gallons at a crude oil price forecast of $47 per barrel. 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. Therefore, in
assessing the impacts of expanded use of renewable fuels, 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 7.2 billion gallons of ethanol (0.25 of which was assumed to
be cellulosic) and 0.3 billion gallons of biodiesel. For the higher
projected renewable fuel consumption scenario, we assumed 9.6 billion
gallons of ethanol (0.25 of which is once again 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.\52\
---------------------------------------------------------------------------

    \49\ Energy Act Section 1504, promulgated on May 8, 2006 at 71
FR 26691.
    \50\ Based on discussions with the refining industry.
    \51\ AEO 2006 Table 17 Renewable Energy Consumption by Sector
and Source shows 0.80 quadrillion BTUs of energy coming from ethanol
in 2012. A parallel spreadsheet provided to EPA shows 2012 total
ethanol use as 628.7 thousand bbls/day (which works out to be 9.64
billion gallons/yr).
    \52\ As a comparison point for cost and emissions analyses, a
2012 reference case of 3.9 billion gallons of ethanol was also
considered. The reference case is described in Section II.A.1
(above) and a complete derivation is contained in DRIA Section
2.1.3.
---------------------------------------------------------------------------

    In addition to modeling two different future 2012 ethanol
consumption levels, two scenarios were considered based on how
refineries could potentially respond to the recent removal of the RFG
oxygenate mandate. In both cases, the impacted RFG areas did not change

from the 2004 base case.\53\ In the maximum scenario (``max-RFG''),
refineries would continue to add oxygenate (ethanol) into all batches
of reformulated gasoline. In this case, refineries currently blending
MTBE (at 11 volume percent) would be expected to replace it with
ethanol (at 10 volume percent). In the minimum scenario (``min-RFG''),
we predict some refineries would respond by using less (or even zero)
ethanol in RFG based on the minimum amount needed to meet volume,
octane, and/or total toxics performance requirements. Applying the max-
RFG and min-RFG criteria resulted in a total of four different 2012
ethanol consumption control cases:
---------------------------------------------------------------------------

    \53\ For a list of the Federal RFG areas, refer to DRIA Table
2.2-1.
---------------------------------------------------------------------------

    1. 7.2 billion gallons of ethanol, maximum amount used in RFG
areas;
    2. 7.2 billion gallons of ethanol, minimum amount used in RFG
areas;
    3. 9.6 billion gallons of ethanol, maximum amount used in RFG
areas; and
    4. 9.6 billion gallons of ethanol, minimum amount used in RFG
areas.
    The seasonal RFG assumptions applied in 2012 (in terms of percent
ethanol marketshare) are summarized below in Table VI.A.4-1. The
rationale behind these selected values are explained in DRIA Section
<IP_ADDRESS>.

               Table VI.A.4-1.--2012 RFG Area Assumptions
------------------------------------------------------------------------
                              ETOH-blended gasoline (% market share) \a\
                             -------------------------------------------
                                                 Max-RFG scenario
          RFG areas            Min-RFG  --------------------------------
                               scenario    Summer     Winter     Summer
                                         (percent)  (percent)  (percent)
------------------------------------------------------------------------
PADD 1......................          0        100        100        100
PADD 2......................         50        100        100        100
PADD 3......................          0         25        100        100
California \b\..............         25        100        100        100
Arizona \c\.................          0        100        100        100
------------------------------------------------------------------------
\a\ Percent marketshare of E10, with the exception of California (E5.7
  year-round) and Arizona (E5.7 summer only).
\b\ Pertains to both Federal RFG and California Phase 3. RFG.
\c\ Pertains to Arizona Clean Burning Gasoline (CBG).

    Once we determined how much ethanol was likely to be used in RFG
areas (by PADD), we systematically allocated the remaining ethanol into
conventional gasoline. First it was apportioned to winter oxy-fuel
areas. In the 2004 base case, there were 14 state-implemented winter
oxy-fuel programs in 11 states. Of these programs, 9 were required in
response to non-attainment with the CO National Ambient Air Quality
Standards (NAAQS) and 4 were implemented to maintain CO attainment
status.\54\ By 2012, 4 areas are expected to be redesignated to CO
attainment status and discontinue oxy-fuel use and 2 areas are
predicted to discontinue using oxy-fuel as a maintenance strategy.
Accordingly, a reduced amount of ethanol was allocated to oxy-fuel
areas in 2012. The remaining ethanol was distributed to conventional
gasoline (CG) in different states based on a computed ethanol margin
(rack gasoline price minus ethanol delivered price adjusted by
miscellaneous subsidies/penalties). The methodology is described in
DRIA Section <IP_ADDRESS>.
---------------------------------------------------------------------------

    \54\ Refer to DRIA Table 2.1-2.
---------------------------------------------------------------------------

    The main difference in the four resulting ethanol consumption
scenarios was how far the ethanol penetrated the conventional gasoline
pool. A summary of the forecasted 2012 ethanol consumption (by control
case, fuel type and season) is found in Table VI.A.4-2.

                       Table VI.A.4-2.--2012 Forecasted U.S. Ethanol Consumption by Season
----------------------------------------------------------------------------------------------------------------
                                                             Ethanol consumption (MMgal)
                                    ----------------------------------------------------------------------------
         2012 Control case                    CG            OXY \a\          RFG \b\                Total
                                    ----------------------------------------------------------------------------
                                       Summer     Winter     Winter     Summer     Winter     Summer     Winter
----------------------------------------------------------------------------------------------------------------
7.2 Bgal/Max-RFG...................      1,269      1,537         72      1,932      2,389      3,201      3,999
7.2 Bgal/Min-RFG...................      2,144      2,571         72        244      2,168      2,388      4,812
9.6 Bgal/Max-RFG...................      2,356      2,830         73      1,941      2,400      4,297      5,303
9.6 Bgal/Min-RFG...................      3,223      3,881         73        246      2,178      3,468      6,132
----------------------------------------------------------------------------------------------------------------
\a\ Winter oxy-fuel programs.
\b\ Federal RFG plus Ca Phase 3 RFG and Arizona CBG.

    As expected, the least amount of ethanol was consumed in
conventional gasoline in the 7.2 billion gallon control case when a
maximum amount was allocated to RFG. Similarly, the most ethanol was
consumed in CG in the 9.6 billion gallon control case when a minimum
amount was allocated to RFG. For more information on the four resulting
2012 control cases, refer to DRIA Section <IP_ADDRESS>.

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
consideration of the benefits of subsidies and credits provided by
Federal and state programs. Much of the demand occurred as a result of
mandates from states and local municipalities, which required the use

of biodiesel. However, over the past couple 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 65 biodiesel plants in operation with an annual
production capacity of 395 million gallons per year.\55\ The majority
of the current production capacity was built in 2005, and was first
available to produce fuel in the last quarter of 2005. Though 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, see Table VI.B.1-2.\56\
---------------------------------------------------------------------------

    \55\ NBB Survey April 28, 2006 ``Commercial Biodiesel Production
Plants.''
    \56\ 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 Historya
----------------------------------------------------------------------------------------------------------------
                                                                 2001     2002     2003     2004     2005   2006
----------------------------------------------------------------------------------------------------------------
Plants.......................................................        9       11       16       22       45  53
Capacity (million gal/yr)....................................       50       54       85      157      290  354
----------------------------------------------------------------------------------------------------------------
\a\ Capacity Data based on surveys conducted around the month of September for most years, though the 2006
  information is based on survey conducted in January 2006.

2. Expected Growth in U.S. Biodiesel Production/Consumption
    In addition to the 53 biodiesel plants already in production, as of
early 2006, there were an additional 50 plants and 8 plant expansions
in the construction phase, which when completed would increase total
biodiesel production capacity to over one billion gallons per year.
Most of these plants should be completed by early 2007. There were also
36 more plants in various stages of the preconstruction phase (i.e.
raising equity, permitting, conceptual design, buying equipment) with a
capacity of 755 million gallons/year. As shown in Table VI.B.2-1, if
all of this capacity came to fruition, U.S. biodiesel capacity would
exceed 1.8 billion gallons.

                            Table VI.B.2-1.--Projected Biodiesel Production Capacity
----------------------------------------------------------------------------------------------------------------
                                                                                Pre-
                                                                    Existing      Construction     construction
                                                                     plants           phase           phase
----------------------------------------------------------------------------------------------------------------
Number of plants...............................................              53              58             36
Total Plant Capacity, MM Gallon/year...........................             354             714            754.7
----------------------------------------------------------------------------------------------------------------

    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 in a manner consistent with the growth of
gasoline.\57\ The resulting 2012 reference case consisted of
approximately 28 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.
---------------------------------------------------------------------------

