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

ENVIRONMENTAL PROTECTION 

AGENCY 

40 CFR Part 80 

[EPA–HQ–OAR–2011–0542; FRL–9502–2] 

RIN 2060–AR07 

Regulation of Fuels and Fuel 

Additives: Identification of Additional 

Qualifying Renewable Fuel Pathways 

Under the Renewable Fuel Standard 

Program 

AGENCY: Environmental Protection 

Agency (EPA). 

ACTION: Direct final rule. 

SUMMARY: EPA is issuing a direct final 

rule identifying additional fuel 

pathways that EPA has determined meet 

the biomass-based diesel, advanced 

biofuel or cellulosic biofuel lifecycle 

greenhouse gas (GHG) reduction 

requirements specified in Clean Air Act 

section 211(o), the Renewable Fuel 

Standard Program, as amended by the 

Energy Independence and Security Act 

of 2007 (EISA). This direct final rule 

describes EPA’s evaluation of biofuels 

produced from camelina oil, energy 

cane, giant reed, and napiergrass; it also 

includes an evaluation of renewable 

gasoline and renewable gasoline 

blendstocks, as well as biodiesel from 

esterification, and clarifies our 

definition of renewable diesel. We are 

also finalizing two changes to regulation 

that were proposed on July 1, 2011(76 

FR 38844). The first change adds ID 

letters to pathways to facilitate 

references to specific pathways. The 

second change adds ‘‘rapeseed’’ to the 

existing pathway for renewable fuel 

made from canola oil. 

This direct final rule adds these 

pathways to Table in regulation as 

pathways which have been determined 

to meet one or more of the GHG 

reduction thresholds specified in CAA 

211(o), and assigns each pathway a 

corresponding D-Code. It allows 

producers or importers of fuel produced 

pursuant to these pathways to generate 

Renewable Identification Numbers 

(RINs), providing that the fuel meets the 

other requirements specified in the RFS 

regulations to qualify it as renewable 

fuel. 

DATES: This rule is effective on March 5, 

2012 without further notice, unless EPA 

receives adverse comment or a hearing 

request by February 6, 2012. If EPA 

receives a timely adverse comment or a 

hearing request, we will publish a 

withdrawal in the Federal Register 

informing the public that the portions of 

the rule with adverse comment will not 

take effect. 

ADDRESSES: Submit your comments, 

identified by Docket ID No. EPA–HQ– 

OAR–2011–0542, by one of the 

following methods: 

• www.regulations.gov: Follow the 

on-line instructions for submitting 

comments. 

• Email: a-and-r-docket@epa.gov, 

Attention Air and Radiation Docket ID 

EPA–HQ–OAR–2011–0542 

• Fax: [Insert fax number]. 

• Mail: Air and Radiation Docket, 

Docket No. EPA–HQ–OAR–2011–0542, 

Environmental Protection Agency, 

Mailcode: 6406J, 1200 Pennsylvania 

Ave. NW., Washington, DC 20460. 

• Hand Delivery: EPA Docket Center, 

EPA/DC, EPA West, Room 3334, 1301 

Constitution Ave. NW., Washington, 

DC, 20460, Attention Air and Radiation 

Docket, ID No. EPA–HQ–OAR–2011– 

0542. Such deliveries are only accepted 

during the Docket’s normal hours of 

operation, and special arrangements 

should be made for deliveries of boxed 

information. 

Instructions: Direct your comments to 

Docket ID No. EPA–HQ–OAR–2011– 

0542. EPA’s policy is that all comments 

received will be included in the public 

docket without change and may be 

made available online at 

www.regulations.gov, including any 

personal information provided, unless 

the comment includes information 

claimed to be Confidential Business 

Information (CBI) or other information 

whose disclosure is restricted by statute. 

Do not submit information that you 

consider to be CBI or otherwise 

protected through www.regulations.gov 

or email. The www.regulations.gov Web 

site is an ‘‘anonymous access’’ system, 

which means EPA will not know your 

identity or contact information unless 

you provide it in the body of your 

comment. If you send an email 

comment directly to EPA without going 

through www.regulations.gov your email 

address will be automatically captured 

and included as part of the comment 

that is placed in the public docket and 

made available on the Internet. If you 

submit an electronic comment, EPA 

recommends that you include your 

name and other contact information in 

the body of your comment and with any 

disk or CD–ROM you submit. If EPA 

cannot read your comment due to 

technical difficulties and cannot contact 

you for clarification, EPA may not be 

able to consider your comment. 

Electronic files should avoid the use of 

special characters, any form of 

encryption, and be free of any defects or 

viruses. For additional information 

about EPA’s public docket visit the EPA 

Docket Center homepage at http:// 

www.epa.gov/epahome/dockets.htm. 

Docket: All documents in the docket 

are listed in the www.regulations.gov 

index. Although listed in the index, 

some information is not publicly 

available, e.g., CBI or other information 

whose disclosure is restricted by statute. 

Certain other material, such as 

copyrighted material, will be publicly 

available only in hard copy. Publicly 

available docket materials are available 

either electronically in 

www.regulations.gov or in hard copy at 

the Air and Radiation Docket and 

Information Center, EPA/DC, EPA West, 

Room 3334, 1301 Constitution Ave. 

NW., Washington, DC. The Public 

Reading Room is open from 8:30 a.m. to 

4:30 p.m., Monday through Friday, 

excluding legal holidays. The telephone 

number for the Public Reading Room is 

(202) 566–1744, and the telephone 

number for the Air Docket is (202) 566– 

1742). 

FOR FURTHER INFORMATION CONTACT: 

Vincent Camobreco, Office of 

Transportation and Air Quality 

(MC6401A), Environmental Protection 

Agency, 1200 Pennsylvania Ave. NW., 

Washington, DC 20460; telephone 

number: (202) 564–9043; fax number: 

(202) 564–1686; email address: 

camobreco.vincent@epa.gov. 

SUPPLEMENTARY INFORMATION: 

I. Why is EPA using a direct final rule? 

EPA is publishing this rule without a 

prior proposed rule because we view 

this as a noncontroversial action. These 

new pathway determinations did not 

require new agricultural sector 

modeling and involved relatively 

straightforward analyses that largely 

relied upon work done for the RFS2 

final rule. If EPA receives relevant 

adverse comment or a hearing request 

on a distinct provision of this 

rulemaking, we will publish a timely 

withdrawal in the Federal Register 

indicating which portion of the rule is 

being withdrawn. Any distinct 

amendment, paragraph, or section of 

today’s rule not withdrawn will become 

effective on the date set out above. 

In the ‘‘Proposed Rules’’ section of 

today’s Federal Register, we are 

publishing a separate document that 

will serve as the proposed rule to 

update Table 1 of § 80.1426 to add any 

additional renewable fuel production 

pathways or regulatory provisions 

which may be withdrawn from the 

direct final rule. We will not institute a 

second comment period on this action. 

Any parties interested in commenting 

must do so at this time. For further 

information about commenting on this 

rule, see the ADDRESSES section of this 

document. We will address all public 

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Federal Register / Vol. 77, No. 3 / Thursday, January 5, 2012 / Rules and Regulations 701 

comments in any subsequent final rule 

based on the proposed rule. 

II. Does this action apply to me? 

Entities potentially affected by this 

action are those involved with the 

production, distribution, and sale of 

transportation fuels, including gasoline 

and diesel fuel or renewable fuels such 

as ethanol and biodiesel. Regulated 

categories and entities affected by this 

action include: 

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) 2 Standard Industrial Classification (SIC) system code. 

This table is not intended to be 

exhaustive, but rather provides a guide 

for readers regarding entities likely to be 

regulated by this action. This table lists 

the types of entities that EPA is now 

aware could be potentially regulated by 

this action. Other types of entities not 

listed in the table could also be 

regulated. To determine whether your 

entity is regulated by this action, you 

should carefully examine the 

applicability criteria of Part 80, subparts 

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

Federal Regulations. If you have any 

question regarding applicability of this 

action to a particular entity, consult the 

person in the preceding FOR FURTHER

INFORMATION CONTACT section above. 

III. What should I consider as I prepare 

my comments for EPA? 

A. Submitting information claimed as 

CBI. Do not submit information you 

claim as CBI to EPA through 

www.regulations.gov or email. Clearly 

mark the part or all of the information 

that you claim to be CBI. For CBI 

information in a disk or CD ROM that 

you mail to EPA, mark the outside of the 

disk or CD ROM as CBI and then 

identify electronically within the disk or 

CD ROM the specific information that is 

claimed as CBI). In addition to one 

complete version of the comment that 

includes information claimed as CBI, a 

copy of the comment that does not 

contain the information claimed as CBI 

must be submitted for inclusion in the 

public docket. Information so marked 

will not be disclosed except in 

accordance with procedures set forth in 

40 CFR part 2. 

B. Tips for Preparing Your Comments. 

When submitting comments, remember 

to: 

• Identify the rulemaking by docket 

number and other identifying 

information (subject heading, Federal 

Register date and page number). 

• Follow directions—The agency may 

ask you to respond to specific questions 

or organize comments by referencing a 

Code of Federal Regulations (CFR) part 

or section number. 

• Explain why you agree or disagree; 

suggest alternatives and substitute 

language for your requested changes. 

• Describe any assumptions and 

provide any technical information and/ 

or data that you used. 

• If you estimate potential costs or 

burdens, explain how you arrived at 

your estimate in sufficient detail to 

allow for it to be reproduced. 

• Provide specific examples to 

illustrate your concerns, and suggest 

alternatives. 

• Explain your views as clearly as 

possible, avoiding the use of profanity 

or personal threats. 

• Make sure to submit your 

comments by the comment period 

deadline identified. 

C. Docket Copying Costs. You may be 

charged a reasonable fee for 

photocopying docket materials, as 

provided in 40 CFR part 2. 

IV. Identification of additional 

qualifying renewable fuel pathways 

under the renewable fuel standard 

(RFS) program 

EPA is issuing a direct final rule to 

identify in the RFS regulations 

additional renewable fuel production 

pathways that we have determined meet 

the greenhouse gas (GHG) reduction 

requirements of the RFS program. This 

direct final rule describes EPA’s 

evaluation of: 

Camelina Oil (New Feedstock) 

• Biodiesel and renewable diesel 

(including jet fuel and heating oil) — 

qualifying as biomass-based diesel and 

advanced biofuel 

• Naphtha and liquefied petroleum 

gas (LPG) — qualifying as advanced 

biofuel 

Energy Cane, Giant Reed, and 

Napiergrass Cellulosic Biomass (New 

Feedstocks) 

• Ethanol, renewable diesel 

(including renewable jet fuel and 

heating oil), and naphtha — qualifying 

as cellulosic biofuel 

Renewable Gasoline and Renewable 

Gasoline Blendstock (New Fuel Types) 

• Produced from crop residue, slash, 

pre-commercial thinnings, tree residue, 

annual cover crops, and cellulosic 

components of separated yard waste, 

separated food waste, and separated 

municipal solid waste (MSW) 

• Using the following processes — all 

utilizing natural gas, biogas, and/or 

biomass as the only process energy 

sources — qualifying as cellulosic 

biofuel: 

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 

Esterification (New Production Process) 

• Process used to produce biodiesel 

from soy bean oil, oil from annual 

covercrops, algal oil, biogenic waste 

oils/fats/greases, non-food grade corn 

oil, Canola/rapeseed oil, and camelina 

oil—qualifying as biomass-based diesel 

and advanced biofuel 

This direct final rule adds these 

pathways to Table 1 to § 80.1426 and 

assigns each pathway one or more D– 

Codes. This final rule allows producers 

or importers of fuel produced under 

these pathways to generate Renewable 

Identification Numbers (RINs) in 

accordance with the RFS regulations, 

providing that the fuel meets other 

definitional criteria for renewable fuel. 

Determining whether a fuel pathway 

satisfies the CAA’s lifecycle GHG 

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702 Federal Register / Vol. 77, No. 3 / Thursday, January 5, 2012 / 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/publicaTMtions/ 

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. 

8McCormick, Margaret. ‘‘Oral Comments of 

Targeted Growth, Incorporated’’ Submitted to the 

EPA on June 9, 2009. 

9See https://www.camelinacompany.com/ 

Marketing/PressRelease.aspx?Id=25. 

