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EO12866_New Fuel Pathways Rule under RFS2_2060-AR07_FRM_FRN_20110625

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 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 oil, energy cane, giant reed, and 

napiergrass; it also includes an evaluation of renewable gasoline and renewable 

gasoline blendstocks, as well as biodiesel from esterification, and clarifies our definition 

of renewable diesel. 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.
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We are also finalizing two changes to Table 1 to § 80.1426. The first change 

identifies 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 RFS2 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.

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?

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 
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affected by this action include:

Category NAICS1

Codes

SIC2

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 action to a particular entity, consult 

the person in the preceding FOR FURTHER INFORMATION CONTACT section above. 
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Outline of This Preamble

I. Identification of Additional Qualifying Renewable Fuel Pathways under the 

Renewable Fuel Standard (RFS) Program

A. Summary of Comments on Invasive Species

B. Analysis of Lifecycle Greenhouse Gas Emissions for Biodiesel, 

Renewable Diesel, Jet Fuel, Heating Oil, Naphtha, and Liquefied Petroleum Gas 

(LPG) Produced from Camelina Oil

C. Lifecycle Greenhouse Gas Emissions Analysis for Ethanol, Diesel, Jet 

Fuel, Heating Oil, and Naphtha Produced from Energy Cane, Giant Reed, and 

Napiergrass

D. Lifecycle Greenhouse Gas Emissions Analysis for Certain Renewable 

Gasoline and Renewable Gasoline Blendstocks Pathways

E. Esterification Production Process Inclusion for Specified Feedstocks 

Producing Biodiesel

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

III. 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

IV. Statutory Provisions and Legal Authority

I. 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. Although only a limited 

number of relevant adverse comments were received, EPA was required to issue a 
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withdrawal notice of the direct final rule on March 5, 2012. A second comment period 

was not issued, since the simultaneous publication of the proposed rule provided an 

adequate notice and comment process. EPA has addressed the comments received in 

this final rule, although most of the analysis presented is similar to the information in the 

proposed rule. EPA is including all of the information again in this document to avoid 

potential confusion raised by the withdrawal process. 

In this action, EPA is issuing a final rule to identify in the RFS regulations 

additional renewable fuel production pathways that we have determined meet the 

greenhouse gas (GHG) reduction requirements of the RFS program. There are three 

critical components of a renewable fuel pathway: (1) fuel type, (2) feedstock, and (3) 

production process. Each specific combination of the three components, or fuel 

pathway, is assigned a D code. This final rule describes EPA’s evaluation of: 

Camelina 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, giant reed, and napiergrass cellulosic biomass (new feedstocks)

 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, 
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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

Esterification (new production process)

 Process used to produce certain renewable fuels from soybean oil, oil from 

annual covercrops, algal oil, biogenic waste oils/fats/greases, non-food grade 

corn oil, Canola/rapeseed oil, and camelina oil – qualifying to generate 

biomass-based diesel and advanced biofuel RINs

This final rule adds these pathways to Table 1 to § 80.1426 and assigns each 

pathway one or more D-Codes. This final rule allows producers or importers of fuel 

produced under these pathways to generate Renewable Identification Numbers (RINs) 

in accordance with the RFS regulations, providing that the fuel meets other definitional 

criteria for renewable fuel. 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 
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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.

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 (RFS2) Final Rule, published March 26, 2010. The evaluations here rely on 

comparisons to the existing analysis. EPA plans to periodically review and revise the 

methodology and assumptions associated with calculating the GHG emissions from all 

renewable fuel pathways. 

A. Summary of Comments on Invasive Species

In response to the proposed rule, EPA received comments highlighting the 

concern that by approving new feedstock types under the RFS program, EPA would be 

encouraging their introduction or expanded planting without considering their potential 

impact as invasive species.1 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 Arundo donax (giant 

reed) and napiergrass have been identified as invasive species in certain parts of the 

country. These commenters asserted that the Arundo donax and napiergrass 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 13112.

 

1

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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Executive Order 131122, signed in February, 1999, requires Federal agencies to:

 identify actions that may affect invasive species;

 use relevant programs and authorities to, inter alia, prevent the introduction of 

invasive species; and

 to the extent practicable and permitted by law... “not authorize, fund, or carry out 

actions that it believes are likely to cause or promote the introduction or spread of 

invasive species in the United States or elsewhere unless, pursuant to guidelines 

that it has prescribed, the agency has determined and made public its 

determination that the benefits of such actions clearly outweigh the potential 

harm caused by invasive species; and that all feasible and prudent measures to 

minimize risk of harm will be taken in conjunction with the actions.”3

The Executive Order defines “invasive species” as an alien species whose 

introduction does or is likely to cause economic or environmental harm or harm to 

human health.” The Executive Order calls for agencies to address the issue of invasive 

species “to the extent practicable and permitted by law,” in situations where agencies 

“authorize, fund, or carry out actions that it believes are likely to cause or promote the 

introduction or spread of invasive species.” However, in this rulemaking, as required by 

the statute, EPA is making a determination as to whether the use of certain biofuels 

would decrease lifecycle emissions of GHG beyond a statutory threshold. The focus of 

this rulemaking is the lifecycle analysis for the production and use of biofuels, with 

cultivation of these crops relevant to the extent it relates to the GHG lifecycle analysis. 

 

2

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

3

EO 13112 § 2(a)(3) (1999).
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Whether these crops will be grown for biofuels, in what locations, and in what quantities, 

will ultimately be decided by market actors, based on competition with other crops, fuels 

and feedstocks, as subject to state, federal, local regulations. This includes the 

requirements in the RFS program which limit the locations in which crops can be grown 

for purposes of feedstock for a RIN generating renewable fuel. However, this rule may 

provide an incentive for those market actors to produce these feedstocks. As discussed 

below, EPA has carefully considered the issues raised concerning invasive species, and 

is approving pathways that include the proposed feedstocks, as they meet the GHG 

emissions reductions specified in the CAA for the RFS program.

None of the feedstocks included in this rulemaking are currently listed on the 

Federal Noxious Weed List4, however Arundo donax is listed as a noxious or invasive 

species by Texas5, Nevada6, and California7, and these states have programs in place 

to address invasive species concerns. Several other states also consider Arundo donax 

a plant of concern,8,9,10,11 and napiergrass is currently not recommended in Florida 

because of invasive potential.12 EPA also received comments stating that Arundo 

 

4

http://plants.usda.gov/java/noxious?rptType=Federal&statefips=&sort=sc. Accessed on March 28, 2012. 

5

See http://info.sos.state.tx.us/fids/200701978-1.html. Accessed on March 30, 2012. 

6

See http://agri.nv.gov/nwac/PLANT_NoxWeedList.htm. Accessed on May 23, 2012

7

Seehttp://pi.cdfa.ca.gov/pqm/manual/pdf/107.pdf. Accessed on March 30, 2012. 

8

See http://www.gaeppc.org/list.cfm. Accessed on May 23, 2012.

9

See http://www.se-eppc.org/pubs/scbooklet.pdf. Accessed on March 30, 2012. 

10 See http://www.dcr.virginia.gov/natural_heritage/documents/invlist.pdf. Accessed on March 30, 2012. 

11 See http://www.tneppc.org/invasive_plants. Accessed on March 30, 2012. 

12 IFAS Assessment of Non-native Plants in Florida’s Natural Areas, 2009. 
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donax is not “invasive” as defined by EO 13112, since Arundo donax “only presents 

problems of invasiveness in riparian areas prone to torrential flooding... giant reed has 

been grown responsibly in numerous places...without problems of invasiveness.”

13

 

Section 211(o) of the CAA defines renewable fuel as fuel produced from 

renewable biomass, and defines categories of renewable fuel in terms of reductions in 

lifecycle GHG emissions compared to the baseline gasoline or diesel fuel. Section 

211(o)(1)(B),(D),(E),(J). The definition of renewable biomass also specifies certain 

conditions that biomass must meet to be considered renewable biomass. Section 

211(o)(1)(I). However the definition of renewable biomass does not refer to the wide 

variety of other factors that may relate to the impact of the biomass or the fuel on air 

quality, the environment, and various other impacts. Separately, Congress does specify 

that EPA is to consider these kinds of factors, including environmental impacts of the 

production and use of renewable fuels, but this consideration is in the context of 

determining the required volumes of renewable fuel for years where Congress does not 

specify specific volumes. Section 211(o)(2)(B)(ii). Given the text and structure of 

section 211(o), EPA does not appear to have the discretion to consider factors other 

than the lifecycle analysis of GHG emissions and the definition of renewable biomass in 

determining whether a fuel produced from biomass should be considered a renewable 

fuel for purposes of the RFS program. 

Nonetheless, the Executive Order emphasizes the importance of addressing the 

potential impacts of invasive species to the extent practicable. In that context, there are

a number of state, federal, and local mechanisms in place that could be used to reduce 

 

13Comment submitted by R. Timothy Columbus and Christopher G. Falcone, Steptoe & Johnson LLP on behalf of 

The Chemtex Group, dated February 13, 2012. Document ID# EPA-HQ-OAR-2011-0542-0124. 
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the potential invasive impacts of Arundo donax. For example, if producers were to apply 

for the Biomass Crop Assistance Program (BCAP), the United States Department of 

Agriculture (USDA) would require an environmental assessment that analyzes the risk 

of invasiveness. A similar analysis was required for miscanthus, which is an approved 

RFS2 feedstock that may be considered invasive in certain circumstances.14 In 

addition, USDA’s Conservation Reserve Program (CRP) can also impose restrictions on 

farmers interested in growing Arundo donax on CRP land. Other requirements are also 

in place that would restrict the growing patterns of these feedstocks for use in the RFS2 

program. For example, any fuel produced for the RFS2 would also have to meet the 

definition of renewable biomass, and could therefore only be planted on existing 

agricultural land.

Furthermore, invasive species are controlled and regulated under various 

existing federal and state guidelines. The Animal and Plant Health Inspection Service 

(APHIS) of the United States Department of Agriculture (USDA) regulates noxious 

weeds under the authority of the Plant Protection Act (PPA). APHIS names the 

regulated weeds in the noxious weed regulations (7 CFR 360) in order to ensure 

transparency. Listed kinds may not be imported into the United States, or moved 

interstate, without a special permit. 

The risk posed by potentially invasive feedstocks can be managed through the 

use of best practices.15 Commenters referenced the voluntary best practices document 

 

14 See http://www.fsa.usda.gov/Internet/FSA_File/finaleagiantmcanthus.pdf

15 Comment submitted by R. Timothy Columbus and Christopher G. Falcone, Steptoe & Johnson LLP on behalf of 

the Biofuels Center of North Carolina and the Institute for Sustainable and Renewable Resources, dated February 

13, 2012. Document ID# EPA-HQ-OAR-2011-0542-0123
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developed jointly by the North Carolina Department of Agriculture and Consumer 

Services, the NC State University Cooperative Extension, and the Biofuel Center of 

North Carolina. Many of the recommendations developed in this document are similar 

to the best practices USDA describes for the management of similar energy crops such 

as switchgrass and miscanthus.16 For example, both USDA and the North Carolina 

voluntary standards recommend developing management plans that avoid sites without 

buffer areas and production in floodplains. 

This determination is not a tacit approval to grow these feedstocks without having 

to meet any other appropriate local, state, or federal mandates associated with control 

of invasive species. This rulemaking is also not a determination that a risk assessment 

would not be appropriate to evaluate invasiveness based on the specific location and 

species of plant being grown. As a member of the federal National Invasive Species 

Council17, EPA will continue to work with this body and its member agencies, including 

the USDA, to monitor, avoid, and mitigate the risk from invasive species. As a 

participant in this Council, EPA encourages producers to work with local, state, and 

federal agencies to develop and adopt best practices – such as buffers for riparian 

areas – for minimizing any potential invasive species impacts of feedstocks considered 

under this rule. 

 

16 See http://www.nrcs.usda.gov/Internet/FSE_DOCUMENTS/stelprdb1044768.pdf

17 http://www.invasivespecies.gov/
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B. 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 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 (RFS2) 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.18 Compared to 

many other oilseeds, camelina has a relatively short growing season (less than 100 

days), and can be grown either as a spring annual or in the winter in milder climates.

19,20

 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 

 

18 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

19 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.