    \57\ 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. 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. Production Capacity of Cellulosic Ethanol
    Beginning in 2013, a minimum of 250 million gallons per year of
cellulosic ethanol must be used in gasoline. The Act's definition of
cellulosic, however, includes corn based ethanol as long as greater
than 90% of the process energy was derived from animal wastes or other
waste materials. As discussed in section VI.A. above, we believe that
of the ethanol plants currently in existence, under construction, or in
the final stages of planning there is likely to be more than 250
million gallons per year of ethanol produced from plants which meet
these alternative definitions for cellulosic ethanol.
    However, this is not to say that ethanol produced from cellulose
will not be part of the renewable supply by 2012. As far as we know
there is currently only one demonstration-level cellulosic ethanol
plant in operation in North America; it produces 1 million gallons of
ethanol per year (Iogen a privately held company, based in Ottawa,
Ontario, Canada). However, the technology used to produce ethanol from
cellulosic feedstocks continues to improve. With the grants made
available through the Energy Act, we expect several cellulosic process
plants will be constructed and an ever increasing effort will naturally
be made to find better, more efficient ways to produce cellulosic
ethanol.
    To produce ethanol from cellulosic feedstocks, pretreatment is
necessary to hydrolyze cellulosic and hemicellulosic polymers and break
down the lignin sheath. In so doing, the structure of the cellulosic
feedstock is opened to allow efficient and effective enzyme hydrolysis
of the cellulose/hemicellulose to glucose and xylose. The central
problem is that the [alpha]-linked saccharide polymers in the
cellulose/hemicellulose structure prevent the microbial fermentation
reaction. By comparison, when corn kernels are used as feedstock,
fermentation of the starch produced from the corn kernels which have
[alpha]-linked saccharide polymers takes place much more readily. An
acid hydrolysis process was developed to pretreat cellulosic feedstocks
(through hydrolysis which breaks up the [beta]-links), but it continues
to be prohibitively expensive for producing ethanol.
    Some technologies that are being developed may solve some of the
problems associated with production of ethanol from cellulosic sources.
Specifically, one problem with cellulosic feedstocks is that the
hydrolysis reactions produce both glucose, a six-carbon sugar, and
xylose, a 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 cellulose
hydrolysis enzymes and ethanol-fermenting organisms. Now, glucose and
xylose can be co-fermented--hence, the present-day terminology: Weak-
acid enzymatic hydrolysis and co-fermentation. In addition, several
research 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 a process known as weak-acid,
enzymatic-prehydrolysis.
    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. In particular, there is only one cellulosic
ethanol plant in North America (Iogen, Ottawa, Ontario, Canada). To the
best of our knowledge, the technology that Iogen employs is not yet
fully developed or optimized. Generally, the industry seems to be
moving toward a process that uses dilute acid enzymatic prehydrolysis
with simultaneous saccharification (enzymatic) and co-fermentation.
3. Renewable Fuel Distribution System Capability
    Ethanol and biodiesel blended fuels are 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. In the
past the refining industry has raised concerns regarding whether the
distribution infrastructure can expand rapidly enough to accommodate
the increased demand for ethanol. The most comprehensive study of the
infrastructure requirements for an expanded fuel ethanol industry was
conducted for the Department of Energy (DOE) in 2002.\58\ 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 this preamble.
---------------------------------------------------------------------------

    \58\ ``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 and independent 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. We also expect that by
ending the use of MTBE that the former MTBE feedstock, isobutylene,
will be reused to produce increased volumes of alkylate, a moderate to
high octane gasoline blendstock. 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 production of
alkylate.
    As discussed in section II., we chose to analyze a range of
renewable fuels 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, and the higher end is based on AEO 2006. 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
VII-1.

       Table VII-1.--Renewable Fuels Volumes Used in Cost Analysis
------------------------------------------------------------------------
                                           Renewable fuels  consumption
                                            in 2012  (billion gallons)
                                         -------------------------------
                                                Low            High
------------------------------------------------------------------------
Corn Ethanol............................            6.95            9.35
Cellulosic Ethanol......................            0.25            0.25
Biodiesel...............................            0.30            0.30
                                         -------------------------------
    Total Biofuel Consumption...........            7.5             9.90
------------------------------------------------------------------------

    We have estimated an average corn ethanol production cost of $1.20
per gallon in 2012 (2004 dollars) in the case of 7.5 billion gallons
per year (bill gal/yr) and $1.26 per gallon in the case of 9.9 bill
gal/yr. 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 this 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 gal in 2012. For yellow grease derived
biodiesel, we estimate an average production cost of $1.19 per gallon
in 2004 and $1.10 in 2012.
    The impacts on overall gasoline costs with and without fuel
consumption subsidies resulting from the increased use of ethanol and
the corresponding changes to the other aspects of gasoline were
estimated for both of these cases. The 7.5 bill gal/yr case would
result in increased total costs which range from 0.33 cents to 0.41
cents per gallon depending on assumptions with respect to ethanol use
in RFG and butane control constraints. The 9.9 bill gal/yr case would
result in increased total costs which range from 0.93 to 1.05 cents per
gallon. The actual cost at the fuel pump, however, will be decreased
due the effect of State and Federal tax subsidies for ethanol. Taking
this into consideration results in ``at the pump'' decreased costs
(cost savings) ranging from 0.82 to 0.89 cents per gallon for the 7.5
bill gal/yr case and ``at the pump'' decreased costs ranging from 0.98
to 1.08 cents per gallon for the 9.9 bill gal/yr case. We ask for
comment on these derived costs as well as on the analysis methodology
used to derive these costs, and refer the reader to Section 7 of the
DRIA which contains much 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,\59\ and it produces results that
compare well with cost information found in surveys of existing
plants.\60\ 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.
---------------------------------------------------------------------------

    \59\ Kwaitkowski, J.R., McAloon, A., Taylor, F., Johnston, D.B.,
Industrial Crops and Products 23 (2006) 288-296.
    \60\ 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 50% of the final
per-gallon cost, while utilities, capital and labor comprise about 20%,
10%, and 5%, respectively. For this work, we used corn price
projections from USDA of $2.23 per bushel in 2012 for the 7.2 bill gal/
yr case, and an adjusted value of $2.31 per bushel for the 9.6 bill
gal/yr

case.\61\ The adjustment at the higher volume case was taken from work
done by FAPRI and EIA.62 63 Prices used for DDGS were $65
per ton in the 7.2 bill gal/yr case and $55 per ton in the 9.6 case,
based on work by FAPRI and EIA.\64\ Energy prices were derived from
historical data and projected to 2012 using EIA's AEO 2006.\65\ While
we believe the use of USDA and FAPRI estimates for corn and DDGS prices
is reasonable, additional modeling work is being done for the final
rulemaking using the Forestry and Agricultural Sector Optimization
Model described further in Chapter 8 of the RIA.
---------------------------------------------------------------------------

    \61\ USDA Agricultural Baseline Projections to 2015, Report OCE-
2006-1.
    \62\ EIA NEMS model for ethanol production, updated for AEO
2006.
    \63\ Food and Agricultural Policy Research Institute (FAPRI)
study entitled ``Implications of Increased Ethanol Production for
U.S. Agriculture'', FAPRI-UMC Report 10-05.
    \64\ Food and Agricultural Policy Research Institute (FAPRI)
U.S. and World Agricultural Outlook, January 2006, FAPRI Staff
Report 06-FSR 1.
    \65\ Historical data at http://tonto.eia.doe.gov/[fxsp0]dnav/pet/pet--pri--allmg--d--nus--PTA--cpgal--m.htm (gasoline), http://

tonto.eia.doe.gov/[fxsp0]dnav/ng/ng--pri--sum--dcu--nus--m.htm
(natural gas), http://www.eia.doe.gov/cneaf/[fxsp0]electricity/page/sales--revenue.xls (electricity), http://www.eia.doe.gov/

[fxsp0]cneaf/coal/page/acr/table28.html (coal); EIA Annual Energy
Outlook 2006, Tables 8, 12, 13, 15; EIA Web site.
---------------------------------------------------------------------------

    The estimated average corn ethanol production cost of $1.20 per
gallon in 2012 (2004 dollars) in the case of 7.2 bill gal/yr and $1.26
per gallon in the case of 9.6 bill gal/yr 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 does not account for any
subsidies on production or sale of ethanol. This cost is independent of
the market price of ethanol, which has been related closely to the
wholesale price of gasoline for the past decade.66 67
---------------------------------------------------------------------------

    \66\ Whims, J., Sparks Companies, Inc. and Kansas State
University, ``Corn Based Ethanol Costs and Margins, Attachment 1''
(Published May 2002).
    \67\ 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.\68\ It is expected that 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 these processes will simply be corn ethanol plants
with additional fuel handling mechanisms that allow them to combust
waste materials for process energy instead of natural gas. We expect
them to be in locations where the very low or zero cost of the waste
material or biogas itself will likely offset the costs of hauling it
and/or the additional capital for processing and firing it, making them
cost-competitive with conventional corn ethanol plants. Furthermore,
because the quantity of ethanol produced using these processes is still
expected to be a relatively small fraction of the total ethanol demand,
the sensitivity of the overall analysis to this assumption is also very
small. 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.
---------------------------------------------------------------------------

    \68\ Energy Policy Act of 2005, Section 1501 amending Clean Air
Act Section 211(o)(1)(A).
---------------------------------------------------------------------------

    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 hardwood
chips.\69\ 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.
---------------------------------------------------------------------------

    \69\ 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 proposed 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.\70\ 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.
---------------------------------------------------------------------------

    \70\ 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).
    c. Ethanol's Blending Cost. Ethanol has a high octane value of 115
(R+M)/2 which contributes to its value as a gasoline blendstock. As the
volume of ethanol blended into gasoline increases from 2004 to 2012,
refiners will account for the octane provided by ethanol when they plan
their gasoline production. This additional octane would allow them to
back off of their octane production from their other gasoline producing
units resulting in a cost savings to the refinery. For this cost
analysis, the cost savings is expressed as a cost credit to ethanol
added to the production cost for producing ethanol.
    We obtained gasoline blending costs on a PADD basis for octane from
a consultant who conducted a cost analysis for a renewable fuels
program using an LP refinery cost model. LP refinery models value the
cost of octane based on the octane producing capacity for the
refinery's existing units, by

