14190 Federal Register / Vol. 78, No. 43 / Tuesday, March 5, 2013 / Rules and Regulations 

p.m. on the Thursday before Memorial 

Day (observed), and, if necessary due to 

inclement weather, from 2 p.m. through 

7 p.m. on the Thursday following 

Memorial Day (observed). 

Dated: February 21, 2013. 

Kevin C. Kiefer, 

Captain, U.S. Coast Guard, Captain of the 

Port Baltimore. 

[FR Doc. 2013–05076 Filed 3–4–13; 8:45 am] 

BILLING CODE 9110–04–P 

ENVIRONMENTAL PROTECTION 

AGENCY 

40 CFR Part 80 

[EPA–HQ–OAR–2011–0542; FRL–9686–3] 

RIN 2060–AR07 

Regulation of Fuels and Fuel 

Additives: Identification of Additional 

Qualifying Renewable Fuel Pathways 

Under the Renewable Fuel Standard 

Program 

AGENCY: Environmental Protection 

Agency (EPA). 

ACTION: Final rule. 

SUMMARY: EPA is issuing a final rule 

identifying additional fuel pathways 

that EPA has determined meet the 

biomass-based diesel, advanced biofuel 

or cellulosic biofuel lifecycle 

greenhouse gas (GHG) reduction 

requirements specified in Clean Air Act 

section 211(o), the Renewable Fuel 

Standard (RFS) Program, as amended by 

the Energy Independence and Security 

Act of 2007 (EISA). This final rule 

describes EPA’s evaluation of biofuels 

produced from camelina (Camelina 

sativa) oil and energy cane; it also 

includes an evaluation of renewable 

gasoline and renewable gasoline 

blendstocks, and clarifies our definition 

of renewable diesel. The inclusion of 

these pathways creates additional 

opportunity and flexibility for regulated 

parties to comply with the advanced 

and cellulosic requirements of EISA and 

provides the certainty necessary for 

investments to bring these biofuels into 

commercial production from these new 

feedstocks. 

We are not finalizing at this time 

determinations on biofuels produced 

from giant reed (Arundo donax) or 

napier grass (Pennisetum purpureum) or 

biodiesel produced from esterification. 

We continue to consider the issues 

concerning these proposals, and will 

make a final decision on them at a later 

time. 

DATES: This rule is effective on May 6, 

2013. 

FOR FURTHER INFORMATION CONTACT: 

Vincent Camobreco, Office of 

Transportation and Air Quality 

(MC6401A), Environmental Protection 

Agency, 1200 Pennsylvania Ave. NW., 

Washington, DC 20460; telephone 

number: (202) 564–9043; fax number: 

(202) 564–1686; email address: 

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 affected by this 

action include: 

Category NAICS1

Codes SIC 2 Codes Examples of potentially regulated entities 

Industry ............................................ 324110 2911 Petroleum Refineries. 

Industry ............................................ 325193 2869 Ethyl alcohol manufacturing. 

Industry ............................................ 325199 2869 Other basic organic chemical manufacturing. 

Industry ............................................ 424690 5169 Chemical and allied products merchant wholesalers. 

Industry ............................................ 424710 5171 Petroleum bulk stations and terminals. 

Industry ............................................ 424720 5172 Petroleum and petroleum products merchant wholesalers. 

Industry ............................................ 454319 5989 Other fuel dealers. 

1 North American Industry Classification System (NAICS). 

2Standard Industrial Classification (SIC) system code. 

This table is not intended to be 

exhaustive, but rather provides a guide 

for readers regarding entities likely to be 

regulated by this action. This table lists 

the types of entities that EPA is now 

aware could be potentially regulated by 

this action. Other types of entities not 

listed in the table could also be 

regulated. To determine whether your 

entity is regulated by this action, you 

should carefully examine the 

applicability criteria of Part 80, subparts 

D, E and F of title 40 of the Code of 

Federal Regulations. If you have any 

question regarding applicability of this 

action to a particular entity, consult the 

person in the preceding FOR FURTHER

INFORMATION CONTACT section above. 

Outline of This Preamble 

I. Executive Summary 

A. Purpose of the Regulatory Action 

B. Summary of the Major Provisions of the 

Regulatory Action In Question 

II. Identification of Additional Qualifying 

Renewable Fuel Pathways Under the 

Renewable Fuel Standard (RFS) Program 

A. Analysis of Lifecycle Greenhouse Gas 

Emissions for Biodiesel, Renewable 

Diesel, Jet Fuel, Heating Oil, Naphtha, 

and Liquefied Petroleum Gas (LPG) 

Produced From Camelina Oil 

B. Lifecycle Greenhouse Gas Emissions 

Analysis for Ethanol, Diesel, Jet Fuel, 

Heating Oil, and Naphtha Produced 

From Energy Cane 

C. Lifecycle Greenhouse Gas Emissions 

Analysis for Certain Renewable Gasoline 

and Renewable Gasoline Blendstocks 

Pathways 

D. Esterification Production Process 

Inclusion for Specified Feedstocks 

Producing Biodiesel 

III. Additional Changes to Listing of 

Available Pathways in Table 1 of 80.1426 

IV. Statutory and Executive Order Reviews 

A. Executive Order 12866: Regulatory 

Planning and Review and Executive 

Order 13563: Improving Regulation and 

Regulatory Review 

B. Paperwork Reduction Act 

C. Regulatory Flexibility Act 

D. Unfunded Mandates Reform Act 

E. Executive Order 13132 (Federalism) 

F. Executive Order 13175 (Consultation 

and Coordination With Indian Tribal 

Governments) 

G. Executive Order 13045: Protection of 

Children From Environmental Health 

Risks and Safety Risks 

H. Executive Order 13211: Actions 

Concerning Regulations That 

Significantly Affect Energy Supply, 

Distribution, or Use 

I. National Technology Transfer and 

Advancement Act 

J. Executive Order 12898: Federal Actions 

To Address Environmental Justice in 

Minority Populations and Low-Income 

Populations 

K. Congressional Review Act 

V. Statutory Provisions and Legal Authority 

I. Executive Summary 

A. Purpose of This Regulatory Action 

In this rulemaking, EPA is taking final 

action to identify additional fuel 


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Federal Register / Vol. 78, No. 43 / Tuesday, March 5, 2013 / Rules and Regulations 14191 

pathways that we have determined meet 

the greenhouse gas (GHG) reduction 

requirements under the Renewable Fuel 

Standard (RFS) program. This final rule 

describes EPA’s evaluation of biofuels 

produced from camelina (Camelina 

sativa) oil, which qualify as biomassbased diesel or advanced biofuel, as 

well as biofuels from energy cane which 

qualify as cellulosic biofuel. This final 

rule also qualifies renewable gasoline 

and renewable gasoline blendstock 

made from certain qualifying feedstocks 

as cellulosic biofuel. Finally, this rule 

clarifies the definition of renewable 

diesel to explicitly include jet fuel. 

EPA is taking this action as a result of 

changes to the RFS program in Clean 

Air Act (‘‘CAA’’) Section 211(o) 

required by the Energy Independence 

and Security Act of 2007 (‘‘EISA’’). This 

rulemaking modifies the RFS 

regulations published at 40 CFR 

§ 80.1400 et seq. The RFS program 

regulations specify the types of 

renewable fuels eligible to participate in 

the RFS program and the procedures by 

which renewable fuel producers and 

importers may generate Renewable 

Identification Numbers (‘‘RINs’’) for the 

qualifying renewable fuels they produce 

through approved fuel pathways. See 75 

FR 14670 (March 26, 2010); 75 FR 26026 

(May 10, 2010); 75 FR 37733 (June 30, 

2010); 75 FR 59622 (September 28, 

2010); 75 FR 76790 (December 9, 2010); 

75 FR 79964 (December 21, 2010); 77 FR 

1320 (January 9, 2012); and 77 FR 74592 

(December 17, 2012). 

By qualifying these new fuel 

pathways, this rule provides 

opportunities to increase the volume of 

advanced, low-GHG renewable fuels— 

such as cellulosic biofuels—under the 

RFS program. EPA’s comprehensive 

analyses show significant lifecycle GHG 

emission reductions from these fuel 

types, as compared to the baseline 

gasoline or diesel fuel that they replace. 

B. Summary of the Major Provisions of 

the Regulatory Action In Question 

This final rule describes EPA’s 

evaluation of: 

Camelina (Camelina sativa) oil (new 

feedstock) 

• Biodiesel, and renewable diesel, 

(including jet fuel, and heating oil)— 

qualifying to generate biomass-based 

diesel and advanced biofuel RINs 

• Naphtha and liquefied petroleum 

gas (LPG)—qualifying to generate 

advanced biofuel RINs 

Energy cane cellulosic biomass (new 

feedstock) 

• Ethanol, renewable diesel 

(including renewable jet fuel and 

heating oil), and renewable gasoline 

blendstock—qualifying to generate 

cellulosic biofuel RINs 

Renewable gasoline and renewable 

gasoline blendstock (new fuel types) 

• Produced from crop residue, slash, 

pre-commercial thinnings, tree residue, 

annual cover crops, and cellulosic 

components of separated yard waste, 

separated food waste, and separated 

municipal solid waste (MSW) 

• Using the following processes—all 

utilizing natural gas, biogas, and/or 

biomass as the only process energy 

sources—qualifying to generate 

cellulosic biofuel RINs: 

Æ Thermochemical pyrolysis 

Æ Thermochemical gasification 

Æ Biochemical direct fermentation 

Æ Biochemical fermentation with 

catalytic upgrading 

Æ Any other process that uses biogas 

and/or biomass as the only process 

energy sources 

This final rule adds these pathways to 

Table 1 to § 80.1426. This final rule 

allows producers or importers of fuel 

produced under these pathways to 

generate RINs in accordance with the 

RFS regulations, providing that the fuel 

meets other definitional criteria for 

renewable fuel. The inclusion of these 

pathways creates additional opportunity 

and flexibility for regulated parties to 

comply with the requirements of EISA. 

Substantial investment has been made 

to commercialize these new feedstocks, 

and the cellulosic biofuel industry in 

the United States continues to make 

significant advances in its progress 

towards large scale commercial 

production. Approval of these new 

feedstocks will help further the 

Congressional intent to expand the 

volumes of cellulosic and advanced 

biofuels. 

We are also finalizing two changes to 

Table 1 to 80.1426 that were proposed 

on July 1, 2011(76 FR 38844). The first 

change adds ID letters to pathways to 

facilitate references to specific 

pathways. The second change adds 

‘‘rapeseed’’ to the existing pathway for 

renewable fuel made from canola oil. 

II. Identification of Additional 

Qualifying Renewable Fuel Pathways 

Under the Renewable Fuel Standard 

(RFS) Program 

This rule was originally published in 

the Federal Register at 77 FR 462, 

January 5, 2012 as a direct final rule, 

with a parallel publication of a 

proposed rule. A limited number of 

relevant adverse comments were 

received, and EPA published a 

withdrawal notice of the direct final 

rule on March 5, 2012 (77 FR 13009). A 

second comment period was not issued, 

since the simultaneous publication of 

the proposed rule provided an adequate 

notice and comment process. EPA is 

finalizing several of the proposed 

actions in this final rule, but continues 

to consider determinations on biofuels 

produced from giant reed (Arundo 

donax) or napier grass (Pennisetum 

purpureum) or biodiesel produced from 

esterification. EPA will make a final 

decision on theses elements of the 

proposal at a later time. 

In this action, EPA is issuing a final 

rule to identify in the RFS regulations 

additional renewable fuel production 

pathways that we have determined meet 

the greenhouse gas (GHG) reduction 

requirements of the RFS program. There 

are three critical components of a 

renewable fuel pathway: (1) Fuel type, 

(2) feedstock, and (3) production 

process. Each specific combination of 

the three components, or fuel pathway, 

is assigned a D code which is used to 

designate the type of biofuel and its 

compliance category under the RFS 

program. This final rule describes EPA’s 

lifecycle GHG evaluation of camelina oil 

and energy cane. 

Determining whether a fuel pathway 

satisfies the CAA’s lifecycle GHG 

reduction thresholds for renewable fuels 

requires a comprehensive evaluation of 

the lifecycle GHG emissions of the 

renewable fuel as compared to the 

lifecycle GHG emissions of the baseline 

gasoline or diesel fuel that it replaces. 

As mandated by CAA section 211(o), the 

GHG emissions assessments must 

evaluate the aggregate quantity of GHG 

emissions (including direct emissions 

and significant indirect emissions such 

as significant emissions from land use 

changes) related to the full fuel 

lifecycle, including all stages of fuel and 

feedstock production, distribution, and 

use by the ultimate consumer. 

In examining the full lifecycle GHG 

impacts of renewable fuels for the RFS 

program, EPA considers the following: 

• Feedstock production—based on 

agricultural sector models that include 

direct and indirect impacts of feedstock 

production. 

• Fuel production—including process 

energy requirements, impacts of any raw 

materials used in the process, and 

benefits from co-products produced. 

• Fuel and feedstock distribution— 

including impacts of transporting 

feedstock from production to use, and 

transport of the final fuel to the 

consumer. 

• Use of the fuel—including 

combustion emissions from use of the 

fuel in a vehicle. 

Many of the pathways evaluated in 

this rulemaking rely on a comparison to 

the lifecycle GHG analysis work that 

was done as part of the Renewable Fuel 


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14192 Federal Register / Vol. 78, No. 43 / Tuesday, March 5, 2013 / Rules and Regulations 

1Putnam, 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. 

2Moser, 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. 

3McVay, K.A., and P.F. Lamb. 2008. Camelina 

production in Montana. MSU Ext. MT200701AG 

(revised). http://msuextension.org/publications/ 

AgandNaturalResources/MT200701AG.pdf. 

4Putnam et al., 1993. 

5Lafferty, 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%20Camelina%20Production%20Guide%202009.pdf. 

6Telephone conversation with Scott Johnson, 

Sustainable Oils, January 11, 2011. 

7See http://agr.mt.gov/camelina/FDAletter11- 

09.pdf. 

8Comment 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. 

9http://www.gpo.gov/fdsys/pkg/FR-1999-02-08/ 

pdf/99-3184.pdf. 

10However, this list is not exhaustive and is 

generally limited to species that are not currently 

in the U.S. or are incipient to the U.S. See http://

plants.usda.gov/java/ 

noxious?rptType=Federal&statefips=&sort=sc. 

Accessed on March 28, 2012. 

11EPA continues to evaluate Arundo donax and 

napier grass as feedstock for a renewable fuel 

pathway, and will make a final decision on these 

pathways at a later time. 

12McCormick, Margaret. ‘‘Oral Comments of 

Targeted Growth, Incorporated’’ Submitted to the 

EPA on June 9, 2009. 

13See https://www.camelinacompany.com/ 

Marketing/PressRelease.aspx?Id=25. 

Standard Program Final Rule, published 

March 26, 2010 (75 FR 14670) (March 

2010 RFS). The evaluations here rely on 

comparisons to the existing analyses 

presented in the March 2010 final rule. 

EPA plans to periodically review and 

revise the methodology and 

assumptions associated with calculating 

the GHG emissions from all renewable 

fuel pathways. 

A. Analysis of Lifecycle Greenhouse Gas 

Emissions for Biodiesel, Renewable 

Diesel, Jet Fuel, Heating Oil, Naphtha, 

and Liquefied Petroleum Gas (LPG) 

Produced From Camelina Oil 

The following sections describe EPA’s 

evaluation of camelina (Camelina 

sativa) as a biofuel feedstock under the 

RFS program. As discussed previously, 

this analysis relies on a comparison to 

the lifecycle GHG analysis work that 

was done as part of the Renewable Fuel 

Standard Program (RFS) Final Rule, 

published March 26, 2010 for soybean 

oil biofuels. 

1. Feedstock Production 

Camelina sativa (camelina) is an 

oilseed crop within the flowering plant 

family Brassicaceae that is native to 

Northern Europe and Central Asia. 

Camelina’s suitability to northern 

climates and low moisture requirements 

allows it to be grown in areas that are 

unsuitable for other major oilseed crops 

such as soybeans, sunflower, and 

canola/rapeseed. Camelina also requires 

the use of little to no tillage.1 Compared 

to many other oilseeds, camelina has a 

relatively short growing season (less 

than 100 days), and can be grown either 

as a spring annual or in the winter in 

milder climates.2 3 Camelina can also be 

used to break the continuous planting 

cycle of certain grains, effectively 

reducing the disease, insect, and weed 

pressure in fields planted with such 

grains (like wheat) in the following 

year.4

Although camelina has been 

cultivated in Europe in the past for use 

as food, medicine, and as a source for 

lamp oil, commercial production using 

modern agricultural techniques has 

been limited.5 In addition to being used 

as a renewable fuel feedstock, small 

quantities of camelina (less than 5% of 

total U.S. camelina production) are 

currently used as a dietary supplement 

and in the cosmetics industry. 

Approximately 95% of current US 

production of camelina has been used 

for testing purposes to evaluate its use 

as a feedstock to produce primarily jet 

fuel.6 The FDA has not approved 

camelina for food uses, although it has 

approved the inclusion of certain 

quantities of camelina meal in 

commercial feed.7

In response to the proposed rule, EPA 

received comments highlighting the 

concern that by approving certain new 

feedstock types under the RFS program, 

EPA would be encouraging their 

introduction or expanded planting 

without considering their potential 

impact as invasive species.8 The degree 

of concern expressed by the commenters 

depended somewhat on the feedstock. 

As pointed out by the commenters, 

camelina and energy cane are not 

‘‘native species,’’ defined as ‘‘a species 

that, other than as a result of an 

introduction, historically occurred or 

currently occurs in that ecosystem.’’ The 

commenters asserted that there is a 

‘‘potential risk posed by the non-native 

species camelina and energy cane.’’ In 

contrast, comments stated that giant 

reed (Arundo donax) or napier grass 

(Pennisetum purpureum) have been 

identified as invasive species in certain 

parts of the country. These commenters 

asserted that the Arundo donax and 

napier grass pose a ‘‘clear risk of 

invasion.’’ Commenters stated that EPA 

should not approve the proposed 

feedstocks until EPA has conducted an 

invasive species analysis, as required 

under Executive Order (EO) 13112.9

The information before us does not 

raise significant concerns about the 

threat of invasiveness and related GHG 

emissions for camelina. For example, 

camelina is not listed on the Federal 

Noxious Weed List,10 nor is it listed on 

any state invasive species or noxious 

weed list. We believe that the 

production of camelina is unlikely to 

spread beyond the intended borders in 

which it is grown, which is consistent 

with the assumption in EPA’s lifecycle 

analysis that significant expenditures of 

energy or other sources of GHGs will not 

be required to remediate the spread of 

this feedstock from the specific 

locations where it is grown as a 

renewable fuel feedstock for the RFS 

program. Therefore, we are finalizing 

the camelina pathway in this rule based 

on our lifecycle analysis discussed 

below.11

Camelina is currently being grown on 

approximately 50,000 acres of land in 

the U.S., primarily in Montana, eastern 

Washington, and the Dakotas.12 USDA 

does not systematically collect camelina 

production information; therefore data 

on historical acreage is limited. 

