[Federal Register Volume 78, Number 43 (Tuesday, March 5, 2013)]
[Rules and Regulations]
[Pages 14190-14217]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2013-04929]


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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 80

[EPA-HQ-OAR-2011-0542; FRL-9686-3]
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: Final rule.

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SUMMARY: EPA is issuing a 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 (RFS) Program, as amended by the Energy 
Independence and Security Act of 2007 (EISA). This final rule describes 
EPA's evaluation of biofuels produced from camelina (Camelina sativa) 
oil and energy cane; it also includes an evaluation of renewable 
gasoline and renewable gasoline blendstocks, and clarifies our 
definition of renewable diesel. The inclusion of these pathways creates 
additional opportunity and flexibility for regulated parties to comply 
with the advanced and cellulosic requirements of EISA and provides the 
certainty necessary for investments to bring these biofuels into 
commercial production from these new feedstocks.
    We are not finalizing at this time determinations on biofuels 
produced from giant reed (Arundo donax) or napier grass (Pennisetum 
purpureum) or biodiesel produced from esterification. We continue to 
consider the issues concerning these proposals, and will make a final 
decision on them at a later time.

DATES: This rule is effective on May 6, 2013.

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:

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:

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                                                NAICS \1\                     Examples of potentially regulated
                  Category                        Codes       SIC \2\ Codes                entities
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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.
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\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.

Outline of This Preamble

I. Executive Summary
    A. Purpose of the Regulatory Action
    B. Summary of the Major Provisions of the Regulatory Action In 
Question
II. Identification of Additional Qualifying Renewable Fuel Pathways 
Under the Renewable Fuel Standard (RFS) Program
    A. Analysis of Lifecycle Greenhouse Gas Emissions for Biodiesel, 
Renewable Diesel, Jet Fuel, Heating Oil, Naphtha, and Liquefied 
Petroleum Gas (LPG) Produced From Camelina Oil
    B. Lifecycle Greenhouse Gas Emissions Analysis for Ethanol, 
Diesel, Jet Fuel, Heating Oil, and Naphtha Produced From Energy Cane
    C. Lifecycle Greenhouse Gas Emissions Analysis for Certain 
Renewable Gasoline and Renewable Gasoline Blendstocks Pathways
    D. Esterification Production Process Inclusion for Specified 
Feedstocks Producing Biodiesel
III. Additional Changes to Listing of Available Pathways in Table 1 
of 80.1426
IV. Statutory and Executive Order Reviews
    A. Executive Order 12866: Regulatory Planning and Review and 
Executive Order 13563: Improving Regulation and Regulatory Review
    B. Paperwork Reduction Act
    C. Regulatory Flexibility Act
    D. Unfunded Mandates Reform Act
    E. Executive Order 13132 (Federalism)
    F. Executive Order 13175 (Consultation and Coordination With 
Indian Tribal Governments)
    G. Executive Order 13045: Protection of Children From 
Environmental Health Risks and Safety Risks
    H. Executive Order 13211: Actions Concerning Regulations That 
Significantly Affect Energy Supply, Distribution, or Use
    I. National Technology Transfer and Advancement Act
    J. Executive Order 12898: Federal Actions To Address 
Environmental Justice in Minority Populations and Low-Income 
Populations
    K. Congressional Review Act
V. Statutory Provisions and Legal Authority

I. Executive Summary

A. Purpose of This Regulatory Action

    In this rulemaking, EPA is taking final action to identify 
additional fuel

[[Page 14191]]

pathways that we have determined meet the greenhouse gas (GHG) 
reduction requirements under the Renewable Fuel Standard (RFS) program. 
This final rule describes EPA's evaluation of biofuels produced from 
camelina (Camelina sativa) oil, which qualify as biomass-based diesel 
or advanced biofuel, as well as biofuels from energy cane which qualify 
as cellulosic biofuel. This final rule also qualifies renewable 
gasoline and renewable gasoline blendstock made from certain qualifying 
feedstocks as cellulosic biofuel. Finally, this rule clarifies the 
definition of renewable diesel to explicitly include jet fuel.
    EPA is taking this action as a result of changes to the RFS program 
in Clean Air Act (``CAA'') Section 211(o) required by the Energy 
Independence and Security Act of 2007 (``EISA''). This rulemaking 
modifies the RFS regulations published at 40 CFR Sec.  80.1400 et seq. 
The RFS program regulations specify the types of renewable fuels 
eligible to participate in the RFS program and the procedures by which 
renewable fuel producers and importers may generate Renewable 
Identification Numbers (``RINs'') for the qualifying renewable fuels 
they produce through approved fuel pathways. See 75 FR 14670 (March 26, 
2010); 75 FR 26026 (May 10, 2010); 75 FR 37733 (June 30, 2010); 75 FR 
59622 (September 28, 2010); 75 FR 76790 (December 9, 2010); 75 FR 79964 
(December 21, 2010); 77 FR 1320 (January 9, 2012); and 77 FR 74592 
(December 17, 2012).
    By qualifying these new fuel pathways, this rule provides 
opportunities to increase the volume of advanced, low-GHG renewable 
fuels--such as cellulosic biofuels--under the RFS program. EPA's 
comprehensive analyses show significant lifecycle GHG emission 
reductions from these fuel types, as compared to the baseline gasoline 
or diesel fuel that they replace.

B. Summary of the Major Provisions of the Regulatory Action In Question

    This final rule describes EPA's evaluation of:
    Camelina (Camelina sativa) oil (new feedstock)
     Biodiesel, and renewable diesel, (including jet fuel, and 
heating oil)--qualifying to generate biomass-based diesel and advanced 
biofuel RINs
     Naphtha and liquefied petroleum gas (LPG)--qualifying to 
generate advanced biofuel RINs
    Energy cane cellulosic biomass (new feedstock)
     Ethanol, renewable diesel (including renewable jet fuel 
and heating oil), and renewable gasoline blendstock--qualifying to 
generate cellulosic biofuel RINs
    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 
to generate cellulosic biofuel RINs:
    [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
    This final rule adds these pathways to Table 1 to Sec.  80.1426. 
This final rule allows producers or importers of fuel produced under 
these pathways to generate RINs in accordance with the RFS regulations, 
providing that the fuel meets other definitional criteria for renewable 
fuel. The inclusion of these pathways creates additional opportunity 
and flexibility for regulated parties to comply with the requirements 
of EISA. Substantial investment has been made to commercialize these 
new feedstocks, and the cellulosic biofuel industry in the United 
States continues to make significant advances in its progress towards 
large scale commercial production. Approval of these new feedstocks 
will help further the Congressional intent to expand the volumes of 
cellulosic and advanced biofuels.
    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.