added capital and operating costs for new octane producing capacity,
and based on purchased gasoline blendstocks. The value of octane is
expressed as a per-gallon cost per octane value, and ranges from 0.38
cents per octane-gallon in PADD 2 where lots of ethanol is expected to
be used, to 1.43 cents per octane-gallon in California. Octane is more
costly in California because the Phase 3 RFG standards restriction
aromatics content which also reduces the use of a gasoline blendstock
named reformate--a relatively cheap source of octane. Also,
California's Phase 3 RFG distillation restrictions tend to limit the
volume of eight carbon alkylate, another lower cost and moderately high
octane blendstock.
    Another blending factor for ethanol is its energy content. Ethanol
contains a lower heat content per gallon than gasoline. Since refiners
blend up their gasoline based on volume, they do not consider the
energy content of its gasoline, only its price. Instead, the consumer
pays for a gasoline's energy density based on the distance that the
consumer can achieve on a gallon of gasoline. Since we try to capture
all the costs of using ethanol, we consider this effect. Ethanol
contains 76,000 British Thermal Units (BTU) per gallon which is
significantly lower than gasoline, which contains an average of 115,000
BTUs per gallon. This lower energy density is accounted for below in
the discussion of the gasoline costs.
2. Biodiesel Production Costs
    We based our cost to produce biodiesel fuel on a range estimated
from the use of USDA's and NREL's biodiesel computer models. Both of
these models represent the continuous transesterification process for
converting vegetable soy oil to esters, along with the ester finishing
processes and glycerol recovery. The models estimate biodiesel
production costs using prices for soy oil, methanol, chemicals and the
byproduct glycerol. The models estimate the capital, fixed and
operating costs associated with the production of soy based biodiesel
fuel, considering utility, labor, land and any other process and
operating requirements.
    Each model is based on a medium sized biodiesel plant that was
designed to process raw degummed virgin soy oil as the feedstock,
yielding 10 million gallons per year of biodiesel fuel. USDA estimated
the equipment needs and operating requirements for their biodiesel
plant 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. The NREL model is
also based on process simulation software, though the results are
adjusted to reflect NREL's modeling methods.
    The production costs are based on an average biodiesel plant
located in the Midwest using soy oil 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 production costs are based on a
plant that makes 10 million gallons per year of biodiesel fuel.
    The model is further modified to use input prices for the
feedstocks, byproducts and energy prices to reflect the effects of the
fuels provisions in the Energy Act. Based on the USDA model, for soy
oil-derived biodiesel we estimate a production cost of $2.06 per gallon
in 2004 and $1.89 per gal in 2012 (in 2004 dollars) For yellow grease
derived biodiesel, USDA's model estimates an average production cost of
$1.19 per gallon in 2004 and $1.10 in 2012 (in 2004 dollars). In order
to capture a range of production costs, we compared these cost
projections to those derived from the NREL biodiesel model. With the
NREL model, we estimate biodiesel production cost of $2.11 per gallon
for soy oil feedstocks and $1.28 per gallon for yellow grease in 2012,
which are slightly higher than the USDA results.
    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 111 cents per
gallon for soy derived biodiesel and 60 to 78 cents per gallon for
yellow grease biodiesel 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
expires in 2008 if not extended. Congress may later elect to extend the
blender credit program, though, 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 under two scenarios, with refinery diesel prices
as forecasted by EIA's AEO 2006 with crude at $47 a barrel and with
refinery diesel prices based on $70 per barrel crude oil.
    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 the AEO scenario, 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 $90 million per
year, which equates to a reduction in fuel cost of about 0.15 c/
gal.\71\ Without the subsidy, the transport diesel fuel costs are
increased by $118 million per year, or an increase of 0.20 c/gal for
transport diesel fuel. With crude at $70 per barrel, including the
biodiesel blenders subsidy, results in a cost reduction of $184 million
per

year, or a reduction of 0.31 c/gal for the total transport diesel pool.
Without the subsidy, transport diesel costs are increased by $25
million per year, or 0.04 c/gal.
---------------------------------------------------------------------------

    \71\ Based on EIA's AEO 2006, the total volume of highway and
off-road diesel fuel consumed in 2012 was estimated at 58.9 billion
gallons.
---------------------------------------------------------------------------

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.\72\ That study
provided the foundation 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 the case where the minimum volume of ethanol is used to meet
the requirements of the RFS (7.2 bill gal/yr) and for the projected
case where the volume of ethanol used is 9.6 bill gal/yr. 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.
---------------------------------------------------------------------------

    \72\ 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 bill gal/yr of ethanol
would be used in 2010, and the second assumed that 10 bill gal/yr of
ethanol would be used in the 2015 timetable. We interpolated between
these two cases to provide an estimate of the capital costs to support
the use of 7.2 bill gal/yr of ethanol in 2012.\73\ The 10 bill gal/yr
case examined in the DOE study was used to represent the projected case
examined in today's rule of 9.6 bill gal/yr of ethanol.\74\ Table
VII.B.1.a-1 contains 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, the total capital costs equate
to approximately one cent per gallon. We performed a sensitivity
analysis where we increased reliance on rail use at the expense of
barge use in transporting ethanol. The costs were relatively
insensitive, increasing to just 1.1 cents per gallon.
---------------------------------------------------------------------------

    \73\ See Chapter 7.3 of the Draft 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.
    \74\ For both the 7.2 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.

    Table VII.B.1.a-1.--Estimated Ethanol Distribution Infrastructure
 Capital Costs ($M) Relative to a 3.9 Billion Gallon per Year Reference
                                  Case
------------------------------------------------------------------------
                                            7.2 billion     9.6 billion
                                           gallons  (per   gallons  (per
                                               year)           year)
------------------------------------------------------------------------
Fixed Facilities:
    Retail..............................              24              44
    Terminals...........................             142             246
Mobile Facilities:
    Transport Trucks....................              38              50
    Barges..............................              30              52
    Rail Cars...........................             104             161
                                         -------------------------------
        Total Capital Costs.............             317             542
------------------------------------------------------------------------

    b. Ethanol Freight Costs. The DOE study contains ethanol freight
costs for each of the 5 PADDs. The Energy Information Administration
translated these cost estimates to a census division basis.\75\ We took
the EIA projections and translated them into State-by-State ethanol
freight costs. In conducting this translation, we accounted for
increases in the cost in transportation fuels used to ship ethanol by
truck, rail, and barge. We estimate that the freight cost to transport
ethanol to terminals would range from 5 cents per gallon in the
Midwest, to 18 cents per gallon to the West Coast, which averages 9.2
cents per gallon of ethanol on a national basis.
---------------------------------------------------------------------------

    \75\ 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.

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

    We estimate the total cost for producing and distributing ethanol
to be between $1.30 and $1.36 per gallon of ethanol, on a nationwide
average basis. This estimate includes both the capital costs to upgrade
the distribution system and freight costs.
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 28 million gallons.\76\
---------------------------------------------------------------------------

    \76\ 2004 baseline of 25 million gallons grown with diesel
demand to 2012.
---------------------------------------------------------------------------

    For the purposes of this analysis, we are assuming that to ensure
consistent operations under cold conditions all terminals will install
heated biodiesel storage tanks and biodiesel will be transported to
terminals in insulated tank trucks and rail cars in the cold
seasons.\77\ Due to the developing nature of the biodiesel industry,
specific information on biodiesel freight costs is lacking. The need to
protect biodiesel from gelling during the winter may marginally
increase freight costs over those for ethanol. Counterbalancing this is
the likelihood that biodiesel shipping distances may be somewhat
shorter due to the more geographically dispersed nature of biodiesel
production facilities. In any event, the potential difference between
biodiesel and ethanol freight costs is likely to be small and the cost
of distributing biodiesel does not appreciably affect the results of
our analysis. Therefore, we believe that

estimated freight costs for ethanol of 9.2 cents per gallon adequately
reflects the freight costs for biodiesel for this analysis.
---------------------------------------------------------------------------

    \77\ See section VI.C. in today's preamble regarding the special
handling requirements for biodiesel under cold conditions.
---------------------------------------------------------------------------

    The capital costs associated with distribution of biodiesel will be
somewhat higher per gallon than those associated with the distribution
of ethanol due to the need for storage tanks, barges, tanker trucks and
rail cars to be insulated and in many cases heated. We estimate that to
handle the increased biodiesel volume will require a total capital cost
investment of $49,813,000, which equates to about 2 cents per gallon of
new biodiesel volume.
    We estimate the total cost for producing and distributing biodiesel
to be between $2.00 and $2.22 per gallon of biodiesel, on a nationwide
average basis. This estimate includes both the capital costs to upgrade
the distribution system and freight costs.

