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EO12866_New Fuel Pathways Rule under RFS 2060-AR07 FRM FRN_20130214

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.

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 (Saccharum spp.); 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 also finalizing two changes to Table 1 to § 80.1426. The first change identifies 
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Page 2 of 94

separate pathways by letter, to facilitate references to specific pathways. The second change 

adds “rapeseed” to the existing pathway for renewable fuel made from canola oil. We are also 

correcting an inadvertent omission to the proposal which incorrectly omitted a pathway for 

producing naphtha from switchgrass and miscanthus; this pathway was included in the original 

March 2010 RFS final rule. 

This final rule adds these pathways to Table 1 to § 80.1426 as pathways which have been 

determined to meet one or more of the GHG reduction thresholds specified in CAA 211(o), and 

assigns each pathway a corresponding D-Code. It allows producers or importers of fuel 

produced pursuant to these pathways to generate Renewable Identification Numbers (RINs), 

providing that the fuel meets the other requirements specified in the RFS regulations to qualify it 

as renewable fuel.

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 [Insert date 60 days from date of publication in the Federal 

Register].

FOR FURTHER INFORMATION CONTACT: Vincent Camobreco, Office of 

Transportation and Air Quality (MC6401A), Environmental Protection Agency, 1200 

Pennsylvania Ave., N.W., Washington, DC 20460; telephone number: (202) 564-9043; fax 

number: (202) 564-1686; email address: camobreco.vincent@epa.gov. 

SUPPLEMENTARY INFORMATION:

Does This Action Apply to Me?
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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:

Category NAICS1

Codes

SIC

2

Codes

Examples of Potentially Regulated Entities

Industry

Industry

Industry

Industry

Industry

Industry

Industry

324110

325193

325199

424690

424710

424720

454319

2911

2869

2869

5169

5171

5172

5989

Petroleum Refineries

Ethyl alcohol manufacturing

Other basic organic chemical manufacturing

Chemical and allied products merchant wholesalers

Petroleum bulk stations and terminals

Petroleum and petroleum products merchant 

wholesalers

Other fuel dealers

1 North American Industry Classification System (NAICS)

2

Standard Industrial Classification (SIC) system code.

This table is not intended to be exhaustive, but rather provides a guide for readers 

regarding entities likely to be regulated by this action. This table lists the types of entities that 

EPA is now aware could be potentially regulated by this action. Other types of entities not listed 

in the table could also be regulated. To determine whether your entity is regulated by this action, 

you should carefully examine the applicability criteria of Part 80, subparts D, E and F of title 40 

of the Code of Federal Regulations. If you have any question regarding applicability of this 
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Page 4 of 94

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 this Regulatory Action

II. Identification of Additional Qualifying Renewable Fuel Pathways under the Renewable 

Fuel Standard (RFS) Program

A. Lifecycle Greenhouse Gas Emissions Analysis 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 pathways that we 
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Page 5 of 94

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 (Saccharum spp.) 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 § 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: 
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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 (Saccharum spp.) 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: 

o Thermochemical pyrolysis

o Thermochemical gasification

o Biochemical direct fermentation

o Biochemical fermentation with catalytic upgrading 

o 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 § 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 
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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 on 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 
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Page 8 of 94

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.
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Many of the pathways evaluated in this rulemaking rely on a comparison to the lifecycle 

GHG analysis work that was done as part of the Renewable Fuel Standard Program Final Rule, 

published March 26, 2010 (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.25 Compared to many other oilseeds, 

 

25 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
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Page 10 of 94

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. 26,27 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.28 

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.29 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.30 The FDA has not approved camelina for food uses, although it has approved 

the inclusion of certain quantities of camelina meal in commercial feed.31 

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 

 

26 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.

27 McVay, K.A., and P.F. Lamb. 2008. Camelina production in Montana. MSU Ext. MT200701AG (revised). 

http://msuextension.org/publica¬tions/AgandNaturalResources/MT200701AG.pdf.

28 Putnam et al., 1993

29

 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.

