[Federal Register Volume 77, Number 3 (Thursday, January 5, 2012)]
[Rules and Regulations]
[Pages 700-727]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2011-31580]



[[Page 699]]

Vol. 77

Thursday,

No. 3

January 5, 2012

Part V





 Environmental Protection Agency





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40 CFR Part 80





 Regulation of Fuels and Fuel Additives: Identification of Additional 
Qualifying Renewable Fuel Pathways Under the Renewable Fuel Standard 
Program; Direct Final Rule

  Federal Register / Vol. 77 , No. 3 / Thursday, January 5, 2012 / 
Rules and Regulations  

[[Page 700]]


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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 80

[EPA-HQ-OAR-2011-0542; FRL-9502-2]
RIN 2060-AR07


Regulation of Fuels and Fuel Additives: Identification of 
Additional Qualifying Renewable Fuel Pathways Under the Renewable Fuel 
Standard Program

AGENCY: Environmental Protection Agency (EPA).

ACTION: Direct final rule.

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SUMMARY: EPA is issuing a direct final rule identifying additional fuel 
pathways that EPA has determined meet the biomass-based diesel, 
advanced biofuel or cellulosic biofuel lifecycle greenhouse gas (GHG) 
reduction requirements specified in Clean Air Act section 211(o), the 
Renewable Fuel Standard Program, as amended by the Energy Independence 
and Security Act of 2007 (EISA). This direct final rule describes EPA's 
evaluation of biofuels produced from camelina oil, energy cane, giant 
reed, and napiergrass; it also includes an evaluation of renewable 
gasoline and renewable gasoline blendstocks, as well as biodiesel from 
esterification, and clarifies our definition of renewable diesel. We 
are also finalizing two changes to regulation that were proposed on 
July 1, 2011(76 FR 38844). The first change adds ID letters to pathways 
to facilitate references to specific pathways. The second change adds 
``rapeseed'' to the existing pathway for renewable fuel made from 
canola oil.
    This direct final rule adds these pathways to Table in regulation 
as pathways which have been determined to meet one or more of the GHG 
reduction thresholds specified in CAA 211(o), and assigns each pathway 
a corresponding D-Code. It allows producers or importers of fuel 
produced pursuant to these pathways to generate Renewable 
Identification Numbers (RINs), providing that the fuel meets the other 
requirements specified in the RFS regulations to qualify it as 
renewable fuel.

DATES: This rule is effective on March 5, 2012 without further notice, 
unless EPA receives adverse comment or a hearing request by February 6, 
2012. If EPA receives a timely adverse comment or a hearing request, we 
will publish a withdrawal in the Federal Register informing the public 
that the portions of the rule with adverse comment will not take 
effect.

ADDRESSES: Submit your comments, identified by Docket ID No. EPA-HQ-
OAR-2011-0542, by one of the following methods:
     www.regulations.gov: Follow the on-line instructions for 
submitting comments.
     Email: [email protected], Attention Air and Radiation 
Docket ID EPA-HQ-OAR-2011-0542
     Fax: [Insert fax number].
     Mail: Air and Radiation Docket, Docket No. EPA-HQ-OAR-
2011-0542, Environmental Protection Agency, Mailcode: 6406J, 1200 
Pennsylvania Ave. NW., Washington, DC 20460.
     Hand Delivery: EPA Docket Center, EPA/DC, EPA West, Room 
3334, 1301 Constitution Ave. NW., Washington, DC, 20460, Attention Air 
and Radiation Docket, ID No. EPA-HQ-OAR-2011-0542. Such deliveries are 
only accepted during the Docket's normal hours of operation, and 
special arrangements should be made for deliveries of boxed 
information.
    Instructions: Direct your comments to Docket ID No. EPA-HQ-OAR-
2011-0542. EPA's policy is that all comments received will be included 
in the public docket without change and may be made available online at 
www.regulations.gov, including any personal information provided, 
unless the comment includes information claimed to be Confidential 
Business Information (CBI) or other information whose disclosure is 
restricted by statute. Do not submit information that you consider to 
be CBI or otherwise protected through www.regulations.gov or email. The 
www.regulations.gov Web site is an ``anonymous access'' system, which 
means EPA will not know your identity or contact information unless you 
provide it in the body of your comment. If you send an email comment 
directly to EPA without going through www.regulations.gov your email 
address will be automatically captured and included as part of the 
comment that is placed in the public docket and made available on the 
Internet. If you submit an electronic comment, EPA recommends that you 
include your name and other contact information in the body of your 
comment and with any disk or CD-ROM you submit. If EPA cannot read your 
comment due to technical difficulties and cannot contact you for 
clarification, EPA may not be able to consider your comment. Electronic 
files should avoid the use of special characters, any form of 
encryption, and be free of any defects or viruses. For additional 
information about EPA's public docket visit the EPA Docket Center 
homepage at http://www.epa.gov/epahome/dockets.htm.
    Docket: All documents in the docket are listed in the 
www.regulations.gov index. Although listed in the index, some 
information is not publicly available, e.g., CBI or other information 
whose disclosure is restricted by statute. Certain other material, such 
as copyrighted material, will be publicly available only in hard copy. 
Publicly available docket materials are available either electronically 
in www.regulations.gov or in hard copy at the Air and Radiation Docket 
and Information Center, EPA/DC, EPA West, Room 3334, 1301 Constitution 
Ave. NW., Washington, DC. The Public Reading Room is open from 8:30 
a.m. to 4:30 p.m., Monday through Friday, excluding legal holidays. The 
telephone number for the Public Reading Room is (202) 566-1744, and the 
telephone number for the Air Docket is (202) 566-1742).

FOR FURTHER INFORMATION CONTACT: Vincent Camobreco, Office of 
Transportation and Air Quality (MC6401A), Environmental Protection 
Agency, 1200 Pennsylvania Ave. NW., Washington, DC 20460; telephone 
number: (202) 564-9043; fax number: (202) 564-1686; email address: 
[email protected].

SUPPLEMENTARY INFORMATION: 

I. Why is EPA using a direct final rule?

    EPA is publishing this rule without a prior proposed rule because 
we view this as a noncontroversial action. These new pathway 
determinations did not require new agricultural sector modeling and 
involved relatively straightforward analyses that largely relied upon 
work done for the RFS2 final rule. If EPA receives relevant adverse 
comment or a hearing request on a distinct provision of this 
rulemaking, we will publish a timely withdrawal in the Federal Register 
indicating which portion of the rule is being withdrawn. Any distinct 
amendment, paragraph, or section of today's rule not withdrawn will 
become effective on the date set out above.
    In the ``Proposed Rules'' section of today's Federal Register, we 
are publishing a separate document that will serve as the proposed rule 
to update Table 1 of Sec.  80.1426 to add any additional renewable fuel 
production pathways or regulatory provisions which may be withdrawn 
from the direct final rule. We will not institute a second comment 
period on this action. Any parties interested in commenting must do so 
at this time. For further information about commenting on this rule, 
see the ADDRESSES section of this document. We will address all public

[[Page 701]]

comments in any subsequent final rule based on the proposed rule.

II. Does this action apply to me?

    Entities potentially affected by this action are those involved 
with the production, distribution, and sale of transportation fuels, 
including gasoline and diesel fuel or renewable fuels such as ethanol 
and biodiesel. Regulated categories and entities affected by this 
action include:

------------------------------------------------------------------------
                                                          Examples of
                                 NAICS \1\   SIC \2\      potentially
            Category               Codes      Codes        regulated
                                                            entities
------------------------------------------------------------------------
Industry.......................     324110       2911  Petroleum
                                                        Refineries.
Industry.......................     325193       2869  Ethyl alcohol
                                                        manufacturing.
Industry.......................     325199       2869  Other basic
                                                        organic chemical
                                                        manufacturing.
Industry.......................     424690       5169  Chemical and
                                                        allied products
                                                        merchant
                                                        wholesalers.
Industry.......................     424710       5171  Petroleum bulk
                                                        stations and
                                                        terminals.
Industry.......................     424720       5172  Petroleum and
                                                        petroleum
                                                        products
                                                        merchant
                                                        wholesalers.
Industry.......................     454319       5989  Other fuel
                                                        dealers.
------------------------------------------------------------------------
\1\ North American Industry Classification System (NAICS)
\2\ Standard Industrial Classification (SIC) system code.

    This table is not intended to be exhaustive, but rather provides a 
guide for readers regarding entities likely to be regulated by this 
action. This table lists the types of entities that EPA is now aware 
could be potentially regulated by this action. Other types of entities 
not listed in the table could also be regulated. To determine whether 
your entity is regulated by this action, you should carefully examine 
the applicability criteria of Part 80, subparts D, E and F of title 40 
of the Code of Federal Regulations. If you have any question regarding 
applicability of this action to a particular entity, consult the person 
in the preceding FOR FURTHER INFORMATION CONTACT section above.

III. What should I consider as I prepare my comments for EPA?

    A. Submitting information claimed as CBI. Do not submit information 
you claim as CBI to EPA through www.regulations.gov or email. Clearly 
mark the part or all of the information that you claim to be CBI. For 
CBI information in a disk or CD ROM that you mail to EPA, mark the 
outside of the disk or CD ROM as CBI and then identify electronically 
within the disk or CD ROM the specific information that is claimed as 
CBI). In addition to one complete version of the comment that includes 
information claimed as CBI, a copy of the comment that does not contain 
the information claimed as CBI must be submitted for inclusion in the 
public docket. Information so marked will not be disclosed except in 
accordance with procedures set forth in 40 CFR part 2.
    B. Tips for Preparing Your Comments. When submitting comments, 
remember to:
     Identify the rulemaking by docket number and other 
identifying information (subject heading, Federal Register date and 
page number).
     Follow directions--The agency may ask you to respond to 
specific questions or organize comments by referencing a Code of 
Federal Regulations (CFR) part or section number.
     Explain why you agree or disagree; suggest alternatives 
and substitute language for your requested changes.
     Describe any assumptions and provide any technical 
information and/or data that you used.
     If you estimate potential costs or burdens, explain how 
you arrived at your estimate in sufficient detail to allow for it to be 
reproduced.
     Provide specific examples to illustrate your concerns, and 
suggest alternatives.
     Explain your views as clearly as possible, avoiding the 
use of profanity or personal threats.
     Make sure to submit your comments by the comment period 
deadline identified.
    C. Docket Copying Costs. You may be charged a reasonable fee for 
photocopying docket materials, as provided in 40 CFR part 2.

IV. Identification of additional qualifying renewable fuel pathways 
under the renewable fuel standard (RFS) program

    EPA is issuing a direct final rule to identify in the RFS 
regulations additional renewable fuel production pathways that we have 
determined meet the greenhouse gas (GHG) reduction requirements of the 
RFS program. This direct final rule describes EPA's evaluation of:

Camelina Oil (New Feedstock)

     Biodiesel and renewable diesel (including jet fuel and 
heating oil) -- qualifying as biomass-based diesel and advanced biofuel
     Naphtha and liquefied petroleum gas (LPG) -- qualifying as 
advanced biofuel

Energy Cane, Giant Reed, and Napiergrass Cellulosic Biomass (New 
Feedstocks)

     Ethanol, renewable diesel (including renewable jet fuel 
and heating oil), and naphtha -- qualifying as cellulosic biofuel

Renewable Gasoline and Renewable Gasoline Blendstock (New Fuel Types)

     Produced from crop residue, slash, pre-commercial 
thinnings, tree residue, annual cover crops, and cellulosic components 
of separated yard waste, separated food waste, and separated municipal 
solid waste (MSW)
     Using the following processes -- all utilizing natural 
gas, biogas, and/or biomass as the only process energy sources -- 
qualifying as cellulosic biofuel:
    [cir] Thermochemical pyrolysis
    [cir] Thermochemical gasification
    [cir] Biochemical direct fermentation
    [cir] Biochemical fermentation with catalytic upgrading
    [cir] Any other process that uses biogas and/or biomass as the only 
process energy sources

Esterification (New Production Process)

     Process used to produce biodiesel from soy bean oil, oil 
from annual covercrops, algal oil, biogenic waste oils/fats/greases, 
non-food grade corn oil, Canola/rapeseed oil, and camelina oil--
qualifying as biomass-based diesel and advanced biofuel
    This direct final rule adds these pathways to Table 1 to Sec.  
80.1426 and assigns each pathway one or more D-Codes. This final rule 
allows producers or importers of fuel produced under these pathways to 
generate Renewable Identification Numbers (RINs) in accordance with the 
RFS regulations, providing that the fuel meets other definitional 
criteria for renewable fuel.
    Determining whether a fuel pathway satisfies the CAA's lifecycle 
GHG

[[Page 702]]

reduction thresholds for renewable fuels requires a comprehensive 
evaluation of the lifecycle GHG emissions of the renewable fuel as 
compared to the lifecycle GHG emissions of the baseline gasoline or 
diesel fuel that it replaces. As mandated by CAA section 211(o), the 
GHG emissions assessments must evaluate the aggregate quantity of GHG 
emissions (including direct emissions and significant indirect 
emissions such as significant emissions from land use changes) related 
to the full fuel lifecycle, including all stages of fuel and feedstock 
production, distribution, and use by the ultimate consumer.
    In examining the full lifecycle GHG impacts of renewable fuels for 
the RFS program, EPA considers the following:
     Feedstock production--based on agricultural sector models 
that include direct and indirect impacts of feedstock production
     Fuel production--including process energy requirements, 
impacts of any raw materials used in the process, and benefits from co-
products produced.
     Fuel and feedstock distribution--including impacts of 
transporting feedstock from production to use, and transport of the 
final fuel to the consumer.
     Use of the fuel--including combustion emissions from use 
of the fuel in a vehicle.
    Many of the pathways evaluated in this rulemaking rely on a 
comparison to the lifecycle GHG analysis work that was done as part of 
the Renewable Fuel Standard Program (RFS2) Final Rule, published March 
26, 2010. The evaluations here rely on comparisons to the existing 
analysis. EPA plans to periodically review and revise the methodology 
and assumptions associated with calculating the GHG emissions from all 
renewable fuel pathways.

A. Analysis of Lifecycle Greenhouse Gas Emissions for Biodiesel, 
Renewable Diesel, Jet Fuel, Naphtha, and Liquefied Petroleum Gas (LPG) 
Produced From Camelina Oil

1. Feedstock Production
    Camelina sativa (camelina) is an oilseed crop within the flowering 
plant family Brassicaceae that is native to Northern Europe and Central 
Asia. Camelina's suitability to northern climates and low moisture 
requirements allows it to be grown in areas that are unsuitable for 
other major oilseed crops such as soybeans, sunflower, and canola/
rapeseed. Camelina also requires the use of little to no tillage.\1\ 
Compared to many other oilseeds, camelina has a relatively short 
growing season (less than 100 days), and can be grown either as a 
spring annual or in the winter in milder climates. \2\ \3\ Camelina can 
also be used to break the continuous planting cycle of certain grains, 
effectively reducing the disease, insect, and weed pressure in fields 
planted with such grains (like wheat) in the following year.\4\
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    \1\ Putnam, D.H., J.T. Budin, L.A. Field, and W.M. Breene. 1993. 
Camelina: A promising low-input oilseed. p. 314-322. In: J. Janick 
and J.E. Simon (eds.), New crops. Wiley, New York.
    \2\ Moser, B.R., Vaughn, S.F. 2010. Evaluation of Alkyl Esters 
from Camelina Sativa Oil as Biodiesel and as Blend Components in 
Ultra Low Sulfur Diesel Fuel. Bioresource Technology. 101:646-653.
    \3\ McVay, K.A., and P.F. Lamb. 2008. Camelina production in 
Montana. MSU Ext. MT200701AG (revised). http://msuextension.org/publica[not]tions/AgandNaturalResources/MT200701AG.pdf.
    \4\ Putnam et al., 1993.
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    Although camelina has been cultivated in Europe in the past for use 
as food, medicine, and as a source for lamp oil, commercial production 
using modern agricultural techniques has been limited.\5\ In addition 
to being used as a renewable fuel feedstock, small quantities of 
camelina (less than 5% of total U.S. camelina production) are currently 
used as a dietary supplement and in the cosmetics industry. 
Approximately 95% of current US production of camelina has been used 
for testing purposes to evaluate its use as a feedstock to produce 
primarily jet fuel.\6\ The FDA has not approved camelina for food uses, 
although it has approved the inclusion of certain quantities of 
camelina meal in commercial feed.\7\
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    \5\ Lafferty, Ryan M., Charlie Rife and Gus Foster. 2009. Spring 
camelina production guide for the Central High Plains. Blue Sun 
Biodiesel special publication. Blue Sun Agriculture Research & 
Development, Golden, CO. http://www.gobluesun.com/upload/Spring%20Cam-elina%20Production%20Guide%202009.pdf.
    \6\ Telephone conversation with Scott Johnson, Sustainable Oils, 
January 11, 2011.
    \7\ See http://agr.mt.gov/camelina/FDAletter11-09.pdf.
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    Camelina is currently being grown on approximately 50,000 acres of 
land in the U.S., primarily in Montana, eastern Washington, and the 
Dakotas.\8\ USDA does not systematically collect camelina production 
information; therefore data on historical acreage is limited. However, 
available information indicates that camelina has been grown on trial 
plots in 12 U.S. states.\9\
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    \8\ McCormick, Margaret. ``Oral Comments of Targeted Growth, 
Incorporated'' Submitted to the EPA on June 9, 2009.
    \9\ See https://www.camelinacompany.com/Marketing/PressRelease.aspx?Id=25.
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    For the purposes of analyzing the lifecycle GHG emissions of 
camelina, EPA has considered the likely production pattern for camelina 
grown for biofuel production. Given the information currently 
available, camelina is expected to be primarily planted in the U.S. as 
a rotation crop on acres that would otherwise remain fallow during the 
camelina planting. Since substituting fallow land with camelina 
production would not typically displace another crop, EPA does not 
believe new acres would need to be brought into agricultural use to 
increase camelina production. In addition, camelina currently has only 
limited high-value niche markets for uses other than renewable fuels. 
Unlike commodity crops that are tracked by USDA, camelina does not have 
a well-established, internationally traded market that would be 
significantly affected by an increase in the use of camelina to produce 
biofuels. For these reasons, which are described in more detail below, 
EPA has determined that production of camelina-based biofuels is not 
expected to result in significant GHG emissions related to direct land 
use change since it is grown on fallow land. Furthermore, due to the 
limited non-biofuel uses for camelina, production of camelina-based 
biofuels is not expected to have a significant impact on other 
agricultural crop production or commodity markets (either camelina or 
other crop markets) and consequently would not result in significant 
GHG emissions related to indirect land use change. To the extent 
camelina-based biofuel production decreases the demand for alternative 
biofuels, some with higher GHG emissions, this biofuel could have some 
beneficial GHG impact. However, it is uncertain which mix of biofuel 
sources the market will demand so this potential GHG impact cannot be 
quantified.
a. Growing Practices
    Current market conditions indicate that camelina will most likely 
be grown in rotation with wheat on dryland wheat acres replacing a 
period that they would otherwise be left fallow.\10\ In areas with 
lower precipitation, dryland wheat farmers currently leave acres fallow 
once every three to four years to allow additional moisture and 
nutrients to accumulate and to control pests. Current research 
indicates that camelina could be introduced into this rotation in 
certain areas without adversely impacting moisture or nutrient 
accumulation (see Figure 1). Because camelina has shallow roots with 
drought resistant characteristics, the

