Regulation of Fuels and Fuel Additives: Renewable Fuel Standard Program [[pp. 55601-55651]]
[Federal Register: September 22, 2006 (Volume 71, Number 184)]
[Proposed Rules]
[Page 55601-55651]
From the Federal Register Online via GPO Access [wais.access.gpo.gov]
[DOCID:fr22se06-29]
[[pp. 55601-55651]]
Regulation of Fuels and Fuel Additives: Renewable Fuel
Standard Program
[[Continued from page 55600]]
[[Page 55601]]
Total....................................................... 4,872 102 2,218 39 259 9 7,349 141
--------------------------------------------------------------------------------------------------------------------------------------------------------
\a\ Under Construction.
A select group of builders, technology providers, and construction
contractors are completing the majority of the construction projects
described in Table VI.A.2-1. As such, the completion dates of these
projects are staggered over approximately 18 months, resulting in the
gradual phase-in of ethanol production shown in Figure VI.A.2-2.
[GRAPHIC]
[TIFF OMITTED]
TP22SE06.003
As shown in Table VI.A.2-1 and Figure VI.A.2-2, once all the
construction projects currently underway are complete (estimated by
December 2007), the resulting U.S. ethanol production capacity would be
over 7.3 billion gallons. Together with estimated biodiesel production
(300 million gallons by 2012), this would be more than enough renewable
fuel to satisfy the 2012 renewable fuel requirement (7.5 billion
gallons) contained in the Act. However, ethanol production is not
expected to stop here. There are more and more ethanol projects being
announced each day. Many of these potential projects are at various
stages of planning, such as conducting feasibility studies, gaining
city/county approval, applying for permits, applying for financing/
fundraising, or obtaining contractor agreements. Other projects have
been proposed or announced, but have not entered the formal planning
process. If all these plants were to come to fruition, the combined
domestic ethanol production could exceed 20 billion gallons as shown in
Table VI.A.2-2.
[[Page 55602]]
Table VI.A.2-2.--Potential U.S. Ethanol Production Projects
--------------------------------------------------------------------------------------------------------------------------------------------------------
2006 baseline + UC Planned Proposed Total ETOH potential
\a\ -----------------------------------------------------------------
-----------------------
MMGal/yr Plants MMGal/yr Plants MMGal/yr Plants MMGal/yr Plants
--------------------------------------------------------------------------------------------------------------------------------------------------------
PADD 1......................................................... 0.4 1 250 3 1,005 21 1,255 25
PADD 2......................................................... 7,010 128 1,940 15 7,508 90 16,458 233
PADD 3......................................................... 60 2 108 1 599 9 767 12
PADD 4......................................................... 155 5 0 0 815 14 970 19
PADD 5......................................................... 124 5 128 2 676 18 928 25
----------------------------------------------------------------------------------------
Total...................................................... 7,349 141 2,426 21 10,603 152 20,378 314
--------------------------------------------------------------------------------------------------------------------------------------------------------
\a\ Under Construction.
However, although there is clearly a great potential for growth in
ethanol production, it is unlikely that all the announced projects
would actually reach completion in a reasonable amount of time. There
is no precise way to know exactly which plants would come to fruition
in the future; however, we've chosen to focus our further discussions
on only those plants which are under construction or in the final
planning stages (denoted as ``planned'' above in Table VI.A.2-2). The
distinction between ``planned'' versus ``proposed'' is that as of June
2006 planned projects had completed permitting, fundraising/financing,
and had builders assigned with definitive construction timelines
whereas proposed projects did not.
As shown in Table VI.A.2-2, once all the under construction and
planned projects are complete (by 2012 or sooner), the resulting U.S.
ethanol production capacity would be 9.8 billion gallons, exceeding the
2012 EIA demand estimate (9.6 billion gallons). This forecasted growth
would double today's production capacity and greatly exceed the 2012
renewable fuel requirement (7.5 billion gallons). In addition, domestic
ethanol production would be supplemented by imports, which are also
expected to increase in the future (as discussed in DRIA Section 1.5).
Of the 60 forecasted new ethanol plants (39 under construction and
21 planned), all would (at least initially) rely on grain-based
feedstocks. Of the plants, 56 would rely exclusively on corn as a
feedstock. As for the remaining plants: Two would rely on both corn and
milo, one would process molasses and sweet sorghum, and the last would
start off processing corn and then transition into processing bagasse,
rice hulls, and wood.
Under the Energy Act, the RFS program requires that 250 million
gallons of the renewable fuel consumed in 2013 and beyond meet the
definition of cellulosic biomass ethanol. As discussed in Section
III.B.1, the Act defines cellulosic biomass ethanol as ethanol derived
from any lignocellulosic or hemicellulosic matter that is available on
a renewable or recurring basis including dedicated energy crops and
trees, wood and wood residues, plants, grasses, agricultural residues,
fibers, animal wastes and other waste materials, and municipal solid
waste. The term also includes any ethanol produced in facilities where
animal or other waste materials are digested or otherwise used to
displace 90 percent of more of the fossil fuel normally used in the
production of ethanol.
Of the 60 forecasted plants, only one is expected to meet the
definition of ``cellulosic biomass ethanol'' based on feedstocks. The
planned 108 MMgal/yr facility would start off processing corn and then
transition into processing bagasse, rice hulls, and wood (cellulosic
feedstocks). It is unclear as to whether this facility would be
processing cellulosic material by 2013, however there are several other
facilities that could potentially meet the Act's definition of
cellulosic ethanol based on plant energy sources. In total, there are
seven ethanol plants that burn or plan to burn renewable feedstocks to
generate steam for their processes. As shown in Table VI.A.1-2, two
existing plants burn renewable feedstocks. One plant burns a
combination of coal and biomass and the other burns syrup from the
production process. Together these existing plants have a combined
ethanol production capacity of 99 MMgal/yr. Additionally, there are
four under construction ethanol plants which plan to burn renewable
fuels. One plant plans to burn a combination of coal and biomass, two
plants plan to rely on manure/syngas, and the other plans to start up
burning natural gas and then transition to biomass. Together these
under construction facilities have a combined ethanol production
capacity of 87 MMgal/yr. Finally, a planned 275 MMgal/yr ethanol
production facility plans to burn a combination of coal, tires, and
biomass. Depending on how much fossil fuel is displaced by these
renewable feedstocks (on a plant-by-plant basis), a portion or all of
the aforementioned ethanol production (up to 461 MMgal/yr) could
potentially qualify as ``cellulosic biomass ethanol'' under the Act.
Combined with the 108 MMgal/yr plant planning to process renewable
feedstocks, the total cellulosic potential could be as high as 569
MMgal/yr in 2013. Even if only half of this ethanol were to end up
qualifying as cellulosic biomass ethanol, it would still be more than
enough to satisfy the Act's cellulosic requirement (250 million
gallons).\41\
---------------------------------------------------------------------------
\41\ We anticipate a ramp-up in cellulosic ethanol production in
the years to come so that capacity exists to satisfy the 2013 Act's
requirement (250 million gallons of cellulosic biomass ethanol).
Therefore, for subsequent analysis purposes, we have assumed that
250 million gallons of ethanol would come from cellulosic biomass
sources by 2012.
---------------------------------------------------------------------------
3. Current Ethanol and MTBE Consumption
To understand the impact of the increased ethanol production/use on
gasoline properties and in turn overall air quality, we first need to
gain a better understanding of where ethanol is used today and how the
picture is going to change in the future. As such, in addition to the
production analysis presented above, we have completed a parallel
consumption analysis comparing current ethanol consumption to future
predictions.
In the 2004 base case, 3.5 billion gallons of ethanol \42\ and 1.9
billion gallons of MTBE \43\ were blended into gasoline to supply the
transportation sector with a total of 136 billion gallons of
gasoline.\44\ A breakdown of the 2004 gasoline and oxygenate
consumption by PADD is found below in Table VI. A.3-1.
---------------------------------------------------------------------------
\42\ EIA Monthly Energy Review, June 2006 (Table 10.1: Renewable
Energy Consumption by Source, Appendix A: Thermal Conversion
Factors).
\43\ File containing historical RFG MTBE usage obtained from EIA
representative on March 9, 2006.
\44\ EIA 2004 Petroleum Marketing Annually (Table 48: Prime
Supplier Sales Volumes of Motor Gasoline by Grade, Formulation, PAD
District, and State).
[[Page 55603]]
Table VI.A.3-1.--2004 U.S. Gasoline & Oxygenate Consumption by PADD
----------------------------------------------------------------------------------------------------------------
Ethanol MTBE \a\
PADD Gasoline ---------------------------------------------------
MMgal MMgal Percent MMgal Percent
----------------------------------------------------------------------------------------------------------------
PADD 1......................................... 49,193 660 1.34 1,360 2.76
PADD 2......................................... 38,789 1,616 4.17 1 0.00
PADD 3......................................... 20,615 79 0.38 498 2.42
PADD 4......................................... 4,542 83 1.83 0 0.00
PADD 5 \b\..................................... 7,918 209 2.63 19 0.23
California..................................... 14,836 853 5.75 0 0.00
----------------------------------------------------------------
Total...................................... 135,893 3,500 2.58 1,878 1.38
----------------------------------------------------------------------------------------------------------------
\a\ MTBE blended into RFG.
\b\ PADD 5 excluding California.
As shown above, nearly half (or about 45 percent) of the ethanol
was consumed in PADD 2 gasoline, not surprisingly, where the majority
of ethanol was produced. The next highest region of use was the State
of California which accounted for about 25 percent of domestic ethanol
consumption. This is reasonable because California alone accounts for
over 10 percent of the nation's total gasoline consumption and all the
fuel (both Federal RFG and California Phase 3 RFG) has been assumed to
contain ethanol (following their recent MTBE ban) at 5.7 volume
percent.\45\ The bulk of the remaining ethanol was used in reformulated
gasoline (RFG) and winter oxy-fuel areas requiring oxygenated gasoline.
Overall, 62 percent of ethanol was used in RFG, 33 percent was used in
CG, and 5 percent was used in winter oxy-fuel.\46\
---------------------------------------------------------------------------
\45\ Based on conversation with Dean Simeroth at California Air
Resources Board (CARB).
\46\ For the purpose of this analysis, except where noted, the
term pertains to Federal RFG plus California Phase 3 RFG (CaRFG3)
and Arizona Clean Burning Gasoline (CBG).
---------------------------------------------------------------------------
As shown above in Table VI.A.3-1, 99 percent of MTBE use occurred
in PADDs 1 and 3. This reflects the high concentration of RFG areas in
the northeast (PADD 1) and the local production of MTBE in the gulf
coast (PADD 3). PADD 1 receives a large portion of its gasoline from
PADD 3 refineries who either produce the fossil-fuel based oxygenate or
are closely affiliated with MTBE-producing petrochemical facilities in
the area. Overall, 100 percent of MTBE in 2004 was assumed to be used
in reformulated gasoline.\47\
---------------------------------------------------------------------------
\47\ 2004 MTBE consumption was obtained from EIA. The data
received was limited to states with RFG programs, thus MTBE use was
assumed to be limited to RFG areas for the purpose of this analysis.
---------------------------------------------------------------------------
In 2004, total ethanol use exceeded MTBE use. Ethanol's lead
oxygenate role is relatively new, however the trend has been a work in
progress over the past few years. From 2001 to 2004, ethanol
consumption more than doubled (from 1.7 to 3.5 billion gallons), while
MTBE use (in RFG) was virtually cut in half (from 3.7 to 1.9 billion
gallons). A plot of oxygenate use over the past decade is provided
below in Figure VI.A.3-1.
The nation's transition to ethanol is linked to states'' responses
to recent environmental concerns surrounding MTBE groundwater
contamination. Resulting concerns over drinking water quality have
prompted several states to significantly restrict or completely ban
MTBE use in gasoline. At the time of this analysis, 19 states had
adopted MTBE bans. A list of the states with MTBE bans is provided in
DRIA Table 2.1-4.
[[Page 55604]]
[GRAPHIC]
[TIFF OMITTED]
TP22SE06.004
4. Expected Growth in Ethanol Consumption
---------------------------------------------------------------------------
\48\ Total ethanol use based on EIA Monthly Energy Review, June
2006 (Table 10.1: Renewable Energy Consumption by Source, Appendix
A: Thermal Conversion Factors). MTBE use in RFG also provided by EIA
(file received from EIA representative on March 9, 2006). Reported
2004 MTBE use has been adjusted from 2.0 to 1.9 Bgal based on
assumption of timely implementation of CA, CT, and NY MTBE bans on
1/1/04 (EIA reported a slight delay and thus showed small amounts of
MTBE use in these states in 2004).
---------------------------------------------------------------------------
As mentioned above, ethanol demand is expected to increase well
beyond the levels contained in the renewable fuels standard (RFS) under
the Act. With the removal of the oxygenate mandate for reformulated
gasoline (RFG),\49\ all U.S. refiners are expected to eliminate the use
of MTBE in gasoline as soon as possible. In order to accomplish this
transition quickly (by 2006 or 2007 at the latest) while maintaining
gasoline volume, octane, and mobile source air toxics emission
performance standards, refiners are electing to blend ethanol into
virtually all of their RFG.\50\ This has caused a dramatic increase in
demand for ethanol which, in 2006 is being met by temporarily shifting
large volumes of ethanol out of conventional gasoline and into RFG
areas. By 2012, however, ethanol production will have grown to
accommodate the removal of MTBE without the need for such a shift from
conventional gasoline. More important than the removal of MTBE over the
long term, however, is the impact that the dramatic rise in the price
of crude oil is having on demand for renewable fuels, both ethanol and
biodiesel. This has dramatically improved the economics for renewable
fuel use, leading to a surge in demand that is expected to continue. In
the Annual Energy Outlook (AEO) 2006, EIA forecasted that by 2012,
total ethanol use (corn, cellulosic, and imports) would be about 9.6
billion gallons \51\ and biodiesel use would be about 0.3 billion
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
[[Page 55605]]
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 2.1.4.2.
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 2.1.4.3.
---------------------------------------------------------------------------
\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 2.1.4.6.
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
[[Page 55606]]
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
[[Page 55607]]
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
[[Page 55608]]
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
[[Page 55609]]
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/dnav/pet/
pet_pri_allmg_d_nus_PTA_cpgal_m.htm (gasoline),
http://tonto.eia.doe.gov/dnav/ng/ng_pri_sum_dcu_nus_m.htm
(natural gas),
http://www.eia.doe.gov/cneaf/electricity/page/sales_revenue.xls (electricity),
http://www.eia.doe.gov/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
[[Page 55610]]
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
[[Page 55611]]
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
[[Page 55612]]
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
[[Page 55613]]
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
[[Page 55614]]
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
[[Page 55615]]
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 $70 Per Barrel
[Million dollars and cents per gallon]
--------------------------------------------------------------------------------------------------------------------------------------------------------
--------------------------------------------------------------------------------------------------------------------------------------------------------
7.2 Bil gals, max RFG
7.2 Bil gals, min RFG
9.6 Bil gals, max RFG
9.6 Bil gals, min RFG
--------------------------------------------------------------------------------------------------------------------------------------------------------
Butane Removed in Winter................................ Yes No Yes No Yes No Yes No
--------------------------------------------------------------------------------------------------------------------------------------------------------
[[Page 55616]]
Total Cost without Subsidies ($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.
[[Page 55617]]
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.
[[Page 55618]]
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.
[[Page 55619]]
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/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
[[Page 55620]]
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
[[Page 55621]]
(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
majority of these emissions are related to farming and ethanol
production. Both farms and ethanol plants are generally located in
ozone attainment areas.
Table VIII.B.1-4 shows estimates of annual emissions expected to
occur nationwide due to increased production of biodiesel. These
estimates include a reduction in emissions related to the distribution
of the displaced diesel fuel.
Table VIII.B.1-4.--Annual Emissions Nationwide From Biodiesel Production
and Transportation
[Tons per year]
------------------------------------------------------------------------
Change in
Reference emissions
inventory: 28 Inventory: 300
Pollutant mill gal mill gal
biodiesel per biodiesel per
year year
------------------------------------------------------------------------
VOC..................................... 1,300 12,700
NOX..................................... 1,400 13,600
CO...................................... 800 7,200
PM10.................................... 50 1,000
SOX..................................... 200 1,800
------------------------------------------------------------------------
The potential emission increases related to biodiesel production
and distribution are generally much smaller, with the possible
exception of VOC emissions. Again, these emissions are generally
expected to be in ozone attainment areas.
2. Sensitivity Analysis
The national emission inventories for VOC and NOX in
2012 with current fuels are summarized in Table VIII.B.2-1. Here, the
emission effects contained in the EPA Predictive Models are assumed to
apply to all vehicles, not just Tier 0 vehicles. Also shown are the
changes in emissions projected for the two cases for future ethanol
volume and the two cases of ethanol use in RFG. CO emissions are the
same as in the primary analysis, as they are not affected by the EPA
Predictive Models.
[[Page 55622]]
Table VIII.B.2-1.--2012 Emissions Nationwide From Gasoline Vehicles and Equipment Under Several Ethanol Use
Scenarios: Sensitivity Analysis
[Tons per year]
----------------------------------------------------------------------------------------------------------------
Inventory Change in inventory in control cases
-------------------------------------------------------------------------------
7.2 Billion gallons of ethanol 9.6 Billion gallons of ethanol
Pollutant ---------------------------------------------------------------
Reference case Minimum RFG Maximum RFG Minimum RFG Maximum RFG
use use use use
----------------------------------------------------------------------------------------------------------------
VOC............................. 5,775,000 4,000 -8,000 14,000 -5,000
NOX............................. 2,610,000 49,000 45,000 95,000 89,000
CO.............................. 64,799,000 -843,000 -1,229,000 -1,971,000 -2,319,000
Benzene......................... 175,000 -9,000 -5,000 -14,000 - 10,000
Formaldehyde.................... 39,300 0 -200 300 0
Acetaldehyde.................... 19,200 5,800 4,700 9,000 8,000
1,3-Butadiene................... 17,900 -600 -400 -1,100 -800
----------------------------------------------------------------------------------------------------------------
The overall VOC and NOX emission impacts of the various
ethanol use scenarios change to some degree when all motor vehicles are
assumed to be sensitive to fuel ethanol content. The increase in VOC
emissions either decreases substantially or turns into a net decrease
due to a greater reduction in exhaust VOC emissions from onroad
vehicles. However, the increase in NOX emissions gets
larger, as more vehicles are assumed to be affected by ethanol.
Emissions of the four air toxics generally decrease slightly, due to
the greater reduction in exhaust VOC emissions.
3. Local and Regional VOC and NOX Emission Impacts in July
We also estimate the percentage change in VOC and NOX
emissions from gasoline fueled motor vehicles and equipment in those
areas which actually experienced a significant change in ethanol use.
Specifically, we focused on areas where the market share of ethanol
blends was projected to change by 50 percent or more. We also focused
on summertime emissions, as these are most relevant to ozone formation.
Finally, we developed separately estimates for: (1) RFG areas,
including the state of California and the portions of Arizona where
their CBG fuel programs apply, (2) low RVP areas (i.e., RVP standards
less than 9.0 RVP, and (3) areas with a 9.0 RVP standard. This set of
groupings helps to highlight the emissions impact of increased ethanol
use in those areas where emission control is most important.
Table VIII.B.3-1 presents our primary estimates of the percentage
change in VOC and NOX emission inventories for these three
types of areas. While ethanol use is going up in the vast majority of
the nation, ethanol use in RFG areas under the ``Minimum Use in RFG''
scenarios is actually decreasing compared to the 2012 reference case.
This is important to note in order to understand the changes in
emissions indicated.
Table VIII.B.3-1.--Change in Emissions From Gasoline Vehicles and Equipment in Counties Where Ethanol Use
Changed Significantly--Primary Analysis
----------------------------------------------------------------------------------------------------------------
Ethanol use 7.2 Billion gallons 9.6 Billion gallons
----------------------------------------------------------------------------------------------------------------
Ethanol use in RFG Minimum Maximum Minimum Maximum
----------------------------------------------------------------------------------------------------------------
RFG Areas
----------------------------------------------------------------------------------------------------------------
Ethanol Use..................... Down.............. Up................ Down.............. Up.
VOC............................. 1.6%.............. 0.4%.............. 1.6%.............. 0.4%.
NOX............................. -5.2%............. 2.4%.............. -5.2%............. 2.4%.
----------------------------------------------------------------------------------------------------------------
Low RVP Areas
----------------------------------------------------------------------------------------------------------------
Ethanol Use..................... Up................ Up................ Up................ Up.
VOC............................. 3.1%.............. 3.2%.............. 4.1%.............. 3.5%.
NOX............................. 4.1%.............. 6.0%.............. 4.8%.............. 4.4%.
----------------------------------------------------------------------------------------------------------------
Other Areas
----------------------------------------------------------------------------------------------------------------
Ethanol Use..................... Up................ Up................ Up................ Up.
VOC............................. 4.1%.............. 4.1%.............. 5.4%.............. 4.4%.
NOX............................. 4.6%.............. 6.0%.............. 5.8%.............. 4.8%.
----------------------------------------------------------------------------------------------------------------
As expected, increased ethanol use tends to increase NOX
emissions. The increase in low RVP and other areas is greater than in
RFG areas, since the RFG in the RFG areas included in this analysis all
contained MTBE. Also, increased ethanol use tends to increase VOC
emissions, indicating that the increase in non-exhaust VOC emissions
exceeds the reduction in exhaust VOC emissions. This effect is muted
with RFG due to the absence of an RVP waiver for ethanol blends. The
reader is referred to Chapter 2 of the DRIA for discussion of how
ethanol levels will change at the state-level.
Table VIII.B.3-2 presents the percentage change in VOC and
NOX
[[Page 55623]]
emission inventories under our sensitivity case (i.e., when we apply
the emission effects of the EPA Predictive Models to all motor vehicles).
Table VIII.B.3-2.--Change in Emissions From Gasoline Vehicles and Equipment in Counties Where Ethanol Use
Changed Significantly--Sensitivity Analysis
----------------------------------------------------------------------------------------------------------------
7.2 Bgal Min 7.2 Bgal Max 9.6 Bgal Min 9.6 Bgal Max
----------------------------------------------------------------------------------------------------------------
RFG Areas
----------------------------------------------------------------------------------------------------------------
Ethanol Use..................... Down.............. Up................ Down.............. Up.
VOC............................. 2.6%.............. 0.2%.............. 2.6%.............. 0.2%.
NOX............................. -9.0%............. 4.7%.............. -9.0%............. 4.7%.
----------------------------------------------------------------------------------------------------------------
Low RVP Areas
----------------------------------------------------------------------------------------------------------------
Ethanol Use..................... Up................ Up................ Up................ Up.
VOC............................. 2.1%.............. 2.1%.............. 3.1%.............. 2.5%.
NOX............................. 8.2%.............. 10.6%............. 9.8%.............. 8.9%.
----------------------------------------------------------------------------------------------------------------
Other Areas
----------------------------------------------------------------------------------------------------------------
Ethanol Use..................... Up................ Up................ Up................ Up.
VOC............................. 3.4%.............. 3.4%.............. 4.6%.............. 3.7%.
NOX............................. 8.4%.............. 10.1%............. 10.3%............. 8.8%.
----------------------------------------------------------------------------------------------------------------
Directionally, the changes in VOC and NOX emissions in
the various areas are consistent with those from our primary analysis.