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

http://msuextension.org/publica¬tions/AgandNaturalResources/MT200701AG.pdf.
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such grains (like wheat) in the following year.21 

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.22 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.23 The FDA has not 

approved camelina for food uses, although it has approved the inclusion of certain 

quantities of camelina meal in commercial feed.24 

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

U.S., primarily in Montana, eastern Washington, and the Dakotas.25 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.26

In response to the proposed rule, two commenters were supportive of the use of 

 

21 Putnam et al., 1993

22

 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.

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

24 See http://agr.mt.gov/camelina/FDAletter11-09.pdf. 

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

2009.

26 See https://www.camelinacompany.com/Marketing/PressRelease.aspx?Id=25
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renewable feedstocks such as camelina oil to produce biofuels for aviation. One 

commenter noted that aviation is unique in its complete dependency upon liquid fuel -

today and into the foreseeable future. Another commenter noted that development of 

additional feedstocks and production pathways should increase supply and ultimately 

move us closer to the day when renewable jet fuels are price-competitive with legacy 

fossil fuels and help cut our dependence on foreign oil. EPA also received comment 

regarding a concern that EPA did not adequately establish that camelina would only be 

grown on fallow land and therefore would not have a land use impact and that EPA 

overestimated the likely yields in growing camelina and therefore underestimated the 

land requirements. 

In terms of the comment on camelina not being grown on fallow land, for the 

purposes of analyzing the lifecycle GHG emissions of camelina, EPA has considered 

the likely production pattern for camelina grown for biofuel production. Given the 

information currently available, camelina is expected to be primarily planted in the U.S. 

as a rotation crop on acres that would otherwise remain fallow. Because camelina has 

not yet been established as a commercial crop with significant monetary value, farmers 

are unlikely to dedicate acres that could otherwise be used to produce cash crops solely 

for camelina production. Since camelina would therefore not be expected to displace 

another crop, EPA does not believe new acres would need to be brought into 

agricultural use to increase camelina production. In addition, camelina currently has 

only limited high-value niche markets for uses other than renewable fuels. Unlike 

commercial crops that are tracked by USDA, camelina does not have a wellestablished, internationally traded market that would be significantly affected by an 
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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 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 
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compared to wheat and other crops with established, commercially traded markets.27 

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.28 However, the inclusion of oilseed 

crops can improve overall water use efficiency and the long term economic productivity 

of wheat acres. In addition, selective breeding is expected to reduce the potential 

negative impacts on wheat yields.29 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. 

 

27 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.

28 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. 

29 See Shonnard et al., 2010; Lafferty et al., 2009
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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

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
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Shaded cells indicate fallow months Hatched line cells indicate growing moths

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. Consistent with 

EPA’s approach to all RFS2 feedstock pathway analyses, we will periodically reevaluate 

whether our assessment of GHG impacts will need to be updated in the future. 

a. Land Availability

USDA estimates that there are approximately 60 million acres of wheat in the 

U.S.30 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.31 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 

 

30 2009 USDA Baseline. See http://www.ers.usda.gov/publications/oce091/

31 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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used to produce camelina, even though a recent paper stated that only 5 million acres 

would have the potential to grow camelina in a sustainable manner in a way that would 

not impact the food supply. This commenter misinterpreted EPA’s assumptions. EPA’s 

assessment is based on a three year rotation cycle in which only one third of the 9 

million available acres would be fallow in any given year. In other words, EPA assumed 

only 3 million acres would be planted with camelina in any given year. This number is 

less than the 5 million acres the Shonnard et. al. paper states would be available 

annually for camelina planting. 

b. Projected Volumes

Based on these projections of land availability, EPA estimates that at current 

yields (approximately 800 pounds per acre), approximately 100 million gallons (MG) of 

camelina-based renewable fuels could be produced with camelina grown in rotation with 

existing crop acres without having direct land use change impacts. Also, since 

camelina will likely be grown on fallow land and thus not displace any other crop and 

since camelina currently does not have other significant markets, expanding production 

and use of camelina for biofuel purposes is not likely to have other agricultural market 

impacts and therefore, would not result in any significant indirect land use impacts.32

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.33 Yields of 1650 

 

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

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

33 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.
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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,34 approximately 200 MG of camelina-based renewable fuels could be 

produced on existing wheat/fallow acres. Finally, if investment in new seed technology 

allows yields to increase to levels assumed by Shonnard et al (3000 pounds per acre), 

approximately 400 MG of camelina-based renewable fuels could be produced on 

existing acres.35 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 use36. 

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 increase over time. 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

 

34

 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, 

35 See Shonnard et al., 2010

36 This assumes no significant adverse climate impacts on world agricultural yields over the analytical timeframe. 
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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.37 Because expected returns on camelina are relatively uncertain, 

farmers are not expected to grow camelina on land that would otherwise be used to 

grow cash crops with well established prices and markets. Instead, farmers are most 

likely to grow camelina on land that would otherwise be left fallow for a season. The 

opportunity cost of growing camelina on this type of land is much lower. As previously 

discussed, this type of land represents the 9 million acres currently being targeted for 

camelina production. Current returns on camelina are relatively low ($13.24 per acre), 

given average yields of approximately 800 pounds per acre and the current contract 

price of $0.145 per pound.38 See Table 1. For comparison purposes, the USDA 

projections for wheat returns are between $88-$105 per acre between 2010 and 2020. 

Over time, advancements in seed technology, improvements in planting and harvesting 

techniques, and higher input usage could significantly increase future camelina yields 

and returns. 

Table 1: Camelina Costs and Returns

2010 Camelina39 2022 

Camelina40

2030 

Camelina41

 

37 See Lafferty et al, 2009; Shonnard et al, 2010; Sustainable Oils Memo dated November 5, 2010, 

38 Wheeler & Guillen-Portal, 2007

39 See Sustainable Oils Memo dated November 5, 2010, 

40Based on yields technically feasible. See McVey and Lamb, 2008; Ehrenson & Guy, 2008.
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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 lb/acre)

$15.00

(15 lb/acre)

$15

(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 

 

41 Adapted from Shonnard et al, 2010.
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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.42 For example, if camelina production expanded beyond the 9 million 

acres assumed available from wheat fallow land, it could impact other crops. However, 

as discussed above this is not likely to happen in the near term due to uncertainties in

camelina financial returns. Camelina production could also occur in areas where wheat 

is not commonly grown. For example, testing of camelina production has occurred in 

Florida in rotation with kanaf, peanuts, cotton, and corn. However, only 200 acres of 

camelina were harvested in 2010 in Florida. While Florida acres of camelina are 

expected to be higher in 2011, very little research has been done on growing camelina 

in Florida. For example, little is known about potential seedling disease in Florida or 

how camelina may be affected differently than in colder climates.43 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 

 

42 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. 

43 Wright & Marois, 2011. 
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any country. For the same reasons that pertain to U.S. production of camelina, we 

expect that camelina grown in other countries would also be produced on land that 

would otherwise be fallow and would therefore have no significant land use change 

impacts. The renewable biomass provisions under the Energy Independence and 

Security Act would prohibit direct land conversion into new agricultural land for camelina 

production for biofuel internationally. Additionally, any camelina production on existing 

cropland internationally would not be expected to have land use impacts beyond what 

was considered for international soybean production (soybean oil is the expected major 

feedstock source for US biodiesel fuel production and thus the feedstock of reference 

for the camelina evaluation). Because of these factors along with the small amounts of 

fuel potentially coming from other countries, we believe that incorporating fuels 

produced in other countries will not impact our threshold analysis for camelina-based 

biofuels.

d. Crop Inputs

For comparison purposes, Table 2 shows the inputs required for camelina 

production compared to the FASOM agricultural input assumptions for soybeans. Since 

yields and input assumptions vary by region, a range of values for soybean production 

are shown in Table 2. The camelina input values in Table 2 represent average values, 

camelina input values will also vary by region, however, less data is available 

comparing actual practices by region due to limited camelina production. More 

information on camelina inputs is available in materials provided in the docket. 
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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, pesticide, and petroleum use. 

In summary, EPA concludes that the agricultural inputs for growing camelina are 

similar to those for growing soy beans, direct land use impact is expected to be 

negligible due to planting on land that would be otherwise fallow, and the limited 

production and use of camelina indicates no expected impacts on other crops and 

therefore no indirect land use impacts. 

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 

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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discussed above, camelina seeds produce more oil per pound than soybeans. As a 

result, the lifecycle GHG emissions associated with crushing and oil extraction are lower 

for camelina than soybeans, per pound of vegetable oil produced. Table 3 summarizes 

data on inputs, outputs and estimated lifecycle GHG emissions from crushing and oil 

extraction. The data on soybean crushing comes from the RFS2 final rule, based on a 

process model developed by USDA-ARS.44 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

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 

 

44 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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per pound of seed, as discussed above, the energy needed to move the camelina would 

be lower than soybeans per gallon of fuel produced. To the extent that camelina is 

grown on more disperse fallow land than soybean and would need to be transported 

further, the energy needed to move the camelina could be higher than soybean. We

believe the assumption to use the same distribution impacts for camelina as soybean is 

a reasonable estimate of the GHG emissions from camelina feedstock distribution. In 

addition, the final fuel produced from camelina is also expected to be similar in 

composition to the comparable fuel produced from soybeans, therefore we are 

assuming GHG emissions from the distribution and use of fuels made from camelina will 

be the same as emissions of fuel produced from soybeans. 

3. Fuel Production

There are two main fuel production processes used to convert camelina oil into 

fuel. The trans-esterification process produces biodiesel and a glycerin co-product. 

The hydrotreating process can be configured to produce renewable diesel either 

primarily as diesel fuel (including heating oil) or primarily as jet fuel. Possible additional 

products from hydrotreating include naphtha LPG, and propane. Both processes and 

the fuels produced are described in the following sections. Both processes use 

camelina oil as a feedstock and camelina crushing is also included in the analysis. 

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 
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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 RFS2 final rule. Therefore the same coproduct credit would apply to glycerin from camelina biodiesel as glycerin produced in 

the biodiesel pathways modeled for the RFS2 final rule. The assumption is that the 

GHG reductions associated with the replacement of residual oil with glycerin on an 

energy equivalent basis represents an appropriate midrange co-product credit of 

biodiesel produced glycerin. 

As part of our RFS2 proposal, we assumed the glycerin would have no value and 

would effectively receive no co-product credits in the soy biodiesel pathway. We 

received numerous comments, however, 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 RFS2 final rule took into 

consideration the possible range of co-product credit results. The actual co-product 

benefit will be based on what products are replaced by the glycerin and what new uses 

develop for the co-product glycerin. The total amount of glycerin produced from the 

biodiesel industry will actually be used across a number of different markets with 

different GHG impacts. This could include for example, replacing petroleum glycerin, 

replacing fuel products (residual oil, diesel fuel, natural gas, etc.), or being used in new 
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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 RFS2 rule) on which to allocate glycerin use across the range of likely uses. 

Therefore, EPA believes that the approach used in RFS2 of picking a surrogate use for 

modeling purposes in the mid-range of likely glycerin uses, and the GHG emissions 

results tied to such use, is reasonable. The replacement of an energy equivalent 

amount of residual oil is a simplifying assumption determined by EPA to reflect the midrange of possible glycerin uses in terms of GHG credits. EPA believes that it is 

appropriately representative of GHG reduction credit across the possible range without 

necessarily biasing the results toward high or low GHG impact. Given the fundamental 

difficulty of predicting possible glycerin uses and impacts of those uses many years into 

the future under evolving market conditions, EPA believes it is reasonable to use the 

more simplified approach to calculating co-product GHG benefit associated with glycerin 

production at this time. EPA will continue to evaluate the co-product credit associated 

with glycerine production in future rulemakings. 