10See Shonnard, D. R., Williams, L., & Kalnes, T. 

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

Sustainable Advanced Biodiesel. Environmental 

Progress & Sustainable Energy, 382–392. 

reduction thresholds for renewable fuels 

requires a comprehensive evaluation of 

the lifecycle GHG emissions of the 

renewable fuel as compared to the 

lifecycle GHG emissions of the baseline 

gasoline or diesel fuel that it replaces. 

As mandated by CAA section 211(o), the 

GHG emissions assessments must 

evaluate the aggregate quantity of GHG 

emissions (including direct emissions 

and significant indirect emissions such 

as significant emissions from land use 

changes) related to the full fuel 

lifecycle, including all stages of fuel and 

feedstock production, distribution, and 

use by the ultimate consumer. 

In examining the full lifecycle GHG 

impacts of renewable fuels for the RFS 

program, EPA considers the following: 

• Feedstock production—based on 

agricultural sector models that include 

direct and indirect impacts of feedstock 

production 

• Fuel production—including process 

energy requirements, impacts of any raw 

materials used in the process, and 

benefits from co-products produced. 

• Fuel and feedstock distribution— 

including impacts of transporting 

feedstock from production to use, and 

transport of the final fuel to the 

consumer. 

• Use of the fuel—including 

combustion emissions from use of the 

fuel in a vehicle. 

Many of the pathways evaluated in 

this rulemaking rely on a comparison to 

the lifecycle GHG analysis work that 

was done as part of the Renewable Fuel 

Standard Program (RFS2) Final Rule, 

published March 26, 2010. The 

evaluations here rely on comparisons to 

the existing analysis. EPA plans to 

periodically review and revise the 

methodology and assumptions 

associated with calculating the GHG 

emissions from all renewable fuel 

pathways. 

A. Analysis of Lifecycle Greenhouse Gas 

Emissions for Biodiesel, Renewable 

Diesel, Jet Fuel, Naphtha, and Liquefied 

Petroleum Gas (LPG) Produced From 

Camelina Oil 

1. Feedstock Production 

Camelina sativa (camelina) is an 

oilseed crop within the flowering plant 

family Brassicaceae that is native to 

Northern Europe and Central Asia. 

Camelina’s suitability to northern 

climates and low moisture requirements 

allows it to be grown in areas that are 

unsuitable for other major oilseed crops 

such as soybeans, sunflower, and 

canola/rapeseed. Camelina also requires 

the use of little to no tillage.1 Compared 

to many other oilseeds, camelina has a 

relatively short growing season (less 

than 100 days), and can be grown either 

as a spring annual or in the winter in 

milder climates. 2 3 Camelina can also be 

used to break the continuous planting 

cycle of certain grains, effectively 

reducing the disease, insect, and weed 

pressure in fields planted with such 

grains (like wheat) in the following 

year.4

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

Camelina is currently being grown on 

approximately 50,000 acres of land in 

the U.S., primarily in Montana, eastern 

Washington, and the Dakotas.8 USDA 

does not systematically collect camelina 

production information; therefore data 

on historical acreage is limited. 

However, available information 

indicates that camelina has been grown 

on trial plots in 12 U.S. states.9

For the purposes of analyzing the 

lifecycle GHG emissions of camelina, 

EPA has considered the likely 

production pattern for camelina grown 

for biofuel production. Given the 

information currently available, 

camelina is expected to be primarily 

planted in the U.S. as a rotation crop on 

acres that would otherwise remain 

fallow during the camelina planting. 

Since substituting fallow land with 

camelina production would not 

typically displace another crop, EPA 

does not believe new acres would need 

to be brought into agricultural use to 

increase camelina production. In 

addition, camelina currently has only 

limited high-value niche markets for 

uses other than renewable fuels. Unlike 

commodity crops that are tracked by 

USDA, camelina does not have a 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 grown on fallow 

land. Furthermore, due to the limited 

non-biofuel uses for camelina, 

production of camelina-based biofuels is 

not expected to have a significant 

impact on other agricultural crop 

production or commodity markets 

(either camelina or other crop markets) 

and consequently would not result in 

significant GHG emissions related to 

indirect land use change. To the extent 

camelina-based biofuel production 

decreases the demand for alternative 

biofuels, some with higher GHG 

emissions, this biofuel could have some 

beneficial GHG impact. However, it is 

uncertain which mix of biofuel sources 

the market will demand so this potential 

GHG impact cannot be quantified. 

a. Growing Practices 

Current market conditions indicate 

that camelina will most likely be grown 

in rotation with wheat on dryland wheat 

acres replacing a period that they would 

otherwise be left fallow.10 In areas with 

lower precipitation, dryland wheat 

farmers currently leave acres fallow 

once every three to four years to allow 

additional moisture and nutrients to 

accumulate and to control pests. Current 

research indicates that camelina could 

be introduced into this rotation in 

certain areas without adversely 

impacting moisture or nutrient 

accumulation (see Figure 1). Because 

camelina has shallow roots with 

drought resistant characteristics, the 

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11See Shonnard et al., 2010; Lafferty et al., 2009. 

12Wheeler, P and F. Guillen-Portal. 2007. 

Camelina Production in Montana: A survey study 

sponsored by Targeted Growth, Inc. and Barkley Ag. 

Enterprises, LLP (unpublished). 

land can be returned to wheat 

cultivation the following year with 

moisture and soil nutrients intact 

quantitatively similar to a fallow year.11

In addition, camelina uses the same equipment for harvesting as wheat; 

therefore, farmers would not need to 

invest in new equipment to add 

camelina to the rotation with wheat.12

BILLING CODE 6560–50–P 

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

BILLING CODE 6560–50–C 


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Federal Register / Vol. 77, No. 3 / Thursday, January 5, 2012 / Rules and Regulations 705 

13 2009 USDA Baseline. See http:// 

www.ers.usda.gov/publications/oce091/. 14 Johnson, S. and McCormick, M., Camelina: an 

Annual Cover Crop Under 40 CFR Part 80 Subpart 

M, Memorandum, dated November 5, 2010. 15Wheeler, P. and Guillen-Portal F. 2007. 

Camelina Production in Montana: A survey study 

sponsored by Targeted Growth, Inc. and Barkley Ag. 

Enterprises, LLP. 

16See 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. 17Ehrensing, 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. 18See Shonnard et al., 2010. 19This assumes no significant adverse climate 

impacts on world agricultural yields over the 

analytical timeframe. 

20See Lafferty et al., 2009; Shonnard et al., 2010; 

Sustainable Oils Memo dated November 5, 2010, 

21Wheeler & Guillen-Portal, 2007. 

22See Sustainable Oils Memo dated November 5, 

2010, 

23Based on yields technically feasible. See 

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

24Adapted from Shonnard et al, 2010. 

b. Land Availability 

USDA estimates that there are 

approximately 60 million acres of wheat 

in the U.S.13 USDA and wheat state 

cooperative extension reports through 

2008 indicate that 83% of U.S. wheat 

production is under non-irrigated, 

dryland conditions. Of the 

approximately 50 million non-irrigated 

acres, at least 45% are estimated to 

follow a wheat/fallow rotation. Thus, 

approximately 22 million acres are 

potentially suitable for camelina 

production. However, according to 

industry projections, only about 9 

million of these wheat/fallow acres have 

the appropriate climate, soil profile, and 

market access for camelina 

production.14 Therefore, our analysis 

uses the estimate that only 9 million 

wheat/fallow acres are available for 

camelina production. 

c. Projected Volumes 

Based on these projections of land 

availability, EPA estimates that at 

current yields (approximately 800 

pounds per acre), approximately 100 

million gallons (MG) of camelina-based 

renewable fuels could be produced with 

camelina grown in rotation with 

existing crop acres without having 

direct land use change impacts. Also, 

since camelina will likely be grown on 

fallow land and thus not displace any 

other crop and since camelina currently 

does not have other significant markets, 

expanding production and use of 

camelina for biofuel purposes is not 

likely to have other agricultural market 

impacts and therefore, would not result 

in any significant indirect land use 

impacts.15 This assessment is based on 

a three year rotation cycle in which only 

one third of the 9 million available acres 

would be fallow in any given year. 

Yields of camelina are expected to 

approach the yields of similar oilseed 

crops over the next few years, as 

experience with growing camelina 

improves cultivation practices and the 

application of existing technologies are 

more widely adopted.16 Yields of 1650 

pounds per acre have been achieved on 

test plots, and are in line with expected 

yields of other oilseeds such as canola/ 

rapeseed. Assuming average US yields 

of 1650 pounds per acre,17

approximately 200 MG of camelinabased renewable fuels could be 

produced on existing wheat/fallow 

acres. Finally, if investment in new seed 

technology allows yields to increase to 

levels assumed by Shonnard et al (3000 

pounds per acre), approximately 400 

MG of camelina-based renewable fuels 

could be produced on existing acres.18

Depending on future crop yields, we 

project that roughly 100 MG to 400 MG 

of camelina-based biofuels could be 

produced on currently fallow land with 

no impacts on land use.19

d. Indirect Impacts 

Although wheat can in some cases be 

grown in rotation with other crops such 

as lentils, flax, peas, garbanzo, and 

millet, cost and benefit analysis indicate 

that camelina is most likely to be 

planted on soil with lower moisture and 

nutrients where other rotation crops are 

not viable.20 Because expected returns 

on camelina are relatively uncertain, 

farmers are not expected to grow 

camelina on land that would otherwise 

be used to grow cash crops with well 

established prices and markets. Instead, 

farmers are most likely to grow camelina 

on land that would otherwise be left 

fallow for a season. The opportunity 

cost of growing camelina on this type of 

land is much lower. As previously 

discussed, this type of land represents 

the 9 million acres currently being 

targeted for camelina production. 

Current returns on camelina are 

relatively low ($13.24 per acre), given 

average yields of approximately 800 

pounds per acre and the current 

contract price of $0.145 per pound.21

See Table 1. For comparison purposes, 

the USDA projections for wheat returns 

are between $88–$105 per acre between 

2010 and 2020. Over time, 

advancements in seed technology, 

improvements in planting and 

harvesting techniques, and higher input 

usage could significantly increase future 

camelina yields and returns. 

TABLE 1—CAMELINA COSTS AND RETURNS

Inputs Rates 2010 Camelina 22 2022 Camelina 23 2030 Camelina 24

Herbicides: 

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

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

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

Seed: 

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

(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. 

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

25See 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. 

26Wright & Marois, 2011. 

TABLE 1—CAMELINA COSTS AND RETURNS—Continued 

Inputs Rates 2010 Camelina 22 2022 Camelina 23 2030 Camelina 24

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.25

For example, if camelina production 

expanded beyond the 9 million acres 

assumed available from wheat fallow 

land, it could impact other crops. 

However, as discussed above this is not 

likely to happen in the near term due to 

uncertainties in camelina financial 

returns. Camelina production could also 

occur in areas where wheat is not 

commonly grown. For example, testing 

of camelina production has occurred in 

Florida in rotation with kanaf, peanuts, 

cotton, and corn. However, only 200 

acres of camelina were harvested in 

2010 in Florida. While Florida acres of 

camelina are expected to be higher in 

2011, very little research has been done 

on growing camelina in Florida. For 

example, little is known about potential 

seedling disease in Florida or how 

camelina may be affected differently 

than in colder climates.26 Therefore, 

camelina grown outside of a wheat 

fallow situation was not considered as 

part of this analysis. 

The determination in this final rule is 

based on our projection that camelina is 

likely to be produced on what would 

otherwise be fallow land. However, the 

rule applies to all camelina regardless of 

where it is grown. EPA does not expect 

that significant camelina would be 

grown on non-fallow land, and small 

quantities that may be grown elsewhere 

and used for biofuel production will not 

significantly impact our analysis. 

Furthermore, although we expect 

most camelina used as a feedstock for 

renewable fuel production that would 

qualify in the RFS program would be 

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

apply to qualifying renewable fuel made 

from camelina grown in any country. 

For the same reasons that pertain to U.S. 

production of camelina, we expect that 

camelina grown in other countries 

would also be produced on land that 

would otherwise be fallow and would 

therefore have no significant land use 

change impacts. The renewable biomass 

provisions under the Energy 

Independence and Security Act would 

prohibit direct land conversion into new 

agricultural land for camelina 

production for biofuel internationally. 