30 Telephone conversation with Scott Johnson, Sustainable Oils, January 11, 2011.

31 See http://agr.mt.gov/camelina/FDAletter11-09.pdf. 
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Page 11 of 94

species.32 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) 13112.33

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, 

34 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 

 

32 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. 

33 http://www.gpo.gov/fdsys/pkg/FR-1999-02-08/pdf/99-3184.pdf

34 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://plants.usda.gov/java/noxious?rptType=Federal&statefips=&sort=sc. Accessed on 

March 28, 2012. 
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Page 12 of 94

pathway in this rule based on our lifecycle analysis discussed below.

35

 

Camelina is currently being grown on approximately 50,000 acres of land in the U.S., 

primarily in Montana, eastern Washington, and the Dakotas.36 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.37

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, 

 

35

 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.

36 McCormick, Margaret. “Oral Comments of Targeted Growth, Incorporated” Submitted to the EPA on June 9, 

2009.

37 See https://www.camelinacompany.com/Marketing/PressRelease.aspx?Id=25
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camelina is expected to be primarily planted in the U.S. as a rotation crop on acres that would 

otherwise remain fallow38. 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.

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 

 

38 Fallow land here refers to cropland that is periodically not cultivated. 
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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.39 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. 

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.40 However, the 

 

39 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.

40 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. 
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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 pools41. 

In addition, selective breeding is expected to reduce the potential negative impacts on wheat 

yields.42 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. 

Figure 1: Examples of Traditional Wheat and Camelina/Wheat Rotations

Example 1: Traditional Winter Wheat/Spring Wheat/Fallow Rotation

Jan Feb Mar April May June July Aug Sept Oct Nov Dec

Year 0 Winter 

Wheat 

Planting

Year 1 Winter 

Wheat 

Harvest

Year 2 Spring 

Wheat 

Planting

Spring 

Wheat 

Harvest

Year 3 Winter 

Wheat 

Planting

 

41 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. 

42 See Shonnard et al., 2010; Lafferty et al., 2009
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Example 2: Winter Wheat/Camelina/Spring Wheat Rotation

Jan Feb Mar April May June July Aug Sept Oct Nov Dec

Year 0 Winter 

Wheat 

Planting

Year 1 Winter 

Wheat 

Harvest

Year 2 Camelina 

Planting

Camelina 

Harvest

Year 3 Spring 

Wheat 

Planting

Spring 

Wheat 

Harvest

Winter 

Wheat 

Planting

Shaded cells indicate fallow months Hatched line cells indicate growing months

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 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 
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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.43 

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.44 Therefore, our 

analysis uses the estimate that only 9 million wheat/fallow acres are available for camelina 

production. 

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 

 

43 2009 USDA Baseline. See http://www.ers.usda.gov/publications/oce091/

44 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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(approximately 800 pounds per acre), approximately 100 million gallons (MG) of camelinabased 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.45 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.46 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,47

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 camelinabased renewable fuels could be produced on existing acres.48

 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 use49. 

 

45 Wheeler, P. and Guillen-Portal F. 2007. Camelina Production in Montana: A survey study sponsored by Targeted 

Growth, Inc. and Barkley Ag. Enterprises, LLP. 

46 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.

47

 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, 

48 See Shonnard et al., 2010

49 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.50 

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 

 

50 See Lafferty et al, 2009; Shonnard et al, 2010; Sustainable Oils Memo dated November 5, 2010, 
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of $0.145 per pound.51 See Table 1. For comparison purposes, the USDA projections for wheat 

returns are between $133-$159 per acre between 2010 and 2020.52 Over time, advancements in 

seed technology, improvements in planting and harvesting techniques, and higher input usage 

could significantly increase future camelina yields and returns. 

Table 1: Camelina Costs and Returns

2010 Camelina53 2022 Camelina54 2030 Camelina55

Inputs Rates

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 

(4 lbs/acre)

$7.20 

(5 lbs/acre)

$7.20 

(5 lbs/acre)

Fertilizer

 Nitrogen Fertilizer $1/pd $25.00

(25 lb/acre)

$40.00

(40 lb/acre)

$75

(75 lbs/acre)

 Phosphate Fertilizer $1/pd $15.00 $15.00 $15

 

51 Wheeler & Guillen-Portal, 2007

52 See http://www.ers.usda.gov/media/273343/oce121_2_.pdf 

53 See Sustainable Oils Memo dated November 5, 2010, 

54Based on yields technically feasible. See McVey and Lamb, 2008; Ehrenson & Guy, 2008.