II. Identification of Additional Qualifying Renewable Fuel Pathways 
Under the Renewable Fuel Standard (RFS) Program

    This rule was originally published in the Federal Register at 77 FR 
462, January 5, 2012 as a direct final rule, with a parallel 
publication of a proposed rule. A limited number of relevant adverse 
comments were received, and EPA published a withdrawal notice of the 
direct final rule on March 5, 2012 (77 FR 13009). A second comment 
period was not issued, since the simultaneous publication of the 
proposed rule provided an adequate notice and comment process. EPA is 
finalizing several of the proposed actions in this final rule, but 
continues to consider determinations on biofuels produced from giant 
reed (Arundo donax) or napier grass (Pennisetum purpureum) or biodiesel 
produced from esterification. EPA will make a final decision on theses 
elements of the proposal at a later time.
    In this action, EPA is issuing a 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. There are three critical components of a renewable fuel 
pathway: (1) Fuel type, (2) feedstock, and (3) production process. Each 
specific combination of the three components, or fuel pathway, is 
assigned a D code which is used to designate the type of biofuel and 
its compliance category under the RFS program. This final rule 
describes EPA's lifecycle GHG evaluation of camelina oil and energy 
cane.
    Determining whether a fuel pathway satisfies the CAA's lifecycle 
GHG 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

[[Page 14192]]

Standard Program Final Rule, published March 26, 2010 (75 FR 14670) 
(March 2010 RFS). The evaluations here rely on comparisons to the 
existing analyses presented in the March 2010 final rule. 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, Heating Oil, Naphtha, and Liquefied 
Petroleum Gas (LPG) Produced From Camelina Oil

    The following sections describe EPA's evaluation of camelina 
(Camelina sativa) as a biofuel feedstock under the RFS program. As 
discussed previously, this analysis relies on a comparison to the 
lifecycle GHG analysis work that was done as part of the Renewable Fuel 
Standard Program (RFS) Final Rule, published March 26, 2010 for soybean 
oil biofuels.
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/publications/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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    In response to the proposed rule, EPA received comments 
highlighting the concern that by approving certain new feedstock types 
under the RFS program, EPA would be encouraging their introduction or 
expanded planting without considering their potential impact as 
invasive species.\8\ The degree of concern expressed by the commenters 
depended somewhat on the feedstock. As pointed out by the commenters, 
camelina and energy cane are not ``native species,'' defined as ``a 
species that, other than as a result of an introduction, historically 
occurred or currently occurs in that ecosystem.'' The commenters 
asserted that there is a ``potential risk posed by the non-native 
species camelina and energy cane.'' In contrast, comments stated that 
giant reed (Arundo donax) or napier grass (Pennisetum purpureum) have 
been identified as invasive species in certain parts of the country. 
These commenters asserted that the Arundo donax and napier grass pose a 
``clear risk of invasion.'' Commenters stated that EPA should not 
approve the proposed feedstocks until EPA has conducted an invasive 
species analysis, as required under Executive Order (EO) 13112.\9\
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    \8\ Comment submitted by Jonathan Lewis, Senior Counsel, Climate 
Policy, Clean Air Task Force et al., dated February 6, 2012. 
Document ID  EPA-HQ-OAR-2011-0542-0118.
    \9\ http://www.gpo.gov/fdsys/pkg/FR-1999-02-08/pdf/99-3184.pdf.
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    The information before us does not raise significant concerns about 
the threat of invasiveness and related GHG emissions for camelina. For 
example, camelina is not listed on the Federal Noxious Weed List,\10\ 
nor is it listed on any state invasive species or noxious weed list. We 
believe that the production of camelina is unlikely to spread beyond 
the intended borders in which it is grown, which is consistent with the 
assumption in EPA's lifecycle analysis that significant expenditures of 
energy or other sources of GHGs will not be required to remediate the 
spread of this feedstock from the specific locations where it is grown 
as a renewable fuel feedstock for the RFS program. Therefore, we are 
finalizing the camelina pathway in this rule based on our lifecycle 
analysis discussed below.\11\
    Camelina is currently being grown on approximately 50,000 acres of 
land in the U.S., primarily in Montana, eastern Washington, and the 
Dakotas.\12\ 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.\13\
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    \10\ However, this list is not exhaustive and is generally 
limited to species that are not currently in the U.S. or are 
incipient to the U.S. See http:[sol][sol]plants.usda.gov/java/
noxious?rptType=Federal&statefips=&sort=sc. Accessed on March 28, 
2012.
    \11\ EPA continues to evaluate Arundo donax and napier grass as 
feedstock for a renewable fuel pathway, and will make a final 
decision on these pathways at a later time.
    \12\ McCormick, Margaret. ``Oral Comments of Targeted Growth, 
Incorporated'' Submitted to the EPA on June 9, 2009.
    \13\ See https:[sol][sol]www.camelinacompany.com/Marketing/
PressRelease.aspx?Id=25.
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    In response to the proposed rule, two commenters were supportive of 
the use of renewable feedstocks such as camelina oil to produce 
biofuels for aviation. One commenter noted that aviation is unique in 
its complete dependency upon liquid fuel--today and into the 
foreseeable future. Another commenter noted that development of 
additional feedstocks and production pathways should increase supply 
and ultimately move us closer to the day when renewable jet fuels are 
price-competitive with legacy fossil fuels and help cut our dependence 
on foreign oil. EPA also received comment regarding a concern that EPA 
did not adequately establish that camelina would only be grown on 
fallow land and therefore would not have a land use impact and that EPA 
overestimated the likely yields in growing camelina and therefore 
underestimated the land requirements.
    In terms of the comment on camelina not being grown on fallow land, 
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

[[Page 14193]]

expected to be primarily planted in the U.S. as a rotation crop on 
acres that would otherwise remain fallow.\14\ Because camelina has not 
yet been established as a commercial crop with significant monetary 
value, farmers are unlikely to dedicate acres for camelina production 
that could otherwise be used to produce other cash crops. Since 
camelina would therefore not be expected to displace another crop but 
rather maximize the value of the land through planting camelina in 
rotation, 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 commercial 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 expected to be 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.
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    \14\ Fallow land here refers to cropland that is periodically 
not cultivated.
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    Commenters stated that EPA failed to justify why camelina would be 
grown on fallow land and thus result in no land use change. In the 
proposed rule, EPA provided a detailed description of the economics 
indicating why producers are most likely to grow camelina on land that 
would otherwise remain fallow. This analysis formed the basis for why 
it was reasonable and logical for camelina to be grown on acres that 
would otherwise remain fallow. Comments also indicated that EPA's 
economic basis for assuming camelina would most likely be grown on 
fallow land was inadequate, especially if production of camelina was 
scaled up. However, the comment did not indicate any specific point of 
error in our economically based analysis. As we described in the 
proposed rule and discuss below, camelina is currently not a 
commercially raised crop in the United States, therefore the returns on 
camelina are expected to be low compared to wheat and other crops with 
established, commercially traded markets.\15\ Therefore, EPA expects 
that initial production of camelina for biofuel production will be on 
land with the lowest opportunity cost. Based on this logic, EPA 
believes camelina will be grown as a rotation crop, as discussed below, 
on dryland wheat acres replacing a period that the land would otherwise 
be left fallow.
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    \15\ 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.
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    In the semi-arid regions of the Northern Great Plains, dryland 
wheat farmers currently leave acres fallow once every three to four 
years to allow additional moisture and nutrients to accumulate (see 
Figure 1). Recent research indicates that introducing cool season 
oilseed crops such as camelina can provide benefits by reducing soil 
erosion, increasing soil organic matter, and disrupting pest cycles. 
Although long-term data on the effects of replacing wheat/fallow 
growing patterns with wheat/oilseed rotations is limited, there is some 
data that growing oilseeds in drier semi-arid regions year after year 
can lead to reduced wheat yields.\16\ However, the diversification and 
intensification of wheat-fallow cropping systems can improve the long 
term economic productivity of wheat acres by increasing soil nitrogen 
and soil organic carbon pools.\17\ In addition, selective breeding is 
expected to reduce the potential negative impacts on wheat yields.\18\ 
Additional research in this area is needed and if significant negative 
impacts on crop rotations are determined from camelina grown on fallow 
acres EPA would take that into account in future analysis.
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    \16\ Personal communication with Andrew Lenssen, Department of 
Agronomy, Iowa State University, April 17, 2012. See also http://www.ars.usda.gov/is/pr/2010/100413.htm.
    \17\ See Sainju, U.M., T. Caesar-Tonthat, A.W. Lenssen, R.G. 
Evans, and R. Kohlberg. 2007. Long-term tillage and cropping 
sequence effects on dryland residue and soil carbon fractions. Soil 
Science Society of America Journal 71: 1730-1739.
    \18\ See Shonnard et al., 2010; Lafferty et al., 2009.