Additionally, any camelina production 

on existing cropland internationally 

would not be expected to have land use 

impacts beyond what was considered 

for international soybean production 

(soybean oil is the expected major 

feedstock source for U.S. biodiesel fuel 

production and thus the feedstock of 

reference for the camelina evaluation). 

Because of these factors along with the 

small amounts of fuel potentially 

coming from other countries, we believe 

that incorporating fuels produced in 

other countries will not impact our 

threshold analysis for camelina-based 

biofuels. 

e. Crop Inputs 

For comparison purposes, Table 2 

shows the inputs required for camelina 

production compared to the FASOM 

agricultural input assumptions for 

soybeans. Since yields and input 

assumptions vary by region, a range of 

values for soybean production are 

shown in Table 2. The camelina input 

values in Table 2 represent average 

values, camelina input values will also 

vary by region, however, less data is 

available comparing actual practices by 

region due to limited camelina 

production. More information on 

camelina inputs is available in materials 

provided in the docket. 

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 


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Federal Register / Vol. 77, No. 3 / Thursday, January 5, 2012 / Rules and Regulations 707 

27A. 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. 

0.18 pounds of oil. In comparison, 

camelina is approximately 36% oil, 

therefore crushing one pound of 

camelina yields 0.36 pounds of oil. The 

difference in oil yield is taken into 

account when calculating the emissions 

per mmBTU included in Table 2. As 

shown in Table 2, GHG emissions from 

feedstock production for camelina and 

soybeans are relatively similar when 

factoring in variations in oil yields per 

acre and fertilizer, herbicide, pesticide, 

and petroleum use. 

In summary, EPA concludes that the 

agricultural inputs for growing camelina 

are similar to those for growing soy 

beans, direct land use impact is 

expected to be negligible due to planting 

on land that would be otherwise fallow, 

and the limited production and use of 

camelina indicates no expected impacts 

on other crops and therefore no indirect 

land use impacts. 

f. Crushing and Oil Extraction 

We also looked at the seed crushing 

and oil extraction process and compared 

the lifecycle GHG emissions from this 

stage for soybean oil and camelina oil. 

As discussed above, camelina seeds 

produce more oil per pound than 

soybeans. As a result, the lifecycle GHG 

emissions associated with crushing and 

oil extraction are lower for camelina 

than soybeans, per pound of vegetable 

oil produced. Table 3 summarizes data 

on inputs, outputs and estimated 

lifecycle GHG emissions from crushing 

and oil extraction. The data on soybean 

crushing comes from the RFS2 final 

rule, based on a process model 

developed by USDA–ARS.27 The data 

on camelina crushing is from Shonnard 

et al. (2010). 

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

Item Soybeans Camelina Units 

Material Inputs: 

Beans or Seeds .......................................................................................... 5 .38 2 .90 Lbs. 

Energy Inputs: 

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

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

Outputs: 

Refined vegetable oil .................................................................................. 1 .00 1 .00 Lbs. 

Meal ............................................................................................................ 4 .08 1 .85 Lbs. 

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

2. Feedstock Distribution, Fuel 

Distribution, and Fuel Use 

For this analysis, EPA projects that 

the feedstock distribution emissions 

will be the same for camelina and 

soybean oil. To the extent that camelina 

contains more oil per pound of seed, as 

discussed above, the energy needed to 

move the camelina would be lower than 

soybeans per gallon of fuel produced. 

To the extent that camelina is grown on 

more disperse fallow land than soybean 

and would need to be transported 

further, the energy needed to move the 

camelina could be higher than soybean. 

Based on this, we believe the 

assumption to use the same distribution 

impacts for camelina as soybean is a 

reasonable estimate of the GHG 

emissions from camelina feedstock 

distribution. In addition, the final fuel 

produced from camelina is also 

expected to be similar in composition to 

the comparable fuel produced from 

soybeans, therefore we are assuming 

GHG emissions from the distribution 

and use of fuels made from camelina 

will be the same as emissions of fuel 

produced from soybeans. 

3. Fuel Production 

There are two main fuel production 

processes used to convert camelina oil 

into fuel. The trans-esterification 

process produces biodiesel and a 

glycerin co-product. The hydrotreating 

process can be configured to produce 

renewable diesel either primarily as 

diesel fuel (including heating oil) or 

primarily as jet fuel. Possible additional 

products from hydrotreating include 

naphtha, LPG, and propane. Both 

processes and the fuels produced are 

described in the following sections. 

Both processes use camelina oil as a 

feedstock and camelina crushing is also 

included in the analysis. 

a. Biodiesel 

For this analysis, we assumed the 

same biodiesel production facility 

designs and conversion efficiencies as 

modeled for biodiesel produced from 

soybean oil and canola/rapeseed oil. 

Camelina oil biodiesel is produced 

using the same methods as soybean oil 

biodiesel, therefore plant designs are 

assumed to not significantly differ 

between fuels made from these 

feedstocks. As was the case for soybean 

oil biodiesel, we have not projected in 

our assessment of camelina oil biodiesel 

any significant improvements in plant 

technology. Unanticipated energy 

saving improvements would further 

improve GHG performance of the fuel 

pathway. 

The glycerin produced from camelina 

biodiesel production is equivalent to the 

glycerin produced from the existing 

biodiesel pathways (e.g., based on soy 

oil) that were analyzed as part of the 

RFS2 final rule. Therefore the same coproduct credit would apply to glycerin 

from camelina biodiesel as glycerin 

produced in the biodiesel pathways 

modeled for the RFS2 final rule. The 

assumption is that the GHG reductions 

associated with the replacement of 

residual oil with glycerin on an energy 

equivalent basis represents an 

appropriate midrange co-product credit 

of biodiesel produced glycerin. 

As part of our RFS2 proposal, we 

assumed the glycerin would have no 

value and would effectively receive no 

co-product credits in the soy biodiesel 

pathway. We received numerous 

comments, however, stating that the 

glycerin would have a beneficial use 

and should generate co-product 

benefits. Therefore, the biodiesel 

glycerin co-product determination made 

as part of the RFS2 final rule took into 

consideration the possible range of coproduct credit results. The actual coproduct benefit will be based on what 

products are replaced by the glycerin 

and what new uses develop for the coproduct 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 

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

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

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

from Fats and Oils. Thermochemical Conversion of 

Biomass to Liquid Fuels and Chemicals, Chapter 18, 

p. 475. 

29For 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. 

petroleum glycerin, replacing fuel 

products (residual oil, diesel fuel, 

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

products that don’t have a direct 

replacement, but may nevertheless have 

indirect effects on the extent to which 

existing competing products are used. 

The more immediate GHG reduction 

credits from glycerin co-product use 

will likely range from fairly high 

reduction credits when petroleum 

glycerin is replaced to lower reduction 

credits if it is used in new markets that 

have no direct replacement product, and 

therefore no replaced emissions. 

EPA does not have sufficient 

information (and received no relevant 

comments as part of the RFS2 rule) on 

which to allocate glycerin use across the 

range of likely uses. Therefore, EPA 

believes that the approach used in RFS2 

of picking a surrogate use for modeling 

purposes in the mid-range of likely 

glycerin uses, and the GHG emissions 

results tied to such use, is reasonable. 

The replacement of an energy 

equivalent amount of residual oil is a 

simplifying assumption determined by 

EPA to reflect the mid-range of possible 

glycerin uses in terms of GHG credits. 

EPA believes that it is appropriately 

representative of GHG reduction credit 

across the possible range without 

necessarily biasing the results toward 

high or low GHG impact. Given the 

fundamental difficulty of predicting 

possible glycerin uses and impacts of 

those uses many years into the future 

under evolving market conditions, EPA 

believes it is reasonable to use the more 

simplified approach to calculating coproduct GHG benefit associated with 

glycerin production. 

Given the fact that GHG emissions 

from camelina-based biodiesel would be 

similar to the GHG emissions from 

soybean- based biodiesel at all stages of 

the lifecycle but would not result in 

land use change as was the case for soy 

oil used as a feedstock, we believe 

biodiesel from camelina oil will also 

meet the 50% GHG emissions reduction 

threshold to qualify as a biomass based 

diesel and an advanced fuel. Therefore, 

EPA is including biodiesel produced 

from camelina oil under the same 

pathways for which biodiesel made 

from soybean oil qualifies under the 

RFS2 final rule. 

b. Renewable Diesel (Including Jet Fuel 

and Heating Oil), Naphtha, and LPG 

The same feedstocks currently used 

for biodiesel production can also be 

used in a hydrotreating process to 

produce a slate of products, including 

diesel fuel, heating oil (defined as No. 

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

and propane. Since the term renewable 

diesel is defined to include the products 

diesel fuel, jet fuel and heating oil, the 

following discussion uses the term 

renewable diesel to also include diesel 

fuel, jet fuel and heating oil. The yield 

of renewable diesel is relatively 

insensitive to feedstock source.28 While 

any propane produced as part of the 

hydrotreating process will most likely 

be combusted within the facility for 

process energy, the other co-products 

that can be produced (i.e., renewable 

diesel, naphtha, LPG) are higher value 

products that could be used as 

transportation fuels or, in the case of 

naphtha, a blendstock for production of 

transportation fuel. The hydrotreating 

process maximized for producing a 

diesel fuel replacement as the primary 

fuel product requires more overall 

material and energy inputs than 

transesterification to produce biodiesel, 

but it also results in a greater amount of 

other valuable co-products as listed 

above. The hydrotreating process can 

also be maximized for jet fuel 

production which requires even more 

process energy than the process 

optimized for producing a diesel fuel 

replacement, and produces a greater 

amount of co-products per barrel of 

feedstock, especially naphtha. 

Producers of renewable diesel from 

camelina have expressed interest in 

generating RINs under the RFS2 

program for the slate of products 

resulting from the hydrotreating 

process. Our lifecycle analysis accounts 

for the various uses of the co-products. 

There are two main approaches to 

accounting for the co-products 

produced, the allocation approach, and 

the displacement approach. In the 

allocation approach all the emissions 

from the hydrotreating process are 

allocated across all the different coproducts. There are a number of ways to 

do this but since the main use of the coproducts would be to generate RINs as 

a fuel product we allocate based on the 

energy content of the co-products 

produced. In this case, emissions from 

the process would be allocated equally 

to all the Btus produced. Therefore, on 

a per Btu basis all co-products would 

have the same emissions. The 

displacement approach would attribute 

all of the emissions of the hydrotreating 

process to one main product and then 

account for the emission reductions 

from the other co-products displacing 

alternative product production. For 

example, if the hydrotreating process is 

configured to maximize diesel fuel 

replacement production, all of the 

emissions from the process would be 

attributed to diesel fuel, but we would 

then assume the other co-products were 

displacing alternative products, for 

example, naphtha would displace 

gasoline, LPG would displace natural 

gas, etc. This assumes the other 

alternative products are not produced or 

used, so we would subtract the 

emissions of gasoline production and 

use, natural gas production and use, etc. 

This would show up as a GHG emission 

credit associated with the production of 

diesel fuel replacement. 

To account for the case where RINs 

are generated for the jet fuel, naphtha 

and LPG in addition to the diesel 

replacement fuel produced, we would 

not give the diesel 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.29 On the 

other hand, the upstream lifecycle GHG 

emissions associated with producing 

and transporting the plant oil feedstocks 

will be distributed over a larger group 

of RIN-generating products. Assuming 

each product (except propane) produced 

via the camelina oil hydrotreating 

process will generate RINs results in 

higher lifecycle GHG emissions for 

diesel fuel replacement as compared to 

the case where the co-products are not 

used to generate RINs. This general 

principle is also true when the 

hydrotreating process is maximized for 

jet fuel production. As a result, the 

worst GHG performance (i.e., greatest 

lifecycle GHG emissions) for diesel 

replacement fuel and jet fuel produced 

from camelina oil via hydrotreating will 

occur when all of the co-products are 

RIN-generating (we assume propane will 

be used for process energy). Thus, if 

these fuels meet the 50% GHG 

reduction threshold for biomass based 

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

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Federal Register / Vol. 77, No. 3 / Thursday, January 5, 2012 / Rules and Regulations 709 

30Pearlson, M., N. 2011. A Techno-Economic and 

Environmental Assessment of Hydroprocessed 

Renewable Distillate Fuels. 31Huo, 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. 