55 Adapted from Shonnard et al, 2010.
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(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/pricing $116.00 $198 $270

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.56 

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 

 

56 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. 
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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.57 Therefore, camelina grown 

outside of a wheat fallow situation was not considered as part of this analysis. 

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.

 

57 Wright & Marois, 2011. 
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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. 

Table 2: Inputs for Camelina and Soybean Production

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, 

N2O N/A 22 kg CO2eq N/A 9 - 12 kg CO2eq

Nitrogen Fertilizer 40 lbs 7 kg CO2eq 3.5 - 8.2 lbs 1 - 3 kg CO2eq

Phosphorus Fertilizer 15 lbs 1 kg CO2eq 5.4 - 21.4 lbs 0 - 2 kg CO2eq

Potassium Fertilizer 10 lbs 0 kg CO2eq 3.1 - 24.3 lbs 0 - 2 kg CO2eq

Herbicide 2.75 lbs 3 kg CO2eq 0.0 - 1.3 lbs 0 - 2 kg CO2eq

Pesticide 0 lbs 0 kg CO2eq 0.1 - 0.8 lbs 0 - 2 kg CO2eq

Diesel 3.5 gal 5 kg CO2eq 3.8 - 8.9 gal 7 - 20 kg CO2eq

Gasoline 0 gal 0 kg CO2eq 1.6 - 3.0 gal 3 - 5 kg CO2eq

Total 39 kg CO2eq 21 - 47 kg CO2eq

(per acre) (per mmbtu fuel) (per acre) (per mmbtu fuel)

Camelina Soybeans (varies by region)

Inputs Emissions Inputs Emissions
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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.58 The data on 

camelina crushing is from Shonnard et al. (2010).

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

 

58 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
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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 
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naphtha LPG, and propane. Both processes and the fuels produced are described in the 

following sections. Both processes use camelina oil as a feedstock and camelina crushing is also 

included in the analysis. 

a. Biodiesel

For this analysis, we assumed the same biodiesel production facility designs and 

conversion efficiencies as modeled for biodiesel produced from soybean oil and canola/rapeseed 

oil. Camelina oil biodiesel is produced using the same methods as soybean oil biodiesel, 

therefore plant designs are assumed to not significantly differ between fuels made from these 

feedstocks. As was the case for soybean oil biodiesel, we have not projected in our assessment of 

camelina oil biodiesel any significant improvements in plant technology. Unanticipated energy

saving improvements would further improve GHG performance of the fuel pathway.

The glycerin produced from camelina biodiesel production is 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 
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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. 
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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.59 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 

 

59 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
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optimized for producing a diesel fuel replacement, and produces a greater amount of co-products 

per barrel of feedstock, especially naphtha.

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 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 
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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 coproducts.60

 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 RINgenerating 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. 

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

 

60 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
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available literature (Kalnes et al, 2010, Pearlson, M., N., 2011, 61 Stratton et al., 2010, Huo et al., 

200862). 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.63 This data is summarized in Table 4. 

Table 4: Hydrotreating Processes to Convert Camelina Oil into Diesel Replacement Fuel 

and Jet Fuel64

Maximized for Diesel 

Fuel Production

Maximized for Jet Fuel 

Production

Units

(per gallon of fuel 

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

 

61 Pearlson, M., N. 2011. A Techno-Economic and Environmental Assessment of Hydroprocessed Renewable 

Distillate Fuels. 

62 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

63 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.

64 Based on Pearlson (2011), Table 3.1 and Table 3.2
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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.65 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.