However, available information 

indicates that camelina has been grown 

on trial plots in 12 U.S. states.13

In response to the proposed rule, two 

commenters were supportive of the use 

of renewable feedstocks such as 

camelina oil to produce biofuels for 

aviation. One commenter noted that 

aviation is unique in its complete 

dependency upon liquid fuel—today 

and into the foreseeable future. Another 

commenter noted that development of 

additional feedstocks and production 

pathways should increase supply and 

ultimately move us closer to the day 

when renewable jet fuels are pricecompetitive 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 


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Federal Register / Vol. 78, No. 43 / Tuesday, March 5, 2013 / Rules and Regulations 14193 

14Fallow land here refers to cropland that is 

periodically not cultivated. 

15See Shonnard, D. R., Williams, L., & Kalnes, T. 

N. 2010. Camelina-Derived Jet Fuel and Diesel: 

Sustainable Advanced Biodiesel. Environmental 

Progress & Sustainable Energy, 382–392. 

16Personal 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. 

17See Sainju, U.M., T. Caesar-Tonthat, A.W. 

Lenssen, R.G. Evans, and R. Kohlberg. 2007. Longterm tillage and cropping sequence effects on 

dryland residue and soil carbon fractions. Soil 

Science Society of America Journal 71: 1730–1739. 

18See Shonnard et al., 2010; Lafferty et al., 2009. 

expected to be primarily planted in the 

U.S. as a rotation crop on acres that 

would otherwise remain fallow.14

Because camelina has not yet been 

established as a commercial crop with 

significant monetary value, farmers are 

unlikely to dedicate acres for camelina 

production that could otherwise be used 

to produce other cash crops. Since 

camelina would therefore not be 

expected to displace another crop but 

rather maximize the value of the land 

through planting camelina in rotation, 

EPA does not believe new acres would 

need to be brought into agricultural use 

to increase camelina production. In 

addition, camelina currently has only 

limited high-value niche markets for 

uses other than renewable fuels. Unlike 

commercial crops that are tracked by 

USDA, camelina does not have a wellestablished, internationally traded 

market that would be significantly 

affected by an increase in the use of 

camelina to produce biofuels. For these 

reasons, which are described in more 

detail below, EPA has determined that 

production of camelina-based biofuels is 

not expected to result in significant 

GHG emissions related to direct land 

use change since it is expected to be 

grown on fallow land. Furthermore, due 

to the limited non-biofuel uses for 

camelina, production of camelina-based 

biofuels is not expected to have a 

significant impact on other agricultural 

crop production or commodity markets 

(either camelina or other crop markets) 

and consequently would not result in 

significant GHG emissions related to 

indirect land use change. To the extent 

camelina-based biofuel production 

decreases the demand for alternative 

biofuels, some with higher GHG 

emissions, this biofuel could have some 

beneficial GHG impact. However, it is 

uncertain which mix of biofuel sources 

the market will demand so this potential 

GHG impact cannot be quantified. 

Commenters stated that EPA failed to 

justify why camelina would be grown 

on fallow land and thus result in no 

land use change. In the proposed rule, 

EPA provided a detailed description of 

the economics indicating why 

producers are most likely to grow 

camelina on land that would otherwise 

remain fallow. This analysis formed the 

basis for why it was reasonable and 

logical for camelina to be grown on 

acres that would otherwise remain 

fallow. Comments also indicated that 

EPA’s economic basis for assuming 

camelina would most likely be grown 

on fallow land was inadequate, 

especially if production of camelina was 

scaled up. However, the comment did 

not indicate any specific point of error 

in our economically based analysis. As 

we described in the proposed rule and 

discuss below, camelina is currently not 

a commercially raised crop in the 

United States, therefore the returns on 

camelina are expected to be low 

compared to wheat and other crops with 

established, commercially traded 

markets.15 Therefore, EPA expects that 

initial production of camelina for 

biofuel production will be on land with 

the lowest opportunity cost. Based on 

this logic, EPA believes camelina will be 

grown as a rotation crop, as discussed 

below, on dryland wheat acres replacing 

a period that the land would otherwise 

be left fallow. 

In the semi-arid regions of the 

Northern Great Plains, dryland wheat 

farmers currently leave acres fallow 

once every three to four years to allow 

additional moisture and nutrients to 

accumulate (see Figure 1). Recent 

research indicates that introducing cool 

season oilseed crops such as camelina 

can provide benefits by reducing soil 

erosion, increasing soil organic matter, 

and disrupting pest cycles. Although 

long-term data on the effects of 

replacing wheat/fallow growing patterns 

with wheat/oilseed rotations is limited, 

there is some data that growing oilseeds 

in drier semi-arid regions year after year 

can lead to reduced wheat yields.16

However, the diversification and 

intensification of wheat-fallow cropping 

systems can improve the long term 

economic productivity of wheat acres by 

increasing soil nitrogen and soil organic 

carbon pools.17 In addition, selective 

breeding is expected to reduce the 

potential negative impacts on wheat 

yields.18 Additional research in this area 

is needed and if significant negative 

impacts on crop rotations are 

determined from camelina grown on 

fallow acres EPA would take that into 

account in future analysis. 


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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 


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Federal Register / Vol. 78, No. 43 / Tuesday, March 5, 2013 / Rules and Regulations 14195 

19 2009 USDA Baseline. See http:// 

www.ers.usda.gov/publications/oce091/. 

20 Johnson, S. and McCormick, M., Camelina: an 

Annual Cover Crop Under 40 CFR Part 80 Subpart 

M, Memorandum, dated November 5, 2010. 

21Wheeler, P. and Guillen-Portal F. 2007. 

Camelina Production in Montana: A survey study 

sponsored by Targeted Growth, Inc. and Barkley Ag. 

Enterprises, LLP. 

22See 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. 

23Ehrensing, 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. 

24See Shonnard et al., 2010. 

25This assumes no significant adverse climate 

impacts on world agricultural yields over the 

analytical timeframe. 

26See Lafferty et al, 2009; Shonnard et al, 2010; 

Sustainable Oils Memo dated November 5, 2010. 

27Wheeler & Guillen-Portal, 2007. 

28See http://www.ers.usda.gov/media/273343/ 

oce121_2_.pdf. 

it becomes a commercial crop with a 

well-established market value. EPA 

once again reiterates that we will 

continue to monitor the growing 

patterns associated with camelina to 

determine whether actual production is 

consistent with the assumptions used in 

this analysis. Monitoring will be done 

by tracking the amount of RIN 

generating camelina fuel produced 

through the EPA Moderated Transaction 

System (EMTS). We can compare the 

amount of RIN generating fuel against 

expected volumes from fallow acres in 

conjunction with USDA. Consistent 

with EPA’s approach to all RFS 

feedstock pathway analyses, we will 

periodically reevaluate whether our 

assessment of GHG impacts will need to 

be updated in the future based on the 

potential for significant changes in our 

analyses. 

a. Land Availability 

USDA estimates that there are 

approximately 60 million acres of wheat 

in the U.S.19 USDA and wheat state 

cooperative extension reports through 

2008 indicate that 83% of US wheat 

production is under non-irrigated, 

dryland conditions. Of the 

approximately 50 million non-irrigated 

acres, at least 45% are estimated to 

follow a wheat/fallow rotation. Thus, 

approximately 22 million acres are 

potentially suitable for camelina 

production. However, according to 

industry projections, only about 9 

million of these wheat/fallow acres have 

the appropriate climate, soil profile, and 

market access for camelina 

production.20 Therefore, our analysis 

uses the estimate that only 9 million 

wheat/fallow acres are available for 

camelina production. 

One commenter stated that EPA 

assumed more than 8 million acres 

would be used to produce camelina, 

even though a recent paper stated that 

only 5 million acres would have the 

potential to grow camelina in a 

sustainable manner in a way that would 

not impact the food supply. This 

commenter misinterpreted EPA’s 

assumptions. EPA’s assessment is based 

on a three year rotation cycle in which 

only one third of the 9 million available 

acres would be fallow in any given year. 

In other words, EPA assumed only 3 

million acres would be planted with 

camelina in any given year. This 

number is less than the 5 million acres 

the Shonnard et. al. paper states would 

be available annually for camelina 

planting. 

b. Projected Volumes 

Based on these projections of land 

availability, EPA estimates that at 

current yields (approximately 800 

pounds per acre), approximately 100 

million gallons (MG) of camelina-based 

renewable fuels could be produced with 

camelina grown in rotation with 

existing crop acres without having 

direct land use change impacts. Also, 

since camelina will likely be grown on 

fallow land and thus not displace any 

other crop and since camelina currently 

does not have other significant markets, 

expanding production and use of 

camelina for biofuel purposes is not 

likely to have other agricultural market 

impacts and therefore, would not result 

in any significant indirect land use 

impacts.21 Yields of camelina are 

expected to approach the yields of 

similar oilseed crops over the next few 

years, as experience with growing 

camelina improves cultivation practices 

and the application of existing 

technologies are more widely adopted.22

Yields of 1650 pounds per acre have 

been achieved on test plots, and are in 

line with expected yields of other 

oilseeds such as canola/rapeseed. 

Assuming average US yields of 1650 

pounds per acre,23 approximately 200 

MG of camelina-based renewable fuels 

could be produced on existing wheat/ 

fallow acres. Finally, if investment in 

new seed technology allows yields to 

increase to levels assumed by Shonnard 

et al (3000 pounds per acre), 

approximately 400 MG of camelinabased renewable fuels could be 

produced on existing acres.24

Depending on future crop yields, we 

project that roughly 100 MG to 400 MG 

of camelina-based biofuels could be 

produced on currently fallow land with 

no impacts on land use.25

We also received comments that we 

overestimated long term camelina 

yields. The commentors stated that 

reaching yields of 3000 pounds per acre 

may be attainable, but previous trials do 

not suggest that yields could reach this 

level in ten years. As a point of 

clarification, we did not assume that 

yields would need to be 3000 pounds 

per acre for biodiesel produced from 

camelina oil to qualify as an advanced 

biofuel. In the analysis presented below, 

EPA assumed yields of camelina would 

be 1650 pounds per acre. Since the use 

of camelina as a biofuel feedstock in the 

U.S. is in its infancy, it is reasonable to 

consider how yields will change over 

time. Furthermore, jet fuel contracts and 

the BCAP programs play a very 

important part in determining the 

amount of camelina planted, and 

therefore interest in increasing yields. 

As the commenter noted, this yield 

assumption is within the range of 

potential yields of 330–2400 pounds per 

acre found in the current literature. 

c. Indirect Impacts 

Although wheat can in some cases be 

grown in rotation with other crops such 

as lentils, flax, peas, garbanzo, and 

millet, cost and benefit analysis indicate 

that camelina is most likely to be 

planted on soil with lower moisture and 

nutrients where other rotation crops are 

not viable.26 Because expected returns 

on camelina are relatively uncertain, 

farmers are not expected to grow 

camelina on land that would otherwise 

be used to grow cash crops with well 

established prices and markets. Instead, 

farmers are most likely to grow camelina 

on land that would otherwise be left 

fallow for a season. The opportunity 

cost of growing camelina on this type of 

land is much lower. As previously 

discussed, this type of land represents 

the 9 million acres currently being 

targeted for camelina production. 

Current returns on camelina are 

relatively low ($13.24 per acre), given 

average yields of approximately 800 

pounds per acre and the current 

contract price of $0.145 per pound.27

See Table 1. For comparison purposes, 

the USDA projections for wheat returns 

are between $133–$159 per acre 

between 2010 and 2020.28 Over time, 

advancements in seed technology, 

improvements in planting and 

harvesting techniques, and higher input 

usage could significantly increase future 

camelina yields and returns. 


emcdonald on DSK67QTVN1PROD with RULES
14196 Federal Register / Vol. 78, No. 43 / Tuesday, March 5, 2013 / Rules and Regulations 

29See Sustainable Oils Memo dated November 5, 

2010. 

30Based on yields technically feasible. See 

McVey and Lamb, 2008; Ehrenson & Guy, 2008. 

31Adapted from Shonnard et al, 2010. 

32See 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. 33Wright & Marois, 2011. 

TABLE 1—CAMELINA COSTS AND RETURNS

Inputs Rates 2010 

Camelina 29

2022 

Camelina 30

2030 

Camelina 31

Herbicides: 

Glysophate (Fall) .............................................................. 16 oz. ( $0.39/oz) .................. $7.00 $7.00 $7.00 

Glysophate (Spring) ......................................................... 16 oz. ( $0.39/oz) .................. $7.00 $7.00 $7.00 

Post .................................................................................. 12 oz ( $0.67/oz) ................... $8.00 $8.00 $8.00 

Seed: 

Camelina seed ................................................................. $1.44/lb .................................. $5.76 

(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 means by which the majority of 

all domestic camelina is commercially 

harvested in the short- to medium-term, 

in the long term camelina may expand 

to other regions and growing methods.32

For example, if camelina production 

expanded beyond the 9 million acres 

assumed available from wheat fallow 

land, it could impact other crops. 

However, as discussed above this is not 

likely to happen in the near term due to 

uncertainties in camelina financial 

returns. Camelina production could also 

occur in areas where wheat is not 

commonly grown. For example, testing 

of camelina production has occurred in 

Florida in rotation with kanaf, peanuts, 

cotton, and corn. However, only 200 

acres of camelina were harvested in 

2010 in Florida. While Florida acres of 

camelina are expected to be higher in 

2011, very little research has been done 

on growing camelina in Florida. For 

example, little is known about potential 

seedling disease in Florida or how 

camelina may be affected differently 

than in colder climates.33 Therefore, 

camelina grown outside of a wheat 

fallow situation was not considered as 

part of this analysis. 

The determination in this final rule is 

based on our projection that camelina is 

likely to be produced on what would 

otherwise be fallow land. However, the 

rule applies to all camelina regardless of 

where it is grown. EPA does not expect 

that significant camelina would be 

grown on non-fallow land, and small 

quantities that may be grown elsewhere 

and used for biofuel production will not 

significantly impact our analysis. 

Furthermore, although we expect 

most camelina used as a feedstock for 

renewable fuel production that would 

qualify in the RFS program would be 

grown in the U.S., today’s rule would 

apply to qualifying renewable fuel made 

from camelina grown in any country. 

For the same reasons that pertain to U.S. 

production of camelina, we expect that 

camelina grown in other countries 

would also be produced on land that 

would otherwise be fallow and would 

therefore have no significant land use 

change impacts. The renewable biomass 

provisions under the Energy 

Independence and Security Act would 

prohibit direct land conversion into new 

agricultural land for camelina 

production for biofuel internationally. 

Additionally, any camelina production 

on existing cropland internationally 

would not be expected to have land use 

impacts beyond what was considered 

for international soybean production 

(soybean oil is the expected major 

feedstock source for US biodiesel fuel 

production and thus the feedstock of 

reference for the camelina evaluation). 

Because of these factors along with the 

small amounts of fuel potentially 

coming from other countries, we believe 

that incorporating fuels produced in 

other countries will not impact our 

threshold analysis for camelina-based 

biofuels. 

d. Crop Inputs 

For comparison purposes, Table 2 

shows the inputs required for camelina 

production compared to the FASOM 

agricultural input assumptions for 

soybeans. Since yields and input 

assumptions vary by region, a range of 

values for soybean production are 

shown in Table 2. The camelina input 

values in Table 2 represent average 

values, camelina input values will also 

vary by region, however, less data is 

available comparing actual practices by 

region due to limited camelina 

production. More information on 

camelina inputs is available in materials 

provided in the docket. 


emcdonald on DSK67QTVN1PROD with RULES
Federal Register / Vol. 78, No. 43 / Tuesday, March 5, 2013 / Rules and Regulations 14197 

34A. Pradhan, D.S. Shrestha, A. McAloon, W. 

Yee, M. Haas, J.A. Duffield, H. Shapouri, September 

2009, ‘‘Energy Life-Cycle Assessment of Soybean 

Biodiesel’’, United States Department of 

Agriculture, Office of the Chief Economist, Office of 

Energy Policy and New Uses, Agricultural 

Economic Report Number 845. 

TABLE 2—INPUTS FOR CAMELINA AND SOYBEAN PRODUCTION

Camelina Soybeans (varies by region) 

Inputs 

(per acre) 

Emissions 

(per mmBtu fuel) 

Inputs 

(per acre) 

Emissions 

(per mmBtu fuel) 

N2O ...................................... N/A ....................................... 22 kg CO2-eq ....................... N/A ....................................... 9–12 kg CO2-eq. 

Nitrogen Fertilizer ................. 40 lbs ................................... 7 kg CO2-eq ......................... 3.5–8.2 lbs ........................... 1–3 kg CO2-eq. 

Phosphorous Fertilizer ......... 15 lbs ................................... 1 kg CO2-eq ......................... 5.4–21.4 lbs ......................... 0–2 kg CO2-eq. 

Potassium Fertilizer .............. 10 lbs ................................... 0 kg CO2-eq ......................... 3.1–24.3 lbs ......................... 0–2 kg CO2-eq. 

Herbicide .............................. 2.75 lbs ................................ 3 kg CO2-eq ......................... 0.0–1.3 lbs ........................... 0–2 kg CO2-eq. 

Pesticide ............................... 0 lbs ..................................... 0 kg CO2-eq ......................... 0.1–0.8 lbs ........................... 0–2 kg CO2-eq. 

Diesel ................................... 3.5 gal .................................. 5 kg CO2-eq ......................... 3.8–8.9 gal ........................... 7–20 kg CO2-eq. 

Gasoline ............................... 0 gal ..................................... 0 kg CO2-eq ......................... 1.6–3.0 gal ........................... 3–5 kg CO2-eq. 

Total ..................................... .............................................. 39 kg CO2-eq ....................... .............................................. 21–47 kg CO2-eq. 

Regarding crop inputs per acre, it 

should be noted that camelina has a 

higher percentage of oil per pound of 

seed than soybeans. Soybeans are 

approximately 18% oil, therefore 

crushing one pound of soybeans yields 

0.18 pounds of oil. In comparison, 

camelina is approximately 36% oil, 

therefore crushing one pound of 

camelina yields 0.36 pounds of oil. The 

difference in oil yield is taken into 

account when calculating the emissions 

per mmBTU included in Table 2. As 

shown in Table 2, GHG emissions from 

feedstock production for camelina and 

soybeans are relatively similar when 

factoring in variations in oil yields per 

acre and fertilizer, herbicide, pesticide, 

and petroleum use. 