Given the fact that GHG emissions from camelina-based biodiesel would be 

similar to the GHG emissions from soybean- based biodiesel at all stages of the 

lifecycle but would not result in land use change as was the case for soy oil used as a 
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feedstock, we believe biodiesel from camelina oil will also meet the 50% GHG 

emissions reduction threshold to qualify as a biomass based diesel and an advanced 

fuel. Therefore, EPA is including biodiesel produced from camelina oil under the same 

pathways for which biodiesel made from soybean oil qualifies under the RFS2 final rule. 

b. Renewable Diesel (Including Jet Fuel and Heating Oil), Naphtha, and LPG

The same feedstocks currently used for biodiesel production can also be used in 

a hydrotreating process to produce a slate of products, including diesel fuel, heating oil 

(defined as No. 1 or No. 2 diesel), jet fuel, naphtha, LPG, and propane. Since the term 

renewable diesel is defined to include the products diesel fuel, jet fuel and heating oil, 

the following discussion uses the term renewable diesel to also include diesel fuel, jet 

fuel and heating oil. The yield of renewable diesel is relatively insensitive to feedstock 

source.45 While any propane produced as part of the hydrotreating process will most 

likely be combusted within the facility for process energy, the other co-products that can 

be produced (i.e., renewable diesel, naphtha, LPG) are higher value products that could 

be used as transportation fuels or, in the case of naphtha, a blendstock for production of 

transportation fuel. The hydrotreating process maximized for producing a diesel fuel 

replacement as the primary fuel product requires more overall material and energy 

inputs than transesterification to produce biodiesel, but it also results in a greater 

amount of other valuable co-products as listed above. The hydrotreating process can 

also be maximized for jet fuel production which requires even more process energy than 

the process optimized for producing a diesel fuel replacement, and produces a greater 

amount of co-products per barrel of feedstock, especially naphtha.

 

45 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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Producers of renewable diesel from camelina have expressed interest in 

generating RINs under the RFS2 program for the slate of products resulting from the 

hydrotreating process. Our lifecycle analysis accounts for the various uses of the coproducts. 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 coproducts. There are a number of ways to do this but since the main use of the coproducts 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 
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replacement fuel a displacement credit for these co-products. Instead, the lifecycle 

GHG emissions from the fuel production processes would be allocated to each of the 

RIN-generating products on an energy content basis. This has the effect of tending to 

increase the fuel production lifecycle GHG emissions associated with the diesel 

replacement fuel because there are less co-product displacement credits to assign than 

would be the case if RINs were not generated for the co-products.46 On the other hand, 

the upstream lifecycle GHG emissions associated with producing and transporting the 

plant oil feedstocks will be distributed over a larger group of RIN-generating products. 

Assuming each product (except propane) produced via the camelina oil hydrotreating 

process will generate RINs results in higher lifecycle GHG emissions for diesel fuel 

replacement as compared to the case where the co-products are not used to generate 

RINs. This general principle is also true when the hydrotreating process is maximized 

for jet fuel production. As a result, the worst GHG performance (i.e., greatest lifecycle 

GHG emissions) for diesel replacement fuel and jet fuel produced from camelina oil via 

hydrotreating will occur when all of the co-products are RIN-generating (we assume 

propane will be used for process energy). Thus, if these fuels meet the 50% GHG 

reduction threshold for biomass based diesel or advanced biofuel when co-products are 

RIN-generating, they will also do so in the case when RINs are not generated for coproducts. 

We have evaluated information about the lifecycle GHG emissions associated 

with the hydrotreating process which can be maximized for jet fuel or diesel 

 

46 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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replacement fuel production. Our evaluation considers information published in peerreviewed journal articles and publicly available literature (Kalnes et al, 2010, Pearlson, 

M., N., 2011, 47 Stratton et al., 2010, Huo et al., 200848). 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.49 This data is summarized in Table 4. 

Table 4: Hydrotreating Processes to Convert Camelina Oil into Diesel 

Replacement Fuel and Jet Fuel50

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

 

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

Distillate Fuels. 

48 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

49 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.

50 Based on Pearlson (2011), Table 3.1 and Table 3.2
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Outputs

Diesel Fuel 123,136 55,845 Btu

Jet fuel 23,197 118,669 Btu

Naphtha 3,306 17,042 Btu

LPG 3,084 15,528 Btu

Propane 7,454 9,881 Btu

Table 5 compares lifecycle GHG emissions from oil extraction and fuel 

production for soybean oil biodiesel and for camelina-based diesel and jet fuel. The 

lifecycle GHG estimates for camelina oil diesel and jet fuel are based on the 

input/output data summarized in Table 3 (for oil extraction) and Table 4 (for fuel 

production). We assume that the propane co-product does not generate RINs; instead, 

it is used for process energy displacing natural gas. We also assume that the naphtha 

is used as blendstock for production of transportation fuel to generate RINs. In this 

case we assume that RINs are generated for the use of LPG in a way that meets the 

EISA definition of transportation fuel, for example it could be used in a nonroad vehicle. 

The lifecycle GHG results in Table 5 represent the worst case scenario (i.e., highest 

GHG emissions) because all of the eligible co-products are used to generate RINs. 

This is because, as discussed above, lifecycle GHG emissions per Btu of diesel or jet 

fuel would be lower if the naphtha or LPG is not used to generate RINs and is instead 

used for process energy displacing fossil fuel such as natural gas. Supporting 

information for the values in Table 5, including key assumptions and data, is provided 

through the docket. 
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Table 5: Fuel Production Lifecycle GHG Emissions (kgCO2e / mmBtu)51

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 RINgenerating product from the same process will be assigned equal lifecycle GHG 

 

51 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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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 
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GHG emissions for RIN-generating co-products are very similar, we can also conclude 

renewable gasoline blendstock and LPG produced from camelina oil will also meet the 

50% GHG emissions reduction threshold. If the facility does not actually generate RINs 

for one or more of these co-products, we estimate that the lifecycle GHG emissions 

related to the RIN-generating products would be lower, thus renewable diesel (which 

includes diesel fuel, jet fuel, and heating oil) from camelina would still meet the 50% 

emission reduction threshold. 

4. Summary

Current information suggests that camelina will be produced on land that would 

otherwise remain fallow. Therefore, increased production of camelina-based renewable 

fuel is not expected to result in significant land use change emissions. For the purposes 

of this analysis, EPA is projecting there will be no land use emissions associated with 

camelina production for use as a renewable fuel feedstock. 

However, while production of camelina on acres that would otherwise remain 

fallow is expected to be the primary means by which the majority of all camelina is 

commercially harvested in the short- to medium- term, in the long term camelina may 

expand to other growing methods and lands if demand increases substantially beyond 

what EPA is currently predicting. While the impacts are uncertain, there are some 

indications demand could increase significantly. For example, camelina is included 

under USDA’s Biomass Crop Assistance Program (BCAP) and there is growing support 

for the use of camelina oil in producing drop-in alternative aviation fuels. EPA plans to 

monitor the expansion of camelina production to verify whether camelina is primarily 

grown on existing acres once camelina is produced at larger-scale volumes. Similarly, 
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we will consider market impacts if alternative uses for camelina expand significantly 

beyond what was described in the above analysis. Just as EPA plans to periodically 

review and revise the methodology and assumptions associated with calculating the 

GHG emissions from all renewable fuel feedstocks, EPA expects to review and revise 

as necessary the analysis of camelina in the future. 

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

camelina is used to produce renewable fuel, and considering that other sources of GHG 

emissions related to camelina biodiesel or renewable diesel production have 

comparable GHG emissions to biodiesel from soybean oil, we have determined that 

camelina-based biodiesel and renewable diesel should be treated in the same manner 

as soy-based biodiesel and renewable diesel in qualifying as biomass-based diesel and 

advanced biofuel for purposes of RIN generation, since the GHG emission performance 

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

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

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

GHG emissions compared to the baseline petroleum diesel fuel. Furthermore, 

approximately 80% of the lifecycle impacts from soybean biodiesel were from land use 

change emissions which are assumed to be not significant for the camelina pathway 

considered. Thus, EPA is including camelina oil as a potential feedstock under the 

same biodiesel and renewable diesel (which includes diesel fuel, jet fuel, and heating 

oil) pathways for which soybean oil currently qualifies. We are also including a pathway 

for naphtha and LPG produced from camelina oil through hydrotreating. This is based 

on the fact that our analysis shows that even when all of the co-products are used to 
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generate RINs the lifecycle GHG emissions for RIN-generating co-products including 

diesel replacement fuel, jet fuel, naphtha and LPG produced from camelina oil will all 

meet the 50% GHG emissions reduction threshold. 

We are also clarifying that two existing pathways for RIN generation in the RFS 

regulations that list "renewable diesel" as a fuel product produced through a 

hydrotreating process include jet fuel. This applies to two pathways in Table 1 to 

§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 coprocess 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 RFS2 

final rule, identifies jet fuel and renewable diesel as separate fuel types. Accordingly, in 

light of the revised definition of renewable diesel enacted after the RFS2 rule, there is 

ambiguity regarding the extent to which references in Table 1 to “renewable diesel” 

include jet fuel.
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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 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 §80.1426.52 As was discussed previously, if 

the displacement approach is used when jet fuel is the primary product produced it 

results in lower emissions then the production maximized for diesel fuel production. 

Therefore, since the hydrotreating process maximized for diesel fuel meets the 50% 

lifecycle GHG threshold for the feedstocks in question, the process maximized for jet 

fuel would also qualify. 

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. 

 

52 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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We note that although the definition of renewable diesel includes jet fuel and 

heating oil, we have also listed in Table 1 of section 80.1426 of the RFS2 regulations jet 

fuel and heating oil as specific co-products in addition to listing renewable diesel to 

assure clarity. This clarification also pertains to all the feedstocks already included in 

Table 1 for renewable diesel. 

C. Lifecycle Greenhouse Gas Emissions Analysis for Ethanol, Diesel, Jet 

Fuel, Heating Oil, and Naphtha Produced from Energy Cane, Giant Reed, 

and Napiergrass

For this rulemaking, EPA considered the lifecycle GHG impacts of three new 

types of high-yielding perennial grasses similar in cellulosic composition to switchgrass 

and comparable in status as an emerging energy crop. The three grasses considered 

in this rulemaking are energy cane (related to sugarcane), giant reed (Arundo donax), 

and napiergrass (pennisetum purpureum), also known as elephant grass. In the 

proposed and final RFS2 rule, EPA analyzed the lifecycle GHG impacts of producing 

and using cellulosic ethanol and cellulosic Fischer-Tropsch diesel from switchgrass. 

The midpoint of the range of switchgrass results showed a 110% GHG reduction (range 

of 102%-117%) for cellulosic ethanol (biochemical process), a 72% (range of -64% to -

79%) reduction for cellulosic ethanol (thermochemical process), and a 71% (range of -

62% to -77%) reduction for cellulosic diesel (F-T process) compared to the petroleum 

baseline. In the RFS2 final rule, we indicated that some feedstock sources can be 

determined to be similar enough to those modeled that the modeled results could 

reasonably be extended to these similar feedstock types. For instance, information on 

miscanthus indicated that this perennial grass will yield more feedstock per acre than 
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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, giant reed, or 

napiergrass as feedstocks for the cellulosic biofuel pathways in Table 1 at that time, 

since we did not have sufficient time to adequately consider them. Based in part on 

additional information received through the petition process for EPA approval of energy 

cane, giant reed, and napiergrass pathways, EPA has evaluated these feedstocks and 

is now including these three feedstocks 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 these feedstocks to switchgrass and miscanthus, EPA believes that new 

agricultural sector modeling is not needed to analyze them. We have instead relied 

upon the switchgrass analysis to assess the relative GHG impacts of biofuel produced

from energy cane, giant reed, and napiergrass. As with the switchgrass analysis, we 

have attributed all land use impacts and resource inputs from use of these feedstocks to 

the portion of the fuel produced that is derived from the cellulosic components of the 

feedstocks. Based on this analysis and currently available information, we conclude 

that biofuel (ethanol, cellulosic diesel, jet fuel, heating oil and naphtha) produced from 
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the cellulosic biomass of energy cane, giant reed, or napiergrass has similar lifecycle 

GHG impacts to switchgrass biofuel and meets the 60% GHG reduction threshold 

required for cellulosic biofuel. 

1. Feedstock Production and Distribution

For the purposes of this rulemaking, energy cane refers to varieties of perennial 

grasses in the Saccharum genus which are intentionally bred for high cellulosic biomass 

productivity but have characteristically low sugar content making them unsuitable as a 

primary source of sugar as compared to other varieties of grasses commonly known as 

“sugarcane” in the Saccharum genus. Energy cane varieties developed to date have 

low tolerance for cold temperatures but grow well in warm, humid climates. Energy cane 

originated from efforts to improve disease resistance and hardiness of commercial 

sugarcane by crossbreeding commercial and wild sugarcane strains. Certain higher 

fiber, lower sugar varieties that resulted were not suitable for commercial sugar 

production, and are now being developed as a high-biomass energy crop. There is 

currently no commercial production of energy cane. Current plantings are mainly limited 

to research field trials and small demonstrations for bioenergy purposes. However, 

based in part on discussions with industry, EPA anticipates continued development of 

energy cane particularly in the south-central and southeastern United States due to its 

high yields in these regions.