[[Page 703]]

land can be returned to wheat cultivation the following year with 
moisture and soil nutrients intact quantitatively similar to a fallow 
year.\11\ In addition, camelina uses the same equipment for harvesting 
as wheat; therefore, farmers would not need to invest in new equipment 
to add camelina to the rotation with wheat.\12\
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    \10\ See Shonnard, D. R., Williams, L., & Kalnes, T. N. 2010. 
Camelina-Derived Jet Fuel and Diesel: Sustainable Advanced 
Biodiesel. Environmental Progress & Sustainable Energy, 382-392.
    \11\ See Shonnard et al., 2010; Lafferty et al., 2009.
    \12\ Wheeler, P and F. Guillen-Portal. 2007. Camelina Production 
in Montana: A survey study sponsored by Targeted Growth, Inc. and 
Barkley Ag. Enterprises, LLP (unpublished).
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BILLING CODE 6560-50-P

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[GRAPHIC] [TIFF OMITTED] TR05JA12.006

BILLING CODE 6560-50-C

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b. Land Availability
    USDA estimates that there are approximately 60 million acres of 
wheat in the U.S.\13\ USDA and wheat state cooperative extension 
reports through 2008 indicate that 83% of U.S. wheat production is 
under non-irrigated, dryland conditions. Of the approximately 50 
million non-irrigated acres, at least 45% are estimated to follow a 
wheat/fallow rotation. Thus, approximately 22 million acres are 
potentially suitable for camelina production. However, according to 
industry projections, only about 9 million of these wheat/fallow acres 
have the appropriate climate, soil profile, and market access for 
camelina production.\14\ Therefore, our analysis uses the estimate that 
only 9 million wheat/fallow acres are available for camelina 
production.
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    \13\ 2009 USDA Baseline. See http://www.ers.usda.gov/publications/oce091/.
    \14\ Johnson, S. and McCormick, M., Camelina: an Annual Cover 
Crop Under 40 CFR Part 80 Subpart M, Memorandum, dated November 5, 
2010.
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c. Projected Volumes
    Based on these projections of land availability, EPA estimates that 
at current yields (approximately 800 pounds per acre), approximately 
100 million gallons (MG) of camelina-based renewable fuels could be 
produced with camelina grown in rotation with existing crop acres 
without having direct land use change impacts. Also, since camelina 
will likely be grown on fallow land and thus not displace any other 
crop and since camelina currently does not have other significant 
markets, expanding production and use of camelina for biofuel purposes 
is not likely to have other agricultural market impacts and therefore, 
would not result in any significant indirect land use impacts.\15\ This 
assessment is based on a three year rotation cycle in which only one 
third of the 9 million available acres would be fallow in any given 
year. Yields of camelina are expected to approach the yields of similar 
oilseed crops over the next few years, as experience with growing 
camelina improves cultivation practices and the application of existing 
technologies are more widely adopted.\16\ Yields of 1650 pounds per 
acre have been achieved on test plots, and are in line with expected 
yields of other oilseeds such as canola/rapeseed. Assuming average US 
yields of 1650 pounds per acre,\17\ approximately 200 MG of camelina-
based renewable fuels could be produced on existing wheat/fallow acres. 
Finally, if investment in new seed technology allows yields to increase 
to levels assumed by Shonnard et al (3000 pounds per acre), 
approximately 400 MG of camelina-based renewable fuels could be 
produced on existing acres.\18\ Depending on future crop yields, we 
project that roughly 100 MG to 400 MG of camelina-based biofuels could 
be produced on currently fallow land with no impacts on land use.\19\
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    \15\ Wheeler, P. and Guillen-Portal F. 2007. Camelina Production 
in Montana: A survey study sponsored by Targeted Growth, Inc. and 
Barkley Ag. Enterprises, LLP.
    \16\ See Hunter, J and G. Roth. 2010. Camelina Production and 
Potential in Pennsylvania, Penn State University Agronomy Facts 72. 
See http://pubs.cas.psu.edu/freepubs/pdfs/uc212.pdf.
    \17\ Ehrensing, D.T. and S.O. Guy. 2008. Oilseed Crops--
Camelina. Oregon State Univ. Ext. Serv. EM8953-E. See http://extension.oregonstate.edu/catalog/pdf/em/em8953-e.pdf; McVay & Lamb, 
2008.
    \18\ See Shonnard et al., 2010.
    \19\ This assumes no significant adverse climate impacts on 
world agricultural yields over the analytical timeframe.
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d. Indirect Impacts
    Although wheat can in some cases be grown in rotation with other 
crops such as lentils, flax, peas, garbanzo, and millet, cost and 
benefit analysis indicate that camelina is most likely to be planted on 
soil with lower moisture and nutrients where other rotation crops are 
not viable.\20\ Because expected returns on camelina are relatively 
uncertain, farmers are not expected to grow camelina on land that would 
otherwise be used to grow cash crops with well established prices and 
markets. Instead, farmers are most likely to grow camelina on land that 
would otherwise be left fallow for a season. The opportunity cost of 
growing camelina on this type of land is much lower. As previously 
discussed, this type of land represents the 9 million acres currently 
being targeted for camelina production. Current returns on camelina are 
relatively low ($13.24 per acre), given average yields of approximately 
800 pounds per acre and the current contract price of $0.145 per 
pound.\21\ See Table 1. For comparison purposes, the USDA projections 
for wheat returns are between $88-$105 per acre between 2010 and 2020. 
Over time, advancements in seed technology, improvements in planting 
and harvesting techniques, and higher input usage could significantly 
increase future camelina yields and returns.
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    \20\ See Lafferty et al., 2009; Shonnard et al., 2010; 
Sustainable Oils Memo dated November 5, 2010,
    \21\ Wheeler & Guillen-Portal, 2007.
    \22\ See Sustainable Oils Memo dated November 5, 2010,
    \23\ Based on yields technically feasible. See McVey and Lamb, 
2008; Ehrenson & Guy, 2008.
    \24\ Adapted from Shonnard et al, 2010.

                                       Table 1--Camelina Costs and Returns
----------------------------------------------------------------------------------------------------------------
             Inputs                      Rates        2010 Camelina \22\  2022 Camelina \23\  2030 Camelina \24\
----------------------------------------------------------------------------------------------------------------
Herbicides:
    Glysophate (Fall)...........  16 oz. ( $0.39/oz)  $7.00.............  $7.00.............  $7.00.
    Glysophate (Spring).........  16 oz. ( $0.39/oz)  $7.00.............  $7.00.............  $7.00.
    Post........................  12 oz ( $0.67/oz).  $8.00.............  $8.00.............  $8.00.
Seed:
    Camelina seed...............  $1.44/lb..........  $5.76.............  $7.20.............  $7.20
                                                      (4 lbs/acre)......  (5 lbs/acre)......  (5 lbs/acre).
Fertilizer:
    Nitrogen Fertilizer.........  $1/pd.............  $25.00............  $40.00............  $75
                                                      (25 lb/acre)......  (40 lb/acre)......  (75 lbs/acre).
    Phosphate Fertilizer........  $1/pd.............  $15.00............  $15.00............  $15
                                                      (15 lb/acre)......  (15 lb/acre)......  (15 lb/acre).
                                                     -----------------------------------------------------------
        Sub-Total...............  ..................  $67.76............  $84.20............  $119.20.
                                                     -----------------------------------------------------------
Logistics:
    Planting Trip...............  ..................  $10.00............  $10.00............  $10.00.
    Harvest & Hauling...........  ..................  $25.00............  $25.00............  $25.00.
                                                     -----------------------------------------------------------

[[Page 706]]

 
        Total Cost..............  ..................  $102.76...........  $119.20...........  $154.20.
                                                     ===========================================================
Yields..........................  lb/acre...........  800...............  1650..............  3000.
Price...........................  $/lb..............  $0.145............  $0.120............  $0.090.
    Total Revenue at avg prod/    ..................  $116.00...........  $198..............  $270.
     pricing.
    Returns.....................  ..................  $13.24............  $78.80............  $115.80.
----------------------------------------------------------------------------------------------------------------

    While replacing the fallow period in a wheat rotation is expected 
to be the primary means by which the majority of all domestic camelina 
is commercially harvested in the short- to medium- term, in the long 
term camelina may expand to other regions and growing methods.\25\ For 
example, if camelina production expanded beyond the 9 million acres 
assumed available from wheat fallow land, it could impact other crops. 
However, as discussed above this is not likely to happen in the near 
term due to uncertainties in camelina financial returns. Camelina 
production could also occur in areas where wheat is not commonly grown. 
For example, testing of camelina production has occurred in Florida in 
rotation with kanaf, peanuts, cotton, and corn. However, only 200 acres 
of camelina were harvested in 2010 in Florida. While Florida acres of 
camelina are expected to be higher in 2011, very little research has 
been done on growing camelina in Florida. For example, little is known 
about potential seedling disease in Florida or how camelina may be 
affected differently than in colder climates.\26\ Therefore, camelina 
grown outside of a wheat fallow situation was not considered as part of 
this analysis.
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    \25\ See Sustainable Oils Memo dated November 5, 2010 for a map 
of the regions of the country where camelina is likely to be grown 
in wheat fallow conditions.
    \26\ Wright & Marois, 2011.
---------------------------------------------------------------------------

    The determination in this final rule is based on our projection 
that camelina is likely to be produced on what would otherwise be 
fallow land. However, the rule applies to all camelina regardless of 
where it is grown. EPA does not expect that significant camelina would 
be grown on non-fallow land, and small quantities that may be grown 
elsewhere and used for biofuel production will not significantly impact 
our analysis.
    Furthermore, although we expect most camelina used as a feedstock 
for renewable fuel production that would qualify in the RFS program 
would be grown in the U.S., today's rule would apply to qualifying 
renewable fuel made from camelina grown in any country. For the same 
reasons that pertain to U.S. production of camelina, we expect that 
camelina grown in other countries would also be produced on land that 
would otherwise be fallow and would therefore have no significant land 
use change impacts. The renewable biomass provisions under the Energy 
Independence and Security Act would prohibit direct land conversion 
into new agricultural land for camelina production for biofuel 
internationally. Additionally, any camelina production on existing 
cropland internationally would not be expected to have land use impacts 
beyond what was considered for international soybean production 
(soybean oil is the expected major feedstock source for U.S. biodiesel 
fuel production and thus the feedstock of reference for the camelina 
evaluation). Because of these factors along with the small amounts of 
fuel potentially coming from other countries, we believe that 
incorporating fuels produced in other countries will not impact our 
threshold analysis for camelina-based biofuels.
e. Crop Inputs
    For comparison purposes, Table 2 shows the inputs required for 
camelina production compared to the FASOM agricultural input 
assumptions for soybeans. Since yields and input assumptions vary by 
region, a range of values for soybean production are shown in Table 2. 
The camelina input values in Table 2 represent average values, camelina 
input values will also vary by region, however, less data is available 
comparing actual practices by region due to limited camelina 
production. More information on camelina inputs is available in 
materials provided in the docket.
[GRAPHIC] [TIFF OMITTED] TR05JA12.007

    Regarding crop inputs per acre, it should be noted that camelina 
has a higher percentage of oil per pound of seed than soybeans. 
Soybeans are approximately 18% oil, therefore crushing one pound of 
soybeans yields

[[Page 707]]

0.18 pounds of oil. In comparison, camelina is approximately 36% oil, 
therefore crushing one pound of camelina yields 0.36 pounds of oil. The 
difference in oil yield is taken into account when calculating the 
emissions per mmBTU included in Table 2. As shown in Table 2, GHG 
emissions from feedstock production for camelina and soybeans are 
relatively similar when factoring in variations in oil yields per acre 
and fertilizer, herbicide, pesticide, and petroleum use.
    In summary, EPA concludes that the agricultural inputs for growing 
camelina are similar to those for growing soy beans, direct land use 
impact is expected to be negligible due to planting on land that would 
be otherwise fallow, and the limited production and use of camelina 
indicates no expected impacts on other crops and therefore no indirect 
land use impacts.
f. Crushing and Oil Extraction
    We also looked at the seed crushing and oil extraction process and 
compared the lifecycle GHG emissions from this stage for soybean oil 
and camelina oil. As discussed above, camelina seeds produce more oil 
per pound than soybeans. As a result, the lifecycle GHG emissions 
associated with crushing and oil extraction are lower for camelina than 
soybeans, per pound of vegetable oil produced. Table 3 summarizes data 
on inputs, outputs and estimated lifecycle GHG emissions from crushing 
and oil extraction. The data on soybean crushing comes from the RFS2 
final rule, based on a process model developed by USDA-ARS.\27\ The 
data on camelina crushing is from Shonnard et al. (2010).
---------------------------------------------------------------------------

    \27\ A. Pradhan, D.S. Shrestha, A. McAloon, W. Yee, M. Haas, 
J.A. Duffield, H. Shapouri, September 2009, ``Energy Life-Cycle 
Assessment of Soybean Biodiesel'', United States Department of 
Agriculture, Office of the Chief Economist, Office of Energy Policy 
and New Uses, Agricultural Economic Report Number 845.

                     Table 3--Comparison of Camelina and Soybean Crushing and Oil Extraction
----------------------------------------------------------------------------------------------------------------
                Item                       Soybeans           Camelina                      Units
----------------------------------------------------------------------------------------------------------------
Material Inputs:
    Beans or Seeds..................               5.38               2.90  Lbs.
Energy Inputs:
    Electricity.....................             374                 47     Btu.
    Natural Gas & Steam.............           1,912                780     Btu.
Outputs:
    Refined vegetable oil...........               1.00               1.00  Lbs.
    Meal............................               4.08               1.85  Lbs.
    GHG Emissions...................             213                 64     gCO2e/lb refined oil.
----------------------------------------------------------------------------------------------------------------

2. Feedstock Distribution, Fuel Distribution, and Fuel Use
    For this analysis, EPA projects that the feedstock distribution 
emissions will be the same for camelina and soybean oil. To the extent 
that camelina contains more oil per pound of seed, as discussed above, 
the energy needed to move the camelina would be lower than soybeans per 
gallon of fuel produced. To the extent that camelina is grown on more 
disperse fallow land than soybean and would need to be transported 
further, the energy needed to move the camelina could be higher than 
soybean. Based on this, we believe the assumption to use the same 
distribution impacts for camelina as soybean is a reasonable estimate 
of the GHG emissions from camelina feedstock distribution. In addition, 
the final fuel produced from camelina is also expected to be similar in 
composition to the comparable fuel produced from soybeans, therefore we 
are assuming GHG emissions from the distribution and use of fuels made 
from camelina will be the same as emissions of fuel produced from 
soybeans.
3. Fuel Production
    There are two main fuel production processes used to convert 
camelina oil into fuel. The trans-esterification process produces 
biodiesel and a glycerin co-product. The hydrotreating process can be 
configured to produce renewable diesel either primarily as diesel fuel 
(including heating oil) or primarily as jet fuel. Possible additional 
products from hydrotreating include naphtha, LPG, and propane. Both 
processes and the fuels produced are described in the following 
sections. Both processes use camelina oil as a feedstock and camelina 
crushing is also included in the analysis.
a. Biodiesel
    For this analysis, we assumed the same biodiesel production 
facility designs and conversion efficiencies as modeled for biodiesel 
produced from soybean oil and canola/rapeseed oil. Camelina oil 
biodiesel is produced using the same methods as soybean oil biodiesel, 
therefore plant designs are assumed to not significantly differ between 
fuels made from these feedstocks. As was the case for soybean oil 
biodiesel, we have not projected in our assessment of camelina oil 
biodiesel any significant improvements in plant technology. 
Unanticipated energy saving improvements would further improve GHG 
performance of the fuel pathway.
    The glycerin produced from camelina biodiesel production is 
equivalent to the glycerin produced from the existing biodiesel 
pathways (e.g., based on soy oil) that were analyzed as part of the 
RFS2 final rule. Therefore the same co-product credit would apply to 
glycerin from camelina biodiesel as glycerin produced in the biodiesel 
pathways modeled for the RFS2 final rule. The assumption is that the 
GHG reductions associated with the replacement of residual oil with 
glycerin on an energy equivalent basis represents an appropriate 
midrange co-product credit of biodiesel produced glycerin.
    As part of our RFS2 proposal, we assumed the glycerin would have no 
value and would effectively receive no co-product credits in the soy 
biodiesel pathway. We received numerous comments, however, stating that 
the glycerin would have a beneficial use and should generate co-product 
benefits. Therefore, the biodiesel glycerin co-product determination 
made as part of the RFS2 final rule took into consideration the 
possible range of co-product credit results. The actual co-product 
benefit will be based on what products are replaced by the glycerin and 
what new uses develop for the co-product glycerin. The total amount of 
glycerin produced from the biodiesel industry will actually be used 
across a number of different markets with different GHG impacts. This 
could include for example, replacing