 

65 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.
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Table 5: Fuel Production Lifecycle GHG Emissions (kgCO2e / mmBtu)66

Feedstock

Production 

Process

RINGenerating 

Products

Other Coproducts Oil Extraction Processing Total

Soybean Oil

TransEsterification Biodiesel Glycerin 

14 

 

(1)

 

13 

Camelina Oil

TransEsterification Biodiesel Glycerin 

4 

 

(1)

 

3 

Camelina Oil Hydrotreating 

Maximized for 

Diesel

Diesel Propane 

4 

 

8 

 

Jet Fuel 12 

Naphtha

LPG

Camelina Oil Hydrotreating 

Maximized for 

Jet Fuel

Diesel Fuel Propane 

4 

 

11 

 

Jet Fuel 14

Naphtha

LPG

As discussed above, for a process that produces more than one RIN-generating output 

(e.g., the hydrotreating process summarized in Table 5 which produces diesel replacement fuel, 

jet fuel, and naphtha) we allocate lifecycle GHG emissions to the RIN generating products on an 

energy equivalent basis. We then normalize the allocated lifecycle GHG emissions per mmBtu 

of each fuel product. Therefore, each RIN-generating product from the same process will be 

 

66 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. 
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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 
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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 
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associated with calculating the GHG emissions from all renewable fuel feedstocks, EPA expects 

to review and revise as necessary the analysis of camelina in the future. 

Taking into account the assumption of no land use change emissions when camelina is 

used to produce renewable fuel, and considering that other sources of GHG emissions related to 

camelina biodiesel or renewable diesel production have comparable GHG emissions to biodiesel 

from soybean oil, we have determined that camelina-based biodiesel and renewable diesel should 

be treated in the same manner as soy-based biodiesel and renewable diesel in qualifying as 

biomass-based diesel and advanced biofuel for purposes of RIN generation, since the GHG 

emission performance of the camelina-based fuels will be at least as good and in some respects 

better than that modeled for fuels made from soybean oil. EPA found as part of the Renewable 

Fuel Standard final rulemaking that soybean biodiesel resulted in a 57% reduction in GHG 

emissions compared to the baseline petroleum diesel fuel. Furthermore, approximately 80% of 

the lifecycle impacts from soybean biodiesel were from land use change emissions which are 

assumed to be not significant for the camelina pathway considered. Thus, EPA is including 

camelina oil as a potential feedstock under the same biodiesel and renewable diesel (which 

includes diesel fuel, jet fuel, and heating oil) pathways for which soybean oil currently qualifies. 

We are also including a pathway for naphtha and LPG produced from camelina oil through 

hydrotreating. This is based on the fact that our analysis shows that even when all of the coproducts 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 
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process include jet fuel. This applies to two pathways in Table 1 to §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. 

§ 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 §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 §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 
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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 §80.1426.67 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. 

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 §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 highyielding perennial grass similar in cellulosic composition to switchgrass and comparable in status 

 

67 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. 
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as an emerging energy crop. The grass considered in this rulemaking is energy cane (Saccharum 

spp.), which is generally a hybrid of Saccharum officinarum, Saccharum spontaneum, 

Saccharum barberi, and/or Saccharum sinensethat has been bred to maximize biomass content 

rather than sugar content.

68

 

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.69 

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. 

For example, energy cane is not listed on the Federal Noxious Weed List, nor is it listed on any

state invasive species or noxious weed lists. We believe that the production of energy cane 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 energy cane pathway in this rule based on our lifecycle analysis discussed below.

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 

 

68 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

69 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.
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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 §

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 § 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 
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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 
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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.73,74 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. 

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 

 

73 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.

74 See Hale, A.L. Sugar Bulletin, 2010, 88, 28-29
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acre in the southern United States by 202279. 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. 

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 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 

 

79 These yields assume no significant adverse climate impacts on world agricultural yields over the analytical 

timeframe. 
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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 
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and land use change impacts of switchgrass.80 

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). 