32We 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. 

33Based on Pearlson (2011), Table 3.1 and Table 

3.2. 

34Lifecycle 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. 

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., 

2011,30 Stratton et al., 2010, Huo et al., 

2008).31 Our analysis of GHG emissions 

from the hydrotreating process is based 

on the mass and energy balance data in 

Pearlson (2011) which analyzes a 

hydrotreating process maximized for 

diesel replacement fuel production and 

a hydrotreating process maximized for 

jet fuel production.32 This data is 

summarized in Table 4. 

TABLE 4—HYDROTREATING PROCESSES TO CONVERT CAMELINA OIL INTO DIESEL REPLACEMENT FUEL AND JET FUEL33

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. 

TABLE 5—FUEL PRODUCTION LIFECYCLE GHG EMISSIONS (KGCO2e/MMBTU) 34

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. 

LPG. 

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

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

Diesel. 

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 

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

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 naphtha and LPG 

produced from camelina oil will also 

meet the 50% GHG emissions reduction 

threshold. If the facility does not 

actually generate RINs for one or more 

of these co-products, we estimate that 

the lifecycle GHG emissions related to 

the RIN-generating products would be 

lower, thus renewable diesel (which 

includes diesel fuel, jet fuel, and heating 

oil) from camelina would still meet the 

50% emission reduction threshold. 

4. Summary 

Current information suggests that 

camelina has limited niche markets and 

will be produced on land that would 

otherwise remain fallow. Therefore, 

increased production of camelina-based 

renewable fuel is not expected to result 

in significant land use change 

emissions. For the purposes of this 

analysis, EPA is projecting there will be 

no land use emissions associated with 

camelina production for use as a 

renewable fuel feedstock. 

However, while production of 

camelina on acres that would otherwise 

remain fallow is expected to be the 

primary means by which the majority of 

all camelina is commercially harvested 

in the short- to medium- term, in the 

long term camelina may expand to other 

growing methods and lands if demand 

increases substantially beyond what 

EPA is currently predicting. While the 

impacts are uncertain, there are some 

indications demand could increase 

significantly. For example, camelina is 

included under USDA’s Biomass Crop 

Assistance Program (BCAP) and there is 

growing support for the use of camelina 

oil in producing drop-in alternative 

aviation fuels. EPA plans to monitor the 

expansion of camelina production to 

verify whether camelina is primarily 

grown on existing acres once camelina 

is produced at larger-scale volumes. 

Similarly, we will consider market 

impacts if alternative uses for camelina 

expand significantly beyond what was 

described in the above analysis. Just as 

EPA plans to periodically review and 

revise the methodology and 

assumptions associated with calculating 

the GHG emissions from all renewable 

fuel feedstocks, EPA expects to review 

and revise as necessary the analysis of 

camelina in the future. 

Taking into account the assumption of 

no land use change emissions when 

camelina is used to produce renewable 

fuel, and considering that other sources 

of GHG emissions related to camelina 

biodiesel or renewable diesel 

production have comparable GHG 

emissions to biodiesel from soybean oil, 

we have determined that 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 

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 RFS2 final rule, 

identifies jet fuel and renewable diesel 

as separate fuel types. Accordingly, in 

light of the revised definition of 

renewable diesel enacted after the RFS2 

rule, there is ambiguity regarding the 

extent to which references in Table 1 to 

‘‘renewable diesel’’ include jet fuel. 

The original lifecycle analysis for the 

renewable diesel from hydrotreating 

pathways listed in Table 1 to § 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 

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Federal Register / Vol. 77, No. 3 / Thursday, January 5, 2012 / Rules and Regulations 711 

35The exception is naphtha produced from waste 

categories, but these would pass the lifecycle 

thresholds regardless of the allocation approach 

used given their low feedstock GHG impacts. 

36See http://www.fs.fed.us/database/feis/plants/ 

graminoid/arudon/all.html. 

37See Lewandowski, I., Scurlock, J.M.O., 

Lindvall, E., Christou, M. (2003). The development 

and current status of perennial rhizomatous grasses 

Continued 

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 § 80.1426.35 As was 

discussed previously, if the 

displacement approach is used when jet 

fuel is the primary product produced it 

results in lower emissions then the 

production maximized for diesel fuel 

production. Therefore, since the 

hydrotreating process maximized for 

diesel fuel meets the 50% lifecycle GHG 

threshold for the feedstocks in question, 

the process maximized for jet fuel 

would also qualify. 

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 RFS2 

regulations jet fuel and heating oil as 

specific co-products in addition to 

listing renewable diesel to assure 

clarity. This clarification also pertains to 

all the feedstocks already included in 

Table 1 for renewable diesel. 

B. Lifecycle Greenhouse Gas Emissions 

Analysis for Ethanol, Diesel, Jet Fuel, 

Heating Oil, and Naphtha Produced 

From Energy Cane, Giant Reed, and 

Napiergrass 

For this rulemaking, EPA considered 

the lifecycle GHG impacts of three new 

types of high-yielding perennial grasses 

similar in cellulosic composition to 

switchgrass and comparable in status as 

an emerging energy crop. Energy cane 

(related to sugarcane), giant reed 

(Arundo donax), and napiergrass 

(pennisetum purpureum), also known as 

elephant grass. In the proposed and 

final RFS2 rule, EPA analyzed the 

lifecycle GHG impacts of producing and 

using cellulosic ethanol and cellulosic 

Fischer-Tropsch diesel from 

switchgrass. The midpoint of the range 

of switchgrass results showed a 110% 

GHG reduction (range of 102%–117%) 

for cellulosic ethanol (biochemical 

process), a 72% (range of ¥64% to 

¥79%) reduction for cellulosic ethanol 

(thermochemical process), and a 71% 

(range of ¥62% to ¥77%) reduction for 

cellulosic diesel (F–T process) 

compared to the petroleum baseline. In 

the RFS2 final rule, we indicated that 

some feedstock sources can be 

determined to be similar enough to 

those modeled that the modeled results 

could reasonably be extended to these 

similar feedstock types. For instance, 

information on miscanthus indicated 

that this perennial grass will yield more 

feedstock per acre than the modeled 

switchgrass feedstock without 

additional inputs with GHG 

implications (such as fertilizer). 

Therefore in the final rule EPA 

concluded that since biofuel made from 

the cellulosic biomass in switchgrass 

was found to satisfy the 60% GHG 

reduction threshold for cellulosic 

biofuel, biofuel produced form the 

cellulosic biomass in miscanthus would 

also comply. In the final rule we 

included cellulosic biomass from 

switchgrass and miscanthus as eligible 

feedstocks for the cellulosic biofuel 

pathways included in Table 1 to 

§ 80.1426. 

We did not include other perennial 

grasses such as energy cane, giant reed, 

or napiergrass as feedstocks for the 

cellulosic biofuel pathways in Table 1 at 

that time, since we did not have 

sufficient time to adequately consider 

them. Based in part on additional 

information received through the 

petition process for EPA approval of 

energy cane, giant reed, and napiergrass 

pathways, EPA has evaluated these 

feedstocks and is now including the 

cellulose, hemicelluloses and lignin 

portions of renewable biomass from 

energy cane, giant reed, and napiergrass 

in Table 1 to § 80.1426 as approved 

feedstocks for cellulosic biofuel 

pathways. 

As described in detail in the following 

sections of this preamble, because of the 

similarity of these feedstocks to 

switchgrass and miscanthus, EPA 

believes that new agricultural sector 

modeling is not needed to analyze them. 

We have instead relied upon the 

switchgrass analysis to assess the 

relative GHG impacts of biofuel 

produced from energy cane, giant reed, 

and napiergrass. As with the 

switchgrass analysis, we have attributed 

all land use impacts and resource inputs 

from use of these feedstocks to the 

portion of the fuel produced that is 

derived from the cellulosic components 

of the feedstocks. Based on this analysis 

and currently available information, we 

conclude that biofuel (ethanol, 

cellulosic diesel, jet fuel, heating oil and 

naptha) produced from the cellulosic 

biomass of energy cane, giant reed, or 

napiergrass has similar lifecycle GHG 

impacts to switchgrass biofuel and 

meets the 60% GHG reduction threshold 

required for cellulosic biofuel. 

1. Feedstock Production and 

Distribution 

For the purposes of this rulemaking, 

energy cane refers to varieties of 

perennial grasses in the Saccharum 

genus which are intentionally bred for 

high cellulosic biomass productivity but 

have characteristically low sugar 

content making them unsuitable as a 

primary source of sugar as compared to 

other varieties of grasses commonly 

known as ‘‘sugarcane’’ in the 

Saccharum genus. Energy cane varieties 

developed to date have low tolerance for 

cold temperatures but grow well in 

warm, humid climates. Energy cane 

originated from efforts to improve 

disease resistance and hardiness of 

commercial sugarcane by crossbreeding 

commercial and wild sugarcane strains. 

Certain higher fiber, lower sugar 

varieties that resulted were not suitable 

for commercial sugar production, and 

are now being developed as a highbiomass energy crop. There is currently 

no commercial production of energy 

cane. Current plantings are mainly 

limited to research field trials and small 

demonstrations for bioenergy purposes. 

However, based in part on discussions 

with industry, EPA anticipates 

continued development of energy cane 

particularly in the south-central and 

southeastern United States due to its 

high yields in these regions. 

Giant reed refers to the perennial 

grass Arundo donax of the Gramineae 

family. Giant reed thrives in subtropical 

and warm-temperate areas and is grown 

throughout Asia, southern Europe, 

Africa, the Middle East, and warmer 

U.S. states for multiple uses such as 

paper and pulp, musical instruments, 

rayon, particle boards, erosion control, 

and ornamental purposes.36 37 Based in 

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

as energy crops in the US and Europe. Biomass and 

Bioenergy 25, 335–361. 

38For a map depicting the northern limit for 

sustained napiergrass production in the United 

States see Figure 1 in Woodard, K., R. and 

Sollenberger, L, E. 2008. Production of Biofuel 

Crops in Florida: Elephantgrass. Institute of Food 

and Agricultural Sciences, University of Florida. SS 

AGR 297. 

39See 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. 

40See Hale, A.L. Sugar Bulletin, 2010, 88, 28–29. 

41Huang, P., Bransby, D., and Sladden, S. (2010). 

Exceptionally high yields and soil carbon 

sequestration recorded for giant reed in Alabama. 

Poster session presented at: ASA, CSSA, and SSSA 

2010 International Annual Meetings, Green 

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

CA. 

42Mantineo, M., D’Agnosta, G.M., Copani, V., 

Patane`, C., and Cosentino, S.L. (2009). Biomass 

yield and energy balance of three perennial crops 

for energy use in the semi-arid Mediterranean 

environment. Field Crops Research 114, 204–213. 

43Lewandowski et al. 2003. 

44Based on discussions with industry and USDA 

and Woodard and Sollenberger (2008). 

45These yields assume no significant adverse 

climate impacts on world agricultural yields over 

the analytical timeframe. 

part on discussions with industry, EPA 

anticipates continued development of 

giant reed as an energy crop particularly 

in the Mediterranean region and warmer 

U.S. states. 

Napiergrass is a tall bunch-type grass 

that has traditionally been grown as a 

high-yielding forage crop across the wet 

tropics. There is a considerable body of 

agronomic research on the production of 

napiergrass as a forage crop. More 

recently, researchers have investigated 

ways to maximize traits desirable in 

bioenergy crops. Practices have been 

developed by USDA and other 

researchers to lower fertilization rates 

and increase biomass production. Based 

in part on discussions with industry, 

EPA anticipates continued development 

of napiergrass as an energy crop 

particularly in Gulf Coast Region of the 

United States (more specifically the 

growing region includes Florida and 

southern portions of Texas, Louisiana, 

Georgia, Alabama and Mississippi).38

a. Crop Yields 

For the purposes of analyzing the 

GHG emissions from energy cane, giant 

reed, and napiergrass production, EPA 

examined crop yields and production 

inputs in relation to switchgrass to 

assess the relative GHG impacts. Current 

national yields for switchgrass are 

approximately 4.5 to 5 dry tons per acre. 