In summary, EPA concludes that the 

agricultural inputs for growing camelina 

are similar to those for growing soy 

beans, direct land use change impacts 

are expected to be negligible due to 

planting on land that would be 

otherwise fallow, and the limited 

production and use of camelina 

indicates no expected impacts on other 

crops and therefore no indirect land use 

impacts. 

e. Crushing and Oil Extraction 

We also looked at the seed crushing 

and oil extraction process and compared 

the lifecycle GHG emissions from this 

stage for soybean oil and camelina oil. 

As discussed above, camelina seeds 

produce more oil per pound than 

soybeans. As a result, the lifecycle GHG 

emissions associated with crushing and 

oil extraction are lower for camelina 

than soybeans, per pound of vegetable 

oil produced. Table 3 summarizes data 

on inputs, outputs and estimated 

lifecycle GHG emissions from crushing 

and oil extraction. The data on soybean 

crushing comes from the March 2010 

RFS final rule, based on a process model 

developed by USDA–ARS.34 The data 

on camelina crushing is from Shonnard 

et al. (2010). 

TABLE 3—COMPARISON OF CAMELINA AND SOYBEAN CRUSHING AND OIL EXTRACTION

Item Soybeans Camelina Units 

Material Inputs: 

Beans or Seeds ........................................................................................................ 5.38 2.90 Lbs. 

Energy Inputs: 

Electricity .................................................................................................................. 374 47 Btu. 

Natural Gas & Steam ............................................................................................... 1,912 780 Btu. 

Outputs: 

Refined vegetable oil ................................................................................................ 1.00 1.00 Lbs. 

Meal .......................................................................................................................... 4.08 1.85 Lbs. 

GHG Emissions ........................................................................................................ 213 64 gCO2e/lb refined oil. 

2. Feedstock Distribution, Fuel 

Distribution, and Fuel Use 

For this analysis, EPA projects that 

the feedstock distribution emissions 

will be the same for camelina and 

soybean oil. To the extent that camelina 

contains more oil per pound of seed, as 

discussed above, the energy needed to 

move the camelina would be lower than 

soybeans per gallon of fuel produced. 

To the extent that camelina is grown on 

more disperse fallow land than soybean 

and would need to be transported 

further, the energy needed to move the 

camelina could be higher than soybean. 

We believe the assumption to use the 

same distribution impacts for camelina 

as soybean is a reasonable estimate of 

the GHG emissions from camelina 

feedstock distribution. In addition, the 

final fuel produced from camelina is 

also expected to be similar in 

composition to the comparable fuel 

produced from soybeans, therefore we 

are assuming GHG emissions from the 

distribution and use of fuels made from 

camelina will be the same as emissions 

of fuel produced from soybeans. 

3. Fuel Production 

There are two main fuel production 

processes used to convert camelina oil 

into fuel. The trans-esterification 

process produces biodiesel and a 

glycerin co-product. The hydrotreating 

process can be configured to produce 

renewable diesel either primarily as 

diesel fuel (including heating oil) or 

primarily as jet fuel. Possible additional 

products from hydrotreating include 

naphtha LPG, and propane. Both 

processes and the fuels produced are 

described in the following sections. 

Both processes use camelina oil as a 

feedstock and camelina crushing is also 

included in the analysis. 


emcdonald on DSK67QTVN1PROD with RULES
14198 Federal Register / Vol. 78, No. 43 / Tuesday, March 5, 2013 / Rules and Regulations 

35 Kalnes, T., N., McCall, M., M., Shonnard, D., 

R., 2010. Renewable Diesel and Jet-Fuel Production 

from Fats and Oils. Thermochemical Conversion of 

Biomass to Liquid Fuels and Chemicals, Chapter 18, 

p. 475. 

a. Biodiesel 

For this analysis, we assumed the 

same biodiesel production facility 

designs and conversion efficiencies as 

modeled for biodiesel produced from 

soybean oil and canola/rapeseed oil. 

Camelina oil biodiesel is produced 

using the same methods as soybean oil 

biodiesel, therefore plant designs are 

assumed to not significantly differ 

between fuels made from these 

feedstocks. As was the case for soybean 

oil biodiesel, we have not projected in 

our assessment of camelina oil biodiesel 

any significant improvements in plant 

technology. Unanticipated energy 

saving improvements would further 

improve GHG performance of the fuel 

pathway. 

The glycerin produced from camelina 

biodiesel production is chemically 

equivalent to the glycerin produced 

from the existing biodiesel pathways 

(e.g., based on soy oil) that were 

analyzed as part of the March 2010 RFS 

final rule. Therefore the same coproduct credit would apply to glycerin 

from camelina biodiesel as glycerin 

produced in the biodiesel pathways 

modeled for the March 2010 RFS final 

rule. The assumption is that the GHG 

reductions associated with the 

replacement of residual oil with 

glycerin on an energy equivalent basis 

represents an appropriate midrange coproduct credit of biodiesel produced 

glycerin. 

As part of our RFS2 proposal, we 

assumed the glycerin would have no 

value and would effectively receive no 

co-product credits in the soy biodiesel 

pathway. We received numerous 

comments, however, asserting that the 

glycerin would have a beneficial use 

and should generate co-product 

benefits. Therefore, the biodiesel 

glycerin co-product determination made 

as part of the March 2010 RFS final rule 

took into consideration the possible 

range of co-product credit results. The 

actual co-product benefit will be based 

on what products are replaced by the 

glycerin and what new uses develop for 

the co-product glycerin. The total 

amount of glycerin produced from the 

biodiesel industry will actually be used 

across a number of different markets 

with different GHG impacts. This could 

include for example, replacing 

petroleum glycerin, replacing fuel 

products (residual oil, diesel fuel, 

natural gas, etc.), or being used in new 

products that don’t have a direct 

replacement, but may nevertheless have 

indirect effects on the extent to which 

existing competing products are used. 

The more immediate GHG reduction 

credits from glycerin co-product use 

could range from fairly high reduction 

credits if petroleum glycerin is replaced 

to lower reduction credits if it is used 

in new markets that have no direct 

replacement product, and therefore no 

replaced emissions. 

EPA does not have sufficient 

information (and received no relevant 

comments as part of the March 2010 

RFS rule) on which to allocate glycerin 

use across the range of likely uses. 

Therefore, EPA believes that the 

approach used in the RFS of picking a 

surrogate use for modeling purposes in 

the mid-range of likely glycerin uses, 

and the GHG emissions results tied to 

such use, is reasonable. The 

replacement of an energy equivalent 

amount of residual oil is a simplifying 

assumption determined by EPA to 

reflect the mid-range of possible 

glycerin uses in terms of GHG credits. 

EPA believes that it is appropriately 

representative of GHG reduction credit 

across the possible range without 

necessarily biasing the results toward 

high or low GHG impact. Given the 

fundamental difficulty of predicting 

possible glycerin uses and impacts of 

those uses many years into the future 

under evolving market conditions, EPA 

believes it is reasonable to use the more 

simplified approach to calculating coproduct GHG benefits associated with 

glycerin production at this time. EPA 

will continue to evaluate the co-product 

credit associated with glycerine 

production in future rulemakings. 

Given the fact that GHG emissions 

from camelina-based biodiesel would be 

similar to the GHG emissions from 

soybean-based biodiesel at all stages of 

the lifecycle but would not result in 

land use changes as was the case for soy 

oil used as a feedstock, we believe 

biodiesel from camelina oil will also 

meet the 50% GHG emissions reduction 

threshold to qualify as a biomass based 

diesel and an advanced fuel. Therefore, 

EPA is including biodiesel produced 

from camelina oil under the same 

pathways for which biodiesel made 

from soybean oil qualifies under the 

March 2010 RFS final rule. 

b. Renewable Diesel (Including Jet Fuel 

and Heating Oil), Naphtha, and LPG 

The same feedstocks currently used 

for biodiesel production can also be 

used in a hydrotreating process to 

produce a slate of products, including 

diesel fuel, heating oil (defined as No. 

1 or No. 2 diesel), jet fuel, naphtha, LPG, 

and propane. Since the term renewable 

diesel is defined to include the products 

diesel fuel, jet fuel and heating oil, the 

following discussion uses the term 

renewable diesel to also include diesel 

fuel, jet fuel and heating oil. The yield 

of renewable diesel is relatively 

insensitive to feedstock source.35 While 

any propane produced as part of the 

hydrotreating process will most likely 

be combusted within the facility for 

process energy, the other co-products 

that can be produced (i.e., renewable 

diesel, naphtha, LPG) are higher value 

products that could be used as 

transportation fuels or, in the case of 

naphtha, a blendstock for production of 

transportation fuel. The hydrotreating 

process maximized for producing a 

diesel fuel replacement as the primary 

fuel product requires more overall 

material and energy inputs than 

transesterification to produce biodiesel, 

but it also results in a greater amount of 

other valuable co-products as listed 

above. The hydrotreating process can 

also be maximized for jet fuel 

production which requires even more 

process energy than the process 

optimized for producing a diesel fuel 

replacement, and produces a greater 

amount of co-products per barrel of 

feedstock, especially naphtha. 

Producers of renewable diesel from 

camelina have expressed interest in 

generating RINs under the RFS program 

for the slate of products resulting from 

the hydrotreating process. Our lifecycle 

analysis accounts for the various uses of 

the co-products. There are two main 

approaches to accounting for the coproducts produced, the allocation 

approach, and the displacement 

approach. In the allocation approach all 

the emissions from the hydrotreating 

process are allocated across all the 

different co-products. There are a 

number of ways to do this but since the 

main use of the co-products would be to 

generate RINs as a fuel product we 

allocate based on the energy content of 

the co-products produced. In this case, 

emissions from the process would be 

allocated equally to all the Btus 

produced. Therefore, on a per Btu basis 

all co-products would have the same 

emissions. The displacement approach 

would attribute all of the emissions of 

the hydrotreating process to one main 

product and then account for the 

emission reductions from the other coproducts 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 


emcdonald on DSK67QTVN1PROD with RULES
Federal Register / Vol. 78, No. 43 / Tuesday, March 5, 2013 / Rules and Regulations 14199 

36For 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. 

37Pearlson, M., N. 2011. A Techno-Economic and 

Environmental Assessment of Hydroprocessed 

Renewable Distillate Fuels. 

38Huo, 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. 

39We 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. 

40Based on Pearlson (2011), Table 3.1 and Table 

3.2. 

41See for example the spreadsheet with lifecycle 

GHG emissions calculations titled ‘‘Final Camelina 

Calculations for Docket’’ with document number 

EPA–HQ–OAR–2011–0542–0046. 

alternative products, for example, 

naphtha would displace gasoline, LPG 

would displace natural gas, etc. This 

assumes the other alternative products 

are not produced or used, so we would 

subtract the emissions of gasoline 

production and use, natural gas 

production and use, etc. This would 

show up as a GHG emission credit 

associated with the production of diesel 

fuel replacement. 

To account for the case where RINs 

are generated for the jet fuel, naphtha 

and LPG in addition to the diesel 

replacement fuel produced, we would 

not give the diesel replacement fuel a 

displacement credit for these coproducts. Instead, the lifecycle GHG 

emissions from the fuel production 

processes would be allocated to each of 

the RIN-generating products on an 

energy content basis. This has the effect 

of tending to increase the fuel 

production lifecycle GHG emissions 

associated with the diesel replacement 

fuel because there are less co-product 

displacement credits to assign than 

would be the case if RINs were not 

generated for the co-products.36 On the 

other hand, the upstream lifecycle GHG 

emissions associated with producing 

and transporting the plant oil feedstocks 

will be distributed over a larger group 

of RIN-generating products. Assuming 

each product (except propane) produced 

via the camelina oil hydrotreating 

process will generate RINs results in 

higher lifecycle GHG emissions for 

diesel fuel replacement as compared to 

the case where the co-products are not 

used to generate RINs. This general 

principle is also true when the 

hydrotreating process is maximized for 

jet fuel production. As a result, the 

worst GHG performance (i.e., greatest 

lifecycle GHG emissions) for diesel 

replacement fuel and jet fuel produced 

from camelina oil via hydrotreating will 

occur when all of the co-products are 

RIN-generating (we assume propane will 

be used for process energy). Thus, if 

these fuels meet the 50% GHG 

reduction threshold for biomass based 

diesel or advanced biofuel when coproducts are RIN-generating, they will 

also do so in the case when RINs are not 

generated for co-products. 

We have evaluated information about 

the lifecycle GHG emissions associated 

with the hydrotreating process which 

can be maximized for jet fuel or diesel 

replacement fuel production. Our 

evaluation considers information 

published in peer-reviewed journal 

articles and publicly available literature 

(Kalnes et al., 2010, Pearlson, M., N., 

2011,37 Stratton et al., 2010, Huo et al., 

2008 38). Our analysis of GHG emissions 

from the hydrotreating process is based 

on the mass and energy balance data in 

Pearlson (2011) which analyzes a 

hydrotreating process maximized for 

diesel replacement fuel production and 

a hydrotreating process maximized for 

jet fuel production.39 This data is 

summarized in Table 4. 

TABLE 4—HYDROTREATING PROCESSES TO CONVERT CAMELINA OIL INTO DIESEL REPLACEMENT FUEL AND JET FUEL40

Maximized 

for diesel 

fuel 

production 

Maximized 

for jet fuel 

production 

Units 

(per gallon of 

fuel 

produced) 

Inputs: 

Refined camelina oil ........................................................................................................... 9 .56 12 .84 Lbs. 

Hydrogen ............................................................................................................................. 0 .04 0 .08 Lbs. 

Electricity ............................................................................................................................. 652 865 Btu. 

Natural Gas ......................................................................................................................... 23,247 38,519 Btu. 

Outputs: 

Diesel Fuel .......................................................................................................................... 123,136 55,845 Btu. 

Jet fuel ................................................................................................................................ 23,197 118,669 Btu. 

Naphtha ............................................................................................................................... 3,306 17,042 Btu. 

LPG ..................................................................................................................................... 3,084 15,528 Btu. 

Propane ............................................................................................................................... 7,454 9,881 Btu. 

Table 5 compares lifecycle GHG 

emissions from oil extraction and fuel 

production for soybean oil biodiesel and 

for camelina-based diesel and jet fuel. 

The lifecycle GHG estimates for 

camelina oil diesel and jet fuel are based 

on the input/output data summarized in 

Table 3 (for oil extraction) and Table 4 

(for fuel production). We assume that 

the propane co-product does not 

generate RINs; instead, it is used for 

process energy displacing natural gas. 

We also assume that the naphtha is used 

as blendstock for production of 

transportation fuel to generate RINs. In 

this case we assume that RINs are 

generated for the use of LPG in a way 

that meets the EISA definition of 

transportation fuel, for example it could 

be used in a nonroad vehicle. The 

lifecycle GHG results in Table 5 

represent the worst case scenario (i.e., 

highest GHG emissions) because all of 

the eligible co-products are used to 

generate RINs. This is because, as 

discussed above, lifecycle GHG 

emissions per Btu of diesel or jet fuel 

would be lower if the naphtha or LPG 

is not used to generate RINs and is 

instead used for process energy 

displacing fossil fuel such as natural 

gas. Supporting information for the 

values in Table 5, including key 

assumptions and data, is provided 

through the docket.41 The key 

assumptions and data discussed in the 

docket include the emissions factors for 

natural gas, hydrogen and grid average 

electricity, and the energy allocation 

and displacement credits given to coproducts. These data and assumptions 

are based on the approach taken in the 

March 2010 RFS rule, as explained 

further below. 


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42Lifecycle 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. 

TABLE 5—FUEL PRODUCTION LIFECYCLE GHG EMISSIONS

[kgCO2e/mmBtu) 42

Feedstock Production process RIN-Generating 

products Other co-products Oil extraction Processing Total 

Soybean Oil ............... Trans-Esterification ... Biodiesel ................... Glycerin ..................... 14 (1 ) 13 

Camelina Oil .............. Trans-Esterification ... Biodiesel ................... Glycerin ..................... 4 (1 ) 3 

Camelina Oil .............. Hydrotreating Maximized for Diesel.Diesel ........................

Jet Fuel. 

Naphtha. 

Propane .................... 4 8 12 

LPG. 

Camelina Oil .............. Hydrotreating Maximized for Jet Fuel.Diesel Fuel ................

Jet Fuel. 

Naphtha. 

Propane .................... 4 11 14 

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 emissions per mmBtu from fuel 

processing. For example, based on the 

lifecycle GHG estimates in Table 5 for 

the hydrotreating process maximized to 

produce jet fuel, the jet fuel and the 

naphtha both have lifecycle GHG 

emissions of 14 kgCO2e/mmBtu. For the 

same reasons, the lifecycle GHG 

emissions from the jet fuel and naphtha 

will stay equivalent if we consider 

upstream GHG emissions, such as 

emissions associated with camelina 

cultivation and harvesting. Lifecycle 

GHG emissions from fuel distribution 

and use could be somewhat different for 

the jet fuel and naphtha, but since these 

stages produce a relatively small share 

of the emissions related to the full fuel 

lifecycle, the overall difference will be 

quite small. 

Given that GHG emissions from 

camelina oil would be similar to the 

GHG emissions from soybean oil at all 

stages of the lifecycle but would not 

result in land use change emissions (soy 

oil feedstock did have a significant land 

use change impact but still met a 50% 

GHG reduction threshold), and 

considering differences in process 

emissions between soybean biodiesel 

and camelina-based renewable diesel, 

we conclude that renewable diesel from 

camelina oil will also meet the 50% 

GHG emissions reduction threshold to 

qualify as biomass based diesel and 

advanced fuel. Although some of the 

potential configurations result in fuel 

production GHG emissions that are 

higher than fuel production GHG 

emissions for soybean oil biodiesel, land 

use change emissions account for 

approximately 80% of the soybean oil to 

biodiesel lifecycle GHGs. Since 

camelina is assumed not to have land 

use change emissions, our analysis 

shows that camelina renewable diesel 

will qualify for advanced renewable fuel 

and biomass-based diesel RINs even for 

the cases with the highest lifecycle 

GHGs (e.g., when all of the co-products 

are used to generate RINs.) Because the 

lifecycle GHG emissions for RINgenerating co-products are very similar, 

we can also conclude renewable 

gasoline blendstock and LPG produced 

from camelina oil will also meet the 

50% GHG emissions reduction 

threshold. If the facility does not 

actually generate RINs for one or more 

of these co-products, we estimate that 

the lifecycle GHG emissions related to 

the RIN-generating products would be 

lower, thus renewable diesel (which 

includes diesel fuel, jet fuel, and heating 

oil) from camelina would still meet the 

50% emission reduction threshold. 