 

80 See Final Regulatory Impact Analysis Chapter 2 , February 2010.
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Table 6: Production Inputs and GHG Emissions for Switchgrass and Energy Cane (Biochemical Ethanol), 2022

Switchgrass Energy Cane

Emission 

Factors

Inputs 

(per dry ton 

of biomass)

Emissions

(per mmBtu 

fuel)

Inputs

(per dry ton 

of biomass)

Emissions

(per mmBtu 

fuel)

Nitrogen Fertilizer 3,29 

kgCO2e/

ton of 

nitrogen

15.2 lbs 3.6 kgCO2e 8.4 lbs 2 kgCO2e

N2O N/A N/A 7.6 kgCO2e N/A 5.9 kgCO2e

Phosphorus Fertilizer 1,12 

kgCO2e /

ton of 

phosphate

6.1 lbs 0.5 kgCO2e 3.2 lbs 0.3 kgCO2e

Potassium Fertilizer 743

kgCO2e /

ton of 

potassium

6.1 lbs 0.3 kgCO2e 4.2 lbs 0.2 kgCO2e

Herbicide 23,45 

kgCO2e /

tons of 

herbicide

0.002 lbs 0.003 kgCO2e 1.0 lbs 1.8 kgCO2e

Insecticide (average across 

regions)

27,22 

kgCO2e /

tons of 

pesticide

0.025 lbs 0.04 kgCO2e 0 lbs 0 kgCO2e

Lime 408 

kgCO2e /

ton of lime

0 lbs 0 kgCO2e 104.7 lbs 3.1 kgCO2e
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Diesel 97

kgCO2e /

mmBtu 

diesel

0.4 gal 0.8 kgCO2e 1.3 gal 2.4 kgCO2e

Electricity (irrigation) 220

kgCO2e /

mmBtu

0 kWh 0 kgCO2e 14.7 kWh 1.6 kgCO2e

Total Emissions

13

kgCO2e 

/

mmBtu

17

kgCO2e 

/

mmBtu

Assumes 2022 switchgrass yield of 6.59 dry tons/acre and 92.3 gal ethanol/dry ton and 2022 energy cane yield of 19.1 dry tons/acre and 92 gal ethanol/dry ton. 

More detail on calculations and assumptions is included in materials to the docket. 
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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, 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) diesel81) 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 

 

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

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.
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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 
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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 § 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. 

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 § 80.1426 of the regulations. The 

following feedstocks were evaluated:

 Cellulosic biomass from crop residue, slash, pre-commercial thinnings and tree residue, 
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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, precommercial 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 
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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
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(NREL) for this rule for a process to make renewable gasoline blendstock.82 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 2010RFS 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.83 In addition, since 

the renewable gasoline and renewable gasoline blendstock pathways include feedstocks that 

 

82 Kinchin, Christopher. Catalytic Fast Pyrolysis with Upgrading to Gasoline and Diesel Blendstocks. National 

Renewable Energy Laboratory (NREL). 2011.

83 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. 
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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.84 

Feedstock production emissions are shown in Table 7 below for corn stover. Corn stover 

feedstock production emissions are mainly a result of corn stover removal increasing the 

profitability of corn production (resulting in shifts in cropland and thus slight emission impacts) 

and also the need for additional fertilizer inputs to replace the nutrients lost when corn stover is 

removed. However, corn stover removal also has an emissions benefit as it encourages the use 

of no-till farming which results in the lowering of domestic land use change emissions. This 

change to no-till farming results in a negative value for domestic land use change emission 

impacts (see also Table 13 below). For other waste feedstocks (e.g., tree residues and cellulosic 

components of separate yard, food, and MSW), the feedstock production emissions are even 

lower than the values shown for corn stover since the use of such feedstocks does not require 

land use changes or additional agricultural inputs. Therefore, we conclude that if the use of corn 

stover 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. 