[[Page 708]]

petroleum glycerin, replacing fuel products (residual oil, diesel fuel, 
natural gas, etc.), or being used in new products that don't have a 
direct replacement, but may nevertheless have indirect effects on the 
extent to which existing competing products are used. The more 
immediate GHG reduction credits from glycerin co-product use will 
likely range from fairly high reduction credits when petroleum glycerin 
is replaced to lower reduction credits if it is used in new markets 
that have no direct replacement product, and therefore no replaced 
emissions.
    EPA does not have sufficient information (and received no relevant 
comments as part of the RFS2 rule) on which to allocate glycerin use 
across the range of likely uses. Therefore, EPA believes that the 
approach used in RFS2 of picking a surrogate use for modeling purposes 
in the mid-range of likely glycerin uses, and the GHG emissions results 
tied to such use, is reasonable. The replacement of an energy 
equivalent amount of residual oil is a simplifying assumption 
determined by EPA to reflect the mid-range of possible glycerin uses in 
terms of GHG credits. EPA believes that it is appropriately 
representative of GHG reduction credit across the possible range 
without necessarily biasing the results toward high or low GHG impact. 
Given the fundamental difficulty of predicting possible glycerin uses 
and impacts of those uses many years into the future under evolving 
market conditions, EPA believes it is reasonable to use the more 
simplified approach to calculating co-product GHG benefit associated 
with glycerin production.
    Given the fact that GHG emissions from camelina-based biodiesel 
would be similar to the GHG emissions from soybean- based biodiesel at 
all stages of the lifecycle but would not result in land use change as 
was the case for soy oil used as a feedstock, we believe biodiesel from 
camelina oil will also meet the 50% GHG emissions reduction threshold 
to qualify as a biomass based diesel and an advanced fuel. Therefore, 
EPA is including biodiesel produced from camelina oil under the same 
pathways for which biodiesel made from soybean oil qualifies under the 
RFS2 final rule.
b. Renewable Diesel (Including Jet Fuel and Heating Oil), Naphtha, and 
LPG
    The same feedstocks currently used for biodiesel production can 
also be used in a hydrotreating process to produce a slate of products, 
including diesel fuel, heating oil (defined as No. 1 or No. 2 diesel), 
jet fuel, naphtha, LPG, and propane. Since the term renewable diesel is 
defined to include the products diesel fuel, jet fuel and heating oil, 
the following discussion uses the term renewable diesel to also include 
diesel fuel, jet fuel and heating oil. The yield of renewable diesel is 
relatively insensitive to feedstock source.\28\ While any propane 
produced as part of the hydrotreating process will most likely be 
combusted within the facility for process energy, the other co-products 
that can be produced (i.e., renewable diesel, naphtha, LPG) are higher 
value products that could be used as transportation fuels or, in the 
case of naphtha, a blendstock for production of transportation fuel. 
The hydrotreating process maximized for producing a diesel fuel 
replacement as the primary fuel product requires more overall material 
and energy inputs than transesterification to produce biodiesel, but it 
also results in a greater amount of other valuable co-products as 
listed above. The hydrotreating process can also be maximized for jet 
fuel production which requires even more process energy than the 
process optimized for producing a diesel fuel replacement, and produces 
a greater amount of co-products per barrel of feedstock, especially 
naphtha.
---------------------------------------------------------------------------

    \28\ Kalnes, T., N., McCall, M., M., Shonnard, D., R., 2010. 
Renewable Diesel and Jet-Fuel Production from Fats and Oils. 
Thermochemical Conversion of Biomass to Liquid Fuels and Chemicals, 
Chapter 18, p. 475.
---------------------------------------------------------------------------

    Producers of renewable diesel from camelina have expressed interest 
in generating RINs under the RFS2 program for the slate of products 
resulting from the hydrotreating process. Our lifecycle analysis 
accounts for the various uses of the co-products. There are two main 
approaches to accounting for the co-products produced, the allocation 
approach, and the displacement approach. In the allocation approach all 
the emissions from the hydrotreating process are allocated across all 
the different co-products. There are a number of ways to do this but 
since the main use of the co-products would be to generate RINs as a 
fuel product we allocate based on the energy content of the co-products 
produced. In this case, emissions from the process would be allocated 
equally to all the Btus produced. Therefore, on a per Btu basis all co-
products would have the same emissions. The displacement approach would 
attribute all of the emissions of the hydrotreating process to one main 
product and then account for the emission reductions from the other co-
products displacing alternative product production. For example, if the 
hydrotreating process is configured to maximize diesel fuel replacement 
production, all of the emissions from the process would be attributed 
to diesel fuel, but we would then assume the other co-products were 
displacing alternative products, for example, naphtha would displace 
gasoline, LPG would displace natural gas, etc. This assumes the other 
alternative products are not produced or used, so we would subtract the 
emissions of gasoline production and use, natural gas production and 
use, etc. This would show up as a GHG emission credit associated with 
the production of diesel fuel replacement.
    To account for the case where RINs are generated for the jet fuel, 
naphtha and LPG in addition to the diesel replacement fuel produced, we 
would not give the diesel replacement fuel a displacement credit for 
these co-products. Instead, the lifecycle GHG emissions from the fuel 
production processes would be allocated to each of the RIN-generating 
products on an energy content basis. This has the effect of tending to 
increase the fuel production lifecycle GHG emissions associated with 
the diesel replacement fuel because there are less co-product 
displacement credits to assign than would be the case if RINs were not 
generated for the co-products.\29\ On the other hand, the upstream 
lifecycle GHG emissions associated with producing and transporting the 
plant oil feedstocks will be distributed over a larger group of RIN-
generating products. Assuming each product (except propane) produced 
via the camelina oil hydrotreating process will generate RINs results 
in higher lifecycle GHG emissions for diesel fuel replacement as 
compared to the case where the co-products are not used to generate 
RINs. This general principle is also true when the hydrotreating 
process is maximized for jet fuel production. As a result, the worst 
GHG performance (i.e., greatest lifecycle GHG emissions) for diesel 
replacement fuel and jet fuel produced from camelina oil via 
hydrotreating will occur when all of the co-products are RIN-generating 
(we assume propane will be used for process energy). Thus, if these 
fuels meet the 50% GHG reduction threshold for biomass based diesel or 
advanced biofuel when co-products are RIN-generating, they will

[[Page 709]]

also do so in the case when RINs are not generated for co-products.
---------------------------------------------------------------------------

    \29\ For a similar discussion see page 46 of Stratton, R.W., 
Wong, H.M., Hileman, J.I. 2010. Lifecycle Greenhouse Gas Emissions 
from Alternative Jet Fuels. PARTNER Project 28 report. Version 1.1. 
PARTNER-COE-2010-001. June 2010, http://web.mit.edu/aeroastro/partner/reports/proj28/partner-proj28-2010-001.pdf.
---------------------------------------------------------------------------

    We have evaluated information about the lifecycle GHG emissions 
associated with the hydrotreating process which can be maximized for 
jet fuel or diesel replacement fuel production. Our evaluation 
considers information published in peer-reviewed journal articles and 
publicly available literature (Kalnes et al, 2010, Pearlson, M., N., 
2011,\30\ Stratton et al., 2010, Huo et al., 2008).\31\ Our analysis of 
GHG emissions from the hydrotreating process is based on the mass and 
energy balance data in Pearlson (2011) which analyzes a hydrotreating 
process maximized for diesel replacement fuel production and a 
hydrotreating process maximized for jet fuel production.\32\ This data 
is summarized in Table 4.
---------------------------------------------------------------------------

    \30\ Pearlson, M., N. 2011. A Techno-Economic and Environmental 
Assessment of Hydroprocessed Renewable Distillate Fuels.
    \31\ Huo, H., Wang., M., Bloyd, C., Putsche, V., 2008. Life-
Cycle Assessment of Energy and Greenhouse Gas Effects of Soybean-
Derived Biodiesel and Renewable Fuels. Argonne National Laboratory. 
Energy Systems Division. ANL/ESD/08-2. March 12, 2008.
    \32\ We have also considered data submitted by companies 
involved in the hydrotreating industry which is claimed as 
confidential business information (CBI). The conclusions using the 
CBI data are consistent with the analysis presented here.
    \33\ Based on Pearlson (2011), Table 3.1 and Table 3.2.

     Table 4--Hydrotreating Processes to Convert Camelina Oil Into Diesel Replacement Fuel and Jet Fuel\33\
----------------------------------------------------------------------------------------------------------------
                                            Maximized for
                                             diesel fuel     Maximized for jet      Units (per gallon of fuel
                                              production      fuel production               produced)
----------------------------------------------------------------------------------------------------------------
Inputs:
    Refined camelina oil................               9.56              12.84  Lbs.
    Hydrogen............................               0.04               0.08  Lbs.
    Electricity.........................             652                865     Btu.
    Natural Gas.........................          23,247             38,519     Btu.
Outputs:
    Diesel Fuel.........................         123,136             55,845     Btu.
    Jet fuel............................          23,197            118,669     Btu.
    Naphtha.............................           3,306             17,042     Btu.
    LPG.................................           3,084             15,528     Btu.
    Propane.............................           7,454              9,881     Btu.
----------------------------------------------------------------------------------------------------------------

    Table 5 compares lifecycle GHG emissions from oil extraction and 
fuel production for soybean oil biodiesel and for camelina-based diesel 
and jet fuel. The lifecycle GHG estimates for camelina oil diesel and 
jet fuel are based on the input/output data summarized in Table 3 (for 
oil extraction) and Table 4 (for fuel production). We assume that the 
propane co-product does not generate RINs; instead, it is used for 
process energy displacing natural gas. We also assume that the naphtha 
is used as blendstock for production of transportation fuel to generate 
RINs. In this case we assume that RINs are generated for the use of LPG 
in a way that meets the EISA definition of transportation fuel, for 
example it could be used in a nonroad vehicle. The lifecycle GHG 
results in Table 5 represent the worst case scenario (i.e., highest GHG 
emissions) because all of the eligible co-products are used to generate 
RINs. This is because, as discussed above, lifecycle GHG emissions per 
Btu of diesel or jet fuel would be lower if the naphtha or LPG is not 
used to generate RINs and is instead used for process energy displacing 
fossil fuel such as natural gas. Supporting information for the values 
in Table 5, including key assumptions and data, is provided through the 
docket.

                                          Table 5--Fuel Production Lifecycle GHG Emissions (kgCO2e/mmBtu) \34\
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                              RIN-Generating
             Feedstock                Production process         products          Other co-products    Oil extraction     Processing         Total
--------------------------------------------------------------------------------------------------------------------------------------------------------
Soybean Oil.......................  Trans-Esterification.  Biodiesel...........  Glycerin............               14              (1)               13
Camelina Oil......................  Trans-Esterification.  Biodiesel...........  Glycerin............                4              (1)                3
Camelina Oil......................  Hydrotreating          Diesel..............  Propane.............                4                8               12
                                     Maximized for Diesel. Jet Fuel............
                                                           Naphtha.............
                                                           LPG.................
 
Camelina Oil......................  Hydrotreating          Jet Fuel............  Propane.............                4               11               14
                                     Maximized for Jet     Diesel..............
                                     Fuel.                 Naphtha.............
                                                           LPG.
--------------------------------------------------------------------------------------------------------------------------------------------------------

    As discussed above, for a process that produces more than one RIN-
generating output (e.g., the hydrotreating process summarized in Table 
5 which produces diesel replacement fuel, jet fuel, and naphtha) we 
allocate lifecycle GHG emissions to the RIN generating products on an 
energy equivalent basis. We then normalize the allocated lifecycle GHG 
emissions per mmBtu of each fuel product. Therefore, each RIN-
generating product from the same process will be assigned equal 
lifecycle GHG emissions per mmBtu from fuel processing. For example, 
based on the

[[Page 710]]

lifecycle GHG estimates in Table 5 for the hydrotreating process 
maximized to produce jet fuel, the jet fuel and the naphtha both have 
lifecycle GHG emissions of 14 kgCO2e/mmBtu. For the same 
reasons, the lifecycle GHG emissions from the jet fuel and naphtha will 
stay equivalent if we consider upstream GHG emissions, such as 
emissions associated with camelina cultivation and harvesting. 
Lifecycle GHG emissions from fuel distribution and use could be 
somewhat different for the jet fuel and naphtha, but since these stages 
produce a relatively small share of the emissions related to the full 
fuel lifecycle, the overall difference will be quite small.
---------------------------------------------------------------------------

    \34\ Lifecycle GHG emissions are normalized per mmBtu of RIN-
generating fuel produced. Totals may not be the sum of the rows due 
to rounding error. Parentheses indicate negative numbers. Process 
emissions for biodiesel production are negative because they include 
the glycerin offset credit.
---------------------------------------------------------------------------

    Given that GHG emissions from camelina oil would be similar to the 
GHG emissions from soybean oil at all stages of the lifecycle but would 
not result in land use change emissions (soy oil feedstock did have a 
significant land use change impact but still met a 50% GHG reduction 
threshold), and considering differences in process emissions between 
soybean biodiesel and camelina-based renewable diesel, we conclude that 
renewable diesel from camelina oil will also meet the 50% GHG emissions 
reduction threshold to qualify as biomass based diesel and advanced 
fuel. Although some of the potential configurations result in fuel 
production GHG emissions that are higher than fuel production GHG 
emissions for soybean oil biodiesel, land use change emissions account 
for approximately 80% of the soybean oil to biodiesel lifecycle GHGs. 
Since camelina is assumed not to have land use change emissions, our 
analysis shows that camelina renewable diesel will qualify for advanced 
renewable fuel and biomass-based diesel RINs even for the cases with 
the highest lifecycle GHGs (e.g., when all of the co-products are used 
to generate RINs.) Because the lifecycle GHG emissions for RIN-
generating co-products are very similar, we can also conclude naphtha 
and LPG produced from camelina oil will also meet the 50% GHG emissions 
reduction threshold. If the facility does not actually generate RINs 
for one or more of these co-products, we estimate that the lifecycle 
GHG emissions related to the RIN-generating products would be lower, 
thus renewable diesel (which includes diesel fuel, jet fuel, and 
heating oil) from camelina would still meet the 50% emission reduction 
threshold.
4. Summary
    Current information suggests that camelina has limited niche 
markets and will be produced on land that would otherwise remain 
fallow. Therefore, increased production of camelina-based renewable 
fuel is not expected to result in significant land use change 
emissions. For the purposes of this analysis, EPA is projecting there 
will be no land use emissions associated with camelina production for 
use as a renewable fuel feedstock.
    However, while production of camelina on acres that would otherwise 
remain fallow is expected to be the primary means by which the majority 
of all camelina is commercially harvested in the short- to medium- 
term, in the long term camelina may expand to other growing methods and 
lands if demand increases substantially beyond what EPA is currently 
predicting. While the impacts are uncertain, there are some indications 
demand could increase significantly. For example, camelina is included 
under USDA's Biomass Crop Assistance Program (BCAP) and there is 
growing support for the use of camelina oil in producing drop-in 
alternative aviation fuels. EPA plans to monitor the expansion of 
camelina production to verify whether camelina is primarily grown on 
existing acres once camelina is produced at larger-scale volumes. 
Similarly, we will consider market impacts if alternative uses for 
camelina expand significantly beyond what was described in the above 
analysis. Just as EPA plans to periodically review and revise the 
methodology and assumptions associated with calculating the GHG 
emissions from all renewable fuel feedstocks, EPA expects to review and 
revise as necessary the analysis of camelina in the future.
    Taking into account the assumption of no land use change emissions 
when camelina is used to produce renewable fuel, and considering that 
other sources of GHG emissions related to camelina biodiesel or 
renewable diesel production have comparable GHG emissions to biodiesel 
from soybean oil, we have determined that camelina-based biodiesel and 
renewable diesel should be treated in the same manner as soy-based 
biodiesel and renewable diesel in qualifying as biomass-based diesel 
and advanced biofuel for purposes of RIN generation, since the GHG 
emission performance of the camelina-based fuels will be at least as 
good and in some respects better than that modeled for fuels made from 
soybean oil. EPA found as part of the Renewable Fuel Standard final 
rulemaking that soybean biodiesel resulted in a 57% reduction in GHG 
emissions compared to the baseline petroleum diesel fuel. Furthermore, 
approximately 80% of the lifecycle impacts from soybean biodiesel were 
from land use change emissions which are assumed to be not significant 
for the camelina pathway considered. Thus, EPA is including camelina 
oil as a potential feedstock under the same biodiesel and renewable 
diesel (which includes diesel fuel, jet fuel, and heating oil) pathways 
for which soybean oil currently qualifies. We are also including a 
pathway for naphtha and LPG produced from camelina oil through 
hydrotreating. This is based on the fact that our analysis shows that 
even when all of the co-products are used to generate RINs the 
lifecycle GHG emissions for RIN-generating co-products including diesel 
replacement fuel, jet fuel, naphtha and LPG produced from camelina oil 
will all meet the 50% GHG emissions reduction threshold.
    We are also clarifying that two existing pathways for RIN 
generation in the RFS regulations that list ``renewable diesel'' as a 
fuel product produced through a hydrotreating process include jet fuel. 
This applies to two pathways in Table 1 to Sec.  80.1426 of the RFS 
regulations which both list renewable diesel made from soy bean oil, 
oil from annual covercrops, algal oil, biogenic waste oils/fats/
greases, or non-food grade corn oil using hydrotreating as a process. 
If parties produce jet fuel from the hydrotreating process and co-
process renewable biomass and petroleum they can generate advanced 
biofuel RINs (D code 5) for the jet fuel produced. If they do not co-
process renewable biomass and petroleum they can generate biomass-based 
diesel RINs (D code 4) for the jet fuel produced.
    Sec.  80.1401 of the RFS regulations currently defines non-ester 
renewable diesel as a fuel that is not a mono-alkyl ester and which can 
be used in an engine designed to operate on conventional diesel fuel or 
be heating oil or jet fuel. The reference to jet fuel in this 
definition was added by direct final rule dated May 10, 2010. Table 1 
to Sec.  80.1426 identifies approved fuel pathways by fuel type, 
feedstock source and fuel production processes. The table, which was 
largely adopted as part of the March 26, 2010 RFS2 final rule, 
identifies jet fuel and renewable diesel as separate fuel types. 
Accordingly, in light of the revised definition of renewable diesel 
enacted after the RFS2 rule, there is ambiguity regarding the extent to 
which references in Table 1 to ``renewable diesel'' include jet fuel.
    The original lifecycle analysis for the renewable diesel from 
hydrotreating pathways listed in Table 1 to Sec.  80.1426 was not based 
on producing jet fuel but rather other transportation diesel fuel 
products, namely a diesel fuel replacement. As discussed above, the

[[Page 711]]

hydrotreating process can produce a mix of products including jet fuel, 
diesel, naphtha, LPG and propane. Also, as discussed, there are 
differences in the process configured for maximum jet fuel production 
vs. the process maximized for diesel fuel production and the lifecycle 
results vary depending on what approach is used to consider co-products 
(i.e., the allocation or displacement approach).
    In cases where there are no pathways for generating RINs for the 
co-products from the hydrotreating process it would be appropriate to 
use the displacement method for capturing the credits of co-products 
produced. This is the case for most of the original feedstocks included 
in Table 1 to Sec.  80.1426.\35\ As was discussed previously, if the 
displacement approach is used when jet fuel is the primary product 
produced it results in lower emissions then the production maximized 
for diesel fuel production. Therefore, since the hydrotreating process 
maximized for diesel fuel meets the 50% lifecycle GHG threshold for the 
feedstocks in question, the process maximized for jet fuel would also 
qualify.
---------------------------------------------------------------------------

    \35\ The exception is naphtha produced from waste categories, 
but these would pass the lifecycle thresholds regardless of the 
allocation approach used given their low feedstock GHG impacts.
---------------------------------------------------------------------------

    Thus, we are interpreting the references to ``renewable diesel'' in 
Table 1 to include jet fuel, consistent with our regulatory definition 
of ``non-ester renewable diesel,'' since doing so clarifies the 
existing regulations while ensuring that Table 1 to Sec.  80.1426 
appropriately identifies fuel pathways that meet the GHG reduction 
thresholds associated with each pathway.
    We note that although the definition of renewable diesel includes 
jet fuel and heating oil, we have also listed in Table 1 of section 
80.1426 of the RFS2 regulations jet fuel and heating oil as specific 
co-products in addition to listing renewable diesel to assure clarity. 
This clarification also pertains to all the feedstocks already included 
in Table 1 for renewable diesel.