4. Summary 

Current information suggests that 

camelina will be produced on land that 

would otherwise remain fallow. 

Therefore, increased production of 

camelina-based renewable fuel is not 

expected to result in significant land use 

change emissions; however, the agency 

will continue to monitor volumes 

through EMTS to verify this 

assumption. For the purposes of this 

analysis, EPA is projecting there will be 

no land use emissions associated with 

camelina production for use as a 

renewable fuel feedstock. 

However, while production of 

camelina on acres that would otherwise 

remain fallow is expected to be the 

primary means by which the majority of 

all camelina is commercially harvested 

in the short- to medium- term, in the 

long term camelina may expand to other 

growing methods and lands if demand 

increases substantially beyond what 

EPA is currently predicting. While the 

impacts are uncertain, there are some 

indications demand could increase 

significantly. For example, camelina is 

included under USDA’s Biomass Crop 

Assistance Program (BCAP) and there is 

growing support for the use of camelina 

oil in producing drop-in alternative 

aviation fuels. EPA plans to monitor, 

through EMTS and in collaboration with 

USDA, the expansion of camelina 

production to verify whether camelina 

is primarily grown on existing acres 

once camelina is produced at largerscale volumes. Similarly, we will 

consider market impacts if alternative 

uses for camelina expand significantly 

beyond what was described in the above 

analysis. Just as EPA plans to 

periodically review and revise the 

methodology and assumptions 

associated with calculating the GHG 

emissions from all renewable fuel 

feedstocks, EPA expects to review and 

revise as necessary the analysis of 

camelina in the future. 

Taking into account the assumption of 

no land use change emissions when 

camelina is used to produce renewable 

fuel, and considering that other sources 

of GHG emissions related to camelina 

biodiesel or renewable diesel 

production have comparable GHG 

emissions to biodiesel from soybean oil, 

we have determined that camelinabased 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 


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43The 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. 

44Comment 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. 

45See https://www.crops.org/publications/jpr/ 

abstracts/2/3/211?access=0&view=pdf and http:// 

www.cpact.embrapa.br/eventos/2010/ 

simposio_agroenergia/palestras/10_terca/Tarde/ 

USA/4%20%20%208-10- 

2010%20Cold%20Tolerance.pdf. 

camelina-based fuels will be at least as 

good and in some respects better than 

that modeled for fuels made from 

soybean oil. EPA found as part of the 

Renewable Fuel Standard final 

rulemaking that soybean biodiesel 

resulted in a 57% reduction in GHG 

emissions compared to the baseline 

petroleum diesel fuel. Furthermore, 

approximately 80% of the lifecycle 

impacts from soybean biodiesel were 

from land use change emissions which 

are assumed to be not significant for the 

camelina pathway considered. Thus, 

EPA is including camelina oil as a 

potential feedstock under the same 

biodiesel and renewable diesel (which 

includes diesel fuel, jet fuel, and heating 

oil) pathways for which soybean oil 

currently qualifies. We are also 

including a pathway for naphtha and 

LPG produced from camelina oil 

through hydrotreating. This is based on 

the fact that our analysis shows that 

even when all of the co-products are 

used to generate RINs the lifecycle GHG 

emissions for RIN-generating coproducts 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 coprocess renewable biomass and 

petroleum they can generate advanced 

biofuel RINs (D code 5) for the jet fuel 

produced. If they do not co-process 

renewable biomass and petroleum they 

can generate biomass-based diesel RINs 

(D code 4) for the jet fuel produced. 

§ 80.1401 of the RFS regulations 

currently defines non-ester renewable 

diesel as a fuel that is not a mono-alkyl 

ester and which can be used in an 

engine designed to operate on 

conventional diesel fuel or be heating 

oil or jet fuel. The reference to jet fuel 

in this definition was added by direct 

final rule dated May 10, 2010. Table 1 

to § 80.1426 identifies approved fuel 

pathways by fuel type, feedstock source 

and fuel production processes. The 

table, which was largely adopted as part 

of the March 26, 2010 RFS final rule, 

identifies jet fuel and renewable diesel 

as separate fuel types. Accordingly, in 

light of the revised definition of 

renewable diesel enacted after the RFS2 

rule, there is ambiguity regarding the 

extent to which references in Table 1 to 

‘‘renewable diesel’’ include jet fuel. 

The original lifecycle analysis for the 

renewable diesel from hydrotreating 

pathways listed in Table 1 to § 80.1426 

was not based on producing jet fuel but 

rather other transportation diesel fuel 

products, namely a diesel fuel 

replacement. As discussed above, the 

hydrotreating process can produce a 

mix of products including jet fuel, 

diesel, naphtha, LPG and propane. Also, 

as discussed, there are differences in the 

process configured for maximum jet fuel 

production vs. the process maximized 

for diesel fuel production and the 

lifecycle results vary depending on what 

approach is used to consider coproducts (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 coproducts produced. This is the case for 

most of the original feedstocks included 

in Table 1 to § 80.1426.43 As was 

discussed previously, if the 

displacement approach is used when jet 

fuel is the primary product produced it 

results in lower emissions than the 

production maximized for diesel fuel 

production. Therefore, since the 

hydrotreating process maximized for 

diesel fuel meets the 50% lifecycle GHG 

threshold for the feedstocks in question, 

the process maximized for jet fuel 

would also qualify. 

Thus, we are interpreting the 

references to ‘‘renewable diesel’’ in 

Table 1 to include jet fuel, consistent 

with our regulatory definition of ‘‘nonester renewable diesel,’’ since doing so 

clarifies the existing regulations while 

ensuring that Table 1 to § 80.1426 

appropriately identifies fuel pathways 

that meet the GHG reduction thresholds 

associated with each pathway. 

We note that although the definition 

of renewable diesel includes jet fuel and 

heating oil, we have also listed in Table 

1 of section 80.1426 of the RFS 

regulations jet fuel and heating oil as 

specific co-products in addition to 

listing renewable diesel to assure 

clarity. This clarification also pertains to 

all the feedstocks already included in 

Table 1 for renewable diesel. 

B. Lifecycle Greenhouse Gas Emissions 

Analysis for Ethanol, Diesel, Jet Fuel, 

Heating Oil, and Naphtha Produced 

From Energy Cane 

For this rulemaking, EPA considered 

the lifecycle GHG impacts of a new type 

of high-yielding perennial grass similar 

in cellulosic composition to switchgrass 

and comparable in status as an emerging 

energy crop. The grass considered in 

this rulemaking is energy cane, which is 

defined as a complex hybrid in the 

Saccharum genus that has been bred to 

maximize cellulosic rather than sugar 

content. 

As discussed above, in response to the 

proposed rule, EPA received comments 

highlighting the concern that by 

approving certain new feedstock types 

under the RFS program, EPA would be 

encouraging their introduction or 

expanded planting without considering 

their potential impact as invasive 

species.44

As described in the previous section 

on camelina, the information before us 

does not raise significant concerns about 

the threat of invasiveness and related 

GHG emissions for energy cane. Energy 

cane is generally a hybrid of Saccharum 

officinarum and Saccharum 

spontaneum, though other species such 

as Saccharum barberi and Saccharum 

sinense have been used in the 

development of new cultivars.45 Given 

the fact that S. spontaneum is listed on 

the Federal Noxious Weed List, this 

rulemaking does not allow for the 

inclusion of S. spontaneum in the 

definition of energy cane. However, 

hybrids derived from S. spontaneum 

that have been developed and publicly 

released by USDA are included in this 

definition of the energy cane feedstock. 

USDA’s Agricultural Research Service 

has developed strains of energy cane 

that strive to maximize fiber content and 

minimize invasive traits. Therefore, we 

believe that the production of cultivars 

of energy cane that were developed by 

USDA are unlikely to spread beyond the 

intended borders in which it is grown, 

which is consistent with the assumption 

in EPA’s lifecycle analysis that 

significant expenditures of energy or 

other sources of GHGs will not be 

required to remediate the spread of this 

feedstock from the specific locations 

where it is grown as a renewable fuel 


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46See 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. 

47See Hale, A.L. Sugar Bulletin, 2010, 88, 28–29. 

48These yields assume no significant adverse 

climate impacts on world agricultural yields over 

the analytical timeframe. 

feedstock for the RFS program. 

Therefore, we are finalizing the energy 

cane pathway in this rule based on our 

lifecycle analysis discussed below. 

In the proposed and final RFS rule, 

EPA analyzed the lifecycle GHG impacts 

of producing and using cellulosic 

ethanol and cellulosic Fischer-Tropsch 

diesel from switchgrass. The midpoint 

of the range of switchgrass results 

showed a 110% GHG reduction (range 

of 102%–117%) for cellulosic ethanol 

(biochemical process), a 72% (range of 

¥64% to ¥79%) reduction for 

cellulosic ethanol (thermochemical 

process), and a 71% (range of ¥62% to 

¥77%) reduction for cellulosic diesel 

(F–T process) compared to the 

petroleum baseline. In the RFS final 

rule, we indicated that some feedstock 

sources can be determined to be similar 

enough to those modeled that the 

modeled results could reasonably be 

extended to these similar feedstock 

types. For instance, information on 

miscanthus indicated that this perennial 

grass will yield more feedstock per acre 

than the modeled switchgrass feedstock 

without additional inputs with GHG 

implications (such as fertilizer). 

Therefore in the final rule EPA 

concluded that since biofuel made from 

the cellulosic biomass in switchgrass 

was found to satisfy the 60% GHG 

reduction threshold for cellulosic 

biofuel, biofuel produced from the 

cellulosic biomass in miscanthus would 

also comply. In the final rule we 

included cellulosic biomass from 

switchgrass and miscanthus as eligible 

feedstocks for the cellulosic biofuel 

pathways included in Table 1 to 

§ 80.1426. 

We did not include other perennial 

grasses such as energy cane as 

feedstocks for the cellulosic biofuel 

pathways in Table 1 at that time, since 

we did not have sufficient time to 

adequately consider them. Based in part 

on additional information received 

through the petition process for EPA 

approval of the energy cane pathway, 

EPA has evaluated energy cane and is 

now including it as a feedstock in Table 

1 to § 80.1426 as approved pathways for 

cellulosic biofuel pathways. 

As described in detail in the following 

sections of this preamble, because of the 

similarity of energy cane to switchgrass 

and miscanthus, and because crop 

production input emissions (e.g., diesel 

and pesticide emissions) are generally a 

small fraction of the overall lifecycle 

GHG emissions (representing 

approximately 1% of total emissions for 

switchgrass), EPA believes that new 

agricultural sector modeling is not 

needed to analyze energy cane. We have 

instead relied upon the switchgrass 

analysis to assess the relative GHG 

impacts of biofuel produced from 

energy cane. As with the switchgrass 

analysis, we have attributed all land use 

impacts and resource inputs from use of 

these feedstocks to the portion of the 

fuel produced that is derived from the 

cellulosic components of the feedstocks. 

Based on this analysis and currently 

available information, we conclude that 

biofuel (ethanol, cellulosic diesel, jet 

fuel, heating oil and naphtha) produced 

from the cellulosic biomass of energy 

cane has similar lifecycle GHG impacts 

to switchgrass biofuel and meets the 

60% GHG reduction threshold required 

for cellulosic biofuel. 

1. Feedstock Production and 

Distribution 

For the purposes of this rulemaking, 

energy cane refers to varieties of 

perennial grasses in the Saccharum 

genus which are intentionally bred for 

high cellulosic biomass productivity but 

have characteristically low sugar 

content making them less suitable as a 

primary source of sugar as compared to 

other varieties of grasses commonly 

known as ‘‘sugarcane’’ in the Saccharum 

genus. Energy cane varieties developed 

to date have low tolerance for cold 

temperatures but grow well in warm, 

humid climates. Energy cane originated 

from efforts to improve disease 

resistance and hardiness of commercial 

sugarcane by crossbreeding commercial 

and wild sugarcane strains. Certain 

higher fiber, lower sugar varieties that 

resulted were not suitable for 

commercial sugar production, and are 

now being developed as a high-biomass 

energy crop. There is currently no 

commercial production of energy cane. 

Current plantings are mainly limited to 

research field trials and small 

demonstrations for bioenergy purposes. 

However, based in part on discussions 

with industry, EPA anticipates 

continued development of energy cane 

particularly in the south-central and 

southeastern United States due to its 

high yields in these regions. 

a. Crop Yields 

For the purposes of analyzing the 

GHG emissions from energy cane 

production, EPA examined crop yields 

and production inputs in relation to 

switchgrass to assess the relative GHG 

impacts. Current national yields for 

switchgrass are approximately 4.5 to 5 

dry tons per acre. Average energy cane 

yields exceed switchgrass yields in both 

unfertilized and fertilized trails 

conducted in the southern United 

States. Unfertilized yields are around 

7.3 dry tons per acre while fertilized 

trials show energy cane yields range 

from approximately 11 to 20 dry tons 

per acre.46 47 Until recently there have 

been few efforts to improve energy cane 

yields, but several energy cane 

development programs are now 

underway to further increase its biomass 

productivity. In general, energy cane 

will have higher yields than 

switchgrass, so from a crop yield 

perspective, the switchgrass analysis 

would be a conservative estimate when 

comparing against the energy cane 

pathway. 

Furthermore, EPA’s analysis of 

switchgrass for the RFS rulemaking 

assumed a 2% annual increase in yield 

that would result in an average national 

yield of 6.6 dry tons per acre in 2022. 

EPA anticipates a similar yield 

improvement for energy cane due to 

their similarity as perennial grasses and 

their comparable status as energy crops 

in their early stages of development. 

Given this, our analysis assumes an 

average energy cane yield of 19 dry tons 

per acre in the southern United States 

by 2022.48 The ethanol yield for all of 

the grasses is approximately the same so 

the higher crop yields for energy cane 

result directly in greater ethanol 

production compared to switchgrass per 

acre of production. 

Based on these yield assumptions, in 

areas with suitable growing conditions, 

energy cane would require 

approximately 26% to 47% of the land 

area required by switchgrass to produce 

the same amount of biomass due to 

higher yields. Even without yield 

growth assumptions, the currently 

higher crop yield rates means the land 

use required for energy cane would be 

lower than for switchgrass. Therefore 

less crop area would be converted and 

displaced resulting in smaller land-use 

change GHG impacts than that assumed 

for switchgrass to produce the same 

amount of fuel. Furthermore, we believe 

energy cane will have a similar impact 

on international markets as assumed for 

switchgrass. Like switchgrass, energy 

cane is not expected to be traded 

internationally and its impacts on other 

crops are expected to be limited. 

b. Land Use 

In EPA’s March 2010 RFS analysis, 

switchgrass plantings displaced 

primarily soybeans and wheat, and to a 

lesser extent hay, rice, sorghum, and 

cotton. Energy cane, with production 

focused in the southern United States, is 


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49See Final Regulatory Impact Analysis Chapter 

2, February 2010. 

likely to be grown on land once used for 

pasture, rice, commercial sod, cotton or 

alfalfa, which would likely have less of 

an international indirect impact than 

switchgrass because some of those 

commodities are not as widely traded as 

soybeans or wheat. Given that energy 

cane will likely displace the least 

productive land first, EPA concludes 

that the land use GHG impact for energy 

cane per gallon should be no greater and 

likely less than estimated for 

switchgrass. 

Considering the total land potentially 

impacted by all the new feedstocks 

included in this rulemaking would not 

impact these conclusions (including the 

camelina discussed in the previous 

section and energy cane considered 

here). As discussed previously, the 

camelina is expected to be grown on 

fallow land in the Northwest, while 

energy cane is expected to be grown 

mainly in the south on existing 

cropland or pastureland. In the 

switchgrass ethanol scenario done for 

the Renewable Fuel Standard final 

rulemaking, total cropland acres 

increases by 4.2 million acres, including 

an increase of 12.5 million acres of 

switchgrass, a decrease of 4.3 million 

acres of soybeans, a 1.4 million acre 

decrease of wheat acres, a decrease of 1 

million acres of hay, as well as 

decreases in a variety of other crops. 

Given the higher yields of the energy 

cane considered here compared to 

switchgrass, there would be ample land 

available for production without having 

any adverse impacts beyond what was 

considered for switchgrass production. 

This analysis took into account the 

economic conditions such as input costs 

and commodity prices when evaluating 

the GHG and land use change impacts 

of switchgrass. 

One commenter stated that by 

assuming no land use change for energy 

cane and other feedstocks, the Agency 

may have underestimated the increase 

in GHG emissions that could result from 

breaking new land. According to the 

commenter, EPA assumed that these 

feedstocks will be grown on the least 

productive land without citing any 

specific models or studies. 

The commenter appears to have 

misinterpreted EPA’s analysis. EPA did 

not assume these crops would be grown 

on fallow acres, nor did EPA assume 

that switchgrass would only be 

produced on the least productive lands. 

EPA assumed these crops would be 

grown on acres similar to switchgrass, 

and therefore applied the land use 

change impacts of switchgrass analyzed 

in the final RFS rule. In the final RFS, 

EPA provided detailed information on 

the types of crops (e.g., wheat) that 

would be displaced by dedicated 

switchgrass. This analysis took into 

account the economic conditions such 

as input costs and commodity prices 

when evaluating the GHG and land use 

change impacts of switchgrass.49

c. Crop Inputs and Feedstock Transport 

EPA also assessed the GHG impacts 

associated with planting, harvesting, 

and transporting energy cane in 

comparison to switchgrass. Table 6 

shows the assumed 2022 commercialscale production inputs for switchgrass 

(used in the RFS rulemaking analysis), 

average energy cane production inputs 

(USDA projections and industry data) 

and the associated GHG emissions. 

Available data gathered by EPA 

suggest that energy cane requires on 

average less nitrogen, phosphorous, 

potassium, and pesticide than 

switchgrass per dry ton of biomass, but 

more herbicide, lime, diesel, and 

electricity per unit of biomass. 

This assessment assumes production 

of energy cane uses electricity for 

irrigation given that growers will likely 

irrigate when possible to improve 

yields. Irrigation rates will vary 

depending on the timing and amount of 

rainfall, but for the purpose of 

estimating GHG impacts of electricity 

use for irrigation, we assumed a rate 

similar to what we assumed for other 

irrigated crops in the Southwest, South 

Central, and Southeast as shown in 

Table 6. 

Applying the GHG emission factors 

used in the March 2010 RFS final rule, 

energy cane production results in 

slightly higher GHG emissions relative 

to switchgrass production (an increase 

of approximately 4 kg CO2eq/mmbtu). 