Average energy cane yields exceed 

switchgrass yields in both unfertilized 

and fertilized trails conducted in the 

southern United States. Unfertilized 

yields are around 7.3 dry tons per acre 

while fertilized trials show energy cane 

yields range from approximately 11 to 

20 dry tons per acre.39 40 Until recently 

there have been few efforts to improve 

energy cane yields, but several energy 

cane development programs are now 

underway to further increase its biomass 

productivity. Giant reed field trials 

conducted in Alabama over a 9-year 

period showed an average yield of 15 

dry tons per acre with no nitrogen 

fertilizer applied after the first year.41

Fertilized field trials have shown yields 

around 13 to 28 dry tons per acre in 

Spain, and 12 dry tons per acre in Italy 

(based on annual yields of 3, 14, 17, 16, 

and 12).42 High yields have been 

demonstrated with unimproved giant 

reed populations, and therefore there is 

potential for increased biomass 

productivity through improved growing 

methods and breeding efforts.43

Napiergrass field trials have produced 

dry biomass yields exceeding 20 tons 

per acre per year in north-central 

Florida. Using currently available 

technology, average yields for fullseason napiergrass should range from 14 

to 18 tons per acre with future 

improvements expected. Yield depends 

greatly on the type of cultivar and the 

amount and distribution of rainfall and 

fertilization rates. There is potential for 

increased biomass productivity through 

improved growing methods and 

breeding efforts.44 In general, the yields 

for all three of the energy grasses 

considered here will have higher yields 

than switchgrass, so from a crop yield 

perspective, the switchgrass analysis 

would be a conservative estimate when 

comparing against the energy cane, 

napier grass, and giant reed pathways. 

Furthermore, EPA’s analysis of 

switchgrass for the RFS2 rulemaking 

assumed a 2% annual increase in yield 

that would result in an average national 

yield of 6.6 dry tons per acre in 2022. 

EPA anticipates a similar yield 

improvement for energy cane, giant 

reed, and napiergrass due to their 

similarity as perennial grasses and their 

comparable status as energy crops in 

their early stages of development. Given 

this, our analysis assumes an average 

energy cane yield of 19 dry tons per acre 

in the southern United States by 2022; 

an average giant reed yield of 

approximately 18 dry tons per acre by 

2022; and an average napiergrass yield 

of approximately 20 dry tons per acre by 

2022.45 The ethanol yield for all of the 

grasses is approximately the same so the 

higher crop yields for energy cane, 

napiergrass, and giant reed result 

directly in greater ethanol production 

compared to switchgrass per acre of 

production. 

Based on these yield assumptions, in 

areas with suitable growing conditions, 

energy cane would require 

approximately 26% to 47% of the land 

area required by switchgrass to produce 

the same amount of biomass, giant reed 

would require less than 40% of the land 

area required by switchgrass to produce 

the same amount of biomass, and 

napiergrass would require 

approximately 33% of the land area 

required by switchgrass to produce the 

same amount of biomass due to their 

higher yields. Even without yield 

growth assumptions, their currently 

higher crop yield rates means the land 

use required for these crops would be 

lower than for switchgrass. Therefore 

less crop area would be converted and 

displaced resulting in smaller land-use 

change GHG impacts than that assumed 

for switchgrass to produce the same 

amount of fuel. Furthermore, we believe 

energy cane and napiergrass will have a 

similar impact on international markets 

as assumed for switchgrass. Like 

switchgrass, energy cane and 

napiergrass are not expected to be 

traded internationally and their impacts 

on other crops are expected to be 

limited. Increased giant reed demand in 

the U.S. for biofuels is not expected to 

impact existing markets for giant reed, 

which are relatively small niche markets 

(e.g., musical instrument reeds). 

b. Land Use 

In EPA’s RFS2 analysis, switchgrass 

plantings displaced primarily soybeans 

and wheat, and to a lesser extent hay, 

rice, sorghum, and cotton. Energy cane 

and napiergrass, with production 

focused in the southern United States, 

are likely to be grown on land once used 

for pasture, rice, commercial sod, cotton 

or alfalfa, which would likely have less 

of an international indirect impact than 

switchgrass because some of those 

commodities are not as widely traded as 

soybeans or wheat. Given that energy 

cane and napiergrass will likely 

displace the least productive land first, 

EPA concludes that the land use GHG 

impact for energy cane and napiergrass 

per gallon should be no greater and 

likely less than estimated for 

switchgrass. Given that giant reed is in 

early stages of development as an energy 

crop, there is limited information on 

where it will be grown and what crops 

it will displace. We expect giant reed 

will displace the least productive land 

first and would likely have a similar or 

smaller indirect impact associated with 

crop displacement than what we 

assumed for switchgrass. 

Considering the total land potentially 

impacted by all the new feedstocks 

included in this rulemaking would not 

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Federal Register / Vol. 77, No. 3 / Thursday, January 5, 2012 / Rules and Regulations 713 

impact these conclusions (including the 

camelina discussed in the previous 

section and the three energy grasses 

considered here). As discussed 

previously, the camelina is expected to 

be grown on fallow land in the 

Northwest, while energy grasses are 

expected to be grown mainly in the 

south on existing cropland or 

pastureland. In the switchgrass ethanol 

scenario done for the Renewable Fuel 

Standard final rulemaking, total 

cropland acres increases by 4.2 million 

acres, including an increase of 12.5 

million acres of switchgrass, a decrease 

of 4.3 million acres of soybeans, a 1.4 

million acre decrease of wheat acres, a 

decrease of 1 million acres of hay, as 

well as decreases in a variety of other 

crops. Given the higher yields of the 

energy grasses considered here 

compared to switchgrass, there would 

be ample land available for production 

without having any adverse impacts 

beyond what was considered for 

switchgrass production. 

c. Crop Inputs and Feedstock Transport 

EPA also assessed the GHG impacts 

associated with planting, harvesting, 

and transporting energy cane, giant 

reed, and napiergrass feedstocks in 

comparison to switchgrass. Table 6 

shows the assumed 2022 commercialscale production inputs for switchgrass 

(used in the RFS2 rulemaking analysis), 

average energy cane, giant reed, and 

napiergrass production inputs (USDA 

projections and industry data) and the 

associated GHG emissions. 

Available data gathered by EPA 

suggest that energy cane requires on 

average less nitrogen, phosphorous, 

potassium, and pesticide than 

switchgrass per dry ton of biomass, but 

more herbicide, lime, diesel, and 

electricity per unit of biomass. Giant 

reed may require on average less 

nitrogen and insecticide than 

switchgrass, but more phosphorous, 

potassium, herbicide, diesel, and 

electricity per unit of biomass. 

Napiergrass may require similar 

amounts of nitrogen fertilizer 

application as switchgrass, less 

phosphorous, potassium and insecticide 

than switchgrass, but more herbicide, 

lime, diesel, and electricity per unit of 

biomass. 

This assessment assumes production 

of all three new feedstocks uses 

electricity for irrigation given that 

growers will likely irrigate when 

possible to improve yields. Irrigation 

rates will vary depending on the timing 

and amount of rainfall, but for the 

purpose of estimating GHG impacts of 

electricity use for irrigation, we 

assumed a rate similar to what we 

assumed for other irrigated crops in the 

Southwest, South Central, and 

Southeast as shown in Table 6. 

Applying the GHG emission factors 

used in the RFS2 final rule, energy cane 

production results in slightly higher 

GHG emissions relative to switchgrass 

production (an increase of 

approximately 4 kg CO2eq/mmbtu). 

Giant reed production results in slightly 

lower GHG emissions relative to 

switchgrass production (a decrease of 

approximately 2 kg CO2eq/mmbtu). 

Napiergrass production results in 

slightly higher GHG emissions relative 

to switchgrass production (an increase 

of approximately 6 kg CO2eq/mmbtu). 

TABLE 6—PRODUCTION INPUTS AND GHG EMISSIONS FOR SWITCHGRASS, ENERGY CANE, GIANT REED, AND

NAPIERGRASS (BIOCHEMICAL ETHANOL), 2022 

Emission factors 

Switchgrass Energy Cane Giant Reed Napiergrass 

Inputs (per 

dry ton of 

biomass) 

Emissions (per 

mmBtu fuel) 

Inputs (per 

dry ton of 

biomass) 

Emissions (per 

mmBtu fuel) 

Inputs (per 

dry ton of 

biomass) 

Emissions (per 

mmBtu fuel) 

Inputs (per 

dry ton of 

biomass) 

Emissions (per 

mmBtu fuel) 

Nitrogen Fertilizer 3,29 kgCO2e/ton 

of nitrogen.

15.2 lbs .... 3.6 kgCO2e .... 8.4 lbs ...... 2 kgCO2e ....... 5 lbs ......... 1 kgCO2e ....... 10 lbs ....... 2.4 kgCO2e. 

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

Phosphorus Fertilizer.1,12 kgCO2e/ton 

of phosphate.

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

Potassium Fertilizer.743 kgCO2e/ton 

of potassium.

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

Herbicide ............. 23,45 kgCO2e/ 

tons of herbicide.

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

Insecticide (average across regions).27,22 kgCO2e/ 

tons of pesticide.

0.025 lbs .. 0.04 kgCO2e .. 0 lbs ......... 0 kgCO2e ....... 0 lbs ......... 0 kgCO2e ....... 0 lbs ......... 0 kgCO2e. 

Lime .................... 408 kgCO2e/ton 

of lime.

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

Diesel .................. 97 kgCO2e/ 

mmBtu diesel.

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

Electricity (irrigation).220 kgCO2e/ 

mmBtu.

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

Total Emissions.............................. .................. 13 kgCO2e/ 

mmBtu.

.................. 17 kgCO2e/ 

mmBtu.

.................. 11 kgCO2e/ 

mmBtu.

.................. 19 kgCO2e/ 

mmBtu. 

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

giant reed yield of 18 dry tons/acre and 92.3 gal ethanol/dry ton, and 2022 napiergrass yield of 20 dry tons/acre and 92.3 gal ethanol/dry ton. More detail on calculations and assumptions is included in materials to the docket. 

GHG emissions associated with 

distributing energy cane, giant reed, and 

napiergrass feedstocks are expected to 

be similar to EPA’s estimates for 

switchgrass feedstock because they are 

all herbaceous agricultural crops 

requiring similar transport, loading, 

unloading, and storage regimes. Our 

analysis therefore assumes the same 

GHG impact for feedstock distribution 

as we assumed for switchgrass, although 

distributing energy cane, giant reed, and 

napiergrass feedstocks could be less 

GHG intensive because higher yields 

could translate to shorter overall 

hauling distances to storage or biofuel 

production facilities per gallon or Btu of 

final fuel produced. 

2. Fuel Production, Distribution, and 

Use 

Energy cane, giant reed, and 

napiergrass are suitable for the same 

conversion processes as other cellulosic 

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

46The F–T diesel process modeled applies to 

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

feedstocks, such as switchgrass and corn 

stover. Currently available information 

on energy cane, giant reed, and 

napiergrass composition shows that 

their hemicellulose, cellulose, and 

lignin content are comparable to other 

crops that qualify under the RFS 

regulations as feedstocks for the 

production of cellulosic biofuels. Based 

on this similar composition as well as 

conversion yield data provided by 

industry, we applied the same 

production processes that were modeled 

for switchgrass in the final RFS2 rule 

(biochemical ethanol, thermochemical 

ethanol, and Fischer-Tropsch (F–T) 

diesel 46) to energy cane, giant reed, and 

napiergrass. We assumed the GHG 

emissions associated with producing 

biofuels from energy cane, giant reed, 

and napiergrass are similar to what we 

estimated for switchgrass and other 

cellulosic feedstocks. EPA also assumes 

that the distribution and use of biofuel 

made from energy cane, giant reed, and 

napiergrass will not differ significantly 

from similar biofuel produced from 

other cellulosic sources. As was done 

for the switchgrass case, this analysis 

assumes energy grasses grown in the 

United States for production purposes. 

If crops were grown internationally, 

used for biofuel production, and the fuel 

was shipped to the U.S., shipping the 

finished fuel to the U.S. could increase 

transport emissions. However, 

considering the increased transport 

emissions associated with sugarcane 

ethanol distribution to the U.S., this 

would at most add 1–2% to the overall 

lifecycle GHG impacts of the energy 

grasses. 