B. Lifecycle Greenhouse Gas Emissions Analysis for Ethanol, Diesel, Jet 
Fuel, Heating Oil, and Naphtha Produced From Energy Cane, Giant Reed, 
and Napiergrass

    For this rulemaking, EPA considered the lifecycle GHG impacts of 
three new types of high-yielding perennial grasses similar in 
cellulosic composition to switchgrass and comparable in status as an 
emerging energy crop. Energy cane (related to sugarcane), giant reed 
(Arundo donax), and napiergrass (pennisetum purpureum), also known as 
elephant grass. In the proposed and final RFS2 rule, EPA analyzed the 
lifecycle GHG impacts of producing and using cellulosic ethanol and 
cellulosic Fischer-Tropsch diesel from switchgrass. The midpoint of the 
range of switchgrass results showed a 110% GHG reduction (range of 
102%-117%) for cellulosic ethanol (biochemical process), a 72% (range 
of -64% to -79%) reduction for cellulosic ethanol (thermochemical 
process), and a 71% (range of -62% to -77%) reduction for cellulosic 
diesel (F-T process) compared to the petroleum baseline. In the RFS2 
final rule, we indicated that some feedstock sources can be determined 
to be similar enough to those modeled that the modeled results could 
reasonably be extended to these similar feedstock types. For instance, 
information on miscanthus indicated that this perennial grass will 
yield more feedstock per acre than the modeled switchgrass feedstock 
without additional inputs with GHG implications (such as fertilizer). 
Therefore in the final rule EPA concluded that since biofuel made from 
the cellulosic biomass in switchgrass was found to satisfy the 60% GHG 
reduction threshold for cellulosic biofuel, biofuel produced form the 
cellulosic biomass in miscanthus would also comply. In the final rule 
we included cellulosic biomass from switchgrass and miscanthus as 
eligible feedstocks for the cellulosic biofuel pathways included in 
Table 1 to Sec.  80.1426.
    We did not include other perennial grasses such as energy cane, 
giant reed, or napiergrass as feedstocks for the cellulosic biofuel 
pathways in Table 1 at that time, since we did not have sufficient time 
to adequately consider them. Based in part on additional information 
received through the petition process for EPA approval of energy cane, 
giant reed, and napiergrass pathways, EPA has evaluated these 
feedstocks and is now including the cellulose, hemicelluloses and 
lignin portions of renewable biomass from energy cane, giant reed, and 
napiergrass in Table 1 to Sec.  80.1426 as approved feedstocks for 
cellulosic biofuel pathways.
    As described in detail in the following sections of this preamble, 
because of the similarity of these feedstocks to switchgrass and 
miscanthus, EPA believes that new agricultural sector modeling is not 
needed to analyze them. We have instead relied upon the switchgrass 
analysis to assess the relative GHG impacts of biofuel produced from 
energy cane, giant reed, and napiergrass. As with the switchgrass 
analysis, we have attributed all land use impacts and resource inputs 
from use of these feedstocks to the portion of the fuel produced that 
is derived from the cellulosic components of the feedstocks. Based on 
this analysis and currently available information, we conclude that 
biofuel (ethanol, cellulosic diesel, jet fuel, heating oil and naptha) 
produced from the cellulosic biomass of energy cane, giant reed, or 
napiergrass has similar lifecycle GHG impacts to switchgrass biofuel 
and meets the 60% GHG reduction threshold required for cellulosic 
biofuel.
1. Feedstock Production and Distribution
    For the purposes of this rulemaking, energy cane refers to 
varieties of perennial grasses in the Saccharum genus which are 
intentionally bred for high cellulosic biomass productivity but have 
characteristically low sugar content making them unsuitable as a 
primary source of sugar as compared to other varieties of grasses 
commonly known as ``sugarcane'' in the Saccharum genus. Energy cane 
varieties developed to date have low tolerance for cold temperatures 
but grow well in warm, humid climates. Energy cane originated from 
efforts to improve disease resistance and hardiness of commercial 
sugarcane by crossbreeding commercial and wild sugarcane strains. 
Certain higher fiber, lower sugar varieties that resulted were not 
suitable for commercial sugar production, and are now being developed 
as a high-biomass energy crop. There is currently no commercial 
production of energy cane. Current plantings are mainly limited to 
research field trials and small demonstrations for bioenergy purposes. 
However, based in part on discussions with industry, EPA anticipates 
continued development of energy cane particularly in the south-central 
and southeastern United States due to its high yields in these regions.
    Giant reed refers to the perennial grass Arundo donax of the 
Gramineae family. Giant reed thrives in subtropical and warm-temperate 
areas and is grown throughout Asia, southern Europe, Africa, the Middle 
East, and warmer U.S. states for multiple uses such as paper and pulp, 
musical instruments, rayon, particle boards, erosion control, and 
ornamental purposes.36 37 Based in

[[Page 712]]

part on discussions with industry, EPA anticipates continued 
development of giant reed as an energy crop particularly in the 
Mediterranean region and warmer U.S. states.
---------------------------------------------------------------------------

    \36\ See http://www.fs.fed.us/database/feis/plants/graminoid/arudon/all.html.
    \37\ See Lewandowski, I., Scurlock, J.M.O., Lindvall, E., 
Christou, M. (2003). The development and current status of perennial 
rhizomatous grasses as energy crops in the US and Europe. Biomass 
and Bioenergy 25, 335-361.
---------------------------------------------------------------------------

    Napiergrass is a tall bunch-type grass that has traditionally been 
grown as a high-yielding forage crop across the wet tropics. There is a 
considerable body of agronomic research on the production of 
napiergrass as a forage crop. More recently, researchers have 
investigated ways to maximize traits desirable in bioenergy crops. 
Practices have been developed by USDA and other researchers to lower 
fertilization rates and increase biomass production. Based in part on 
discussions with industry, EPA anticipates continued development of 
napiergrass as an energy crop particularly in Gulf Coast Region of the 
United States (more specifically the growing region includes Florida 
and southern portions of Texas, Louisiana, Georgia, Alabama and 
Mississippi).\38\
---------------------------------------------------------------------------

    \38\ For a map depicting the northern limit for sustained 
napiergrass production in the United States see Figure 1 in Woodard, 
K., R. and Sollenberger, L, E. 2008. Production of Biofuel Crops in 
Florida: Elephantgrass. Institute of Food and Agricultural Sciences, 
University of Florida. SS AGR 297.
---------------------------------------------------------------------------

a. Crop Yields
    For the purposes of analyzing the GHG emissions from energy cane, 
giant reed, and napiergrass production, EPA examined crop yields and 
production inputs in relation to switchgrass to assess the relative GHG 
impacts. Current national yields for switchgrass are approximately 4.5 
to 5 dry tons per acre. Average energy cane yields exceed switchgrass 
yields in both unfertilized and fertilized trails conducted in the 
southern United States. Unfertilized yields are around 7.3 dry tons per 
acre while fertilized trials show energy cane yields range from 
approximately 11 to 20 dry tons per acre.\39\ \40\ Until 
recently there have been few efforts to improve energy cane yields, but 
several energy cane development programs are now underway to further 
increase its biomass productivity. Giant reed field trials conducted in 
Alabama over a 9-year period showed an average yield of 15 dry tons per 
acre with no nitrogen fertilizer applied after the first year.\41\ 
Fertilized field trials have shown yields around 13 to 28 dry tons per 
acre in Spain, and 12 dry tons per acre in Italy (based on annual 
yields of 3, 14, 17, 16, and 12).\42\ High yields have been 
demonstrated with unimproved giant reed populations, and therefore 
there is potential for increased biomass productivity through improved 
growing methods and breeding efforts.\43\ Napiergrass field trials have 
produced dry biomass yields exceeding 20 tons per acre per year in 
north-central Florida. Using currently available technology, average 
yields for full-season napiergrass should range from 14 to 18 tons per 
acre with future improvements expected. Yield depends greatly on the 
type of cultivar and the amount and distribution of rainfall and 
fertilization rates. There is potential for increased biomass 
productivity through improved growing methods and breeding efforts.\44\ 
In general, the yields for all three of the energy grasses considered 
here will have higher yields than switchgrass, so from a crop yield 
perspective, the switchgrass analysis would be a conservative estimate 
when comparing against the energy cane, napier grass, and giant reed 
pathways.
---------------------------------------------------------------------------

    \39\ See Bischoff, K.P., Gravois, K.A., Reagan, T.E., Hoy, J.W., 
Kimbeng, C.A., LaBorde, C.M., Hawkins, G.L. Plant Regis. 2008, 2, 
211-217.
    \40\ See Hale, A.L. Sugar Bulletin, 2010, 88, 28-29.
    \41\ Huang, P., Bransby, D., and Sladden, S. (2010). 
Exceptionally high yields and soil carbon sequestration recorded for 
giant reed in Alabama. Poster session presented at: ASA, CSSA, and 
SSSA 2010 International Annual Meetings, Green Revolution 2.0; 2010 
Oct 31-Nov 4; Long Beach, CA.
    \42\ Mantineo, M., D'Agnosta, G.M., Copani, V., Patan[egrave], 
C., and Cosentino, S.L. (2009). Biomass yield and energy balance of 
three perennial crops for energy use in the semi-arid Mediterranean 
environment. Field Crops Research 114, 204-213.
    \43\ Lewandowski et al. 2003.
    \44\ Based on discussions with industry and USDA and Woodard and 
Sollenberger (2008).
---------------------------------------------------------------------------

    Furthermore, EPA's analysis of switchgrass for the RFS2 rulemaking 
assumed a 2% annual increase in yield that would result in an average 
national yield of 6.6 dry tons per acre in 2022. EPA anticipates a 
similar yield improvement for energy cane, giant reed, and napiergrass 
due to their similarity as perennial grasses and their comparable 
status as energy crops in their early stages of development. Given 
this, our analysis assumes an average energy cane yield of 19 dry tons 
per acre in the southern United States by 2022; an average giant reed 
yield of approximately 18 dry tons per acre by 2022; and an average 
napiergrass yield of approximately 20 dry tons per acre by 2022.\45\ 
The ethanol yield for all of the grasses is approximately the same so 
the higher crop yields for energy cane, napiergrass, and giant reed 
result directly in greater ethanol production compared to switchgrass 
per acre of production.
---------------------------------------------------------------------------

    \45\ These yields assume no significant adverse climate impacts 
on world agricultural yields over the analytical timeframe.
---------------------------------------------------------------------------

    Based on these yield assumptions, in areas with suitable growing 
conditions, energy cane would require approximately 26% to 47% of the 
land area required by switchgrass to produce the same amount of 
biomass, giant reed would require less than 40% of the land area 
required by switchgrass to produce the same amount of biomass, and 
napiergrass would require approximately 33% of the land area required 
by switchgrass to produce the same amount of biomass due to their 
higher yields. Even without yield growth assumptions, their currently 
higher crop yield rates means the land use required for these crops 
would be lower than for switchgrass. Therefore less crop area would be 
converted and displaced resulting in smaller land-use change GHG 
impacts than that assumed for switchgrass to produce the same amount of 
fuel. Furthermore, we believe energy cane and napiergrass will have a 
similar impact on international markets as assumed for switchgrass. 
Like switchgrass, energy cane and napiergrass are not expected to be 
traded internationally and their impacts on other crops are expected to 
be limited. Increased giant reed demand in the U.S. for biofuels is not 
expected to impact existing markets for giant reed, which are 
relatively small niche markets (e.g., musical instrument reeds).
b. Land Use
    In EPA's RFS2 analysis, switchgrass plantings displaced primarily 
soybeans and wheat, and to a lesser extent hay, rice, sorghum, and 
cotton. Energy cane and napiergrass, with production focused in the 
southern United States, are likely to be grown on land once used for 
pasture, rice, commercial sod, cotton or alfalfa, which would likely 
have less of an international indirect impact than switchgrass because 
some of those commodities are not as widely traded as soybeans or 
wheat. Given that energy cane and napiergrass will likely displace the 
least productive land first, EPA concludes that the land use GHG impact 
for energy cane and napiergrass per gallon should be no greater and 
likely less than estimated for switchgrass. Given that giant reed is in 
early stages of development as an energy crop, there is limited 
information on where it will be grown and what crops it will displace. 
We expect giant reed will displace the least productive land first and 
would likely have a similar or smaller indirect impact associated with 
crop displacement than what we assumed for switchgrass.
    Considering the total land potentially impacted by all the new 
feedstocks included in this rulemaking would not

[[Page 713]]

impact these conclusions (including the camelina discussed in the 
previous section and the three energy grasses considered here). As 
discussed previously, the camelina is expected to be grown on fallow 
land in the Northwest, while energy grasses are expected to be grown 
mainly in the south on existing cropland or pastureland. In the 
switchgrass ethanol scenario done for the Renewable Fuel Standard final 
rulemaking, total cropland acres increases by 4.2 million acres, 
including an increase of 12.5 million acres of switchgrass, a decrease 
of 4.3 million acres of soybeans, a 1.4 million acre decrease of wheat 
acres, a decrease of 1 million acres of hay, as well as decreases in a 
variety of other crops. Given the higher yields of the energy grasses 
considered here compared to switchgrass, there would be ample land 
available for production without having any adverse impacts beyond what 
was considered for switchgrass production.
c. Crop Inputs and Feedstock Transport
    EPA also assessed the GHG impacts associated with planting, 
harvesting, and transporting energy cane, giant reed, and napiergrass 
feedstocks in comparison to switchgrass. Table 6 shows the assumed 2022 
commercial-scale production inputs for switchgrass (used in the RFS2 
rulemaking analysis), average energy cane, giant reed, and napiergrass 
production inputs (USDA projections and industry data) and the 
associated GHG emissions.
    Available data gathered by EPA suggest that energy cane requires on 
average less nitrogen, phosphorous, potassium, and pesticide than 
switchgrass per dry ton of biomass, but more herbicide, lime, diesel, 
and electricity per unit of biomass. Giant reed may require on average 
less nitrogen and insecticide than switchgrass, but more phosphorous, 
potassium, herbicide, diesel, and electricity per unit of biomass. 
Napiergrass may require similar amounts of nitrogen fertilizer 
application as switchgrass, less phosphorous, potassium and insecticide 
than switchgrass, but more herbicide, lime, diesel, and electricity per 
unit of biomass.
    This assessment assumes production of all three new feedstocks uses 
electricity for irrigation given that growers will likely irrigate when 
possible to improve yields. Irrigation rates will vary depending on the 
timing and amount of rainfall, but for the purpose of estimating GHG 
impacts of electricity use for irrigation, we assumed a rate similar to 
what we assumed for other irrigated crops in the Southwest, South 
Central, and Southeast as shown in Table 6.
    Applying the GHG emission factors used in the RFS2 final rule, 
energy cane production results in slightly higher GHG emissions 
relative to switchgrass production (an increase of approximately 4 kg 
CO2eq/mmbtu). Giant reed production results in slightly 
lower GHG emissions relative to switchgrass production (a decrease of 
approximately 2 kg CO2eq/mmbtu). Napiergrass production 
results in slightly higher GHG emissions relative to switchgrass 
production (an increase of approximately 6 kg CO2eq/mmbtu).

                               Table 6--Production Inputs and GHG Emissions for Switchgrass, Energy Cane, Giant Reed, and Napiergrass (Biochemical Ethanol), 2022
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
                                                               Switchgrass                         Energy Cane                         Giant Reed                         Napiergrass
                                                  ----------------------------------------------------------------------------------------------------------------------------------------------
                                 Emission factors    Inputs (per                         Inputs (per                         Inputs (per                         Inputs (per
                                                     dry ton of      Emissions (per      dry ton of      Emissions (per      dry ton of      Emissions (per      dry ton of      Emissions (per
                                                      biomass)         mmBtu fuel)        biomass)         mmBtu fuel)        biomass)         mmBtu fuel)        biomass)        mmBtu fuel)
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Nitrogen Fertilizer...........  3,29 kgCO2e/ton    15.2 lbs......  3.6 kgCO2e........  8.4 lbs.......  2 kgCO2e..........  5 lbs.........  1 kgCO2e..........  10 lbs........  2.4 kgCO2e.
                                 of nitrogen.
N2O...........................  N/A..............  N/A...........  7.6 kgCO2e........  N/A...........  5.9 kgCO2e........  N/A...........  4.8 kgCO2e........  N/A...........  7.6 kgCO2e.
Phosphorus Fertilizer.........  1,12 kgCO2e/ton    6.1 lbs.......  0.5 kgCO2e........  3.2 lbs.......  0.3 kgCO2e........  7.4 lbs.......  0.6 kgCO2e........  1.1 lbs.......  0.1 kgCO2e.
                                 of phosphate.
Potassium Fertilizer..........  743 kgCO2e/ton of  6.1 lbs.......  0.3 kgCO2e........  4.2 lbs.......  0.2 kgCO2e........  7.4 lbs.......  0.4 kgCO2e........  4.0 lbs.......  0.2 kgCO2e.
                                 potassium.
Herbicide.....................  23,45 kgCO2e/tons  0.002 lbs.....  0.003 kgCO2e......  1.0 lbs.......  1.8 kgCO2e........  0.02 lbs......  0.03 kgCO2e.......  0.4 lbs.......  0.6 kgCO2e.
                                 of herbicide.
Insecticide (average across     27,22 kgCO2e/tons  0.025 lbs.....  0.04 kgCO2e.......  0 lbs.........  0 kgCO2e..........  0 lbs.........  0 kgCO2e..........  0 lbs.........  0 kgCO2e.
 regions).                       of pesticide.
Lime..........................  408 kgCO2e/ton of  0 lbs.........  0 kgCO2e..........  104.7 lbs.....  3.1 kgCO2e........  0 lbs.........  0 kgCO2e..........  100 lbs.......  2.9 kgCO2e.
                                 lime.
Diesel........................  97 kgCO2e/mmBtu    0.4 gal.......  0.8 kgCO2e........  1.3 gal.......  2.4 kgCO2e........  1.4 gal.......  2.5 kgCO2e........  1.3 gal.......  2.2 kgCO2e.
                                 diesel.
Electricity (irrigation)......  220 kgCO2e/mmBtu.  0 kWh.........  0 kgCO2e..........  14.7 kWh......  1.6 kgCO2e........  10 kWh........  1 kgCO2e..........  25 kWh........  2.7 kgCO2e.
                                                  ----------------------------------------------------------------------------------------------------------------------------------------------
    Total Emissions...........  .................  ..............  13 kgCO2e/mmBtu...  ..............  17 kgCO2e/mmBtu...  ..............  11 kgCO2e/mmBtu...  ..............  19 kgCO2e/mmBtu.
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Assumes 2022 switchgrass yield of 6.59 dry tons/acre and 92.3 gal ethanol/dry ton, 2022 energy cane yield of 19.1 dry tons/acre and 92 gal ethanol/dry ton, 2022 giant reed yield of 18 dry tons/
  acre and 92.3 gal ethanol/dry ton, and 2022 napiergrass yield of 20 dry tons/acre and 92.3 gal ethanol/dry ton. More detail on calculations and assumptions is included in materials to the
  docket.