Giant reed refers to the perennial grass Arundo donax of the Poaceae family. 

Giant reed thrives in subtropical and warm-temperate areas and is grown throughout 

Asia, southern Europe, Africa, the Middle East, and warmer U.S. states for multiple 

uses such as paper and pulp, musical instruments, rayon, particle boards, erosion 
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control, and ornamental purposes.53,54 Based in part on discussions with industry, EPA 

anticipates continued development of giant reed as an energy crop particularly in the 

Mediterranean region and warmer U.S. states. 

Napiergrass is a tall bunch-type grass that has traditionally been grown as a 

high-yielding forage crop across the wet tropics. There is a considerable body of 

agronomic research on the production of napiergrass as a forage crop. More recently, 

researchers have investigated ways to maximize traits desirable in bioenergy crops. 

Practices have been developed by USDA and other researchers to lower fertilization 

rates and increase biomass production. Based in part on discussions with industry, 

EPA anticipates continued development of napiergrass as an energy crop particularly in 

Gulf Coast Region of the United States (more specifically the growing region includes 

Florida and southern portions of Texas, Louisiana, Georgia, Alabama and Mississippi).55

a. Crop Yields

For the purposes of analyzing the GHG emissions from energy cane, giant reed, 

and napiergrass production, EPA examined crop yields and production inputs in relation 

to switchgrass to assess the relative GHG impacts. Current national yields for 

switchgrass are approximately 4.5 to 5 dry tons per acre. Average energy cane yields 

exceed switchgrass yields in both unfertilized and fertilized trails conducted in the 

southern United States. Unfertilized yields are around 7.3 dry tons per acre while 

 

53See http://www.fs.fed.us/database/feis/plants/graminoid/arudon/all.html

54 See Lewandowski, I., Scurlock, J.M.O., Lindvall, E., Christou, M. (2003). The development and current status of 

perennial rhizomatous grasses as energy crops in the US and Europe. Biomass and Bioenergy 25, 335-361.

55 For a map depicting the northern limit for sustained napiergrass production in the United States see Figure 1 in 

Woodard, K., R. and Sollenberger, L, E. 2008. Production of Biofuel Crops in Florida: Elephantgrass. Institute of 

Food and Agricultural Sciences, University of Florida. SS AGR 297.
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fertilized trials show energy cane yields range from approximately 11 to 20 dry tons per 

acre.56,57 Until recently there have been few efforts to improve energy cane yields, but 

several energy cane development programs are now underway to further increase its 

biomass productivity. Giant reed field trials conducted in Alabama over a 9-year period 

showed an average yield of 15 dry tons per acre with no nitrogen fertilizer applied after 

the first year.58 Fertilized field trials have shown yields around 13 to 28 dry tons per acre 

in Spain, and 12 dry tons per acre in Italy (based on annual yields of 3, 14, 17, 16, and

12).59 High yields have been demonstrated with unimproved giant reed populations, and 

therefore there is potential for increased biomass productivity through improved growing 

methods and breeding efforts.60 Napiergrass field trials have produced dry biomass 

yields exceeding 20 tons per acre per year in north-central Florida. Using currently 

available technology, average yields for full-season napiergrass should range from 14 to 

18 tons per acre with future improvements expected. Yield depends greatly on the type 

of cultivar and the amount and distribution of rainfall and fertilization rates. There is 

potential for increased biomass productivity through improved growing methods and 

breeding efforts.61 In general, the yields for all three of the energy grasses considered 

 

56 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.

57 See Hale, A.L. Sugar Bulletin, 2010, 88, 28-29

58 Huang, P., Bransby, D., and Sladden, S. (2010). Exceptionally high yields and soil carbon sequestration recorded 

for giant reed in Alabama. Poster session presented at: ASA, CSSA, and SSSA 2010 International Annual Meetings, 

Green Revolution 2.0; 2010 Oct 31–Nov 4; Long Beach, CA.

59 Mantineo, M., D’Agnosta, G.M., Copani, V., Patanè, C., and Cosentino, S.L. (2009). Biomass yield and energy 

balance of three perennial crops for energy use in the semi-arid Mediterranean environment. Field Crops Research 

114, 204-213.

60 Lewandowski et al. 2003

61 Based on discussions with industry and USDA and Woodard and Sollenberger (2008)
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here will have higher yields than switchgrass, so from a crop yield perspective, the 

switchgrass analysis would be a conservative estimate when comparing against the 

energy cane, napier grass, and giant reed pathways. 

Furthermore, EPA’s analysis of switchgrass for the RFS2 rulemaking assumed a 

2% annual increase in yield that would result in an average national yield of 6.6 dry tons 

per acre in 2022. EPA anticipates a similar yield improvement for energy cane, giant 

reed, and napiergrass due to their similarity as perennial grasses and their comparable 

status as energy crops in their early stages of development. Given this, our analysis 

assumes an average energy cane yield of 19 dry tons per acre in the southern United 

States by 2022; an average giant reed yield of approximately 18 dry tons per acre by 

2022; and an average napiergrass yield of approximately 20 dry tons per acre by 

202262. The ethanol yield for all of the grasses is approximately the same so the higher 

crop yields for energy cane, napiergrass, and giant reed result directly in greater ethanol 

production compared to switchgrass per acre of production. 

Based on these yield assumptions, in areas with suitable growing conditions, 

energy cane would require approximately 26% to 47% of the land area required by 

switchgrass to produce the same amount of biomass, giant reed would require less than 

40% of the land area required by switchgrass to produce the same amount of biomass, 

and napiergrass would require approximately 33% of the land area required by 

switchgrass to produce the same amount of biomass due to their higher yields. Even 

without yield growth assumptions, their currently higher crop yield rates means the land 

use required for these crops would be lower than for switchgrass. Therefore less crop 

 

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

timeframe. 
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area would be converted and displaced resulting in smaller land-use change GHG 

impacts than that assumed for switchgrass to produce the same amount of fuel. 

Furthermore, we believe energy cane and napiergrass will have a similar impact on 

international markets as assumed for switchgrass. Like switchgrass, energy cane and 

napiergrass are not expected to be traded internationally and their impacts on other 

crops are expected to be limited. Increased giant reed demand in the U.S. for biofuels 

is not expected to impact existing markets for giant reed, which are relatively small 

niche markets (e.g., musical instrument reeds). 

b. Land Use

In EPA’s RFS2 analysis, switchgrass plantings displaced primarily soybeans and 

wheat, and to a lesser extent hay, rice, sorghum, and cotton. Energy cane and 

napiergrass, with production focused in the southern United States, are likely to be 

grown on land once used for pasture, rice, commercial sod, cotton or alfalfa, which 

would likely have less of an international indirect impact than switchgrass because 

some of those commodities are not as widely traded as soybeans or wheat. Given that 

energy cane and napiergrass will likely displace the least productive land first, EPA 

concludes that the land use GHG impact for energy cane and napiergrass per gallon 

should be no greater and likely less than estimated for switchgrass. Given that giant 

reed is in early stages of development as an energy crop, there is limited information on 

where it will be grown and what crops it will displace. We expect giant reed will displace 

the least productive land first and would likely have a similar or smaller indirect impact 

associated with crop displacement than what we assumed for switchgrass. 

Considering the total land potentially impacted by all the new feedstocks included 
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in this rulemaking would not impact these conclusions (including the camelina 

discussed in the previous section and the three energy grasses considered here). As 

discussed previously, the camelina is expected to be grown on fallow land in the 

Northwest, while energy grasses are expected to be grown mainly in the south on 

existing cropland or pastureland. In the switchgrass ethanol scenario done for the 

Renewable Fuel Standard final rulemaking, total cropland acres increases by 4.2 million 

acres, including an increase of 12.5 million acres of switchgrass, a decrease of 4.3 

million acres of soybeans, a 1.4 million acre decrease of wheat acres, a decrease of 1 

million acres of hay, as well as decreases in a variety of other crops. Given the higher 

yields of the energy grasses considered here compared to switchgrass, there would be 

ample land available for production without having any adverse impacts beyond what 

was considered for switchgrass production. 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 giant reed, 

napiergrass, 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 
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use change impacts of switchgrass analyzed in the final RFS2 rule. In the final RFS2, 

EPA provided detailed information on the types of crops (e.g., wheat) that would be 

displaced by dedicated switchgrass. This analysis took into account the economic 

conditions such as input costs and commodity prices when evaluating the GHG and 

land use change impacts of switchgrass.63 

c. Crop Inputs and Feedstock Transport

EPA also assessed the GHG impacts associated with planting, harvesting, and 

transporting energy cane, giant reed, and napiergrass feedstocks in comparison to 

switchgrass. Table 6 shows the assumed 2022 commercial-scale production inputs for 

switchgrass (used in the RFS2 rulemaking analysis), average energy cane, giant reed, 

and napiergrass production inputs (USDA projections and industry data) and the 

associated GHG emissions. 

Available data gathered by EPA suggest that energy cane requires on average 

less nitrogen, phosphorous, potassium, and pesticide than switchgrass per dry ton of 

biomass, but more herbicide, lime, diesel, and electricity per unit of biomass. Giant 

reed may require on average less nitrogen and insecticide than switchgrass, but more 

phosphorous, potassium, herbicide, diesel, and electricity per unit of biomass. 

Napiergrass may require similar amounts of nitrogen fertilizer application as 

switchgrass, less phosphorous, potassium and insecticide than switchgrass, but more 

herbicide, lime, diesel and electricity per unit of biomass.

This assessment assumes production of all three new feedstocks uses electricity 

for irrigation given that growers will likely irrigate when possible to improve yields. 

 

63 See Final Regulatory Impact Analysis Chapter 2 , February 2010.
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Irrigation rates will vary depending on the timing and amount of rainfall, but for the 

purpose of estimating GHG impacts of electricity use for irrigation, we assumed a rate 

similar to what we assumed for other irrigated crops in the Southwest, South Central, 

and Southeast as shown in Table 6. 

Applying the GHG emission factors used in the RFS2 final rule, energy cane 

production results in slightly higher GHG emissions relative to switchgrass production 

(an increase of approximately 4 kg CO2eq/mmbtu). Giant reed production results in 

slightly lower GHG emissions relative to switchgrass production (a decrease of 

approximately 2 kg CO2eq/mmbtu). Napiergrass production results in slightly higher 

GHG emissions relative to switchgrass production (an increase of approximately 6 kg 

CO2eq/mmbtu).
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Table 6: Production Inputs and GHG Emissions for Switchgrass, Energy Cane, Giant Reed, and Napiergrass 

(Biochemical Ethanol), 2022

Switchgrass Energy Cane Giant Reed Napiergrass

Emission 

Factors

Inputs 

(per dry ton 

of biomass)

Emissions

(per mmBtu 

fuel)

Inputs

(per dry ton 

of biomass)

Emissions

(per mmBtu 

fuel)

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 5 lbs 1 kgCO2e 10 lbs 2.4 kgCO2e

N2O N/A N/A 7.6 kgCO2e N/A 5.9 kgCO2e N/A 4.8 kgCO2e N/A 7.6 kgCO2e

Phosphorus Fertilizer 1,12 

kgCO2e /

ton of 

phosphate

6.1 lbs 0.5 kgCO2e 3.2 lbs 0.3 kgCO2e 7.4 lbs 0.6 kgCO2e 1.1 lbs 0.1 kgCO2e

Potassium Fertilizer 743

kgCO2e /

ton of 

potassium

6.1 lbs 0.3 kgCO2e 4.2 lbs 0.2 kgCO2e 7.4 lbs 0.4 kgCO2e 4.0 lbs 0.2 kgCO2e

Herbicide 23,45 

kgCO2e /

tons of 

herbicide

0.002 lbs 0.003 kgCO2e 1.0 lbs 1.8 kgCO2e 0.02 lbs 0.03 kgCO2e 0.4 lbs 0.6 kgCO2e

Insecticide (average 

across regions)

27,22 

kgCO2e /

tons of 

pesticide

0.025 lbs 0.04 kgCO2e 0 lbs 0 kgCO2e 0 lbs 0 kgCO2e 0 lbs 0 kgCO2e
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Lime 408 

kgCO2e /

ton of lime

0 lbs 0 kgCO2e 104.7 lbs 3.1 kgCO2e 0 lbs 0 kgCO2e 100 lbs 2.9 kgCO2e

Diesel 97

kgCO2e /

mmBtu 

diesel

0.4 gal 0.8 kgCO2e 1.3 gal 2.4 kgCO2e 1.4 gal 2.5 kgCO2e 1.3 gal 2.2 kgCO2e

Electricity (irrigation) 220

kgCO2e /

mmBtu

0 kWh 0 kgCO2e 14.7 kWh 1.6 kgCO2e 10 kWh 1 kgCO2e 25 kWh 2.7 kgCO2e

Total Emissions

13

kgCO2e 

/

mmBtu

17

kgCO2e 

/

mmBtu

11

kgCO2e 

/

mmBtu

19

kgCO2e 

/

mmBtu

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

ethanol/dry ton, 2022 giant reed yield of 18 dry tons/acre and 92.3 gal ethanol/dry ton, and 2022 napiergrass yield of 20 dry tons/acre and 92.3 gal 

ethanol/dry ton. More detail on calculations and assumptions is included in materials to the docket. 
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GHG emissions associated with distributing energy cane, giant reed, and 

napiergrass feedstocks are expected to be similar to EPA’s estimates for switchgrass 

feedstock because they are all herbaceous agricultural crops requiring similar transport, 

loading, unloading, and storage regimes. Our analysis therefore assumes the same 

GHG impact for feedstock distribution as we assumed for switchgrass, although 

distributing energy cane, giant reed, and napiergrass feedstocks could be less GHG 

intensive because higher yields could translate to shorter overall hauling distances to 

storage or biofuel production facilities per gallon or Btu of final fuel produced. 