 

84 Results for feedstock distribution are aggregated along with fuel distribution and are reported in a later section, 

see conclusion section. 
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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, 
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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. 
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Table 7: Feedstock Production Emissions for Renewable Gasoline and Renewable Gasoline 

Blendstock Pathways Using Corn Stover

Feedstock Production 

Emission Sources

Catalytic Pyrolysis and 

Upgrading to 

Renewable Gasoline 

and Renewable 

Gasoline Blendstock (g 

CO2-eq./mmBtu)

Biochemical 

Fermentation and 

Upgrading to 

Renewable Gasoline 

and Renewable 

Gasoline Blendstock 

via Carboxylic Acid 

(g CO2-eq./mmBtu)

Direct Biochemical 

Fermentation 

Process to 

Renewable Gasoline 

and Renewable 

Gasoline Blendstock 

(g CO2-eq./mmBtu)

Domestic Livestock 7,648 6,770 ~ 9,086

Domestic Farm Inputs and 

Fertilizer N2O

1,397 1,237 ~ 1,660

Domestic Rice Methane 366 324 ~ 434

Domestic Land Use 

Change

-9,124 -8,076 ~ -10,820

International Livestock 0 0 0

International Farm Inputs 

and Fertilizer N2O

0 0 0

International Rice Methane 0 0 0

International Land Use 

Change

0 0 0

Total Feedstock 

Production Emissions:

287 254 ~ 361

Assumed yield (gal/ton of 

biomass)

64.5 75 92.3
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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 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 
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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 §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.

85,

 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. 

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 

 

85 See http://www.epa.gov/otaq/fuels/renewablefuels/compliancehelp/rfs2-lca-pathways.htm for list of petitions 

received by EPA. 
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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.

86,87

 

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.88 Catalytic pyrolysis 

involves the rapid heating of biomass to about 500°C at slightly above atmospheric pressure. 

 

86 Regalbuto, John. “An NSF perspective on next generation hydrocarbon biorefineries,” Computers and Chemical 

Engineering 34 (2010) 1393-1396. February 2010.

87 Serrano-Ruiz, J., Dumesic, James. “Catalytic routes for the conversion of biomass into liquid hydrocarbon 

transportation fuels,” Energy Environmental Science (2011) 4, 83-99.

88 Kinchin, Christopher. Catalytic Fast Pyrolysis with Upgrading to Gasoline and Diesel Blendstocks. National 

Renewable Energy Laboratory (NREL). 2011.
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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. 

Table 8: 2022 Energy Use at Cellulosic Biofuel Facilities (Btu/gal)

Technology Biomass Use Natural Gas Use

Purchased 

Electricity

Sold 

Electricity

Catalytic Pyrolysis to 

Renewable Gasoline or 

Renewable Gasoline 

Blendstock 136,000 51,000 0 -2,000
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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.89 See 

Table 9 for a summary of emissions from fuel production. 

Table 9: Fuel Production Emissions for Catalytic Pyrolysis and Upgrading to Renewable 

Gasoline or Renewable Gasoline Blendstock Using Corn Stover

Lifecycle Stage Catalytic Pyrolysis to 

Renewable Gasoline or 

Renewable Gasoline 

Blendstock (g CO2-

eq./mmBtu)

On-Site & Upstream Emissions (Natural 

Gas & Biomass*) 

31,000

 

89 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.
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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.90 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. 

 

90 Hydrogen emissions are modeled as natural gas and electricity demands.
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Table 10: 2022 Energy Use at Cellulosic Facility (Btu/gal)

Technology

Biomass 

Use

Natural 

Gas 

Use

Purchased 

Electricity

Sold 

Electricity

Biochemical Fermentation to Renewable 

Gasoline or Renewable Gasoline 

Blendstock via Carboxylic Acid 49,000 59,000 0 -2,000

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 

Lifecycle Stage GHG Emissions (g CO2-

eq./mmBtu)

On-Site & Upstream Emissions (Natural Gas 

& Biomass*)

33,000

Electricity Co-Product Credit -3,000

Total Fuel Production Emissions: 30,000

*Only non-CO2 combustion emissions from biomass

c. Biological Conversion to Renewable Gasoline and Renewable Gasoline Blendstock 

The third production process we investigated involves the use of microorganisms to 

ferment sugars hydrolyzed from cellulose directly into hydrocarbons which could be either a 
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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. 
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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 

Lifecycle Stage Cellulosic Biochemical 

Ethanol Emissions

(g CO2-eq./mmBtu)

Direct Biochemical 

Fermentation to Renewable 

Gasoline and Renewable 

Gasoline 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 Emissions92: -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.93 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.