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GHG emissions associated with 

distributing energy cane are expected to 

be similar to EPA’s estimates for 

switchgrass feedstock because they are 

all herbaceous agricultural crops 

requiring similar transport, loading, 


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50The F–T diesel process modeled applies to 

cellulosic diesel, jet fuel, heating oil, and naphtha. 

unloading, and storage regimes. Our 

analysis therefore assumes the same 

GHG impact for feedstock distribution 

as we assumed for switchgrass, although 

distributing energy cane could be less 

GHG intensive because higher yields 

could translate to shorter overall 

hauling distances to storage or biofuel 

production facilities per gallon or Btu of 

final fuel produced. 

2. Fuel Production, Distribution, and 

Use 

Energy cane is suitable for the same 

conversion processes as other cellulosic 

feedstocks, such as switchgrass and corn 

stover. Currently available information 

on energy cane composition shows that 

hemicellulose, cellulose, and lignin 

content are comparable to other crops 

that qualify under the RFS regulations 

as feedstocks for the production of 

cellulosic biofuels. Based on this similar 

composition as well as conversion yield 

data provided by industry, we applied 

the same production processes that were 

modeled for switchgrass in the final RFS 

rule (biochemical ethanol, 

thermochemical ethanol, and FischerTropsch (F–T) diesel 50) to energy cane. 

We assumed the GHG emissions 

associated with producing biofuels from 

energy cane are similar to what we 

estimated for switchgrass and other 

cellulosic feedstocks. EPA also assumes 

that the distribution and use of biofuel 

made from energy cane will not differ 

significantly from similar biofuel 

produced from other cellulosic sources. 

As was done for the switchgrass case, 

this analysis assumes energy grasses 

grown in the United States for 

production purposes. If crops were 

grown internationally, used for biofuel 

production, and the fuel was shipped to 

the U.S., shipping the finished fuel to 

the U.S. could increase transport 

emissions. However, based on analysis 

of the increased transport emissions 

associated with sugarcane ethanol 

distribution to the U.S. considered for 

the 2010 final rule, this would at most 

add 1–2% to the overall lifecycle GHG 

impacts of the energy grasses. 

3. Summary 

Based on our comparison to 

switchgrass, EPA believes that cellulosic 

biofuel produced from the cellulose, 

hemicellulose and lignin portions of 

energy cane has similar or better 

lifecycle GHG impacts than biofuel 

produced from the cellulosic biomass 

from switchgrass. Our analysis suggests 

that energy cane has GHG impacts 

associated with growing and harvesting 

the feedstock that are similar to 

switchgrass. Emissions from growing 

and harvesting energy cane are 

approximately 4 kg CO2eq/mmBtu 

higher than switchgrass. These are small 

changes in the overall lifecycle, 

representing at most a 6% change in the 

energy grass lifecycle impacts in 

comparison to the petroleum fuel 

baseline. Furthermore, energy cane is 

expected to have similar or lower GHG 

emissions than switchgrass associated 

with other components of the biofuel 

lifecycle. 

Under a hypothetical worst case, if 

the calculated increases in growing and 

harvesting the new feedstocks are 

incorporated into the lifecycle GHG 

emissions calculated for switchgrass, 

and other lifecycle components are 

projected as having similar GHG 

impacts to switchgrass (including land 

use change associated with switchgrass 

production), the overall lifecycle GHG 

reductions for biofuel produced from 

energy cane still meet the 60% 

reduction threshold for cellulosic 

biofuel. We believe these are 

conservative estimates, as use of energy 

cane as a feedstock is expected to have 

smaller land-use GHG impacts than 

switchgrass, due to higher yields. The 

docket for this rule provides additional 

detail on the analysis of energy cane as 

a biofuel feedstock. 

Although this analysis assumes 

energy cane biofuels produced for sale 

and use in the United States will most 

likely come from domestically produced 

feedstock, we also intend for the 

approved pathways to cover energy cane 

from other countries. We do not expect 

incidental amounts of biofuels from 

feedstocks produced in other nations to 

impact our assessment that the average 

GHG emissions reductions will meet the 

threshold for qualifying as a cellulosic 

biofuel pathway. Moreover, those 

countries most likely to be exporting 

energy cane or biofuels produced from 

energy cane are likely to be major 

producers which typically use similar 

cultivars and farming techniques. 

Therefore, GHG emissions from 

producing biofuels with energy cane 

grown in other countries should be 

similar to the GHG emissions we 

estimated for U.S. energy cane, though 

they could be slightly higher or lower. 

For example, the renewable biomass 

provisions under the Energy 

Independence and Security Act as 

outlined in the March 2010 RFS final 

rule regulations, would preclude use of 

a crop as a feedstock for renewable fuel 

if it was gown on land that was a direct 

conversion of previously unfarmed land 

in other countries into cropland for 

energy grass-based renewable fuel 

production. Furthermore, any energy 

grass production on existing cropland 

internationally would not be expected 

to have land use impacts beyond what 

was considered for switchgrass 

production. Even if there were 

unexpected larger differences, EPA 

believes the small amounts of feedstock 

or fuel potentially coming from other 

countries will not impact our threshold 

analysis. 

Based on our assessment of 

switchgrass in the March 2010 RFS final 

rule and this comparison of GHG 

emissions from switchgrass and energy 

cane, we do not expect variations to be 

large enough to bring the overall GHG 

impact of fuel made from energy cane to 

come close to the 60% threshold for 

cellulosic biofuel. Therefore, EPA is 

including cellulosic biofuel produced 

from the cellulose, hemicelluloses and 

lignin portions of energy cane under the 

same pathways for which cellulosic 

biomass from switchgrass qualifies 

under the RFS final rule. 

C. Lifecycle Greenhouse Gas Emissions 

Analysis for Certain Renewable 

Gasoline and Renewable Gasoline 

Blendstocks Pathways 

In this rule, EPA is also adding 

pathways to Table 1 to § 80.1426 for the 

production of renewable gasoline and 

renewable gasoline blendstock using 

specified feedstocks, fuel production 

processes, and process energy sources. 

The feedstocks we considered are 

generally considered waste feedstocks 

such as crop residues or cellulosic 

components of separated yard waste. 

These feedstocks have been identified 

by the industry as the most likely 

feedstocks for use in making renewable 

gasoline or renewable gasoline 

blendstock in the near term due to their 

availability and low cost. Additionally, 

these feedstocks have already been 

analyzed by EPA as part of the RFS 

rulemaking for the production of other 

fuel types. Consequently, no new 

modeling is required and we rely on 

earlier assessments of feedstock 

production and distribution for 

assessing the likely lifecycle impact on 

renewable gasoline and renewable 

gasoline blendstock. We have also relied 

on the petroleum gasoline baseline 

assessment from the March 2010 RFS 

rule for estimating the fuel distribution 

and use GHG emissions impacts for 

renewable gasoline and renewable 

gasoline blendstock. Consequently, the 

only new analysis required is of the 

technologies for turning the feedstock 

into renewable gasoline and renewable 

gasoline blendstock. 


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51 Kinchin, Christopher. Catalytic Fast Pyrolysis 

with Upgrading to Gasoline and Diesel Blendstocks. 

National Renewable Energy Laboratory (NREL). 

2011. 

52Aden, Andy. Feedstock Considerations and 

Impacts on Biorefining. National Renewable Energy 

Laboratory (NREL). December 2009. The report 

indicates that woody biomass feedstocks generally 

have higher yields than crop residues or herbaceous 

grasses (∼6% higher yields). However the same 

lower yield was assumed for all as a conservatively 

low estimate. 53Results for feedstock distribution are 

aggregated along with fuel distribution and are 

reported in a later section, see conclusion section. 

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 March 2010 RFS 

rulemaking, FASOM and FAPRI 

modeling was performed to analyze the 

emissions impact of using corn stover as 

a biofuel feedstock and this modeling 

was extended to some additional 

feedstock sources considered similar to 

corn stover. This approach was used for 

crop residues, slash, pre-commercial 

thinnings, tree residue and cellulosic 

components of separated yard, food, and 

MSW. These feedstocks are all excess 

materials and thus, like corn stover, 

were determined to have little or no 

land use change GHG impacts. Their 

GHG emission impacts are mainly 

associated with collection, transport, 

and processing into biofuel. See the RFS 

rulemaking preamble for further 

discussion. We used the results of the 

corn stover modeling in this analysis to 

estimate the upper bound of agricultural 

sector impacts from the production of 

the various cellulosic feedstocks noted 

above. 

The agriculture sector modeling 

results for corn stover represents all of 

the direct and significant indirect 

emissions in the agriculture sector 

(feedstock production emissions) for a 

certain quantity of corn stover 

produced. For the March 2010 RFS 

rulemaking, this was roughly 62 million 

dry tons of corn stover to produce 5.7 

billion gallons of ethanol assuming 

biochemical fermentation to ethanol 

processing. We have calculated GHG 

emissions from feedstock production for 

that amount of corn stover. The GHG 

emissions were then divided by the total 

heating value of the fuel to get feedstock 

production emissions per mmBtu of 

fuel. In addition to the biochemical 

ethanol process, a similar analysis was 

completed for thermochemical ethanol 

and F–T diesel pathways as part of the 

RFS rulemaking. 

In this rulemaking we are analyzing 

renewable gasoline and renewable 

gasoline blendstock produced from corn 

stover (and, by extension, other waste 

feedstocks). The number of gallons of 

fuel produced from a ton of corn stover 

(modeled process yields) is specific to 

the process used to produce renewable 

fuel. EPA has adjusted the results of the 

earlier corn stover modeling to reflect 

the different process yields and heating 

value of renewable gasoline or 

renewable gasoline blendstock product. 

The results of this calculation are shown 

below in Table 7. 

We based our process yields and 

heating values for renewable gasoline 

and renewable gasoline blendstock on 

several process technologies 

representative of technologies 

anticipated to be used in producing 

these fuels. As discussed later in this 

section, there are four main types of fuel 

production technologies available for 

producing renewable gasoline. These 

four processes can be characterized as 

(1) thermochemical gasification, (2) 

catalytic pyrolysis and upgrading to 

renewable gasoline or renewable 

gasoline blendstock (‘‘catalytic pyrolysis 

and upgrading’’), (3) biochemical 

fermentation with upgrading to 

renewable gasoline or renewable 

gasoline blendstock via carboxylic acid 

(‘‘fermentation and upgrading’’), and (4) 

direct biochemical fermentation to 

renewable gasoline and renewable 

gasoline blendstock (‘‘direct 

fermentation’’). The thermochemical 

gasification process was modeled as part 

of the March 2010 RFS final rule, 

included as producing naptha via the F– 

T process. Our analysis of the catalytic 

pyrolysis process was based on the 

modeling work completed by the 

National Renewable Energy Laboratory 

(NREL) for this rule for a process to 

make renewable gasoline blendstock.51

The fermentation and upgrading process 

was modeled based on confidential 

business information (CBI) from 

industry for a unique process which 

uses biochemical conversion of 

cellulose to renewable gasoline via a 

carboxylic acid route. In addition, we 

have qualitatively assessed the direct 

fermentation to renewable gasoline 

process based on similarities to the 

biochemical ethanol process already 

analyzed as part of the March 2010 RFS 

rulemaking. The fuel production section 

below provides further discussion on 

extending the GHG emissions results of 

the biochemical ethanol fermentation 

process to a biochemical renewable 

gasoline or renewable gasoline 

blendstock fermentation process. In 

some cases, the available data sources 

included process yields for renewable 

gasoline or renewable gasoline 

blendstock produced from wood chips 

rather than corn stover which was 

specifically modeled as a feedstock in 

the RFS final rule. We believe that the 

process yields are not significantly 

impacted by the source of cellulosic 

material whether the cellulosic material 

comes from residue such as corn stover 

or wood material such as from tree 

residues. We made the simplifying 

assumption that one dry ton of wood 

feedstock produces the same volume of 

renewable gasoline or renewable 

gasoline blendstock as one dry ton of 

corn stover. We believe this is 

reasonable considering that the RFS 

rulemaking analyses for biochemical 

ethanol and thermochemical F–T diesel 

processes showed limited variation in 

process yields between different 

feedstocks for a given process 

technology.52 In addition, since the 

renewable gasoline and renewable 

gasoline blendstock pathways include 

feedstocks that were already considered 

as part of the RFS2 final rule, the 

existing feedstock lifecycle GHG 

impacts for distribution of corn stover 

were also applied to this analysis.53

Feedstock production emissions are 

shown in Table 7 below for corn stover. 

Corn stover feedstock production 

emissions are mainly a result of corn 

stover removal increasing the 

profitability of corn production 

(resulting in shifts in cropland and thus 

slight emission impacts) and also the 

need for additional fertilizer inputs to 

replace the nutrients lost when corn 

stover is removed. However, corn stover 

removal also has an emissions benefit as 

it encourages the use of no-till farming 

which results in the lowering of 

domestic land use change emissions. 

This change to no-till farming results in 

a negative value for domestic land use 

change emission impacts (see also Table 

13 below). For other waste feedstocks 

(e.g., tree residues and cellulosic 

components of separate yard, food, and 

MSW), the feedstock production 

emissions are even lower than the 

values shown for corn stover since the 


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Federal Register / Vol. 78, No. 43 / Tuesday, March 5, 2013 / Rules and Regulations 14207 

use of such feedstocks does not require 

land use changes or additional 

agricultural inputs. Therefore, we 

conclude that if the use of corn stover 

as a feedstock in the production of 

renewable gasoline and renewable 

gasoline blendstock yields lifecycle 

GHG emissions results for the resulting 

fuel that qualify it as cellulosic biofuel 

(i.e., it has at least a 60% lifecycle GHG 

reduction as compared to conventional 

fuel), then the use of other waste 

feedstocks with little or no land use 

change emissions will also result in 

renewable gasoline or renewable 

gasoline blendstock that qualifies as 

cellulosic biofuel. 

One commenter stated that the 

Agency assumed that using the corn 

stover for biofuels production would 

result in additional no-till farming 

without any evidence that the stover 

would actually be removed from notilled acres. This commenter feels that 

with recent increased profitability from 

corn production, farmers may actually 

increase tillage to reap high corn prices. 

This commenter urged the EPA to 

consider changes to soil carbon from the 

removal of corn stover as they may have 

an impact on the GHG score of this new 

biofuel pathway. This commenter 

further urged the Agency to not simply 

assume that additional no-till practices 

will be adopted with residue extraction. 

The analysis the EPA conducted to 

evaluate the GHG impacts associated 

with corn stover removal as part of the 

March 2010 RFS final rule did not 

assume that the corn stover had to be 

removed from no-till corn production. 

The models used to evaluate the 

impacts of stover removal included the 

option for farmers to switch to no-till 

practices and therefore have the option 

for more stover removal. As the demand 

for stover increased in the case where 

stover is used for biofuel production, 

the relative costs associated with no-till 

factored in the impact of lost corn yield 

as well as higher yield for corn stover. 

The model optimized the rate of returns 

for the farmers such that no-till 

practices were applied until the 

increased returns for greater stover 

removal on no-till acres were balanced 

by lost profits from lower corn yields. 

Therefore, the comment that we 

assumed stover had to come from no-till 

acres or that the economics would drive 

more intensive tillage practices is not 

accurate, as described in more detail in 

the March 2010 RFS final rule. 

Furthermore, there is an annual soil 

carbon penalty applied to crops with 

residue removal in our models. Thus, as 

one shifts from conventional corn to 

residue corn, an annual soil carbon 

penalty factor is applied. If residue 

removal is combined with switching to 

conservation tillage or no-till, then the 

net soil C effect would be the sum of the 

till change effect and the ‘‘crop change’’ 

effect. 

For the March 2010 RFS rulemaking, 

EPA conducted an in-depth literature 

review of corn stover removal practices 

and consulted with numerous experts in 

the field. In the FRM, EPA recognized 

that sustainable stover removal practices 

vary significantly based on local 

differences in soil and erosion 

conditions, soil type, landscape (slope), 

tillage practices, crop rotation 

managements, and the use of cover 

crops. EPA, in consultation with USDA, 

based its impacts on corn stover from 

reduced till and no till acres based on 

agronomical practices, nutrient 

requirements, and erosion 

considerations. EPA does not believe 

that the commentor has provided new 

information that would substantially 

change our analysis of the GHG 

emissions associated with corn stover. 

However, EPA will continue to monitor 

actual practices and based on new data 

will consider reviewing and revising the 

methodology and assumptions 

associated with calculating the GHG 

emissions from all renewable fuel 

feedstocks. 

TABLE 7—FEEDSTOCK PRODUCTION EMISSIONS FOR RENEWABLE GASOLINE AND RENEWABLE GASOLINE BLENDSTOCK

PATHWAYS USING CORN STOVER

Feedstock production 

emission sources 

Catalytic pyrolysis and 

upgrading to renewable 

gasoline and renewable 

gasoline blendstock (g 

CO2-eq./mmBtu) 

Biochemical fermentation and upgrading to renewable gasoline and 

renewable gasoline 

blendstock via carboxylic 

acid (g CO2-eq./mmBtu) 

Direct biochemical fermentation process to renewable gasoline and 

renewable gasoline 

blendstock (g CO2-eq./ 

mmBtu) 

Domestic Livestock ...................................................................... 7,648 6,770 ∼ 9,086 

Domestic Farm Inputs and Fertilizer N2O ................................... 1,397 1,237 ∼ 1,660 

Domestic Rice Methane .............................................................. 366 324 ∼ 434 

Domestic Land Use Change ....................................................... ¥9,124 ¥8,076 ∼¥10,820 

International Livestock ................................................................. 0 0 0 

International Farm Inputs and Fertilizer N2O .............................. 0 0 0 

International Rice Methane .......................................................... 0 0 0 

International Land Use Change ................................................... 0 0 0 

Total Feedstock Production Emissions: ............................... 287 254 ∼ 361 

Assumed yield (gal/ton of biomass) ............................................ 64.5 75 92.3 

The results in Table 7 differ for the 

different pathways considered because 

of the different amounts of corn stover 

used to produce the same amount of 

fuel in each case. Table 7 only considers 

the feedstock production impacts 

associated with the renewable gasoline 

or renewable gasoline blendstocks 

pathways, other aspects of the lifecycle 

are discussed in the following sections. 

2. Fuel Distribution 

A petroleum gasoline baseline was 

developed as part of the RFS final rule 

which included estimates for fuel 

distribution emissions. Since renewable 

gasoline and renewable gasoline 

blendstocks when blended into gasoline 

are similar to petroleum gasoline, it is 

reasonable to assume similar fuel 

distribution emissions. Therefore, the 

existing fuel distribution lifecycle GHG 

impacts of the petroleum gasoline 

baseline from the RFS final rule were 

applied to this analysis. 