The main difference is that the increases in VOC emissions are smaller,
due to more vehicles experiencing a reduction in exhaust VOC emissions,
and the increases in NOX emissions are larger.
C. Impact on Air Quality
We estimate the impact of increased ethanol use on the ambient
concentrations of two pollutants: ozone and PM. Quantitative estimates
are made for ozone, while only qualitative estimates can be made
currently for ambient PM. These impacts are described below.
1. Impact of 7.2 Billion Gallon Ethanol Use on Ozone
We use a metamodeling tool developed at EPA, the ozone response
surface metamodel (Ozone RSM), to estimate the effects of the projected
changes in emissions from gasoline vehicles and equipment for the 7.2
billion gallon ethanol use case. The changes in diesel emissions are
negligible in comparison. We did not include the estimated changes in
emissions from renewable fuel production and distribution, because of
their more approximate nature. Their geographical concentration also
makes it more difficult to simulate with the Ozone RSM.
The Ozone RSM was created using multiple runs of the Comprehensive
Air Quality Model with Extensions (CAMx). Base and proposed control
CAMx metamodeling was completed for the year 2015 over a modeling
domain that includes all or part of 37 Eastern U.S. states, plus the
District of Columbia. For more information on the Ozone RSM, please see
the Chapter 5 of the DRIA for this proposal.
The Ozone RSM limits the number of geographically distinct changes
in VOC and NOX emissions which can be simulated. As a
result, we could not apply distinct changes in emissions for each
county. Therefore, two separate runs were made with different VOC and
NOX emissions reductions. We then selected the ozone impacts
from the various runs which best matched the VOC and NOX
emission reductions for that county. This models the impact of local
emissions reasonably well, but loses some accuracy with respect to
ozone transport. No ozone impact was assumed for areas which did not
experience a significant change in ethanol use. The predicted ozone
impacts of increased ethanol use for those areas where ethanol use is
projected to change by more than a 50% market share are summarized in
Table VIII.C.1-1. As shown in Table 5.1-2 of the DRIA, national average
impacts (based on the 37-state area modeled) which include those areas
where no change in ethanol use is occurring are considerably smaller.
Table VIII.C.1-1.--Impact on 8-hour Design Value Equivalent Ozone Levels (ppb) a
----------------------------------------------------------------------------------------------------------------
Primary Analysis Sensitivity Analysis
---------------------------------------------------
Min RFG Use Max RFG Use Min RFG Use Max RFG Use
----------------------------------------------------------------------------------------------------------------
Minimum Change.............................................. -0.030 -0.025 -0.180 0.000
Maximum Change.............................................. 0.395 0.526 0.637 0.625
Average Change b............................................ 0.137 0.171 0.294 0.318
Population-Weighted Change b................................ 0.134 0.129 0.268 0.250
----------------------------------------------------------------------------------------------------------------
a In comparison to the 80 ppb 8-hour ozone standards.
b Only for those areas experiencing a change in ethanol blend market share of at least 50 percent.
As can be seen, ozone levels generally increase to a small degree
with increased ethanol use. This is likely due to the projected
increases in both VOC and NOX emissions. Some areas do see a
small decrease in ozone levels. In our primary analysis, where exhaust
emissions from Tier 1 and later onroad vehicles are assumed to be unaffected
[[Page 55624]]
by ethanol use, the population-weighted increase in ambient ozone
levels in those areas where ethanol use changed significantly is 0.129-
0.134 ppb. Since the 8-hour ambient ozone standard is 80 ppb, this
increase represents about 0.16 percent of the standard, a very small
percentage.
In our sensitivity analysis, where exhaust emissions from Tier 1
and later onroad vehicles are assumed to respond to ethanol like Tier 0
vehicles, the population-weighted increase in ambient ozone levels is
roughly twice as high, or 0.250-0.268 ppb. This increase represents
about 0.32 percent of the standard.
There are a number of important caveats concerning these estimates.
First, the emission effects of adding ethanol to gasoline are based on
extremely limited data for recent vehicles and equipment. Second, the
Ozone RSM does not account for changes in CO emissions. As shown above,
ethanol use should reduce CO emissions significantly, directionally
reducing ambient ozone levels in those areas where ozone formation is
VOC-limited. (Ozone levels in areas which are NOX-limited
are unlikely to be affected by a change in CO emissions.) The Ozone RSM
also does not account for changes in VOC reactivity. With additional
ethanol use, the ethanol content of VOC should increase. Ethanol is
less reactive than the average VOC. Therefore, this change should also
reduce ambient ozone levels in a way not addressed by the Ozone RSM,
again in those areas where ozone formation is predominantly VOC-limited.
Moving to health effects, exposure to ozone has been linked to a
variety of respiratory effects including premature mortality, hospital
admissions and illnesses resulting in school absences. Ozone can also
adversely affect the agricultural and forestry sectors by decreasing
yields of crops and forests. Although the health and welfare impacts of
changes in ambient ozone levels are typically quantified in regulatory
impact analyses, we do not evaluate them for this analysis. On average,
the changes in ambient ozone levels shown above are small and would be
even smaller if changes in CO emissions and VOC reactivity were taken
into account. The increase in ozone would likely lead to negligible
monetized impacts. We therefore do not estimate and monetize ozone
health impacts for the changes in renewable use due to the small
magnitude of this change, and the uncertainty present in the air
quality modeling conducted here, as well as the uncertainty in the
underlying emission effects themselves discussed earlier.
2. Particulate Matter
Ambient PM can come from two distinct sources. First, PM can be
directly emitted into the atmosphere. Second, PM can be formed in the
atmosphere from gaseous pollutants. Gasoline-fueled vehicles and
equipment contribute to ambient PM concentrations in both ways.
As described above, we are not currently able to predict the impact
of fuel quality on direct PM emissions from gasoline-fueled vehicles or
equipment. Therefore, we are unable at this time to project the effect
that increased ethanol use will have on levels of directly emitted PM
in the atmosphere.
PM can also be formed in the atmosphere (termed secondary PM here)
from several gaseous pollutants emitted by gasoline-fueled vehicles and
equipment. Sulfur dioxide emissions contribute to ambient sulfate PM.
NOX emissions contribute to ambient nitrate PM. VOC
emissions contribute to ambient organic PM, particularly the portion of
this PM comprised of organic carbon. Increased ethanol use is not
expected to change gasoline sulfur levels, so emissions of sulfur
dioxide and any resultant ambient concentrations of sulfate PM are not
expected to change. Increased ethanol use is expected to increase
NOX emissions, as described above. Thus, the possibility
exists that ambient nitrate PM levels could increase. Increased ethanol
is generally expected to increase VOC emissions, which could also
impact the formation of secondary organic PM. However, some VOC
emissions, namely exhaust VOC emissions, are expected to decrease,
while non-exhaust VOC emissions are expected to increase and the impact
on PM is a function of the type of VOC emissions.
The formation of secondary organic PM is very complex, due in part
to the wide variety of VOCs emitted into the atmosphere. Whether or not
a specific gaseous VOC reacts to form PM in the atmosphere depends on
the types of reactions that VOC undergoes, which in turn can depend on
other pollutants present, such as ozone, NOX and other
reactive compounds. The relative mass of secondary PM formed per mass
of gaseous VOC emitted can also depend on the concentration of the
gaseous VOC and the organic PM in the atmosphere. Most of the secondary
organic PM exists in a continually changing equilibrium between the
gaseous and PM phases. Both the rates of these reactions and the
gaseous-PM equilibria depend on temperature, so seasonal differences
can be expected.
Recent smog chamber studies have indicated that gaseous aromatic
VOCs can form secondary PM under certain conditions. These compounds
comprise a greater fraction of exhaust VOC emissions than non-exhaust
VOC emissions, as non-exhaust VOC emissions are dominated by VOCs with
relatively high vapor pressures. Aromatic VOCs tend to have lower vapor
pressures. As increased ethanol use is expected to reduce exhaust VOC
emissions, emissions of aromatic VOCs should also decrease. In
addition, refiners are expected to reduce the aromatic content of
gasoline by 5 volume percentage points as ethanol is blended into
gasoline. Emissions of aromatic VOCs should decrease with lower
concentrations of aromatics in gasoline. Thus, emissions of gaseous
aromatic VOCs could decrease for both reasons.
Overall, we expect that the decrease in secondary organic PM is
likely to exceed the increase in secondary nitrate PM. In 1999,
NOX emissions from gasoline-fueled vehicles and equipment
comprised about 20% of national NOX emissions from all
sources. In contrast, gasoline-fueled vehicles and equipment comprised
over 60% of all national gaseous aromatic VOC emissions. The percentage
increase in national NOX emissions due to increased ethanol
use should be smaller than the percentage decrease in national
emissions of gaseous aromatics. Finally, in most urban areas, ambient
levels of secondary organic PM exceed those of secondary nitrate PM.
Thus, directionally, we expect a net reduction in ambient PM levels due
to increased ethanol use. However, we are unable to quantify this
reduction at this time.
EPA currently utilizes the CMAQ model to predict ambient levels of
PM as a function of gaseous and PM emissions. This model includes
mechanisms to predict the formation of nitrate PM from NOX
emissions. However, it does not currently include any mechanisms
addressing the formation of secondary organic PM. EPA is currently
developing a model of secondary organic PM from gaseous toluene
emissions. We plan to incorporate this mechanism into the CMAQ model in
2007. The impact of other aromatic compounds will be added as further
research clarifies their role in secondary organic PM formation.
Therefore, we expect to be able to quantitatively estimate the impact
of decreased toluene emissions and increased NOX emissions
due to
[[Page 55625]]
increased ethanol use as part of future analyses of U.S. fuel
requirements required by the Act.
IX. Impacts on Fossil Fuel Consumption and Related Implications
Renewable fuels have been of significant interest for many years
due to their ability to displace fossil fuels, which have often been
targeted as primary contributors to emissions of greenhouse gases such
as carbon dioxide and national energy concerns such as dependence on
foreign sources of petroleum. Because significantly more renewable fuel
is expected to be consumed over the next few years than has been
consumed in the past, there is increased interest in the degree to
which their increased use will impact greenhouse gas emissions and
fossil fuel consumption.
Based on our analysis, we estimate that increases in the use of
renewable fuels will reduce fossil fuel consumption and GHG emissions
as shown in Table IX-1 in 2012. The results represent the percent
reduction in total transportation sector emissions and energy use. The
ranges result from different cases evaluated of the amount of renewable
fuel (7.5 billion gallons versus 9.9 billion gallons) that will
actually be produced in 2012.
Table IX-1.--Lifecycle Impacts of Increased Renewable Fuel Use Relative
to the 2012 Reference Case
------------------------------------------------------------------------
7.5 Billion 9.9 Billion
case a case b
------------------------------------------------------------------------
Percent Reduction in Transportation Sector 1.0 1.6
Petroleum Energy Use.........................
Percent Reduction in Transportation Sector 0.5 0.8
Fossil Fuel Energy Use.......................
Percent Reduction in Transportation Sector GHG 0.4 0.6
Emissions....................................
Percent Reduction in Transportation Sector CO2 0.6 0.9
Emissions....................................
------------------------------------------------------------------------
a 7.2 billion gallons of ethanol.
b 9.6 billion gallons of ethanol.
This section provides a summary of our analysis of the fossil fuel
impacts of the RFS rule.
A. Lifecycle Modeling
Although the use of renewable fuels in the transportation sector
directly displaces some petroleum consumed as motor vehicle fuel, this
displacement of petroleum is in fact only one aspect of the overall
impact of renewable fuels on fossil fuel use. Fossil fuels are also
used in producing and transporting renewable feedstocks such as plants
or animal byproducts, in converting the renewable feedstocks into
renewable fuel, and in transporting and blending the renewable fuels
for consumption as motor vehicle fuel. To estimate the true impacts of
increases in renewable fuels on fossil fuel use, modelers attempt to
take many or all these steps into account. Similarly, energy is used
and GHGs emitted in the pumping of oil, transporting the oil to the
refinery, refining the crude oil into finished transportation fuel,
transporting the refined gasoline or diesel fuel to the consumer and
then burning the fuel in the vehicle. Such analyses are termed
lifecycle or well-to-wheels analyses.
A variety of approaches are available to conduct lifecycle
analysis. This variety largely reflects different assumptions about (1)
the boundary conditions and (2) the estimates of input factors. The
boundary conditions determine the scope of the analysis. For example, a
lifecycle analysis could include energy required to make farm equipment
as part of the estimate of energy required to grow corn. The agency
chose a lifecycle analytic boundary that encompasses the fuel-cycle and
does not include the example used above. Differing estimates on input
factors (e.g. amount of fertilizer to grow corn) can also affect the
results of the lifecycle analysis.
For this proposed rulemaking, we have made use of a fuel-cycle
model, GREET,\87\ developed at Argonne National Laboratory (ANL) under
the sponsorship of the U.S. Department of Energy's Office of Energy
Efficiency and Renewable Energy (EERE). GREET has been under
development for several years and has undergone extensive peer review
through multiple updates. Of the available sources of information on
lifecycle analyses of energy consumed and emissions generated, we
believe that GREET offers the most comprehensive treatment of the
transportation sector. For instance, GREET provides lifecycle
assessments for ethanol made from corn and cellulosic materials,
biodiesel made from soybean oil, and petroleum-based gasoline and
diesel fuel. Thus GREET provides a means for calculating the relative
greenhouse gas (GHG) and petroleum impacts of renewable fuels that
displace conventional motor vehicle fuels. For this proposal, we used
version 1.7 of the GREET model, with a few modifications to its input
assumptions as described in more detail below.
---------------------------------------------------------------------------
\87\ Greenhouse gases, Regulated Emissions, and Energy use in
Transportation.
---------------------------------------------------------------------------
We do not believe that it would be appropriate at this time to base
the regulatory provisions for this rule on lifecycle modeling, as
described in more detail in Section III.B.4. Although the GREET model
does provide a peer-reviewed source for lifecycle modeling, a consensus
on all the assumptions, including point estimates, that are used as
inputs into that model does not exist.\88\ Also, given the short
timeframe available for the development of this proposal, we have not
had the opportunity to initiate the type of public dialogue on
lifecycle modeling that would be necessary before such analyses could
be incorporated into a regulatory framework. We have therefore chosen
to use lifecycle modeling only as a means to estimate the impacts of
the increased use of renewable fuel.
---------------------------------------------------------------------------
\88\ See Chapter 6.1.2 of the RIA for further discussion of
input assumptions used for the GREET modeling. Also see IX.A.2 of
this preamble section for a discussion about the differing estimates.
---------------------------------------------------------------------------
In addition to the GREET model tool, EPA has also developed a
lifecycle modeling tool that is specific to individual fuel producers.
This FUEL-CO2 model is intended to help fuel producers estimate the
lifecycle greenhouse gas emissions and fossil energy use for all stages
in the development of their specific fuel. EPA will evaluate whether
the FUEL-CO2 model would be an appropriate tool for fuel providers who
wish to demonstrate their actual reductions in greenhouse gas emissions
and fossil energy use. This may also be the best way for ethanol
producers to quantify the benefits of their renewable process energy
use when qualifying corn ethanol as cellulosic biomass ethanol (an
option for ethanol producers, stipulated in the Act).
[[Page 55626]]
1. Modifications to GREET Assumptions
GREET is subject to periodic updates by ANL, each of which results
in some changes to the inputs and assumptions that form the basis for
the lifecycle estimates of emissions generated and energy consumed.
These updates generally focus on those input values for those fuels or
vehicle technologies that are the focus of ANL at the time. As a result
there are a variety of other inputs related to ethanol and biodiesel
that have not been updated in some time. In the context of the RFS
program, we determined that some of the GREET input values that were
either based on outdated information or did not appropriately reflect
market conditions under a renewable fuels mandate should be examined
more closely, and updated if necessary.
In the timeframe available for developing this proposal, we chose
to concentrate our efforts on those GREET input values for ethanol that
had significant influence on the lifecycle emissions or energy
estimates and that were likely to be based on outdated information. We
reviewed the input values only for ethanol made from corn, since this
particular renewable fuel is likely to continue to dominate the
renewable fuel pool through at least 2012. For cellulosic ethanol and
biodiesel the GREET default values were used in this proposal. However,
we have also initiated a contract with ANL to investigate a wider
variety of GREET input values, including those associated with the
following fuel/feedstock pathways:
? Ethanol from corn.
? Ethanol from cellulosic materials (hybrid populars,
switchgrass, and corn stover).
? Biodiesel from soybean oil.
? Methanol from renewable sources.
? Natural gas from renewable sources.
? Renewable diesel formulations.
The contract focuses on the potential fuel production developments
and efficiency improvements that could occur within the time-frame of
the RFS program. The GREET input value changes resulting from this work
are projected to be available in the fall of 2006, not in time for this
proposal, but they will be incorporated into revised lifecycle
assessments for the final rule.
We did not investigate the input values associated with the
production of petroleum-based gasoline or diesel fuel in the GREET
model for this proposal. However, the refinery modeling discussed in
Section VII will provide some additional information on the process
energy requirements associated with the production of gasoline and
diesel under a renewable fuels mandate. We will use information from
this refinery modeling for the final rule to determine if any GREET
input values should be changed.
A summary of the GREET corn ethanol input values we investigated
and modified for this proposal is given below. We also examined several
other GREET input values, but determined that the default GREET values
should not be changed for a variety of reasons. These included ethanol
plant process efficiency, corn and ethanol transport distances and
modes, corn farming inputs, CO2 emissions from corn farming
land use change, and byproduct allocation methods. Our investigation of
these other GREET input values are discussed more fully in Chapter 6 of
the RIA. The current GREET default factors for these other inputs were
included in the analysis for this proposal.
a. Wet-Mill Versus Dry Mill Ethanol Plants. The two basic methods
for producing ethanol from corn are wet milling and dry milling. In the
wet milling process, the corn is soaked to separate the starch, used to
make ethanol, from the other components of the corn kernel. In the dry
milling process, the entire corn kernel is ground and fermented to
produce ethanol. The remaining components of the corn are then dried
for animal feed (dried distillers grains with solubles, or DDGS). Wet
milling is more complicated and expensive than dry milling, but it
produces more valuable products (ethanol plus corn syrup, corn oil, and
corn gluten meal and feeds). The majority of ethanol plants in the
United States are dry mill plants, which produce ethanol more simply
and efficiently. The GREET default is 70 percent dry mill, 30 percent
wet mill.
For this analysis, we expect most new ethanol plants will be dry
mill operations. That has been the trend in the last few years as the
demand for ethanol has grown, and our analysis of ethanol plants under
construction and planned for the near future has verified this.
Therefore, it was assumed that essentially all new ethanol facilities
would be dry mill plants.
b. Coal Versus Natural Gas in Ethanol Plants. The type of fuel used
within the ethanol plant for process energy, to power the various
components that are used in ethanol production (dryers, grinders,
heating, etc.) can vary among ethanol plants. The type of fuel used has
an impact on the energy usage, efficiency, and emissions of the plant,
and is primarily determined by economics. Most new plants built in the
last few years have used natural gas. Based on specific situations and
economics, some new plants are using coal. In addition, EPA is
promoting the use of combined heat and power, or cogeneration, in
ethanol plants to improve plant energy-efficiency and to reduce air
emissions. This technology, in the face of increasing natural gas
prices, may make coal a more attractive energy source for new ethanol
plants.
GREET assumes that 20 percent of plants will be powered by coal.
However, our review of plants under construction and those planned for
the near future indicates that coal will only be used for approximately
10% of the plants. This is the value we assumed in GREET for our
analysis. However, as new plants are constructed to meet the demands of
the RFS, this percentage is expected to go up. Future work in
preparation for the final rule will evaluate the potential trends for
combined heat and power and coal as process fuel.
c. Ethanol Production Yield. It is generally assumed that 1 bushel
of corn yields 2.7 gallons of ethanol. However, the development of new
enzymes continues to increase the potential ethanol yield. We used a
value of 2.71 gal/bu in our analysis. This value represents pure
ethanol production (i.e. no denaturant). This value is consistent with
the cost modeling of corn ethanol discussed in Section VII.
2. Controversy Concerning the Ethanol Energy Balance
Although we have made use of lifecycle impact estimates from ANL's
GREET model, there are a variety of lifecycle impact analyses from
other researchers that provide alternative and sometimes significantly
different estimates. The lifecycle energy balance for corn-ethanol, in
particular, has been the subject of numerous and sometimes contentious
debates.
Several metrics are commonly used to describe the energy efficiency
of renewable fuels. We have chosen to use displacement indexes for this
proposal because they provide the least ambiguous and most relevant
mechanism for estimating the impacts of renewable fuels on GHGs and
petroleum consumption. However, other metrics, such as the net energy
balance and energy efficiency, have more commonly been used in the
past. The use of these metrics has served to complicate the issue since
they do not involve a direct comparison to the gasoline that the
ethanol is replacing.
Among researchers who have studied the lifecycle energy balance of
corn-ethanol, the primary differences of opinion appear to center on
fossil energy associated with fertilizers, the
[[Page 55627]]
energy required to convert corn into ethanol, and the value of co-
products. As a result of these differences, the net energy balance has
been estimated to be somewhere between -34 and + 31 thousand Btu/gal,
and the energy efficiency has been estimated to be somewhere between
0.6 and 1.4.\89\ A concern arises in cases where a researcher concludes
that the net energy balance is negative, or the energy efficiency is
less than 1.0. Such cases would indicate that the fossil energy used in
the production and transportation of ethanol exceeds the energy in the
ethanol itself, and this is generally interpreted to mean that
lifecycle fossil fuel use negates the benefits of replacing gasoline
with ethanol. However, since the metrics used do not actually compare
ethanol to gasoline, such interpretations are unwarranted.
---------------------------------------------------------------------------
\89\ A net energy balance of zero, or an energy efficiency of
1.0, would indicate that the full lifecycle fossil fuels used in the
production and transportation of ethanol are exactly equal to the
energy in the ethanol itself.
---------------------------------------------------------------------------
The primary studies that conclude that the energy balance is
negative were conducted by Dr. David Pimental of Cornell University and
Dr. T. Patzek of University of California, Berkeley 90 91.
Many other researchers, however, have criticized that work as being
based on out-dated farming and ethanol production data, including data
not normally considered in lifecycle analysis for fuels, and not
following the standard methodology for lifecycle analysis in terms of
valuing co-products. Furthermore, several recent surveys have concluded
that the energy balance is positive, although they differ in their
numerical estimates.92 93 94 Authors of the GREET model have
also concluded that the lifecycle amount of fossil energy used to
produce ethanol is less than the amount of energy in the ethanol
itself. Based on our review of all the available information, we have
concluded that the energy balance is indeed positive, and we believe
that the GREET model provides an accurate basis for quantifying the
lifecycle impacts.
---------------------------------------------------------------------------
\90\ Pimentel, David ``Ethanol Fuel: Energy Balance, Economics,
and Environmental Impacts are Negative'', Vol. 12, No. 2, 2003
International Association for Mathematical Geology, Natural
Resources Research.
\91\ Pimentel, D.; Patzek, T. ``Ethanol production using corn,
switchgrass, and wood; biodiesel production using soybean and
sunflower.'' Nat. Resour. Res. 2005, 14 (1), 65-76.
\92\ Hammerschlag, R. ``Ethanol's Energy Return on Investment: A
Survey of the Literature 1990--Present.'' Environ. Sci. Technol.