    GHG emissions associated with distributing energy cane, giant reed, 
and napiergrass feedstocks are expected to be similar to EPA's 
estimates for switchgrass feedstock because they are all herbaceous 
agricultural crops requiring similar transport, loading, unloading, and 
storage regimes. Our analysis therefore assumes the same GHG impact for 
feedstock distribution as we assumed for switchgrass, although 
distributing energy cane, giant reed, and napiergrass feedstocks could 
be less GHG intensive because higher yields could translate to shorter 
overall hauling distances to storage or biofuel production facilities 
per gallon or Btu of final fuel produced.
2. Fuel Production, Distribution, and Use
    Energy cane, giant reed, and napiergrass are suitable for the same 
conversion processes as other cellulosic

[[Page 714]]

feedstocks, such as switchgrass and corn stover. Currently available 
information on energy cane, giant reed, and napiergrass composition 
shows that their hemicellulose, cellulose, and lignin content are 
comparable to other crops that qualify under the RFS regulations as 
feedstocks for the production of cellulosic biofuels. Based on this 
similar composition as well as conversion yield data provided by 
industry, we applied the same production processes that were modeled 
for switchgrass in the final RFS2 rule (biochemical ethanol, 
thermochemical ethanol, and Fischer-Tropsch (F-T) diesel \46\) to 
energy cane, giant reed, and napiergrass. We assumed the GHG emissions 
associated with producing biofuels from energy cane, giant reed, and 
napiergrass are similar to what we estimated for switchgrass and other 
cellulosic feedstocks. EPA also assumes that the distribution and use 
of biofuel made from energy cane, giant reed, and napiergrass will not 
differ significantly from similar biofuel produced from other 
cellulosic sources. As was done for the switchgrass case, this analysis 
assumes energy grasses grown in the United States for production 
purposes. If crops were grown internationally, used for biofuel 
production, and the fuel was shipped to the U.S., shipping the finished 
fuel to the U.S. could increase transport emissions. However, 
considering the increased transport emissions associated with sugarcane 
ethanol distribution to the U.S., this would at most add 1-2% to the 
overall lifecycle GHG impacts of the energy grasses.
---------------------------------------------------------------------------

    \46\ The F-T diesel process modeled applies to cellulosic 
diesel, jet fuel, heating oil, and naphtha.
---------------------------------------------------------------------------

3. Summary
    Based on our comparison of switchgrass and the three feedstocks 
considered here, EPA believes that cellulosic biofuel produced from the 
cellulose, hemicellulose and lignin portions of energy cane, giant 
reed, and napiergrass has similar or better lifecycle GHG impacts than 
biofuel produced from the cellulosic biomass from switchgrass. Our 
analysis suggests that the three feedstocks considered have GHG impacts 
associated with growing and harvesting the feedstock that are similar 
to switchgrass. Emissions from growing and harvesting energy cane are 
approximately 4 kg CO2eq/mmBtu higher than switchgrass, emissions from 
growing and harvesting giant reed are approximately 2 kg CO2eq/mmBtu 
lower than switchgrass, and emissions from growing and harvesting 
napiergrass are approximately 6 kg CO2eq/mmBtu higher than switchgrass. 
These are small changes in the overall lifecycle, representing at most 
a 6% change in the energy grass lifecycle impacts in comparison to the 
petroleum fuel baseline. Furthermore, the three feedstocks considered 
are expected to have similar or lower GHG emissions than switchgrass 
associated with other components of the biofuel lifecycle.
    Under a hypothetical worst case, if the calculated increases in 
growing and harvesting the new feedstocks are incorporated into the 
lifecycle GHG emissions calculated for switchgrass, and other lifecycle 
components are projected as having similar GHG impacts to switchgrass 
(including land use change associated with switchgrass production), the 
overall lifecycle GHG reductions for biofuel produced from energy cane, 
giant reed, and napiergrass still meet the 60% reduction threshold for 
cellulosic biofuel, the lowest being a 64% reduction (for napiergrass 
F-T diesel) compared to the petroleum baseline. We believe these are 
conservative estimates, as use of energy cane, giant reed, or 
napiergrass as a feedstock is expected to have smaller land-use GHG 
impacts than switchgrass, due to their higher yields. The docket for 
this rule provides additional detail on the analysis of energy cane, 
giant reed, and napiergrass as biofuel feedstocks.
    Although this analysis assumes energy cane, giant reed, and 
napiergrass biofuels produced for sale and use in the United States 
will most likely come from domestically produced feedstock, we also 
intend for the approved pathways to cover energy cane, giant reed, and 
napiergrass from other countries. We do not expect incidental amounts 
of biofuels from feedstocks produced in other nations to impact our 
average GHG emissions. Moreover, those countries most likely to be 
exporting energy cane, giant reed, or napiergrass or biofuels produced 
from these feedstocks are likely to be major producers which typically 
use similar cultivars and farming techniques. Therefore, GHG emissions 
from producing biofuels with energy cane, giant reed, or napiergrass 
grown in other countries should be similar to the GHG emissions we 
estimated for U.S. energy cane, giant reed, or napiergrass, though they 
could be slightly (and insignificantly) higher or lower. For example, 
the renewable biomass provisions under the Energy Independence and 
Security Act would prohibit direct conversion of previously unfarmed 
land in other countries into cropland for energy grass-based renewable 
fuel production. Furthermore, any energy grass production on existing 
cropland internationally would not be expected to have land use impacts 
beyond what was considered for switchgrass production. Even if there 
were unexpected larger differences, EPA believes the small amounts of 
feedstock or fuel potentially coming from other countries will not 
impact our threshold analysis.
    Based on our assessment of switchgrass in the RFS2 final rule and 
this comparison of GHG emissions from switchgrass and energy cane, 
giant reed, and napiergrass, we do not expect variations to be large 
enough to bring the overall GHG impact of fuel made from energy cane, 
giant reed or napier grass to come close to the 60% threshold for 
cellulosic biofuel. Therefore, EPA is including cellulosic biofuel 
produced from the cellulose, hemicelluloses and lignin portions of 
energy cane, giant reed, and napiergrass under the same pathways for 
which cellulosic biomass from switchgrass qualifies under the RFS2 
final rule.

C. Lifecycle Greenhouse Gas Emissions Analysis for Certain Renewable 
Gasoline and Renewable Gasoline Blendstocks Pathways

    In this rule, EPA is also adding pathways to Table 1 to Sec.  
80.1426 for the production of renewable gasoline and renewable gasoline 
blendstock using specified feedstocks, fuel production processes, and 
process energy sources. The feedstocks we considered are generally 
considered waste feedstocks such as crop residues or cellulosic 
components of separated yard waste. These feedstocks have been 
identified by the industry as the most likely feedstocks for use in 
making renewable gasoline or renewable gasoline blendstock in the near 
term due to their availability and low cost. Additionally, these 
feedstocks have already been analyzed by EPA as part of the RFS2 
rulemaking for the production of other fuel types. Consequently, no new 
modeling is required and we rely on earlier assessments of feedstock 
production and distribution for assessing the likely lifecycle impact 
on renewable gasoline and renewable gasoline blendstock. We have also 
relied on the petroleum gasoline baseline assessment from the RFS2 rule 
for estimating the fuel distribution and use GHG emissions impacts for 
renewable gasoline and renewable gasoline blendstock. Consequently, the 
only new analysis required is of the technologies for turning the 
feedstock into renewable

[[Page 715]]

gasoline and renewable gasoline blendstock.
1. Feedstock Production and Distribution
    EPA has evaluated renewable gasoline and renewable gasoline 
blendstock pathways that utilize cellulosic feedstocks currently 
included in Table 1 to Sec.  80.1426 of the regulations. The following 
feedstocks were evaluated:
     Cellulosic biomass from crop residue, slash, pre-
commercial thinnings and tree residue, annual cover crops;
     Cellulosic components of separated yard waste;
     Cellulosic components of separated food waste; and
     Cellulosic components of separated MSW.
    The FASOM and FAPRI models were used to analyze the GHG impacts of 
the feedstock production portion of a fuel's lifecycle. In the RFS2 
rulemaking, FASOM and FAPRI modeling was performed to analyze the 
emissions impact of using corn stover as a biofuel feedstock and this 
modeling was extended to some additional feedstock sources considered 
similar to corn stover. This approach was used for crop residues, 
slash, pre-commercial thinnings, tree residue and cellulosic components 
of separated yard, food, and MSW. These feedstocks are all excess 
materials and thus, like corn stover, were determined to have little or 
no land use change GHG impacts. Their GHG emission impacts are mainly 
associated with collection, transport, and processing into biofuel. See 
the RFS2 rulemaking preamble for further discussion. We used the 
results of the corn stover modeling in this analysis to estimate the 
upper bound of agricultural sector impacts from the production of the 
various cellulosic feedstocks noted above.
    The agriculture sector modeling results for corn stover represent 
all of the direct and significant indirect emissions in the agriculture 
sector (feedstock production emissions) for a certain quantity of corn 
stover produced. For the RFS2 rulemaking, this was roughly 62 million 
dry tons of corn stover to produce 5.7 billion gallons of ethanol 
assuming biochemical fermentation to ethanol processing. We have 
calculated GHG emissions from feedstock production for that amount of 
corn stover. The GHG emissions were then divided by the total heating 
value of the fuel to get feedstock production emissions per mmBtu of 
fuel. In addition to the biochemical ethanol process, a similar 
analysis was completed for thermochemical ethanol and F-T diesel 
pathways as part of the RFS2 rulemaking.
    In this rulemaking we are analyzing renewable gasoline and 
renewable gasoline blendstock produced from corn stover (and, by 
extension, other waste feedstocks). The number of gallons of fuel 
produced from a ton of corn stover (modeled process yields) is specific 
to the process used to produce renewable fuel. EPA has adjusted the 
results of the earlier corn stover modeling to reflect the different 
process yields and heating value of renewable gasoline or renewable 
gasoline blendstock product. The results of this calculation are shown 
below in Table 7.
    We based our process yields and heating values for renewable 
gasoline and renewable gasoline blendstock on several process 
technologies representative of technologies anticipated to be used in 
producing these fuels. As discussed later in this section, there are 
four main types of fuel production technologies available for producing 
renewable gasoline. These four processes can be characterized as (1) 
thermochemical gasification, (2) catalytic pyrolysis and upgrading to 
renewable gasoline or renewable gaoline blendstock (``catalytic 
pyrolysis''), (3) biochemical fermentation with upgrading to renewable 
gasoline or renewable gasoline blendstock via carboxylic acid 
(``fermentation and upgrading''), and (4) direct biochemical 
fermentation to renewable gasoline and renewable gasoline blendstock 
(``direct fermentation''). The thermochemical gasification process was 
modeled as part of the RFS2 final rule, included as producing naptha 
via the F-T process. Our analysis of the catalytic pyrolysis process 
was based on the modeling work completed by the National Renewable 
Energy Laboratory (NREL) for this rule for a process to make renewable 
gasoline blendstock.\47\ The fermentation and upgrading process was 
modeled based on confidential business information (CBI) from industry 
for a unique process which uses biochemical conversion of cellulose to 
renewable gasoline via a carboxylic acid route. In addition, we have 
qualitatively assessed the direct fermentation to renewable gasoline 
process based on similarities to the biochemical ethanol process 
already analyzed as part of the RFS2 rulemaking. The fuel production 
section below provides further discussion on extending the GHG 
emissions results of the biochemical ethanol fermentation process to a 
biochemical renewable gasoline or renewable gasoline blendstock 
fermentation process. In some cases, the available data sources 
included process yields for renewable gasoline or renewable gasoline 
blendstock produced from wood chips rather than corn stover which was 
specifically modeled as a feedstock in the RFS2 final rule. We believe 
that the process yields are not significantly impacted by the source of 
cellulosic material whether the cellulosic material comes from residue 
such as corn stover or wood material such as from tree residues. We 
made the simplifying assumption that one dry ton of wood feedstock 
produces the same volume of renewable gasoline or renewable gasoline 
blendstock as one dry ton of corn stover. We believe this is reasonable 
considering that the RFS2 rulemaking analyses for biochemical ethanol 
and thermochemical F-T diesel processes showed limited variation in 
process yields between different feedstocks for a given process 
technology.\48\ In addition, since the renewable gasoline and renewable 
gasoline blendstock pathways include feedstocks that were already 
considered as part of the RFS2 final rule, the existing feedstock 
lifecycle GHG impacts for distribution of corn stover were also applied 
to this analysis.\49\
---------------------------------------------------------------------------

    \47\ Kinchin, Christopher. Catalytic Fast Pyrolysis with 
Upgrading to Gasoline and Diesel Blendstocks. National Renewable 
Energy Laboratory (NREL). 2011.
    \48\ Aden, Andy. Feedstock Considerations and Impacts on 
Biorefining. National Renewable Energy Laboratory (NREL). December 
2009.
    \49\ Results for feedstock distribution are aggregated along 
with fuel distribution and are reported in a later section, see 
conclusion section.
---------------------------------------------------------------------------

    Feedstock production emissions are shown in Table 7 below for corn 
stover. Corn stover feedstock production emissions are mainly a result 
of corn stover removal increasing the profitability of corn production 
(resulting in shifts in cropland and thus slight emission impacts) and 
also the need for additional fertilizer inputs to replace the nutrients 
lost when corn stover is removed. However, corn stover removal also has 
an emissions benefit as it encourages the use of no-till farming which 
results in the lowering of domestic land use change emissions. This 
change to no-till farming results in a negative value for domestic land 
use change emission impacts (see also Table 13 below). For other waste 
feedstocks (e.g., tree residues and cellulosic components of separate 
yard, food, and MSW), the feedstock production emissions are even lower 
than the values shown for corn stover since the use of such feedstocks 
does not require land use changes or additional agricultural inputs. 
Therefore, we conclude that if the use of corn stover

[[Page 716]]

as a feedstock in the production of renewable gasoline and renewable 
gasoline blendstock yields lifecycle GHG emissions results for the 
resulting fuel that qualify it as cellulosic biofuel (i.e., it has at 
least a 60% lifecycle GHG reduction as compared to conventional fuel), 
then the use of other waste feedstocks with little or no land use 
change emissions will also result in renewable gasoline or renewable 
gasoline blendstock that qualifies as cellulosic biofuel.

 Table 7--Feedstock Production Emissions for Renewable Gasoline and Renewable Gasoline Blendstock Pathways Using
                                                   Corn Stover
----------------------------------------------------------------------------------------------------------------
                                                                                                     Direct
                                                                                                  biochemical
                                                             Catalytic         Biochemical        fermentation
                                                            pyrolysis to     fermentation to       process to
                                                             renewable          renewable          renewable
         Feedstock production emission sources                gasoline         gasoline via       gasoline and
                                                         blendstock (g CO2-  carboxylic acid       renewable
                                                             eq./mmBtu)     (g CO2-eq./mmBtu)       gasoline
                                                                                               blendstock (g CO2-
                                                                                                   eq./mmBtu)
----------------------------------------------------------------------------------------------------------------
Domestic Livestock.....................................              7,648              6,770            ~ 9,086
Domestic Farm Inputs and Fertilizer N2O................              1,397              1,237            ~ 1,660
Domestic Rice Methane..................................                366                324              ~ 434
Domestic Land Use Change...............................             -9,124             -8,076          ~ -10,820
International Livestock................................                  0                  0                  0
International Farm Inputs and Fertilizer N2O...........                  0                  0                  0
International Rice Methane.............................                  0                  0                  0
International Land Use Change..........................                  0                  0                  0
                                                        --------------------------------------------------------
    Total Feedstock Production Emissions...............                287                254              ~ 361
----------------------------------------------------------------------------------------------------------------

    The results in Table 7 differ for the different pathways considered 
because of the different amounts of corn stover used to produce the 
same amount of fuel in each case. Table 7 only considers the feedstock 
production impacts associated with the renewable gasoline pathways, 
other aspects of the lifecycle are discussed in the following sections.
2. Fuel Distribution
    A petroleum gasoline baseline was developed as part of the RFS2 
final rule which included estimates for fuel distribution emissions. 
Since renewable gasoline and renewable gasoline blendstocks when 
blended into gasoline are similar to petroleum gasoline, it is 
reasonable to assume similar fuel distribution emissions. Therefore, 
the existing fuel distribution lifecycle GHG impacts of the petroleum 
gasoline baseline from the RFS2 final rule were applied to this 
analysis.
3. Use of the Fuel
    A petroleum gasoline baseline was developed as part of the RFS2 
final rule which estimated the tailpipe emissions from fuel combustion. 
Since renewable gasoline and renewable gasoline blendstock are similar 
to petroleum gasoline, the non-CO2 combustion emissions 
calculated as part of the RFS2 final rule for petroleum gasoline were 
applied to our analysis of the renewable gasoline and renewable 
gasoline blendstock pathways. Only non-CO2 emissions were 
included since carbon fluxes from land use change are accounted for as 
part of the biomass feedstock production.
4. Fuel Production
    In the RFS2 rulemaking, EPA analyzed several of the main cellulosic 
biofuel pathways: a biochemical fermentation process to ethanol and two 
thermochemical gasification processes, one producing mixed alcohols 
(primarily ethanol) and the other one producing mixed hydrocarbons 
(primarily diesel fuel). These pathways all exceeded the 60% lifecycle 
GHG threshold requirements for cellulosic biofuel using the specified 
feedstocks. Refer to the preamble and regulatory impact analysis (RIA) 
from the final RFS2 rule for more details. From these analyses, it was 
determined that ethanol and diesel fuel produced from the specified 
cellulosic feedstocks and processes would be eligible for cellulosic 
and advanced biofuel RINs.
    The thermochemical gasification process to diesel fuel (via F-T 
synthesis) also produces a smaller portion of naphtha, a gasoline 
blendstock. In the final RFS2 rule, naphtha produced with specified 
cellulosic feedstocks by a F-T process was included as exceeding the 
60% lifecycle GHG threshold, with an applicable D-Code of 3, in Table 1 
to Sec.  80.1426.
    Since the final RFS2 rule was released, EPA has received several 
petitions and inquiries that suggest that renewable gasoline or 
renewable gasoline blendstock produced using processes other than the 
F-T process could also qualify for a similar D-Code of 3.\50\ For the 
reasons described below, we have decided to authorize the generation of 
RINs with a D code of 3 for renewable gasoline and renewable gasoline 
blendstock produced using specified cellulosic feedstocks for the 
processes considered here.
---------------------------------------------------------------------------