3. Use of the Fuel 

A petroleum gasoline baseline was 

developed as part of the RFS final rule 

which estimated the tailpipe emissions 

from fuel combustion. Since renewable 

gasoline and renewable gasoline 

blendstock are similar to petroleum 

gasoline in energy and hydrocarbon 


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14208 Federal Register / Vol. 78, No. 43 / Tuesday, March 5, 2013 / Rules and Regulations 

54See http://www.epa.gov/otaq/fuels/ 

renewablefuels/compliancehelp/rfs2-lcapathways.htm for list of petitions received by EPA. 

55Regalbuto, John. ‘‘An NSF perspective on next 

generation hydrocarbon biorefineries,’’ Computers 

and Chemical Engineering 34 (2010) 1393–1396. 

February 2010. 56Serrano-Ruiz, J., Dumesic, James. ‘‘Catalytic 

routes for the conversion of biomass into liquid 

hydrocarbon transportation fuels,’’ Energy 

Environmental Science (2011) 4, 83–99. 

57 Kinchin, Christopher. Catalytic Fast Pyrolysis 

with Upgrading to Gasoline and Diesel Blendstocks. 

National Renewable Energy Laboratory (NREL). 

2011. 

content, the non-CO2 combustion 

emissions calculated as part of the RFS 

final rule for petroleum gasoline were 

applied to our analysis of the renewable 

gasoline and renewable gasoline 

blendstock pathways. Only non-CO2

emissions were included since carbon 

fluxes from land use change are 

accounted for as part of the biomass 

feedstock production. 

4. Fuel Production 

In the March 2010 RFS rulemaking, 

EPA analyzed several of the main 

cellulosic biofuel pathways: a 

biochemical fermentation process to 

ethanol and two thermochemical 

gasification processes, one producing 

mixed alcohols (primarily ethanol) and 

the other one producing mixed 

hydrocarbons (primarily diesel fuel). 

These pathways all exceeded the 60% 

lifecycle GHG threshold requirements 

for cellulosic biofuel using the specified 

feedstocks. Refer to the preamble and 

regulatory impact analysis (RIA) from 

the final rule for more details. From 

these analyses, it was determined that 

ethanol and diesel fuel produced from 

the specified cellulosic feedstocks and 

processes would be eligible for 

cellulosic and advanced biofuel RINs. 

The thermochemical gasification 

process to diesel fuel (via F–T synthesis) 

also produces a smaller portion of 

renewable gasoline blendstock. In the 

final rule, naphtha produced with 

specified cellulosic feedstocks by a F–T 

process was included as exceeding the 

60% lifecycle GHG threshold, with an 

applicable D–Code of 3, in Table 1 to 

§ 80.1426. In this rule, we are changing 

the reference to F–T as the process 

technology to the more correct reference 

as gasification technology since F–T 

reactions are only part of the process 

technology. 

Since the final March 2010 RFS rule 

was released, EPA has received several 

petitions and inquiries that suggest that 

renewable gasoline or renewable 

gasoline blendstock produced using 

processes other than the F–T process 

could also qualify for a similar D–Code 

of 3.54 For the reasons described below, 

we have decided to authorize the 

generation of RINs with a D code of 3 

for renewable gasoline and renewable 

gasoline blendstock produced using 

specified cellulosic feedstocks for the 

processes considered here. 

Several routes have been identified as 

available for the production of 

renewable gasoline and renewable 

gasoline blendstock from renewable 

biomass. These include catalytic 

pyrolysis and upgrading to renewable 

gasoline or renewable gasoline 

blendstock (‘‘catalytic pyrolysis and 

upgrading’’), biochemical fermentation 

with upgrading to renewable gasoline or 

renewable gasoline blendstock via 

carboxylic acid (‘‘fermentation and 

upgrading’’), and direct biochemical 

fermentation to renewable gasoline and 

renewable gasoline blendstock (‘‘direct 

fermentation’’) and other thermocatalytic hydrodeoxygenation routes 

with upgrading such as aqueous phase 

processing.55 56

Similar to how we analyzed several of 

the main routes for cellulosic ethanol 

and cellulosic diesel for the final March 

2010 RFS rule, we have chosen to 

analyze the main renewable gasoline 

and renewable gasoline blendstock 

pathways in order to estimate the 

potential GHG reduction profile for 

renewable gasoline and renewable 

gasoline blendstock across a range of 

other production technologies for which 

we are confident will have at least as 

great of GHG emission reductions as 

those specifically analyzed. 

a. Catalytic Pyrolysis With Upgrading to 

Renewable Gasoline and Renewable 

Gasoline Blendstock 

The first production process we 

investigated for this rule is a catalytic 

fast pyrolysis route to bio-oils with 

upgrading to a renewable gasoline or a 

renewable gasoline blendstock. We 

utilized process modeling results from 

the National Renewable Energy 

Laboratory (NREL). Information 

provided by industry and claimed as 

CBI are based on similar processing 

methods and suggest similar results 

than those reported by NREL. Details on 

the NREL modeling are described 

further in a technical report available 

through the docket.57 Catalytic pyrolysis 

involves the rapid heating of biomass to 

about 500°C at slightly above 

atmospheric pressure. The rapid heating 

thermally decomposes biomass, 

converting it into pyrolysis vapor, 

which is condensed into a liquid bio-oil. 

The liquid bio-oil can then be upgraded 

using conventional hydroprocessing 

technology and further separated into 

renewable gasoline, renewable gasoline 

blendstock and renewable diesel 

streams (cellulosic diesel from catalytic 

pyrolysis is already included as an 

acceptable pathway in the RFS 

program). Some industry sources also 

expect to produce smaller fractions of 

heating oil in addition to gasoline and 

diesel blendstocks. Excess electricity 

from the process is also accounted for in 

our modeling as a co-product credit in 

which any excess displaces U.S. average 

grid electricity. Excess electricity is 

generated from the use of co-product 

coke/char and product gases and is 

available because internal electricity 

demands are fully met. The estimated 

energy inputs and electricity credits 

shown in Table 8, below, utilize the 

data provided by the NREL process 

modeling. However, industry sources 

also identified potential areas for 

improvements in energy use, such as the 

use of biogas fired dryers instead of 

natural gas fired dryers for drying 

incoming wet feedstocks and increased 

turbine efficiencies for electricity 

production which may result in lower 

energy consumption than estimated by 

NREL and thus improve GHG 

performance compared to our estimates 

here. 

TABLE 8—2022 ENERGY USE AT CELLULOSIC BIOFUEL FACILITIES

[Btu/gal] 

Technology Biomass use Natural gas 

use 

Purchased 

electricity Sold electricity 

Catalytic Pyrolysis to Renewable Gasoline or Renewable Gasoline 

Blendstock .................................................................................................... 136,000 51,000 0 ¥2,000 


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Federal Register / Vol. 78, No. 43 / Tuesday, March 5, 2013 / Rules and Regulations 14209 

58A 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. 

59Hydrogen emissions are modeled as natural gas 

and electricity demands. 

The emissions from energy inputs 

were calculated by multiplying the 

amount of energy by emission factors for 

fuel production and combustion, based 

on the same method and factors used in 

the March 2010 RFS final rulemaking. 

The emission factors for the different 

fuel types are from GREET and were 

based on assumed carbon contents of 

the different process fuels. The 

emissions from producing electricity in 

the U.S. were also taken from GREET 

and represent average U.S. grid 

electricity production emissions. 

The major factors influencing the 

emissions from the fuel production 

stage of the catalytic pyrolysis pathway 

are the use of natural gas (mainly due 

to hydrogen production for 

hydroprocessing) and the co-products 

available for additional heat and power 

generation.58 See Table 9 for a summary 

of emissions from fuel production. 

TABLE 9—FUEL PRODUCTION EMISSIONS FOR CATALYTIC PYROLYSIS AND UPGRADING TO RENEWABLE GASOLINE OR

RENEWABLE GASOLINE BLENDSTOCK USING CORN STOVER

Lifecycle stage 

Catalytic pyrolysis to 

renewable gasoline or 

renewable gasoline 

blendstock 

(g CO2-eq./mmBtu) 

On-Site & Upstream Emissions (Natural Gas & Biomass*) ................................................................................................ 31,000 

Electricity Co-Product Credit ............................................................................................................................................... ¥3,000 

Total Fuel Production Emissions: ................................................................................................................................. 28,000 

* Only non-CO2 combustion emissions from biomass 

b. Catalytic Upgrading of 

Biochemically Derived Intermediates to 

Renewable Gasoline and Renewable 

Gasoline Blendstock 

The second production process we 

investigated is a biochemical 

fermentation process to intermediate, 

such as carboxylic acids with catalytic 

upgrading to renewable gasoline or 

renewable gasoline blendstock. This 

process involves the fermentation of 

biomass using microorganisms that 

produce a variety of carboxylic acids. If 

the feedstock has high lignin content, 

then the biomass is pretreated to 

enhance digestibility. The acids are then 

neutralized to carboxylate salts and 

further converted to ketones and 

alcohols for refining into gasoline, 

diesel, and jet fuel. 

The process requires the use of 

natural gas and hydrogen inputs.59 No 

purchased electricity is required as 

lignin is projected to be used to meet all 

facility demands as well as provide 

excess electricity to the grid. EPA used 

the estimated energy and material 

inputs along with emission factors to 

estimate the GHG emissions from this 

process. The energy inputs and 

electricity credits are shown in Table 

10, below. These inputs are based on 

Confidential Business Information (CBI), 

rounded to the nearest 1000 units, 

provided by industry as part of the 

petition process for new fuel pathways. 

TABLE 10—2022 ENERGY USE AT CELLULOSIC FACILITY

[Btu/gal] 

Technology Biomass use Natural gas 

use 

Purchased 

electricity Sold electricity 

Biochemical Fermentation to Renewable Gasoline or Renewable Gasoline 

Blendstock via Carboxylic Acid .................................................................... 49,000 59,000 0 ¥2,000 

The process also uses a small amount 

of buffer material as neutralizer which 

was not included in the GHG lifecycle 

results due to its likely negligible 

emissions impact. The GHG emissions 

estimates from the fuel production stage 

are seen in Table 11. 

TABLE 11—FUEL PRODUCTION EMISSIONS FOR BIOCHEMICAL FERMENTATION TO RENEWABLE GASOLINE OR RENEWABLE

GASOLINE BLENDSTOCK VIA CARBOXYLIC ACID USING CORN STOVER

Lifecycle stage GHG Emissions 

(g CO2-eq./mmBtu) 

On-Site & Upstream Emissions (Natural Gas & Biomass*) ................................................................................................ 33,000 

Electricity Co-Product Credit ............................................................................................................................................... ¥3,000 

Total Fuel Production Emissions: ........................................................................................................................................ 30,000 

* Only non-CO2 combustion emissions from biomass 


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14210 Federal Register / Vol. 78, No. 43 / Tuesday, March 5, 2013 / Rules and Regulations 

60Numbers do not add up due to rounding. 61Memorandum 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’’. 

c. Biological Conversion to Renewable 

Gasoline and Renewable Gasoline 

Blendstock 

The third production process we 

investigated involves the use of 

microorganisms to biologically convert 

sugars hydrolyzed from cellulose 

directly into hydrocarbons which could 

be either a complete fuel as renewable 

gasoline or a renewable gasoline 

blendstock. The process is similar to the 

biochemical fermentation to ethanol 

pathway modeled for the final rule with 

the major difference being the end fuel 

product, hydrocarbons instead of 

ethanol. Researchers believe that this 

new technology could achieve 

improvements over classical 

fermentation approaches because 

hydrocarbons generally separate 

spontaneously from the aqueous phase, 

thereby avoiding poisoning of microbes 

by the accumulated products and 

facilitating separation/collection of 

hydrocarbons from the reaction 

medium. In other words, some energy 

savings may result because fewer 

separation unit operations could be 

required for separating the final product 

from other reactants and there may be 

better conversion yields as the 

fermentation microorganisms are not 

poisoned when interacting with 

accumulated products. We also expect 

that the lignin/byproduct portions of the 

biomass from the fermentation to 

hydrocarbon process could be converted 

into heat and electricity for internal 

demands or for export, similar to the 

biochemical fermentation to ethanol 

pathway. 

Therefore, we can conservatively 

extend our final March 2010 RFS rule 

biochemical fermentation to ethanol 

process results to a similar (but likely 

slightly improved) process that instead 

produces hydrocarbons. Since the final 

rule cellulosic ethanol GHG results were 

well above the 60% GHG reduction 

threshold for cellulosic biofuels, if 

actual emissions from other necessary 

changes to the direct biochemical 

fermentation to hydrocarbons process 

represent some small increment in GHG 

emissions, the pathway would still 

likely meet the threshold. Table 12 is 

our qualitative assessment of the 

potential emissions reductions from a 

process using biochemical fermentation 

to cellulosic hydrocarbons assuming 

similarities to the biochemical 

fermentation to cellulosic ethanol route 

from the final rule. 

TABLE 12—FUEL PRODUCTION EMISSIONS FOR MARCH 2010 RFS CELLULOSIC BIOCHEMICAL ETHANOL COMPARED TO DIRECT BIOCHEMICAL FERMENTATION TO RENEWABLE GASOLINE OR RENEWABLE GASOLINE BLENDSTOCK USING CORN

STOVER

Lifecycle stage 

Cellulosic biochemical 

ethanol emissions 

(g CO2-eq./mmBtu) 

Direct biochemical 

fermentation to 

renewable gasoline 

and renewable 

gasoline blendstock 

emissions 

(g CO2-eq./mmBtu) 

On-Site Emissions & Upstream (biomass) .............................................................................. 3,000 < or = 3,000 

Electricity Co-Product Credit ................................................................................................... ¥35,000 = ¥35,000 

Total Fuel Production Emissions 60: ........................................................................................ ¥33,000 < or = ¥33,000 

Table 13 below breaks down by stage 

the lifecycle GHG emissionsfor the 

renewable gasoline and renewable 

gasoline blendstock pathways using 

corn stover and the 2005 petroleum 

baseline. The table demonstrates the 

contribution of each stage in the fuel 

pathway and its relative significance in 

terms of GHG emissions. These results 

are also presented in graphical form in 

a supplemental memorandum to the 

docket.61 As noted above, these analyses 

assume natural gas as the process energy 

when needed; using biogas as process 

energy would result in an even better 

lifecycle GHG impact. 

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 


emcdonald on DSK67QTVN1PROD with RULES
Federal Register / Vol. 78, No. 43 / Tuesday, March 5, 2013 / Rules and Regulations 14211 

62Regalbuto, John. ‘‘An NSF perspective on next 

generation hydrocarbon biorefineries,’’ Computers 

and Chemical Engineering 34 (2010) 1393–1396. 

February 2010. 

63Serrano-Ruiz, J., Dumesic, James. ‘‘Catalytic 

routes for the conversion of biomass into liquid 

hydrocarbon transportation fuels,’’ Energy 

Environmental Science (2011) 4, 83–99. 

64Our lifecycle analysis assumes that producers 

would use the same type of biomass as both the 

feedstock and the process energy. 65One 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. 

TABLE 13—LIFECYCLE GHG EMISSIONS FOR RENEWABLE GASOLINE AND RENEWABLE GASOLINE BLENDSTOCK PATHWAYS

USING CORN STOVER, 2022—Continued 

[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 

% Change from Baseline ................................................................................. ¥67% ¥65% ¥129% ........................

* Emissions included in fuel production stage. 

d. Extension of Modeling Results to 

Other Production Processes Producing 

Renewable Gasoline or Renewable 

Gasoline Blendstock 

In the March 2010 RFS rulemaking, 

we modeled the GHG emissions results 

from the biochemical fermentation 

process to ethanol, thermochemical 

gasification processes to mixed alcohols 

(primarily ethanol) and mixed 

hydrocarbons (primarily diesel fuel). We 

extended these modeled process results 

to apply when the biofuel was produced 

from ‘‘any’’ process. We determined that 

since we modeled multiple cellulosic 

biofuel processes and all were shown to 

exceed the 60% lifecycle GHG threshold 

requirements for cellulosic biofuel using 

the specified feedstocks its was 

reasonable to extend to other processes 

(e.g. additional thermo-catalytic 

hydrodeoxygenation routes with 

upgrading similar to pyrolysis and 

aqueous phase processing) that might 

develop as these would likely represent 

improvements over existing processes as 

the industry works to improve the 

economics of cellulosic biofuel 

production by, for example, reducing 

energy consumption and improving 

process yields. Similarly, this rule 

assesses multiple processes for the 

production of renewable gasoline and 

renewable gasoline blendstocks and all 

were shown to exceed the 60% lifecycle 

GHG threshold requirements for 

cellulosic biofuel using specified 

feedstocks. 

As was the case in our earlier 

rulemaking, a couple reasons in 

particular support extending our 

modeling results to other production 

process producing renewable gasoline 

or renewable gasoline blendstock from 

cellulosic feedstock. Under this rule we 

analyzed the core technologies most 

likely available through 2022 for 

production of renewable gasoline and 

renewable gasoline blendstock routes 

from cellulosic feedstock as shown in 

literature. 62 63 The two primary routes 

for renewable gasoline and renewable 

gasoline blendstock production from 

cellulosic feedstock can be classified as 

either thermochemical or biological. 

Each of these two major categories has 

two subcategories. The processes under 

the thermochemical category include: 

• Pyrolysis and Upgrading—in which 

cellulosic biomass is decomposed with 

temperature to bio-oils and requires 

further catalytic processing to produce a 

finished fuel 

• Gasification—in which cellulosic 

biomass is decomposed to syngas with 

further catalytic processing of methanol 

to gasoline or through Fischer-Tropsch 

(F–T) synthesis to gasoline 

The processes under the biochemical 

category include: 

• Biological conversion to 

hydrocarbons—requires the release of 

sugars from biomass and 

microorganisms to biologically convert 

sugars straight into hydrocarbons 

instead of alcohols 

• Catalytic upgrading of 

biochemically produced 

intermediates—requires the release of 

sugars from biomass and aqueous- or 

liquid-phase processing of sugars or 

biochemically produced intermediate 

products into hydrocarbons using solid 

catalysts, 

As part of the modeling effort here, as 

well as for the March 2010 RFS final 

rule, we have considered the lifecycle 

GHG impacts of the four possible 

production technologies mentioned 

above. The pyrolysis and upgrading, 

direct biological conversion, and 

catalytic upgrading of biochemically 

produced intermediates are considered 

in this rule and the gasification route 

was already included in the March 2010 

final rule. In all cases, the processes that 

we have considered meet the 60% 

lifecycle GHG reduction required for 

cellulosic biofuels. Furthermore, we 

believe that the results from our 

modeling would cover all the likely 

variations within these potential routes 

for producing renewable gasoline and 

renewable gasoline blendstock which 

also use natural gas, biogas or biomass 64

for process energy and that all such 

production variations would also meet 

the 60% lifecycle threshold.65

The main reason for this is that we 

believe that our energy input 

assumptions are reasonable at this time 

but probably in some cases are 

conservatively high for commercial 

scale cellulosic facilities. The cellulosic 

industry is in its early stages of 

development and many of the estimates 

of process technology GHG impacts is 

based on pre-commercial scale 

assessments and demonstration 

programs. Commercial scale cellulosic 

facilities will continue to make 

efficiency improvements over time to 

maximize their fuel products/coproducts 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 


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14212 Federal Register / Vol. 78, No. 43 / Tuesday, March 5, 2013 / Rules and Regulations 

66 Kinchin, Christopher. Catalytic Fast Pyrolysis 

with Upgrading to Gasoline and Diesel Blendstocks. 