2006, 40, 1744-1750.
\93\ Farrell, A., Pelvin, R., Turner, B., Joenes, A., O'Hare,
M., Kammen, D., ``Ethanol Can Contribute to Energy and Environmental
Goals'', Science, 1/27/2006, Vol. 311, 506-508.
\94\ Hill, J., Nelson, E., Tilman, D., Polasky, S., Tiffany, D.,
``Environmental, economic, and energetic costs and benefits of
biodiesel and ethanol biofuels'', Proceedings of the National
Academy of Sciences, 7/25/2006, Vol. 103, No. 30, 11206-11210.
---------------------------------------------------------------------------
B. Overview of Methodology
The GREET model does not provide estimates of energy consumed and
emissions generated in total, such as the total amount of natural gas
consumed in the U.S. in a given year by ethanol production facilities.
Instead, it provides estimates on a national average, per fuel unit
basis, such as the amount of natural gas consumed for the average
ethanol production facility per million Btus of ethanol produced. As a
result we could not use GREET directly to estimate the nationwide
impacts of replacing some gasoline and diesel with renewable fuels.
Instead, we used GREET to generate comparisons between renewable
fuels and the petroleum-based fuels that they displace. These
comparisons allowed us to develop displacement indexes that represent
the amount of lifecycle GHGs or fossil fuel reduced when a Btu of
renewable fuel replaces a Btu of gasoline or diesel. In order to
estimate the incremental impacts of increased use of renewable fuels on
GHGs and fossil fuels, we combined those displacement indexes with our
renewable fuel volume scenarios and GHG emissions and fossil fuel
consumption data for the conventional fuels replaced. For example, to
estimate the impact of corn-ethanol use on GHGs, these factors were
combined in the following way:
SGHG,corn ethanol = Rcorn ethanol x
LCgasoline x DIGHG,corn ethanol
Where:
SGHG,corn ethanol = Lifecycle GHG emission reduction
relative to the 2012 reference case associated with use of corn
ethanol (million tons of GHG).
Rcorn ethanol = Amount of gasoline replaced by corn
ethanol on an energy basis (Btu).
LCgasoline = Lifecycle emissions associated with gasoline
use (million tons of GHG per Btu of gasoline).
DIGHG,corn ethanol = Displacement Index for GHGs and corn
ethanol, representing the percent reduction in gasoline lifecycle
GHG emissions which occurs when a Btu of gasoline is replaced by a
Btu of corn ethanol.
Variations of the above equation were also generated for impacts on
all four endpoints of interest (emissions of CO2, emissions of GHGs,
fossil fuel consumption, and petroleum consumption) as well as all
three renewable fuels examined (corn-ethanol, cellulosic ethanol, and
biodiesel). Each of the variables in the above equation are discussed
in more detail below. Section 6 of the DRIA provides details of the
analysis.
1. Amount of Conventional Fuel Replaced by Renewable Fuel (R)
In general, the volume fraction (R) represents the amount of
conventional fuel no longer consumed--that is, displaced--as a result
of the use of the replacement renewable fuel. Thus R represents the
total amount of renewable fuel used under each of our renewable fuel
volume scenarios, in units of Btu. We make the assumption that vehicle
energy efficiency will not be affected by the presence of renewable
fuels (i.e., efficiency of combusting one Btu of ethanol is equal to
the efficiency of combusting one Btu of gasoline).
Consistent with the emissions modeling described in Section VII,
our analysis of the GHG and fossil fuel consumption impacts of
renewable fuel use was conducted using three volume scenarios. The
first scenario was a base case representing 2004 renewable fuel
production levels, projected to 2012. This scenario provided the point
of comparison for the other two scenarios. The other two renewable fuel
scenarios for 2012 represented the RFS program requirements and the
volume projected by EIA. In both scenarios, we assumed that the
biodiesel production volume would be 0.3 billion gallons based on an
EIA projection, and that the cellulosic ethanol production volume would
be 0.25 billion gallons based on the Energy Act's requirement that 250
million gallons of cellulosic ethanol be produced starting in the next
year, 2013. The remaining renewable fuel volumes in each scenario would
be ethanol made from corn. The total volumes for all three scenarios
are shown in Table IX.B.1-1. For the purposes of calculating the R
values, we assumed the ethanol volumes are 5% denatured, and the
volumes were converted to total Btu using the appropriate volumetric
energy content values (76,000 Btu/gal for ethanol, and 118,000 Btu/gal
for biodiesel).
[[Page 55628]]
Table IX.B.1-1.--Volume scenarios in 2012
[billion gallons]
------------------------------------------------------------------------
RFS
Reference required Projected
case volume: 7.5 volume: 9.9
B gal B gal
------------------------------------------------------------------------
Corn-ethanol.................. 3.9 6.95 9.35
Cellulosic ethanol............ 0.0 0.25 0.25
Biodiesel..................... 0.028 0.3 0.3
-----------------------------------------
Total volume.............. 3.928 7.5 9.9
------------------------------------------------------------------------
Since the impacts of increased renewable fuel use were measured
relative to the 2012 reference case, the value of R actually
represented the incremental amount of renewable fuel between the
reference case and each of the two other scenarios.
2. Lifecycle Impacts of Conventional Fuel Use (LC)
In order to determine the lifecycle impact that increased renewable
fuel volumes may have on any particular endpoint (fossil fuel
consumption or emissions of GHGs), we also needed to know the
conventional fuel inventory on a lifecycle basis. Since available
sources of GHG emissions are provided on a direct rather than a
lifecycle basis, we converted these direct emission and energy
estimates into their lifecycle counterparts. We used GREET to develop
multiplicative factors for converting direct (vehicle-based) emissions
of GHGs and energy use into full lifecycle factors. Table IX.B.2-1
shows the total lifecycle petroleum and GHG emissions associated with
direct use of a Btu value of gasoline and diesel fuel.
Table IX.B.2-1.--Lifecycle Emissions and Energy (LC Values)
------------------------------------------------------------------------
Gasoline Diesel
------------------------------------------------------------------------
Petroleum (Btu/Btu)........................... 1.11 1.10
Fossil fuel (Btu/Btu)......................... 1.22 1.21
GHG (Tg-CO2-eq/QBtu).......................... 99.4 94.5
CO2 (Tg-CO2/QBtu)............................. 94.2 91.9
------------------------------------------------------------------------
3. Displacement Indexes (DI)
The displacement index (DI) represents the percent reduction in GHG
emissions or fossil fuel energy brought about by the use of a renewable
fuel in comparison to the conventional gasoline or diesel that the
renewable fuel replaces. The formula for calculating the displacement
index depends on which fuel is being displaced (i.e. gasoline or
diesel), and which endpoint is of interest (e.g. petroleum energy,
GHG). For instance, when investigating the CO2 impacts of
ethanol used in gasoline, the displacement index is calculated as follows:
[GRAPHIC]
[TIFF OMITTED]
TP22SE06.005
The units of g/Btu ensure that the comparison between the renewable
fuel and the conventional fuel is made on a common basis, and that
differences in the volumetric energy content of the fuels is taken into
account. The denominator includes the CO2 emitted through
combustion of the gasoline itself in addition to all the CO2
emitted during its manufacturer and distribution. The numerator, in
contrast, includes only the CO2 emitted during the
manufacturer and distribution of ethanol, not the CO2
emitted during combustion of the ethanol.
The combustion of biomass-based fuels, such as ethanol from corn
and woody crops, generates CO2. However, in the long run the
CO2 emitted from biomass-based fuels combustion does not
increase atmospheric CO2 concentrations, assuming the
biogenic carbon emitted is offset by the uptake of CO2
resulting from the growth of new biomass. As a result, CO2
emissions from biomass-based fuels combustion are not included in their
lifecycle emissions results and are not used in the CO2
displacement index calculations shown above.
Using GREET, we calculated the lifecycle values for energy consumed
and GHGs produced for corn-ethanol, cellulosic ethanol, and soybean-
based biodiesel. These values were in turn used to calculate the
displacement indexes. The results are shown in Table IX.B.3-1. Details
of these calculations can be found in Chapter 6 of the RIA. As noted
previously, different models can result in different estimates. For
example, whereas GREET estimates a net GHG reduction of about 26% for
corn ethanol compared to gasoline, the previously cited works by
Farrell et al. estimates around a 13% reduction.
Table IX.B.3-1.--Displacement Indexes Derived From GREET
----------------------------------------------------------------------------------------------------------------
Cellulosic
Corn ethanol ethanol Biodiesel
(percent) (percent) (percent)
----------------------------------------------------------------------------------------------------------------
DIPetroleum..................................................... 92.3 92.7 84.6
DIFossil Fuel................................................... 40.1 96.0 47.9
DIGHG........................................................... 25.8 98.1 53.4
[[Page 55629]]
DICO2........................................................... 43.9 110.1 56.8
----------------------------------------------------------------------------------------------------------------
The displacement indexes in this table represent the impact of
replacing a Btu of gasoline or diesel with a Btu of renewable fuel.
Thus, for instance, for every Btu of gasoline which is replaced by corn
ethanol, the total lifecycle GHG emissions that would have been
produced from that Btu of gasoline would be reduced by 25.8 percent.
For every Btu of diesel which is replaced by biodiesel, the total
lifecycle petroleum energy that would have been consumed as a result of
burning that Btu of diesel fuel would be reduced by 84.6 percent.
Note that our DI estimates for cellulosic ethanol assume that the
ethanol in question was in fact produced from a cellulosic feedstock,
such as wood, corn stalks, or switchgrass. However, the definition of
cellulosic biomass ethanol given in the Energy Act also includes
ethanol made from non-cellulosic feedstocks if 90 percent of the
process energy used to operate the facility is derived from a renewable
source. In the context of our cost analysis, we have assumed this
latter definition of cellulosic ethanol. Further discussion of this
issue can be found in Chapter 1, Section 1.2.2 of the RIA.
C. Impacts of Increased Renewable Fuel Use
We used the methodology described above to calculate impacts of
increased use of renewable fuels on consumption of petroleum and fossil
fuels and also on emissions of CO2 and GHGs. This section
describes our results.
1. Fossil Fuels and Petroleum
We used the equation for S above to calculate the reduction
associated with the increased use of renewable fuels on lifecycle
fossil fuels and petroleum. These values are then compared to the total
U.S. transportation sector emissions to get a percent reduction. The
results are presented in Tables IX.C.1-1 and IX.C.1-2.
Table IX.C.1.-1.--Fossil Fuel Impacts of Increased Use of Renewable
Fuels in the Transportation Sector in 2012, Relative to the 2012
Reference Case
------------------------------------------------------------------------
RFS Required Projected
volume: 7.5 volume: 9.9
Bgal Bgal
------------------------------------------------------------------------
Reduction (quadrillion Btu)............. 0.2 0.3
Percent reduction....................... 0.5 0.8
------------------------------------------------------------------------
Table IX.C.1.-2.--Petroleum Impacts of Increased Use of Renewable Fuels
in the Transportation Sector in 2012, Relative to the 2012 Reference
Case
------------------------------------------------------------------------
RFS Required Projected
volume: 7.5 volume: 9.9
Bgal Bgal
------------------------------------------------------------------------
Reduction (billion gal)................. 2.3 3.9
Percent reduction....................... 1.0 1.6
------------------------------------------------------------------------
2. Greenhouse Gases and Carbon Dioxide
One issue that has come to the forefront in the assessment of the
environmental impacts of transportation fuels relates to the effect
that the use of such fuels could have on emissions of greenhouse gases
(GHGs). The combustion of fossil fuels has been identified as a major
contributor to the increase in concentrations of atmospheric carbon
dioxide (CO2) since the beginning of the industrialized era,
as well as the build-up of trace GHGs such as methane (CH4)
and nitrous oxide (N2O). This lifecycle analysis evaluates
the impacts of renewable fuel use on greenhouse gas emissions.
The relative global warming contribution of emissions of various
greenhouse gases is dependant on their radiative forcing, atmospheric
lifetime, and other considerations. For example, on a mass basis, the
radiative forcing of CH4 is much higher than that of
CO2, but its effective atmospheric residence time is much
lower. The relative warming impacts of various greenhouse gases, taking
into account factors such as atmospheric lifetime and direct warming
effects, are reported on a CO2-equivalent basis as global
warming potentials (GWPs). The GWPs used by GREET were developed by the
UN Intergovernmental Panel on Climate Change (IPCC) as listed in their
Third Assessment Report \95\, and are shown in Table IX.C.2-1.
---------------------------------------------------------------------------
\95\ IPCC ``Climate Change 2001: The Scientific Basis'', Chapter
6; Intergovernmental Panel on Climate Change; J. T. Houghton, Y.
Ding, D. J. Griggs, M. Noguer, P. J. van der Linden, X. Dai, C. A.
Johnson; and K. Maskell, eds.; Cambridge University Press.
Cambridge, U. K. 2001. http://www.grida.no/climate/ipcc_tar/wg1/index.htm.
Table IX.C.2-1.--Global Warming Potentials for Greenhouse Gases
------------------------------------------------------------------------
Greenhouse gas GWP
------------------------------------------------------------------------
CO2.......................................................... 1
CH4.......................................................... 23
N2O.......................................................... 296
------------------------------------------------------------------------
Greenhouse gases are measured in terms of CO2-equivalent
emissions, which result from multiplying the GWP for each of the three
pollutants shown in the above table by the mass of emission for each
pollutant. The sum of
[[Page 55630]]
impacts for CH4, N2O, and CO2, yields
the total effective GHG impact.
We used the equation for S above to calculate the reduction
associated with the increased use of renewable fuels on lifecycle
emissions of CO2. These values are then compared to the
total U.S. transportation sector emissions to get a percent reduction.
The results are presented in Table IX.C.2-2.
Table IX.C.2-2.--CO2 Emission Impacts of Increased Use of Renewable Fuels in the Transportation Sector in 2012,
Relative to the 2012 Reference Case
----------------------------------------------------------------------------------------------------------------
RFS Required volume: Projected Volume: 9.9
7.5 Bgal Bgal
----------------------------------------------------------------------------------------------------------------
Reduction (million metric tons CO2) 12.6 19.8
Percent reduction 0.6 % 0.9 %
----------------------------------------------------------------------------------------------------------------
Carbon dioxide is a subset of GHGs, along with CH4 and
N2O as discussed above. It can be seen from Table IX.B.3-1
that the displacement index of CO2 is greater than for GHGs
for each renewable fuel. This indicates that lifecycle emissions of
CH4 and N2O are higher for renewable fuels than
for the conventional fuels replaced. Therefore, reductions associated
with the increased use of renewable fuels on lifecycle emissions of
GHGs are lower than the values for CO2. The results for GHGs
are presented in Table IX.C.2-3.
Table IX.C.2-3.--GHG Emission Impacts of Increased Use of Renewable
Fuels in the Transportation Sector in 2012, Relative to the 2012
Reference Case
------------------------------------------------------------------------
RFS
Required Projected
volume: 7.5 Volume: 9.9
Bgal Bgal
------------------------------------------------------------------------
Reduction (million metric tons CO2-eq.)....... 9.0 13.5
Percent reduction............................. 0.4% 0.6%
------------------------------------------------------------------------
D. Implications of Reduced Imports of Petroleum Products
This section only considers the impacts on imports of oil and
petroleum products. Expanded production and use of renewable fuels
could have other economic impacts such as on the exports of
agricultural products like corn. See section X of the preamble for a
discussion on agricultural sector impacts.
In 2005, the United States imported almost 60 percent of the oil it
consumed. This compares to just over 35 percent oil imports in
1975.\96\ Transportation accounts for 70% of the U.S. oil consumption.
It is clear that oil imports have a significant impact on the U.S.
economy. Expanded production of renewable fuel is expected to
contribute to energy diversification and the development of domestic
sources of energy. We consider whether the RFS will reduce U.S.
dependence on imported oil by calculating avoided expenditures on
petroleum imports. Note that we do not calculate whether this reduction
is socially beneficially, which would depend on the scarcity value of
domestically produced ethanol versus that of imported petroleum products.
---------------------------------------------------------------------------
\96\ Davis, Stacy C.; Diegel, Susan W., Transportation Energy
Data Book: 25th Edition, Oak Ridge National Laboratory, U.S.
Department of Energy, ORNL-6974, 2006.
---------------------------------------------------------------------------
To assess the impact of the RFS program on petroleum imports, the
fraction of domestic consumption derived from foreign sources was
estimated using results from the AEO 2006. In section 6.4.1 of the DRIA
we describe how fuel producers change their mix in response to a
decrease in fuel demand. We do not expect the projected reductions in
petroleum consumption (0.3 to 0.57 Quads) to impact world oil prices by
a measurable amount. We base this assumption on the overall size of
worldwide petroleum demand and analysis of the AEO 2006 cases. As a
consequence, domestic crude oil production for the 7.5 or 9.9 cases
would not be expected to change significantly versus the RFS reference
case. Thus, petroleum reductions will come largely from reductions in
net petroleum imports. This conclusion is confirmed by comparing the
AEO 2006 low macroeconomic growth case to the AEO 2006 reference case,
as discussed in the RIA 6.4.1. The AEO 2006 shows that for a reduction
in petroleum demand on the order of the reductions estimated for the
RFS, net imports will account for approximately 95% of the reductions.
However, if petroleum reductions were large enough to impact world oil
prices, the mix of domestic crude oil, imports of finished products,
and imports of crude oil used by fuel producers would change. We
discuss this uncertainty in more detail in section 6.4.1 of the RIA and
solicit comments to the extent by which the RFS may have a price effect
and impact the imports of crude oil and refined products.
We quantified the fraction of net petroleum imports that would be
crude oil versus finished products. Comparison of same cases in the AEO
2006 shows that finished products initially compose all the net import
reductions, followed by imported crude oil once reductions in
consumption reach beyond 1.2 Quads of petroleum product. However, there
is significant uncertainty in quantifying how refineries will change
their mix of sources with a decrease in petroleum demand, particularly
at the levels estimated for the RFS. For example, a comparison between
the AEO low price case (as opposed to low macroeconomic growth case)
and the reference case would yield a 50-50 split between product and
crude imports. We believe that the actual refinery response could range
between these two points, so that finished product imports would
compose between 50 to 100% of the net import reductions, with crude oil
imports making up the remainder. For the purposes of this rulemaking,
we show values for the case where net import reductions come entirely
from imports of finished products, as shown below in Table IX.D-1. We
compare these reductions in imports against the AEO projected levels of
net petroleum imports. The range of reductions in net petroleum imports
are estimated to be between 1 to 2%, as shown in Table IX.D-2.
Table IX.D-1.--Reductions in Imports of Finished Products
[barrels per day]
------------------------------------------------------------------------
Cases 2012
------------------------------------------------------------------------
7.5........................................................ 145,454
9.9........................................................ 240,892
------------------------------------------------------------------------
[[Page 55631]]
Table IX.D-2.--Percent Reductions in Petroleum Imports Compared to
AEO2006 Import Projections
------------------------------------------------------------------------
Cases 2012
------------------------------------------------------------------------
7.5............................................................ 1.1%
9.9............................................................ 1.7%
------------------------------------------------------------------------
One of the effects of increased use of renewable fuel is that it
diversifies the energy sources used in making transportation fuel. To
the extent that diverse sources of fuel energy reduce the dependence on
any one source, the risks, both financial as well as strategic, of
potential disruption in supply or spike in cost of a particular energy
source is reduced.
To understand the energy security implications of the RFS, EPA will
work with Oak Ridge National Laboratory (ORNL). As a first step, ORNL
will update and apply the approach used in the 1997 report Oil Imports:
An Assessment of Benefits and Costs, by Leiby, Jones, Curlee and
Lee.\97\ This paper was cited and its results utilized in previous DOT/
NHTSA rulemakings, including the 2006 Final Regulatory Impact Analysis
of CAFE Reform for Light Trucks.\98\ This approach is consistent with
that used in the Effectiveness and Impact of Corporate Average Fuel
Economy (CAFE) Standards Report conducted by the National Research
Council/National Academy of Sciences in 2002. Both reports estimate the
marginal benefits to society, in dollars per barrel, of reducing either
imports or consumption. This ``oil premium'' approach emphasizes
identifying those energy-security related costs that are not reflected
in the market price of oil, and which may change in response to an
incremental change in the level of oil imports or consumption.\99\
---------------------------------------------------------------------------
\97\ Leiby, Paul N., Donald W. Jones, T. Randall Curlee, and
Russell Lee,Oil Imports: An Assessment of Benefits and Costs, ORNL-
6851, Oak Ridge National Laboratory, November 1, 1997.
(http://pzl1.ed.ornl.gov/energysecurity.html).
\98\ US DOT, NHTSA 2006. ``Final Regulatory Impact
Analysis:Corporate Average Fuel Economy and CAFE Reform for MY 2008-
2011 Light Trucks,'' Office of Regulatory Analysis and Evaluation,
National Center for Statistics and Analysis, March.
(http://www.nhtsa.dot.gov/staticfiles/DOT/NHTSA/Rulemaking/Rules/
Associated%20Files/2006_FRIAPublic.pdf).
\99\ For instance, the 1997 ORNL study gave a range for the
``oilpremium'' $0 to $13 per barrel (adjusted to $2004) based on
1994 market conditions. The actual value depended on assumptions
about the market power of foreign exporters and the monopsony power
of the U.S., the risk of future oil price shocks and the employment
of hedging strategies, and the connections between oil shocks and GNP.
---------------------------------------------------------------------------
Since the 1997 publication of this report changes in oil market
conditions, both current and projected, suggest that the magnitude of
the ``oil premium'' may have changed. Significant factors that should
be reconsidered include: Oil prices, current and anticipated levels of
OPEC production, U.S. import levels, potential OPEC behavior and
responses, and disruption likelihoods. ORNL will apply the most
recently available careful quantitative assessment of disruption
likelihoods, from the Stanford Energy Modeling Forum's 2005 workshop
series, as well as other assessments \100\. ORNL will also revisit the
issue of the macroeconomic consequences of oil market disruptions and
sustained higher oil prices. Using the ``oil premium'' calculation
methodology which combines short-run and long-run costs and benefits,
and accounting for uncertainty in the key driving factors, ORNL will
provide an updated range of estimates of the marginal energy security
implications of displacing oil consumption with renewable fuels. The
results of this work effort are not available for this proposal but
will be part of the assessment of impacts of the RFS in the final rule.
Although not directly applicable, financial economics literature has
examined risk diversification. The agency is interested in ways to
examine changes in risks associated with diversifying energy sources in
general and solicits comments as such.
---------------------------------------------------------------------------
\100\ Stanford Energy Modeling Forum, Phillip C. Beccue and
Hillard G.Huntington, 2005. ``An Assessment of Oil Market Disruption
Risks,'' FINAL REPORT, EMF SR 8, October 3.
(http://www.stanford.edu/group/EMF/publications/search.htm).
---------------------------------------------------------------------------
We also calculate the decreased expenditures on petroleum imports
and compare this with the U.S. trade position measured as U.S. net
exports of all goods and services economy-wide. All reductions in
petroleum imports are expected to be from finished petroleum products
rather than crude oil. The reduced expenditures in petroleum product
imports were calculated by multiplying the reductions in gasoline and
diesel imports by their corresponding price. According to the EIA, the
price of imported finished products is the market price minus domestic
local transportation from refineries and minus taxes.\101\ An estimate
was made by using the AEO 2006 gasoline and distillate price forecasts
and subtracting the average Federal and state taxes based on historical
data.\102\
---------------------------------------------------------------------------
\101\ EIA (September 1997), ``Petroleum 1996: Issues and
Trends'', Office of Oil and Gas, DOE/EIA-0615, p. 71.