    \50\ See http://www.epa.gov/otaq/fuels/renewablefuels/compliancehelp/rfs2-lca-pathways.htm for list of petitions received 
by EPA.
---------------------------------------------------------------------------

    Several routes have been identified as available for the production 
of renewable gasoline and renewable gasoline blendstock from renewable 
biomass. These include catalytic pyrolysis and upgrading to renewable 
gasoline or renewable gasoline blendstock (``catalytic pyrolysis''), 
biochemical fermentation with upgrading to renewable gasoline or 
renewable gasoline blendstock via carboxylic acid (``fermentation and 
upgrading''), and direct biochemical fermentation to renewable gasoline 
and renewable gasoline blendstock (``direct 
fermentation'').51 52
---------------------------------------------------------------------------

    \51\ Regalbuto, John. ``An NSF perspective on next generation 
hydrocarbon biorefineries,'' Computers and Chemical Engineering 34 
(2010) 1393-1396. February 2010.
    \52\ Serrano-Ruiz, J., Dumesic, James. ``Catalytic routes for 
the conversion of biomass into liquid hydrocarbon transportation 
fuels,'' Energy Environmental Science (2011) 4, 83-99.
---------------------------------------------------------------------------

    Similar to how we analyzed several of the main routes for 
cellulosic ethanol and cellulosic diesel for the final RFS2 rule, we 
have chosen to analyze the main renewable gasoline and renewable 
gasoline blendstock pathways in order to estimate the potential GHG 
reduction profile for renewable gasoline and renewable gasoline 
blendstock across a

[[Page 717]]

range of other production technologies for which we are confident will 
have at least as great of GHG emission reductions as those specifically 
analyzed.
a. Catalytic Pyrolysis to Renewable Gasoline and Renewable Gasoline 
Blendstock
    The first production process we investigated for this rule is a 
catalytic fast pyrolysis route to bio-oils with upgrading to a 
renewable gasoline or a renewable gasoline blendstock. We utilized 
process modeling results from the National Renewable Energy Laboratory 
(NREL). Information provided by industry and claimed as CBI are based 
on similar processing methods and suggest similar results than those 
reported by NREL. Details on the NREL modeling are described further in 
a technical report available through the docket.\53\ Catalytic 
pyrolysis involves the rapid heating of biomass to about 500[deg]C at 
slightly above atmospheric pressure. The rapid heating thermally 
decomposes biomass, converting it into pyrolysis vapor, which is 
condensed into a liquid bio-oil. The liquid bio-oil can then be 
upgraded using conventional hydroprocessing technology and further 
separated into gasoline and diesel blendstock streams (cellulosic 
diesel from catalytic pyrolysis is already included as an acceptable 
pathway in the RFS2 program). Some industry sources also expect to 
produce smaller fractions of heating oil in addition to gasoline and 
diesel blendstocks. Excess electricity from the process is also 
accounted for in our modeling as a co-product credit in which any 
excess displaces U.S. average grid electricity. Excess electricity is 
generated from the use of co-product coke/char and product gases and is 
available because internal electricity demands are fully met. The 
estimated energy inputs and electricity credits shown in Table 8, 
below, utilize the data provided by the NREL process modeling. However, 
Industry sources also identified potential areas for improvements in 
energy use, such as the use of biomass fired dryers instead of natural 
gas fired dryers for drying incoming wet feedstocks and increased 
turbine efficiencies for electricity production which may result in 
lower energy consumption than estimated by NREL and thus improve GHG 
performance compared to our estimates here.
---------------------------------------------------------------------------

    \53\ Kinchin, Christopher. Catalytic Fast Pyrolysis with 
Upgrading to Gasoline and Diesel Blendstocks. National Renewable 
Energy Laboratory (NREL). 2011.

                            Table 8--2022 Energy Use at Cellulosic Biofuel Facilities
                                                    [Btu/gal]
----------------------------------------------------------------------------------------------------------------
                                                                                Purchased
             Technology                  Biomass use      Natural gas use      electricity      Sold electricity
----------------------------------------------------------------------------------------------------------------
Catalytic Pyrolysis to Renewable               136,000             51,000                  0             -2,000
 Gasoline Blendstock................
----------------------------------------------------------------------------------------------------------------

    The emissions from energy inputs were calculated by multiplying the 
amount of energy by emission factors for fuel production and 
combustion, based on the same method and factors used in the RFS2 final 
rulemaking. The emission factors for the different fuel types are from 
GREET and were based on assumed carbon contents of the different 
process fuels. The emissions from producing electricity in the U.S. 
were also taken from GREET and represent average U.S. grid electricity 
production emissions.
    The major factors influencing the emissions from the fuel 
production stage of the catalytic pyrolysis pathway are the use of 
natural gas (mainly due to hydrogen production for hydroprocessing) and 
the co-products available for additional heat and power generation.\54\ 
See Table 9 for a summary of emissions from fuel production.
---------------------------------------------------------------------------

    \54\ A steam methane reformer (SMR) is used to produce the 
hydrogen necessary for hydroprocessing. In the U.S. over 95% of 
hydrogen is currently produced via steam reforming (DOE, 2002 ``A 
National Vision of America's Transition to a Hydrogen Economy to 
2030 and Beyond''). Other alternatives are available, such as 
renewable or nuclear resources used to extract hydrogen from water 
or the use of biomass to produces hydrogen. These alternative 
methods, however, are currently not as efficient or cost effective 
as the use of fossil fuels and therefore we conservatively estimate 
emissions from hydrogen production using the more commonly used SMR 
technology.

 Table 9--Fuel Production Emissions for Catalytic Pyrolysis to Renewable
                  Gasoline Blendstock Using Corn Stover
------------------------------------------------------------------------
                                                            Catalytic
                                                          pyrolysis to
                                                            renewable
                    Lifecycle stage                         gasoline
                                                          blendstock (g
                                                         CO2-eq./mmBtu)
------------------------------------------------------------------------
On-Site & Upstream Emissions (Natural Gas & Biomass*).            31,000
Electricity Co-Product Credit.........................            -3,000
Total Fuel Production Emissions:......................            28,000
------------------------------------------------------------------------
Only non-CO2 combustion emissions from biomass.

    b. Fermentation and Upgrading to Renewable Gasoline and Renewable 
Gasoline Blendstock
    The second production process we investigated is a biochemical 
fermentation process to intermediate carboxylic acids with catalytic 
upgrading to renewable gasoline or renewable gasoline blendstock. This 
process involves the fermentation of biomass using a mixed-culture of 
microorganisms that produce a variety of carboxylic acids. If the 
feedstock has high lignin content, then the biomass is pretreated to 
enhance digestibility. The acids are then neutralized to carboxylate 
salts and further converted to ketones and alcohols for refining into 
gasoline, diesel, and jet fuel.
    The process requires the use of natural gas and hydrogen 
inputs.\55\ No purchased electricity is required as lignin is projected 
to be used to meet all facility demands as well as provide excess 
electricity to the grid. EPA used the estimated energy and material 
inputs along with emission factors to estimate the GHG emissions from 
this process. The energy inputs and electricity credits are shown in 
Table 10, below. These inputs are based on Confidential Business 
Information (CBI), rounded to the nearest 1000 units, provided by 
industry as part of the petition process for new fuel pathways.
---------------------------------------------------------------------------

    \55\ Hydrogen emissions are modeled as natural gas and 
electricity demands.

[[Page 718]]



                                Table 10--2022 Energy Use at Cellulosic Facility
                                                    [Btu/gal]
----------------------------------------------------------------------------------------------------------------
                                                                                Purchased
             Technology                  Biomass use      Natural gas use      electricity      Sold electricity
----------------------------------------------------------------------------------------------------------------
Biochemical Fermentation to                     49,000             59,000                  0             -2,000
 Renewable Gasoline or Renewable
 Gasoline Blendstock via Carboxylic
 Acid...............................
----------------------------------------------------------------------------------------------------------------

    The process also uses a small amount of buffer material as 
neutralizer which was not included in the GHG lifecycle results due to 
its likely negligible emissions impact. The GHG emissions estimates 
from the fuel production stage are seen in Table 11.

   Table 11--Fuel Production Emissions for Biochemical Fermentation to
 Renewable Gasoline or Renewable Gasoline Blendstock via Carboxylic Acid
                            Using Corn Stover
------------------------------------------------------------------------
                                                        GHG Emissions (g
                    Lifecycle stage                      CO2-eq./mmBtu)
------------------------------------------------------------------------
On-Site & Upstream Emissions (Natural Gas & Biomass*).            33,000
Electricity Co-Product Credit.........................            -3,000
                                                       -----------------
    Total Fuel Production Emissions:..................            30,000
------------------------------------------------------------------------
*Only non-CO2 combustion emissions from biomass

c. Direct Fermentation to Renewable Gasoline and Renewable Gasoline 
Blendstock
    The third production process we investigated involves the use of 
microorganisms to ferment sugars hydrolyzed from cellulose directly 
into hydrocarbons which could be either a complete fuel as renewable 
gasoline or a renewable gasoline blendstock. The process is similar to 
the biochemical fermentation to ethanol pathway modeled for the final 
RFS2 rule with the major difference being the end fuel product, 
hydrocarbons instead of ethanol. Researchers believe that this new 
technology could achieve improvements over classical fermentation 
approaches because hydrocarbons separate spontaneously from the aqueous 
phase, thereby avoiding poisoning of microbes by the accumulated 
products and facilitating separation/collection of alkanes from the 
reaction medium.\56\ In other words, some energy savings may result 
because fewer separation unit operations could be required for 
separating the final product from other reactants and there may be 
better conversion yields as the fermentation microorganisms are not 
poisoned when interacting with accumulated products. We also expect 
that the lignin/byproduct portions of the biomass from the fermentation 
to hydrocarbon process could be converted into heat and electricity for 
internal demands or for export, similar to the biochemical fermentation 
to ethanol pathway.
---------------------------------------------------------------------------

    \56\ Serrano-Ruiz, J., Dumesic, James. ``Catalytic routes for 
the conversion of biomass into liquid hydrocarbon transportation 
fuels,'' Energy Environmental Science (2011) 4, 83-99.
---------------------------------------------------------------------------

    Therefore, we can conservatively extend our final RFS2 rule 
biochemical fermentation to ethanol process results to a similar (but 
likely slightly improved) process that instead produces hydrocarbons. 
Since the final RFS2 rule cellulosic ethanol GHG results were well 
above the 60% GHG reduction threshold for cellulosic biofuels, if 
actual emissions from other necessary changes to the direct biochemical 
fermentation to hydrocarbons process represent some small increment in 
GHG emissions, the pathway would still likely meet the threshold. Table 
12 is our qualitative assessment of the potential emissions reductions 
from a process using biochemical fermentation to cellulosic 
hydrocarbons assuming similarities to the biochemical fermentation to 
cellulosic ethanol route from the final RFS2 rule.

   Table 12--Fuel Production Emissions for RFS2 Cellulosic Biochemical
    Ethanol Compared to Direct Biochemical Fermentation to Renewable
       Gasoline or Renewable Gasoline Blendstock Using Corn Stover
------------------------------------------------------------------------
                                                             Direct
                                                          biochemical
                                                        fermentation to
                                     RFS2 Cellulosic       renewable
                                       biochemical        gasoline and
          Lifecycle stage           ethanol emissions      renewable
                                    (g CO2-eq./mmBtu)       gasoline
                                                           blendstock
                                                       emissions (g CO2-
                                                           eq./mmBtu)
------------------------------------------------------------------------
On-Site Emissions & Upstream                    3,000       < or = 3,000
 (biomass)........................
Electricity Co-Product Credit.....            -35,000          = -35,000
                                   -------------------------------------
    Total Fuel Production                     -33,000     < or = -33,000
     Emissions \57\...............
------------------------------------------------------------------------

    Table 13 below breaks down by stage the lifecycle GHG emissions for 
the renewable gasoline and renewable gasoline blendstock pathways using 
corn stover and the 2005 petroleum baseline. The table demonstrates the 
contribution of each stage in the fuel pathway and its relative 
significance in terms of GHG emissions. These results are also 
presented in graphical form in a supplemental memorandum to the 
docket.\58\ As noted above, these analyses assume natural gas as the 
process energy when needed; using biogas or biomass as process energy 
would result in an even better lifecycle GHG impact.
---------------------------------------------------------------------------

    \57\ Numbers do not add up due to rounding.
    \58\ Memorandum to the Air and Radiation Docket EPA-HQ-OAR-2011-
0542 ``Supplemental Information for Renewable Gasoline and Renewable 
Gasoline Blendstock Pathways Under the Renewable Fuel Standard 
(RFS2) Program''.

[[Page 719]]



 Table 13--Lifecycle GHG Emissions for Renewable Gasoline and Renewable Gasoline Blendstock Pathways Using Corn
                                                  Stover, 2022
                                               [kg CO2-eq./mmBtu]
----------------------------------------------------------------------------------------------------------------
                                                                                  Direct
                                                                               biochemical
                                          Catalytic         Biochemical      fermentation to
                                         pyrolysis to     fermentation to       renewable        2005 gasoline
              Fuel type                   renewable          renewable         gasoline and         baseline
                                           gasoline         gasoline via        renewable
                                          blendstock      carboxylic acid        gasoline
                                                                                blendstock
----------------------------------------------------------------------------------------------------------------
Net Domestic Agriculture (w/o land                    9                  8               ~ 11  .................
 use change)........................
Net International Agriculture (w/o
 land use change):
    Domestic Land Use Change........                 -9                 -8              ~ -11  .................
International Land Use Change:
    Fuel Production.................                 28                 30         < or = -33                 19
    Fuel and Feedstock Transport....                  2                  2                ~ 2                  *
    Tailpipe Emissions..............                  2                  2                ~ 1                 79
                                     ---------------------------------------------------------------------------
        Total Emissions.............                 32                 34         < or = -29                 98
                                     ===========================================================================
        % Change from Baseline......               -67%               -65%              -129%  .................
----------------------------------------------------------------------------------------------------------------
* Emissions included in fuel production stage.

d. Extension of Modeling Results to Other Production Processes 
Producing Renewable Gasoline or Renewable Gasoline Blendstock
    In the RFS2 rulemaking, we modeled the GHG emissions results from 
the biochemical fermentation process to ethanol, thermochemical 
gasification processes to mixed alcohols (primarily ethanol) and mixed 
hydrocarbons (primarily diesel fuel). We extended these modeled process 
results to apply when the biofuel was produced from ``any'' process. We 
determined that since we modeled multiple cellulosic biofuel processes 
and all were shown to exceed the 60% lifecycle GHG threshold 
requirements for cellulosic biofuel using the specified feedstocks its 
was reasonable to extend to other processes that might develop as these 
would likely represent improvements over existing processes as the 
industry works to improve the economics of cellulosic biofuel 
production by, for example, reducing energy consumption and improving 
process yields. Similarly, this rule assesses multiple processes for 
the production of renewable gasoline and renewable gasoline blendstocks 
and all were shown to exceed the 60% lifecycle GHG threshold 
requirements for cellulosic biofuel using specified feedstocks.
    As was the case in our earlier rulemaking, a couple reasons in 
particular support extending our modeling results to other production 
process producing renewable gasoline or renewable gasoline blendstock 
from cellulosic feedstock. Under this rule we analyzed the core 
technologies most likely available through 2022 for production of 
renewable gasoline and renewable gasoline blendstock routes from 
cellulosic feedstock as shown in literature. \59\ \60\ The 
two primary routes for renewable gasoline and renewable gasoline 
blendstock production from cellulosic feedstock can be classified as 
either thermochemical or biological. Each of these two major categories 
has two subcategories. The processes under the thermochemical category 
include:
---------------------------------------------------------------------------

    \59\ Regalbuto, John. ``An NSF perspective on next generation 
hydrocarbon biorefineries,'' Computers and Chemical Engineering 34 
(2010) 1393-1396. February 2010.
    \60\ Serrano-Ruiz, J., Dumesic, James. ``Catalytic routes for 
the conversion of biomass into liquid hydrocarbon transportation 
fuels,'' Energy Environmental Science (2011) 4, 83-99.
---------------------------------------------------------------------------

     Pyrolysis--in which cellulosic biomass is decomposed with 
temperature to bio-oils and requires further catalytic processing to 
produce a finished fuel.
     Gasification--in which cellulosic biomass is decomposed to 
syngas with further catalytic processing of methanol to gasoline or 
through Fischer-Tropsch (F-T) synthesis to gasoline.
    The processes under the biochemical category include:
     Direct fermentation--requires the release of sugars from 
biomass and the use of ``synthetic biology'' in which microorganisms 
are altered to ferment sugars straight into hydrocarbons instead of 
alcohols.
     Fermentation w/catalytic upgrading--requires the release 
of sugars from biomass and aqueous- or liquid-phase processing of 
sugars or intermediate fermentation products into hydrocarbons using 
solid catalysts,
    As part of the modeling effort here, as well as for the RFS2 final 
rule, we have considered the lifecycle GHG impacts of the four possible 
production technologies mentioned above. The pyrolysis, direct 
fermentation, and fermentation with catalytic upgrading are considered 
in this rule and the gasification route was already included in the 
RFS2 final rule. In all cases, the processes that we have considered 
meet the 60% lifecycle GHG reduction required for cellulosic biofuels. 
Furthermore, we believe that the results from our modeling would cover 
all the likely variations within these potential routes for producing 
renewable gasoline and renewable gasoline blendstock which also use 
natural gas, biogas or biomass for process energy and that all such 
production variations would also meet the 60% lifecycle threshold.
    The main reason for this is that we believe that our energy input 
assumptions are reasonable at this time but probably in some cases 
conservative for commercial scale cellulosic facilities. The cellulosic 
industry is in its early stages of development and many of the 
estimates of process technology GHG impacts is based on pre-commercial 
scale assessments and demonstration programs. Commercial scale 
cellulosic facilities will continue to make efficiency improvements 
over time to maximize their fuel products/co-products and minimize 
wastes. For cellulosic facilities, such improvements include increasing 
conversion yields and fully utilizing the biomass input for valuable 
products.
    An example of increasing the amount of biomass utilized is the 
combustion of undigested or unconverted biomass for heat and power. The 
three routes that we analyzed for the production of renewable gasoline 
and renewable gasoline blendstock in today's rule assume an electricity 
production credit from the economically-driven use of