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 developed our own spreadsheet cost model. As described above in
Section VI.A, the cost analysis is conducted by comparing a base year
before the Energy Act's fuel changes to a modeled year with the fuel
changes. We used 2004 as the base year. We grew the 2004 gasoline
demand to 2012 to create a reference case assuming that the 2004 fuel
demand scenario remained the same (fuel quality remained constant). The
sum of fuel changes, including the increased use of ethanol, the phase-
out of MTBE and the conversion of a part of the MTBE feedstocks to
alkylate, is all assumed to occur by 2012 and is compared to the 2012
reference case. This analysis considers the production cost,
distribution cost as well as the cost for balancing the octane and RVP
caused by these fuel changes.
    In addition to assessing the cost at 7.2 and 9.6 billion gallons of
total ethanol use in gasoline, we considered that ethanol could be used
at different levels in RFG. Instead of picking a single point for
ethanol use in RFG, we assessed a range (see Section VI.A above). At
the high end of the range, ethanol is used in RFG in both summer and
winter. At the low end of the range, ethanol is still used in
wintertime RFG, but to only a very limited extent in summertime RFG.
The lower rate of ethanol use in summertime RFG may occur because the
RVP increase associated with ethanol will cause refiners to incur a
cost to further control the volatility of their summertime RFG.
1. RVP Cost for Blending Ethanol Into Summertime RFG
    Blending ethanol into summertime RFG causes about a 1 PSI (pounds
per square inch) increase in RVP. To enable this gasoline to continue
to be sold into the summertime RFG market, this vapor pressure increase
must be accounted for by adjusting the RVP of the base gasoline. The
vapor pressure adjustment is made by reducing of volume of pentanes in
the gasoline boiling that comes from the fluid catalytic cracking unit
(FCCU). To reduce the pentane content FCC naphtha, refiners would
likely have to add a distillation column called a depentanizer, where
pentanes and lighter hydrocarbons are removed from the hydrocarbon feed
and drawn off the top of the column while the heavier C6+ hydrocarbons
are removed from the bottom. While the pentanes would be removed from
the summertime RFG pool, they are expected to be reblended into either
summertime CG or wintertime CG and RFG. To rebalance the RVP of the
nonsummertime RFG pool or wintertime RFG or CG pool caused by relocated
pentanes, butanes are estimated to be removed from the gasoline pool.
When ethanol is blended into summertime RFG, about 10 percent of the
base gasoline is lost due to the removed pentanes. We believe that
refiners would reblend these removed pentanes into summertime CG or
wintertime CG and RFG and rebalance the RVP of the gasoline pool into
which the pentanes are being reblended by removing butanes, thus
reducing the volume loss to one fifth of that if the pentanes were
permanently removed. There is an opportunity cost to removing butanes
from gasoline. In 2004 butanes sold into the butane market were valued
36 cents per gallon less than gasoline, however, this opportunity cost
would be much greater if pentanes were permanently removed from
gasoline.
    We developed cost estimates for adding and operating a new
depentanizer distillation column for the removal of pentanes from FCC
naphtha in each refinery. The feed rate for an average FCC unit was
estimated by PADD and ranged from 7 to 35 thousand barrels per day.
Once the capital and operating costs were estimated, the total costs
were averaged over the entire gasoline pool, which ranged from about
two to three times the volume of FCC naphtha. When ethanol is being
blended newly into summertime RFG, the capital and operating costs will
both apply. However, when we model ethanol coming out of a summertime
RFG market, we only reduce the depentanizer operating costs since the
capital costs are sunk.
    Our analysis showed that the RVP blending costs for blending
ethanol into summertime RFG ranges from 1 to 1.4 cents per gallon of
RFG. If the ethanol is coming out of summertime RFG, which occurs in
some of the scenarios that we modeled, there would be a cost savings of
0.8 to 1.2 cents per gallon of RFG.
    In the cost of refinery gasoline section below, we took into
account that butanes have a lower energy density compared to the
gasoline pool from which the butanes were removed. This energy content
adjustment will offset some of the cost for removing the butanes.
Butane's energy density is 94,000 BTUs per gallon compared to 115,000
BTU per gallon for gasoline.
    For further details on RVP reduction costs, see Section 7.4.2 of
the RIA.
2. Cost Savings for Phasing Out Methyl Tertiary Butyl Ether (MTBE)
    The Energy Act rescinded the oxygen standard for RFG and when the
provision took effect, U.S. refiners stopped blending MTBE into
gasoline. When MTBE use ended, the operating costs for operating those
plants also ceased. The total costs saved for not operating the MTBE
plants is calculated by multiplying the volume of MTBE no longer
blended into gasoline with the operating costs for the plants producing
that MTBE.
    We determined the operating costs saved by shutting down these
plants. The volumetric feedstock demands and the operating costs
factors for each of these MTBE plants are taken from literature. We
estimated the MTBE operating costs to be $1.40 per gallon for captive
and ethylene cracker plants, $1.48 per gallon for propylene oxide
plants and $1.55 per gallon for merchant operating costs. Weighted by
the percentages for domestic MTBE production, the average cost savings
for no longer producing MTBE is estimated to be $1.46 per gallon.
    We also credited MTBE for its octane blending value. MTBE has a
high octane value of 110 (R+M)/2 which increases its value compared to
gasoline. This high octane value partially offsets its production cost.
The cost of octane is presented above in subsection VII.(A)(1)(c) and
is applied to the difference in octane value between MTBE and the
average of the various gasoline grades (88 (R+M)/2). Accounting for
MTBE's octane value reduces its cost down to $1.27 to $1.38 per gallon
depending on the PADD. When accounting for the volume of

MTBE removed, we also adjust for its energy content, which is 93,500
BTU per gallon.
    For further information on costs savings due to MTBE phaseout, see
Section 7.4.3 of the RIA.
3. Production of Alkylate From MTBE Feedstocks
    Discontinuing the blending of MTBE into U.S. gasoline is expected
to result in the reuse of most of the primary MTBE feedstocks,
isobutylene, to be used to produce alkylate. Alkylate is formed by
reacting isobutylene together with isobutane. Prior to the
establishment of the oxygen requirement for RFG, this isobutylene was,
in most cases, used to make alkylate. Another option would be for
reacting isobutylene with itself to form isooctene which would likely
be hydrogenated to then form isooctane. However, our cost analysis
found that alkylate is a more cost-effective way to reuse the
isobutylene, even after considering isooctane's higher octane content.
The cost for converting to alkylate is estimated to be $1.42 per gallon
for captive (in-refinery) plants and ethylene cracker plants, $1.46 per
gallon for propylene oxide plants and $1.52 per gallon for merchant
MTBE plants. We believe that the cost for converting merchant MTBE
plants to alkylate is too high to support its conversion, thus the
conversion cost is estimated to be $1.43 per gallon, the average of the
conversion costs for captive, ethylene cracker and propylene oxide MTBE
plants. This projected percent of MTBE plant conversion results in 0.84
gallons of alkylate produced for each gallon of MTBE no longer
produced.
    The alkylate production cost is adjusted by PADD to account for the
blending octane of alkylate, which varies by 1 to 2 cents per gallon
depending on the value of octane in each PADD. Including its octane
value, the cost of producing alkylate varies from $1.38 to $ 1.41 per
gallon.
    For further information on production of alkylate from MTBE
feedstocks, see section 7.4.4 of the RIA.
4. Changes in Refinery Produced Gasoline Volume and Its Costs
    In the sections above, we estimated changes in gasoline volume and
the cost associated with those volume changes for ethanol, MTBE,
alkylate and butane. As these various gasoline blendstocks are added to
or removed from the gasoline pool, they affect the refinery production
of gasoline (or oxygenate blendstock).
    To estimate the changes in refinery gasoline production volumes, it
was necessary to balance the total energy production of each control
case to the reference case. The energy content of the reference case
was estimated by multiplying the volumetric energy content of each
gasoline pool blendstock, including MTBE, ethanol and refinery produced
gasoline, by the associated gallons.
    The increase or decrease in ethanol content in summertime RFG
assumed under the different scenarios resulted in the change in the
volumes of butane in RFG as described above. We identified that the
increase or decrease in ethanol in wintertime RFG and CG could cause
reductions or increases in the amount of butanes blended into
wintertime gasoline. Wintertime gasoline is limited in vapor pressure
by the American Standard for Testing Materials (ASTM) RVP and V/L
(vapor-liquid) standards. According to a refiner with extensive
refining capacity, and also Jacobs Engineering, a refining industry
consulting firm, refineries are blending their wintertime gasoline up
to those standards today and are limited from blending more butane
available to them. If this is the case, for each gallon of summertime
RFG and wintertime RFG and CG blended with ethanol 2 percent of the
base gasoline volume would be lost in terms of butane removed. However,
some refineries may have room to blend more butane. Also, we are aware
that some states offer 1 PSI waivers for blending of ethanol into
wintertime gasoline, presumably to accommodate splash blending of
ethanol.\78\ Consequently, it may be possible to accommodate the 1 PSI
vapor pressure increase without forcing the removal of some or all of
this butane. For this reason we assessed the costs as a range, on the
upper end assuming that butane content would have to be removed to
account for new ethanol blended into summertime RFG and wintertime RFG
and CG , and on the low end assuming only that blending of ethanol into
summertime RFG cause butanes to be removed.
---------------------------------------------------------------------------

    \78\ Most people are aware of the 1 PSI RVP waiver that ethanol
is provided for the summertime, but some states offer a similar
waiver to ethanol for wintertime blending as well.
---------------------------------------------------------------------------

    For estimating the volume of butane which must be removed from the
gasoline because of the addition of ethanol, we assumed that ethanol
will be used at 10 volume percent except for California where it would
continue to be used at 5.7 volume percent. Development of the estimates
for winter vs. summer ethanol consumption for the control cases is
discussed in Chapter 2.1 of the RIA. For the reference case, we
estimated that 55 percent of the ethanol would be used in the winter
and 45 percent in the summer. Table VII.C.4-1 summarizes the summertime
RFG and wintertime RFG and CG volumes of ethanol and estimated change
in butane content.

              Table VII.C.4-1.--Estimated Changes in U.S. Summertime RFG Ethanol Volumes and Their Impact on Butane Blending Into Gasoline
                                                                [Million gallons in 2012]
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                         Reference case       7.2 Bil gals max RFG    7.2 Bil gals min RFG   9.6 Bil gals max RFG   9.6 Bil gals min RFG
--------------------------------------------------------------------------------------------------------------------------------------------------------
Summertime RFG Ethanol.............  1,155.................  1,932.................  244..................  1,932................  244
Wintertime RFG & CG Ethanol........  2,178.................  3,999.................  4,812................  5,303................  6,132
Change in Butane...................  ......................  -140 to -456..........  164 to -297..........  -140 to -690.........  164 to -535
--------------------------------------------------------------------------------------------------------------------------------------------------------

    The change in volume of ethanol, MTBE, alkylate, and butane for
each control case is adjusted for energy content. The volume of
refinery gasoline is then adjusted to maintain the same energy content
as that of the reference gasoline pool. The refinery gasoline
production is estimated by dividing the BTU content of gasoline,
estimated to be 115,000 BTU per gallon, into the total amount of BTUs
for the entire gasoline pool after accounting for the BTUs of the other
blendstocks. The BTU-balanced gasoline pool volumes for each control
case are shown in Table

VII.C.4-2. The changes are shown for both assumptions with respect to
the need to remove butane from winter gasoline to accommodate more
ethanol blending.