(http://tonto.eia.doe.gov/FTPROOT/petroleum/061596.pdf)
\102\ The average taxes per gallon of gasoline and diesel have
stayedrelatively constant. For 2000-2006, gasoline taxes were $0.44/
gallon ($2004) while for 2002-2006, diesel taxes were $0.49/gallon.
The average was taken from available EIA data
(http://tonto.eia.doe.gov/oog/info/gdu/gasdiesel.asp).
---------------------------------------------------------------------------
We compare these avoided petroleum import expenditures against the
projected value of total U.S. net exports of all goods and services
economy-wide. Net exports is a measure of the difference between the
value of exports of goods and services by the U.S. and the value of
U.S. imports of goods and services from the rest of the world. For
example, according to the AEO 2006, the value of total import
expenditures of goods and services exceeds the value of U.S. exports of
goods and services to the rest of the world by $695 billion for 2006
(for a net export level of minus $695 billion).\103\ This net exports
level is projected to diminish to minus $383 billion by 2012. In Table
IX.D-3, we compare the avoided expenditures in petroleum imports versus
the total value of U.S. net exports of goods and services for the whole
economy for 2012. Relative to the 2012 projection, the avoided
petroleum expenditures due to the RFS would represent 0.9 to 1.5% of
economy-wide net exports.
---------------------------------------------------------------------------
\103\ For reference, the U.S. Bureau of Economic Analysis (BEA)
reports that the 2005 import expenditures. on energy-related
petroleum products totaled $235.5 billion (2004$) while petroleum
exports totaled $13.6 billion--for a net of $221.9 billion in
expenditures. Net petroleum expenditures made up a significant
fraction of the $591.3 billion current account deficit in goods and
services for 2005 (2004$). (http://www.bea.gov/)
[[Page 55632]]
Table IX.D-3.--Avoided Petroleum Import Expenditures for 2012
[$2004 billion]
------------------------------------------------------------------------
Percent
Avoided versus
AEO2006 total net exports RFS Cases expenditures total net
in petroleum exports
imports (Percent)
------------------------------------------------------------------------
-$383........................... 7.5 3.5 0.9
9.9 5.8 1.5
------------------------------------------------------------------------
X. Agricultural Sector Economic Impacts
As described in more detail in the Draft Regulatory Impact Analysis
accompanying this proposal, we plan to evaluate the economic impact on
the agricultural sector. However, due to the timing of that analysis,
it will not be completed until the final rule. In the meantime, we
briefly describe here (and in more detail in the draft RIA) our planned
analyses and the sources of assumptions which could critically impact
those assessments. Finally, we ask for specific comment on the best
sources of information we use in these analyses.
We will be using the Forest and Agricultural Sector Optimization
Model (``FASOM'') developed over the past 30 years by Bruce McCarl,
Texas A&M University and others. This is a constrained optimization
model which seeks to allocate resources and production to maximize
producer plus consumer surpluses. We have consulted with a range of
experts both within EPA as well as at our sister agencies, the U.S.
Departments of Agriculture and Energy and they support the use of this
model for assessing the economic impacts on the agricultural sector of
various renewable fuel pathways evaluated in this rule. The objective
of this modeling assessment is to predict the economic impacts that
will directly result from the expanded use of farm products for
transportation fuel production. We anticipate that the growing demand
for corn for ethanol production in particular but also soybeans and
other agricultural crops such as rapeseed and other oil seeds for
biodiesel production will increase the production of these feedstocks
and impact farm income. The additional corn to produce ethanol may come
from several sources, including (1) more intensive cultivation of
existing land that currently produces corn, (2) switching production
from soybean and cotton to corn, (3) additional acres of land being
cultivated, or (4) diversion from corn exports. The implications to
U.S. net exports and environment effects partially depend on which
source supplies more corn. Eventually various cellulose sources such as
corn stover and switchgrass for cellulose-based ethanol production may
well become highly demanded and also significantly impact the
agricultural sector.
Using the FASOM model, we will estimate the direct impact on farm
income resulting from higher demand for corn and soybeans, for example.
Additionally, we will estimate impacts on farm employment. Since we
expect the higher demand for feedstock will increase both the supply
and cost of feedstock, we will also consider how the higher renewable
fuel feedstock cost impacts the cost of other agricultural products
(corn and soy meal are important sources not only for directly making
food for human consumption but also as feed for farm animals). As an
estimate of the impact on corn and soybeans prices, we are relying on
the estimates provided by the U.S. Department of Agriculture \104\
rather than using the FASOM model to derive these price impacts.
Additionally, we will rely on the Energy Information Agency's estimates
for fuel mix in predicting the amount of ethanol and biodiesel in the
fuel pool. Other than these external constraints, we expect to use
FASOM as the basic model for estimating economic impacts on farm sector
and how these might more generally impact the U.S. economy. Note that
this FASOM analysis is a partial equilibrium analysis, focusing almost
exclusively on impacts in the U.S. agricultural sector. As a result, it
cannot be utilized to make broader assessments of net social benefits
resulting from this rulemaking, which for example would require
evaluation of the transfer payments to farmers and ethanol producers
from consumers and refiners.
---------------------------------------------------------------------------
\104\ ``USDA Agricultural Baseline Projections to 2015.''
---------------------------------------------------------------------------
XI. Public Participation
We request comments on all aspects of this proposal. The comment
period for this proposed rule will be November 12, 2006. Comments can
be submitted to the Agency through any of the means listed under
ADDRESSES above.
We will hold a public hearing on October 13, 2006. The public
hearing will start at 10 a.m. (Central) at the Sheraton Gateway Suites
Chicago O'Hare, 6501 North Mannheim Road, Rosemont, Illinois 60018. If
you would like to present testimony at the public hearing, we ask that
you notify the contact person listed under FOR FURTHER INFORMATION
CONTACT above at least ten days beforehand. You should estimate the
time you will need for your presentation and identify any needed audio/
visual equipment. We suggest that you bring copies of your statement or
other material for the EPA panel and the audience. It would also be
helpful if you send us a copy of your statement or other materials
before the hearing.
We will arrange for a written transcript of the hearing and keep
the official record of the hearing open for 30 days to allow for the
public to supplement the record. You may make arrangements for copies
of the transcript directly with the court reporter.
XII. Administrative Requirements
A. Executive Order 12866: Regulatory Planning and Review
Under Executive Order (EO) 12866, (58 FR 51735, October 4, 1993)
this action is a ``significant regulatory action'' because of the
policy implications of the proposed rule. Even though EPA has estimated
that renewable fuel use through 2012 will be sufficient to meet the
levels required in the standard, the proposed rule reflects the first
renewable fuel mandate at the Federal level. Accordingly, EPA submitted
this action to the Office of Management and Budget (OMB) for review
under EO 12866 and any changes made in response to OMB recommendations
have been documented in the docket for this action.
B. Paperwork Reduction Act
The information collection requirements in this proposed rule have
been submitted for approval to the Office of Management and Budget
(OMB) under the Paperwork Reduction
[[Page 55633]]
Act, 44 U.S.C. 3501 et seq. The Information Collection Request (ICR)
document prepared by EPA has been assigned EPA ICR number 2242.01.
The information is planned to be collected to ensure that the
required amount of renewable fuel is used each year. The credit trading
program required by the Energy Act will be satisfied through a program
utilizing Renewable Identification Numbers (RIN), which serve as a
surrogate for renewable fuel consumption. Our proposed RIN-based
program would fulfill all the functions of a credit trading program,
and thus would meet the Energy Act's requirements. For each calendar
year, each obligated party would be required to submit a report to the
Agency documenting the RINs it acquired, and showing that the sum of
all RINs acquired were equal to or greater than its renewable volume
obligation. The Agency could then verify that the RINs used for
compliance purposes were valid by simply comparing RINs reported by
producers to RINs claimed by obligated parties. The Agency will then
calculate the total amount of renewable fuel produced each year.
For fuel standards, Section 208(a) of the Clean Air Act requires
that manufacturers provide information the Administrator may reasonably
require to determine compliance with the regulations; submission of the
information is therefore mandatory. We will consider confidential all
information meeting the requirements of Section 208(c) of the Clean Air
Act.
The annual public reporting and recordkeeping burden for this
collection of information is estimated to be 3.1 hours per response.
Burden means the total time, effort, or financial resources expended by
persons to generate, maintain, retain, or disclose or provide
information to or for a Federal agency. This includes the time needed
to review instructions; develop, acquire, install, and utilize
technology and systems for the purposes of collecting, validating, and
verifying information, processing and maintaining information, and
disclosing and providing information; adjust the existing ways to
comply with any previously applicable instructions and requirements
which have subsequently changed; train personnel to be able to respond
to a collection of information; search data sources; complete and
review the collection of information; and transmit or otherwise
disclose the information.
A document entitled ``Information Collection Request (ICR); OMB-83
Supporting Statement, Environmental Protection Agency, Office of Air
and Radiation,'' has been placed in the public docket. The supporting
statement provides a detailed explanation of the Agency's estimates by
collection activity. The estimates contained in the docket are briefly
summarized here:
Estimated total number of potential respondents: 4,945.
Estimated total number of responses: 4,970.
Estimated total annual burden hours: 15,560.
Estimated total annual costs: $2,911,000, including $1,806,240 in
purchased services.
An agency may not conduct or sponsor, and a person is not required
to respond to a collection of information unless it displays a
currently valid OMB control number. The OMB control numbers for EPA's
regulations in 40 CFR are listed in 40 CFR part 9.
To comment on the Agency's need for this information, the accuracy
of the provided burden estimates, and any suggested methods for
minimizing respondent burden, including the use of automated collection
techniques, EPA has established a public docket for this rule, which
includes this ICR, under Docket ID number EPA-OAR-2005-0161. Submit any
comments related to the ICR for this proposed rule to EPA and OMB. See
the ADDRESSES section at the beginning of this notice for where to
submit comments to EPA. Send comments to OMB at the Office of
Information and Regulatory Affairs, Office of Management and Budget,
725 17th Street, NW., Washington, DC 20503, Attention: Desk Office for
EPA. Since OMB is required to make a decision concerning the ICR
between 30 and 60 days after publication in the Federal Register, a
comment to OMB is best assured of having its full effect if OMB
receives it by October 30, 2006. The final rule will respond to any OMB
or public comments on the information collection requirements contained
in this proposal.
C. Regulatory Flexibility Act
1. Overview
The Regulatory Flexibility Act (RFA) generally requires an agency
to prepare a regulatory flexibility analysis of any rule subject to
notice and comment rulemaking requirements under the Administrative
Procedure Act or any other statute unless the agency certifies that the
rule will not have a significant economic impact on a substantial
number of small entities. Small entities include small businesses,
small organizations, and small governmental jurisdictions.
For purposes of assessing the impacts of today's rule on small
entities, small entity is defined as: (1) A small business as defined
by the Small Business Administration's (SBA) regulations at 13 CFR
121.201 (see table below); (2) a small governmental jurisdiction that
is a government of a city, county, town, school district or special
district with a population of less than 50,000; and (3) a small
organization that is any not-for-profit enterprise which is
independently owned and operated and is not dominant in its field. The
following table provides an overview of the primary SBA small business
categories potentially affected by this regulation:
----------------------------------------------------------------------------------------------------------------
NAICS
Industry Defined as small entity by SBA if: codes\a\
----------------------------------------------------------------------------------------------------------------
Gasoline refiners............................... < =1,500 employees and a crude capacity of 324110
< =125,000 bpcd\b\.
----------------------------------------------------------------------------------------------------------------
\a\ North American Industrial Classification System.
\b\ barrels of crude per day.
2. Background--Small Refiners Versus Small Refineries
Title XV (Ethanol and Motor Fuels) of the Energy Policy Act
provides, at Section 1501(a)(2) [42 U.S.C. 7545(o)(9)(A)-(D)], special
provisions for ``small refineries'', such as a temporary exemption from
the standards until calendar year 2011. The Act defines the term
``small refinery'' as ``* * * a refinery for which the average
aggregate daily crude oil throughput for a calendar year * * * does not
exceed 75,000 barrels.'' This term is different from a small refiner,
which is what the Regulatory Flexibility Act is concerned with. A small
refiner is a small business that meets the criteria set out in SBA's
regulations at 13 CFR 121.201; whereas a small refinery, per the Energy
Policy Act, is a refinery where the annual crude throughput is less
than or equal to 75,000 barrels (i.e., a small-capacity refinery), and
could be owned by a
[[Page 55634]]
larger refiner that exceeds SBA's small entity size standards.
Previous EPA fuel regulations have afforded regulatory flexibility
provisions to small refiners, as we believe that refineries owned by
small businesses generally face unique economic challenges, compared to
larger refiners. As small refiners generally lack the resources
available to larger companies (including those larger companies that
own small-capacity refineries) to raise capital for any necessary
investments for meeting regulatory requirements, these flexibility
provisions were provided to reduce the disproportionate burden on those
refiners that qualified as small refiners.
3. Summary of Potentially Affected Small Entities
The refiners that are potentially affected by this proposed rule
are those that produce gasoline. For our recent proposed rule ``Control
of Hazardous Air Pollutants From Mobile Sources'' (71 FR 15804,
Wednesday, March 29, 2006), we performed an industry characterization
of potentially affected gasoline refiners; we used that industry
characterization to determine which refiners would also meet the SBA
definition of a small refiner under this proposal. From the industry
characterization, we determined that there were 20 gasoline refiners
that met the definition of a small refiner. Of these 20 refiners, 17
owned refineries that also met the Energy Policy Act's definition of a
small refinery.
4. Impact of the Regulations on Small Entities
As previously stated, many aspects of the RFS program, such as the
required amount of annual renewable fuel volumes, were specified in the
Energy Policy Act. As shown above in Table III.D.3.c-2, the annual
projections of ethanol production exceed the required annual renewable
fuel volumes. When the small refinery exemption ends, it is anticipated
that there will be over one billion gallons in excess RINs available.
We believe that this large volume of excess RINs will also lower the
costs of this program. If there were a shortage of RINs, or if any
party were to `hoard' RINs, the cost of a RIN could be high; however
with excess RINs, we believe that this program will not impose a
significant economic burden on small refineries, small refiners, or any
other obligated party. Further, we have determined that this proposed
rule will not have a significant economic impact on a substantial
number of small entities.
When the Agency certifies that a rule will not have a significant
economic impact on a substantial number of small entities, EPA's policy
is to make an assessment of the rule's impact on any small entities and
to engage the potentially regulated entities in a dialog regarding the
rule, and minimize the impact to the extent feasible. The following
sections discuss our outreach with the potentially affected small
entities and proposed regulatory flexibilities to decrease the burden
on these entities in compliance with the requirements of the RFS program
5. Small Refiner Outreach
Although we do not believe that the RFS program would have a
significant economic impact on a substantial number of small entities,
EPA nonetheless has tried to reduce the impact of this rule on small
entities. We held meetings with small refiners to discuss the
requirements of the RFS program and the special provisions offered by
the Energy Policy Act for small refineries.
The Energy Policy Act set out the following provisions for small
refineries:
? A temporary exemption from the Renewable Fuels Standard
requirement until 2011;
? An extension of the temporary exemption period for at
least two years for any small refinery where it is determined that the
refinery would be subject to a disproportionate economic hardship if
required to comply;
? Any small refinery may petition, at any time, for an
exemption based on disproportionate economic hardship; and,
? A small refinery may waive its temporary exemption to
participate in the credit generation program, or it may also ``opt-
in'', by waiving its temporary exemption, to be subject to the RFS
requirement.
During these meetings with the small refiners we also discussed the
impacts of these provisions being offered to small refineries only. As
stated above, three refiners met the definition of a small refiner, but
their refineries did not meet the Act's definition of a small refinery;
which naturally concerned the small refiners. Another concern that the
small refiners had was that if this rule were to have a significant
economic impact on a substantial number of small entities a lengthy
SBREFA process would ensue (which would delay the promulgation of the
RFS rulemaking, and thus provide less lead time for these small
entities prior to the RFS program start date).
Following our discussions with the small refiners, they provided
three suggested regulatory flexibility options that they believed could
further assist affected small entities in complying with the RFS
program standard: (1) That all small refiners be afforded the Act's
small refinery temporary exemption, (2) that small refiners be allowed
to generate credits if they elect to comply with the RFS program
standard prior to the 2011 small refinery compliance date, and (3)
relieve small refiners who generate blending credits of the RFS program
compliance requirements.
We agreed with the small refiners'' suggestion that small refiners
be afforded temporary exemption that the Act specifies for small
refineries. Regarding the small refiners' second and third suggestions
regarding credits, our proposed RIN-based program will automatically
provide them with credit for any renewables that they blend into their
motor fuels. Until 2011, small refiners will essentially be treated as
oxygenate blenders and may separate RINs from batches and trade or sell
these RINs.
6. Conclusions
After considering the economic impacts of today's proposed rule on
small entities, we certify that this action will not have a significant
economic impact on a substantial number of small entities.
While the Energy Policy Act provided for a temporary exemption for
small refineries from the requirements of today's proposed rule, these
parties will have to comply with the requirements following the
exemption period. However, we still believe that small refiners
generally lack the resources available to larger companies, and
therefore find it necessary to extend the small refinery temporary
exemption to all small refiners. Thus, we are proposing to allow the
small refinery temporary exemption, as set out in the Act, to all
qualified small refiners. In addition, past fuels rulemakings have
included a provision that, to qualify for EPA's small refiner
flexibilities, a refiner must have no more than 1,500 total corporate
employees and have a crude capacity of no more than 155,000 bpcd
(slightly higher than SBA's crude capacity limit of 125,000 bpcd). To
be consistent with these previous rules, we are also proposing to allow
those refiners that meet these criteria to be considered small refiners
for this rulemaking. Lastly, we are proposing that small refiners may
separate RINs from batches and trade or sell these RINs prior to 2011
if the small refiner operates as a blender
[[Page 55635]]
We continue to be interested in the potential impacts of this
proposed rule on small entities and welcome comments on issues related
to such impacts.
D. Unfunded Mandates Reform Act
Title II of the Unfunded Mandates Reform Act of 1995 (UMRA), Public
Law 104-4, establishes requirements for Federal agencies to assess the
effects of their regulatory actions on State, local, and tribal
governments and the private sector. Under Section 202 of the UMRA, EPA
generally must prepare a written statement, including a cost-benefit
analysis, for proposed and final rules with ``Federal mandates'' that
may result in expenditures to State, local, and tribal governments, in
the aggregate, or to the private sector, of $100 million or more in any
one year. Before promulgating an EPA rule for which a written statement
is needed, Section 205 of the UMRA generally requires EPA to identify
and consider a reasonable number of regulatory alternatives and adopt
the least costly, most cost-effective or least burdensome alternative
that achieves the objectives of the rule. The provisions of Section 205
do not apply when they are inconsistent with applicable law. Moreover,
Section 205 allows EPA to adopt an alternative other than the least
costly, most cost-effective or least burdensome alternative if the
Administrator publishes with the final rule an explanation why that
alternative was not adopted.
Before EPA establishes any regulatory requirements that may
significantly or uniquely affect small governments, including tribal
governments, it must have developed under Section 203 of the UMRA a
small government agency plan. The plan must provide for notifying
potentially affected small governments, enabling officials of affected
small governments to have meaningful and timely input in the
development of EPA regulatory proposals with significant Federal
intergovernmental mandates, and informing, educating, and advising
small governments on compliance with the regulatory requirements.
EPA has determined that this rule does not contain a Federal
mandate that may result in expenditures of $100 million or more for
State, local, and tribal governments, in the aggregate, or the private
sector in any one year. EPA has estimated that renewable fuel use
through 2012 will be sufficient to meet the required levels. Therefore,
individual refiners, blenders, and importers are already on track to
meet rule obligations through normal market-driven incentives. Thus,
today's rule is not subject to the requirements of Sections 202 and 205
of the UMRA.
This rule contains no Federal mandates for State, local, or tribal
governments as defined by the provisions of Title II of the UMRA. The
rule imposes no enforceable duties on any of these governmental
entities. Nothing in the rule would significantly or uniquely affect
small governments.
E. Executive Order 13132: Federalism
Executive Order 13132, entitled ``Federalism'' (64 FR 43255, August
10, 1999), requires EPA to develop an accountable process to ensure
``meaningful and timely input by State and local officials in the
development of regulatory policies that have Federalism implications.''
``Policies that have Federalism implications'' is defined in the
Executive Order to include regulations that have ``substantial direct
effects on the States, on the relationship between the national
government and the States, or on the distribution of power and
responsibilities among the various levels of government.''
This proposed rule does not have Federalism implications. It will
not have substantial direct effects on the States, on the relationship
between the national government and the States, or on the distribution
of power and responsibilities among the various levels of government,
as specified in Executive Order 13132. Thus, Executive Order 13132 does
not apply to this rule.
In the spirit of Executive Order 13132, and consistent with EPA
policy to promote communications between EPA and State and local
governments, EPA specifically solicits comment on this proposed rule
from State and local officials.
F. Executive Order 13175: Consultation and Coordination With Indian
Tribal Governments
Executive Order 13175, entitled ``Consultation and Coordination
with Indian Tribal Governments'' (59 FR 22951, November 9, 2000),
requires EPA to develop an accountable process to ensure ``meaningful
and timely input by tribal officials in the development of regulatory
policies that have tribal implications.''
This proposed rule does not have tribal implications, as specified
in Executive Order 13175. This rule would be implemented at the Federal
level and collectively apply to refiners, blenders, and importers. EPA
expects these entities to meet the standards on a collective basis
through 2012 even without imposition of any RFS obligations on any
individual party. Tribal governments will be affected only to the
extent they purchase and use regulated fuels. Thus, Executive Order
13175 does not apply to this rule. EPA specifically solicits additional
comment on this proposed rule from tribal officials.
G. Executive Order 13045: Protection of Children From Environmental
Health and Safety Risks
Executive Order 13045: ``Protection of Children from Environmental
Health Risks and Safety Risks'' (62 FR 19885, April 23, 1997) applies
to any rule that: (1) Is determined to be ``economically significant''
as defined under Executive Order 12866, and (2) concerns an
environmental health or safety risk that EPA has reason to believe may
have a disproportionate effect on children. If the regulatory action
meets both criteria, the Agency must evaluate the environmental health
or safety effects of the planned rule on children, and explain why the
planned regulation is preferable to other potentially effective and
reasonably feasible alternatives considered by the Agency.
EPA interprets Executive Order 13045 as applying only to those
regulatory actions that are based on health or safety risks, such that
the analysis required under Section 5-501 of the Order has the
potential to influence the regulation. This proposed rule is not
subject to Executive Order 13045 because it does not establish an
environmental standard intended to mitigate health or safety risks and
because it implements specific standards established by Congress in
statutes.
H. Executive Order 13211: Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution, or Use
This rule is not a ``significant energy action'' as defined in
Executive Order 13211, ``Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution, or Use'' (66 FR 28355
(May 22, 2001)) because it is not likely to have a significant adverse
effect on the supply, distribution, or use of energy.