[[Page 720]]

lignin or waste byproducts; we also ran a sensitivity case where no 
electricity credit was given. We found that all of the routes analyzed 
would still pass the GHG threshold without an electricity credit, 
providing confidence that over the range of technology options, these 
process technologies will surely allow the cellulosic biofuel produced 
to exceed the threshold for cellulosic biouel GHG performance. Without 
excess electricity production the catalytic pyrolysis pathway results 
in a 65% lifecycle GHG reduction, the biochemical fermentation via 
carboxylic acid pathway results in a 62% lifecycle GHG reduction, and 
the direct biochemical fermentation pathway results in a 93% reduction 
in lifecycle GHG emissions compared to the petroleum fuel baseline.
    Additionally, while the final results reported in this rule include 
an electricity credit, this electricity credit is based on current 
technology for generating electricity; it is possible that over the 
next decade as cellulosic biofuel production matures, the efficiency 
with which electricity is generated at these facilities will also 
improve. Such efficiency improvements will tend to improve the GHG 
performance for cellulosic biofuel technologies in general including 
those used to produce renewable gasoline.
    Furthermore, industry has identified other areas for energy 
improvements which our current pathway analyses do not include. 
Therefore, the results we have come up with for the individual pathway 
types represent conservative estimates and any variations in the 
pathways considered are likely to result in greater GHG reductions that 
what is considered here. For example, the variation of the catalytic 
pyrolysis route considered here resulted in a 67% reduction in 
lifecycle GHG emissions compared to the petroleum baseline. However, as 
was mentioned this was based on data from our NREL modeling and 
industry CBI data indicated more efficient energy performance which, if 
realized, would improve GHG performance. Another area for improvement 
in this pathway could be the use of anaerobic digestion to treat 
organics in waste water. If the anaerobic digestion is on-site, then 
enough biogas could potentially be produced to replace all of the 
fossil natural gas used as fuel and about half the natural gas fed for 
hydrogen production.\61\ Thus, fossil natural gas consumption could be 
further minimized under certain scenarios. We believe that as 
commercial scale cellulosic facilities develop, more of these 
improvements will be made to maximize the use of all the biomass and 
waste byproducts available to bring the facility closer to energy self-
sufficiency. These improvements could help to increase the economic 
profitability for cellulosic facilities where fossil energy inputs 
become costly to purchase. Therefore we can extend the modeling results 
for our pyrolysis route to all variations of this production technology 
which use natural gas, biogas or biomass for production energy for 
producing renewable gasoline or renewable gasoline blendstock.
---------------------------------------------------------------------------

    \61\ Kinchin, Christopher. Catalytic Fast Pyrolysis with 
Upgrading to Gasoline and Diesel Blendstocks. National Renewable 
Energy Laboratory (NREL). 2011.
---------------------------------------------------------------------------

    The F-T gasification technology route considered as part of the 
RFS2 final rule resulted in an approximately 91% reduction in lifecycle 
GHG emissions compared to the petroleum baseline. This could be 
considered a conservative estimate as the process did not assume any 
excess electricity production, which as mentioned above could lead to 
additional GHG reductions. The F-T process involves gasifying biomass 
into syngas (mix of H2 and CO) and then converting the 
syngas through a catalytic process into a hydrocarbon mix that is 
further refined into finished product. The F-T process considered was 
based on producing both gasoline and diesel fuel so that it was not 
optimized for renewable gasoline production. A process for producing 
primarily renewable gasoline rather than diesel from a gasification 
route should not result in a significantly worse GHG impacts compared 
to the mixed fuel process analyzed. Furthermore, as the lifecycle GHG 
reduction from the F-T process considered was around 91%, there is 
considerable room for variations in this route to still meet the 60% 
lifecycle GHG reduction threshold for cellulosic fuels. Therefore, in 
addition to the F-T process orginially analyzed for producing naphtha, 
we can extend the results based on the above analyses to include all 
variations of the gasification route which use natural gas, biogas or 
biomass for production energy for producing renewable gasoline or 
renewable gasoline blendstock. These variations include for example 
different catalysts and different refining processes to produce 
different mixes of final fuel product. While the current Table 1 entry 
in the regulations does not specify process energy sources, we are 
adding these specific eligible energy sources since we have not 
analyzed other energy sources (e.g. coal) as also allowing the pathway 
to meet the GHG performance threshold.
    There is an even wider gap between the results modeled for the 
direct fermentation route and the cellulosic lifecycle GHG threshold. 
The variation we considered for the direct fermentation process 
resulted in an approximately 129% reduction in lifecycle GHG emissions 
compared to the petroleum baseline. This process did consider 
production of electricity as part of the process but as mentioned even 
if this was not the case the pathway would still easily fall below the 
60% lifecycle threshold for cellulosic biofuels. If actual emissions 
from other necessary changes to the direct biochemical fermentation to 
hydrocarbons process represent some small increment in GHG emissions, 
the pathway would still likely meet the threshold. Therefore, we can 
extend the results to all variations of the direct biochemical route 
for renewable gasoline or renewable gasoline blendstock production 
which use natural gas, biogas or biomass for production energy.
    The biochemical with catalytic upgrading route that we evaluated 
resulted in a 65% reduction in GHG emissions compared to the petroleum 
baseline. However, this can be considered a conservative estimate. For 
instance, the biochemical fermentation to gasoline via carboxylic acid 
route considered did not include the potential for generating steam 
from the combustion of undigested biomass and then using this steam for 
process energy. If this had been included, natural gas consumption 
could potentially be decreased which would lower the potential GHG 
emissions estimated from the process. Therefore, the scenario analyzed 
could be considered conservative in estimating actual natural gas 
usage. As was the case with the pyrolysis route considered, we believe 
that as commercial scale cellulosic facilities develop, improvements 
will be made to maximize the use of all the biomass and waste 
byproducts available to bring the facility closer to energy self-
sufficiency. These improvements help to increase the economic 
profitability for cellulosic facilities where fossil energy inputs 
become costly to purchase. The processes we analyzed for this 
rulemaking utilized a mix of natural gas and biomass for process 
energy, with biogas replacing natural gas providing improved GHG 
performance. We have not analyzed other fuel types (e.g., coal) and are 
therefore not approving processes that utilized other fuel sources at 
this point. Therefore, we are extending our results

[[Page 721]]

to include all variations of the biochemical with catalytic upgrading 
process utilizing natural gas, biogas or biomass for process energy.
    While actual cellulosic facilities may show some modifications to 
the process scenarios we have already analyzed, our results give a good 
indication of the range of emissions we could expect from processes 
producing renewable gasoline and renewable gasoline blendstock from 
cellulosic feedstock, all of which meet the 60% cellulosic biofuel 
threshold (assuming they are utilizing natural gas, biogas or biomass 
for process energy). Technology changes in the future are likely to 
increase efficiency to maximize profits, while also lowering lifecycle 
GHG emissions. Therefore, we have concluded that since all of the 
renewable gasoline or renewable gasoline blendstock fuel processing 
methods we have analyzed exceed the 60% threshold using specific 
cellulosic feedstock types, we can conclude that processes producing 
renewable gasoline or renewable gasoline blendstock that fit within the 
categories of process analyzed here and are produced from the same 
feedstock types and using natural gas, biogas or biomass for process 
energy use will also meet the 60% GHG reduction threshold. In addition, 
while other technologies may develop, we expect that they will only 
become commercially competitive if they have better yield (more gallons 
per ton of feedstock) or lower production cost due to lower energy 
consumption. Both of these factors would suggest better GHG 
performance. This would certainly be the case if such processes also 
relied upon using biogas and/or biomass as the primary energy source. 
Therefore based on our review of the existing primary cellulosic 
biofuel production processes, likely GHG emission improvements for 
existing or new technologies, and consideration of the positive GHG 
emissions benefits associated with using biogas and/or biomass for 
process energy, we are approving for cellulosic RIN generation any 
process for renewable gasoline and renewable gasoline blendstock 
production using specified cellulosic biomass feedstocks as long as the 
process utilizes biogas and/or biomass for all process energy.
5. Summary
    Three renewable gasoline and renewable gasoline blendstock pathways 
were compared to baseline petroleum gasoline, using the same value for 
baseline gasoline as in the RFS2 final rule analysis. The results of 
the analysis indicate that the renewable gasoline and renewable 
gasoline blendstock pathways result in a GHG emissions reduction of 65-
129% or better compared to the gasoline fuel it would replace using 
corn stover as a feedstock. Since the renewable gasoline and renewable 
gasoline blendstock pathways which use corn stover as a feedstock all 
exceed the 60% lifecycle GHG threshold requirements for cellulosic 
biofuel, and since these pathways capture the likely current 
technologies and since future technology improvements are likely to 
increase efficiency and lower GHG emissions, we have determined that 
all processes producing renewable gasoline or renewable gasoline 
blendstock from corn stover can qualify if they fall in the following 
process characterizations:
     Catalytic pyrolysis and upgrading utilizing natural gas, 
biogas, and/or biomass as the only process energy sources.
     Gasification and upgrading utilizing natural gas, biogas, 
and/or biomass as the only process energy sources.
     Direct fermentation utilizing natural gas, biogas, and/or 
biomass as the only process energy sources.
     Fermentation and upgrading utilizing natural gas, biogas, 
and/or biomass as the only process energy sources.
     Any process utilizing biogas and/or biomass as the only 
process energy sources.
    As was the case for extending corn stover results to other 
feedstocks in the RFS2 final rule, these results are also reasonably 
extended to feedstocks with similar or lower GHG emissions profiles, 
including the following feedstocks:
     Cellulosic biomass from crop residue, slash, pre-
commercial thinnings and tree residue, annual cover crops;
     Cellulosic components of separated yard waste;
     Cellulosic components of separated food waste; and
     Cellulosic components of separated MSW.
    For more information on the reasoning for extension to these other 
feedstocks refer to the feedstock production and distribution section 
or the RFS2 rulemaking (75 FR 14793-14795).
    Based on these results, today's rule includes pathways for the 
generation of cellulosic biofuel RINs for renewable gasoline or 
renewable gasoline blendstock produced by catalytic pyrolysis and 
upgrading, gasification and upgrading, direct fermentation, 
fermentation and upgrading, all utilizing natural gas, biogas, and/or 
biomass as the only process energy sources or any process utilizing 
biogas and/or biomass as the only energy sources, and using corn stover 
as a feedstock or the feedstocks noted above. In order to qualify for 
RIN generation, the fuel must meet the other definitional criteria for 
renewable fuel (e.g., produced from renewable biomass, and used to 
reduce or replace petroleum-based transportation fuel, heating oil or 
jet fuel) specified in the Clean Air Act and the RFS regulations.
    A manufacturer of a renewable motor vehicle gasoline (including 
parties using a renewable blendstock obtained from another party), must 
satisfy EPA motor vehicle registration requirements in 40 CFR Part 79 
for the fuel to be used as a transportation fuel. Per 40 CFR 
79.56(e)(3)(i), a renewable motor vehicle gasoline would be in the Non-
Baseline Gasoline category or the Atypical Gasoline category (depending 
on its properties) since it is not derived only from conventional 
petroleum, heavy oil deposits, coal, tar sands and/or oil sands (40 CFR 
79.56(e)(3)(i)(5)).In either case, the Tier 1 requirements at 40 CFR 
79.52 (emissions characterization) and the Tier 2 requirements at 40 
CFR 79.53 (animal exposure) are conditions for registration unless the 
manufacturer qualifies for a small business provision at 40 CFR 
79.58(d). For a non-baseline gasoline, a manufacturer under $50 million 
in annual revenue is exempt from Tier 1 and Tier 2. For an atypical 
gasoline there is no exemption from Tier 1, but a manufacturer under 
$10 million in annual revenue is exempt from Tier 2.
    Registration for a motor vehicle gasoline at 40 CFR 79 is via EPA 
Form 3520-12, Fuel Manufacturer Notification for Motor Vehicle Fuel, 
available at: http://www.epa.gov/otaq/regs/fuels/ffarsfrms.htm.

D. Esterification Production Process Inclusion for Specified Feedstocks 
Producing Biodiesel

    Table 14, shown below, includes pathways for biodiesel using 
specified feedstocks and the production process transesterification. 
Transesterification is the most commonly used method to produce 
biodiesel (i.e., methyl esters) by

[[Page 722]]

reacting triglycerides with methanol typically under the presence of a 
base catalyst, see the simplified form in Equation 1.\62\
---------------------------------------------------------------------------

    \62\ Commonly used base catalysts include sodium hydroxide 
(NaOH), potassium hydroxide (KOH) and sodium methoxide 
(NaOCH3).

                     Table 14--Excerpts of Existing Fuel Pathways From Sec.   40 CFR 80.1426
----------------------------------------------------------------------------------------------------------------
                                                        Production process
            Fuel type                  Feedstock           requirements                    D-Code
----------------------------------------------------------------------------------------------------------------
Biodiesel, and renewable diesel.  Soy bean oil; Oil    One of the           4 (Biomass-Based Diesel).
                                   from annual          following: Trans-
                                   covercrops; Algal    Esterification
                                   oil; Biogenic        Hydrotreating
                                   waste oils/fats/     Excluding
                                   greases; Non-food    processes that co-
                                   grade corn oil.      process renewable
                                                        biomass and
                                                        petroleum.
Biodiesel, and renewable diesel.  Soy bean oil; Oil    One of the           5 (Advanced Biofuel).
                                   from annual          following: Trans-
                                   covercrops; Algal    Esterification
                                   oil; Biogenic        Hydrotreating
                                   waste oils/fats/     Includes only
                                   greases; Non-food    processes that co-
                                   grade corn oil.      process renewable
                                                        biomass and
                                                        petroleum.
----------------------------------------------------------------------------------------------------------------

                                                                            [GRAPHIC] [TIFF OMITTED] TR05JA12.008
                                                                            
    While triglycerides are usually the main component of oils, fats, 
and grease feedstocks, there are other components such as free fatty 
acids (FFAs) that are typically removed prior to transesterification. 
Removal or conversion of FFAs is important if the traditional base-
catalyzed transesterification production process is used since FFAs 
will react with base catalysts to produce soaps that inhibit the 
transesterification reaction. Table 15 below gives the usual ranges for 
FFAs found in biodiesel feedstocks.

          Table 15--Ranges of FFA in Biodiesel Feedstocks 63 64
------------------------------------------------------------------------
                                                              Percentage
                    Biodiesel feedstock                          FFA
------------------------------------------------------------------------
Refined vegetable oils.....................................        <0.05
Crude vegetable oils.......................................      0.3-0.7
Restaurant waste grease....................................          2-7
Yellow grease..............................................          <15
Animal fat.................................................         5-30
Brown grease...............................................          >15
Trap grease................................................       40-100
------------------------------------------------------------------------

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

    \63\ Van Gerpen, J., Shanks, B., Pruszko, R., Clements, D., 
Knothe, G., ``Biodiesel Production Technology,'' NREL/SR-510-36244, 
July 2004.
    \64\ Van Gerpen, J., ``Used and Waste Oil and Grease for 
Biodiesel,'' NC State University A&T State University Cooperative 
Extension, http://www.extension.org/pages/Used_and_Waste_Oil_and_Grease_for_Biodiesel.
---------------------------------------------------------------------------

    One of the most widely used methods for treating biodiesel 
feedstocks with higher FFA content is acid catalysis. Acid catalysis 
typically uses a strong acid such as sulfuric acid to catalyze the 
esterification of the FFAs and the transesterification of the 
triglycerides. The simplified form of the esterification process is 
given below in Equation 2. Acid esterification can be applied to 
feedstocks with FFA contents above 5%. Because the transesterification 
of triglycerides is slow under acid catalysis, a technique commonly 
used to overcome the reaction rate issue is to first convert the FFAs 
through an acid esterification (also known as an acid ``pretreatment'' 
step), and then follow-up with the traditional base-catalyzed 
transesterification of triglycerides. See Figure 2 for a general flow 
diagram of the acid esterification and subsequent transesterification 
biodiesel process.
[GRAPHIC] [TIFF OMITTED] TR05JA12.009


[[Page 723]]


[GRAPHIC] [TIFF OMITTED] TR05JA12.010

    Under the RFS2 final rule, biodiesel from biogenic waste oils/fats/
greases qualifies for D-Codes 4 and 5 using a ``transesterification'' 
process. This conclusion was based on the analysis of yellow grease as 
a feedstock in a process where there was an acid ``pretreatment'' or 
``esterification'' process to treat the FFAs contained in the 
feedstock. In fact, one of the material inputs assumed in the modeling 
for the final RFS2 rule yellow grease pathway is sulfuric acid, which 
is the catalyst commonly used for acid esterification. However, we had 
not stipulated ``esterification'' as a qualified production process in 
Table 1 to Sec.  40 CFR 80.1426. We believe this ambiguity could 
unnecessarily cause confusion as to whether esterification can also be 
used for the production of biodiesel under the currently approved 
pathways.
    Since the biodiesel modeling completed for the final RFS2 rule 
actually includes esterification upstream of the transesterification 
process, we find it appropriate to clarify Table 1 to Sec.  40 CFR 
80.1426 to include ``esterification'' as a qualified process in which 
to produce biodiesel. As the modeling for yellow grease met an 86% GHG 
reduction emissions level, and yellow grease is typically <15% FFA 
content, it is reasonable to conclude that esterification and 
subsequent transesterification with a yellow grease feedstock 
containing FFAs at the very least up to 15% can meet the GHG reduction 
threshold for biomass-based diesel and advanced biofuel of 50%.
    As noted in Table 15, however, there are feedstocks that may 
contain even higher levels of FFAs. As described below, EPA has 
evaluated the use of these higher FFA feedstocks to make biodiesel and 
has determined that use of such feedstocks also results in a biodiesel 
with lifecycle GHG emissions at least 50% less than that of 
conventional fuel.
    The National Biodiesel Board (NBB) has conducted a comprehensive 
survey of the actual energy used by commercial biodiesel production 
plants in the U.S.\65\ The survey depicts the amount of energy and 
incidental process materials such as acids used to produce a gallon of 
biodiesel. The survey data returned represents 37% of the surveyed 230 
NBB biodiesel members in 2008 and includes producers using a variety of 
virgin oils and recycled or reclaimed fats and oils. While there is no 
specific data on the FFA content of the feedstocks used, the feedstocks 
did include reclaimed greases which represent the feedstocks which 
typically have the highest FFA content. As the data is partially 
aggregated, we used the maximum surveyed electricity and natural gas 
used at the facilities and a high estimate of ``materials used'' based 
on a sum of industry averages for all process materials for calculating 
potential GHG emissions. Even though some of the facilities might be 
processing feedstocks with relatively low FFA content, we believe that 
using these maximum observed inputs for energy used plus a high 
estimate for process materials used will estimate the highest GHG 
emissions profile for biodiesel production GHG emissions. When combined 
with the feedstock GHG emissions impact (see discussion below), the 
results still predict a GHG emissions reduction comfortably exceeding 
50% as compared to the petroleum fuel it displaces. Therefore, there is 
little risk in predicting that any facility that utilizes 
esterification and feedstock over the range of likely FFA content can 
meet the 50% biomass-based diesel and advanced biofuel threshold.
---------------------------------------------------------------------------