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[[Page 14194]]

[GRAPHIC] [TIFF OMITTED] TR05MR13.014

    As pointed out by commenters, in the future camelina production 
could expand beyond what is currently assumed in this analysis. 
However, camelina would most likely not be able to compete with other 
uses of land until

[[Page 14195]]

it becomes a commercial crop with a well-established market value. EPA 
once again reiterates that we will continue to monitor the growing 
patterns associated with camelina to determine whether actual 
production is consistent with the assumptions used in this analysis. 
Monitoring will be done by tracking the amount of RIN generating 
camelina fuel produced through the EPA Moderated Transaction System 
(EMTS). We can compare the amount of RIN generating fuel against 
expected volumes from fallow acres in conjunction with USDA. Consistent 
with EPA's approach to all RFS feedstock pathway analyses, we will 
periodically reevaluate whether our assessment of GHG impacts will need 
to be updated in the future based on the potential for significant 
changes in our analyses.
a. Land Availability
    USDA estimates that there are approximately 60 million acres of 
wheat in the U.S.\19\ USDA and wheat state cooperative extension 
reports through 2008 indicate that 83% of US 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.\20\ 
Therefore, our analysis uses the estimate that only 9 million wheat/
fallow acres are available for camelina production.
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    \19\ 2009 USDA Baseline. See http://www.ers.usda.gov/publications/oce091/.
    \20\ 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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    One commenter stated that EPA assumed more than 8 million acres 
would be used to produce camelina, even though a recent paper stated 
that only 5 million acres would have the potential to grow camelina in 
a sustainable manner in a way that would not impact the food supply. 
This commenter misinterpreted EPA's assumptions. EPA's 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. In other 
words, EPA assumed only 3 million acres would be planted with camelina 
in any given year. This number is less than the 5 million acres the 
Shonnard et. al. paper states would be available annually for camelina 
planting.
b. 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.\21\ 
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.\22\ 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,\23\ 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.\24\ 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.\25\
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    \21\ Wheeler, P. and Guillen-Portal F. 2007. Camelina Production 
in Montana: A survey study sponsored by Targeted Growth, Inc. and 
Barkley Ag. Enterprises, LLP.
    \22\ 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.
    \23\ 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.
    \24\ See Shonnard et al., 2010.
    \25\ This assumes no significant adverse climate impacts on 
world agricultural yields over the analytical timeframe.
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    We also received comments that we overestimated long term camelina 
yields. The commentors stated that reaching yields of 3000 pounds per 
acre may be attainable, but previous trials do not suggest that yields 
could reach this level in ten years. As a point of clarification, we 
did not assume that yields would need to be 3000 pounds per acre for 
biodiesel produced from camelina oil to qualify as an advanced biofuel. 
In the analysis presented below, EPA assumed yields of camelina would 
be 1650 pounds per acre. Since the use of camelina as a biofuel 
feedstock in the U.S. is in its infancy, it is reasonable to consider 
how yields will change over time. Furthermore, jet fuel contracts and 
the BCAP programs play a very important part in determining the amount 
of camelina planted, and therefore interest in increasing yields. As 
the commenter noted, this yield assumption is within the range of 
potential yields of 330-2400 pounds per acre found in the current 
literature.
c. 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.\26\ 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.\27\ See Table 1. For comparison purposes, the USDA projections 
for wheat returns are between $133-$159 per acre between 2010 and 
2020.\28\ Over time, advancements in seed technology, improvements in 
planting and harvesting techniques, and higher input usage could 
significantly increase future camelina yields and returns.
---------------------------------------------------------------------------

    \26\ See Lafferty et al, 2009; Shonnard et al, 2010; Sustainable 
Oils Memo dated November 5, 2010.
    \27\ Wheeler & Guillen-Portal, 2007.
    \28\ See http://www.ers.usda.gov/media/273343/oce121_2_.pdf.

[[Page 14196]]



                                       Table 1--Camelina Costs and Returns
----------------------------------------------------------------------------------------------------------------
                                                                   2010 Camelina   2022 Camelina   2030 Camelina
                Inputs                            Rates                \29\            \30\            \31\
----------------------------------------------------------------------------------------------------------------
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
      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.\32\ 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.\33\ Therefore, camelina 
grown outside of a wheat fallow situation was not considered as part of 
this analysis.
---------------------------------------------------------------------------

    \29\ See Sustainable Oils Memo dated November 5, 2010.
    \30\ Based on yields technically feasible. See McVey and Lamb, 
2008; Ehrenson & Guy, 2008.
    \31\ Adapted from Shonnard et al, 2010.
    \32\ 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.
    \33\ 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 US 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.
d. 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.

[[Page 14197]]



                               Table 2--Inputs for Camelina and Soybean Production
----------------------------------------------------------------------------------------------------------------
                                              Camelina                        Soybeans (varies by region)
                               ---------------------------------------------------------------------------------
                                                     Emissions (per      Inputs (per      Emissions (per mmBtu
                                Inputs (per acre)     mmBtu fuel)           acre)                 fuel)
----------------------------------------------------------------------------------------------------------------
N2O...........................  N/A..............  22 kg CO2-eq.....  N/A.............  9-12 kg CO2-eq.
Nitrogen Fertilizer...........  40 lbs...........  7 kg CO2-eq......  3.5-8.2 lbs.....  1-3 kg CO2-eq.
Phosphorous Fertilizer........  15 lbs...........  1 kg CO2-eq......  5.4-21.4 lbs....  0-2 kg CO2-eq.
Potassium Fertilizer..........  10 lbs...........  0 kg CO2-eq......  3.1-24.3 lbs....  0-2 kg CO2-eq.
Herbicide.....................  2.75 lbs.........  3 kg CO2-eq......  0.0-1.3 lbs.....  0-2 kg CO2-eq.
Pesticide.....................  0 lbs............  0 kg CO2-eq......  0.1-0.8 lbs.....  0-2 kg CO2-eq.
Diesel........................  3.5 gal..........  5 kg CO2-eq......  3.8-8.9 gal.....  7-20 kg CO2-eq.
Gasoline......................  0 gal............  0 kg CO2-eq......  1.6-3.0 gal.....  3-5 kg CO2-eq.
Total.........................  .................  39 kg CO2-eq.....  ................  21-47 kg CO2-eq.
----------------------------------------------------------------------------------------------------------------

    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 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 
change impacts are 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.
e. 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 March 
2010 RFS final rule, based on a process model developed by USDA-
ARS.\34\ The data on camelina crushing is from Shonnard et al. (2010).
---------------------------------------------------------------------------

    \34\ 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. 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.