EPA expects the provisions to have very little effect on the
national fuel supply, since normal market forces alone are promoting
greater renewable fuel use than required by the RFS mandate.
Nevertheless, the rule is an important part of the nation's efforts to
reduce dependence on foreign oil. We discuss our analysis of the energy
and supply effects of the increased use of renewable fuels in Sections
VI and X of this preamble.
[[Page 55636]]
I. National Technology Transfer Advancement Act
Section 12(d) of the National Technology Transfer and Advancement
Act of 1995 (``NTTAA''), Public Law 104-113, 12(d) (15 U.S.C. 272 note)
directs EPA to use voluntary consensus standards in its regulatory
activities unless to do so would be inconsistent with applicable law or
otherwise impractical. Voluntary consensus standards are technical
standards (e.g., materials specifications, test methods, sampling
procedures, and business practices) that are developed or adopted by
voluntary consensus standards bodies. The NTTAA directs EPA to provide
Congress, through OMB, explanations when the Agency decides not to use
available and applicable voluntary consensus standards.
This proposed rulemaking does not involve technical standards.
Therefore, EPA is not considering the use of any voluntary consensus
standards.
XIII. Statutory Authority
Statutory authority for the rules proposed today can be found in
section 211 of the Clean Air Act, 42 U.S.C. 7545. Additional support
for the procedural and compliance related aspects of today's proposal,
including the proposed recordkeeping requirements, come from Sections
114, 208, and 301(a) of the CAA, 42 U.S.C. 7414, 7542, and 7601(a).
List of Subjects in 40 CFR Part 80
Environmental protection, Air pollution control, Fuel additives,
Gasoline, Imports, Incorporation by reference, Labeling, Motor vehicle
pollution, Penalties, Reporting and recordkeeping requirements.
Dated: September 7, 2006.
Stephen L. Johnson,
Administrator.
40 CFR part 80 is proposed to be amended as follows:
PART 80--REGULATION OF FUELS AND FUEL ADDITIVES
1. The authority citation for part 80 continues to read as follows:
Authority: 42 U.S.C. 7414, 7542, 7545, and 7601(a).
2. Section 80.1100 is revised to read as follows:
Sec. 80.1100 How is the statutory default requirement for 2006 implemented?
(a) Definitions. The definitions of Sec. 80.2 and the following
additional definitions apply to this section only.
(1) Renewable fuel. (i) Renewable fuel means motor vehicle fuel
that is used to replace or reduce the quantity of fossil fuel present
in a fuel mixture used to operate a motor vehicle, and which:
(A) Is produced from grain, starch, oil seeds, vegetable, animal,
or fish materials including fats, greases, and oils, sugarcane, sugar
beets, sugar components, tobacco, potatoes, or other biomass; or
(B) Is natural gas produced from a biogas source, including a
landfill, sewage waste treatment plant, feedlot, or other place where
decaying organic material is found.
(ii) The term ``renewable fuel'' includes cellulosic biomass
ethanol, waste derived ethanol, biodiesel, and any blending components
derived from renewable fuel.
(2) Cellulosic biomass ethanol means ethanol derived from any
lignocellulosic or hemicellulosic matter that is available on a
renewable or recurring basis, including dedicated energy crops and
trees, wood and wood residues, plants, grasses, agricultural residues,
fibers, animal wastes and other waste materials, and municipal solid
waste. The term also includes any ethanol produced in facilities where
animal wastes or other waste materials are digested or otherwise used
to displace 90 percent or more of the fossil fuel normally used in the
production of ethanol.
(3) Waste derived ethanol means ethanol derived from animal wastes,
including poultry fats and poultry wastes, and other waste materials,
or municipal solid waste.
(4) Small refinery means a refinery for which the average aggregate
daily crude oil throughput for a calendar year (as determined by
dividing the aggregate throughput for the calendar year by the number
of days in the calendar year) does not exceed 75,000 barrels.
(5) Biodiesel means a diesel fuel substitute produced from
nonpetroleum renewable resources that meets the registration
requirements for fuels and fuel additives established by the
Environmental Protection Agency under section 211 of the Clean Air Act.
It includes biodiesel derived from animal wastes (including poultry
fats and poultry wastes) and other waste materials, or biodiesel
derived from municipal solid waste and sludges and oils derived from
wastewater and the treatment of wastewater.
(b) Renewable fuel standard for 2006. The percentage of renewable
fuel in the total volume of gasoline sold or dispensed to consumers in
2006 in the United States shall be a minimum of 2.78 percent on an
annual average volume basis.
(c) Responsible parties. Parties collectively responsible for
attainment of the standard in paragraph (b) of this section are
refiners (including blenders) and importers of gasoline. However, a
party that is a refiner only because he owns or operates a small
refinery is exempt from this responsibility.
(d) EPA determination of attainment. EPA will determine after the
close of 2006 whether or not the requirement in paragraph (b) of this
section has been met. EPA will base this determination on information
routinely published by the Energy Information Administration on the
annual domestic volume of gasoline sold or dispensed to U.S. consumers
and of ethanol produced for use in such gasoline, supplemented by
readily available information concerning the use in motor fuel of other
renewable fuels such as cellulosic biomass ethanol, waste derived
ethanol, biodiesel, and other non-ethanol renewable fuels.
(1) The renewable fuel volume will equal the sum of all renewable
fuel volumes used in motor fuel, provided that:
(i) One gallon of cellulosic biomass ethanol or waste derived
ethanol shall be considered to be the equivalent of 2.5 gallons of
renewable fuel; and
(ii) Only the renewable fuel portion of blending components derived
from renewable fuel shall be counted towards the renewable fuel volume.
(2) If the nationwide average volume percent of renewable fuel in
gasoline in 2006 is equal to or greater than the standard in paragraph
(b) of this section, the standard has been met.
(e) Consequence of nonattainment in 2006. In the event that EPA
determines that the requirement in paragraph (b) of this section has
not been attained in 2006, a deficit carryover volume shall be added to
the renewable fuel volume obligation for 2007 for use in calculating
the standard applicable to gasoline in 2007.
(1) The deficit carryover volume shall be calculated as follows:
DC = Vgas* (Rs-Ra)
Where:
DC = Deficit carryover in gallons of renewable fuel.
Vgas = Volume of gasoline sold or dispensed to U.S. consumers in
2006, in gallons.
Rs = 0.0278.
Ra = Ratio of renewable fuel volume divided by total gasoline volume
determined in accordance with paragraph (d)(2) of this section.
(2) There shall be no other consequence of failure to attain the
standard in paragraph (b) of this section in 2006 for any of the
parties in paragraph (c) of this section.
[[Page 55637]]
3. Section 80.1101 is added to read as follows:
Sec. 80.1101 Definitions.
The definitions of Sec. 80.2 and the following additional
definitions apply for purposes of this subpart.
(a) Cellulosic biomass ethanol means either of the following:
(1) Ethanol derived from any lignocellulosic or hemicellulosic
matter that is available on a renewable or recurring basis, which
includes any of the following:
(i) Dedicated energy crops and trees.
(ii) Wood and wood residues.
(iii) Plants.
(iv) Grasses.
(v) Agricultural residues.
(vi) Animal wastes and other waste materials.
(vii) Municipal solid waste.
(2) Ethanol made at facilities at which animal wastes or other
waste materials are digested or otherwise used onsite to displace 90
percent or more of the fossil fuel that is combusted to produce thermal
energy integral to the process of making ethanol and which comply with
the recordkeeping requirements of Sec. 80.1151(a)(4).
(b) Other waste materials means either of the following:
(1) Waste materials that are residues rather than being produced
solely for the purpose of being combusted to produce energy (e.g.,
residual tops, branches, and limbs from a tree farm could be waste
materials while wood chips used as fuel and which come from plants
grown solely for such purpose would not be waste materials).
(2) Waste heat that is captured from an off-site combustion process
(e.g., furnace, boiler, heater, or chemical process).
(c) Otherwise used means either of the following:
(1) The direct combustion of the waste materials to make thermal energy.
(2) The use of waste heat as a source of thermal energy.
(d) Waste derived ethanol means ethanol derived from either of the
following:
(1) Animal wastes, including poultry fats and poultry wastes, and
other waste materials.
(2) Municipal solid waste.
(e) Biogas means methane or other hydrocarbon gas produced from
decaying organic material, including landfills, sewage waste treatment
plants, and animal feedlots.
(f) Renewable fuel. (1) Renewable fuel is motor vehicle fuel that
is used to replace or reduce the quantity of fossil fuel present in a
fuel mixture used to operate a motor vehicle, and is produced from
either of the following:
(i) Grain.
(ii) Starch.
(iii) Oilseeds.
(iv) Vegetable, animal or fish materials including fats, greases
and oils.
(v) Sugarcane.
(vi) Sugar beets.
(vii) Sugar components.
(viii) Tobacco.
(ix) Potatoes.
(x) Other biomass; or is natural gas produced from a biogas source,
including a landfill, sewage waste treatment plant, feedlot, or other
place where decaying organic material is found.
(2) The term ``Renewable fuel'' includes cellulosic biomass
ethanol, waste derived ethanol, biodiesel (mono-alkyl ester), non-ester
renewable diesel, and blending components derived from renewable fuel.
(3) Small volume additives less than 1.0 percent of the total
volume of a renewable fuel shall be counted as part of the total
renewable fuel volume.
(4) A fuel produced by a renewable fuel producer that is used in
boilers or heaters is not a motor vehicle fuel, and therefore is not a
renewable fuel.
(g) Blending component has the same meaning as ``Gasoline blending
stock, blendstock, or component'' as defined at Sec. 80.2(s), for
which the portion that can be counted as renewable fuel is calculated
as set forth in Sec. 80.1115(a).
(h) Motor vehicle has the meaning given in Section 216(2) of the
Clean Air Act (42 U.S.C. 7550).
(i) Small refinery means a refinery for which the average aggregate
daily crude oil throughput for the calendar year 2004 (as determined by
dividing the aggregate throughput for the calendar year by the number
of days in the calendar year) does not exceed 75,000 barrels.
(j) Biodiesel (mono-alkyl ester) means a motor vehicle fuel or fuel
additive which:
(1) Is registered as a motor vehicle fuel or fuel additive under 40
CFR part 79;
(2) Is a mono-alkyl ester;
(3) Meets ASTM D-6751-02a;
(4) Is intended for use in engines that are designed to run on
conventional diesel fuel, and
(5) Is derived from nonpetroleum renewable resources (as defined in
paragraph (o) of this section).
(k) Non-ester renewable diesel means a motor vehicle fuel or fuel
additive which:
(1) Is registered as a motor vehicle fuel or fuel additive under 40
CFR part 79;
(2) Is not a mono-alkyl ester;
(3) Is intended for use in engines that are designed to run on
conventional diesel fuel; and
(4) Is derived from nonpetroleum renewable resources (as defined in
paragraph (o) of this section).
(l) Biocrude means plant oils or animal fats that are used as
feedstocks to any production unit in a refinery that normally processes
crude oil to make gasoline or diesel fuels.
(m) Biocrude-based renewable fuels are renewable fuels that are
gasoline or diesel products resulting from the processing of biocrudes
in atmospheric distillation or other process units at refineries that
normally process petroleum-based feedstocks.
(n) Importers, for the purposes of this subpart only, are those
persons who:
(1) Are considered importers under Sec. 80.2(r); and
(2) Are persons who bring gasoline into the 48 contiguous states of
the United States from areas that have not chosen to opt in to the
program requirements of this subpart (per Sec. 80.1143).
(o) Nonpetroleum renewable resources include, but are not limited
to, either of the following:
(1) Plant oils.
(2) Animal fats and animal wastes, including poultry fats and
poultry wastes, and other waste materials.
(3) Municipal solid waste and sludges and oils derived from
wastewater and the treatment of wastewater.
(p) Export of renewable fuel means:
(1) Transfer of a batch of renewable fuel to a location outside the
United States; and
(2) Transfer of a batch of renewable fuel from the contiguous 48
states to Alaska, Hawaii, or a United States territory, unless that
state or territory has received an approval from the Administrator to
opt-in to the renewable fuel program pursuant to Sec. 80.1143.
(q) Renewable Identification Number (RIN), is a unique number
generated to represent a volume of renewable fuel in accordance with
Sec. 80.1126.
(r) Standard-value is a RIN generated to represent renewable fuel
with an equivalence value up to and including 1.0.
(s) Extra-value RIN is a RIN generated to represent renewable fuel
with an equivalence value greater than 1.0.
(t) Batch-RIN is a RIN that represents a batch of renewable fuel
containing multiple gallons. A batch-RIN uniquely identifies all of the
gallon-RINs in that batch.
(u) Gallon-RIN is a RIN that represents an individual gallon of
renewable fuel.
[[Page 55638]]
Sec. Sec. 80.1102-80.1103 [Added and Reserved]
4. Sections 80.1102 and 80.1103 are added and reserved.
5. Sections 80.1104 through 80.1107 are added to read as follows:
Sec. 80.1104 What are the implementation dates for the Renewable Fuel
Standard Program?
The RFS standards and other requirements of this subpart are
effective beginning the day after [DATE 60 DAYS AFTER PUBLICATION OF
THE FINAL RULE IN THE FEDERAL REGISTER.
Sec. 80.1105 What is the Renewable Fuel Standard?
(a) The annual value of the renewable fuel standard for 2007 shall
be 3.71 percent.
(b) Beginning with the 2008 compliance period, EPA will calculate
the value of the annual standard and publish this value in the Federal
Register by November 30 of the year preceding the compliance period.
(c) EPA will base the calculation of the standard on information
provided by the Energy Information Administration regarding projected
gasoline volumes and projected volumes of renewable fuel expected to be
used in gasoline blending for the upcoming year.
(d) EPA will calculate the annual renewable fuel standard using the
following equation:
[GRAPHIC]
[TIFF OMITTED]
TP22SE06.006
Where:
RFStdi = Renewable Fuel Standard in year i, in percent.
RFVi = Nationwide annual volume of renewable fuels
required by section 211(o)(2)(B) of the Act (42 U.S.C. 7545) for
year i, in gallons.
Gi = Amount of gasoline projected to be used in the 48
contiguous states, in year i, in gallons.
Ri = Amount of renewable fuel blended into gasoline that
is projected to be used in the 48 contiguous states, in year i, in
gallons.
GSi = Amount of gasoline projected to be used in
noncontiguous states or territories (if the state or territory opts-
in) in year i, in gallons.
RSi = Amount of renewable fuel blended into gasoline that
is projected to be used in noncontiguous states or territories (if
the state or territory opts-in) in year i, in gallons.
GEi = Amount of gasoline projected to be produced by
exempt small refineries and small refiners in year i, in gallons
(through 2010 only).
Celli = Beginning in 2013, the amount of renewable fuel
that is required to come from cellulosic sources, in year i, in
gallons (250,000,000 gallons minimum).
(e) Beginning with the 2013 compliance period, EPA will calculate the
value of the annual cellulosic standard and publish this value in the
Federal Register by November 30 of the year preceding the compliance
period.
(f) EPA will calculate the annual cellulosic standard using the
following equation:
[GRAPHIC]
[TIFF OMITTED]
TP22SE06.007
Where:
RFCelli = Renewable Fuel Cellulosic Standard in year i,
in percent.
Gi = Amount of gasoline projected to be used in the 48
contiguous states, in year i, in gallons.
Ri = Amount of renewable fuel blended into gasoline that
is projected to be used in the 48 contiguous states, in year i, in
gallons.
GSi = Amount of gasoline projected to be used in
noncontiguous states or territories (if the state or territory opts-
in) in year i, in gallons.
RSi = Amount of renewable fuel blended into gasoline that
is projected to be used in noncontiguous states or territories (if
the state or territory opts-in) in year i, in gallons.
Celli = Amount of renewable fuel that is required to come
from cellulosic sources, in year i, in gallons (250,000,000 gallons minimum).
Sec. 80.1106 To whom does the Renewable Volume Obligation apply?
(a)(1) An obligated party is a refiner or blender which produces
gasoline within the 48 contiguous states, or an importer which imports
gasoline into the 48 contiguous states.
(2) If the Administrator approves a petition of Alaska, Hawaii, or
a United States territory to opt-in to the renewable fuel program under
the provisions in Sec. 80.1143, then ``obligated party'' shall include
any refiner or blender which produces gasoline within that state or
territory, or an importer which imports gasoline into that state or
territory.
(b)(1) For each calendar year starting with 2007, any obligated
party is required to demonstrate, pursuant to Sec. 80.1127, that they
have satisfied the Renewable Volume Obligation for that calendar year,
as specified in Sec. 80.1107(a), except as otherwise provided in this
section.
(2) The deficit carryover provisions in Sec. 80.1127(b) only apply
if all of the requirements specified in Sec. 80.1127(b) are fully
satisfied.
(c) Any blender whose sole blending activity in a calendar year is
to blend a renewable fuel (or fuels) into gasoline, RBOB, CBOB, or
diesel fuel is not required to meet the renewable volume obligation
specified in Sec. 80.1107(a) for that gasoline for that calendar year.
Sec. 80.1107 How is the Renewable Volume Obligation calculated?
For the purposes of this section, all reformulated gasoline,
conventional gasoline and blendstock, collectively called ``gasoline''
unless otherwise specified, is subject to the requirements under this
subpart, as applicable.
(a) The Renewable Volume Obligation for an obligated party is
determined according to the following formula:
RVOi = RFStdi x GVi +
Di-1
Where:
RVOi = The Renewable Volume Obligation for a refiner,
blender, or importer for calendar year i, in gallons of renewable
fuel.
RFStdi = The renewable fuel standard for calendar year i
from Sec. 80.1105, in percent.
GVi = The non-renewable gasoline volume, determined in
accordance with paragraphs (b), (c), and (d) of this section, which
is produced or imported, in year i, in gallons.
Di-1 = Renewable fuel deficit carryover from the previous
year, per Sec. 80.1127(b), in gallons.
(b) The non-renewable gasoline volume for a refiner, blender, or
importer for a given year, GVi, specified in paragraph (a)
of this section is calculated as follows:
[GRAPHIC]
[TIFF OMITTED]
TP22SE06.008
Where:
x = Batch.
n = Total number of batches of gasoline produced or imported.
Gx = Total volume of gasoline produced or imported, per
paragraph (c) of this section, in gallons.
RBx = Total volume of renewable fuel blended into
gasoline, in gallons.
[[Page 55639]]
(c) For the purposes of this section, all of the following products
that are produced or imported during a calendar year are to be included
in the volume used to calculate a party's renewable volume obligation
under paragraph (a) of this section, except as provided in paragraph
(d) of this section:
(1) Reformulated gasoline.
(2) Conventional gasoline.
(3) Reformulated gasoline blendstock for oxygenate blending (``RBOB'').
(4) Conventional gasoline blendstock that becomes finished
conventional gasoline upon the addition of oxygenate (``CBOB'').
(5) Gasoline treated as blendstock (``GTAB'').
(6) Blendstock that has been combined with other blendstock or
finished gasoline to produce gasoline.
(d) The following products are not included in the volume of
gasoline produced or imported used to calculate a party's renewable
volume obligation under paragraph (a) of this section:
(1) Any renewable fuel as defined in Sec. 80.1101(f).
(2) Blendstock that has not been combined with other blendstock or
finished gasoline to produce gasoline.
(3) Gasoline produced or imported for use in Alaska, Hawaii, the
Commonwealth of Puerto Rico, the U.S. Virgin Islands, Guam, American
Samoa, and the Commonwealth of the Northern Marianas, unless the area
has opted into the RFS program under Sec. 80.1143.
(4) Gasoline produced by a small refinery that has an exemption
under Sec. 80.1141 or an approved small refiner that has an exemption
under Sec. 80.1142 during the period that such exemptions are in effect.
(5) Gasoline exported for use outside the United States.
(6) For blenders, the volume of finished gasoline, RBOB, or CBOB to
which a blender adds blendstocks.
(e) Compliance period. (1) For 2007, the compliance period is [DATE
60 DAYS AFTER PUBLICATION OF THE FINAL RULE IN THE FEDERAL REGISTER]
through December 31, 2007.
(2) Beginning in 2008, and every year thereafter, the compliance
period is January 1 through December 31.
Sec. Sec. 80.1108-80.1114 [Added and Reserved]
6. Sections 80.1108 through 80.1114 are added and reserved.
7. Section 80.1115 is added to read as follows:
Sec. 80.1115 How are equivalence values assigned by renewable fuel
producers?
(a) Each gallon of a renewable fuel shall be assigned an
equivalence value. The equivalence value is a number assigned to every
renewable fuel that is used to determine how many gallon-RINs can be
generated for a batch of renewable fuel according to Sec. 80.1126.
Equivalence Values for certain renewable fuels are assigned in
paragraph (d) of this section. For other renewable fuels, the
equivalence value shall be calculated using the following formula:
EV = (R / 0.931) * (EC / 77,550)
Where:
EV = Equivalence Value for the renewable fuel.
R = Renewable content of the renewable fuel. This is a measure of
the portion of a renewable fuel that came from a renewable source,
expressed as a percent, on an energy basis, of the renewable fuel
that comes from a renewable feedstock.
EC = Energy content of the renewable fuel, in Btu per gallon (lower
heating value).
(b) Technical justification and approval of calculation of the
Equivalence Value.
(1) Producers of renewable fuels must prepare a technical
justification of the calculation of the Equivalence Value for the
renewable fuel including a description of the renewable fuel, its
feedstock and production process.
(2) Producers shall submit the justification to the EPA for approval.
(3) The Agency will review the technical justification and assign
an appropriate Equivalence Value to the renewable fuel based on the
procedure in paragraph (c) of this section.
(c) The equivalence value is assigned as follows:
(1) A value rounded to the nearest tenth if such value is less than 0.9.
(2) 1.0 if the calculated equivalence value is in the range of 0.9 to 1.2.
(3) 1.3, 1.5, or 1.7, for calculated values over 1.2, whichever
value is closest to the calculated equivalence value, based on the
positive difference between the calculated equivalence value and each
of these three values, except as specified in paragraphs (c)(4) and
(c)(5) of this section.
(4) 2.5 for cellulosic biomass ethanol that is produced on or
before December 31, 2012.
(5) 2.5 for waste derived ethanol.
(d) Equivalence values for some renewable fuels are as given in the
following table:
Table 1 of Sec. 80.1115.--Equivalence Values for Some Renewable Fuels
------------------------------------------------------------------------
Equivalence
Renewable fuel type value (EV)
------------------------------------------------------------------------
Cellulosic biomass ethanol and waste derived ethanol 2.5
produced on or before December 31, 2012...................
Ethanol from corn, starches, or sugar...................... 1.0
Biodiesel (mono-alkyl ester)............................... 1.5
Non-ester renewable diesel................................. 1.7
Butanol.................................................... 1.3
ETBE from corn ethanol..................................... 0.4
------------------------------------------------------------------------
Sec. Sec. 80.1116--80.1124 [Added and Reserved]
8. Sections 80.1116 through 80.1124 are added and reserved.
9. Sections 80.1125 through 80.1131 are added to read as follows:
Sec. 80.1125 Renewable Identification Numbers (RINs).
Each RIN is a 34 character numerical code of the following form:
YYYYCCCCFFFFFBBBBBRRDKSSSSSSEEEEEE
(a) YYYY is the calendar year in which the batch of renewable fuel
was produced or imported. YYYY also represents the year in which the
RIN was originally generated.