    \65\ National Biodiesel Board, Comprehensive Survey on Energy 
Use for Biodiesel Production (2008) http://www.biodiesel.org/news/RFS/rfs2docs/NBB%20Energy%20Use%20Survey%20FINAL.pdf.
---------------------------------------------------------------------------

    According to the survey, the maximum electricity use for a producer 
reached as high as 3,071 Btu per gallon biodiesel. This is about 5 
times higher than the industry average. The maximum natural gas usage 
for a producer reached as high as 12,324 Btu per gallon biodiesel, 
which is about 3.5 times higher than the industry average. For 
``materials used'' only an industry average for each material was 
provided in the survey. Therefore, as a conservative estimate, we 
totaled all the average material inputs to equal 0.51 kg/gal 
biodiesel.\66\ We believe that this is conservative because not all 
facilities are likely to use each and every one of the process 
materials listed in the survey (e.g., we totaled all the acids

[[Page 724]]

used even though a facility is not likely to use each different acid). 
Thus, our estimate of materials used will estimate a level of maximum 
usage of materials at a given facility. In addition, we did not include 
a glycerin co-product credit when calculating emissions since the 
esterification reaction does not produce glycerin (see Equation 2). 
Using the same methodology as was used for the yellow grease modeling 
under RFS2, but using the high energy and materials use assumptions per 
the above discussion and omitting the glycerin co-product credit, we 
estimate the emissions from biodiesel processing at 23,708 
gCO2eq per mmBtu of biodiesel. The estimated GHG emissions 
reduction for the entire process is -71%. Since the GHG threshold is at 
-50% for biomass-based diesel and advanced biofuel, we believe that 
there is a large enough margin in the results to reasonably conclude 
that biodiesel using esterification of specified feedstocks with any 
level of FFA content meets the biomass-based diesel and advanced 
biofuel 50% lifecycle GHG reduction threshold. Therefore, we are 
including the process ``esterification'' as an approved biodiesel 
production process in Table 1 to Sec.  40 CFR 80.1426. In addition, 
consistent with the modeling conducted for RFS2, we interpret the RFS 
regulations as they existed prior to today's rule as including a direct 
esterification process as part of the biodiesel pathways for which only 
``trans-esterification'' was specifically referenced in Table 1 to 
Sec.  40 CFR 80.1426.
---------------------------------------------------------------------------

    \66\ The material inputs include methanol, sodium methylate, 
sodium hydroxide, potassium hydroxide, hydrochloric acid, sulfuric 
acid, phosphoric acid, and citric acid. The majority of material 
input is from methanol.
---------------------------------------------------------------------------

V. Additional Changes to Listing of Available Pathways in Table 1 of 
80.1426

    We are also finalizing two changes to Table 1 to 80.1426 that were 
proposed on July 1, 2011 (76 FR 38844). The first change adds ID 
letters to pathways to facilitate references to specific pathways. The 
second change adds ``rapeseed'' to the existing pathway for renewable 
fuel made from canola oil.
    On September 28, 2010, EPA published a ``Supplemental Determination 
for Renewable Fuels Produced Under the Final RFS2 Program from Canola 
Oil'' (FR Vol. 75, No. 187, pg 59622-59634). In the July 1, 2011 NPRM 
(76 FR 38844) we proposed to clarify two aspects of the supplemental 
determination. First we proposed to amend the regulatory language in 
Table 1 to Sec.  80.1426 to clarify that the currently-approved pathway 
for canola also applies more generally to rapeseed. While ``canola'' 
was specifically described as the feedstock evaluated in the 
supplemental determination, we had not intended the supplemental 
determination to cover just those varieties or sources of rapeseed that 
are identified as canola, but to all rapeseed. As described in the July 
1, 2011 NPRM, we currently interpret the reference to ``canola'' in 
Table 1 to Sec.  80.1426 to include any rapeseed. To eliminate 
ambiguity caused by the current language, however, we proposed to 
replace the term ``canola'' in that table with the term ``canola/
rapeseed''. Canola is a type of rapeseed. While the term ``canola'' is 
often used in the American continent and in Australia, the term 
``rapeseed'' is often used in Europe and other countries to describe 
the same crop. We received no adverse comments on our proposal, and 
thus are finalizing it as proposed. This change will enhance the 
clarity of the regulations regarding the feedstocks that qualify under 
the approved canola biodiesel pathway.
    Second, we wish to clarify that although the GHG emissions of 
producing fuels from canola feedstock grown in the U.S. and Canada was 
specifically modeled as the most likely source of canola (or rapeseed) 
oil used for biodiesel produced for sale and use in the U.S., we also 
intended that the approved pathway cover canola/rapeseed oil from other 
countries, and we interpret our regulations in that manner. We expect 
the vast majority of biodiesel used in the U.S. and produced from 
canola/rapeseed oil will come from U.S. and Canadian crops. Incidental 
amounts from crops produced in other nations will not impact our 
average GHG emissions for two reasons. First, our analyses considered 
world-wide impacts and thus considered canola/rapeseed crop production 
in other countries. Second, other countries most likely to be exporting 
canola/rapeseed or biodiesel product from canola/rapeseed are likely to 
be major producers which typically use similar cultivars and farming 
techniques. Therefore, GHG emissions from producing biodiesel with 
canola/rapeseed grown in other countries should be very similar to the 
GHG emissions we modeled for Canadian and U.S. canola, though they 
could be slightly (and insignificantly) higher or lower. At any rate, 
even if there were unexpected larger differences, EPA believes the 
small amounts of feedstock or fuel potentially coming from other 
countries will not impact our threshold analysis. Therefore, EPA 
interprets the approved canola pathway as covering canola/rapeseed 
regardless of country origin.

VI. Statutory and Executive Order Reviews

A. Executive Order 12866: Regulatory Planning and Review

    This action is not a ``significant regulatory action'' under the 
terms of Executive Order 12866 (58 FR 51735, October 4, 1993) and is 
therefore not subject to review under Executive Orders 12866 and 13563 
(76 FR 3821, January 21, 2011).

B. Paperwork Reduction Act

    This action does not impose any new information collection burden. 
The corrections, clarifications, and modifications to the final RFS2 
regulations contained in this rule are within the scope of the 
information collection requirements submitted to the Office of 
Management and Budget (OMB) for the final RFS2 regulations.
    OMB has approved the information collection requirements contained 
in the existing regulations at 40 CFR part 80, subpart M under the 
provisions of the Paperwork Reduction Act, 44 U.S.C. 3501 et seq. and 
has assigned OMB control numbers 2060- 0637 and 2060-0640. The OMB 
control numbers for EPA's regulations in 40 CFR are listed in 40 CFR 
part 9.

C. Regulatory Flexibility Act

    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; (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.
    After considering the economic impacts of this action on small 
entities, I certify that this rule will not have a significant economic 
impact on a substantial number of small entities. This rule will not 
impose any new requirements on small entities. The

[[Page 725]]

relatively minor corrections and modifications this rule makes to the 
final RFS2 regulations do not impact small entities.

D. Unfunded Mandates Reform Act

    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. 
We have determined that this action will not result in expenditures of 
$100 million or more for the above parties and thus, this rule is not 
subject to the requirements of sections 202 or 205 of UMRA.
    This rule is also not subject to the requirements of section 203 of 
UMRA because it contains no regulatory requirements that might 
significantly or uniquely affect small governments. It only applies to 
gasoline, diesel, and renewable fuel producers, importers, distributors 
and marketers and makes relatively minor corrections and modifications 
to the RFS2 regulations.

E. Executive Order 13132 (Federalism)

    This action 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. This action only applies to 
gasoline, diesel, and renewable fuel producers, importers, distributors 
and marketers and makes relatively minor corrections and modifications 
to the RFS2 regulations. Thus, Executive Order 13132 does not apply to 
this action.

F. Executive Order 13175 (Consultation and Coordination With Indian 
Tribal Governments)

    This rule does not have tribal implications, as specified in 
Executive Order 13175 (65 FR 67249, November 9, 2000). It applies to 
gasoline, diesel, and renewable fuel producers, importers, distributors 
and marketers. This action makes relatively minor corrections and 
modifications to the RFS regulations, and does not impose any 
enforceable duties on communities of Indian tribal governments. Thus, 
Executive Order 13175 does not apply to this action.

G. Executive Order 13045: Protection of Children From Environmental 
Health Risks and Safety Risks

    EPA interprets EO 13045 (62 FR 19885, April 23, 1997) as applying 
only to those regulatory actions that concern health or safety risks, 
such that the analysis required under section 5-501 of the EO has the 
potential to influence the regulation. This action is not subject to EO 
13045 because it does not establish an environmental standard intended 
to mitigate health or safety risks.

H. Executive Order 13211: Actions Concerning Regulations That 
Significantly Affect Energy Supply, Distribution, or Use

    This rule is not subject to Executive Order 13211 (66 FR 18355 (May 
22, 2001)), because it is not a significant regulatory action under 
Executive Order 12866.

I. National Technology Transfer and 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. NTTAA directs EPA to provide 
Congress, through OMB, explanations when the Agency decides not to use 
available and applicable voluntary consensus standards.
    This action does not involve technical standards. Therefore, EPA 
did not consider the use of any voluntary consensus standards.

J. Executive Order 12898: Federal Actions To Address Environmental 
Justice in Minority Populations and Low-Income Populations

    Executive Order (EO) 12898 (59 FR 7629 (Feb. 16, 1994)) establishes 
Federal executive policy on environmental justice. Its main provision 
directs Federal agencies, to the greatest extent practicable and 
permitted by law, to make environmental justice part of their mission 
by identifying and addressing, as appropriate, disproportionately high 
and adverse human health or environmental effects of their programs, 
policies, and activities on minority populations and low-income 
populations in the United States.
    EPA has determined that this rule will not have disproportionately 
high and adverse human health or environmental effects on minority or 
low-income populations because it does not affect the level of 
protection provided to human health or the environment. These 
amendments would not relax the control measures on sources regulated by 
the RFS regulations and therefore would not cause emissions increases 
from these sources.

K. Congressional Review Act

    The Congressional Review Act, 5 U.S.C. 801 et seq., as added by the 
Small Business Regulatory Enforcement Fairness Act of 1996, generally 
provides that before a rule may take effect, the agency promulgating 
the rule must submit a rule report, which includes a copy of the rule, 
to each House of the Congress and to the Comptroller General of the 
United States. A major rule cannot take effect until 60 days after it 
is published in the Federal Register. EPA will submit a report 
containing this rule and other required information to the U.S. Senate, 
the U.S. House of Representatives, and the Comptroller General of the 
United States prior to publication of the rule in the Federal Register. 
This action is not a ``major rule'' as defined by 5 U.S.C. 804(2).

VII. Statutory Provisions and Legal Authority

    Statutory authority for the rule finalized 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 rule, 
including the recordkeeping requirements, come from Sections 114, 208, 
and 301(a) of the Clean Air Act, 42 U.S.C. 7414, 7542, and 7601(a).

[[Page 726]]

List of Subjects in 40 CFR Part 80

    Environmental protection, Administrative practice and procedure, 
Agriculture, Air pollution control, Confidential business information, 
Diesel Fuel, Energy, Forest and forest products, Fuel additives, 
Gasoline, Imports, Labeling, Motor vehicle pollution, Penalties, 
Petroleum, Reporting and recordkeeping requirements.

    Dated: November 30, 2011.
Lisa P. Jackson,
Administrator.
    For the reasons set forth in the preamble, 40 CFR part 80 is 
amended as follows:

PART 80--REGULATION OF FUELS AND FUEL ADDITIVES

0
1. The authority citation for part 80 continues to read as follows:

    Authority: 42 U.S.C. 7414, 7521(1), 7545 and 7601(a).


0
2. Section 80.1401 is amended by addition of the following definitions 
of ``Renewable Gasoline'' and ``Renewable Gasoline Blendstock'' in 
alphabetical order to read as follows:


Sec.  80.1401  Definitions.

* * * * *
    Renewable gasoline means renewable fuel made from renewable biomass 
that is composed of only hydrocarbons and which meets the definition of 
gasoline in Sec.  80.2(c).
    Renewable gasoline blendstock means a blendstock made from 
renewable biomass that is composed of only hydrocarbons and which meets 
the definition of gasoline blendstock in Sec.  80.2(s).
* * * * *

0
3. Section 80.1426 is amended by revising Table 1 in paragraph (f)(1) 
to read as follows:


Sec.  80.1426  How are RINs generated and assigned to batches of 
renewable fuel by renewable fuel producers or importers?

* * * * *
    (f) * * *
    (1) * * *

         Table 1 to Sec.   80.1426--Applicable D Codes for Each Fuel Pathway for Use in Generating RINs
----------------------------------------------------------------------------------------------------------------
                                                                              Production process
               Fuel type                           Feedstock                     requirements            D-Code
----------------------------------------------------------------------------------------------------------------
A Ethanol.............................  Corn starch...................  All of the following: Dry mill         6
                                                                         process, using natural gas,
                                                                         biomass, or biogas for
                                                                         process energy and at least
                                                                         two advanced technologies
                                                                         from Table 2 to this section.
B Ethanol.............................  Corn starch...................  All of the following: Dry mill         6
                                                                         process, using natural gas,
                                                                         biomass, or biogas for
                                                                         process energy and at least
                                                                         one of the advanced
                                                                         technologies from Table 2 to
                                                                         this section plus drying no
                                                                         more than 65% of the
                                                                         distillers grains with
                                                                         solubles it markets annually.
C Ethanol.............................  Corn starch...................  All of the following: Dry mill         6
                                                                         process, using natural gas,
                                                                         biomass, or biogas for
                                                                         process energy and drying no
                                                                         more than 50% of the
                                                                         distillers grains with
                                                                         solubles it markets annually.
D Ethanol.............................  Corn starch...................  Wet mill process using biomass         6
                                                                         or biogas for process energy.
E Ethanol.............................  Starches from crop residue and  Fermentation using natural             6
                                         annual covercrops.              gas, biomass, or biogas for
                                                                         process energy.
F Biodiesel, renewable diesel, jet      Soy bean oil; Oil from annual   One of the following: Trans-           4
 fuel and heating oil.                   covercrops; Algal oil;          Esterification,
                                         Biogenic waste oils/fats/       Esterification Hydrotreating
                                         greases; Non-food grade corn    Excluding processes that co-
                                         oil; Camelina oil.              process renewable biomass and
                                                                         petroleum.
G Biodiesel, heating oil..............  Canola/Rapeseed oil...........  Trans-Esterification using             4
                                                                         natural gas or biomass for
                                                                         process energy.
H Biodiesel, renewable diesel, jet      Soy bean oil; Oil from annual   One of the following: Trans-           5
 fuel and heating oil.                   covercrops; Algal oil;          Esterification,
                                         Biogenic waste oils/fats/       Esterification Hydrotreating
                                         greases; Non-food grade corn    Includes only processes that
                                         oil Camelina oil.               co-process renewable biomass
                                                                         and petroleum.
I Naphtha, LPG........................  Camelina oil..................  Hydrotreating.................         5
J Ethanol.............................  Sugarcane.....................  Fermentation..................         5
K Ethanol.............................  Cellulosic Biomass from crop    Any...........................         3
                                         residue, slash, pre-
                                         commercial thinnings and tree
                                         residue, annual covercrops,
                                         switchgrass, miscanthus,
                                         napiergrass, giant reed, and
                                         energy cane; cellulosic
                                         components of separated yard
                                         waste; cellulosic components
                                         of separated food waste; and
                                         cellulosic components of
                                         separated MSW.
L Cellulosic Diesel, jet fuel and       Cellulosic Biomass from crop    Any...........................         7
 heating oil.                            residue, slash, pre-
                                         commercial thinnings and tree
                                         residue, annual covercrops,
                                         switchgrass, miscanthus,
                                         napiergrass, giant reed and
                                         energy cane; cellulosic
                                         components of separated yard
                                         waste; cellulosic components
                                         of separated food waste; and
                                         cellulosic components of
                                         separated MSW.

[[Page 727]]

 
M Renewable Gasoline and Renewable      Cellulosic Biomass from crop    Catalytic Pyrolysis,                   3
 Gasoline Blendstock.                    residue, slash, pre-            Gasification and Upgrading,
                                         commercial thinnings, tree      Direct Fermentation,
                                         residue, annual cover crops;    Fermentation and Upgrading,
                                         cellulosic components of        all utilizing natural gas,
                                         separated yard waste;           biogas, and/or biomass as the
                                         cellulosic components of        only process energy sources.
                                         separated food waste; and       Any process utilizing biogas
                                         cellulosic components of        and/or biomass as the only
                                         separated MSW.                  process energy sources.
N Butanol.............................  Corn starch...................  Fermentation; dry mill using           6
                                                                         natural gas, biomass, or
                                                                         biogas for process energy.
O Ethanol, renewable diesel, jet fuel,  The non-cellulosic portions of  Any...........................         5
 heating oil, and naphtha.               separated food waste.
P Biogas..............................  Landfills, sewage waste         Any...........................         5
                                         treatment plants, manure
                                         digesters.
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[FR Doc. 2011-31580 Filed 1-4-12; 8:45 am]
BILLING CODE 6560-50-P