[[Page 14198]]

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 
chemically equivalent to the glycerin produced from the existing 
biodiesel pathways (e.g., based on soy oil) that were analyzed as part 
of the March 2010 RFS 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 March 2010 RFS 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, asserting 
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 March 2010 RFS 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 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 could range from fairly 
high reduction credits if 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 March 2010 RFS rule) on which to allocate 
glycerin use across the range of likely uses. Therefore, EPA believes 
that the approach used in the RFS 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 benefits associated 
with glycerin production at this time. EPA will continue to evaluate 
the co-product credit associated with glycerine production in future 
rulemakings.
    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 changes 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 
March 2010 RFS 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.\35\ 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.
---------------------------------------------------------------------------

    \35\ 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 RFS 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

[[Page 14199]]

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.\36\ 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 also do 
so in the case when RINs are not generated for co-products.
---------------------------------------------------------------------------

    \36\ 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,\37\ Stratton et al., 2010, Huo et al., 2008 \38\). 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.\39\ This 
data is summarized in Table 4.
---------------------------------------------------------------------------

    \37\ Pearlson, M., N. 2011. A Techno-Economic and Environmental 
Assessment of Hydroprocessed Renewable Distillate Fuels.
    \38\ 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.
    \39\ 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.
    \40\ 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\40\
----------------------------------------------------------------------------------------------------------------
                                               Maximized  for  Maximized  for
                                                diesel  fuel      jet fuel         Units (per gallon of fuel
                                                 production      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.\41\ The key assumptions and data discussed in the docket 
include the emissions factors for natural gas, hydrogen and grid 
average electricity, and the energy allocation and displacement credits 
given to co-products. These data and assumptions are based on the 
approach taken in the March 2010 RFS rule, as explained further below.
---------------------------------------------------------------------------

    \41\ See for example the spreadsheet with lifecycle GHG 
emissions calculations titled ``Final Camelina Calculations for 
Docket'' with document number EPA-HQ-OAR-2011-0542-0046.

[[Page 14200]]



                                                    Table 5--Fuel Production Lifecycle GHG Emissions
                                                                   [kgCO2e/mmBtu) \42\
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                 RIN-Generating                                    Oil
             Feedstock                 Production process           products            Other co-products      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           Diesel Fuel...........  Propane...............               4             11            14
                                      Maximized for Jet      Jet Fuel..............
                                      Fuel.                  Naphtha...............
                                                             LPG.
--------------------------------------------------------------------------------------------------------------------------------------------------------


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

    \42\ 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.
---------------------------------------------------------------------------

    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 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.
    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 renewable 
gasoline blendstock 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 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; however, the agency will continue to monitor 
volumes through EMTS to verify this assumption. 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, through EMTS and in 
collaboration with USDA, 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

[[Page 14201]]

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 RFS 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 
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.\43\ As was discussed previously, if the 
displacement approach is used when jet fuel is the primary product 
produced it results in lower emissions than 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.
---------------------------------------------------------------------------

    \43\ The exception is renewable gasoline blendstock 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 RFS 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

    For this rulemaking, EPA considered the lifecycle GHG impacts of a 
new type of high-yielding perennial grass similar in cellulosic 
composition to switchgrass and comparable in status as an emerging 
energy crop. The grass considered in this rulemaking is energy cane, 
which is defined as a complex hybrid in the Saccharum genus that has 
been bred to maximize cellulosic rather than sugar content.
    As discussed above, in response to the proposed rule, EPA received 
comments highlighting the concern that by approving certain new 
feedstock types under the RFS program, EPA would be encouraging their 
introduction or expanded planting without considering their potential 
impact as invasive species.\44\
---------------------------------------------------------------------------

    \44\ Comment submitted by Jonathan Lewis, Senior Counsel, 
Climate Policy, Clean Air Task Force et al., dated February 6, 2012. 
Document ID  EPA-HQ-OAR-2011-0542-0118.
---------------------------------------------------------------------------

    As described in the previous section on camelina, the information 
before us does not raise significant concerns about the threat of 
invasiveness and related GHG emissions for energy cane. Energy cane is 
generally a hybrid of Saccharum officinarum and Saccharum spontaneum, 
though other species such as Saccharum barberi and Saccharum sinense 
have been used in the development of new cultivars.\45\ Given the fact 
that S. spontaneum is listed on the Federal Noxious Weed List, this 
rulemaking does not allow for the inclusion of S. spontaneum in the 
definition of energy cane. However, hybrids derived from S. spontaneum 
that have been developed and publicly released by USDA are included in 
this definition of the energy cane feedstock. USDA's Agricultural 
Research Service has developed strains of energy cane that strive to 
maximize fiber content and minimize invasive traits. Therefore, we 
believe that the production of cultivars of energy cane that were 
developed by USDA are unlikely to spread beyond the intended borders in 
which it is grown, which is consistent with the assumption in EPA's 
lifecycle analysis that significant expenditures of energy or other 
sources of GHGs will not be required to remediate the spread of this 
feedstock from the specific locations where it is grown as a renewable 
fuel

[[Page 14202]]

feedstock for the RFS program. Therefore, we are finalizing the energy 
cane pathway in this rule based on our lifecycle analysis discussed 
below.
---------------------------------------------------------------------------

    \45\ See https://www.crops.org/publications/jpr/abstracts/2/3/211?access=0&view=pdf and http://www.cpact.embrapa.br/eventos/2010/simposio_agroenergia/palestras/10_terca/Tarde/USA/4%20%20%208-10-2010%20Cold%20Tolerance.pdf.
---------------------------------------------------------------------------

    In the proposed and final RFS 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 RFS 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 from 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 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 the energy cane pathway, EPA has evaluated 
energy cane and is now including it as a feedstock in Table 1 to Sec.  
80.1426 as approved pathways for cellulosic biofuel pathways.
    As described in detail in the following sections of this preamble, 
because of the similarity of energy cane to switchgrass and miscanthus, 
and because crop production input emissions (e.g., diesel and pesticide 
emissions) are generally a small fraction of the overall lifecycle GHG 
emissions (representing approximately 1% of total emissions for 
switchgrass), EPA believes that new agricultural sector modeling is not 
needed to analyze energy cane. We have instead relied upon the 
switchgrass analysis to assess the relative GHG impacts of biofuel 
produced from energy cane. 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 naphtha) produced from the 
cellulosic biomass of energy cane 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 less suitable 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.
a. Crop Yields
    For the purposes of analyzing the GHG emissions from energy cane 
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.46 47 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. In general, energy cane 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 
pathway.
---------------------------------------------------------------------------