(b) CCCC is the registration number assigned according to Sec.
80.1150 to the producer or importer of the batch of renewable fuel.
(c) FFFFF is the registration number assigned according to Sec.
80.1150 to the facility at which the batch of renewable fuel was
produced or imported.
(d) BBBBB is a serial number assigned to the batch which:
(1) Is chosen by the producer or importer of the batch such that no
two batches have the same value in a given calendar year;
(2) Begins with the value 00001 for the first batch produced or
imported by a facility in a given calendar year; and
(3) Increases sequentially for subsequent batches produced or
imported by that facility in that calendar year.
(e) RR is a number representing the equivalence value of the
renewable fuel.
(1) Equivalence values are specified in Sec. 80.1115.
(2) Multiply the equivalence value by 10 to produce the value for RR.
(f) D is a number identifying the type of renewable fuel, as
follows:
(1) D has the value of 1 if the renewable fuel can be categorized
as cellulosic biomass ethanol.
[[Page 55640]]
(2) D has the value of 2 if the renewable fuel cannot be
categorized as cellulosic biomass ethanol.
(g) K is a number identifying the type of RIN as follows:
(1) K has the value of 1 if the batch-RIN is a standard-value RIN.
(2) K has the value of 2 if the batch-RIN is an extra-value RIN.
(h) SSSSSS is a number representing the first gallon associated
with a batch of renewable fuel.
(i) EEEEEE is a number representing the last gallon associated with
a batch of renewable fuel. EEEEEE will be identical to SSSSSS in the
case of a gallon-RIN. Assign the value of EEEEEE as described in Sec.
80.1126.
Sec. 80.1126 How are RINs assigned to batches of renewable fuel by
renewable fuel producers or importers?
(a) Regional applicability. (1) Except as provided in paragraph (b)
of this section, every batch of renewable fuel produced by a facility
located in the contiguous 48 states of the United States, or imported
into the contiguous 48 states, must be assigned a RIN.
(2) If the Administrator approves a petition of Alaska, Hawaii, or
a United States territory to opt-in to the renewable fuel program under
the provisions in Sec. 80.1143, then the requirements of paragraph
(a)(1) of this section shall also apply to renewable fuel produced or
imported into that state or territory beginning in the next calendar
year.
(b) Volume threshold. Pursuant to Sec. 80.1154, producers with
renewable fuel production facilities located within the United States
that produce less than 10,000 gallons of renewable fuel each year, and
importers that import less than 10,000 gallons of renewable fuel each
year, are not required to generate and assign RINs to batches of
renewable fuel. Such producers and importers are also exempt from the
registration, reporting, and recordkeeping requirements of Sec. Sec.
80.1150 through 80.1152. However, for those producers and importers
that voluntarily generate and assign RINs, all the requirements of this
subpart apply.
(c) Generation of RINs. (1) The producer or importer of a batch of
renewable fuel must generate the RINs associated with that batch.
However, a producer of a batch of renewable fuel for export is not
required to generate a RIN for that batch if that producer is also the
exporter and exports the renewable fuel.
(2) A party generating a RIN shall specify the appropriate
numerical values for each component of the RIN in accordance with the
provisions of Sec. 80.1125 and this paragraph (c).
(3) Standard-value RINs shall be generated separately from extra-
value RINs, and distinguished from one another by the K component of
the RIN.
(4) When a standard-value batch-RIN or an extra-value batch-RIN is
initially generated by a renewable fuel producer or importer, the value
of SSSSSS in the batch-RIN shall be 000001 to represent the first
gallon in the batch of renewable fuel.
(5) Generation of standard-value batch-RINs. (i) Except as provided
in paragraph (c)(5)(ii) of this section, a standard-value batch-RIN
shall be generated to represent the gallons in a batch of renewable
fuel. The value of EEEEEE when a batch-RIN is initially generated by a
renewable fuel producer or importer shall be determined as follows:
(A) For renewable fuels with an equivalence value of 1.0 or
greater, the value of EEEEEE shall be the standardized volume of the
batch in gallons.
(B) For renewable fuels with an equivalence value of less than 1.0,
the value of EEEEEE shall be the applicable volume, in gallons,
calculated according to the following formula:
Va = EV * Vs
Where:
Va = Applicable volume of renewable fuel, in gallons, for
use in designating the value of EEEEEE.
EV = Equivalence value for the renewable fuel per Sec. 80.1115.
Vs = Standardized volume of the batch of renewable fuel
at 60 [deg]F, in gallons.
(ii) For biocrude-based renewable fuels, a standard-value batch-RIN
shall be generated to represent the gallons of biocrude rather than the
gallons of renewable fuel. The value of EEEEEE shall be the
standardized volume of the biocrude in gallons.
(6) Generation of extra-value batch-RINs. (i) Extra-value batch-
RINs may be generated for renewable fuels having an equivalence value
greater than 1.0.
(ii) The value for EEEEEE in an extra-value batch-RIN when a batch-
RIN is initially generated by a renewable fuel producer or importer
shall be the applicable volume of renewable fuel calculated according
to the following formula:
Va = (EV-1.0) * Vs
Where:
Va = Applicable volume of renewable fuel, in gallons, for
use in designating the value of EEEEEE.
EV= Equivalence value for the renewable fuel per Sec. 80.1115.
Vs = Standardized volume of the batch of renewable fuel
at 60 [deg]F, in gallons.
(7) Standardization of volumes. In determining the standardized
volume of a batch of renewable fuel for purposes of generating
standard-value batch-RINs or extra-value batch-RINs, pursuant to
paragraphs (c)(5) and (c)(6) of this section, the batch volumes shall
be adjusted to a standard temperature of 60 [deg]F.
(i) For ethanol, the following formula shall be used:
Vs,e = Va,e * (-0.0006301 x T + 1.0378)
Where:
Vs,e = Standardized volume of ethanol at 60 [deg]F, in gallons.
Va,e = Actual volume of ethanol, in gallons.
T = Actual temperature of the batch, in [deg]F.
(ii) For biodiesel (mono alkyl esters), the following formula shall
be used:
Vs,b = Va,b * (-0.0008008 x T + 1.0480)
Where:
Vs,b = Standardized volume of biodiesel at 60 [deg]F, in gallons.
Va,b = Actual volume of biodiesel, in gallons.
T = Actual temperature of the batch, in [deg]F.
(iii) For other renewable fuels, an appropriate formula commonly
accepted by the industry shall be used to standardize the actual volume
to 60 [deg]F.
(d) Assignment of batch-RINs to batches. (1) The producer or
importer of a batch of renewable fuel must assign standard-value RINs
to the batch of renewable fuel that those batch-RINs represent.
(2) The producer or importer of a batch of renewable fuel may
assign extra-value batch-RINs to the batch of renewable fuel that those
batch-RINs represent.
(3) A batch-RIN is assigned to a batch when the batch-RIN is
recorded in a prominent location on a product transfer document
assigned to that batch of renewable fuel per Sec. 80.1153.
Sec. 80.1127 How are RINs used to demonstrate compliance?
(a) Renewable volume obligations. (1) Except as specified in
paragraph (b) of this section, each party that is obligated to meet the
Renewable Volume Obligation under Sec. 80.1107, or an exporter of
renewable fuels, must demonstrate that it has acquired sufficient RINs
to satisfy the following equation:
([Sigma]RINVOL)i + ([Sigma]RINVOL)i-1 = RVOi
Where:
([Sigma]RINVOL)i = Sum of all acquired gallon-RINs that
were generated in year i and are being applied towards the
RVOi, in gallons.
([Sigma]RINVOL)i-1 = Sum of all acquired gallon-RINs that
were generated in year i-1 and are being applied towards the
RVOi, in gallons.
[[Page 55641]]
RVOi = The Renewable Volume Obligation for the obligated
party or renewable fuel exporter for calendar year i, in gallons.
(2) For compliance for calendar years 2009 and later, the value of
([Sigma]RINVOL)i-1 may not exceed a value determined by the
following inequality:
([Sigma]RINVOL)i-1 <= 0.20 * RVOi
Where:
([Sigma]RINVOL)i-1 = Sum of all acquired gallon-RINs that
were generated in year i-1 and are being applied towards the
RVOi, in gallons.
(3) RINs may only be used to demonstrate compliance with the RVO
for the calendar year in which they were generated or the following
calendar year. RINs used to demonstrate compliance in one year cannot
be used to demonstrate compliance in any other year.
(4) A party may acquire a RIN only if that RIN is obtained in
accordance with Sec. Sec. 80.1128 and 80.1129.
(5) Gallon-RINs that can be used for compliance with the RVO shall
be calculated from the following formula:
RINVOL = EEEEEE - SSSSSS + 1
Where:
RINVOL = Gallon-RINs associated with a batch-RIN, in gallons.
EEEEEE = Batch-RIN component identifying the last gallon associated
with the batch of renewable fuel that the batch-RIN represents.
SSSSSS = Batch-RIN component identifying the first gallon associated
with the batch of renewable fuel that the batch-RIN represents.
(b) Deficit carryovers. (1) An obligated party or an exporter of
renewable fuel that fails to meet the requirements of paragraph (a)(1)
of this section for calendar year i is permitted to carry a deficit
into year i + 1 under the following conditions:
(i) The party did not carry a deficit into calendar year i from
calendar year i-1.
(ii) The party subsequently meets the requirements of paragraph
(a)(1) of this section for calendar year i+1.
(2) A deficit is calculated according to the following formula:
Di = RVOi - [([Sigma]RINVOL)i +
([Sigma]RINVOL)i-1]
Where:
Di = The deficit generated in calendar year i that must
be carried over to year i+1 if allowed pursuant to paragraph
(b)(1)(i) of this section, in gallons.
RVOi = The Renewable Volume Obligation for the obligated
party or renewable fuel exporter for calendar year i, in gallons.
([Sigma]RINVOL)1 = Sum of all acquired gallon-RINs that
were generated in year i and are being applied towards the
RVOi, in gallons.
([Sigma]RINVOL)i-1 = Sum of all acquired
gallon-RINs that were generated in year i-1 and are being applied
towards the RVOi, in gallons.
Sec. 80.1128 General requirements for RIN distribution.
(a) RINs assigned to batches of renewable fuel. (1) Except as
provided in Sec. 80.1129 and paragraph (a)(3) of this section, as
title to a batch of renewable fuel is transferred from one party to
another, a batch-RIN that has been assigned to that batch according to
Sec. 80.1126(d) must remain assigned to an equivalent renewable fuel
volume having the same equivalence value.
(i) A batch-RIN assigned to a batch shall be identified on product
transfer documents representing the batch pursuant to Sec. 80.1153.
(ii) Any documentation used to transfer custody of or title to a
batch from one party to another must identify the batch-RINs assigned
to that batch.
(2) If two or more batches of renewable fuel are combined into a
single batch, then all the batch-RINs assigned to all the batches
involved in the merger shall be assigned to the final combined batch.
(3) If a batch of renewable fuel is split into two or more smaller
batches, any batch-RINs assigned to the parent batch must likewise be
split and assigned to the daughter batches.
(i) If the Equivalence Value for the renewable fuel in the parent
batch is equal to or greater than 1.0, then there shall be at least one
gallon-RIN for every gallon in each of the daughter batches.
(ii) If the Equivalence Value for the renewable fuel in the parent
batch is less than 1.0, then the ratio of gallon-RINs to gallons in the
parent batch shall be preserved in all daughter batches.
(iii) For purposes of this paragraph (a)(3), the volume of each
parent and daughter batch shall be standardized to 60 [deg]F pursuant
to Sec. 80.1126(c)(7).
(b) RINs not assigned to batches of renewable fuel. (1) Unassigned
RIN means one of the following:
(i) It is a RIN that contains a K value identifying it as an extra-
value RIN and was not assigned to a batch of renewable fuel by the
producer or importer of that batch; or
(ii) It is a RIN that was separated from the batch to which it was
assigned in accordance with Sec. 80.1129.
(2) Any party that has registered pursuant to Sec. 80.1150 can
hold title to an unassigned RIN.
(3) Unassigned RINs can be transferred from one party to another
any number of times.
(4) An unassigned batch-RIN can be divided by its holder into two
batch-RINs, each representing a smaller number of gallon-RINs if all of
the following conditions are met:
(i) All RIN components other than SSSSSS and EEEEEE are identical
for the parent and daughter RINs.
(ii) The sum of the gallon-RINs associated with the two daughter
batch-RINs is equal to the gallon-RINs associated with the parent batch.
Sec. 80.1129 Requirements for separating RINs from batches.
(a)(1) Separation of a RIN from a batch means termination of the
assignment of the RIN from a batch of renewable fuel.
(2) A RIN that has been assigned to a batch of renewable fuel
according to Sec. 80.1126(d) may be separated from a batch only under
one of the following conditions:
(i) A party that is an obligated party according to Sec. 80.1106
may separate any RINs that have been assigned to a batch if they own
the batch.
(ii) Except as provided in paragraph (a)(2)(v) of this section, any
party that owns a batch of renewable fuel shall have the right to
separate any RINs that have been assigned to that batch once the batch
is blended with gasoline or diesel to produce a motor vehicle fuel.
(iii) Any party that exports a batch of renewable fuel shall have
the right to separate any RINs that have been assigned to the exported
batch.
(iv) Except as provided in paragraph (a)(2)(v) of this section, any
renewable fuel producer that owns a batch of renewable fuel shall have
the right to separate any RINs that have been assigned to that batch if
the renewable fuel is designated as motor vehicle fuel in its neat form
and is used as motor vehicle fuel in its neat form.
(v) RINs assigned to batches of biodiesel (mono-alkyl esters) can
only be separated from those batches once the biodiesel is blended into
diesel fuel at a concentration of 80 volume percent biodiesel or less.
(b) Upon separation from its associated batch, a RIN shall be
removed from all documentation that:
(1) Is used to identify custody or title to the batch; or
(2) Is transferred with the batch.
(c) RINs that have been separated from batches of renewable fuel
become unassigned RINs subject to the provisions of Sec. 80.1128(b).
Sec. 80.1130 Requirements for exporters of renewable fuels.
(a)(1) Any party that exports any amount of renewable fuel shall
acquire sufficient RINs to offset a Renewable Volume Obligation
representing the exported renewable fuel.
[[Page 55642]]
(2) Only exporters located in the applicable region described in
Sec. 80.1126(a) are subject to the requirements of this section.
(b) Renewable Volume Obligations. An exporter of renewable fuel
shall determine its Renewable Volume Obligation from the volumes of the
batches exported.
(1) A renewable fuel exporter's total Renewable Volume Obligation
shall be calculated according to the following formula:
RVOi = [Sigma](VOLk * EVk) + Di-1
Where:
k = Batch.
RVOi = The Renewable Volume Obligation for the exporter
for calendar year i, in gallons of renewable fuel.
VOLk = The standardized volume of batch k of exported
renewable fuel, in gallons.
EVk = The equivalence value for batch k.
Di-1 = Renewable fuel deficit carryover from
the previous year, in gallons.
(2)(i) For exported batches of renewable fuel that have assigned
RINs, the equivalence value may be determined from the RR component of
the RIN.
(ii) If a batch of renewable fuel does not have assigned RINs but
its equivalence value may nevertheless be determined pursuant to Sec.
80.1115(d) based on its composition, then the appropriate equivalence
value shall be used in the calculation of the exporter's Renewable
Volume Obligation.
(iii) If the equivalence value for a batch of renewable fuel cannot
be determined, the value of EVk shall be 1.0.
(3) If the exporter of a batch of renewable fuel is also the
producer of that batch, and no RIN was generated to represent that
batch, then the volume of that batch shall be excluded from the
calculation of the Renewable Volume Obligation.
(c) Each exporter of renewable fuel must demonstrate compliance
with its RVO using RINs it has acquired pursuant to Sec. 80.1127.
Sec. 80.1131 Treatment of invalid RINs.
(a) Invalid RINs. An invalid RIN is a RIN that:
(1) Is a duplicate of a valid RIN;
(2) Was based on volumes that have not been standardized to 60 [deg]F;
(3) Has expired;
(4) Was based on an incorrect equivalence value; or
(5) Was otherwise improperly generated.
(b) In the case of RINs that have been determined to be invalid,
the following provisions apply:
(1) Invalid RINs cannot be used to achieve compliance with the
transferee's Renewable Volume Obligation, regardless of the
transferee's good faith belief that the RINs were valid.
(2) The refiner or importer who used the invalid RINs, and any
transferor of the invalid RINs, must adjust their records, reports, and
compliance calculations as necessary to reflect the deletion of invalid
RINs.
(3) Any valid RINs remaining after deleting invalid RINs, and after
an obligated party applies valid RINs as needed to meet the RVO at the
end of the compliance year, must first be applied to correct the
invalid transfers before the transferor trades or banks the RINs.
(4) In the event that the same RIN is transferred to two or more
parties, the RIN will be deemed to be invalid, and any party to any
transfer of the invalid RIN will be deemed liable for any violations
arising from the transfer or use of the invalid RIN.
(5) A RIN will not be deemed invalid where it can be determined
that the RIN was properly created and transferred.
Sec. Sec. 80.1132-80.1140 [Added and Reserved]
10. Sections 80.1132 through 80.1140 are added and reserved.
11. Sections 80.1141 through 80.1143 are added to read as follows:
Sec. 80.1141 Small refinery exemption.
(a)(1) Pursuant to Sec. 80.1107(d), gasoline produced by a refiner
at a small refinery is qualified for an exemption from the renewable
fuels standards of Sec. 80.1105 if that refinery meets the definition
of a small refinery under Sec. 80.1101(i) for calendar year 2004.
(2) This exemption shall apply through December 31, 2010, unless a
refiner chooses to opt-in to the program requirements of this subpart
(per paragraph (g) of this section) prior to this date.
(b)(1) To apply for an exemption under this section, a refiner must
submit an application to EPA containing the following information:
(i) The annual average aggregate daily crude oil throughput for the
period January 1, 2004, through December 31, 2004 (as determined by
dividing the aggregate throughput for the calendar year by the number 365);
(ii) A letter signed by the president, chief operating or chief
executive officer of the company, or his/her designee, stating that the
information contained in the application is true to the best of his/her
knowledge, and that the company owned the refinery as of January 1,
2006; and
(iii) Name, address, phone number, facsimile number, and E-mail
address of a corporate contact person.
(2) Applications must be submitted by September 1, 2007.
(c) Within 60 days of EPA's receipt of a refiner's application for
a small refinery exemption, EPA will notify the refiner if the
exemption is not approved or of any deficiencies in the application. In
the absence of such notification from EPA, the effective date of the
small refinery exemption is 60 days from EPA's receipt of the refiner's
submission.
(d) If EPA finds that a refiner provided false or inaccurate
information on its application for a small refinery exemption, the
exemption will be void ab initio upon notice from EPA.
(e) If a refiner is complying on an aggregate basis for multiple
refineries, any such refiner may exclude from the calculation of its
Renewable Volume Obligation (under Sec. 80.1107(a)) gasoline from any
refinery receiving the small refinery exemption under paragraph (a) of
this section.
(f)(1) The exemption period in paragraph (a) of this section shall
be extended by the Administrator for a period of not less than two
additional years if a study by the Secretary of Energy determines that
compliance with the requirements of this subpart would impose a
disproportionate economic hardship on the small refinery.
(2) A refiner may at any time petition the Administrator for an
extension of its small refinery exemption under paragraph (a) of this
section for the reason of disproportionate economic hardship.
(3) A petition for an extension of the small refinery exemption
must specify the factors that demonstrate a disproportionate economic
hardship and must provide a detailed discussion regarding the inability
of the refinery to produce gasoline meeting the requirements of Sec.
80.1105 and the date the refiner anticipates that compliance with the
requirements can be achieved at the small refinery.
(4) The Administrator shall act on such a petition not later than
90 days after the date of receipt of the petition.
(g) At any time, a refiner with an approved small refinery
exemption under paragraph (a) of this section may waive that exemption
upon notification to EPA.
(1) A refiner's notice to EPA that it intends to waive its small
refinery exemption must be received by November 1.
(2) The waiver will be effective beginning on January 1 of the
following calendar year, at which point the gasoline produced at that
refinery will be subject to the renewable fuels standard of Sec. 80.1105.
[[Page 55643]]
(3) The waiver must be sent to EPA at one of the addresses listed
in paragraph (m) of this section.
(h) A refiner that acquires a refinery from either an approved
small refiner (under Sec. 80.1142) or another refiner with an approved
small refinery exemption under paragraph (a) of this section shall
notify EPA in writing no later than 20 days following the acquisition.
(i) Applications under paragraph (b) of this section, petitions for
hardship extensions under paragraph (f) of this section, and small
refinery exemption waivers under paragraph (g) of this section shall be
sent to one of the following addresses:
(1) For U.S. mail: U.S. EPA--Attn: RFS Program, Transportation and
Regional Programs Division (6406J), 1200 Pennsylvania Avenue, NW.,
Washington, DC 20460; or
(2) For overnight or courier services: U.S. EPA, Attn: RFS Program,
Transportation and Regional Programs Division (6406J), 1310 L Street,
NW., 6th floor, Washington, DC 20005.
Sec. 80.1142 What are the provisions for small refiners under the RFS
program?
(a)(1) A refiner qualifies for a small refiner exemption if the
refiner does not meet the definition of a small refinery under Sec.
80.1101(i) but meets all of the following criteria:
(i) The refiner produced gasoline at the refinery by processing
crude oil through refinery processing units from January 1, 2004
through December 31, 2004.
(ii) The refiner employed an average of no more than 1,500 people,
based on the average number of employees for all pay periods for
calendar year 2004 for all subsidiary companies, all parent companies,
all subsidiaries of the parent companies, and all joint venture partners.
(iii) The refiner had a corporate-average crude oil capacity less
than or equal to 155,000 barrels per calendar day (bpcd) for 2004.
(2) The small refiner exemption shall apply through December 31,
2010, unless a refiner chooses to opt-in to the program requirements of
this subpart (per paragraph (g) of this section) prior to this date.
(b) To apply for an exemption under this section, a refiner must
submit an application to EPA containing all of the following
information for the refiner and for all subsidiary companies, all
parent companies, all subsidiaries of the parent companies, and all
joint venture partners; approval of an exemption application will be
based on all information submitted under this paragraph and any other
relevant information:
(1) (i) A listing of the name and address of each company location
where any employee worked for the period January 1, 2004 through
December 31, 2004.
(ii) The average number of employees at each location based on the
number of employees for each pay period for the period January 1, 2004
through December 31, 2004.
(iii) The type of business activities carried out at each location.
(iv) For joint ventures, the total number of employees includes the
combined employee count of all corporate entities in the venture.
(v) For government-owned refiners, the total employee count
includes all government employees.
(2) The total corporate crude oil capacity of each refinery as
reported to the Energy Information Administration (EIA) of the U.S.
Department of Energy (DOE), for the period January 1, 2004 through
December 31, 2004. The information submitted to EIA is presumed to be
correct. In cases where a company disagrees with this information, the
company may petition EPA with appropriate data to correct the record
when the company submits its application.
(3) A letter signed by the president, chief operating or chief
executive officer of the company, or his/her designee, stating that the
information contained in the application is true to the best of his/her
knowledge, and that the company owned the refinery as of January 1, 2006.
(4) Name, address, phone number, facsimile number, and e-mail
address of a corporate contact person.