National Renewable Energy Laboratory (NREL). 

2011. 

a sensitivity case where no electricity 

credit was given. We found that all of 

the routes analyzed would still pass the 

GHG threshold without an electricity 

credit, providing confidence that over 

the range of technology options, these 

process technologies will surely allow 

the cellulosic biofuel produced to 

exceed the threshold for cellulosic 

biofuel GHG performance. Without 

excess electricity production the 

catalytic pyrolysis pathway results in a 

65% lifecycle GHG reduction, the 

biochemical fermentation via carboxylic 

acid pathway results in a 62% lifecycle 

GHG reduction, and the direct 

biochemical fermentation pathway 

results in a 93% reduction in lifecycle 

GHG emissions compared to the 

petroleum fuel baseline. 

Additionally, while the final results 

reported in this rule include an 

electricity credit, this electricity credit 

is based on current technology for 

generating electricity; it is possible that 

over the next decade as cellulosic 

biofuel production matures, the 

efficiency with which electricity is 

generated at these facilities will also 

improve. Such efficiency improvements 

will tend to improve the GHG 

performance for cellulosic biofuel 

technologies in general including those 

used to produce renewable gasoline. 

Furthermore, industry has identified 

other areas for energy improvements 

which our current pathway analyses do 

not include. Therefore, the results we 

have come up with for the individual 

pathway types represent conservative 

estimates and any variations in the 

pathways considered are likely to result 

in greater GHG reductions than what is 

considered here. For example, the 

variation of the catalytic pyrolysis route 

considered here resulted in a 67% 

reduction in lifecycle GHG emissions 

compared to the petroleum baseline. 

However, as was mentioned this was 

based on data from our NREL modeling 

and industry CBI data indicated more 

efficient energy performance which, if 

realized, would improve GHG 

performance. Another area for 

improvement in this pathway could be 

the use of anaerobic digestion to treat 

organics in waste water. If the anaerobic 

digestion is on-site, then enough biogas 

could potentially be produced to replace 

all of the fossil natural gas used as fuel 

and about half the natural gas fed for 

hydrogen production.66 Thus, fossil 

natural gas consumption could be 

further minimized under certain 

scenarios. We believe that as 

commercial scale cellulosic facilities 

develop, more of these improvements 

will be made to maximize the use of all 

the biomass and waste byproducts 

available to bring the facility closer to 

energy self-sufficiency. These 

improvements could help to increase 

the economic profitability for cellulosic 

facilities where fossil energy inputs 

become costly to purchase. Therefore 

we can extend the modeling results for 

our pyrolysis route to all variations of 

this production technology which use 

natural gas, biogas or biomass for 

production energy for producing 

renewable gasoline or renewable 

gasoline blendstock. 

The F–T gasification technology route 

considered as part of the March 2010 

RFS final rule resulted in an 

approximately 91% reduction in 

lifecycle GHG emissions compared to 

the petroleum baseline. This could be 

considered a conservatively high 

estimate as the process did not assume 

any excess electricity production, which 

as mentioned above could lead to 

additional GHG reductions. The F–T 

process involves gasifying biomass into 

syngas (mix of H2 and CO) and then 

converting the syngas through a 

catalytic process into a hydrocarbon mix 

that is further refined into finished 

product. The F–T process considered 

was based on producing both gasoline 

and diesel fuel so that it was not 

optimized for renewable gasoline 

production. A process for producing 

primarily renewable gasoline rather 

than diesel from a gasification route 

should not result in a significantly 

worse GHG impacts compared to the 

mixed fuel process analyzed. 

Furthermore, as the lifecycle GHG 

reduction from the F–T process 

considered was around 91%, there is 

considerable room for variations in this 

route to still meet the 60% lifecycle 

GHG reduction threshold for cellulosic 

fuels. Therefore, in addition to the F–T 

process originally analyzed for 

producing naphtha, we can extend the 

results based on the above analyses to 

include all variations of the gasification 

route which use natural gas, biogas or 

biomass for production energy for 

producing renewable gasoline or 

renewable gasoline blendstock. These 

variations include for example different 

catalysts and different refining 

processes to produce different mixes of 

final fuel product. While the current 

Table 1 entry in the regulations does not 

specify process energy sources, we are 

adding these specific eligible energy 

sources since we have not analyzed 

other energy sources (e.g., coal) as also 

allowing the pathway to meet the GHG 

performance threshold. 

There is an even wider gap between 

the results modeled for the direct 

fermentation route and the cellulosic 

lifecycle GHG threshold. The variation 

we considered for the direct 

fermentation process resulted in an 

approximately 129% reduction in 

lifecycle GHG emissions compared to 

the petroleum baseline. This process did 

consider production of electricity as 

part of the process but as mentioned 

even if this was not the case the 

pathway would still easily fall below 

the 60% lifecycle threshold for 

cellulosic biofuels. If actual emissions 

from other necessary changes to the 

direct biochemical fermentation to 

hydrocarbons process represent some 

small increment in GHG emissions, the 

pathway would still likely meet the 

threshold. Therefore, we can extend the 

results to all variations of the direct 

biochemical route for renewable 

gasoline or renewable gasoline 

blendstock production which use 

natural gas, biogas or biomass for 

production energy. 

The biochemical with catalytic 

upgrading route that we evaluated 

resulted in a 65% reduction in GHG 

emissions compared to the petroleum 

baseline. However, this can be 

considered a conservatively high 

estimate. For instance, the biochemical 

fermentation to gasoline via carboxylic 

acid route considered did not include 

the potential for generating steam from 

the combustion of undigested biomass 

and then using this steam for process 

energy. If this had been included, 

natural gas consumption could 

potentially be decreased which would 

lower the potential GHG emissions 

estimated from the process. Therefore, 

the scenario analyzed could be 

considered conservative in estimating 

actual natural gas usage. As was the case 

with the pyrolysis route considered, we 

believe that as commercial scale 

cellulosic facilities develop, 

improvements will be made to 

maximize the use of all the biomass and 

waste byproducts available to bring the 

facility closer to energy self-sufficiency. 

These improvements help to increase 

the economic profitability for cellulosic 

facilities where fossil energy inputs 

become costly to purchase. The 

processes we analyzed for this 

rulemaking utilized a mix of natural gas 

and biomass for process energy, with 

biogas replacing natural gas providing 

improved GHG performance. We have 

not analyzed other fuel types (e.g., coal) 

and are therefore not approving 

processes that utilized other fuel 

sources at this point. Therefore, we are 


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Federal Register / Vol. 78, No. 43 / Tuesday, March 5, 2013 / Rules and Regulations 14213 

extending our results to include all 

variations of the biochemical with 

catalytic upgrading process utilizing 

natural gas, biogas or biomass for 

process energy. 

While actual cellulosic facilities may 

show some modifications to the process 

scenarios we have already analyzed, our 

results give a good indication of the 

range of emissions we could expect 

from processes producing renewable 

gasoline and renewable gasoline 

blendstock from cellulosic feedstock, all 

of which meet the 60% cellulosic 

biofuel threshold (assuming they are 

utilizing natural gas, biogas or biomass 

for process energy). Technology changes 

in the future are likely to increase 

efficiency to maximize profits, while 

also lowering lifecycle GHG emissions. 

Therefore, we have concluded that since 

all of the renewable gasoline or 

renewable gasoline blendstock fuel 

processing methods we have analyzed 

exceed the 60% threshold using specific 

cellulosic feedstock types, we can 

conclude that processes producing 

renewable gasoline or renewable 

gasoline blendstock that fit within the 

categories of process analyzed here and 

are produced from the same feedstock 

types and using natural gas, biogas or 

biomass for process energy use will also 

meet the 60% GHG reduction threshold. 

In addition, while other technologies 

may develop, we expect that they will 

only become commercially competitive 

if they have better yields (more gallons 

per ton of feedstock) or lower 

production costs due to lower energy 

consumption. Both of these factors 

would suggest better GHG performance. 

This would certainly be the case if such 

processes also relied upon using biogas 

and/or biomass as the primary energy 

source. Therefore based on our review 

of the existing primary cellulosic biofuel 

production processes, likely GHG 

emission improvements for existing or 

new technologies, and consideration of 

the positive GHG emissions benefits 

associated with using biogas and/or 

biomass for process energy, we are 

approving for cellulosic RIN generation 

any process for renewable gasoline and 

renewable gasoline blendstock 

production using specified cellulosic 

biomass feedstocks as long as the 

process utilizes biogas and/or biomass 

for all process energy. 

5. Summary 

Three renewable gasoline and 

renewable gasoline blendstock 

pathways were compared to baseline 

petroleum gasoline, using the same 

value for baseline gasoline as in the 

March 2010 RFS final rule analysis. The 

results of the analysis indicate that the 

renewable gasoline and renewable 

gasoline blendstock pathways result in 

a GHG emissions reduction of 65–129% 

or better compared to the gasoline fuel 

it would replace using corn stover as a 

feedstock. The renewable gasoline and 

renewable gasoline blendstock 

pathways which use corn stover as a 

feedstock all exceed the 60% lifecycle 

GHG threshold requirements for 

cellulosic biofuel, these pathways 

capture the likely current technologies, 

and future technology improvements are 

likely to increase efficiency and lower 

GHG emissions. Therefore we have 

determined that all processes producing 

renewable gasoline or renewable 

gasoline blendstock from corn stover 

can qualify if they fall in the following 

process characterizations: 

• Catalytic pyrolysis and upgrading 

utilizing natural gas, biogas, and/or 

biomass as the only process energy 

sources 

• Gasification and upgrading utilizing 

natural gas, biogas, and/or biomass as 

the only process energy sources 

• Thermo-catalytic 

hydrodeoxygenation processes such as 

aqueous phase processing with 

upgrading sufficiently similar to 

pyrolysis and gasification 

• Direct fermentation utilizing natural 

gas, biogas, and/or biomass as the only 

process energy sources 

• Fermentation and upgrading 

utilizing natural gas, biogas, and/or 

biomass as the only process energy 

sources 

• Any process utilizing biogas and/or 

biomass as the only process energy 

sources. 

As was the case for extending corn 

stover results to other feedstocks in the 

March 2010 RFS final rule, these results 

are also reasonably extended to 

feedstocks with similar or lower GHG 

emissions profiles, including the 

following feedstocks: 

• Cellulosic biomass from crop 

residue, slash, pre-commercial 

thinnings and tree residue, annual cover 

crops; 

• Cellulosic components of separated 

yard waste; 

• Cellulosic components of separated 

food waste; and 

• Cellulosic components of separated 

MSW 

For more information on the 

reasoning for extension to these other 

feedstocks refer to the feedstock 

production and distribution section or 

the March 2010 RFS rulemaking (75 FR 

14670). 

Based on these results, today’s rule 

includes pathways for the generation of 

cellulosic biofuel RINs for renewable 

gasoline or renewable gasoline 

blendstock produced by catalytic 

pyrolysis and upgrading, gasification 

and upgrading, other similar thermocatalytic hydrodeoxygenation routes 

with upgrading, direct fermentation, 

fermentation and upgrading, all 

utilizing natural gas, biogas, and/or 

biomass as the only process energy 

sources or any process utilizing biogas 

and/or biomass as the only energy 

sources, and using corn stover as a 

feedstock or the feedstocks noted above. 

In order to qualify for RIN generation, 

the fuel must meet the other definitional 

criteria for renewable fuel (e.g., 

produced from renewable biomass, and 

used to reduce or replace petroleumbased transportation fuel, heating oil or 

jet fuel) specified in the Clean Air Act 

and the RFS regulations. 

A manufacturer of a renewable motor 

vehicle gasoline (including parties using 

a renewable blendstock obtained from 

another party), must satisfy EPA motor 

vehicle registration requirements in 40 

CFR part 79 for the fuel to be used as 

a transportation fuel. Per 40 CFR 

79.56(e)(3)(i), a renewable motor vehicle 

gasoline would be in the Non-Baseline 

Gasoline category or the Atypical 

Gasoline category (depending on its 

properties) since it is not derived only 

from conventional petroleum, heavy oil 

deposits, coal, tar sands and/or oil sands 

(40 CFR 79.56(e)(3)(i)(5)). In either case, 

the Tier 1 requirements at 40 CFR 79.52 

(emissions characterization) and the 

Tier 2 requirements at 40 CFR 79.53 

(animal exposure) are conditions for 

registration unless the manufacturer 

qualifies for a small business provision 

at 40 CFR 79.58(d). For a non-baseline 

gasoline, a manufacturer under $50 

million in annual revenue is exempt 

from Tier 1 and Tier 2. For an atypical 

gasoline there is no exemption from Tier 

1, but a manufacturer under $10 million 

in annual revenue is exempt from Tier 

2. 

Registration for a motor vehicle 

gasoline at 40 CFR 79 is via EPA Form 

3520–12, Fuel Manufacturer 

Notification for Motor Vehicle Fuel, 

available at: http://www.epa.gov/otaq/ 

regs/fuels/ffarsfrms.htm. 

D. Esterification Production Process 

Inclusion for Specified Feedstocks 

Producing Biodiesel 

The Agency is not taking final action 

at this time on its proposed inclusion of 

the process ‘‘esterification’’ as an 

approved biodiesel production process 

in Table 1 to § 40 CFR 80.1426. See 77 

FR 465. We continue to evaluate the 

issue and anticipate issuing a final 

determination as part of a subsequent 

rulemaking. 


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14214 Federal Register / Vol. 78, No. 43 / Tuesday, March 5, 2013 / Rules and Regulations 

III. Additional Changes to Listing of 

Available Pathways in Table 1 of 

80.1426 

We are also finalizing two changes to 

Table 1 to 80.1426 that were proposed 

on July 1, 2011(76 FR 38844). The first 

change adds ID letters to pathways to 

facilitate references to specific 

pathways. The second change adds 

‘‘rapeseed’’ to the existing pathway for 

renewable fuel made from canola oil. 

On September 28, 2010, EPA 

published a ‘‘Supplemental 

Determination for Renewable Fuels 

Produced Under the Final RFS2 

Program from Canola Oil’’ (75 FR 

59622). In the July 1, 2011 NPRM (76 FR 

38844) we proposed to clarify two 

aspects of the supplemental 

determination. First we proposed to 

amend the regulatory language in Table 

1 to § 80.1426 to clarify that the 

currently-approved pathway for canola 

also applies more generally to rapeseed. 

While ‘‘canola’’ was specifically 

described as the feedstock evaluated in 

the supplemental determination, we had 

not intended the supplemental 

determination to cover just those 

varieties or sources of rapeseed that are 

identified as canola, but to all rapeseed. 

As described in the July 1, 2011 NPRM, 

we currently interpret the reference to 

‘‘canola’’ in Table 1 to § 80.1426 to 

include any rapeseed. To eliminate 

ambiguity caused by the current 

language, however, we proposed to 

replace the term ‘‘canola’’ in that table 

with the term ‘‘canola/rapeseed’’. 

Canola is a type of rapeseed. While the 

term ‘‘canola’’ is often used in the 

American continent and in Australia, 

the term ‘‘rapeseed’’ is often used in 

Europe and other countries to describe 

the same crop. We received no adverse 

comments on our proposal, and are 

finalizing it as proposed. This change 

will enhance the clarity of the 

regulations regarding the feedstocks that 

qualify under the approved canola 

biodiesel pathway. 

Second, we wish to clarify that 

although the GHG emissions of 

producing fuels from canola feedstock 

grown in the U.S. and Canada was 

specifically modeled as the most likely 

source of canola (or rapeseed) oil used 

for biodiesel produced for sale and use 

in the U.S., we also intended that the 

approved pathway cover canola/ 

rapeseed oil from other countries, and 

we interpret our regulations in that 

manner. We expect the vast majority of 

biodiesel used in the U.S. and produced 

from canola/rapeseed oil will come from 

U.S. and Canadian crops. Incidental 

amounts from crops produced in other 

nations will not impact our average 

GHG emissions for two reasons. First, 

our analyses considered world-wide 

impacts and thus considered canola/ 

rapeseed crop production in other 

countries. Second, other countries most 

likely to be exporting canola/rapeseed 

or biodiesel product from canola/ 

rapeseed are likely to be major 

producers which typically use similar 

cultivars and farming techniques. 

Therefore, GHG emissions from 

producing biodiesel with canola/ 

rapeseed grown in other countries 

should be very similar to the GHG 

emissions we modeled for Canadian and 

U.S. canola, though they could be 

slightly (and insignificantly) higher or 

lower. At any rate, even if there were 

unexpected larger differences, EPA 

believes the small amounts of feedstock 

or fuel potentially coming from other 

countries will not impact our threshold 

analysis. Therefore, EPA interprets the 

approved canola pathway as covering 

canola/rapeseed regardless of country of 

origin. 

We are also correcting an inadvertent 

omission to the proposal which 

incorrectly did not include a pathway 

for producing naphtha from switchgrass 

and miscanthus; this pathway was 

included in the original March 2010 

RFS final rule. This pathway also 

incorporates the additional energy grass 

feedstock sources being added today, 

namely energy cane. 

IV. Statutory and Executive Order 

Reviews 

A. Executive Order 12866: Regulatory 

Planning and Review and Executive 

Order 13563: Improving Regulation and 

Regulatory Review 

Under Executive Order 12866 (58 FR 

51735, October 4, 1993), this action is a 

‘‘significant regulatory action.’’ 

Accordingly, EPA submitted this action 

to the Office of Management and Budget 

(OMB) for review under Executive 

Orders 12866 and 13563 (76 FR 3821, 

January 21, 2011) and any changes made 

in response to OMB recommendations 

have been documented in the docket for 

this action. 