2. Fuel Production, Distribution, and Use

Energy cane, giant reed, and napiergrass are suitable for the same conversion 

processes as other cellulosic feedstocks, such as switchgrass and corn stover. 

Currently available information on energy cane, giant reed, and napiergrass 

composition shows that their hemicellulose, cellulose, and lignin content are 

comparable to other crops that qualify under the RFS regulations as feedstocks for the 

production of cellulosic biofuels. Based on this similar composition as well as 

conversion yield data provided by industry, we applied the same production processes 

that were modeled for switchgrass in the final RFS2 rule (biochemical ethanol, 

thermochemical ethanol, and Fischer-Tropsch (F-T) diesel64) to energy cane, giant reed, 

and napiergrass. We assumed the GHG emissions associated with producing biofuels 

from energy cane, giant reed, and napiergrass are similar to what we estimated for 

switchgrass and other cellulosic feedstocks. EPA also assumes that the distribution and 

use of biofuel made from energy cane, giant reed, and napiergrass will not differ 

 

64 The F-T diesel process modeled applies to cellulosic diesel, jet fuel, heating oil, and naphtha.
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significantly from similar biofuel produced from other cellulosic sources. As was done 

for the switchgrass case, this analysis assumes energy grasses grown in the United 

States for production purposes. If crops were grown internationally, used for biofuel 

production, and the fuel was shipped to the U.S., shipping the finished fuel to the U.S. 

could increase transport emissions. However, considering the increased transport 

emissions associated with sugarcane ethanol distribution to the U.S., this would at most 

add 1-2% to the overall lifecycle GHG impacts of the energy grasses. 

3. Summary

Based on our comparison of switchgrass and the three feedstocks considered 

here, EPA believes that cellulosic biofuel produced from the cellulose, hemicellulose 

and lignin portions of energy cane, giant reed, and napiergrass has similar or better 

lifecycle GHG impacts than biofuel produced from the cellulosic biomass from 

switchgrass. Our analysis suggests that the three feedstocks considered have GHG 

impacts associated with growing and harvesting the feedstock that are similar to 

switchgrass. Emissions from growing and harvesting energy cane are approximately 4 

kg CO2eq/mmBtu higher than switchgrass, emissions from growing and harvesting 

giant reed are approximately 2 kg CO2eq/mmBtu lower than switchgrass, and 

emissions from growing and harvesting napiergrass are approximately 6 kg 

CO2eq/mmBtu higher than switchgrass. These are small changes in the overall 

lifecycle, representing at most a 6% change in the energy grass lifecycle impacts in 

comparison to the petroleum fuel baseline. Furthermore, the three feedstocks 

considered are expected to have similar or lower GHG emissions than switchgrass 

associated with other components of the biofuel lifecycle. 
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Under a hypothetical worst case, if the calculated increases in growing and 

harvesting the new feedstocks are incorporated into the lifecycle GHG emissions 

calculated for switchgrass, and other lifecycle components are projected as having 

similar GHG impacts to switchgrass (including land use change associated with 

switchgrass production), the overall lifecycle GHG reductions for biofuel produced from 

energy cane, giant reed, and napiergrass still meet the 60% reduction threshold for 

cellulosic biofuel, the lowest being a 64% reduction (for napiergrass diesel produced 

through gasification and upgrading) compared to the petroleum baseline. We believe 

these are conservative estimates, as use of energy cane, giant reed, or napiergrass as 

a feedstock is expected to have smaller land-use GHG impacts than switchgrass, due to 

their higher yields. The docket for this rule provides additional detail on the analysis of 

energy cane, giant reed, and napiergrass as biofuel feedstocks.

Although this analysis assumes energy cane, giant reed, and napiergrass

biofuels produced for sale and use in the United States will most likely come from 

domestically produced feedstock, we also intend for the approved pathways to cover 

energy cane, giant reed, and napiergrass from other countries. We do not expect 

incidental amounts of biofuels from feedstocks produced in other nations to impact our 

average GHG emissions. Moreover, those countries most likely to be exporting energy 

cane, giant reed, or napiergrass or biofuels produced from these feedstocks are likely to 

be major producers which typically use similar cultivars and farming techniques. 

Therefore, GHG emissions from producing biofuels with energy cane, giant reed, or 

napiergrass grown in other countries should be similar to the GHG emissions we 

estimated for U.S. energy cane, giant reed, or napiergrass, though they could be slightly 
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(and insignificantly) higher or lower. For example, the renewable biomass provisions 

under the Energy Independence and Security Act would prohibit direct conversion of 

previously unfarmed land in other countries into cropland for energy grass-based 

renewable fuel production. Furthermore, any energy grass production on existing 

cropland internationally would not be expected to have land use impacts beyond what 

was considered for switchgrass production. Even if there were unexpected larger 

differences, EPA believes the small amounts of feedstock or fuel potentially coming 

from other countries will not impact our threshold analysis. 

Based on our assessment of switchgrass in the RFS2 final rule and this 

comparison of GHG emissions from switchgrass and energy cane, giant reed, and 

napiergrass, we do not expect variations to be large enough to bring the overall GHG 

impact of fuel made from energy cane, giant reed or napier grass to come close to the 

60% threshold for cellulosic biofuel. Therefore, EPA is including cellulosic biofuel 

produced from the cellulose, hemicelluloses and lignin portions of energy cane, giant 

reed, and napiergrass under the same pathways for which cellulosic biomass from 

switchgrass qualifies under the RFS2 final rule. 

D. 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 
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by the industry as the most likely feedstocks for use in making renewable gasoline or 

renewable gasoline blendstock in the near term due to their availability and low cost. 

Additionally, these feedstocks have already been analyzed by EPA as part of the RFS2 

rulemaking for the production of other fuel types. Consequently, no new modeling is 

required and we rely on earlier assessments of feedstock production and distribution for 

assessing the likely lifecycle impact on renewable gasoline and renewable gasoline 

blendstock. We have also relied on the petroleum gasoline baseline assessment from 

the RFS2 rule for estimating the fuel distribution and use GHG emissions impacts for 

renewable gasoline and renewable gasoline blendstock. Consequently, the only new 

analysis required is of the technologies for turning the feedstock into renewable 

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, annual cover crops;

 Cellulosic components of separated yard waste;

 Cellulosic components of separated food waste; and

 Cellulosic components of separated MSW

The FASOM and FAPRI models were used to analyze the GHG impacts of the 

feedstock production portion of a fuel’s lifecycle. In the RFS2 rulemaking, FASOM and 

FAPRI modeling was performed to analyze the emissions impact of using corn stover as 
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a biofuel feedstock and this modeling was extended to some additional feedstock 

sources considered similar to corn stover. This approach was used for crop residues, 

slash, pre-commercial thinnings, tree residue and cellulosic components of separated 

yard, food, and MSW. These feedstocks are all excess materials and thus, like corn 

stover, were determined to have little or no land use change GHG impacts. Their GHG 

emission impacts are mainly associated with collection, transport, and processing into 

biofuel. See the RFS2 rulemaking preamble for further discussion. We used the results 

of the corn stover modeling in this analysis to estimate the upper bound of agricultural 

sector impacts from the production of the various cellulosic feedstocks noted above. 

The agriculture sector modeling results for corn stover 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 RFS2 rulemaking, 

this was roughly 62 million dry tons of corn stover to produce 5.7 billion gallons of 

ethanol assuming biochemical fermentation to ethanol processing. We have calculated 

GHG emissions from feedstock production for that amount of corn stover. The GHG 

emissions were then divided by the total heating value of the fuel to get feedstock 

production emissions per mmBtu of fuel. In addition to the biochemical ethanol process, 

a similar analysis was completed for thermochemical ethanol and F-T diesel pathways 

as part of the RFS2 rulemaking. 

In this rulemaking we are analyzing renewable gasoline and renewable gasoline 

blendstock produced from corn stover (and, by extension, other waste feedstocks). The 

number of gallons of fuel produced from a ton of corn stover (modeled process yields) is 

specific to the process used to produce renewable fuel. EPA has adjusted the results of 
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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 

RFS2 final rule, included as producing naptha via the F-T process. Our analysis of the 

catalytic pyrolysis process was based on the modeling work completed by the National 

Renewable Energy Laboratory (NREL) for this rule for a process to make renewable 

gasoline blendstock.65 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 

 

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

Renewable Energy Laboratory (NREL). 2011.
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analyzed as part of the RFS2 rulemaking. The fuel production section below provides 

further discussion on extending the GHG emissions results of the biochemical ethanol 

fermentation process to a biochemical renewable gasoline or renewable gasoline 

blendstock fermentation process. In some cases, the available data sources included 

process yields for renewable gasoline or renewable gasoline blendstock produced from 

wood chips rather than corn stover which was specifically modeled as a feedstock in the 

RFS2 final rule. We believe that the process yields are not significantly impacted by the 

source of cellulosic material whether the cellulosic material comes from residue such as 

corn stover or wood material such as from tree residues. We made the simplifying 

assumption that one dry ton of wood feedstock produces the same volume of renewable 

gasoline or renewable gasoline blendstock as one dry ton of corn stover. We believe 

this is reasonable considering that the RFS2 rulemaking analyses for biochemical 

ethanol and thermochemical F-T diesel processes showed limited variation in process 

yields between different feedstocks for a given process technology.66 In addition, since 

the renewable gasoline and renewable gasoline blendstock pathways include 

feedstocks that were already considered as part of the RFS2 final rule, the existing 

feedstock lifecycle GHG impacts for distribution of corn stover were also applied to this 

analysis.67 

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 

 

66 Aden, Andy. Feedstock Considerations and Impacts on Biorefining. National Renewable Energy Laboratory 

(NREL). December 2009.

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

see conclusion section. 
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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. 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 
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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 RFS2 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 RFS2 

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 RFS2 rulemaking, EPA conducted an in-depth literature review of corn 

stover removal practices and consulted with numerous experts in the field. In the FRM, 

EPA recognized that sustainable stover removal practices vary significantly based on 

local differences in soil and erosion conditions, soil type, landscape (slope), tillage 
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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
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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 RFS2 final rule 

which included estimates for fuel distribution emissions. Since renewable gasoline and 

renewable gasoline blendstocks when blended into gasoline are similar to petroleum 

gasoline, it is reasonable to assume similar fuel distribution emissions. Therefore, the 

existing fuel distribution lifecycle GHG impacts of the petroleum gasoline baseline from 

the RFS2 final rule were applied to this analysis. 

3. Use of the fuel

A petroleum gasoline baseline was developed as part of the RFS2 final rule 

which estimated the tailpipe emissions from fuel combustion. Since renewable gasoline 

and renewable gasoline blendstock are similar to petroleum gasoline, the non-CO2

combustion emissions calculated as part of the RFS2 final rule for petroleum gasoline 

were applied to our analysis of the renewable gasoline and renewable gasoline 

blendstock pathways. Only non-CO2 emissions were included since carbon fluxes from 

land use change are accounted for as part of the biomass feedstock production. 

