modeling conducted by Jacob's Consultancy that established
baselines based on 2004 volumes, which were then used to project a
reference case and 2 control cases for 2012. The contractor developed a
five region, U.S. demand model in which specific regional clean product
demands are sold at hypothetical regional terminals.
1. Description of Cases Modeled
a. Base Case (2004)
    The baseline case was established by modeling fuel volumes for
2004, with data on fuel properties provided to the contractor by EPA.
Fuel property data for this base case was built off of 2004 refinery
batch reports provided to EPA; however, the base case assumed sulfur
standards based on gasoline data in 2004, not with fully phased in Tier
2 gasoline standards at the 30 ppm level. In addition we assumed the
phase-in of 15 ppm sulfur standards for highway, nonroad, locomotive
and marine diesel fuel. The supply/demand balance for the U.S. was
based on gasoline volumes from EIA and the California Air Resources
Board (CARB). Our decision to use 2004 rather than 2005 as the baseline
year was because of the refinery upset conditions associated with the
Gulf Coast hurricanes in 2005.
b. Reference Case (2012)
    The reference case was based on modeling the base case, using 2012
fuel prices, and scaling the 2004 fuel volumes to 2012 based on growth
in fuel demand. In addition, we scaled MTBE and ethanol upward, in
proportion to gasoline growth, and assumed the RFS program would not be
in effect. For example, if the PADD 1 gasoline pool MTBE oxygen was 0.5
wt% in 2004, the reference case assumed it should remain at 0.5 wt%.
Finally, we assumed the MSAT 1 standards would remain in place as would
the RFG oxygen mandate. We assumed the crude slate quality in 2012 is
the same as the baseline case.
c. Control Cases (2012)
    Two control cases were run for 2012. The assumptions for each of
the control cases are summarized below
    Control Case 1 (RFS case): 6.7 billion gallons/yr (BGY) of ethanol
in gasoline; it reflects the renewable fuel mandate. We have also
assumed that 0.3 billion gallons of biodiesel will be consumed as
reflected in Table II.A.1-1. In addition, it is assumed that no MTBE is
in gasoline, MSAT1 is in place, the psi waiver for conventional
gasoline containing 10 volume percent ethanol is in effect, the RFS is
in effect, and there is no RFG oxygenate mandate.
    Control Case 2 (EIA case): Same as Control Case 1, except the
ethanol volume in gasoline is 9.6 BGY.
2. Overview of Cost Analysis Provided by the Contractor Refinery Model
    The estimated cost of increased use of renewable fuels, the cost
savings from the phase out of MTBE and the cost of converting some of
the former MTBE feedstocks to produce alkylate, isooctane, and
isooctene is provided by the output of the refinery model. As described
in VII.C.1, the cost analysis was conducted by comparing the 2012
reference case with the two control cases which are assumed to take
place in 2012.
    The major factors which impact the costs in the refinery model are
(1) blending in more ethanol, (2) adjusting the gasoline blending to
lower RVP, (3) removing the MTBE, (4) converting MTBE feedstocks to
other high quality replacement, and (5) adjusting for the change in
gasoline energy density. The first is the addition of ethanol to the
gasoline pool. The refinery model estimates the cost impact of
increasing the volume of ethanol in the reference case from 3.94
billion gallons to 6.67 and 9.60 billion gallons in the RFS and EIA
modeled cases, respectively. The estimated production prices for
ethanol for the RFS and EIA cases are provided above in Section VII.A.
We also show the results with the federal and state subsidies applied
to the production price of ethanol.
    The addition of ethanol to wintertime gasoline, and to summertime
RFG, will cause an increase of approximately 1 psi in RVP which needs
to be offset to maintain constant RVP levels. One method that refiners
could choose to offset the increase in RVP is to reduce the butane
levels in their gasoline. To some extent, the modeling results showed
some occurrences of that, but it also did not report an overall
increase in butane sales as a result of the increased use of ethanol.
    To convert the captive MTBE over to alkylate, after the rejection
of methanol, refiners will need to combine refinery-produced isobutane
with the isobutylene that was used as a feedstock for MTBE. The use of
the isobutane will reduce the RVP of the gasoline pool from which it
comes, helping to offset the RVP impacts of ethanol. Also, the
increased production of alkylate provides a low RVP gasoline blendstock
which offsets a portion of the cracked stocks produced by the fluidized
catalytic cracker unit. Other means that the refinery model used to
offset the high blending RVP of ethanol included purchasing gasoline
components with lower RVP, producing more poly gasoline which has low
RVP and selling more high-RVP naphtha to petrochemical sales.
3. Overall Impact on Fuel Cost
    Based on the refinery modeling conducted for today's rule, we have
calculated the costs of these fuels changes that will occur for the RFS
and EIA cases. The costs are expressed two different ways. First, we
express the cost of the program without the ethanol consumption
subsidies in which the costs are based on the total accumulated cost of
each of the fuels changes. Second, we express the cost with the ethanol
consumption subsidies included since the subsidized portion of the
renewable fuels costs will not be represented to the consumer in its
fuels costs paid at the pump, but instead by being paid through the
state and federal tax revenues. In all cases, the capital costs are
amortized at 7 percent return on investment (ROI), and based on 2006
dollars.
a. Cost Without Ethanol Subsidies
    Table VII.C.3.a-1 summarizes the costs without ethanol subsidies
for each of the two control cases, including the cost for each aspect
of the fuel changes, and the aggregated total and the per-gallon costs
for all the fuel changes.\100\ This estimate of costs reflects the
changes in gasoline that are occurring with the expanded use of
ethanol, including the corresponding removal of MTBE. 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
projected to be consumed in 2012. We excluded federal and state ethanol
consumption subsidies which avoids the transfer payments caused by
these subsidies that would hide a portion of the program's costs.
---------------------------------------------------------------------------

    \100\ 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 VII.C.3.A-1.--Estimated Cost Without Ethanol Consumption Subsidies
                         [Million dollars and cents per gallon; 7% ROI and 2006 dollars]
----------------------------------------------------------------------------------------------------------------
                                                                   RFS case 6.8    EIA case 9.6    EIA case 9.6
                                                                   billion gals    billion gals    billion gals
                                                                  incremental to  incremental to  incremental to
                                                                  reference case  reference case     RFS case
----------------------------------------------------------------------------------------------------------------