 

92 Numbers do not add up due to rounding.

93 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”
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Table 13: Lifecycle GHG Emissions for Renewable Gasoline and Renewable Gasoline 

Blendstock Pathways Using Corn Stover, 2022 (kg CO2-eq./mmBtu)

Fuel Type

Catalytic 

Pyrolysis and 

Upgrade to 

Renewable 

Gasoline and 

Renewable 

Gasoline 

Blendstock 

Biochemical 

Fermentation to 

Renewable 

Gasoline and 

Renewable 

Gasoline 

Blendstock via 

Carboxylic Acid 

Direct Biochemical 

Fermentation to 

Renewable Gasoline 

and Renewable 

Gasoline Blendstock 

2005 

Gasoline 

Baseline

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

% Change from

Baseline -67% -65% -129%
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*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 
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renewable gasoline blendstock routes from cellulosic feedstock as shown in literature. 94,95 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:

 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 

“production strain optimization” in which microorganisms are altered to ferment 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 intermediate 

fermentation 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 fermentation, and catalytic upgrading of 

 

94 Regalbuto, John. “An NSF perspective on next generation hydrocarbon biorefineries,” Computers and Chemical 

Engineering 34 (2010) 1393-1396. February 2010.

95 Serrano-Ruiz, J., Dumesic, James. “Catalytic routes for the conversion of biomass into liquid hydrocarbon 

transportation fuels,” Energy Environmental Science (2011) 4, 83-99.
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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 biomass96 for process energy and that all such production variations 

would also meet the 60% lifecycle threshold.97 

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 

 

96 Our lifecycle analysis assumes that producers would use the same type of biomass as both the feedstock and the 

process energy.

97

 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.
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also ran a sensitivity case where no electricity credit was given. We found that all of the routes 

analyzed would still pass the GHG threshold without an electricity credit, providing confidence 

that over the range of technology options, these process technologies will surely allow the 

cellulosic biofuel produced to exceed the threshold for cellulosic 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 
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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.98 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. 

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%, 

 

98 Kinchin, Christopher. Catalytic Fast Pyrolysis with Upgrading to Gasoline and Diesel Blendstocks. National 

Renewable Energy Laboratory (NREL). 2011.
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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 
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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 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 
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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 
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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
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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 
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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 § 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.

II. 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 §80.1426 to 

clarify that the currently-approved pathway for canola also applies more generally to rapeseed. 
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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 §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 
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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. 

III. 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.
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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. 
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D. Unfunded Mandates Reform Act

This rule does not contain a Federal mandate that may result in expenditures of $100 

million or more for State, local, and tribal governments, in the aggregate, or the private sector in 

any one year. We have determined that this action will not result in expenditures of $100 million 

or more for the above parties and thus, this rule is not subject to the requirements of sections 202 

or 205 of UMRA.

This rule is also not subject to the requirements of section 203 of UMRA because it 

contains no regulatory requirements that might significantly or uniquely affect small 

governments. It only applies to gasoline, diesel, and renewable fuel producers, importers, 

distributors and marketers and makes relatively minor corrections and modifications to the 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
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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. 
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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 lowincome 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 
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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). 

IV. 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). 

Regulation of Fuels and Fuel Additives: Identification of Additional Qualifying Renewable 

Fuel Pathways under the Renewable Fuel Standard Program

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.
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Dated: ____________________________

__________________________________

Lisa P. Jackson,

Administrator

Billing Code: 6550-50-P
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For the reasons set forth in the preamble, 40 CFR part 80 is amended as follows:

PART 80 — REGULATION OF FUELS AND FUEL ADDITIVES

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

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

2. Section 80.1401 is amended by adding definitions of “Renewable Gasoline” and 

“Renewable Gasoline Blendstock” in alphabetical order to read as follows:

§80.1401 Definitions

* * * * *

Renewable gasoline means renewable fuel made from renewable biomass that is 

composed of only hydrocarbons and which meets the definition of gasoline in §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 

§80.2(s).

* * * * *

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

§80.1426 How are RINs generated and assigned to batches of renewable fuel by 

renewable fuel producers or importers? 