4. Fuel production

In the RFS2 rulemaking, EPA analyzed several of the main cellulosic biofuel 
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pathways: a biochemical fermentation process to ethanol and two thermochemical 

gasification processes, one producing mixed alcohols (primarily ethanol) and the other 

one producing mixed hydrocarbons (primarily diesel fuel). These pathways all 

exceeded the 60% lifecycle GHG threshold requirements for cellulosic biofuel using the 

specified feedstocks. Refer to the preamble and regulatory impact analysis (RIA) from 

the final RFS2 rule for more details. From these analyses, it was determined that 

ethanol and diesel fuel produced from the specified cellulosic feedstocks and processes 

would be eligible for cellulosic and advanced biofuel RINs.

The thermochemical gasification process to diesel fuel (via F-T synthesis) also 

produces a smaller portion of renewable gasoline blendstock. In the final RFS2 rule, 

naphtha produced with specified cellulosic feedstocks by a F-T process was included as 

exceeding the 60% lifecycle GHG threshold, with an applicable D-Code of 3, in Table 1 

to §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 RFS2 rule was released, EPA has received several petitions and 

inquiries that suggest that renewable gasoline or renewable gasoline blendstock 

produced using processes other than the F-T process could also qualify for a similar DCode of 3.68,

 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. 

 

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

received by EPA. 
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Several routes have been identified as available for the production of renewable 

gasoline and renewable gasoline blendstock from renewable biomass. These include 

catalytic pyrolysis and upgrading to renewable gasoline or renewable gasoline 

blendstock (“catalytic pyrolysis and upgrading”), biochemical fermentation with 

upgrading to renewable gasoline or renewable gasoline blendstock via carboxylic acid 

(“fermentation and upgrading”), and direct biochemical fermentation to renewable 

gasoline and renewable gasoline blendstock (“direct fermentation”).69,70 

Similar to how we analyzed several of the main routes for cellulosic ethanol and 

cellulosic diesel for the final RFS2 rule, we have chosen to analyze the main renewable 

gasoline and renewable gasoline blendstock pathways in order to estimate the potential 

GHG reduction profile for renewable gasoline and renewable gasoline blendstock 

across a 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 

 

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

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

70 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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reported by NREL. Details on the NREL modeling are described further in a technical 

report available through the docket.71 Catalytic pyrolysis involves the rapid heating of 

biomass to about 500°C at slightly above atmospheric pressure. The rapid heating 

thermally decomposes biomass, converting it into pyrolysis vapor, which is condensed 

into a liquid bio-oil. The liquid bio-oil can then be upgraded using conventional 

hydroprocessing technology and further separated into renewable gasoline, renewable 

gasoline blendstock and renewable diesel streams (cellulosic diesel from catalytic 

pyrolysis is already included as an acceptable pathway in the RFS2 program). Some 

industry sources also expect to produce smaller fractions of heating oil in addition to 

gasoline and diesel blendstocks. Excess electricity from the process is also accounted 

for in our modeling as a co-product credit in which any excess displaces U.S. average 

grid electricity. Excess electricity is generated from the use of co-product coke/char and 

product gases and is available because internal electricity demands are fully met. The 

estimated energy inputs and electricity credits shown in Table 8, below, utilize the data 

provided by the NREL process modeling. However, Industry sources also identified 

potential areas for improvements in energy use, such as the use of biomass fired dryers 

instead of natural gas fired dryers for drying incoming wet feedstocks and increased 

turbine efficiencies for electricity production which may result in lower energy 

consumption than estimated by NREL and thus improve GHG performance compared 

to our estimates here. 

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

 

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

Renewable Energy Laboratory (NREL). 2011.
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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

The emissions from energy inputs were calculated by multiplying the amount of 

energy by emission factors for fuel production and combustion, based on the same 

method and factors used in the RFS2 final rulemaking. The emission factors for the 

different fuel types are from GREET and were based on assumed carbon contents of 

the different process fuels. The emissions from producing electricity in the U.S. were 

also taken from GREET and represent average U.S. grid electricity production 

emissions.

The major factors influencing the emissions from the fuel production stage of the 

catalytic pyrolysis pathway are the use of natural gas (mainly due to hydrogen 

production for hydroprocessing) and the co-products available for additional heat and 

power generation.72 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

 

72 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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Lifecycle Stage Catalytic Pyrolysis 

to Renewable 

Gasoline or 

Renewable Gasoline 

Blendstock (g CO2-

eq./mmBtu)

On-Site & Upstream Emissions 

(Natural Gas & Biomass*) 

31,000

Electricity Co-Product Credit -3,000

Total Fuel Production Emissions: 28,000

*Only non-CO2 combustion emissions from biomass

b. Fermentation and Upgrading to Renewable Gasoline and Renewable Gasoline 

Blendstock

The second production process we investigated is a biochemical fermentation 

process to intermediate carboxylic acids with catalytic upgrading to renewable gasoline 

or renewable gasoline blendstock. This process involves the fermentation of biomass 

using a mixed-culture of microorganisms that produce a variety of carboxylic acids. If 

the feedstock has high lignin content, then the biomass is pretreated to enhance 

digestibility. The acids are then neutralized to carboxylate salts and further converted to 

ketones and alcohols for refining into gasoline, diesel, and jet fuel. 

The process requires the use of natural gas and hydrogen inputs.73 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 

 

73 Hydrogen emissions are modeled as natural gas and electricity demands.
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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. 

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-
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eq./mmBtu)

On-Site & Upstream Emissions (Natural 

Gas & Biomass*)

33,000

Electricity Co-Product Credit -3,000

Total Fuel Production Emissions: 30,000

*Only non-CO2 combustion emissions from biomass

c. Direct Fermentation to Renewable Gasoline and Renewable Gasoline Blendstock 

The third production process we investigated involves the use of microorganisms 

to ferment sugars hydrolyzed from cellulose directly into hydrocarbons which could be 

either a complete fuel as renewable gasoline or a renewable gasoline blendstock. The 

process is similar to the biochemical fermentation to ethanol pathway modeled for the 

final RFS2 rule with the major difference being the end fuel product, hydrocarbons 

instead of ethanol. Researchers believe that this new technology could achieve 

improvements over classical fermentation approaches because hydrocarbons separate 

spontaneously from the aqueous phase, thereby avoiding poisoning of microbes by the 

accumulated products and facilitating separation/collection of alkanes from the reaction 

medium.74 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 

 

74 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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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 RFS2 rule biochemical 

fermentation to ethanol process results to a similar (but likely slightly improved) process 

that instead produces hydrocarbons. Since the final RFS2 rule cellulosic ethanol GHG 

results were well above the 60% GHG reduction threshold for cellulosic biofuels, if 

actual emissions from other necessary changes to the direct biochemical fermentation 

to hydrocarbons process represent some small increment in GHG emissions, the 

pathway would still likely meet the threshold. Table 12 is our qualitative assessment of 

the potential emissions reductions from a process using biochemical fermentation to 

cellulosic hydrocarbons assuming similarities to the biochemical fermentation to 

cellulosic ethanol route from the final RFS2 rule. 

Table 12: Fuel Production Emissions for RFS2 Cellulosic Biochemical Ethanol 

Compared to Direct Biochemical Fermentation to Renewable Gasoline or 

Renewable Gasoline Blendstock Using Corn Stover 

Lifecycle Stage RFS2 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
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Electricity Co-Product Credit -35,000 = -35,000

Total Fuel Production Emissions75: -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.76 

As noted above, these analyses assume natural gas as the process energy when 

needed; using biogas or biomass as process energy would result in an even better 

lifecycle GHG impact.

 

75 Numbers do not add up due to rounding.

76 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 -67% -65% -129%
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Baseline

*Emissions included in fuel production stage.

d. Extension of Modeling Results to Other Production Processes Producing Renewable 

Gasoline or Renewable Gasoline Blendstock 

In the RFS2 rulemaking, we modeled the GHG emissions results from the 

biochemical fermentation process to ethanol, thermochemical gasification processes to 

mixed alcohols (primarily ethanol) and mixed hydrocarbons (primarily diesel fuel). We

extended these modeled process results to apply when the biofuel was produced from 

“any” process. We determined that since we modeled multiple cellulosic biofuel 

processes and all were shown to exceed the 60% lifecycle GHG threshold requirements 

for cellulosic biofuel using the specified feedstocks its was reasonable to extend to other 

processes that might develop as these would likely represent improvements over 

existing processes as the industry works to improve the economics of cellulosic biofuel 

production by, for example, reducing energy consumption and improving process yields. 

Similarly, this rule assesses multiple processes for the production of renewable gasoline 

and renewable gasoline blendstocks and all were shown to exceed the 60% lifecycle 

GHG threshold requirements for cellulosic biofuel using specified feedstocks. 

As was the case in our earlier rulemaking, a couple reasons in particular support 

extending our modeling results to other production process producing renewable 

gasoline or renewable gasoline blendstock from cellulosic feedstock. Under this rule we 

analyzed the core technologies most likely available through 2022 for production of 

renewable gasoline and renewable gasoline blendstock routes from cellulosic feedstock 
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as shown in literature. 77,78 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:

 Direct fermentation – requires the release of sugars from biomass and the use of 

“synthetic biology” in which microorganisms are altered to ferment sugars straight 

into hydrocarbons instead of alcohols

 Fermentation w/ catalytic upgrading – requires the release of sugars from 

biomass and aqueous- or liquid-phase processing of sugars or intermediate 

fermentation products into hydrocarbons using solid catalysts, 

As part of the modeling effort here, as well as for the RFS2 final rule, we have 

considered the lifecycle GHG impacts of the four possible production technologies 

mentioned above. The pyrolysis and upgrading, direct fermentation, and fermentation 

 

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

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

78 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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with catalytic upgrading are considered in this rule and the gasification route was 

already included in the RFS2 final rule. In all cases, the processes that we have 

considered meet the 60% lifecycle GHG reduction required for cellulosic biofuels. 

Furthermore, we believe that the results from our modeling would cover all the likely 

variations within these potential routes for producing renewable gasoline and renewable 

gasoline blendstock which also use natural gas, biogas or biomass for process energy 

and that all such production variations would also meet the 60% lifecycle threshold.79 

The main reason for this is that we believe that our energy input assumptions are 

reasonable at this time but probably in some cases conservative for commercial scale 

cellulosic facilities. The cellulosic industry is in its early stages of development and 

many of the estimates of process technology GHG impacts is based on pre-commercial 

scale assessments and demonstration programs. Commercial scale cellulosic facilities 

will continue to make efficiency improvements over time to maximize their fuel 

products/co-products and minimize wastes. For cellulosic facilities, such improvements 

include increasing conversion yields and fully utilizing the biomass input for valuable 

products. 

An example of increasing the amount of biomass utilized is the combustion of

undigested or unconverted biomass for heat and power. The three routes that we 

analyzed for the production of renewable gasoline and renewable gasoline blendstock 

in today’s rule assume an electricity production credit from the economically-driven use 

of lignin or waste byproducts; we also ran a sensitivity case where no electricity credit 

 

79

 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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was given. We found that all of the routes analyzed would still pass the GHG threshold 

without an electricity credit, providing confidence that over the range of technology 

options, these process technologies will surely allow the cellulosic biofuel produced to 

exceed the threshold for cellulosic biouel GHG performance. Without excess electricity 

production the catalytic pyrolysis pathway results in a 65% lifecycle GHG reduction, the 

biochemical fermentation via carboxylic acid pathway results in a 62% lifecycle GHG 

reduction, and the direct biochemical fermentation pathway results in a 93% reduction in 

lifecycle GHG emissions compared to the petroleum fuel baseline. 

Additionally, while the final results reported in this rule include an electricity 

credit, this electricity credit is based on current technology for generating electricity; it is 

possible that over the next decade as cellulosic biofuel production matures, the 

efficiency with which electricity is generated at these facilities will also improve. Such 

efficiency improvements will tend to improve the GHG performance for cellulosic biofuel 

technologies in general including those used to produce renewable gasoline. 