                                                        Table VII.C.4-2.--Estimated 2012 Volumes
                                                                    [Million gallons]
--------------------------------------------------------------------------------------------------------------------------------------------------------

--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                           7.2 Bil gals, max RFG
                                                           7.2 Bil gals, min RFG
                                                           9.6 Bil gals, max RFG
                                                           9.6 Bil gals, min RFG
--------------------------------------------------------------------------------------------------------------------------------------------------------
Total Ethanol...........................................             7,200
                                                                     7,200
                                                                     9,600
                                                                     9,600
Increase in Ethanol.....................................             3,302
                                                                     3,302
                                                                     5,702
                                                                     5,702
Change in MTBE..........................................             -2091
                                                                     -2091
                                                                     -2091
                                                                     -2091
New Alkylate............................................             1,763
                                                                     1,764
                                                                     1,764
                                                                     1,764
--------------------------------------------------------------------------------------------------------------------------------------------------------
Butane Removed in Winter................................      Yes         No          Yes         No          Yes         No          Yes         No
--------------------------------------------------------------------------------------------------------------------------------------------------------
Change in Butane........................................        -456        -140        -297         164        -690        -140        -535         164
Gasoline................................................     143,486     143,228     143,357     142,980     142,092     141,642     141,965     141,394
Change in Gasoline......................................      -1,873      -2,131      -2,002      -2,379      -3,267      -3,716      -3,394      -3,965
Change in Gasoline (%)..................................        -1.3        -1.5        -1.4        -1.6        -2.2        -2.6        -2.3        -2.7
--------------------------------------------------------------------------------------------------------------------------------------------------------

    Based on our estimated impacts on volumes shown in table VII.C.4-2,
refinery produced gasoline demand will be reduced by a range of 1.3
percent to 2.7 percent compared to the reference case, which would
result in less imported finished petroleum products and/or less crude
oil use. The projected impacts on refinery-produced gasoline demand
depend on the volume of new ethanol blended into gasoline, on the
volume of ethanol blended into summertime RFG and on whether butane
blending into wintertime gasoline will be affected or not. To put this
reduction in refinery-produced gasoline volume in perspective, the
yearly annual growth in gasoline demand in this country is about 1.7
percent.
    The cost for changes to refinery produced gasoline volume is
assumed to be represented by the bulk price of gasoline in each PADD
from EIA's 2004 Petroleum Marketing Annual. The 2004 gasoline cost is
adjusted to 2012 using the ratio of the projected crude oil price in
2012 of $47 per barrel to that in the 2004 base case of $41 per barrel.
The cost for distributing the gasoline to terminals is added on, which
is estimated to be 4 cents per gallon. The estimated cost for producing
and distributing gasoline to terminals (wholesale price at the terminal
rack) ranges from $1.30 per gallon in the Gulf Coast, to $1.53 per
gallon in California.
    Crude oil prices are much higher today which decreases the relative
cost of producing and blending in more ethanol into gasoline. For this
reason, we conducted a sensitivity analysis assuming that crude oil is
priced at around $70 per barrel. Since this is only a sensitivity
analysis, we simply ratioed the gasoline production costs, MTBE and
alkylate feedstock costs and butane value upwards by the same ratio.
The ratio is determined by the projected increase in the wholesale
gasoline price relative to the increase in crude oil price. We
extrapolated this relationship to crude oil priced at $70 per barrel
compared to the price in 2004 which was $41 per barrel, which results
in about a 1.4 ratio factor. We did not adjust other costs and
assumptions which are much less sensitive to the price of crude oil and
therefore not likely to change much (e.g., distribution costs, refinery
utility costs, incremental octane costs, and ethanol production costs).
At a $70 per barrel crude oil price, the cost for production and
distribution of gasoline to the terminal ranges from $2.05 in the Gulf
Coast to $2.43 per gallon in California.
    For further information on gasoline cost see section 7.4.5 in the
RIA.
5. Overall Impact on Fuel Cost
    We combined the costs and volume impacts described in the previous
sections to estimate an overall fuel cost impact due to the changes in
gasoline occurring with the projected fuel changes. This aggregated
cost estimate includes the costs for producing and distributing
ethanol, the blending costs of ethanol in summertime RFG, ending the
production and distribution of MTBE, and reusing the MTBE feedstock
isobutylene for producing alkylate, reducing the content of butane in
summertime RFG and wintertime gasoline and for reducing the volume of
refinery-produced gasoline. We also present the costs for the scenario
that butanes would not need to be removed when ethanol is blended into
wintertime gasoline. The costs for each control case are estimated by
multiplying the change in volume for each gasoline blendstock, relative
to the reference case, times its production, distribution and octane
blending costs.
    The costs of these fuels changes 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. The second way we
express the cost is with the ethanol consumption subsidies included
since the subsidized portion of the renewable fuels costs will be 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. For
both cases we express the costs with and without butanes being removed
due to changes in wintertime blending of ethanol. We evaluated the fuel
costs using ranges in different assumptions to bound the many
uncertainties in the cost analysis (see the DRIA for more discussion
concerning the cost uncertainties).
    a. Cost without Ethanol Subsidies. Table VII.C.5.a-1 summarizes the
costs without ethanol subsidies for each of the four control cases,
including the cost for each aspect of the fuels changes, and the
aggregated total and the per-gallon costs for all the fuel changes.\79\
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. 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.
---------------------------------------------------------------------------

    \79\ 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.5.a-1.--Estimated Cost Without Ethanol Consumption Subsidies ($47/bbl Crude)
                                                          [million dollars, except where noted]
--------------------------------------------------------------------------------------------------------------------------------------------------------

--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                           7.2 Bil gals, max RFG
                                                           7.2 Bil gals, min RFG
                                                           9.6 Bil gals, max RFG
                                                           9.6 Bil gals, min RFG
--------------------------------------------------------------------------------------------------------------------------------------------------------
Adding Ethanol..........................................             3,769
                                                                     3,837
                                                                     6,852
                                                                     6,897
RFG RVP Cost............................................                72
                                                                       -74
                                                                        72
                                                                       -74
Eliminating MTBE........................................            -2,821
                                                                    -2,821
                                                                    -2,821
                                                                    -2,821
Adding Alkylate.........................................             2,520
                                                                     2,520
                                                                     2,521
                                                                     2,521
--------------------------------------------------------------------------------------------------------------------------------------------------------
Butane Removed in Winter................................      Yes         No          Yes         No          Yes         No          Yes         No
--------------------------------------------------------------------------------------------------------------------------------------------------------
Changing Butane Volume..................................        -439        -133        -275         174        -667        -133        -510         174
Additional Gasoline Production..........................      -2,484      -2,826      -2,638      -3,141      -4,350      -4,948      -4,507      -5,270
Total Cost Excluding Subsidies..........................         619         582         548         496       1,606       1,542       1,507       1,426
Per-Gallon Cost Excluding Subsidies (cents per gallon)..        0.41        0.38        0.38        0.33        1.05        1.01        0.99        0.93
--------------------------------------------------------------------------------------------------------------------------------------------------------

    Our analysis shows that when considering all the costs associated
with these fuel changes resulting from the expanded use of subsidized
ethanol that these various possible gasoline use scenarios will cost
the U.S. $0.5 billion to around $1.6 billion in the year 2012.
Expressed as per-gallon costs, these fuel changes would cost the U.S.
0.3 to just over 1 cent per gallon of gasoline.
    b. Gasoline Costs Including Ethanol Consumption Tax Subsidies.
Table VII.C.5.b-1 expresses the total and per-gallon gasoline costs for
the four control scenarios with the Federal and state ethanol subsidies
included. The Federal tax subsidy is 51 cents per gallon for each
gallon of new ethanol blended into gasoline. The state tax subsidies
apply in 5 states and range from 1.6 to 29 cents per gallon. The cost
reduction to the fuel industry and consumers are estimated by
multiplying the subsidy times the volume of new ethanol estimated to be
used in the state. The costs are presented for the case that ethanol
causes butanes to be withheld from the wintertime gasoline pool, and
for the case that the blending of butanes remains unchanged.

                                         Table VII.C.5.b-1.--Estimated Cost Including Subsidies ($47/bbl Crude)
                                                          [million dollars, except where noted]
--------------------------------------------------------------------------------------------------------------------------------------------------------

--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                           7.2 Bil Gals Max RFG
                                                           7.2 Bil Gals Min RFG
                                                           9.6 Bil Gals Max RFG
                                                           9.6 Bil Gals Min RFG
--------------------------------------------------------------------------------------------------------------------------------------------------------
Butane Removed in Winter................................      Yes         No          Yes         No          Yes         No          Yes         No
--------------------------------------------------------------------------------------------------------------------------------------------------------
Total Cost without Subsidies............................         619         582         548         496       1,606       1,542       1,507       1,426
Federal Subsidy.........................................      -1,684      -1,684      -1,684      -1,684      -2,908      -2,908      -2,908      -3,908
State Subsidies.........................................        -180        -180        -173        -173        -189        -189        -176        -176
Total Cost Including Subsidies..........................      -1,245      -1,282      -1,308      -1,361      -1,491      -1,555      -1,578      -1,657
Per-Gallon Cost Including Subsidies (cents/gallon)......       -0.82       -0.84       -0.86       -0.89       -0.98       -1.02       -1.03       -1.08
--------------------------------------------------------------------------------------------------------------------------------------------------------

    The cost including subsidies better represents gasoline's
production cost as might be reflected to the fuel industry as a whole
and to consumers ``at the pump'' because the Federal and state
subsidies tends to hide a portion of the actual costs. Our analysis
suggests that the fuel industry and consumers will see a 0.8 to 1.1
cent per gallon decrease in the apparent cost of producing gasoline
with these changes to gasoline.
    c. Cost Sensitivity Case Assuming $70 per Barrel Crude Oil. As
described above, we analyzed a sensitivity analysis with the future
price of crude oil remained at today's prices which is around $70 per
barrel. This analysis was conducted by applying about a 1.4
multiplication factor times the 2004 gasoline production costs, MTBE
and alkylate feedstock costs and butane value. This factor was derived
by examining the historical association between increasing wholesale
gasoline prices with increasing crude oil prices. We did not adjust the
distribution costs, any of the utility costs, octane value and ethanol
prices based on the assumption that these would change much less and
therefore we kept them the same as that used in the primary analysis.
The cost results of the sensitivity analysis are provided with and
without the ethanol consumption subsidies in Table VII.C.5.c-1.