* * * * *

(f) * * *

Table 1 to §80.1426—Applicable D Codes for Each Fuel Pathway for Use in Generating 

RINs
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Fuel type Feedstock Production process 

requirements

DCode

A Ethanol Corn starch All of the following:

Dry mill process, using 

natural gas, biomass, or 

biogas for process energy and 

at least two advanced 

technologies from Table 2 to 

this section

6

B Ethanol Corn starch All of the following:

Dry 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

6

C Ethanol Corn starch All of the following:

Dry mill process, using 

natural gas, biomass, or 

biogas for process energy and 

6
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drying no more than 50% of 

the distillers grains with 

solubles it markets annually

D Ethanol Corn starch Wet mill process using 

biomass or biogas for process 

energy

6

E Ethanol Starches from crop residue and 

annual covercrops

Fermentation using natural 

gas, biomass, or biogas for 

process energy

6

F Biodiesel, 

renewable 

diesel, jet fuel 

and heating 

oil

Soy bean oil;

Oil from annual covercrops;

Algal oil;

Biogenic waste oils/fats/greases;

Non-food grade corn oil

Camelina sativa oil

One of the following:

Trans-Esterification

Hydrotreating

Excluding processes that coprocess renewable biomass 

and petroleum

4

G Biodiesel, 

heating oil

Canola/Rapeseed oil Trans-Esterification using 

natural gas or biomass for

process energy

4

H Biodiesel, 

renewable 

diesel, jet fuel 

and heating 

oil

Soy bean oil;

Oil from annual covercrops;

Algal oil;

Biogenic waste oils/fats/greases;

Non-food grade corn oil

One of the following:

Trans-Esterification

Hydrotreating

Includes only processes that 

co-process renewable 

5
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Camelina sativa oil biomass and petroleum

I Naphtha, LPG Camelina sativa oil Hydrotreating 5

J Ethanol Sugarcane Fermentation 5

K Ethanol Cellulosic Biomass from crop 

residue, slash, pre-commercial 

thinnings and tree residue, annual 

covercrops, switchgrass, 

miscanthus, and energy cane

(Saccharum spp.); cellulosic 

components of separated yard 

waste; cellulosic components of 

separated food waste; and 

cellulosic components of 

separated MSW

Any 3

L Cellulosic 

diesel, jet fuel 

and heating 

oil

Cellulosic Biomass from crop 

residue, slash, pre-commercial 

thinnings and tree residue, annual 

covercrops, switchgrass, 

miscanthus, and energy cane

(Saccharum spp.); cellulosic 

components of separated yard 

waste; cellulosic components of 

separated food waste; and 

Any 7
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cellulosic components of 

separated MSW

M Renewable 

gasoline and 

renewable 

gasoline 

blendstock

Cellulosic Biomass from crop 

residue, slash, pre-commercial 

thinnings, tree residue, annual 

cover crops; cellulosic 

components of separated yard 

waste; cellulosic components of 

separated food waste; and 

cellulosic components of 

separated MSW

Catalytic Pyrolysis and 

Upgrading, 

Gasification and Upgrading, 

Thermo-Catalytic 

Hydrodeoxygenation and 

Upgrading, Direct

Fermentation, 

Fermentation and Upgrading, 

all 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

3

N Naphtha Cellulosic biomass from 

switchgrass, miscanthus, and

energy cane (Saccharum spp.)

Gasification and upgrading 3

O Butanol Corn starch Fermentation; dry mill using 

natural gas, biomass, or 

biogas for process energy

6

P Ethanol, The non-cellulosic portions of Any 5
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renewable 

diesel, jet 

fuel, heating 

oil, and 

naphtha

separated food waste

Q Biogas Landfills, sewage waste treatment 

plants, manure digesters

Any 5

R Ethanol Grain Sorghum Dry mill process using biogas 

from landfills, waste 

treatment plants, and/or waste 

digesters, and/or natural gas, 

for process energy

6

S Ethanol Grain Sorghum Dry mill process, using only

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

5
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* * * * *