(c) Applications under paragraph (b) of this section must be
submitted by September 1, 2007. EPA will notify a refiner of approval
or disapproval of its small refiner status in writing.
(d) A refiner who qualifies as a small refiner under this section
and subsequently fails to meet all of the qualifying criteria as set
out in paragraph (a) of this section will have its small refiner
exemption terminated effective January 1 of the next calendar year;
however, disqualification shall not apply in the case of a merger
between two approved small refiners.
(e) If EPA finds that a refiner provided false or inaccurate
information on its application for small refiner status under this
subpart, the small refiner's exemption will be void ab initio upon
notice from EPA.
(f) If a small refiner is complying on an aggregate basis for
multiple refineries, the refiner may exclude those refineries from the
compliance calculations under Sec. 80.1125.
(g) (1) An approved small refiner may, at any time, waive the
exemption under paragraph (a) of this section upon notification to EPA.
(2) An approved small refiner's notice to EPA that it intends to
waive the exemption under paragraph (a) of this section must be
received by November 1 in order for the waiver to be effective for the
following calendar year. The waiver will be effective beginning on
January 1 of the following calendar year, at which point the refiner
will be subject to the renewable fuels standard of Sec. 80.1105.
(3) The waiver must be sent to EPA at one of the addresses listed
in paragraph (i) of this section.
(h) A refiner that acquires a refinery from another refiner with
approved small refiner status under paragraph (a) of this section shall
notify EPA in writing no later than 20 days following the acquisition.
(i) Applications under paragraph (b) of this section shall be sent
to one of the following addresses:
(1) For U.S. Mail: U.S. EPA--Attn: RFS Program, Transportation and
Regional Programs Division (6406J), 1200 Pennsylvania Avenue, NW.,
Washington, DC 20460; or
(2) For overnight or courier services: U.S. EPA, Attn: RFS Program,
Transportation and Regional Programs Division (6406J), 1310 L Street,
NW., 6th floor, Washington, DC 20005.
Sec. 80.1143 What are the opt-in provisions for noncontiguous states
and territories?
(a) A noncontiguous state or United States territory may petition
the Administrator to opt-in to the program requirements of this
subpart.
(b) The petition must be signed by the Governor of the state or his
authorized representative (or the equivalent official of the
territory).
(c) The Administrator will approve the petition if it meets the
provisions of paragraphs (b) and (d) of this section.
(d)(1) A petition submitted under this section must be received by
the Agency by October 31 for the state or territory to be included in
the RFS program in the next calendar year.
(2) A petition submitted under this section should be sent to one
of the following addresses:
(i) For U.S. Mail: U.S. EPA-Attn: RFS Program, Transportation and
Regional Programs Division (6406J), 1200 Pennsylvania Avenue, NW.,
Washington, DC 20460; or
(ii) For overnight or courier services: U.S. EPA, Attn: RFS
Program, Transportation and Regional Programs
[[Page 55644]]
Division (6406J), 1310 L Street, NW., 6th floor, Washington, DC 20005.
(e) Upon approval of the petition by the Administrator--
(1) EPA shall calculate the standard for the following year,
including the total gasoline volume for the state or territory in
question.
(2) Beginning on January 1 of the next calendar year, all gasoline
producers in the state or territory for which a petition has been
approved shall be obligated parties as defined in Sec. 80.1106.
(3) Beginning on January 1 of the next calendar year, all renewable
fuel producers in the State or territory for which a petition has been
approved shall, pursuant to Sec. 80.1126(a)(2), be required to
generate RINs and assign them to batches of renewable fuel.
Sec. Sec. 80.1144-80.1149 [Added and Reserved]
12. Sections 80.1144 through 80.1149 are added and reserved.
13. Sections 80.1150 through 80.1154 are added to read as follows:
Sec. 80.1150 What are the registration requirements under the RFS program?
(a)(1) Any obligated party as defined in Sec. 80.1106 and any
exporter of renewable fuel that is subject to a renewable fuels
standard under this subpart, as of [DATE 60 DAYS AFTER PUBLICATION OF
THE FINAL RULE IN THE FEDERAL REGISTER], must provide EPA with the
information specified for registration under Sec. 80.76, if such
information has not already been provided under the provisions of this
part. In addition, for each import facility, the same identifying
information as required for each refinery under Sec. 80.76(c) must be
provided. Registrations must be submitted by no later than [DATE 90
DAYS AFTER PUBLICATION OF THE FINAL RULE IN THE FEDERAL REGISTER].
(2) Any obligated party, as defined in Sec. 80.1106, or any
exporter of renewable fuel that becomes subject to a renewable fuels
standard under this subpart after the date specified in paragraph
(a)(1) of this section, must provide EPA the information specified for
registration under Sec. 80.76, if such information has not already
been provided under the provisions of this part, and must receive EPA-
issued company and facility identification numbers prior to engaging in
any transaction involving RINs. Additionally, for each import facility,
the same identifying information as required for each refinery under
Sec. 80.76(c) must be provided.
(b)(1) Any producer of a renewable fuel that is subject to a
renewable fuels standard under this subpart as of [DATE 60 DAYS AFTER
PUBLICATION OF THE FINAL RULE IN THE FEDERAL REGISTER], must provide
EPA the information specified under Sec. 80.76, if such information
has not already been provided under the provisions of this part, by no
later than [DATE 90 DAYS AFTER PUBLICATION OF THE FINAL RULE IN THE
FEDERAL REGISTER]
.
(2) Any producer of renewable fuel that becomes subject to a
renewable fuels standard under this subpart after the date specified in
paragraph (b)(1) of this section, must provide EPA the information
specified for registration under Sec. 80.76, if such information has
not already been provided under the provisions of this part, and must
receive EPA-issued company and facility identification numbers prior to
generating or creating any RINs.
(c) Any party not covered by paragraphs (a) and (b) of this section
must provide EPA the information specified under Sec. 80.76, if such
information has not already been provided under the provisions of this
part, and must receive EPA-issued company and facility identification
numbers prior to owning any RINs.
(d) Registration shall be on forms, and following policies,
established by the Administrator.
Sec. 80.1151 What are the recordkeeping requirements under the RFS
program?
(a) Beginning with [DATE 60 DAYS AFTER PUBLICATION OF THE FINAL
RULE IN THE FEDERAL REGISTER], any obligated party as defined under
Sec. 80.1106 or exporter of renewable fuel that is subject to the
renewable fuels standard under Sec. 80.1105 must keep all the
following records:
(1) The applicable product transfer documents under Sec. 80.1153.
(2) Copies of all reports submitted to EPA under Sec. 80.1152(a).
(3) Records related to each transaction involving the sale,
purchase, brokering, and trading of RINs, which includes all the
following:
(i) A list of the RINs owned or transferred.
(ii) The parties involved in each transaction including the
transferor, transferee, and any broker or agent.
(iii) The location, time, and date of the transfer of the RIN(s).
(iv) Additional information related to details of the transaction
and its terms.
(4) Records related to the use of RINs, by facility, for
compliance, which includes all the following:
(i) Methods and variables used to calculate the Renewable Volume
Obligation pursuant to Sec. 80.1107.
(ii) List of RINs surrendered to EPA used to demonstrate compliance.
(iii) Additional information related to details of RIN use for
compliance.
(5) Verifiable records of all the following:
(i) The amount and type of fossil fuel and waste material-derived
fuel used in producing on-site thermal energy dedicated to the
production of ethanol at plants producing cellulosic ethanol as defined
in Sec. 80.1101(a)(2).
(ii) The equivalent amount of fossil fuel (based on reasonable
estimates) associated with the use of off-site generated waste heat
that is used in the production of ethanol at plants producing
cellulosic ethanol as defined in Sec. 80.1101(a)(2).
(b) Beginning with [DATE 60 DAYS AFTER PUBLICATION OF THE FINAL
RULE IN THE FEDERAL REGISTER], any importer or producer of renewable
fuel as defined under Sec. 80.1101(e) must keep all the following
records:
(1) The applicable product transfer documents under Sec. 80.1153.
(2) Copies of all reports submitted to EPA under Sec. 80.1152(b).
(3) Records related to the generation of RINs, for each facility,
including all of the following:
(i) Batch Volume.
(ii) RIN number as assigned under Sec. 80.1126.
(iii) Identification of those batches meeting the definition of
cellulosic biomass ethanol.
(iv) Date of production or import.
(v) Results of any laboratory analysis of batch chemical
composition or physical properties.
(vi) Additional information related to details of RIN generation.
(4) Records related to each transaction involving the sale,
purchase, brokering, and trading of RINs, including all of the
following:
(i) A list of the RINs acquired, owned or transferred.
(ii) The parties involved in each transaction including the
transferor, transferee, and any broker or agent.
(iii) The location, time, and date of the transfer of the RIN(s).
(iv) Additional information related to details of the transaction
and its terms.
(c) Beginning with [DATE 60 DAYS AFTER PUBLICATION OF THE FINAL
RULE IN THE FEDERAL REGISTER], any party, other than those parties
covered in paragraphs (a) and (b) of this section, that owns RINs must
keep all of the following records:
(1) The applicable product transfer documents under Sec. 80.1153.
(2) Copies of all reports submitted to EPA under Sec. 80.1152(c).
(3) Records related to each transaction involving the sale,
purchase, brokering, and trading of RINs, including all of the following:
(i) A list of the RINs acquired, owned, or transferred.
[[Page 55645]]
(ii) The parties involved in each transaction including the
transferor, transferee, and any broker or agent.
(iii) The location, time, and date of the transfer of the RIN(s).
(iv) Additional information related to details of the transaction
and its terms.
(d) The records required under this section and under Sec. 80.1153
shall be kept for five years from the date they were created, except
that records related to transactions involving RINs shall be kept for
five years from the date of transfer.
(e) On request by EPA, the records required under this section and
under Sec. 80.1153 must be made available to the Administrator or the
Administrator's authorized representative. For records that are
electronically generated or maintained, the equipment or software
necessary to read the records shall be made available; or, if requested
by EPA, electronic records shall be converted to paper documents which
shall be provided to the Administrator's authorized representative.
Sec. 80.1152 What are the reporting requirements under the RFS program?
(a) Beginning with [DATE 60 DAYS AFTER PUBLICATION OF THE FINAL
RULE IN THE FEDERAL REGISTER], any obligated party as defined in Sec.
80.1106 or exporter of renewable fuel that is subject to the renewable
fuels standard under Sec. 80.1105, and continuing for each year
thereafter, must submit to EPA annual reports that contain the
information required in this section and such other information as EPA
may require:
(1) A summary report of the annual gasoline volume produced or
imported, or volume of renewable fuel exported, and whether the party
is complying on a corporate (aggregate) or facility-by-facility basis.
This report shall include all of the following:
(i) The obligated party's name.
(ii) The EPA company registration number.
(iii) The EPA facility registration number(s).
(iv) The production volume of finished gasoline, RBOB as defined in
Sec. 80.1107(c) and CBOB as defined in Sec. 80.1107(c).
(v) The renewable volume obligation (RVO), as defined in Sec.
80.1127(a) for obligated parties and Sec. 80.1130 for exporters of
renewable fuel, for the reporting year.
(vi) Any deficit RVO carried over from the previous year.
(vii) Any deficit RVO carried into the subsequent year.
(viii) The total number of RINs used for compliance.
(ix) A list of all RINs used for compliance.
(x) Any additional information that the Administrator may require.
(2) A report documenting each transaction of RINs traded between
two parties, shall include all of the following:
(i) The submitting party's name.
(ii) The submitter's EPA company registration number.
(iii) The submitter's EPA facility registration number(s).
(iv) The compliance period,
(v) Transaction type (e.g. purchase, sale).
(vi) Transaction date.
(vii) Trading partner's name.
(viii) Trading partner's EPA company registration number.
(ix) Trading partner's EPA facility registration number.
(x) RINs traded.
(xi) Any additional information that the Administrator may require.
(3) A report that summarizes RIN activities for a given compliance
year shall include all of the following information:
(i) The total prior-years RINs carried over into the current year
(on an annual basis beginning January 1).
(ii) The total current-year RINS acquired.
(iii) The total prior-years RINs acquired.
(iv) The total current-year RINs sold.
(v) The total prior-years RINs sold.
(vi) The total current-year RINs used.
(vii) The total prior-years RINs used.
(viii) The total current-year RINs expired.
(ix) The total prior-years RINs expired.
(x) The total current-year RINs to be carried into next year.
(xi) Any additional information that the Administrator may require.
(4) Reports shall be submitted on forms and following procedures as
prescribed by EPA.
(5) Reports shall be submitted by February 28 for the previous
compliance year.
(6) All reports must be signed and certified as meeting all the
applicable requirements of this subpart by the owner or a responsible
corporate officer of the obligated party.
(b) Beginning with [DATE 60 DAYS AFTER PUBLICATION OF THE FINAL
RULE IN THE FEDERAL REGISTER], any producer or importer of a renewable
fuel that is subject to the renewable fuels standard under Sec.
80.1105, and continuing for each year thereafter, must submit to EPA
annual reports that contain all of the following information:
(1) An annual report that includes all of the following information
on a per-batch basis, where ``batch'' means a discreet quantity of
renewable fuel produced and assigned a unique RIN:
(i) The renewable fuel producer's name.
(ii) The EPA company registration number.
(iii) The EPA facility registration number(s).
(iv) The 34 character RINs generated for each batch according to
Sec. 80.1126.
(v) The production date of each batch.
(vi) The renewable fuel type as defined in Sec. 80.1101(f).
(vii) Information related to the volume of denaturant and
applicable equivalence value.
(viii) The volume produced.
(ix) Any additional information the Administrator may require.
(2) A report documenting each transaction of RINs traded between
two parties, shall include all of the following information:
(i) The submitting party's name.
(ii) The submitter's EPA company registration number.
(iii) The submitter's EPA facility registration number(s).
(iv) The compliance period.
(v) Transaction type (e.g. purchase, sale).
(vi) Transaction date.
(vii) Trading partner's name.
(viii) Trading partner's EPA company registration number.
(ix) Trading partner's EPA facility registration number;
(x) RINs traded.
(xi) Any additional information the Administrator may require.
(3) A report that summarizes RIN activities for a compliance year
shall include all of the following information:
(i) The total prior-years RINs carried over into the current year
(on an annual basis beginning January 1).
(ii) The total current-year RINs generated.
(iii) The total current-year RINS acquired.
(iv) The total prior-years RINs acquired.
(v) The total current-years RINs sold.
(vi) The total prior-years RINs sold.
(vii) The total current-years RINs expired.
(viii) The total prior-years RINs expired.
(ix) The total current-year RINs to be carried into next year.
(x) Any additional information the Administrator may require.
(4) Reports shall be submitted on forms and following procedures as
prescribed by EPA.
(5) Reports shall be submitted by February 28 for the previous year.
(6) All reports must be signed and certified as meeting all the
applicable
[[Page 55646]]
requirements of this subpart by the owner or a responsible corporate
officer of the renewable fuel producer.
(c) Any party, other than those parties covered in paragraphs (a)
and (b) of this section, who owns RINs must submit to EPA annual
reports that contain all of the following information:
(1) A report documenting each transaction of RINs traded between
two parties shall include all of the following:
(i) The submitting party's name.
(ii) The submitter's EPA company registration number.
(iii) The submitter's EPA facility registration number(s).
(iv) The compliance period.
(v) Transaction type (e.g. purchase, sale).
(vi) Transaction date.
(vii) Trading partner's name.
(viii) Trading partner's EPA company registration number.
(ix) Trading partner's EPA facility registration number.
(x) RINs traded.
(xi) Any additional information the Administrator may require.
(2) A report that summarizes RIN activities for a compliance year
shall include all of the following information:
(i) The total prior-years RINs carried over into the current year
(on an annual basis beginning January 1).
(ii) The total current-year RINS acquired.
(iii) The total prior-years RINs acquired.
(iv) The total current-years RINs sold.
(v) The total prior-years RINs sold.
(vi) The total current-years RINs expired.
(vii) The total prior-years RINs expired.
(viii) The total current-year RINs to be carried into next year.
(ix) Any additional information the Administrator may require.
(3) Reports shall be submitted on forms and following procedures as
prescribed by EPA.
(4) Reports shall be submitted by February 28 for the previous year.
(5) All reports must be signed and certified as meeting all the
applicable requirements of this subpart by the owner or a responsible
corporate officer of the renewable fuel producer.
Sec. 80.1153 What are the product transfer document (PTD)
requirements for the RFS program?
(a) Any time that a person transfers ownership of renewable fuels
subject to this subpart, and when RINs continue to accompany the
renewable fuel, the transferor must provide to the transferee documents
identifying the renewable fuel and assigned RINs which include all of
the following information as applicable:
(1) The name and address of the transferor and transferee.
(2) The transferor's and transferee's EPA company registration number.
(3) The transferor's and transferee's EPA facility registration number.
(4) The volume of renewable fuel that is being transferred.
(5) The location of the renewable fuel at the time of transfer.
(6) The date of the transfer.
(7) The RINs assigned to the volume of renewable fuel that is being
transferred.
(b) Except for transfers to truck carriers, retailers or wholesale
purchaser-consumers, product codes may be used to convey the
information required under paragraphs (a)(1) through (a)(4) of this
section if such codes are clearly understood by each transferee. The
RIN number required under paragraph (a)(7) of this section must always
appear in its entirety.
Sec. 80.1154 What are the provisions for renewable fuel producers and
importers who produce or import less than 10,000 gallons of renewable
fuel per year?
(a) Renewable fuel production facilities located within the United
States that produce less than 10,000 gallons of renewable fuel each
year, and importers who import less than 10,000 gallons of renewable
fuel each year, are not required to generate RINs or to assign RINs to
batches of renewable fuel. Such producers and importers that do not
generate and/or assign RINs to batches of renewable fuel are exempt
from the following requirements of subpart K, except as stated in
paragraph (b) of this section:
(1) The registration requirements of Sec. 80.1150:
(2) The recordkeeping requirements of Sec. 80.1151; and
(3) The reporting requirements of Sec. 80.1152.
(b) Renewable fuel producers and importers who produce or import
less than 10,000 gallons of renewable fuel each year and that generate
and/or assign RINs to batches of renewable fuel are subject to the
provisions of Sec. Sec. 80.1150 through 80.1152.
Sec. Sec. 80.1155-80.1159 [Added and Reserved]
14. Sections 80.1155 through 80.1159 are added and reserved.
15. Sections 80.1160 through 80.1165 are added to read as follows:
Sec. 80.1160 What acts are prohibited under the RFS program?
(a) Renewable fuels producer or importer violation. Except as
provided in Sec. 80.1154, no person shall produce or import a
renewable fuel that is not assigned the proper RIN value or identified
by a RIN number as required under Sec. 80.1126.
(b) RIN generation and transfer violations. No person shall do any
of the following:
(1) Improperly generate a RIN (i.e., generate a RIN for which the
applicable renewable fuel volume was not produced).
(2) Transfer to any person an invalid RIN or a RIN that is not
properly identified as required under Sec. 80.1125.
(c) RIN use violations. No person shall do any of the following:
(1) Fail to acquire sufficient RINs, or use invalid RINs, to meet
the party's renewable fuel obligation under Sec. 80.1127.
(2) Fail to acquire sufficient RINs to meet the party's renewable
fuel obligation under Sec. 80.1130.
(d) Causing a violation. No person shall cause another person to
commit an act in violation of any prohibited act under this section.
Sec. 80.1161 Who is liable for violations under the RFS program?
(a) Persons liable for violations of prohibited acts. (1) Any
person who violates a prohibition under Sec. 80.1160(a) through (c) is
liable for the violation of that prohibition.
(2) Any person who causes another person to violate a prohibition
under Sec. 80.1160(a) through (c) is liable for a violation of Sec.
80.1160(d).
(b) Persons liable for failure to meet other provisions of this
subpart.(1) Any person who fails to meet a requirement of any provision
of this subpart is liable for a violation of that provision.
(2) Any person who causes another person to fail to meet a
requirement of any provision of this subpart is liable for causing a
violation of that provision.
(c) Parent corporation liability. Any parent corporation is liable
for any violation of this subpart that is committed by any of its
subsidiaries.
(d) Joint venture liability. Each partner to a joint venture is
jointly and severally liable for any violation of this subpart that is
committed by the joint venture operation.
Sec. 80.1162 [Reserved]
Sec. 80.1163 What penalties apply under the RFS program?
(a) Any person who is liable for a violation under Sec. 80.1161 is
subject a to civil penalty of up to $32,500, as specified in sections
205 and 211(d) of the Clean Air Act, for every day of each such
violation and the amount of economic benefit or savings resulting from
each violation.
[[Page 55647]]
(b) Any person liable under Sec. 80.1161(a) for a violation of
Sec. 80.1160(c) for failure to meet a renewable fuels obligation or
causing another party to fail to meet a renewable fuels obligation
during any averaging period, is subject to a separate day of violation
for each day in the averaging period.
(c) Any person liable under Sec. 80.1161(b) for failure to meet,
or causing a failure to meet, a requirement of any provision of this
subpart is liable for a separate day of violation for each day such a
requirement remains unfulfilled.
Sec. 80.1164 What are the attest engagement requirements under the
RFS program?
In addition to the requirements for attest engagements under
Sec. Sec. 80.125 through 80.133, and other applicable attest
engagement provisions, the following annual attest engagement
procedures are required under this subpart.
(a) The following attest procedures shall be completed for any
obligated party as stated in Sec. 80.1106(b) or exporter of renewable
fuel that is subject to the renewable fuel standard under Sec. 80.1105:
(1) Annual summary report. (i) Obtain and read a copy of the annual
summary report required under Sec. 80.1152(a)(1) which contains
information regarding:
(A) The obligated party's volume of finished gasoline, reformulated
gasoline blendstock for oxygenate blending (RBOB), and conventional
gasoline blendstock that becomes finished conventional gasoline upon
the addition of oxygenate (CBOB) produced or imported during the
reporting year;
(B) Renewable volume obligation (RVO); and
(C) RINs used for compliance.
(ii) Obtain documentation of any volumes of renewable fuel used in
gasoline during the reporting year; compute and report as a finding the
volumes of renewable fuel represented in these documents.
(iii) Agree the volumes of gasoline reported to EPA in the report
required under Sec. 80.1152(a)(1) with the volumes, excluding any
renewable fuel volumes, contained in the inventory reconciliation
analysis under Sec. 80.133.
(iv) Verify that the production volume information in the obligated
party's annual summary report required under Sec. 80.1152(a)(1) agrees
with the volume information, excluding any renewable fuel volumes,
contained in the inventory reconciliation analysis under Sec. 80.133.
(v) Compute and report as a finding the obligated party's RVO, and
any deficit RVO carried over from the previous year or carried into the
subsequent year, and verify that the values agree with the values
reported to EPA.
(vi) Obtain documentation for all RINs used for compliance during
the year being reviewed; compute and report as a finding the RIN
numbers and year of generation of RINs represented in these documents;
and agree with the report to EPA.
(2) RIN transaction report. (i) Obtain and read a copy of the RIN
transaction report required under Sec. 80.1152(a)(2) which contains
information regarding RIN trading transactions.
(ii) Obtain contracts or other documents for all RIN transactions
with another party during the year being reviewed; compute and report
as a finding the transaction types, transaction dates and RINs traded;
and agree with the report to EPA.