                                       Table VII.C.5.c-1.--Estimated Costs for Crude Oil Priced at $70 Per Barrel
                                                         [Million dollars and cents per gallon]
--------------------------------------------------------------------------------------------------------------------------------------------------------

--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                           7.2 Bil gals, max RFG
                                                           7.2 Bil gals, min RFG
                                                           9.6 Bil gals, max RFG
                                                           9.6 Bil gals, min RFG
--------------------------------------------------------------------------------------------------------------------------------------------------------
Butane Removed in Winter................................      Yes         No          Yes         No          Yes         No          Yes         No
--------------------------------------------------------------------------------------------------------------------------------------------------------

Total Cost without Subsidies ($million).................        -171        -187        -223        -245         222         196         138         105
Per-Gallon Cost without Subsidies (c/gal)...............       -0.11       -0.12       -0.15       -0.16        0.15        0.13        0.09        0.07
Total Cost Including Subsidies ($million)...............      -2,035      -2,051      -2,080      -2,102      -2,875      -2,901      -2,945      -2,978
Per-Gallon Cost Including Subsidies (c/gal).............       -1.34       -1.35       -1.37       -1.38       -1.88       -1.90       -1.93       -1.95
--------------------------------------------------------------------------------------------------------------------------------------------------------

    If crude oil stays priced at around $70 per barrel, the cost of
these fuel changes would decrease significantly. In fact, we estimate
that the 7.2 billion gallon ethanol case would result in a cost savings
to the U.S. even if butanes are removed from the wintertime gasoline
pool when ethanol is added. When considering the ethanol subsidies, the
incentive to blend in ethanol becomes much stronger at today's crude
oil prices likely causing a rapid increase in ethanol production
volume.

VIII. What Are the Impacts of Increased Ethanol Use on Emissions and
Air Quality?

    In this section, we evaluate the impact of increased production and
use of renewable fuels on emissions and air quality in the U.S.,
particularly ethanol and biodiesel. In performing these analyses, we
compare the emissions which would have occurred in the future if fuel
quality had remained unchanged from pre-Act levels to those which will
be required under the Energy Policy Act of 2005 (Energy Act or the
Act). This approach differs from that traditionally taken in EPA
regulatory impact analyses. Traditionally, we would have compared
future emissions with and without the requirement of the Energy Act.
However, as described in Section VI, we expect that total renewable
fuel use in the U.S. in 2012 to exceed 7.5 billion gallons even in the
absence of the RFS program. Thus, a traditional regulatory impact
analysis would have shown no impact on emissions or air quality.
    Strictly speaking, if the same volume and types of renewable fuels
are produced and used with and without the RFS program, the RFS program
is having no impact on emissions or air quality. However, levels of
renewable fuel use are increasing dramatically relative to both today
and the recent past, with corresponding impacts on emissions and air
quality. We believe that it is appropriate to evaluate these changes
here, regardless of whether they are occurring due to economic forces
or Energy Act requirements.
    In the process of estimating the impact of increased renewable fuel
use, we also include the impact of reduced use of MTBE in gasoline. It
is the increased production and use of ethanol which is facilitating
the removal of MTBE while still producing the required volume of RFG
which meets both commercial and EPA regulatory specifications. Because
of this connection, we found it impractical to isolate the impact of
increased ethanol use from the removal of MTBE.

A. Effect of Renewable Fuel Use on Emissions

1. Emissions From Gasoline Fueled Motor Vehicles and Equipment
    Several models of the impact of gasoline quality on motor vehicle
emissions have been developed since the early 1990's. We evaluated
these models and selected those which were based on the most
comprehensive set of emissions data and developed using the most
advanced statistical tools for this analysis. Still, as will be
described below, significant uncertainty still exists as to the effect
of these gasoline components on emissions from both motor vehicle and
nonroad equipment, particularly from the latest models equipped with
the most advanced emission controls. Pending adequate funding, we plan
to conduct significant vehicle and equipment testing over the next
several years to improve our estimates of the impact of these additives
and other gasoline properties on emissions. The results of this testing
will not be available for inclusion in the analyses supporting this
rulemaking. We hope that the results from these test programs will be
available for reference in the future evaluations of the emission and
air quality impacts of U.S. fuel programs required by the Act.\80\
---------------------------------------------------------------------------

    \80\ Subject to funding.
---------------------------------------------------------------------------

    The remainder of this sub-section is divided into three parts. The
first evaluates the impact of increased ethanol use and decreased MTBE
use on gasoline quality. The second evaluates the impact of increased
ethanol use and decreased MTBE use on motor vehicle emissions. The
third evaluates the impact of increased ethanol use and decreased MTBE
use on nonroad equipment emissions.
    a. Gasoline Fuel Quality. For this proposal, we estimate the impact
of ethanol use on gasoline quality using fuel survey data obtained by
Alliance of Automobile Manufacturers (AAM) from 2001-2005.\81\ We
estimate the impact of removing MTBE from gasoline based on refinery
modeling performed in support of the RFG rulemaking. We plan to update
these estimates for the FRM using refinery modeling which is currently
underway. In general, as shown in Table VIII.A.1.a-1, adding ethanol to
gasoline is expected to reduce levels of aromatics and olefins in
conventional gasoline, as well as reduce mid and high distillation
temperatures (e.g., T50 and T90). RVP is expected to increase, as most
areas of the country grant ethanol blends a 1.0 RVP waiver of the
applicable RVP standards in the summer. With the exception of RVP, the
effect of removing MTBE results in essentially the opposite impacts.
Please see Chapter 2 of the DRIA for a detailed description of the
methodologies used and the specific changes in projected fuel quality.
---------------------------------------------------------------------------

    \81\ Alliance of Automobile Manufacturers North American Fuel
Survey 2005. For the final rule, we intend to supplement this
empirical approach with the results of refinery modeling which might
better capture all of the effects of ethanol blending on gasoline
quality.

    Table VIII.A.1.a-1.--CG Fuel Quality With and Without Oxygenates
------------------------------------------------------------------------
                                       Typical 9    MTBE CG   Ethanol CG
           Fuel parameter               RVP CG       blend       blend
------------------------------------------------------------------------
RVP (psi)...........................         8.7         8.7         9.7
T50.................................         218         206         186
T90.................................         332         324         325
Aromatics (vol%)....................          32        25.5          27
Olefins (vol%)......................         7.7         7.7         6.1
Oxygen (wt%)........................           0           2         3.5
Sulfur (ppm)........................          30          30          30
Benzene (vol%)......................         1.0         1.0         1.0
------------------------------------------------------------------------

    The effect of adding ethanol and removing MTBE on the quality of
RFG is expected to very limited. RFG must meet stringent VOC,
NOX and toxics performance standards. Thus, the natural
effects of MTBE and ethanol blending on gasoline must often be
addressed through further refining. The largest differences are
expected to exist in terms of the distillation temperatures, due to the
relatively low boiling point of ethanol. Other fuel parameters are
expected to be very similar. For this analysis we have assumed no
changes to fuel parameters other than ethanol and MTBE content for RFG.
    b. Emissions from Motor Vehicles. We use the EPA Predictive Models
to estimate the impact of gasoline fuel quality on exhaust VOC and
NOX emissions from motor vehicles. These models were
developed in 2000, in support of EPA's response to California's request
for a waiver of the RFG oxygen mandate. These models represent a
significant update of the EPA Complex Model. However, they are still
based on emission data from Tier 0 vehicles (roughly equivalent to 1990
model year vehicles). We based our estimates of the impact of fuel
quality on CO emissions on the EPA MOBILE6.2 model. We base our
estimates of the impact of fuel quality on exhaust toxic emissions
(benzene, formaldehyde, acetaldehyde, and 1,3-butadiene) primarily on
the MOBILE6.2 model, updated to reflect the effect of fuel quality on
exhaust VOC emissions per the EPA Predictive Models. Very limited data
are available on the effect of gasoline quality on PM emissions.
Therefore, the effect of increased ethanol use on PM emissions can only
be qualitatively discussed.
    In responding to California's request for a waiver of the RFG
oxygen mandate in 2000, we found that both very limited and conflicting
data were available on the effect of fuel quality on exhaust emissions
from Tier 1 and later vehicles.\82\ Thus, we assumed at the time that
changes to gasoline quality would not affect VOC, CO and NOX
exhaust emissions from these vehicles. Very little additional data has
been collected since that time on which to modify this assumption.
Consequently, for our primary analysis for today's proposal we have
maintained the assumption that changes to gasoline do not affect
exhaust emissions from Tier 1 and later technology vehicles.
---------------------------------------------------------------------------

    \82\ The one exception was the impact of sulfur on emissions
from these later vehicles, which is not an issue here due to the
fact that renewable fuel use is not expected to change sulfur levels
significantly.
---------------------------------------------------------------------------

    There is one recent study by the Coordinating Research Council
(CRC) which assessed the impact of ethanol and two other fuel
properties on emissions from twelve 2000-2004 model year vehicles (CRC
study E-67). The results of this program indicate that emissions from
these late model year vehicles may be at least as sensitive to changes
to these three fuel properties as Tier 0 vehicles on a percentage
basis.\83\ However, because this study is the first of its kind and not
all relevant fuel properties have yet been studied, in our primary
analysis we continue to assume that exhaust emissions from Tier 1 and
later vehicles are not sensitive to fuel quality. Based on the
indications of the CRC E-67 study, we also conducted a sensitivity
analysis where the exhaust VOC and NOX emission impacts for
all vehicles were assumed to be as sensitive to fuel quality as Tier 0
vehicles (i.e., as indicated by the EPA Predictive Models).
---------------------------------------------------------------------------

    \83\ The VOC and NOX emissions from the 2000-2004
model year vehicles are an order of magnitude lower than those from
the Tier 0 vehicles used to develop the EPA Complex and Predictive
Models. Thus, a similar impact of a fuel parameter in terms of
percentage means a much smaller impact in terms of absolute
emissions.
---------------------------------------------------------------------------

    We base our estimates of fuel quality on non-exhaust VOC and
benzene emissions on the EPA MOBILE6.2 model. The one exception to this
is the effect of ethanol on permeation emissions through plastic fuel
tanks and elastomers used in fuel line connections. Recent testing has
shown that ethanol increases permeation emissions, both by permeating
itself and increasing the permeation of other gasoline components. This
effect was included in EPA's analysis of California's most recent
request for a waiver of the RFG oxygen requirement, but is not in
MOBILE6.2.\84\ Therefore, we have added the effect of ethanol on
permeation emissions to MOBILE6.2's estimate of non-exhaust VOC
emissions in assessing the impact of gasoline quality on these
emissions.
---------------------------------------------------------------------------

    \84\ For more information on California's request for a waiver
of the RFG oxygen mandate and the Decision Document for EPA's
response, see http://www.epa.gov/otaq/rfg_regs.htm#waiver.