3. Summary 

Based on our comparison of 

switchgrass and the three feedstocks 

considered here, EPA believes that 

cellulosic biofuel produced from the 

cellulose, hemicellulose and lignin 

portions of energy cane, giant reed, and 

napiergrass has similar or better 

lifecycle GHG impacts than biofuel 

produced from the cellulosic biomass 

from switchgrass. Our analysis suggests 

that the three feedstocks considered 

have GHG impacts associated with 

growing and harvesting the feedstock 

that are similar to switchgrass. 

Emissions from growing and harvesting 

energy cane are approximately 4 kg 

CO2eq/mmBtu higher than switchgrass, 

emissions from growing and harvesting 

giant reed are approximately 2 kg 

CO2eq/mmBtu lower than switchgrass, 

and emissions from growing and 

harvesting napiergrass are 

approximately 6 kg CO2eq/mmBtu 

higher than switchgrass. These are small 

changes in the overall lifecycle, 

representing at most a 6% change in the 

energy grass lifecycle impacts in 

comparison to the petroleum fuel 

baseline. Furthermore, the three 

feedstocks considered are expected to 

have similar or lower GHG emissions 

than switchgrass associated with other 

components of the biofuel lifecycle. 

Under a hypothetical worst case, if 

the calculated increases in growing and 

harvesting the new feedstocks are 

incorporated into the lifecycle GHG 

emissions calculated for switchgrass, 

and other lifecycle components are 

projected as having similar GHG 

impacts to switchgrass (including land 

use change associated with switchgrass 

production), the overall lifecycle GHG 

reductions for biofuel produced from 

energy cane, giant reed, and napiergrass 

still meet the 60% reduction threshold 

for cellulosic biofuel, the lowest being a 

64% reduction (for napiergrass F–T 

diesel) compared to the petroleum 

baseline. We believe these are 

conservative estimates, as use of energy 

cane, giant reed, or napiergrass as a 

feedstock is expected to have smaller 

land-use GHG impacts than switchgrass, 

due to their higher yields. The docket 

for this rule provides additional detail 

on the analysis of energy cane, giant 

reed, and napiergrass as biofuel 

feedstocks. 

Although this analysis assumes 

energy cane, giant reed, and napiergrass 

biofuels produced for sale and use in 

the United States will most likely come 

from domestically produced feedstock, 

we also intend for the approved 

pathways to cover energy cane, giant 

reed, and napiergrass from other 

countries. We do not expect incidental 

amounts of biofuels from feedstocks 

produced in other nations to impact our 

average GHG emissions. Moreover, 

those countries most likely to be 

exporting energy cane, giant reed, or 

napiergrass or biofuels produced from 

these feedstocks are likely to be major 

producers which typically use similar 

cultivars and farming techniques. 

Therefore, GHG emissions from 

producing biofuels with energy cane, 

giant reed, or napiergrass grown in other 

countries should be similar to the GHG 

emissions we estimated for U.S. energy 

cane, giant reed, or napiergrass, though 

they could be slightly (and 

insignificantly) higher or lower. For 

example, the renewable biomass 

provisions under the Energy 

Independence and Security Act would 

prohibit direct conversion of previously 

unfarmed land in other countries into 

cropland for energy grass-based 

renewable fuel production. 

Furthermore, any energy grass 

production on existing cropland 

internationally would not be expected 

to have land use impacts beyond what 

was considered for switchgrass 

production. Even if there were 

unexpected larger differences, EPA 

believes the small amounts of feedstock 

or fuel potentially coming from other 

countries will not impact our threshold 

analysis. 

Based on our assessment of 

switchgrass in the RFS2 final rule and 

this comparison of GHG emissions from 

switchgrass and energy cane, giant reed, 

and napiergrass, we do not expect 

variations to be large enough to bring 

the overall GHG impact of fuel made 

from energy cane, giant reed or napier 

grass to come close to the 60% 

threshold for cellulosic biofuel. 

Therefore, EPA is including cellulosic 

biofuel produced from the cellulose, 

hemicelluloses and lignin portions of 

energy cane, giant reed, and napiergrass 

under the same pathways for which 

cellulosic biomass from switchgrass 

qualifies under the RFS2 final rule. 

C. Lifecycle Greenhouse Gas Emissions 

Analysis for Certain Renewable 

Gasoline and Renewable Gasoline 

Blendstocks Pathways 

In this rule, EPA is also adding 

pathways to Table 1 to § 80.1426 for the 

production of renewable gasoline and 

renewable gasoline blendstock using 

specified feedstocks, fuel production 

processes, and process energy sources. 

The feedstocks we considered are 

generally considered waste feedstocks 

such as crop residues or cellulosic 

components of separated yard waste. 

These feedstocks have been identified 

by the industry as the most likely 

feedstocks for use in making renewable 

gasoline or renewable gasoline 

blendstock in the near term due to their 

availability and low cost. Additionally, 

these feedstocks have already been 

analyzed by EPA as part of the RFS2 

rulemaking for the production of other 

fuel types. Consequently, no new 

modeling is required and we rely on 

earlier assessments of feedstock 

production and distribution for 

assessing the likely lifecycle impact on 

renewable gasoline and renewable 

gasoline blendstock. We have also relied 

on the petroleum gasoline baseline 

assessment from the RFS2 rule for 

estimating the fuel distribution and use 

GHG emissions impacts for renewable 

gasoline and renewable gasoline 

blendstock. Consequently, the only new 

analysis required is of the technologies 

for turning the feedstock into renewable 

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47 Kinchin, Christopher. Catalytic Fast Pyrolysis 

with Upgrading to Gasoline and Diesel Blendstocks. 

National Renewable Energy Laboratory (NREL). 

2011. 

48Aden, Andy. Feedstock Considerations and 

Impacts on Biorefining. National Renewable Energy 

Laboratory (NREL). December 2009. 49Results for feedstock distribution are 

aggregated along with fuel distribution and are 

reported in a later section, see conclusion section. 

gasoline and renewable gasoline 

blendstock. 

1. Feedstock Production and 

Distribution 

EPA has evaluated renewable gasoline 

and renewable gasoline blendstock 

pathways that utilize cellulosic 

feedstocks currently included in Table 1 

to § 80.1426 of the regulations. The 

following feedstocks were evaluated: 

• Cellulosic biomass from crop 

residue, slash, pre-commercial 

thinnings and tree residue, annual cover 

crops; 

• Cellulosic components of separated 

yard waste; 

• Cellulosic components of separated 

food waste; and 

• Cellulosic components of separated 

MSW. 

The FASOM and FAPRI models were 

used to analyze the GHG impacts of the 

feedstock production portion of a fuel’s 

lifecycle. In the RFS2 rulemaking, 

FASOM and FAPRI modeling was 

performed to analyze the emissions 

impact of using corn stover as a biofuel 

feedstock and this modeling was 

extended to some additional feedstock 

sources considered similar to corn 

stover. This approach was used for crop 

residues, slash, pre-commercial 

thinnings, tree residue and cellulosic 

components of separated yard, food, and 

MSW. These feedstocks are all excess 

materials and thus, like corn stover, 

were determined to have little or no 

land use change GHG impacts. Their 

GHG emission impacts are mainly 

associated with collection, transport, 

and processing into biofuel. See the 

RFS2 rulemaking preamble for further 

discussion. We used the results of the 

corn stover modeling in this analysis to 

estimate the upper bound of agricultural 

sector impacts from the production of 

the various cellulosic feedstocks noted 

above. 

The agriculture sector modeling 

results for corn stover represent all of 

the direct and significant indirect 

emissions in the agriculture sector 

(feedstock production emissions) for a 

certain quantity of corn stover 

produced. For the RFS2 rulemaking, 

this was roughly 62 million dry tons of 

corn stover to produce 5.7 billion 

gallons of ethanol assuming biochemical 

fermentation to ethanol processing. We 

have calculated GHG emissions from 

feedstock production for that amount of 

corn stover. The GHG emissions were 

then divided by the total heating value 

of the fuel to get feedstock production 

emissions per mmBtu of fuel. In 

addition to the biochemical ethanol 

process, a similar analysis was 

completed for thermochemical ethanol 

and F–T diesel pathways as part of the 

RFS2 rulemaking. 

In this rulemaking we are analyzing 

renewable gasoline and renewable 

gasoline blendstock produced from corn 

stover (and, by extension, other waste 

feedstocks). The number of gallons of 

fuel produced from a ton of corn stover 

(modeled process yields) is specific to 

the process used to produce renewable 

fuel. EPA has adjusted the results of the 

earlier corn stover modeling to reflect 

the different process yields and heating 

value of renewable gasoline or 

renewable gasoline blendstock product. 

The results of this calculation are shown 

below in Table 7. 

We based our process yields and 

heating values for renewable gasoline 

and renewable gasoline blendstock on 

several process technologies 

representative of technologies 

anticipated to be used in producing 

these fuels. As discussed later in this 

section, there are four main types of fuel 

production technologies available for 

producing renewable gasoline. These 

four processes can be characterized as 

(1) thermochemical gasification, (2) 

catalytic pyrolysis and upgrading to 

renewable gasoline or renewable gaoline 

blendstock (‘‘catalytic pyrolysis’’), (3) 

biochemical fermentation with 

upgrading to renewable gasoline or 

renewable gasoline blendstock via 

carboxylic acid (‘‘fermentation and 

upgrading’’), and (4) direct biochemical 

fermentation to renewable gasoline and 

renewable gasoline blendstock (‘‘direct 

fermentation’’). The thermochemical 

gasification process was modeled as part 

of the RFS2 final rule, included as 

producing naptha via the F–T process. 

Our analysis of the catalytic pyrolysis 

process was based on the modeling 

work completed by the National 

Renewable Energy Laboratory (NREL) 

for this rule for a process to make 

renewable gasoline blendstock.47 The 

fermentation and upgrading process was 

modeled based on confidential business 

information (CBI) from industry for a 

unique process which uses biochemical 

conversion of cellulose to renewable 

gasoline via a carboxylic acid route. In 

addition, we have qualitatively assessed 

the direct fermentation to renewable 

gasoline process based on similarities to 

the biochemical ethanol process already 

analyzed as part of the RFS2 

rulemaking. The fuel production section 

below provides further discussion on 

extending the GHG emissions results of 

the biochemical ethanol fermentation 

process to a biochemical renewable 

gasoline or renewable gasoline 

blendstock fermentation process. In 

some cases, the available data sources 

included process yields for renewable 

gasoline or renewable gasoline 

blendstock produced from wood chips 

rather than corn stover which was 

specifically modeled as a feedstock in 

the RFS2 final rule. We believe that the 

process yields are not significantly 

impacted by the source of cellulosic 

material whether the cellulosic material 

comes from residue such as corn stover 

or wood material such as from tree 

residues. We made the simplifying 

assumption that one dry ton of wood 

feedstock produces the same volume of 

renewable gasoline or renewable 

gasoline blendstock as one dry ton of 

corn stover. We believe this is 

reasonable considering that the RFS2 

rulemaking analyses for biochemical 

ethanol and thermochemical F–T diesel 

processes showed limited variation in 

process yields between different 

feedstocks for a given process 

technology.48 In addition, since the 

renewable gasoline and renewable 

gasoline blendstock pathways include 

feedstocks that were already considered 

as part of the RFS2 final rule, the 

existing feedstock lifecycle GHG 

impacts for distribution of corn stover 

were also applied to this analysis.49

Feedstock production emissions are 

shown in Table 7 below for corn stover. 

Corn stover feedstock production 

emissions are mainly a result of corn 

stover removal increasing the 

profitability of corn production 

(resulting in shifts in cropland and thus 

slight emission impacts) and also the 

need for additional fertilizer inputs to 

replace the nutrients lost when corn 

stover is removed. However, corn stover 

removal also has an emissions benefit as 

it encourages the use of no-till farming 

which results in the lowering of 

domestic land use change emissions. 

This change to no-till farming results in 

a negative value for domestic land use 

change emission impacts (see also Table 

13 below). For other waste feedstocks 

(e.g., tree residues and cellulosic 

components of separate yard, food, and 

MSW), the feedstock production 

emissions are even lower than the 

values shown for corn stover since the 

use of such feedstocks does not require 

land use changes or additional 

agricultural inputs. Therefore, we 

conclude that if the use of corn stover 

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

50See http://www.epa.gov/otaq/fuels/ 

renewablefuels/compliancehelp/rfs2-lcapathways.htm for list of petitions received by EPA. 51Regalbuto, John. ‘‘An NSF perspective on next 

generation hydrocarbon biorefineries,’’ Computers 

and Chemical Engineering 34 (2010) 1393–1396. 