Furthermore, industry has identified other areas for energy improvements which 

our current pathway analyses do not include. Therefore, the results we have come up 

with for the individual pathway types represent conservative estimates and any 

variations in the pathways considered are likely to result in greater GHG reductions that 

what is considered here. For example, the variation of the catalytic pyrolysis route 

considered here resulted in a 67% reduction in lifecycle GHG emissions compared to 

the petroleum baseline. However, as was mentioned this was based on data from our 

NREL modeling and industry CBI data indicated more efficient energy performance 

which, if realized, would improve GHG performance. Another area for improvement in 
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this pathway could be the use of anaerobic digestion to treat organics in waste water. If 

the anaerobic digestion is on-site, then enough biogas could potentially be produced to 

replace all of the fossil natural gas used as fuel and about half the natural gas fed for

hydrogen production.80 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 selfsufficiency. 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 RFS2 final rule 

resulted in an approximately 91% reduction in lifecycle GHG emissions compared to the 

petroleum baseline. This could be considered a conservative estimate as the process 

did not assume any excess electricity production, which as mentioned above could lead 

to additional GHG reductions. The F-T process involves gasifying biomass into syngas 

(mix of H2 and CO) and then converting the syngas through a catalytic process into a 

hydrocarbon mix that is further refined into finished product. The F-T process 

considered was based on producing both gasoline and diesel fuel so that it was not 

optimized for renewable gasoline production. A process for producing primarily 

renewable gasoline rather than diesel from a gasification route should not result in a 

 

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

Renewable Energy Laboratory (NREL). 2011.
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significantly worse GHG impacts compared to the mixed fuel process analyzed. 

Furthermore, as the lifecycle GHG reduction from the F-T process considered was 

around 91%, there is considerable room for variations in this route to still meet the 60% 

lifecycle GHG reduction threshold for cellulosic fuels. Therefore, in addition to the F-T 

process originally analyzed for producing naphtha, we can extend the results based on 

the above analyses to include all variations of the gasification route which use natural 

gas, biogas or biomass for production energy for producing renewable gasoline or 

renewable gasoline blendstock. These variations include for example different catalysts 

and different refining processes to produce different mixes of final fuel product. While 

the current Table 1 entry in the regulations does not specify process energy sources, 

we are adding these specific eligible energy sources since we have not analyzed other 

energy sources (e.g. coal) as also allowing the pathway to meet the GHG performance 

threshold. 

There is an even wider gap between the results modeled for the direct 

fermentation route and the cellulosic lifecycle GHG threshold. The variation we 

considered for the direct fermentation process resulted in an approximately 129% 

reduction in lifecycle GHG emissions compared to the petroleum baseline. This 

process did consider production of electricity as part of the process but as mentioned 

even if this was not the case the pathway would still easily fall below the 60% lifecycle 

threshold for cellulosic biofuels. If actual emissions from other necessary changes to 

the direct biochemical fermentation to hydrocarbons process represent some small 

increment in GHG emissions, the pathway would still likely meet the threshold. 

Therefore, we can extend the results to all variations of the direct biochemical route for 
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renewable gasoline or renewable gasoline blendstock production which use natural gas, 

biogas or biomass for production energy. 

The biochemical with catalytic upgrading route that we evaluated resulted in a 

65% reduction in GHG emissions compared to the petroleum baseline. However, this 

can be considered a conservative estimate. For instance, the biochemical fermentation 

to gasoline via carboxylic acid route considered did not include the potential for 

generating steam from the combustion of undigested biomass and then using this 

steam for process energy. If this had been included, natural gas consumption could 

potentially be decreased which would lower the potential GHG emissions estimated 

from the process. Therefore, the scenario analyzed could be considered conservative 

in estimating actual natural gas usage. As was the case with the pyrolysis route 

considered, we believe that as commercial scale cellulosic facilities develop, 

improvements will be made to maximize the use of all the biomass and waste 

byproducts available to bring the facility closer to energy self-sufficiency. These 

improvements help to increase the economic profitability for cellulosic facilities where 

fossil energy inputs become costly to purchase. The processes we analyzed for this 

rulemaking utilized a mix of natural gas and biomass for process energy, with biogas 

replacing natural gas providing improved GHG performance. We have not analyzed 

other fuel types (e.g., coal) and are therefore not approving processes that utilized other 

fuel sources at this point. Therefore, we are extending our results 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 
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scenarios we have already analyzed, our results give a good indication of the range of 

emissions we could expect from processes producing renewable gasoline and 

renewable gasoline blendstock from cellulosic feedstock, all of which meet the 60% 

cellulosic biofuel threshold (assuming they are utilizing natural gas, biogas or biomass 

for process energy). Technology changes in the future are likely to increase efficiency to 

maximize profits, while also lowering lifecycle GHG emissions. Therefore, we have 

concluded that since all of the renewable gasoline or renewable gasoline blendstock 

fuel processing methods we have analyzed exceed the 60% threshold using specific 

cellulosic feedstock types, we can conclude that processes producing renewable 

gasoline or renewable gasoline blendstock that fit within the categories of process 

analyzed here and are produced from the same feedstock types and using natural gas, 

biogas or biomass for process energy use will also meet the 60% GHG reduction 

threshold. In addition, while other technologies may develop, we expect that they will 

only become commercially competitive if they have better yield (more gallons per ton of 

feedstock) or lower production cost due to lower energy consumption. Both of these 

factors would suggest better GHG performance. This would certainly be the case if 

such processes also relied upon using biogas and/or biomass as the primary energy 

source. Therefore based on our review of the existing primary cellulosic biofuel 

production processes, likely GHG emission improvements for existing or new 

technologies, and consideration of the positive GHG emissions benefits associated with 

using biogas and/or biomass for process energy, we are approving for cellulosic RIN 

generation any process for renewable gasoline and renewable gasoline blendstock 

production using specified cellulosic biomass feedstocks as long as the process utilizes 
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biogas and/or biomass for all process energy. 

5. Summary

Three renewable gasoline and renewable gasoline blendstock pathways were 

compared to baseline petroleum gasoline, using the same value for baseline gasoline 

as in the RFS2 final rule analysis. The results of the analysis indicate that the 

renewable gasoline and renewable gasoline blendstock pathways result in a GHG 

emissions reduction of 65-129% or better compared to the gasoline fuel it would replace 

using corn stover as a feedstock. The renewable gasoline and renewable gasoline 

blendstock pathways which use corn stover as a feedstock all exceed the 60% lifecycle 

GHG threshold requirements for cellulosic biofuel, these pathways capture the likely 

current technologies, and future technology improvements are likely to increase 

efficiency and lower GHG emissions. Therefore we have determined that all processes 

producing renewable gasoline or renewable gasoline blendstock from corn stover can 

qualify if they fall in the following process characterizations:

 Catalytic pyrolysis and upgrading utilizing natural gas, biogas, and/or biomass as 

the only process energy sources

 Gasification and upgrading utilizing natural gas, biogas, and/or biomass as the 

only process energy sources

 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.
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As was the case for extending corn stover results to other feedstocks in the 

RFS2 final rule, these results are also reasonably extended to feedstocks with similar or 

lower GHG emissions profiles, including the following feedstocks:

 Cellulosic biomass from crop residue, slash, pre-commercial thinnings and tree 

residue, annual cover crops;

 Cellulosic components of separated yard waste;

 Cellulosic components of separated food waste; and 

 Cellulosic components of separated MSW

For more information on the reasoning for extension to these other feedstocks 

refer to the feedstock production and distribution section or the RFS2 rulemaking (75 

FR 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, 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 
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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 nonbaseline gasoline, a manufacturer under $50 million in annual revenue is exempt from 

Tier 1 and Tier 2. For an atypical gasoline there is no exemption from Tier 1, but a 

manufacturer under $10 million in annual revenue is exempt from Tier 2. 

Registration for a motor vehicle gasoline at 40 CFR 79 is via EPA Form 3520-12, 

Fuel Manufacturer Notification for Motor Vehicle Fuel, available at: 

http://www.epa.gov/otaq/regs/fuels/ffarsfrms.htm.

E. Esterification Production Process Inclusion for Specified Feedstocks 

Producing Biodiesel

Table 14, shown below, includes pathways for biodiesel using specified 

feedstocks and the production process transesterification. Transesterification is the 

most commonly used method to produce biodiesel (i.e. methyl esters) by reacting 

triglycerides with methanol typically under the presence of a base catalyst, see the 

simplified form in Equation 1.81 

 

81 Commonly used base catalysts include sodium hydroxide (NaOH), potassium hydroxide (KOH) and sodium 

methoxide (NaOCH3)
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Table 14: Excerpts of Existing Fuel Pathways from 40 CFR 80.1426

Fuel Type Feedstock Production Process 

Requirements

D-Code

Biodiesel, and 

renewable diesel 

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

Excluding processes 

that co-process 

renewable biomass 

and petroleum

4

(BiomassBased Diesel)

Biodiesel, and 

renewable diesel 

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 coprocess renewable 

biomass and 

petroleum

5

(Advanced 

Biofuel)

Equation 1: Transesterification
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 () + h (h)

()

⎯⎯⎯⎯⎯⎯ h  () + 

While triglycerides are usually the main component of oils, fats, and grease 

feedstocks, there are other components such as free fatty acids (FFAs) that are typically 

removed prior to transesterification. Removal or conversion of FFAs is important if the 

traditional base-catalyzed transesterification production process is used since FFAs will 

react with base catalysts to produce soaps that inhibit the transesterification reaction. 

Table 15 below gives the usual ranges for FFAs found in biodiesel feedstocks.

Table 15: Ranges of FFA in Biodiesel Feedstocks82,83

Biodiesel Feedstock Percentage FFA 

(%)

Refined vegetable 

oils

<0.05

Crude vegetable oils 0.3-0.7

Restaurant waste 

grease

2-7

Yellow grease <15

Animal fat 5-30

Brown grease >15

 

82 Van Gerpen, J., Shanks, B., Pruszko, R., Clements, D., Knothe, G., “Biodiesel Production Technology,” NREL/SR510-36244, July 2004.

83 Van Gerpen, J., “Used and Waste Oil and Grease for Biodiesel,” NC State University A&T State University 

Cooperative Extension, http://www.extension.org/pages/Used_and_Waste_Oil_and_Grease_for_Biodiesel
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Trap grease 40-100

One of the most widely used methods for treating biodiesel feedstocks with 

higher FFA content is acid catalysis. Acid catalysis typically uses a strong acid such as 

sulfuric acid to catalyze the esterification of the FFAs and the transesterification of the 

triglycerides. The simplified form of the esterification process is given below in Equation 

2. Acid esterification can be applied to feedstocks with FFA contents above 5%. 

Because the transesterification of triglycerides is slow under acid catalysis, a technique 

commonly used to overcome the reaction rate issue is to first convert the FFAs through 

an acid esterification (also known as an acid “pretreatment” step), and then follow-up 

with the traditional base-catalyzed transesterification of triglycerides. See Figure 2 for a 

general flow diagram of the acid esterification and subsequent transesterification 

biodiesel process.

Equation 2: Esterification

   () + h (h)

()

⎯⎯⎯⎯⎯⎯ h  () + 

Figure 2: Process Description for Acid Esterification and Transesterification
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Source: http://www1.eere.energy.gov/biomass/abcs_biofuels.html#biodprod

Under the RFS2 final rule, biodiesel from biogenic waste oils/fats/greases 

qualifies for D-Codes 4 and 5 using a “transesterification” process. This conclusion was 

based on the analysis of yellow grease as a feedstock in a process where there was an 

acid “pretreatment” or “esterification” process to treat the FFAs contained in the 

feedstock. In fact, one of the material inputs assumed in the modeling for the final 

RFS2 rule yellow grease pathway is sulfuric acid, which is the catalyst commonly used 

for acid esterification. However, we had not stipulated “esterification” as a qualified 

production process in Table 1 to 40 CFR 80.1426. We believe this ambiguity could 

unnecessarily cause confusion as to whether esterification can also be used for the 

production of biodiesel under the currently approved pathways. 

Since the biodiesel modeling completed for the final RFS2 rule actually includes 

esterification upstream of the transesterification process, we find it appropriate to clarify 

Table 1 to 40 CFR 80.1426 to include “esterification” as a qualified process in which to 

produce biodiesel. As the modeling for yellow grease met an 86% GHG reduction 

emissions level, and yellow grease is typically <15% FFA content, it is reasonable to 
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conclude that esterification and subsequent transesterification with a yellow grease 

feedstock containing FFAs at the very least up to 15% can meet the GHG reduction 

threshold for biomass-based diesel and advanced biofuel of 50%.