B. Paperwork Reduction Act 

This action does not impose any new 

information collection burden. The 

corrections, clarifications, and 

modifications to the final March 2010 

RFS regulations contained in this rule 

are within the scope of the information 

collection requirements submitted to the 

Office of Management and Budget 

(OMB) for the final March 2010 RFS 

regulations. 

OMB has approved the information 

collection requirements contained in the 

existing regulations at 40 CFR part 80, 

subpart M under the provisions of the 

Paperwork Reduction Act, 44 U.S.C. 

3501 et seq. and has assigned OMB 

control numbers 2060– 0637 and 2060– 

0640. The OMB control numbers for 

EPA’s regulations in 40 CFR are listed 

in 40 CFR part 9. 

C. Regulatory Flexibility Act 

The Regulatory Flexibility Act (RFA) 

generally requires an agency to prepare 

a regulatory flexibility analysis of any 

rule subject to notice and comment 

rulemaking requirements under the 

Administrative Procedure Act or any 

other statute unless the agency certifies 

that the rule will not have a significant 

economic impact on a substantial 

number of small entities. Small entities 

include small businesses, small 

organizations, and small governmental 

jurisdictions. 

For purposes of assessing the impacts 

of today’s rule on small entities, small 

entity is defined as: (1) A small business 

as defined by the Small Business 

Administration’s (SBA) regulations at 13 

CFR 121.201; (2) a small governmental 

jurisdiction that is a government of a 

city, county, town, school district or 

special district with a population of less 

than 50,000; and (3) a small 

organization that is any not-for-profit 

enterprise which is independently 

owned and operated and is not 

dominant in its field. 

After considering the economic 

impacts of this action on small entities, 

I certify that this rule will not have a 

significant economic impact on a 

substantial number of small entities. 

This rule will not impose any new 

requirements on small entities. The 

relatively minor corrections and 

modifications this rule makes to the 

final March 2010 RFS regulations do not 

impact small entities. 

D. Unfunded Mandates Reform Act 

This rule does not contain a Federal 

mandate that may result in expenditures 

of $100 million or more for State, local, 

and tribal governments, in the aggregate, 

or the private sector in any one year. We 

have determined that this action will 

not result in expenditures of $100 

million or more for the above parties 

and thus, this rule is not subject to the 

requirements of sections 202 or 205 of 

UMRA. 

This rule is also not subject to the 

requirements of section 203 of UMRA 

because it contains no regulatory 

requirements that might significantly or 

uniquely affect small governments. It 

only applies to gasoline, diesel, and 

renewable fuel producers, importers, 

distributors and marketers and makes 


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Federal Register / Vol. 78, No. 43 / Tuesday, March 5, 2013 / Rules and Regulations 14215 

relatively minor corrections and 

modifications to the RFS regulations. 

E. Executive Order 13132 (Federalism) 

This action does not have federalism 

implications. It will not have substantial 

direct effects on the States, on the 

relationship between the national 

government and the States, or on the 

distribution of power and 

responsibilities among the various 

levels of government, as specified in 

Executive Order 13132. This action only 

applies to gasoline, diesel, and 

renewable fuel producers, importers, 

distributors and marketers and makes 

relatively minor corrections and 

modifications to the RFS regulations. 

Thus, Executive Order 13132 does not 

apply to this action. 

F. Executive Order 13175 (Consultation 

and Coordination With Indian Tribal 

Governments) 

This rule does not have tribal 

implications, as specified in Executive 

Order 13175 (65 FR 67249, November 9, 

2000). It applies to gasoline, diesel, and 

renewable fuel producers, importers, 

distributors and marketers. This action 

makes relatively minor corrections and 

modifications to the RFS regulations, 

and does not impose any enforceable 

duties on communities of Indian tribal 

governments. Thus, Executive Order 

13175 does not apply to this action. 

G. Executive Order 13045: Protection of 

Children From Environmental Health 

Risks and Safety Risks 

EPA interprets EO 13045 (62 FR 

19885, April 23, 1997) as applying only 

to those regulatory actions that concern 

health or safety risks, such that the 

analysis required under section 5–501 of 

the EO has the potential to influence the 

regulation. This action is not subject to 

EO 13045 because it does not establish 

an environmental standard intended to 

mitigate health or safety risks. 

H. Executive Order 13211: Actions 

Concerning Regulations That 

Significantly Affect Energy Supply, 

Distribution, or Use 

This action is not a ‘‘significant 

energy action’’ as defined in Executive 

Order 13211 (66 FR 28355 (May 22, 

2001)), because it is not likely to have 

a significant adverse effect on the 

supply, distribution, or use of energy. 

This rulemaking does not change any 

programmatic structural component of 

the RFS regulatory requirements. This 

rulemaking does not add any new 

requirements for obligated parties under 

the program or mandate the use of any 

of the new pathways contained in the 

rule. This rulemaking only makes a 

determination to qualify new fuel 

pathways under the RFS regulations, 

creating further opportunity and 

flexibility for compliance with the 

Energy Independence and Security Act 

of 2007 (EISA) mandates. 

I. National Technology Transfer and 

Advancement Act 

Section 12(d) of the National 

Technology Transfer and Advancement 

Act of 1995 (‘‘NTTAA’’), Public Law 

104–113, 12(d) (15 U.S.C. 272 note) 

directs EPA to use voluntary consensus 

standards in its regulatory activities 

unless to do so would be inconsistent 

with applicable law or otherwise 

impractical. Voluntary consensus 

standards are technical standards (e.g., 

materials specifications, test methods, 

sampling procedures, and business 

practices) that are developed or adopted 

by voluntary consensus standards 

bodies. NTTAA directs EPA to provide 

Congress, through OMB, explanations 

when the Agency decides not to use 

available and applicable voluntary 

consensus standards. 

This action does not involve technical 

standards. Therefore, EPA did not 

consider the use of any voluntary 

consensus standards. 

J. Executive Order 12898: Federal 

Actions To Address Environmental 

Justice in Minority Populations and 

Low-Income Populations 

Executive Order (EO) 12898 (59 FR 

7629 (Feb. 16, 1994)) establishes Federal 

executive policy on environmental 

justice. Its main provision directs 

Federal agencies, to the greatest extent 

practicable and permitted by law, to 

make environmental justice part of their 

mission by identifying and addressing, 

as appropriate, disproportionately high 

and adverse human health or 

environmental effects of their programs, 

policies, and activities on minority 

populations and low-income 

populations in the United States. 

EPA has determined that this rule will 

not have disproportionately high and 

adverse human health or environmental 

effects on minority or low-income 

populations because it does not affect 

the level of protection provided to 

human health or the environment. 

These amendments would not relax the 

control measures on sources regulated 

by the RFS regulations and therefore 

would not cause emissions increases 

from these sources. 

K. Congressional Review Act 

The Congressional Review Act, 5 

U.S.C. 801 et seq., as added by the Small 

Business Regulatory Enforcement 

Fairness Act of 1996, generally provides 

that before a rule may take effect, the 

agency promulgating the rule must 

submit a rule report, which includes a 

copy of the rule, to each House of the 

Congress and to the Comptroller General 

of the United States. A major rule 

cannot take effect until 60 days after it 

is published in the Federal Register. 

EPA will submit a report containing this 

rule and other required information to 

the U.S. Senate, the U.S. House of 

Representatives, and the Comptroller 

General of the United States prior to 

publication of the rule the Federal 

Register. This action is not a ‘‘major 

rule’’ as defined by 5 U.S.C. 804(2). 

V. Statutory Provisions and Legal 

Authority 

Statutory authority for the rule 

finalized today can be found in section 

211 of the Clean Air Act, 42 U.S.C. 

7545. Additional support for today’s 

rule comes from Section 301(a) of the 

Clean Air Act, 42 U.S.C. 7414, 7542, and 

7601(a). 

List of Subjects in 40 CFR Part 80 

Environmental protection, 

Administrative practice and procedure, 

Agriculture, Air pollution control, 

Confidential business information, 

Diesel Fuel, Energy, Forest and Forest 

Products, Fuel additives, Gasoline, 

Imports, Labeling, Motor vehicle 

pollution, Penalties, Petroleum, 

Reporting and recordkeeping 

requirements. 

Dated: February 22, 2013. 

Bob Perciasepe, 

Acting Administrator. 

For the reasons set forth in the 

preamble, 40 CFR part 80 is amended as 

follows: 

PART 80—REGULATION OF FUELS 

AND FUEL ADDITIVES 

■ 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 ‘‘Energy cane,’’ 

‘‘Renewable gasoline’’ and ‘‘Renewable 

gasoline blendstock’’ in alphabetical 

order to read as follows: 

§ 80.1401 Definitions. 

* * * * * 

Energy cane means a complex hybrid 

in the Saccharum genus that has been 

bred to maximize cellulosic rather than 

sugar content. For the purposes of this 

section, energy cane excludes the 

species Saccharum spontaneum, but 

includes hybrids derived from S. 


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14216 Federal Register / Vol. 78, No. 43 / Tuesday, March 5, 2013 / Rules and Regulations 

spontaneum that have been developed 

and publicly released by USDA. 

* * * * * 

Renewable gasoline means renewable 

fuel made from renewable biomass that 

is composed of only hydrocarbons and 

which meets the definition of gasoline 

in § 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 paragraph (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) * * * 

(1) * * * 

TABLE 1 TO § 80.1426—APPLICABLE D CODES FOR EACH FUEL PATHWAY FOR USE IN GENERATING RINS

Fuel type Feedstock Production process requirements D–Code 

A ....... Ethanol .................. Corn starch .......................................................... All of the following: Dry mill process, using natural gas, biomass, or biogas for process energy and at least two advanced technologies 

from Table 2 to this section.

6 

B ....... Ethanol .................. Corn starch .......................................................... All of the following: Dry mill process, using natural gas, biomass, or biogas for process energy and at least one of the advanced technologies from Table 2 to this section plus drying no more than 65% of the distillers grains 

with solubles it markets annually.

6 

C ....... Ethanol .................. Corn starch .......................................................... All of the following: Dry mill process, using natural gas, biomass, or biogas for process energy and drying no more than 50% of the distillers grains with solubles it markets annually.6 

D ....... Ethanol .................. Corn starch .......................................................... Wet mill process using biomass or biogas for 

process energy.

6 

E ....... Ethanol .................. Starches from crop residue and annual 

covercrops.

Fermentation using natural gas, biomass, or 

biogas for process energy.

6 

F ....... Biodiesel, renewable diesel, jet 

fuel and heating 

oil.

Soy bean oil; Oil from annual covercrops; Algal 

oil; Biogenic waste oils/fats/greases; Non-food 

grade corn oil Camelina sativa oil.

One of the following: Trans-Esterification 

Hydrotreating Excluding processes that coprocess renewable biomass and petroleum.

4 

G ...... Biodiesel, heating 

oil.

Canola/Rapeseed oil ........................................... Trans-Esterification using natural gas or biomass for process energy.4 

H ....... Biodiesel, renewable diesel, jet 

fuel and heating 

oil.

Soy bean oil; Oil from annual covercrops; Algal 

oil; Biogenic waste oils/fats/greases; Non-food 

grade corn oil Camelina sativa oil.

One of the following: Trans-Esterification 

Hydrotreating Includes only processes that 

co-process renewable biomass and petroleum.

5 

I ........ Naphtha, LPG ....... Camelina sativa oil .............................................. Hydrotreating ....................................................... 5 

J ....... Ethanol .................. Sugarcane ........................................................... Fermentation ........................................................ 5 

K ....... Ethanol .................. Cellulosic Biomass from crop residue, slash, 

pre-commercial thinnings and tree residue, 

annual covercrops, switchgrass, miscanthus, 

and energy cane; cellulosic components of 

separated yard waste; cellulosic components 

of separated food waste; and cellulosic components of separated MSW.

Any ....................................................................... 3 

L ....... Cellulosic diesel, 

jet fuel and heating oil.

Cellulosic Biomass from crop residue, slash, 

pre-commercial thinnings and tree residue, 

annual covercrops, switchgrass, miscanthus, 

and energy cane; cellulosic components of 

separated yard waste; cellulosic components 

of separated food waste; and cellulosic components of separated MSW.

Any ....................................................................... 7 

M ...... Renewable gasoline and renewable gasoline 

blendstock.

Cellulosic Biomass from crop residue, slash, 

pre-commercial thinnings, tree residue, annual 

cover crops; cellulosic components of separated yard waste; cellulosic components of 

separated food waste; and cellulosic components of separated MSW.

Catalytic Pyrolysis and Upgrading, Gasification 

and Upgrading, Thermo-Catalytic 

Hydrodeoxygenation and Upgrading, Direct 

Biological Conversion, Biological Conversion 

and Upgrading, all utilizing natural gas, 

biogas, and/or biomass as the only process 

energy sources Any process utilizing biogas 

and/or biomass as the only process energy 

sources.

3 

N ....... Naphtha ................ Cellulosic biomass from switchgrass, 

miscanthus, and energy cane.

Gasification and upgrading .................................. 3 

O ...... Butanol .................. Corn starch .......................................................... Fermentation; dry mill using natural gas, biomass, or biogas for process energy.6 


emcdonald on DSK67QTVN1PROD with RULES
Federal Register / Vol. 78, No. 43 / Tuesday, March 5, 2013 / Rules and Regulations 14217 

TABLE 1 TO § 80.1426—APPLICABLE D CODES FOR EACH FUEL PATHWAY FOR USE IN GENERATING RINS—Continued 

Fuel type Feedstock Production process requirements D–Code 

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 

R ....... Ethanol .................. Grain Sorghum .................................................... Dry mill process using biogas from landfills, 

waste treatment plants, and/or waste digesters, and/or natural gas, for process energy.

6 

S ....... Ethanol .................. Grain Sorghum .................................................... Dry mill process, using only biogas from landfills, waste treatment plants, and/or waste digesters for process energy and for on-site 

production of all electricity used at the site 

other than up to 0.15 kWh of electricity from 

the grid per gallon of ethanol produced, calculated on a per batch basis.

5 

* * * * * 

[FR Doc. 2013–04929 Filed 3–4–13; 8:45 am] 

BILLING CODE 6560–50–P 

DEPARTMENT OF TRANSPORTATION 

Federal Railroad Administration 

49 CFR Part 219 

[Docket No. FRA–2010–0155] 

RIN 2130–AC24 

Control of Alcohol and Drug Use: 

Addition of Post-Accident 

Toxicological Testing for NonControlled Substances 

AGENCY: Federal Railroad 

Administration (FRA), Department of 

Transportation (DOT). 

ACTION: Final rule. 

SUMMARY: In 1985, FRA implemented a 

post-accident toxicological testing (postaccident testing) program to test railroad 

employees who had been involved in 

serious train accidents for alcohol and 

certain controlled substances 

(marijuana, cocaine, phencyclidine 

(PCP), and selected opiates, 

amphetamines, barbiturates, and 

benzodiazepines). This final rule adds 

certain non-controlled substances with 

potentially impairing side effects to its 

standard post-accident testing panel. 

The non-controlled substances include 

tramadol and sedating antihistamines. 

This final rule makes clear that FRA 

intends to keep the post-accident test 

results for these non-controlled 

substances confidential while it 

continues to obtain and analyze data on 

the extent to which prescription and 

over-the-counter (OTC) drug use by 

railroad employees potentially affects 

rail safety. 

DATES: This rule is effective on May 6, 

2013. Petitions for reconsideration must 

be received on or before May 6, 2013. 

Petitions for reconsideration will be 

posted in the docket for this proceeding. 

Comments on any submitted petition for 

reconsideration must be received on or 

before June 18, 2013. 

ADDRESSES: Petitions for reconsideration 

or comments on such petitions: Any 

petitions and any comments to petitions 

related to Docket No. FRA–2010–0155, 

may be submitted by any of the 

following methods: 

• Online: Comments should be filed 

at the Federal eRulemaking Portal, 

http://www.regulations.gov. Follow the 

online instructions for submitting 

comments. 

• Fax: 202–493–2251. 

• Mail: Docket Management Facility, 

U.S. DOT, 1200 New Jersey Avenue SE., 

W12–140, Washington, DC 20590. 

• Hand Delivery: Room W12–140 on 

the Ground level of the West Building, 

1200 New Jersey Avenue SE., 

Washington, DC between 9 a.m. and 5 

p.m. Monday through Friday, except 

federal holidays. 

Instructions: All submissions must 

include the agency name and docket 

number or Regulatory Identification 

Number (RIN) for this rulemaking. All 

petitions and comments received will be 

posted without change to http:// 

www.regulations.gov; this includes any 

personal information. Please see the 

Privacy Act heading in the 

‘‘Supplementary Information’’ section of 

this document for Privacy Act 

information related to any submitted 

petitions or materials. 

Docket: For access to the docket to 

read background documents or 

comments received, go to http:// 

www.regulations.gov at any time or to 

Room W12–140 on the Ground level of 

the West Building, 1200 New Jersey 

Avenue SE, Washington, DC between 9 

a.m. and 5 p.m. Monday through Friday, 

except Federal holidays. 

FOR FURTHER INFORMATION CONTACT: 

Patricia V. Sun, Trial Attorney, Office of 

Chief Counsel, Mail Stop 10, FRA, 1200 

New Jersey Avenue SE. Washington, DC 

20590 (telephone 202–493–6060), 

patricia.sun@dot.gov. 

SUPPLEMENTARY INFORMATION: 

The NPRM 

In 1985, to further its accident 

investigation program, FRA began 

conducting alcohol and drug tests on 

railroad employees who had been 

involved in serious train accidents that 

met its specified criteria for postaccident testing (see 49 CFR 219.201). 

Since the program’s inception, FRA has 

routinely conducted post-accident tests 

for alcohol and for certain drugs 

classified by the Drug Enforcement 

Administration (DEA) as controlled 

substances because of their potential for 

abuse or addiction. See the Controlled 

Substances Act (CSA), Title II of the 

Comprehensive Drug Abuse Prevention 

Substances Act of 1970 (CSA, 21 U.S.C. 

801 et seq.). As noted in the NPRM, FRA 

has historically conducted post-accident 

tests for alcohol and marijuana, cocaine, 

phencyclidine (PCP), and certain 

opiates, amphetamines, barbiturates, 

and benzodiazepines. The purpose of 

these tests is to determine if alcohol 

misuse or drug abuse played a role in 

the occurrence or severity of an 

accident. 

On May 17, 2012, FRA proposed to 

add routine post-accident tests for 

certain non-controlled substances with 

potentially impairing side effects (77 FR 

29307). As discussed in the NPRM, 

studies have shown a significant 

increase in the daily use of prescription 

drugs, OTC drugs, vitamins, and herbal 


emcdonald on DSK67QTVN1PROD with RULES