February 2010. 

52Serrano-Ruiz, J., Dumesic, James. ‘‘Catalytic 

routes for the conversion of biomass into liquid 

hydrocarbon transportation fuels,’’ Energy 

Environmental Science (2011) 4, 83–99. 

as a feedstock in the production of 

renewable gasoline and renewable 

gasoline blendstock yields lifecycle 

GHG emissions results for the resulting 

fuel that qualify it as cellulosic biofuel 

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

reduction as compared to conventional 

fuel), then the use of other waste 

feedstocks with little or no land use 

change emissions will also result in 

renewable gasoline or renewable 

gasoline blendstock that qualifies as 

cellulosic biofuel. 

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

PATHWAYS USING CORN STOVER

Feedstock production emission sources 

Catalytic pyrolysis 

to renewable gasoline blendstock 

(g CO2-eq./ 

mmBtu) 

Biochemical fermentation to renewable gasoline 

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 

The results in Table 7 differ for the 

different pathways considered because 

of the different amounts of corn stover 

used to produce the same amount of 

fuel in each case. Table 7 only considers 

the feedstock production impacts 

associated with the renewable gasoline 

pathways, other aspects of the lifecycle 

are discussed in the following sections. 

2. Fuel Distribution 

A petroleum gasoline baseline was 

developed as part of the RFS2 final rule 

which included estimates for fuel 

distribution emissions. Since renewable 

gasoline and renewable gasoline 

blendstocks when blended into gasoline 

are similar to petroleum gasoline, it is 

reasonable to assume similar fuel 

distribution emissions. Therefore, the 

existing fuel distribution lifecycle GHG 

impacts of the petroleum gasoline 

baseline from the RFS2 final rule were 

applied to this analysis. 

3. Use of the Fuel 

A petroleum gasoline baseline was 

developed as part of the RFS2 final rule 

which estimated the tailpipe emissions 

from fuel combustion. Since renewable 

gasoline and renewable gasoline 

blendstock are similar to petroleum 

gasoline, the non-CO2 combustion 

emissions calculated as part of the RFS2 

final rule for petroleum gasoline were 

applied to our analysis of the renewable 

gasoline and renewable gasoline 

blendstock pathways. Only non-CO2

emissions were included since carbon 

fluxes from land use change are 

accounted for as part of the biomass 

feedstock production. 

4. Fuel Production 

In the RFS2 rulemaking, EPA 

analyzed several of the main cellulosic 

biofuel pathways: a biochemical 

fermentation process to ethanol and two 

thermochemical gasification processes, 

one producing mixed alcohols 

(primarily ethanol) and the other one 

producing mixed hydrocarbons 

(primarily diesel fuel). These pathways 

all exceeded the 60% lifecycle GHG 

threshold requirements for cellulosic 

biofuel using the specified feedstocks. 

Refer to the preamble and regulatory 

impact analysis (RIA) from the final 

RFS2 rule for more details. From these 

analyses, it was determined that ethanol 

and diesel fuel produced from the 

specified cellulosic feedstocks and 

processes would be eligible for 

cellulosic and advanced biofuel RINs. 

The thermochemical gasification 

process to diesel fuel (via F–T synthesis) 

also produces a smaller portion of 

naphtha, a gasoline blendstock. In the 

final RFS2 rule, naphtha produced with 

specified cellulosic feedstocks by a F–T 

process was included as exceeding the 

60% lifecycle GHG threshold, with an 

applicable D–Code of 3, in Table 1 to 

§ 80.1426. 

Since the final RFS2 rule was 

released, EPA has received several 

petitions and inquiries that suggest that 

renewable gasoline or renewable 

gasoline blendstock produced using 

processes other than the F–T process 

could also qualify for a similar D–Code 

of 3.50 For the reasons described below, 

we have decided to authorize the 

generation of RINs with a D code of 3 

for renewable gasoline and renewable 

gasoline blendstock produced using 

specified cellulosic feedstocks for the 

processes considered here. 

Several routes have been identified as 

available for the production of 

renewable gasoline and renewable 

gasoline blendstock from renewable 

biomass. These include catalytic 

pyrolysis and upgrading to renewable 

gasoline or renewable gasoline 

blendstock (‘‘catalytic pyrolysis’’), 

biochemical fermentation with 

upgrading to renewable gasoline or 

renewable gasoline blendstock via 

carboxylic acid (‘‘fermentation and 

upgrading’’), and direct biochemical 

fermentation to renewable gasoline and 

renewable gasoline blendstock (‘‘direct 

fermentation’’).51 52

Similar to how we analyzed several of 

the main routes for cellulosic ethanol 

and cellulosic diesel for the final RFS2 

rule, we have chosen to analyze the 

main renewable gasoline and renewable 

gasoline blendstock pathways in order 

to estimate the potential GHG reduction 

profile for renewable gasoline and 

renewable gasoline blendstock across a 

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Federal Register / Vol. 77, No. 3 / Thursday, January 5, 2012 / Rules and Regulations 717 

53 Kinchin, Christopher. Catalytic Fast Pyrolysis 

with Upgrading to Gasoline and Diesel Blendstocks. 

National Renewable Energy Laboratory (NREL). 

2011. 54A 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. 

55Hydrogen emissions are modeled as natural gas 

and electricity demands. 

range of other production technologies 

for which we are confident will have at 

least as great of GHG emission 

reductions as those specifically 

analyzed. 

a. Catalytic Pyrolysis to Renewable 

Gasoline and Renewable Gasoline 

Blendstock 

The first production process we 

investigated for this rule is a catalytic 

fast pyrolysis route to bio-oils with 

upgrading to a renewable gasoline or a 

renewable gasoline blendstock. We 

utilized process modeling results from 

the National Renewable Energy 

Laboratory (NREL). Information 

provided by industry and claimed as 

CBI are based on similar processing 

methods and suggest similar results 

than those reported by NREL. Details on 

the NREL modeling are described 

further in a technical report available 

through the docket.53 Catalytic pyrolysis 

involves the rapid heating of biomass to 

about 500°C at slightly above 

atmospheric pressure. The rapid heating 

thermally decomposes biomass, 

converting it into pyrolysis vapor, 

which is condensed into a liquid bio-oil. 

The liquid bio-oil can then be upgraded 

using conventional hydroprocessing 

technology and further separated into 

gasoline and diesel blendstock streams 

(cellulosic diesel from catalytic 

pyrolysis is already included as an 

acceptable pathway in the RFS2 

program). Some industry sources also 

expect to produce smaller fractions of 

heating oil in addition to gasoline and 

diesel blendstocks. Excess electricity 

from the process is also accounted for in 

our modeling as a co-product credit in 

which any excess displaces U.S. average 

grid electricity. Excess electricity is 

generated from the use of co-product 

coke/char and product gases and is 

available because internal electricity 

demands are fully met. The estimated 

energy inputs and electricity credits 

shown in Table 8, below, utilize the 

data provided by the NREL process 

modeling. However, Industry sources 

also identified potential areas for 

improvements in energy use, such as the 

use of biomass fired dryers instead of 

natural gas fired dryers for drying 

incoming wet feedstocks and increased 

turbine efficiencies for electricity 

production which may result in lower 

energy consumption than estimated by 

NREL and thus improve GHG 

performance compared to our estimates 

here. 

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

The emissions from energy inputs 

were calculated by multiplying the 

amount of energy by emission factors for 

fuel production and combustion, based 

on the same method and factors used in 

the RFS2 final rulemaking. The 

emission factors for the different fuel 

types are from GREET and were based 

on assumed carbon contents of the 

different process fuels. The emissions 

from producing electricity in the U.S. 

were also taken from GREET and 

represent average U.S. grid electricity 

production emissions. 

The major factors influencing the 

emissions from the fuel production 

stage of the catalytic pyrolysis pathway 

are the use of natural gas (mainly due 

to hydrogen production for 

hydroprocessing) and the co-products 

available for additional heat and power 

generation.54 See Table 9 for a summary 

of emissions from fuel production. 

TABLE 9—FUEL PRODUCTION EMISSIONS FOR CATALYTIC PYROLYSIS

TO RENEWABLE GASOLINE

BLENDSTOCK USING CORN STOVER

Lifecycle stage 

Catalytic pyrolysis to renewable 

gasoline 

blendstock (g 

CO2-eq./mmBtu) 

On-Site & Upstream Emissions (Natural Gas & 

Biomass*) ...................... 31,000 

Electricity Co-Product 

Credit ............................. ¥3,000 

Total Fuel Production 

Emissions: ..................... 28,000 

Only non-CO2 combustion emissions from 

biomass. 

b. Fermentation and Upgrading to 

Renewable Gasoline and Renewable 

Gasoline Blendstock 

The second production process we 

investigated is a biochemical 

fermentation process to intermediate 

carboxylic acids with catalytic 

upgrading to renewable gasoline or 

renewable gasoline blendstock. This 

process involves the fermentation of 

biomass using a mixed-culture of 

microorganisms that produce a variety 

of carboxylic acids. If the feedstock has 

high lignin content, then the biomass is 

pretreated to enhance digestibility. The 

acids are then neutralized to carboxylate 

salts and further converted to ketones 

and alcohols for refining into gasoline, 

diesel, and jet fuel. 

The process requires the use of 

natural gas and hydrogen inputs.55 No 

purchased electricity is required as 

lignin is projected to be used to meet all 

facility demands as well as provide 

excess electricity to the grid. EPA used 

the estimated energy and material 

inputs along with emission factors to 

estimate the GHG emissions from this 

process. The energy inputs and 

electricity credits are shown in Table 

10, below. These inputs are based on 

Confidential Business Information (CBI), 

rounded to the nearest 1000 units, 

provided by industry as part of the 

petition process for new fuel pathways. 

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

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

routes for the conversion of biomass into liquid 

hydrocarbon transportation fuels,’’ Energy 

Environmental Science (2011) 4, 83–99. 

57Numbers do not add up due to rounding. 

58Memorandum to the Air and Radiation Docket 

EPA–HQ–OAR–2011–0542 ‘‘Supplemental 

Information for Renewable Gasoline and Renewable 

Gasoline Blendstock Pathways Under the 

Renewable Fuel Standard (RFS2) Program’’. 

TABLE 10—2022 ENERGY USE AT CELLULOSIC FACILITY

[Btu/gal] 

Technology Biomass use Natural gas use Purchased 

electricity Sold electricity 

Biochemical Fermentation to Renewable Gasoline or Renewable 

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

The process also uses a small amount 

of buffer material as neutralizer which 

was not included in the GHG lifecycle 

results due to its likely negligible 

emissions impact. The GHG emissions 

estimates from the fuel production stage 

are seen in Table 11. 

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

RENEWABLE GASOLINE BLENDSTOCK

VIA CARBOXYLIC ACID USING CORN

STOVER

Lifecycle stage 

GHG Emissions 

(g CO2-eq./ 

mmBtu) 

On-Site & Upstream Emissions (Natural Gas & 

Biomass*) ...................... 33,000 

Electricity Co-Product 

Credit ............................. ¥3,000 

Total Fuel Production 

Emissions: .............. 30,000 

*Only non-CO2 combustion emissions from 

biomass 

c. Direct Fermentation to Renewable 

Gasoline and Renewable Gasoline 

Blendstock 

The third production process we 

investigated involves the use of 

microorganisms to ferment sugars 

hydrolyzed from cellulose directly into 

hydrocarbons which could be either a 

complete fuel as renewable gasoline or 

a renewable gasoline blendstock. The 

process is similar to the biochemical 

fermentation to ethanol pathway 

modeled for the final RFS2 rule with the 

major difference being the end fuel 

product, hydrocarbons instead of 

ethanol. Researchers believe that this 

new technology could achieve 

improvements over classical 

fermentation approaches because 

hydrocarbons separate spontaneously 

from the aqueous phase, thereby 

avoiding poisoning of microbes by the 

accumulated products and facilitating 

separation/collection of alkanes from 

the reaction medium.56 In other words, 

some energy savings may result because 

fewer separation unit operations could 

be required for separating the final 

product from other reactants and there 

may be better conversion yields as the 

fermentation microorganisms are not 

poisoned when interacting with 

accumulated products. We also expect 

that the lignin/byproduct portions of the 

biomass from the fermentation to 

hydrocarbon process could be converted 

into heat and electricity for internal 

demands or for export, similar to the 

biochemical fermentation to ethanol 

pathway. 