As noted in Table 15, however, there are feedstocks that may contain even 

higher levels of FFAs. As described below, EPA has evaluated the use of these higher 

FFA feedstocks to make biodiesel and has determined that use of such feedstocks also 

results in a biodiesel with lifecycle GHG emissions at least 50% less than that of 

conventional fuel. 

The National Biodiesel Board (NBB) has conducted a comprehensive survey of 

the actual energy used by commercial biodiesel production plants in the U.S.84 The 

survey depicts the amount of energy and incidental process materials such as acids 

used to produce a gallon of biodiesel. The survey data returned represents 37% of the 

surveyed 230 NBB biodiesel members in 2008 and includes producers using a variety 

of virgin oils and recycled or reclaimed fats and oils. While there is no specific data on 

the FFA content of the feedstocks used, the feedstocks did include reclaimed greases 

which represent the feedstocks which typically have the highest FFA content. As the 

data is partially aggregated, we used the maximum surveyed electricity and natural gas 

used at the facilities and a high estimate of “materials used” based on a sum of industry 

averages for all process materials for calculating potential GHG emissions. Even 

though some of the facilities might be processing feedstocks with relatively low FFA 

content, we believe that using these maximum observed inputs for energy used plus a 

high estimate for process materials used will estimate the highest GHG emissions 

 

84 National Biodiesel Board, Comprehensive Survey on Energy Use for Biodiesel Production (2008)

http://www.biodiesel.org/news/RFS/rfs2docs/NBB%20Energy%20Use%20Survey%20FINAL.pdf
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profile for biodiesel production GHG emissions. When combined with the feedstock 

GHG emissions impact (see discussion below), the results still predict a GHG emissions 

reduction comfortably exceeding 50% as compared to the petroleum fuel it displaces. 

Therefore, there is little risk in predicting that any facility that utilizes esterification and 

feedstock over the range of likely FFA content can meet the 50% biomass-based diesel 

and advanced biofuel threshold.

According to the survey, the maximum electricity use for a producer reached as 

high as 3,071 Btu per gallon biodiesel. This is about 5 times higher than the industry 

average. The maximum natural gas usage for a producer reached as high as 12,324 

Btu per gallon biodiesel, which is about 3.5 times higher than the industry average. For 

“materials used” only an industry average for each material was provided in the survey. 

Therefore, as a conservative estimate, we totaled all the average material inputs to 

equal 0.51 kg/gal biodiesel.85 We believe that this is conservative because not all 

facilities are likely to use each and every one of the process materials listed in the 

survey (e.g., we totaled all the acids used even though a facility is not likely to use each 

different acid). Thus, our estimate of materials used will estimate a level of maximum 

usage of materials at a given facility. In addition, we did not include a glycerin coproduct credit when calculating emissions since the esterification reaction does not 

produce glycerin (see Equation 2). Using the same methodology as was used for the 

yellow grease modeling under RFS2, but using the high energy and materials use 

assumptions per the above discussion and omitting the glycerin co-product credit, we 

estimate the emissions from biodiesel processing at 23,708 gCO2eq per mmBtu of 

 

85 The material inputs include methanol, sodium methylate, sodium hydroxide, potassium hydroxide, hydrochloric 

acid, sulfuric acid, phosphoric acid, and citric acid. The majority of material input is from methanol.
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biodiesel. The estimated GHG emissions reduction for the entire process is -71%. 

Since the GHG threshold is at -50% for biomass-based diesel and advanced biofuel, we 

believe that there is a large enough margin in the results to reasonably conclude that 

biodiesel using esterification of specified feedstocks with any level of FFA content 

meets the biomass-based diesel and advanced biofuel 50% lifecycle GHG reduction 

threshold. Therefore, we are including the process “esterification” as an approved 

biodiesel production process in Table 1 to 40 CFR 80.1426. In addition, consistent with 

the modeling conducted for RFS2, we interpret the RFS regulations as they existed 

prior to today’s rule as including a direct esterification process as part of the biodiesel 

pathways for which only “trans-esterification” was specifically referenced in Table 1 to 

40 CFR 80.1426. 

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. While “canola” was specifically described as the 

feedstock evaluated in the supplemental determination, we had not intended the 
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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 
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producing biodiesel with canola/rapeseed grown in other countries should be very 

similar to the GHG emissions we modeled for Canadian and U.S. canola, though they 

could be slightly (and insignificantly) higher or lower. At any rate, even if there were 

unexpected larger differences, EPA believes the small amounts of feedstock or fuel 

potentially coming from other countries will not impact our threshold analysis. 

Therefore, EPA interprets the approved canola pathway as covering canola/rapeseed 

regardless of country of origin.

We are also correcting an inadvertent omission to the proposal which incorrectly 

did not include a pathway for producing naphtha from switchgrass and miscanthus; this 

pathway was included in the original RFS2 final rule. This pathway also incorporates 

the additional energy grass feedstock sources being added today, namely energy cane, 

giant reed and napiergrass. 

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.
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B. Paperwork Reduction Act

This action does not impose any new information collection burden. The 

corrections, clarifications, and modifications to the final RFS2 regulations contained in 

this rule are within the scope of the information collection requirements submitted to the 

Office of Management and Budget (OMB) for the final RFS2 regulations.

OMB has approved the information collection requirements contained in the 

existing regulations at 40 CFR part 80, subpart M under the provisions of the Paperwork 

Reduction Act, 44 U.S.C. 3501 et seq. and has assigned OMB control numbers 2060–

0637 and 2060-0640. The OMB control numbers for EPA’s regulations in 40 CFR are 

listed in 40 CFR part 9. 

C. Regulatory Flexibility Act

The Regulatory Flexibility Act (RFA) generally requires an agency to prepare a 

regulatory flexibility analysis of any rule subject to notice and comment rulemaking 

requirements under the Administrative Procedure Act or any other statute unless the 

agency certifies that the rule will not have a significant economic impact on a substantial 

number of small entities. Small entities include small businesses, small organizations, 

and small governmental jurisdictions.

For purposes of assessing the impacts of today’s rule on small entities, small 

entity is defined as: (1) A small business as defined by the Small Business 

Administration’s (SBA) regulations at 13 CFR 121.201; (2) a small governmental 

jurisdiction that is a government of a city, county, town, school district or special district 

with a population of less than 50,000; and (3) a small organization that is any not-for-
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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 RFS2 

regulations do not impact small entities. 

D. Unfunded Mandates Reform Act

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

$100 million or more for State, local, and tribal governments, in the aggregate, or the 

private sector in any one year. We have determined that this action will not result in 

expenditures of $100 million or more for the above parties and thus, this rule is not 

subject to the requirements of sections 202 or 205 of UMRA.

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

it contains no regulatory requirements that might significantly or uniquely affect small 

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

importers, distributors and marketers and makes relatively minor corrections and 

modifications to the RFS2 regulations.

E. Executive Order 13132 (Federalism)

This action does not have federalism implications. It will not have substantial 

direct effects on the States, on the relationship between the national government and 

the States, or on the distribution of power and responsibilities among the various levels 

of government, as specified in Executive Order 13132. This action only applies to 
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gasoline, diesel, and renewable fuel producers, importers, distributors and marketers 

and makes relatively minor corrections and modifications to the RFS2 regulations. 

Thus, Executive Order 13132 does not apply to this action.

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

Governments)

This rule does not have tribal implications, as specified in Executive

Order 13175 (65 FR 67249, November 9, 2000). It applies to gasoline, diesel, and 

renewable fuel producers, importers, distributors and marketers. This action makes 

relatively minor corrections and modifications to the RFS regulations, and does not 

impose any enforceable duties on communities of Indian tribal governments. Thus, 

Executive Order 13175 does not apply to this action. 

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

Risks and Safety Risks

EPA interprets EO 13045 (62 FR 19885, April 23, 1997) as applying only to those 

regulatory actions that concern health or safety risks, such that the analysis required 

under section 5–501 of the EO has the potential to influence the regulation. This action

is not subject to EO 13045 because it does not establish an environmental standard 

intended to mitigate health or safety risks. 

H. Executive Order 13211: Actions Concerning Regulations That Significantly

Affect Energy Supply, Distribution, or Use

This 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 
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adverse effect on the supply, distribution, or use of energy. This rulemaking does not 

change any programmatic structural component of the RFS2 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 RFS2 

regulations, creating further opportunity and flexibility for compliance with the Energy 

Independence and Security Act of 2007 (EISA) mandates. 

I. National Technology Transfer and Advancement Act

Section 12(d) of the National Technology Transfer and Advancement Act of 1995 

(‘‘NTTAA’’), Public Law 104–113, 12(d) (15 U.S.C. 272 note) directs EPA to use 

voluntary consensus standards in its regulatory activities unless to do so would be 

inconsistent with applicable law or otherwise impractical. Voluntary consensus 

standards are technical standards (e.g., materials specifications, test methods, 

sampling procedures, and business practices) that are developed or adopted by 

voluntary consensus standards bodies. NTTAA directs EPA to provide Congress, 

through OMB, explanations when the Agency decides not to use available and 

applicable voluntary consensus standards.

This action does not involve technical standards. Therefore, EPA did not 

consider the use of any voluntary consensus standards.

J. Executive Order 12898: Federal Actions To Address Environmental Justice 

in Minority Populations and Low-Income Populations

Executive Order (EO) 12898 (59 FR 7629 (Feb. 16, 1994)) establishes Federal 

executive policy on environmental justice. Its main provision directs Federal agencies, 
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to the greatest extent practicable and permitted by law, to make environmental justice 

part of their mission by identifying and addressing, as appropriate, disproportionately 

high and adverse human health or environmental effects of their programs, policies, and 

activities on minority populations and low-income populations in the United States.

EPA has determined that this rule will not have disproportionately high and 

adverse human health or environmental effects on minority or low-income populations 

because it does not affect the level of protection provided to human health or the 

environment. These amendments would not relax the control measures on sources 

regulated by the RFS regulations and therefore would not cause emissions increases 

from these sources.

K. Congressional Review Act

The Congressional Review Act, 5 U.S.C. 801 et seq., as added by the Small 

Business Regulatory Enforcement Fairness Act of 1996, generally provides that before 

a rule may take effect, the agency promulgating the rule must submit a rule report, 

which includes a copy of the rule, to each House of the Congress and to the Comptroller 

General of the United States. A major rule cannot take effect until 60 days after it is

published in the Federal Register. EPA will submit a report containing this rule and 

other required information to the U.S. Senate, the U.S. House of Representatives, and 

the Comptroller General of the United States prior to publication of the rule the Federal 

Register. This action is not a “major rule” as defined by 5 U.S.C. 804(2). 
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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.

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 

6
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natural gas, biomass, or 

biogas for process energy 

and drying no more than 

50% of the distillers grains 

with solubles it markets 

annually

D Ethanol Corn starch Wet mill process using 

biomass 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 oil

One of the following:

Trans-Esterification

Esterification

Hydrotreating

Excluding processes that 

co-process 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, Soy bean oil; One of the following: 5
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renewable 

diesel, jet 

fuel and 

heating oil

Oil from annual covercrops;

Algal oil;

Biogenic waste 

oils/fats/greases;

Non-food grade corn oil

Camelina oil

Trans-Esterification

Esterification

Hydrotreating

Includes only processes 

that co-process renewable 

biomass and petroleum

I Naphtha, 

LPG

Camelina 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, 

napiergrass, giant reed, and 

energy cane; cellulosic 

components of separated yard 

waste; cellulosic components 

of separated food waste; and 

cellulosic components of 

separated MSW

Any 3

L Cellulosic 

diesel, jet 

Cellulosic Biomass from crop 

residue, slash, pre-commercial 

Any 7
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fuel and 

heating oil

thinnings and tree residue, 

annual covercrops, 

switchgrass, miscanthus, 

napiergrass, giant reed and 

energy cane; cellulosic 

components of separated yard 

waste; cellulosic components 

of separated food waste; and 

cellulosic components of 

separated MSW

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, 

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 

3
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as the only process 

energy sources

N Naphtha Cellulosic biomass from 

switchgrass, miscanthus, 

energy cane, giant reed and 

napiergrass

Gasification and 

upgrading

3

O Butanol Corn starch Fermentation; dry mill 

using natural gas, 

biomass, or biogas for 

process energy

6

P Ethanol, 

renewable 

diesel, jet 

fuel, heating 

oil, and 

naphtha

The non-cellulosic portions of 

separated food waste

Any 5

Q Biogas Landfills, sewage waste 

treatment plants, manure 

digesters

Any 5

* * * * *