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

    No models are available which address the impact of gasoline
quality on PM emissions. Very limited data indicate that ethanol
blending might reduce exhaust PM emissions under very cold weather
conditions (e.g., -20 F to 0 F). Very limited testing at warmer
temperatures (e.g., 20 F to 75 F) shows no definite trend in PM
emissions with oxygen content. Thus, for now, no quantitative estimates
can be made regarding the effect of ethanol use on direct PM emissions.
    Table VIII.A.1.b-1 presents the average per vehicle (2012 fleet)
emission impacts of three types of RFG: Non-oxygenated, a typical MTBE
RFG as has been marketed in the Gulf Coast, and a typical ethanol RFG
which has been marketed in the Midwest.

  Table VIII.A.1.b-1.--Effect of RFG on Per Mile Emissions From Tier 0 Vehicles Relative to a Typical 9psi RVP
                                             Conventional Gasoline a
----------------------------------------------------------------------------------------------------------------
                                                                                10 Volume
               Pollutant                         Source             Non-Oxy RFG      11 Volume        percent
                                                                     (percent)     percent MTBE       ethanol
----------------------------------------------------------------------------------------------------------------
                                                Exhaust Emissions
----------------------------------------------------------------------------------------------------------------
VOC...................................  EPA Predictive Models...            -7.7           -11.1           -12.9
NOX...................................  ........................            -1.7             2.4             6.3
CO....................................  MOBILE6.2...............             -24             -28             -32
Exhaust Benzene.......................  EPA Predictive and                   -18             -30             -35
                                         Complex Models.
Formaldehyde..........................  ........................               7              11               2
Acetaldehyde..........................  ........................               7              -8             143
1,3-Butadiene.........................  ........................              22               2              -7
----------------------------------------------------------------------------------------------------------------
                                              Non-Exhaust Emissions
----------------------------------------------------------------------------------------------------------------
VOC...................................  MOBILE6.2 & CRC E-65....             -30             -30             -18
Benzene...............................  MOBILE6.2 & Complex                   -5             -15              -7
                                         Models.
----------------------------------------------------------------------------------------------------------------
\a\ Average per vehicle effects for the 2012 fleet during summer conditions.

    As can be seen, the oxygenated RFG blends are predicted to produce
a greater reduction in exhaust VOC and CO emissions than 9 RVP
conventional gasoline, but a larger increase in NOX
emissions. This comparison assumes that all gasoline meets EPA's Tier 2
gasoline sulfur standard of 30 ppm. Prior to this program, RFG
contained less sulfur than conventional gasoline and produced less
NOX emissions. Non-exhaust VOC emissions with the exception
of permeation are roughly the same due to the fact that the RVP level
of the three blends is the same. However, the increased permeation
emissions associated with ethanol reduces the overall effectiveness of
ethanol RFG.
    An increase in ethanol use will also impact emissions of air
toxics. We evaluated effects on four air toxics affected by fuel
parameter changes in the Complex Model-benzene, formaldehyde,
acetaldehyde and 1,3-butadiene. The most notable effect on toxic
emissions in percentage terms is the increase in acetaldehyde with the
use of ethanol. Acetaldehyde emissions more than double. However, as
will be seen below, base acetaldehyde emissions are low relative to the
other toxics. Thus, the absolute increase in total emissions of these
four air toxics is still relatively low.
    Table VIII.A.1.b-2 presents the effect of blending either MTBE or
ethanol into conventional gasoline while matching octane.

Table VIII.A.1.b-2.--Effect of MTBE and Ethanol in Conventional Gasoline on Tier 0 Vehicle Emissions Relative to
                                a Typical Non-Oxygenated Conventional Gasoline a
----------------------------------------------------------------------------------------------------------------
                                                                                10 Volume
                    Pollutant                                   Source                  11 Volume      percent
                                                                                percent MTBE   ethanol \b\
----------------------------------------------------------------------------------------------------------------
Exhaust VOC.....................................  EPA Predictive Models.............          -9.2          -7.4
NOX.............................................  ..................................           2.6           7.7
CO \c\..........................................  MOBILE6.2.........................      -6/-11       -11/-19
Exhaust Benzene.................................  EPA Predictive and Complex Models.         -22           -27
Formaldehyde....................................  ..................................         +10            +3
Acetaldehyde....................................  ..................................          -8          +141
1,3-Butadiene...................................  ..................................         -12           -27
Non-Exhaust VOC.................................  MOBILE6.2.........................           0           +17
Non-Exhaust Benzene.............................  MOBILE6.2 & Complex Models........         -10           +13
----------------------------------------------------------------------------------------------------------------
\a\ Average per vehicle effects for the 2012 fleet during summer conditions.
\b\ Assumes a 1.0 psi RVP waiver for ethanol blends.
\c\ The first figure shown applies to normal emitters; the second applies to high emitters.

    As was the case with the RFG blends, the two oxygenated blends both
reduce exhaust VOC and CO emissions, but increase NOX
emissions. The MTBE blend does not increase non-exhaust VOC emissions,
but the ethanol blend does due to the commonly granted waiver of the
RVP standard. Both blends have lower exhaust benzene and 1,3-butadiene
emissions. As above, ethanol increases non-exhaust benzene and
acetaldehyde emissions.
    The exhaust emission effects shown above for VOC and NOX
emissions only apply to Tier 0 vehicles in our primary analysis. For
example, MOBILE6.2 estimates that 34% of exhaust VOC emissions and 16%
of NOX emissions from gasoline vehicles in 2012 come from
Tier 0 vehicles. In the sensitivity analysis, these effects are
extended to all gasoline vehicles. The effect of RVP on non-exhaust VOC
emissions is temperature dependent. The figures shown above are based
on the distribution of temperatures occurring across the U.S. in July.
    c. Nonroad Equipment. To estimate the effect of gasoline quality on
emissions from nonroad equipment, we used EPA's NONROAD emission model.
We used the 2005 version of this model, NONROAD2005, which includes the
effect of ethanol on permeation emissions from most nonroad equipment.

    Only sulfur and oxygen content affect exhaust VOC, CO and
NOX emissions in NONROAD. Since sulfur level is assumed to
remain constant, the only difference in exhaust emissions between
conventional and reformulated gasoline is due to oxygen content. Table
VIII.A.1.c-1 shows the effect of adding 11 volume percent MTBE or 10
volume percent ethanol to non-oxygenated gasoline on these emissions.

                    Table VIII.A.1.c-1.--Effect MTBE and Ethanol on Nonroad Exhaust Emissions
----------------------------------------------------------------------------------------------------------------
                                                                  4-Stroke engines          2-Stroke engines
                                                             ---------------------------------------------------
                          Base fuel                            11 Volume    10 Volume    11 Volume    10 Volume
                                                                percent      percent      percent      percent
                                                                  MTBE       ethanol        MTBE       ethanol
----------------------------------------------------------------------------------------------------------------
Exhaust VOC.................................................           -9          -15           -1           -1
Non-Exhaust VOC 0...........................................            0           26            0           26
CO..........................................................          -13          -21           -8          -12
NOX.........................................................          +24          +37          +12          +18
----------------------------------------------------------------------------------------------------------------

    As can be seen, higher oxygen content reduces exhaust VOC and CO
emissions significantly, but also increases NOX emissions.
However, NOX emissions from these engines tend to be fairly
low to start with, given the fact that these engines run much richer
than stoichiometric. Thus, a large percentage increase of a relative
low base value can be a relatively small increase in absolute terms.
    Evaporative emissions from nonroad equipment are impacted by only
RVP, and permeation by ethanol content. Both the RVP increase due to
blending of ethanol and its permeation effect cause non-exhaust VOC
emissions to increase with the use of ethanol in nonroad equipment. The
26 percent effect represents the average impact across the U.S. in July
for both 2-stroke and 4-stroke equipment. We updated the NONROAD2005
hose permeation emission factors for small spark-ignition engines and
recreational marine watercraft to reflect the use of ethanol.
    For nonroad toxics emissions, we base our estimates of the impact
of fuel quality on the fraction of exhaust VOC emissions represented by
each toxic on MOBILE6.2 (i.e., the same effects predicted for onroad
vehicles). The National Mobile Inventory Model (NMIM) contains
estimates of the fraction of VOC emissions represented by the various
air toxics based on oxygenate type (none, MTBE or ethanol). However,
estimates for nonroad gasoline engines running on different fuel types
are limited, making it difficult to accurately model the impacts of
changes in fuel quality. In the recent NPRM addressing mobile air toxic
emissions, EPA replaced the toxic-related fuel effects contained in
NMIM with those from MOBILE6.2 for onroad vehicles.\85\ We follow the
same methodology here. Future testing could significantly alter these
emission impact estimates.
---------------------------------------------------------------------------

    \85\ 71, Federal Register, 15804, March 29, 2006.
---------------------------------------------------------------------------

2. Diesel Fuel Quality: Biodiesel
    EPA assessed the impact of biodiesel fuel on emissions in 2002 and
published a draft report summarizing the results.\86\ At that time,
most of the data available was for pre-1998 model year onroad diesel
engines. The results are summarized in Table VIII.A.2-1. As shown, it
indicated that biodiesel tended to reduce emissions of VOC, CO and PM.
The NOX emission effect was more variable, showing a very
small increase on average.
---------------------------------------------------------------------------

    \86\ ``A Comprehensive Analysis of Biodiesel Impacts on Exhaust
Emissions,'' Draft Technical Report, U.S. EPA, EPA420-P-02-001,
October 2002. http://www.epa.gov/[fxsp0]otaq/models/biodsl.htm.