    \46\ 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.
    \47\ See Hale, A.L. Sugar Bulletin, 2010, 88, 28-29.
---------------------------------------------------------------------------

    Furthermore, EPA's analysis of switchgrass for the RFS 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 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.\48\ The ethanol yield for all of the grasses is 
approximately the same so the higher crop yields for energy cane result 
directly in greater ethanol production compared to switchgrass per acre 
of production.
---------------------------------------------------------------------------

    \48\ 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 
due to higher yields. Even without yield growth assumptions, the 
currently higher crop yield rates means the land use required for 
energy cane 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 will have a 
similar impact on international markets as assumed for switchgrass. 
Like switchgrass, energy cane is not expected to be traded 
internationally and its impacts on other crops are expected to be 
limited.
b. Land Use
    In EPA's March 2010 RFS analysis, switchgrass plantings displaced 
primarily soybeans and wheat, and to a lesser extent hay, rice, 
sorghum, and cotton. Energy cane, with production focused in the 
southern United States, is

[[Page 14203]]

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 will 
likely displace the least productive land first, EPA concludes that the 
land use GHG impact for energy cane per gallon should be no greater and 
likely less than estimated for switchgrass.
    Considering the total land potentially impacted by all the new 
feedstocks included in this rulemaking would not impact these 
conclusions (including the camelina discussed in the previous section 
and energy cane considered here). As discussed previously, the camelina 
is expected to be grown on fallow land in the Northwest, while energy 
cane is 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 cane 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. This analysis took into account the economic conditions 
such as input costs and commodity prices when evaluating the GHG and 
land use change impacts of switchgrass.
    One commenter stated that by assuming no land use change for energy 
cane and other feedstocks, the Agency may have underestimated the 
increase in GHG emissions that could result from breaking new land. 
According to the commenter, EPA assumed that these feedstocks will be 
grown on the least productive land without citing any specific models 
or studies.
    The commenter appears to have misinterpreted EPA's analysis. EPA 
did not assume these crops would be grown on fallow acres, nor did EPA 
assume that switchgrass would only be produced on the least productive 
lands. EPA assumed these crops would be grown on acres similar to 
switchgrass, and therefore applied the land use change impacts of 
switchgrass analyzed in the final RFS rule. In the final RFS, EPA 
provided detailed information on the types of crops (e.g., wheat) that 
would be displaced by dedicated switchgrass. This analysis took into 
account the economic conditions such as input costs and commodity 
prices when evaluating the GHG and land use change impacts of 
switchgrass.\49\
---------------------------------------------------------------------------

    \49\ See Final Regulatory Impact Analysis Chapter 2, February 
2010.
---------------------------------------------------------------------------

c. Crop Inputs and Feedstock Transport
    EPA also assessed the GHG impacts associated with planting, 
harvesting, and transporting energy cane in comparison to switchgrass. 
Table 6 shows the assumed 2022 commercial-scale production inputs for 
switchgrass (used in the RFS rulemaking analysis), average energy cane 
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.
    This assessment assumes production of energy cane 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 March 2010 RFS final 
rule, energy cane production results in slightly higher GHG emissions 
relative to switchgrass production (an increase of approximately 4 kg 
CO2eq/mmbtu).

[[Page 14204]]

[GRAPHIC] [TIFF OMITTED] TR05MR13.015

    GHG emissions associated with distributing energy cane are expected 
to be similar to EPA's estimates for switchgrass feedstock because they 
are all herbaceous agricultural crops requiring similar transport, 
loading,

[[Page 14205]]

unloading, and storage regimes. Our analysis therefore assumes the same 
GHG impact for feedstock distribution as we assumed for switchgrass, 
although distributing energy cane 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 is suitable for the same conversion processes as other 
cellulosic feedstocks, such as switchgrass and corn stover. Currently 
available information on energy cane composition shows that 
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 RFS 
rule (biochemical ethanol, thermochemical ethanol, and Fischer-Tropsch 
(F-T) diesel \50\) to energy cane. We assumed the GHG emissions 
associated with producing biofuels from energy cane 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 
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, based on 
analysis of the increased transport emissions associated with sugarcane 
ethanol distribution to the U.S. considered for the 2010 final rule, 
this would at most add 1-2% to the overall lifecycle GHG impacts of the 
energy grasses.
---------------------------------------------------------------------------

    \50\ The F-T diesel process modeled applies to cellulosic 
diesel, jet fuel, heating oil, and naphtha.
---------------------------------------------------------------------------

3. Summary
    Based on our comparison to switchgrass, EPA believes that 
cellulosic biofuel produced from the cellulose, hemicellulose and 
lignin portions of energy cane has similar or better lifecycle GHG 
impacts than biofuel produced from the cellulosic biomass from 
switchgrass. Our analysis suggests that energy cane has 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. 
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, energy cane is 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 
still meet the 60% reduction threshold for cellulosic biofuel. We 
believe these are conservative estimates, as use of energy cane as a 
feedstock is expected to have smaller land-use GHG impacts than 
switchgrass, due to higher yields. The docket for this rule provides 
additional detail on the analysis of energy cane as a biofuel 
feedstock.
    Although this analysis assumes energy cane 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 from other countries. We do not expect 
incidental amounts of biofuels from feedstocks produced in other 
nations to impact our assessment that the average GHG emissions 
reductions will meet the threshold for qualifying as a cellulosic 
biofuel pathway. Moreover, those countries most likely to be exporting 
energy cane or biofuels produced from energy cane are likely to be 
major producers which typically use similar cultivars and farming 
techniques. Therefore, GHG emissions from producing biofuels with 
energy cane grown in other countries should be similar to the GHG 
emissions we estimated for U.S. energy cane, though they could be 
slightly higher or lower. For example, the renewable biomass provisions 
under the Energy Independence and Security Act as outlined in the March 
2010 RFS final rule regulations, would preclude use of a crop as a 
feedstock for renewable fuel if it was gown on land that was a 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 March 2010 RFS final 
rule and this comparison of GHG emissions from switchgrass and energy 
cane, we do not expect variations to be large enough to bring the 
overall GHG impact of fuel made from energy cane 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 under the same pathways for which 
cellulosic biomass from switchgrass qualifies under the RFS 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 RFS 
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 March 
2010 RFS 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 gasoline and 
renewable gasoline blendstock.