(3) RIN activity report. (i) Obtain and read a copy of the RIN
activity report required under Sec. 80.1152(a)(3) which contains
information regarding RIN activity for the compliance year.
(ii) Obtain documentation of all RINs acquired, used for compliance
(including current-year RINs used and previous-year RINs used)
transferred, sold, and expired during the year being reviewed; compute
and report as a finding the total RINs acquired, used for compliance,
transferred, sold, and expired as represented in these documents; and
agree with the report to EPA.
(b) The following attest procedures shall be completed for any
renewable fuel producer:
(1) Annual batch report. (i) Obtain and read a copy of the annual
batch report required under Sec. 80.1152(b)(1) which contains
information regarding renewable fuel batches.
(ii) Obtain production data for each renewable fuel batch produced
during the year being reviewed; compute and report as a finding the RIN
numbers, production dates, types, volumes of denaturant and applicable
equivalence values, and production volumes for each batch; and agree
with the report to EPA.
(iii) Verify that the proper number of RINs were generated for each
batch of renewable fuel produced, as required under Sec. 80.1126.
(iv) Obtain product transfer documents for each renewable fuel
batch produced during the year being reviewed; report as a finding any
product transfer document that did not include the RIN for the batch.
(2) RIN transaction report. (i) Obtain and read a copy of the RIN
transaction report required under Sec. 80.1152(b)(2) which contains
information regarding RIN trading transactions.
(ii) Obtain contracts or other documents for all RIN transactions
with another party during the year being reviewed; compute and report
as a finding the transaction types, transaction dates, and the RINs
traded; and agree with the report to EPA.
(3) RIN activity report. (i) Obtain and read a copy of the RIN
activity report required under Sec. 80.1152(b)(3) which contains
information regarding RIN activity for the compliance year.
(ii) Obtain documentation of all RINs owned (including RINs created
and acquired), transferred, sold and expired during the year being
reviewed; compute and report as a finding the total RINs owned,
transferred, sold and expired as represented in these documents; and
agree with the report to EPA.
(c) For each averaging period, each party subject to the attest
engagement requirements under this section shall cause the reports
required under this section to be submitted to EPA by May 31 of each year.
Sec. 80.1165 What are the additional requirements under this subpart
for gasoline produced at foreign refineries?
(a) Definitions. The following definitions apply for this section:
(1) Foreign refinery is a refinery that is located outside the
United States, the Commonwealth of Puerto Rico, the U.S. Virgin
Islands, Guam, American Samoa, and the Commonwealth of the Northern
Mariana Islands (collectively referred to in this section as ``the
United States'').
(2) Foreign refiner is a person that meets the definition of
refiner under Sec. 80.2(i) for a foreign refinery.
(3) RFS-FRGAS is gasoline produced at a foreign refinery that has
received a small refinery exemption under Sec. 80.1141 or a small
refiner exemption under Sec. 80.1142 that is imported into the United
States.
(4) Non-RFS-FRGAS is one of the following:
(i) Gasoline produced at a foreign refinery that has received a
small refinery exemption under Sec. 80.1141 or a small refiner
exemption under Sec. 80.1142 that is not imported into the United States.
(ii) Gasoline produced at a foreign refinery that has not received
a small refinery exemption under Sec. 80.1141 or small refiner
exemption under Sec. 80.1142.
(b) General requirements for RFS-FRGAS foreign small refiners. (1)
A foreign refiner that has a small refinery exemption under Sec.
80.1141 or a small
[[Page 55648]]
refiner exemption under Sec. 80.1142 must designate, at the time of
production, each batch of gasoline produced at the foreign refinery
that is exported for use in the United States as RFS-FRGAS; and
(2) Meet all requirements that apply to refiners who have received
a small refinery or small refiner exemption under this subpart.
(c) Designation, foreign refiner certification, and product
transfer documents. (1) Any foreign refiner that has received a small
refinery exemption under Sec. 80.1141 or a small refiner exemption
under Sec. 80.1142 must designate each batch of RFS-FRGAS as such at
the time the gasoline is produced.
(2) On each occasion when RFS-FRGAS is loaded onto a vessel or
other transportation mode for transport to the United States, the
foreign refiner shall prepare a certification for each batch of RFS-
FRGAS that meets the following requirements:
(i) The certification shall include the report of the independent
third party under paragraph (d) of this section, and the following
additional information:
(A) The name and EPA registration number of the refinery that
produced the RFS-FRGAS;
(B) [Reserved]
(ii) The identification of the gasoline as RFS-FRGAS; and,
(iii) The volume of RFS-FRGAS being transported, in gallons.
(3) On each occasion when any person transfers custody or title to
any RFS-FRGAS prior to its being imported into the United States, it
must include the following information as part of the product transfer
document information:
(i) Designation of the gasoline as RFS-FRGAS; and
(ii) The certification required under paragraph (c)(2) of this section.
(d) Load port independent testing and refinery identification. (1)
On each occasion that RFS-FRGAS is loaded onto a vessel for transport
to the United States the small foreign refiner shall have an
independent third party:
(i) Inspect the vessel prior to loading and determine the volume of
any tank bottoms;
(ii) Determine the volume of RFS-FRGAS loaded onto the vessel
(exclusive of any tank bottoms before loading);
(iii) Obtain the EPA-assigned registration number of the foreign
refinery;
(iv) Determine the name and country of registration of the vessel
used to transport the RFS-FRGAS to the United States;
(v) Determine the date and time the vessel departs the port serving
the foreign refinery; and
(vi) Review original documents that reflect movement and storage of
the RFS-FRGAS from the foreign refinery to the load port, and from this
review determine:
(A) The refinery at which the RFS-FRGAS was produced; and
(B) That the RFS-FRGAS remained segregated from Non-RFS-FRGAS and
other RFS-FRGAS produced at a different refinery.
(2) The independent third party shall submit a report to:
(i) The foreign small refiner containing the information required
under paragraph (d)(1) of this section, to accompany the product
transfer documents for the vessel; and
(ii) The Administrator containing the information required under
paragraph (d)(1) of this section, within thirty days following the date
of the independent third party's inspection. This report shall include
a description of the method used to determine the identity of the
refinery at which the gasoline was produced, assurance that the
gasoline remained segregated as specified in paragraph (i)(1) of this
section, and a description of the gasoline's movement and storage
between production at the source refinery and vessel loading.
(3) The independent third party must:
(i) Be approved in advance by EPA, based on a demonstration of
ability to perform the procedures required in this paragraph (d);
(ii) Be independent under the criteria specified in Sec.
80.65(e)(2)(iii); and
(iii) Sign a commitment that contains the provisions specified in
paragraph (f) of this section with regard to activities, facilities,
and documents relevant to compliance with the requirements of this
paragraph (d).
(e) Comparison of load port and port of entry testing. (1)(i) Any
small foreign refiner and any United States importer of RFS-FRGAS shall
compare the results from the load port testing under paragraph (d) of
this section, with the port of entry testing as reported under
paragraph (j) of this section, for the volume of gasoline, except as
specified in paragraph (e)(1)(ii) of this section.
(ii) Where a vessel transporting RFS-FRGAS off loads this gasoline
at more than one United States port of entry, the requirements of
paragraph (e)(1)(i) of this section do not apply at subsequent ports of
entry if the United States importer obtains a certification from the
vessel owner that the requirements of paragraph (e)(1)(i) of this
section were met and that the vessel has not loaded any gasoline or
blendstock between the first United States port of entry and the
subsequent port of entry.
(2) If the temperature-corrected volumes determined at the port of
entry and at the load port differ by more than one percent, the United
States importer shall include the volume of gasoline from the
importer's RFS compliance calculations.
(f) Foreign refiner commitments. Any small foreign refiner shall
commit to and comply with the provisions contained in this paragraph
(f) as a condition to being approved for a small refinery or small
refiner exemption under this subpart.
(1) Any United States Environmental Protection Agency inspector or
auditor must be given full, complete and immediate access to conduct
inspections and audits of the foreign refinery.
(i) Inspections and audits may be either announced in advance by
EPA, or unannounced.
(ii) Access will be provided to any location where:
(A) Gasoline is produced;
(B) Documents related to refinery operations are kept; and
(C) RFS-FRGAS is stored or transported between the foreign refinery
and the United States, including storage tanks, vessels and pipelines.
(iii) Inspections and audits may be by EPA employees or contractors
to EPA.
(iv) Any documents requested that are related to matters covered by
inspections and audits must be provided to an EPA inspector or auditor
on request.
(v) Inspections and audits by EPA may include review and copying of
any documents related to:
(A) The volume of RFS-FRGAS;
(B) The proper classification of gasoline as being RFS-FRGAS or as
not being RFS-FRGAS;
(C) Transfers of title or custody to RFS-FRGAS;
(D) Testing of RFS-FRGAS; and
(E) Work performed and reports prepared by independent third
parties and by independent auditors under the requirements of this
section, including work papers.
(vi) Inspections and audits by EPA may include interviewing employees.
(vii) Any employee of the foreign refiner must be made available
for interview by the EPA inspector or auditor, on request, within a
reasonable time period.
(viii) English language translations of any documents must be
provided to an EPA inspector or auditor, on request, within 10 working days.
(ix) English language interpreters must be provided to accompany
EPA inspectors and auditors, on request.
[[Page 55649]]
(2) An agent for service of process located in the District of
Columbia shall be named, and service on this agent constitutes service
on the foreign refiner or any employee of the foreign refiner for any
action by EPA or otherwise by the United States related to the
requirements of this subpart.
(3) The forum for any civil or criminal enforcement action related
to the provisions of this section for violations of the Clean Air Act
or regulations promulgated thereunder shall be governed by the Clean
Air Act, including the EPA administrative forum where allowed under the
Clean Air Act.
(4) United States substantive and procedural laws shall apply to
any civil or criminal enforcement action against the foreign refiner or
any employee of the foreign refiner related to the provisions of this
section.
(5) Submitting an application for a small refinery or small refiner
exemption, or producing and exporting gasoline under such exemption,
and all other actions to comply with the requirements of this subpart
relating to such exemption constitute actions or activities covered by
and within the meaning of the provisions of 28 U.S.C. 1605(a)(2), but
solely with respect to actions instituted against the foreign refiner,
its agents and employees in any court or other tribunal in the United
States for conduct that violates the requirements applicable to the
foreign refiner under this subpart, including conduct that violates the
False Statements Accountability Act of 1996 (18 U.S.C. 1001) and
section 113(c)(2) of the Clean Air Act (42 U.S.C. 7413).
(6) The foreign refiner, or its agents or employees, will not seek
to detain or to impose civil or criminal remedies against EPA
inspectors or auditors, whether EPA employees or EPA contractors, for
actions performed within the scope of EPA employment related to the
provisions of this section.
(7) The commitment required by this paragraph (f) shall be signed
by the owner or president of the foreign refiner business.
(8) In any case where RFS-FRGAS produced at a foreign refinery is
stored or transported by another company between the refinery and the
vessel that transports the RFS-FRGAS to the United States, the foreign
refiner shall obtain from each such other company a commitment that
meets the requirements specified in paragraphs (f)(1) through (f)(7) of
this section, and these commitments shall be included in the foreign
refiner's application for a small refinery or small refiner exemption
under this subpart.
(g) Sovereign immunity. By submitting an application for a small
refinery or small refiner exemption under this subpart, or by producing
and exporting gasoline to the United States under such exemption, the
foreign refiner, and its agents and employees, without exception,
become subject to the full operation of the administrative and judicial
enforcement powers and provisions of the United States without
limitation based on sovereign immunity, with respect to actions
instituted against the foreign refiner, its agents and employees in any
court or other tribunal in the United States for conduct that violates
the requirements applicable to the foreign refiner under this subpart,
including conduct that violates the False Statements Accountability Act
of 1996 (18 U.S.C. 1001) and section 113(c)(2) of the Clean Air Act (42
U.S.C. 7413).
(h) Bond posting. Any foreign refiner shall meet the requirements
of this paragraph (h) as a condition to approval as benzene foreign
refiner under this subpart.
(1) The foreign refiner shall post a bond of the amount calculated
using the following equation:
Bond = G * $ 0.01
Where:
Bond = Amount of the bond in United States dollars.
G = The largest volume of gasoline produced at the foreign refinery
and exported to the United States, in gallons, during a single
calendar year among the most recent of the following calendar years,
up to a maximum of five calendar years: the calendar year
immediately preceding the date the refinery's application is
submitted, the calendar year the application is submitted, and each
succeeding calendar year.
(2) Bonds shall be posted by:
(i) Paying the amount of the bond to the Treasurer of the United
States;
(ii) Obtaining a bond in the proper amount from a third party
surety agent that is payable to satisfy United States administrative or
judicial judgments against the foreign refiner, provided EPA agrees in
advance as to the third party and the nature of the surety agreement;
or
(iii) An alternative commitment that results in assets of an
appropriate liquidity and value being readily available to the United
States, provided EPA agrees in advance as to the alternative commitment.
(3) Bonds posted under this paragraph (h) shall--
(i) Be used to satisfy any judicial judgment that results from an
administrative or judicial enforcement action for conduct in violation
of this subpart, including where such conduct violates the False
Statements Accountability Act of 1996 (18 U.S.C. 1001) and section
113(c)(2) of the Clean Air Act (42 U.S.C. 7413);
(ii) Be provided by a corporate surety that is listed in the United
States Department of Treasury Circular 570 ``Companies Holding
Certificates of Authority as Acceptable Sureties on Federal Bonds'' and
(iii) Include a commitment that the bond will remain in effect for
at least five years following the end of latest annual reporting period
that the foreign refiner produces gasoline pursuant to the requirements
of this subpart.
(4) On any occasion a foreign refiner bond is used to satisfy any
judgment, the foreign refiner shall increase the bond to cover the
amount used within 90 days of the date the bond is used.
(5) If the bond amount for a foreign refiner increases, the foreign
refiner shall increase the bond to cover the shortfall within 90 days
of the date the bond amount changes. If the bond amount decreases, the
foreign refiner may reduce the amount of the bond beginning 90 days
after the date the bond amount changes.
(i) English language reports. Any document submitted to EPA by a
foreign refiner shall be in English language, or shall include an
English language translation.
(j) Prohibitions. (1) No person may combine RFS-FRGAS with any Non-
RFS-FRGAS, and no person may combine RFS-FRGAS with any RFS-FRGAS
produced at a different refinery, until the importer has met all the
requirements of paragraph (k) of this section.
(2) No foreign refiner or other person may cause another person to
commit an action prohibited in paragraph (j)(1) of this section, or
that otherwise violates the requirements of this section.
(k) United States importer requirements. Any United States importer
of RFS-FRGAS shall meet the following requirements:
(1) Each batch of imported RFS-FRGAS shall be classified by the
importer as being RFS-FRGAS.
(2) Gasoline shall be classified as RFS-FRGAS according to the
designation by the foreign refiner if this designation is supported by
product transfer documents prepared by the foreign refiner as required
in paragraph (c) of this section. Additionally, the importer shall
comply with all requirements of this subpart applicable to importers.
(3) For each gasoline batch classified as RFS-FRGAS, any United States
[[Page 55650]]
importer shall have an independent third party:
(i) Determine the volume of gasoline in the vessel;
(ii) Use the foreign refiner's RFS-FRGAS certification to determine
the name and EPA-assigned registration number of the foreign refinery
that produced the RFS-FRGAS;
(iii) Determine the name and country of registration of the vessel
used to transport the RFS-FRGAS to the United States; and
(iv) Determine the date and time the vessel arrives at the United
States port of entry.
(4) Any importer shall submit reports within 30 days following the
date any vessel transporting RFS-FRGAS arrives at the United States
port of entry to:
(i) The Administrator containing the information determined under
paragraph (k)(3) of this section; and
(ii) The foreign refiner containing the information determined
under paragraph (k)(3)(i) of this section, and including identification
of the port at which the product was off loaded.
(5) Any United States importer shall meet all other requirements of
this subpart for any imported gasoline that is not classified as RFS-
FRGAS under paragraph (k)(2) of this section.
(l) Truck imports of RFS-FRGAS produced at a foreign refinery. (1)
Any refiner whose RFS-FRGAS is transported into the United States by
truck may petition EPA to use alternative procedures to meet the
following requirements:
(i) Certification under paragraph (c)(2) of this section;
(ii) Load port and port of entry testing under paragraphs (d) and
(e) of this section; and
(iii) Importer testing under paragraph (k)(3) of this section.
(2) These alternative procedures must ensure RFS-FRGAS remains
segregated from Non-RFS-FRGAS until it is imported into the United
States. The petition will be evaluated based on whether it adequately
addresses the following:
(i) Provisions for monitoring pipeline shipments, if applicable,
from the refinery, that ensure segregation of RFS-FRGAS from that
refinery from all other gasoline.
(ii) Contracts with any terminals and/or pipelines that receive
and/or transport RFS-FRGAS that prohibit the commingling of RFS-FRGAS
with Non-RFS-FRGAS or RFS-FRGAS from other foreign refineries.
(iii) Attest procedures to be conducted annually by an independent
third party that review loading records and import documents based on
volume reconciliation, or other criteria, to confirm that all RFS-FRGAS
remains segregated throughout the distribution system.
(3) The petition required by this section must be submitted to EPA
along with the application for a small refinery or small refiner
exemption under this subpart.
(m) Additional attest requirements for importers of RFS-FRGAS.
Importers of RFS-FRGAS, for each annual compliance period, must arrange
to have an attest engagement performed of the underlying documentation
that forms the basis of any report or document required under this
subpart. The attest engagement must comply with the procedures and
requirements that apply to importers under Sec. Sec. 80.125 through
80.130, and other applicable attest engagement provisions, and must be
submitted to the Administrator of EPA by August 31 of each year for the
prior annual compliance period. The following additional procedures
shall be carried out for any importer of RFS-FRGAS.
(1) Obtain listings of all tenders of RFS-FRGAS. Agree the total
volume of tenders from the listings to the gasoline inventory
reconciliation analysis in Sec. 80.128(b), and to the volumes
determined by the third party under paragraph (d) of this section.
(2) For each tender under paragraph (m)(1) of this section, where
the gasoline is loaded onto a marine vessel, report as a finding the
name and country of registration of each vessel, and the volumes of
RFS-FRGAS loaded onto each vessel.
(3) Select a sample from the list of vessels identified in
paragraph (m)(2) of this section used to transport RFS-FRGAS, in
accordance with the guidelines in Sec. 80.127, and for each vessel
selected perform the following:
(i) Obtain the report of the independent third party, under
paragraph (d) of this section, and of the United States importer under
paragraph (k) of this section.
(A) Agree the information in these reports with regard to vessel
identification and gasoline volume.
(B) Identify, and report as a finding, each occasion the load port
and port of entry volume results differ by more than the amount allowed
in paragraph (e) of this section, and determine whether the foreign
refiner adjusted its refinery calculations as required in paragraph (e)
of this section.
(ii) Obtain the documents used by the independent third party to
determine transportation and storage of the RFS-FRGAS from the refinery
to the load port, under paragraph (d) of this section. Obtain tank
activity records for any storage tank where the RFS-FRGAS is stored,
and pipeline activity records for any pipeline used to transport the
RFS-FRGAS prior to being loaded onto the vessel. Use these records to
determine whether the RFS-FRGAS was produced at the refinery that is
the subject of the attest engagement, and whether the RFS-FRGAS was
mixed with any Non-RFS-FRGAS or any RFS-FRGAS produced at a different
refinery.
(4) Select a sample from the list of vessels identified in
paragraph (m)(2) of this section used to transport RFS-FRGAS, in
accordance with the guidelines in Sec. 80.127, and for each vessel
selected perform the following:
(i) Obtain a commercial document of general circulation that lists
vessel arrivals and departures, and that includes the port and date of
departure of the vessel, and the port of entry and date of arrival of
the vessel.
(ii) Agree the vessel's departure and arrival locations and dates
from the independent third party and United States importer reports to
the information contained in the commercial document.
(5) Obtain separate listings of all tenders of RFS-FRGAS, and
perform the following:
(i) Agree the volume of tenders from the listings to the gasoline
inventory reconciliation analysis in Sec. 80.128(b).
(ii) Obtain a separate listing of the tenders under this paragraph
(m)(5) where the gasoline is loaded onto a marine vessel. Select a
sample from this listing in accordance with the guidelines in Sec.
80.127, and obtain a commercial document of general circulation that
lists vessel arrivals and departures, and that includes the port and
date of departure and the ports and dates where the gasoline was off
loaded for the selected vessels. Determine and report as a finding the
country where the gasoline was off loaded for each vessel selected.
(6) In order to complete the requirements of this paragraph (m) an
auditor shall:
(i) Be independent of the foreign refiner or importer;
(ii) Be licensed as a Certified Public Accountant in the United
States and a citizen of the United States, or be approved in advance by
EPA based on a demonstration of ability to perform the procedures
required in Sec. Sec. 80.125 through 80.130 and this paragraph (m);
and
(iii) Sign a commitment that contains the provisions specified in
paragraph (f) of this section with regard to activities and documents
relevant to compliance
[[Page 55651]]
with the requirements of Sec. Sec. 80.125 through 80.130 and this
paragraph (m).
(n) Withdrawal or suspension of foreign refiner status. EPA may
withdraw or suspend a foreign refiner's small refinery or small refiner
exemption where--
(1) A foreign refiner fails to meet any requirement of this
section;
(2) A foreign government fails to allow EPA inspections as provided
in paragraph (f)(1) of this section;
(3) A foreign refiner asserts a claim of, or a right to claim,
sovereign immunity in an action to enforce the requirements in this
subpart; or
(4) A foreign refiner fails to pay a civil or criminal penalty that
is not satisfied using the foreign refiner bond specified in paragraph
(g) of this section.
(o) Additional requirements for applications, reports and
certificates. Any application for a small refinery or small refiner
exemption, alternative procedures under paragraph (l) of this section,
any report, certification, or other submission required under this
section shall be--
(1) Submitted in accordance with procedures specified by the
Administrator, including use of any forms that may be specified by the
Administrator.
(2) Be signed by the president or owner of the foreign refiner
company, or by that person's immediate designee, and shall contain the
following declaration: ``I hereby certify: (1) That I have actual
authority to sign on behalf of and to bind [NAME OF FOREIGN REFINER]
with regard to all statements contained herein; (2) that I am aware
that the information contained herein is being Certified, or submitted
to the United States Environmental Protection Agency, under the
requirements of 40 CFR part 80, subpart K, and that the information is
material for determining compliance under these regulations; and (3)
that I have read and understand the information being Certified or
submitted, and this information is true, complete and correct to the
best of my knowledge and belief after I have taken reasonable and
appropriate steps to verify the accuracy thereof. I affirm that I have
read and understand the provisions of 40 CFR part 80, subpart K,
including 40 CFR 80.1165 apply to [NAME OF FOREIGN REFINER]. Pursuant
to Clean Air Act section 113(c) and 18 U.S.C. 1001, the penalty for
furnishing false, incomplete or misleading information in this
certification or submission is a fine of up to $10,000 U.S., and/or
imprisonment for up to five years.''
[FR Doc. 06-7887 Filed 9-21-06; 8:45 am]
BILLING CODE 6560-50-P
![[logo] US EPA](https://webarchive.library.unt.edu/eot2008/20090509061838im_/http://www.epa.gov/epafiles/images/logo_epaseal.gif){kind=logo}