                  Table VIII.A.2-1.--Effect of 20 Vo% Biodiesel Blends on Diesel Emissions (%)
----------------------------------------------------------------------------------------------------------------
                                2002 draft                           Recent test results
          Pollutant             EPA study  ---------------------------------------------------------------------
                                (percent)             Engine testing                    Vehicle testing
----------------------------------------------------------------------------------------------------------------
VOC..........................          -21  -12% (-35% to +14%)..............  +10% (-33% to +113%)
CO...........................          -11  -14% (-28% to +1%)...............  +4% (-11% to +44%)
NOX..........................           +2  +1% (-3% to +6%).................  +2% (-1% to +9%)
PM...........................          -10  -20% (-31%+6%)...................  -3% (-57% to +40%)
----------------------------------------------------------------------------------------------------------------

    We collected relevant engine and vehicle emission test data
developed since the time of the 2002 study. The results of our analysis
of this data are also shown in Table VIII.A.2-1. There, we show the
average change in the emissions of each pollutant across all the
engines or vehicles tested, as well as the range of effects found for
each engine or vehicle. As can be seen, the variability in the emission
effects is quite large, but the results of the more recent testing
generally corroborate the findings of the 2002 study. Refer to DRIA
Tables 3.1-15 and 3.1-16, and their corresponding discussion, for more
detail on the data in the above table.
    Overall, data indicating the effect of biodiesel on emissions is
still quite limited. The emission effects also appear to be dependent
on the load and speed of the engine (or driving cycle and vehicle type
in the case of vehicle testing). However, the data are too limited to
determine the specific way in which this occurs. Also, with the
implementation of stringent NOX and PM emission standards to
onroad and nonroad diesels in the 2007-2010 timeframe, any effect on a
percentage basis will rapidly decrease in magnitude on a mass basis as
base emission inventory level decreases. As additional testing is
performed over the next several years we will update this assessment.
3. Renewable Fuel Production and Distribution
    The primary impact of renewable fuel production and distribution
regards ethanol, since it is expected to be the

predominant renewable fuel used in the foreseeable future. We
approximate the impact of increased ethanol and biodiesel production,
including corn and soy farming, on emissions based on DOE's GREET
model, version 1.6. We also include emissions related to distributing
the renewable fuels and take credit for reduced emissions related to
distributing displaced gasoline and diesel fuel. These emissions are
summarized in Table VIII.A.3-1.

Table VIII.A.3-1.--Well-to-Pump Emissions for Producing and Distributing
                             Renewable Fuels
                [Grams per gallon ethanol or biodiesel] a
------------------------------------------------------------------------
                   Pollutant                      Ethanol     Biodiesel
------------------------------------------------------------------------
VOC...........................................          3.6         41.5
CO............................................          4.4         25.1
NOX...........................................         10.8         44.3
PM10..........................................          6.1          1.5
SOX...........................................          7.2          7.5
------------------------------------------------------------------------
a Includes credit for reduced distribution of gasoline and diesel fuel.

    At the same time, areas with refineries might experience reduced
emissions, not necessarily relative to current emission levels, but
relative to those which would have occurred in the future had renewable
fuel use not risen. However, to the degree that increased renewable
fuel use reduces imports of gasoline and diesel fuel, as opposed to the
domestic production of these fuels, these reduced refinery emissions
will occur overseas and not in the U.S.
    Similarly, areas with MTBE production facilities might experience
reduced emissions from these plants as they cease producing MTBE.
However, many of these plants may be converted to produce other
gasoline blendstocks, such as iso-octane or alkylate. In this case,
their emissions are not likely to change substantially.

B. Impact on Emission Inventories

    We use the NMIM to estimate emissions under the various ethanol
scenarios on a county by county basis. NMIM basically runs MOBILE6.2
and NONROAD2005 with county-specific inputs pertaining to fuel quality,
ambient conditions, levels of onroad vehicle VMT and nonroad equipment
usage, etc. We ran NMIM for two months, July and January. We estimate
annual emission inventories by summing the two monthly inventories and
multiplying by six.
    As described above, we removed the effect of gasoline fuel quality
on exhaust VOC and NOX emissions from the onroad motor
vehicle inventories which are embedded in MOBILE6.2. We then applied
the exhaust emission effects from the EPA Predictive Models. In our
primary analysis, we only applied these EPA Predictive Model effects to
exhaust VOC and NOX emissions from Tier 0 vehicles. In a
sensitivity case, we applied them to exhaust VOC and NOX
emissions from all vehicles. Regarding the effect of fuel quality on
emissions of four air toxics from nonroad equipment (in terms of their
fraction of VOC emissions), in all cases we replaced the fuel effects
contained in NMIM with those for motor vehicles contained in MOBILE6.2.
The projected emission inventories for the primary analysis are
presented first, followed by those for the sensitivity analysis.
1. Primary Analysis
    The national emission inventories for VOC, CO and NOX in
2012 with current fuels (i.e., ``reference fuel'') are summarized in
Table VIII.B.1-1. Also shown are the changes in emissions projected for
the two levels of ethanol use (i.e., ``control cases'') described in
Section VI and the two different cases for ethanol use in RFG.

  Table VIII.B.1.-1.--2012 Emissions Nationwide From Gasoline Vehicles and Equipment Under Several Ethanol Use
                                           Scenarios--Primary Analysis
                                                 [Tons per year]
----------------------------------------------------------------------------------------------------------------
                                     Inventory                 Change in inventory in control cases
                                 -------------------------------------------------------------------------------
                                                    7.2 Billion           9.6 Billion gallons of ethanol
                                                    gallons of   -----------------------------------------------
            Pollutant                                 ethanol
                                  Reference case ----------------   Maximum RFG     Minimum RFG     Maximum RFG
                                                    Minimum RFG         use             use             use
                                                        use
----------------------------------------------------------------------------------------------------------------
VOC.............................       5,837,000          31,000           8,000          57,000          29,000
NOX.............................       2,576,000          19,000          20,000          40,000          39,000
CO..............................      64,799,000        -843,000      -1,229,000      -1,971,000      -2,319,000
Benzene.........................         177,000          -6,000          -3,000         -11,000          -8,000
Formaldehyde....................          40,200             300               0             800             500
Acetaldehyde....................          19,800           6,200           5,000           9,600           8,500
1,3-Butadiene...................          18,200            -500            -300            -800            -600
----------------------------------------------------------------------------------------------------------------

    Both VOC and NOX emissions are projected to increase
with increased use of ethanol. However, the increases are small,
generally less than 2 percent. Emissions of formaldehyde are also
projected to increase slightly, on the order of 1-3 percent. Emissions
of 1,3-butadiene and CO are projected to decrease by about 1-4 percent.
Benzene emissions are projected to decrease by 2-6 percent. The largest
change is in acetaldehyde emissions, an increase of 25-48 percent, as
acetaldehyde is a partial combustion product of ethanol.
    CO also participates in forming ozone, much like VOCs. Generally,
CO is 15-50 times less reactive than typical VOC. Still, the reduction
in CO emissions is roughly 20-140 times the increase in VOC emissions
in the four scenarios. Thus, the projected reduction in CO emissions is
important from an ozone perspective. However, as described above, the
methodology for projecting the effect of ethanol use on CO emissions is
inconsistent with that for exhaust VOC and NOX emissions.
Thus, comparisons between changes in VOC and CO emissions are
particularly uncertain.
    In addition to these changes in emissions due to ethanol use,
biodiesel use is expected to have a minor impact on diesel emissions.
Table VIII.B.1-2 shows the expected emission reductions associated with
an increase in biodiesel fuel use from the reference case of 28 million
gallons in 2012 to approximately 300 million gallons per year in 2012.
This represents an increase from 0.06 to 0.6 percent of onroad diesel
fuel consumption. In terms of a 20 percent biodiesel blend

(B20), it represents an increase from 0.3 to 3.2 percent of onroad
diesel fuel consumption.

  Table VIII.B.1-2.--Annual Emissions Nationwide From Onroad Diesels in
                                  2012
                             [Tons per year]
------------------------------------------------------------------------
                                                             Change in
                                             Reference       emissions
                                           inventory: 28  Inventory: 300
                                             mill gal        mill gal
                                           biodiesel per   biodiesel per
                                               year            year
------------------------------------------------------------------------
VOC.....................................         135,000            -800
NOX.....................................       1,430,000             800
CO......................................         353,000          -1,100
Fine PM.................................          27,000            -100
------------------------------------------------------------------------

    As can be seen, the emission impacts due to biodiesel use are
roughly two orders of magnitude smaller than those due to ethanol use.
    There will also be some increases in emissions due to ethanol and
biodiesel production. Table VIII.B.1-3 shows estimates of annual
emissions expected to occur nationwide due to increased production of
ethanol. These estimates include a reduction in emissions related to
the distribution of the displaced gasoline.

            Table VIII.B.1-3.--Annual Emissions Nationwide From Ethanol Production and Transportation
                                                 [Tons per year]
----------------------------------------------------------------------------------------------------------------
                                                                                Increase in emissions
                                                                                -------------------------------
                                                                     Reference      7.2 Billion     9.6 Billion
                                                                     inventory      gallons of      gallons of
                                                                                ethanol         ethanol
----------------------------------------------------------------------------------------------------------------
VOC.............................................................          15,929          12,744          22,301
NOX.............................................................          47,716          38,173          66,802
CO..............................................................          19,389          15,511          27,144
PM10............................................................          27,094          21,675          37,931
SOX.............................................................          31,760          25,408          44,464
----------------------------------------------------------------------------------------------------------------

    As can be seen, the potential increases in emissions from ethanol
production and transportation are of the same order of magnitude as
those from ethanol use, with the exception of CO emissions. The vast