[[Page 14206]]

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 March 
2010 RFS 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 RFS 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 represents 
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 March 2010 RFS 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 RFS 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 gasoline blendstock (``catalytic 
pyrolysis and upgrading''), (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 March 2010 RFS 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.\51\ 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 March 2010 RFS 
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 RFS 
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 RFS 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.\52\ 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.\53\
---------------------------------------------------------------------------

    \51\ Kinchin, Christopher. Catalytic Fast Pyrolysis with 
Upgrading to Gasoline and Diesel Blendstocks. National Renewable 
Energy Laboratory (NREL). 2011.
    \52\ Aden, Andy. Feedstock Considerations and Impacts on 
Biorefining. National Renewable Energy Laboratory (NREL). December 
2009. The report indicates that woody biomass feedstocks generally 
have higher yields than crop residues or herbaceous grasses (~6% 
higher yields). However the same lower yield was assumed for all as 
a conservatively low estimate.
    \53\ 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

[[Page 14207]]

use of such feedstocks does not require land use changes or additional 
agricultural inputs. Therefore, we conclude that if the use of corn 
stover 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.
    One commenter stated that the Agency assumed that using the corn 
stover for biofuels production would result in additional no-till 
farming without any evidence that the stover would actually be removed 
from no-tilled acres. This commenter feels that with recent increased 
profitability from corn production, farmers may actually increase 
tillage to reap high corn prices. This commenter urged the EPA to 
consider changes to soil carbon from the removal of corn stover as they 
may have an impact on the GHG score of this new biofuel pathway. This 
commenter further urged the Agency to not simply assume that additional 
no-till practices will be adopted with residue extraction.
    The analysis the EPA conducted to evaluate the GHG impacts 
associated with corn stover removal as part of the March 2010 RFS final 
rule did not assume that the corn stover had to be removed from no-till 
corn production. The models used to evaluate the impacts of stover 
removal included the option for farmers to switch to no-till practices 
and therefore have the option for more stover removal. As the demand 
for stover increased in the case where stover is used for biofuel 
production, the relative costs associated with no-till factored in the 
impact of lost corn yield as well as higher yield for corn stover. The 
model optimized the rate of returns for the farmers such that no-till 
practices were applied until the increased returns for greater stover 
removal on no-till acres were balanced by lost profits from lower corn 
yields. Therefore, the comment that we assumed stover had to come from 
no-till acres or that the economics would drive more intensive tillage 
practices is not accurate, as described in more detail in the March 
2010 RFS final rule.
    Furthermore, there is an annual soil carbon penalty applied to 
crops with residue removal in our models. Thus, as one shifts from 
conventional corn to residue corn, an annual soil carbon penalty factor 
is applied. If residue removal is combined with switching to 
conservation tillage or no-till, then the net soil C effect would be 
the sum of the till change effect and the ``crop change'' effect.
    For the March 2010 RFS rulemaking, EPA conducted an in-depth 
literature review of corn stover removal practices and consulted with 
numerous experts in the field. In the FRM, EPA recognized that 
sustainable stover removal practices vary significantly based on local 
differences in soil and erosion conditions, soil type, landscape 
(slope), tillage practices, crop rotation managements, and the use of 
cover crops. EPA, in consultation with USDA, based its impacts on corn 
stover from reduced till and no till acres based on agronomical 
practices, nutrient requirements, and erosion considerations. EPA does 
not believe that the commentor has provided new information that would 
substantially change our analysis of the GHG emissions associated with 
corn stover. However, EPA will continue to monitor actual practices and 
based on new data will consider reviewing and revising the methodology 
and assumptions associated with calculating the GHG emissions from all 
renewable fuel feedstocks.

 Table 7--Feedstock Production Emissions for Renewable Gasoline and Renewable Gasoline Blendstock Pathways Using
                                                   Corn Stover
----------------------------------------------------------------------------------------------------------------
                                                                      Biochemical
                                       Catalytic pyrolysis and      fermentation and        Direct biochemical
                                        upgrading to renewable   upgrading to renewable  fermentation process to
    Feedstock production  emission      gasoline and renewable   gasoline and renewable   renewable gasoline and
               sources                 gasoline blendstock  (g  gasoline blendstock via     renewable gasoline
                                            CO2-eq./mmBtu)      carboxylic acid (g CO2-   blendstock (g CO2-eq./
                                                                       eq./mmBtu)                 mmBtu)
----------------------------------------------------------------------------------------------------------------
Domestic Livestock...................                    7,648                    6,770                  ~ 9,086
Domestic Farm Inputs and Fertilizer                      1,397                    1,237                  ~ 1,660
 N2O.................................
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                                0                        0                        0
 Fertilizer N2O......................
International Rice Methane...........                        0                        0                        0
International Land Use Change........                        0                        0                        0
                                      --------------------------------------------------------------------------
    Total Feedstock Production                             287                      254                    ~ 361
     Emissions:......................
Assumed yield (gal/ton of biomass)...                     64.5                       75                     92.3
----------------------------------------------------------------------------------------------------------------

    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 or renewable 
gasoline blendstocks 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 RFS 
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 RFS final rule were applied to this 
analysis.
3. Use of the Fuel
    A petroleum gasoline baseline was developed as part of the RFS 
final rule which estimated the tailpipe emissions from fuel combustion. 
Since renewable gasoline and renewable gasoline blendstock are similar 
to petroleum gasoline in energy and hydrocarbon

[[Page 14208]]

content, the non-CO2 combustion emissions calculated as part 
of the RFS 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 March 2010 RFS 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 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 renewable gasoline 
blendstock. In the final 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. In this rule, we are changing the reference to F-T as 
the process technology to the more correct reference as gasification 
technology since F-T reactions are only part of the process technology.
    Since the final March 2010 RFS 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.\54\ 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.
---------------------------------------------------------------------------

    \54\ 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 and 
upgrading''), 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'') and other thermo-catalytic hydrodeoxygenation routes 
with upgrading such as aqueous phase processing.55 56
---------------------------------------------------------------------------

    \55\ Regalbuto, John. ``An NSF perspective on next generation 
hydrocarbon biorefineries,'' Computers and Chemical Engineering 34 
(2010) 1393-1396. February 2010.
    \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.
---------------------------------------------------------------------------

    Similar to how we analyzed several of the main routes for 
cellulosic ethanol and cellulosic diesel for the final March 2010 RFS 
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 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 With Upgrading 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.\57\ 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 renewable gasoline, renewable gasoline blendstock and 
renewable diesel streams (cellulosic diesel from catalytic pyrolysis is 
already included as an acceptable pathway in the RFS 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 biogas 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.
---------------------------------------------------------------------------

    \57\ 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           Sold
                 Technology                     Biomass use    Natural gas use    electricity      electricity
----------------------------------------------------------------------------------------------------------------
Catalytic Pyrolysis to Renewable Gasoline or         136,000           51,000                0           -2,000
 Renewable Gasoline Blendstock..............
----------------------------------------------------------------------------------------------------------------


[[Page 14209]]

    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 March 2010 
RFS 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.\58\ 
See Table 9 for a summary of emissions from fuel production.
---------------------------------------------------------------------------

    \58\ 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 and Upgrading
to Renewable Gasoline or Renewable Gasoline Blendstock Using Corn Stover
------------------------------------------------------------------------
                                                  Catalytic pyrolysis to
                                                  renewable gasoline or
                Lifecycle stage                     renewable gasoline
                                                  blendstock (g CO2-eq./
                                                          mmBtu)
------------------------------------------------------------------------
On-Site & Upstream Emissions (Natural Gas &                       31,000
 Biomass*).....................................
Electricity Co-Product Credit..................                   -3,000
                                                ------------------------
    Total Fuel Production Emissions:...........                   28,000
------------------------------------------------------------------------
* Only non-CO2 combustion emissions from biomass

    b. Catalytic Upgrading of Biochemically Derived Intermediates to 
Renewable Gasoline and Renewable Gasoline Blendstock
    The second production process we investigated is a biochemical 
fermentation process to intermediate, such as carboxylic acids with 
catalytic upgrading to renewable gasoline or renewable gasoline 
blendstock. This process involves the fermentation of biomass using 
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.\59\ 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.
---------------------------------------------------------------------------

    \59\ Hydrogen emissions are modeled as natural gas and 
electricity demands.

                                Table 10--2022 Energy Use at Cellulosic Facility
                                                    [Btu/gal]
----------------------------------------------------------------------------------------------------------------
                                                                    Natural gas      Purchased         Sold
                   Technology                       Biomass use         use         electricity     electricity
----------------------------------------------------------------------------------------------------------------
Biochemical Fermentation to Renewable Gasoline            49,000          59,000               0          -2,000
 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 CO2-
                Lifecycle stage                         eq./mmBtu)
------------------------------------------------------------------------
On-Site & Upstream Emissions (Natural Gas &                       33,000
 Biomass*).....................................
Electricity Co-Product Credit..................                   -3,000
Total Fuel Production Emissions:...............                   30,000
------------------------------------------------------------------------
* Only non-CO2 combustion emissions from biomass


[[Page 14210]]

c. Biological Conversion to Renewable Gasoline and Renewable Gasoline 
Blendstock
    The third production process we investigated involves the use of 
microorganisms to biologically convert 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 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 generally separate spontaneously from 
the aqueous phase, thereby avoiding poisoning of microbes by the 
accumulated products and facilitating separation/collection of 
hydrocarbons from the reaction medium. 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.
    Therefore, we can conservatively extend our final March 2010 RFS 
rule biochemical fermentation to ethanol process results to a similar 
(but likely slightly improved) process that instead produces 
hydrocarbons. Since the final 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 rule.

    Table 12--Fuel Production Emissions for March 2010 RFS Cellulosic Biochemical Ethanol Compared to Direct
        Biochemical Fermentation to Renewable Gasoline or Renewable Gasoline Blendstock Using Corn Stover
----------------------------------------------------------------------------------------------------------------
                                                                                            Direct biochemical
                                                                                             fermentation to
                                                                 Cellulosic biochemical  renewable gasoline  and
                        Lifecycle stage                           ethanol emissions (g     renewable  gasoline
                                                                     CO2-eq./mmBtu)        blendstock emissions
                                                                                            (g CO2-eq./mmBtu)
----------------------------------------------------------------------------------------------------------------
On-Site Emissions & Upstream (biomass)........................                    3,000             < or = 3,000
Electricity Co-Product Credit.................................                  -35,000                = -35,000
Total Fuel Production Emissions \60\:.........................                  -33,000           < or = -33,000
----------------------------------------------------------------------------------------------------------------

    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.\61\ As noted above, these analyses assume natural gas as the 
process energy when needed; using biogas as process energy would result 
in an even better lifecycle GHG impact.
---------------------------------------------------------------------------

    \60\ Numbers do not add up due to rounding.
    \61\ 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''.

 Table 13--Lifecycle GHG Emissions for Renewable Gasoline and Renewable Gasoline Blendstock Pathways Using Corn
                                                  Stover, 2022
                                               [kg CO2-eq./mmBtu]
----------------------------------------------------------------------------------------------------------------
                                                                    Biochemical
                                                     Catalytic     fermentation       Direct
                                                   pyrolysis and   to renewable     biochemical
                                                    upgrade to     gasoline and    fermentation
                    Fuel type                        renewable       renewable     to renewable    2005 gasoline
                                                   gasoline and      gasoline      gasoline and      baseline
                                                     renewable    blendstock via     renewable
                                                     gasoline       carboxylic       gasoline
                                                    blendstock         acid         blendstock
----------------------------------------------------------------------------------------------------------------
Net Domestic Agriculture (w/o land use change)..               9               8            ~ 11  ..............
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
 

[[Page 14211]]

 
% 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 March 2010 RFS 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 
(e.g. additional thermo-catalytic hydrodeoxygenation routes with 
upgrading similar to pyrolysis and aqueous phase processing) 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. 62 
63 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:
---------------------------------------------------------------------------

    \62\ Regalbuto, John. ``An NSF perspective on next generation 
hydrocarbon biorefineries,'' Computers and Chemical Engineering 34 
(2010) 1393-1396. February 2010.
    \63\ 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 and Upgrading--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:
     Biological conversion to hydrocarbons--requires the 
release of sugars from biomass and microorganisms to biologically 
convert sugars straight into hydrocarbons instead of alcohols
     Catalytic upgrading of biochemically produced 
intermediates--requires the release of sugars from biomass and aqueous- 
or liquid-phase processing of sugars or biochemically produced 
intermediate products into hydrocarbons using solid catalysts,
    As part of the modeling effort here, as well as for the March 2010 
RFS final rule, we have considered the lifecycle GHG impacts of the 
four possible production technologies mentioned above. The pyrolysis 
and upgrading, direct biological conversion, and catalytic upgrading of 
biochemically produced intermediates are considered in this rule and 
the gasification route was already included in the March 2010 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 \64\ for process energy and that all such production 
variations would also meet the 60% lifecycle threshold.\65\
---------------------------------------------------------------------------

    \64\ Our lifecycle analysis assumes that producers would use the 
same type of biomass as both the feedstock and the process energy.
    \65\ One commenter wanted clarification of the term ``process 
energy'' as it applies to the production of renewable gasoline. The 
EPA did not intend for the term, ``process energy'', to include 
other energy sources, such as electricity to provide power for 
ancillary processes, such as lights, small pumps, computers, and 
other small support equipment.
---------------------------------------------------------------------------

    The main reason for this is that we believe that our energy input 
assumptions are reasonable at this time but probably in some cases are 
conservatively high 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 lignin or waste 
byproducts; we also ran

[[Page 14212]]

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 
biofuel 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 than 
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.\66\ 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.
---------------------------------------------------------------------------

    \66\ 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 
March 2010 RFS final rule resulted in an approximately 91% reduction in 
lifecycle GHG emissions compared to the petroleum baseline. This could 
be considered a conservatively high 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 originally 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 conservatively high 
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

[[Page 14213]]

extending our results 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 yields (more 
gallons per ton of feedstock) or lower production costs 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 March 2010 RFS 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. 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, these pathways capture the likely current 
technologies, and future technology improvements are likely to increase 
efficiency and lower GHG emissions. Therefore 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
     Thermo-catalytic hydrodeoxygenation processes such as 
aqueous phase processing with upgrading sufficiently similar to 
pyrolysis and gasification
     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 March 2010 RFS 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 March 2010 RFS rulemaking (75 FR 14670).
    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, other similar thermo-catalytic 
hydrodeoxygenation routes with 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

    The Agency is not taking final action at this time on its proposed 
inclusion of the process ``esterification'' as an approved biodiesel 
production process in Table 1 to Sec.  40 CFR 80.1426. See 77 FR 465. 
We continue to evaluate the issue and anticipate issuing a final 
determination as part of a subsequent rulemaking.

[[Page 14214]]

III. 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'' (75 FR 59622). 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 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 of origin.
    We are also correcting an inadvertent omission to the proposal 
which incorrectly did not include a pathway for producing naphtha from 
switchgrass and miscanthus; this pathway was included in the original 
March 2010 RFS final rule. This pathway also incorporates the 
additional energy grass feedstock sources being added today, namely 
energy cane.

IV. Statutory and Executive Order Reviews

A. Executive Order 12866: Regulatory Planning and Review and Executive 
Order 13563: Improving Regulation and Regulatory Review

    Under Executive Order 12866 (58 FR 51735, October 4, 1993), this 
action is a ``significant regulatory action.'' Accordingly, EPA 
submitted this action to the Office of Management and Budget (OMB) for 
review under Executive Orders 12866 and 13563 (76 FR 3821, January 21, 
2011) and any changes made in response to OMB recommendations have been 
documented in the docket for this action.

B. Paperwork Reduction Act

    This action does not impose any new information collection burden. 
The corrections, clarifications, and modifications to the final March 
2010 RFS 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 March 2010 RFS 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 relatively minor 
corrections and modifications this rule makes to the final March 2010 
RFS 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

[[Page 14215]]

relatively minor corrections and modifications to the RFS 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 RFS 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 action is not a ``significant energy action'' as defined in 
Executive Order 13211 (66 FR 28355 (May 22, 2001)), because it is not 
likely to have a significant adverse effect on the supply, 
distribution, or use of energy. This rulemaking does not change any 
programmatic structural component of the RFS regulatory requirements. 
This rulemaking does not add any new requirements for obligated parties 
under the program or mandate the use of any of the new pathways 
contained in the rule. This rulemaking only makes a determination to 
qualify new fuel pathways under the RFS regulations, creating further 
opportunity and flexibility for compliance with the Energy Independence 
and Security Act of 2007 (EISA) mandates.

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 the Federal Register. 
This action is not a ``major rule'' as defined by 5 U.S.C. 804(2).

V. 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 today's rule comes from Section 301(a) of the Clean Air Act, 42 
U.S.C. 7414, 7542, and 7601(a).

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: February 22, 2013.
Bob Perciasepe,
Acting 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 adding definitions of ``Energy cane,'' 
``Renewable gasoline'' and ``Renewable gasoline blendstock'' in 
alphabetical order to read as follows:


Sec.  80.1401  Definitions.

* * * * *
    Energy cane means a complex hybrid in the Saccharum genus that has 
been bred to maximize cellulosic rather than sugar content. For the 
purposes of this section, energy cane excludes the species Saccharum 
spontaneum, but includes hybrids derived from S.

[[Page 14216]]

spontaneum that have been developed and publicly released by USDA.
* * * * *
    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               6
                                                                        mill 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               6
                                                                        mill 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               6
                                                                        mill 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                  6
                                                                        biomass or biogas for
                                                                        process energy.
E.............  Ethanol................  Starches from crop residue    Fermentation using natural              6
                                          and annual covercrops.        gas, biomass, or biogas for
                                                                        process energy.
F.............  Biodiesel, renewable     Soy bean oil; Oil from        One of the following: Trans-            4
                 diesel, jet fuel and     annual covercrops; Algal      Esterification
                 heating oil.             oil; Biogenic waste oils/     Hydrotreating Excluding
                                          fats/greases; Non-food        processes that co-process
                                          grade corn oil Camelina       renewable biomass and
                                          sativa oil.                   petroleum.
G.............  Biodiesel, heating oil.  Canola/Rapeseed oil.........  Trans-Esterification using              4
                                                                        natural gas or biomass for
                                                                        process energy.
H.............  Biodiesel, renewable     Soy bean oil; Oil from        One of the following: Trans-            5
                 diesel, jet fuel and     annual covercrops; Algal      Esterification
                 heating oil.             oil; Biogenic waste oils/     Hydrotreating Includes only
                                          fats/greases; Non-food        processes that co-process
                                          grade corn oil Camelina       renewable biomass and
                                          sativa oil.                   petroleum.
I.............  Naphtha, LPG...........  Camelina sativa 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, 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   Cellulosic Biomass from crop  Any.........................            7
                 fuel and heating oil.    residue, slash, pre-
                                          commercial thinnings and
                                          tree residue, annual
                                          covercrops, switchgrass,
                                          miscanthus, and energy
                                          cane; cellulosic components
                                          of separated yard waste;
                                          cellulosic components of
                                          separated food waste; and
                                          cellulosic components of
                                          separated MSW.
M.............  Renewable gasoline and   Cellulosic Biomass from crop  Catalytic Pyrolysis and                 3
                 renewable gasoline       residue, slash, pre-          Upgrading, Gasification and
                 blendstock.              commercial thinnings, tree    Upgrading, Thermo-Catalytic
                                          residue, annual cover         Hydrodeoxygenation and
                                          crops; cellulosic             Upgrading, Direct
                                          components of separated       Biological Conversion,
                                          yard waste; cellulosic        Biological Conversion and
                                          components of separated       Upgrading, all utilizing
                                          food waste; and cellulosic    natural gas, biogas, and/or
                                          components of separated MSW.  biomass as the only process
                                                                        energy sources Any process
                                                                        utilizing biogas and/or
                                                                        biomass as the only process
                                                                        energy sources.
N.............  Naphtha................  Cellulosic biomass from       Gasification and upgrading..            3
                                          switchgrass, miscanthus,
                                          and energy cane.
O.............  Butanol................  Corn starch.................  Fermentation; dry mill using            6
                                                                        natural gas, biomass, or
                                                                        biogas for process energy.

[[Page 14217]]

 
P.............  Ethanol, renewable       The non-cellulosic portions   Any.........................            5
                 diesel, jet fuel,        of separated food waste.
                 heating oil, and
                 naphtha.
Q.............  Biogas.................  Landfills, sewage waste       Any.........................            5
                                          treatment plants, manure
                                          digesters.
R.............  Ethanol................  Grain Sorghum...............  Dry mill process using                  6
                                                                        biogas from landfills,
                                                                        waste treatment plants, and/
                                                                        or waste digesters, and/or
                                                                        natural gas, for process
                                                                        energy.
S.............  Ethanol................  Grain Sorghum...............  Dry mill process, using only            5
                                                                        biogas from landfills,
                                                                        waste treatment plants, and/
                                                                        or waste digesters for
                                                                        process energy and for on-
                                                                        site production of all
                                                                        electricity used at the
                                                                        site other than up to 0.15
                                                                        kWh of electricity from the
                                                                        grid per gallon of ethanol
                                                                        produced, calculated on a
                                                                        per batch basis.
----------------------------------------------------------------------------------------------------------------

* * * * *
[FR Doc. 2013-04929 Filed 3-4-13; 8:45 am]
BILLING CODE 6560-50-P