Therefore, we can conservatively 

extend our final RFS2 rule biochemical 

fermentation to ethanol process results 

to a similar (but likely slightly 

improved) process that instead produces 

hydrocarbons. Since the final RFS2 rule 

cellulosic ethanol GHG results were 

well above the 60% GHG reduction 

threshold for cellulosic biofuels, if 

actual emissions from other necessary 

changes to the direct biochemical 

fermentation to hydrocarbons process 

represent some small increment in GHG 

emissions, the pathway would still 

likely meet the threshold. Table 12 is 

our qualitative assessment of the 

potential emissions reductions from a 

process using biochemical fermentation 

to cellulosic hydrocarbons assuming 

similarities to the biochemical 

fermentation to cellulosic ethanol route 

from the final RFS2 rule. 

TABLE 12—FUEL PRODUCTION EMISSIONS FOR RFS2 CELLULOSIC BIOCHEMICAL ETHANOL COMPARED TO DIRECT

BIOCHEMICAL FERMENTATION TO RENEWABLE GASOLINE OR RENEWABLE GASOLINE BLENDSTOCK USING CORN STOVER

Lifecycle stage 

RFS2 Cellulosic 

biochemical ethanol emissions (g 

CO2-eq./mmBtu) 

Direct biochemical 

fermentation to renewable gasoline 

and renewable 

gasoline 

blendstock emissions (g CO2-eq./ 

mmBtu) 

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

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

Total Fuel Production Emissions 57 ...................................................................................................... ¥33,000 < or = ¥33,000 

Table 13 below breaks down by stage 

the lifecycle GHG emissions for the 

renewable gasoline and renewable 

gasoline blendstock pathways using 

corn stover and the 2005 petroleum 

baseline. The table demonstrates the 

contribution of each stage in the fuel 

pathway and its relative significance in 

terms of GHG emissions. These results 

are also presented in graphical form in 

a supplemental memorandum to the 

docket.58 As noted above, these analyses 

assume natural gas as the process energy 

when needed; using biogas or biomass 

as process energy would result in an 

even better lifecycle GHG impact. 

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Federal Register / Vol. 77, No. 3 / Thursday, January 5, 2012 / Rules and Regulations 719 

59Regalbuto, John. ‘‘An NSF perspective on next 

generation hydrocarbon biorefineries,’’ Computers 

and Chemical Engineering 34 (2010) 1393–1396. 

February 2010. 

60Serrano-Ruiz, J., Dumesic, James. ‘‘Catalytic 

routes for the conversion of biomass into liquid 

hydrocarbon transportation fuels,’’ Energy 

Environmental Science (2011) 4, 83–99. 

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 

to renewable gasoline blendstock 

Biochemical fermentation to renewable gasoline 

via carboxylic acid 

Direct biochemical 

fermentation to renewable gasoline 

and renewable 

gasoline 

blendstock 

2005 gasoline 

baseline 

Net Domestic Agriculture (w/o land use change) .................... 9 8 ∼ 11 ..............................

Net International Agriculture (w/o land use change): 

Domestic Land Use Change ............................................ ¥9 ¥8 ∼ ¥11 ..............................

International Land Use Change: 

Fuel Production ................................................................ 28 30 < or = ¥33 19 

Fuel and Feedstock Transport ......................................... 2 2 ∼ 2 * 

Tailpipe Emissions ............................................................ 2 2 ∼ 1 79 

Total Emissions ......................................................... 32 34 < or = ¥29 98 

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

* Emissions included in fuel production stage. 

d. Extension of Modeling Results to 

Other Production Processes Producing 

Renewable Gasoline or Renewable 

Gasoline Blendstock 

In the RFS2 rulemaking, we modeled 

the GHG emissions results from the 

biochemical fermentation process to 

ethanol, thermochemical gasification 

processes to mixed alcohols (primarily 

ethanol) and mixed hydrocarbons 

(primarily diesel fuel). We extended 

these modeled process results to apply 

when the biofuel was produced from 

‘‘any’’ process. We determined that 

since we modeled multiple cellulosic 

biofuel processes and all were shown to 

exceed the 60% lifecycle GHG threshold 

requirements for cellulosic biofuel using 

the specified feedstocks its was 

reasonable to extend to other processes 

that might develop as these would likely 

represent improvements over existing 

processes as the industry works to 

improve the economics of cellulosic 

biofuel production by, for example, 

reducing energy consumption and 

improving process yields. Similarly, this 

rule assesses multiple processes for the 

production of renewable gasoline and 

renewable gasoline blendstocks and all 

were shown to exceed the 60% lifecycle 

GHG threshold requirements for 

cellulosic biofuel using specified 

feedstocks. 

As was the case in our earlier 

rulemaking, a couple reasons in 

particular support extending our 

modeling results to other production 

process producing renewable gasoline 

or renewable gasoline blendstock from 

cellulosic feedstock. Under this rule we 

analyzed the core technologies most 

likely available through 2022 for 

production of renewable gasoline and 

renewable gasoline blendstock routes 

from cellulosic feedstock as shown in 

literature. 59 60 The two primary routes 

for renewable gasoline and renewable 

gasoline blendstock production from 

cellulosic feedstock can be classified as 

either thermochemical or biological. 

Each of these two major categories has 

two subcategories. The processes under 

the thermochemical category include: 

• Pyrolysis—in which cellulosic 

biomass is decomposed with 

temperature to bio-oils and requires 

further catalytic processing to produce a 

finished fuel. 

• Gasification—in which cellulosic 

biomass is decomposed to syngas with 

further catalytic processing of methanol 

to gasoline or through Fischer-Tropsch 

(F–T) synthesis to gasoline. 

The processes under the biochemical 

category include: 

• Direct fermentation—requires the 

release of sugars from biomass and the 

use of ‘‘synthetic biology’’ in which 

microorganisms are altered to ferment 

sugars straight into hydrocarbons 

instead of alcohols. 

• Fermentation w/catalytic 

upgrading—requires the release of 

sugars from biomass and aqueous- or 

liquid-phase processing of sugars or 

intermediate fermentation products into 

hydrocarbons using solid catalysts, 

As part of the modeling effort here, as 

well as for the RFS2 final rule, we have 

considered the lifecycle GHG impacts of 

the four possible production 

technologies mentioned above. The 

pyrolysis, direct fermentation, and 

fermentation with catalytic upgrading 

are considered in this rule and the 

gasification route was already included 

in the RFS2 final rule. In all cases, the 

processes that we have considered meet 

the 60% lifecycle GHG reduction 

required for cellulosic biofuels. 

Furthermore, we believe that the results 

from our modeling would cover all the 

likely variations within these potential 

routes for producing renewable gasoline 

and renewable gasoline blendstock 

which also use natural gas, biogas or 

biomass for process energy and that all 

such production variations would also 

meet the 60% lifecycle threshold. 

The main reason for this is that we 

believe that our energy input 

assumptions are reasonable at this time 

but probably in some cases conservative 

for commercial scale cellulosic 

facilities. The cellulosic industry is in 

its early stages of development and 

many of the estimates of process 

technology GHG impacts is based on 

pre-commercial scale assessments and 

demonstration programs. Commercial 

scale cellulosic facilities will continue 

to make efficiency improvements over 

time to maximize their fuel products/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 

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

61 Kinchin, Christopher. Catalytic Fast Pyrolysis 

with Upgrading to Gasoline and Diesel Blendstocks. 

National Renewable Energy Laboratory (NREL). 

2011. 

lignin or waste byproducts; we also ran 

a sensitivity case where no electricity 

credit was given. We found that all of 

the routes analyzed would still pass the 

GHG threshold without an electricity 

credit, providing confidence that over 

the range of technology options, these 

process technologies will surely allow 

the cellulosic biofuel produced to 

exceed the threshold for cellulosic 

biouel GHG performance. Without 

excess electricity production the 

catalytic pyrolysis pathway results in a 

65% lifecycle GHG reduction, the 

biochemical fermentation via carboxylic 

acid pathway results in a 62% lifecycle 

GHG reduction, and the direct 

biochemical fermentation pathway 

results in a 93% reduction in lifecycle 

GHG emissions compared to the 

petroleum fuel baseline. 

Additionally, while the final results 

reported in this rule include an 

electricity credit, this electricity credit 

is based on current technology for 

generating electricity; it is possible that 

over the next decade as cellulosic 

biofuel production matures, the 

efficiency with which electricity is 

generated at these facilities will also 

improve. Such efficiency improvements 

will tend to improve the GHG 

performance for cellulosic biofuel 

technologies in general including those 

used to produce renewable gasoline. 

Furthermore, industry has identified 

other areas for energy improvements 

which our current pathway analyses do 

not include. Therefore, the results we 

have come up with for the individual 

pathway types represent conservative 

estimates and any variations in the 

pathways considered are likely to result 

in greater GHG reductions that what is 

considered here. For example, the 

variation of the catalytic pyrolysis route 

considered here resulted in a 67% 

reduction in lifecycle GHG emissions 

compared to the petroleum baseline. 

However, as was mentioned this was 

based on data from our NREL modeling 

and industry CBI data indicated more 

efficient energy performance which, if 

realized, would improve GHG 

performance. Another area for 

improvement in this pathway could be 

the use of anaerobic digestion to treat 

organics in waste water. If the anaerobic 

digestion is on-site, then enough biogas 

could potentially be produced to replace 

all of the fossil natural gas used as fuel 

and about half the natural gas fed for 

hydrogen production.61 Thus, fossil 

natural gas consumption could be 

further minimized under certain 

scenarios. We believe that as 

commercial scale cellulosic facilities 

develop, more of these improvements 

will be made to maximize the use of all 

the biomass and waste byproducts 

available to bring the facility closer to 

energy self-sufficiency. These 

improvements could help to increase 

the economic profitability for cellulosic 

facilities where fossil energy inputs 

become costly to purchase. Therefore 

we can extend the modeling results for 

our pyrolysis route to all variations of 

this production technology which use 

natural gas, biogas or biomass for 

production energy for producing 

renewable gasoline or renewable 

gasoline blendstock. 

The F–T gasification technology route 

considered as part of the RFS2 final rule 

resulted in an approximately 91% 

reduction in lifecycle GHG emissions 

compared to the petroleum baseline. 

This could be considered a conservative 

estimate as the process did not assume 

any excess electricity production, which 

as mentioned above could lead to 

additional GHG reductions. The F–T 

process involves gasifying biomass into 

syngas (mix of H2 and CO) and then 

converting the syngas through a 

catalytic process into a hydrocarbon mix 

that is further refined into finished 

product. The F–T process considered 

was based on producing both gasoline 

and diesel fuel so that it was not 

optimized for renewable gasoline 

production. A process for producing 

primarily renewable gasoline rather 

than diesel from a gasification route 

should not result in a significantly 

worse GHG impacts compared to the 

mixed fuel process analyzed. 

Furthermore, as the lifecycle GHG 

reduction from the F–T process 

considered was around 91%, there is 

considerable room for variations in this 

route to still meet the 60% lifecycle 

GHG reduction threshold for cellulosic 

fuels. Therefore, in addition to the F–T 

process orginially analyzed for 

producing naphtha, we can extend the 

results based on the above analyses to 

include all variations of the gasification 

route which use natural gas, biogas or 

biomass for production energy for 

producing renewable gasoline or 

renewable gasoline blendstock. These 

variations include for example different 

catalysts and different refining 

processes to produce different mixes of 

final fuel product. While the current 

Table 1 entry in the regulations does not 

specify process energy sources, we are 

adding these specific eligible energy 

sources since we have not analyzed 

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

allowing the pathway to meet the GHG 

performance threshold. 

There is an even wider gap between 

the results modeled for the direct 

fermentation route and the cellulosic 

lifecycle GHG threshold. The variation 

we considered for the direct 

fermentation process resulted in an 

approximately 129% reduction in 

lifecycle GHG emissions compared to 

the petroleum baseline. This process did 

consider production of electricity as 

part of the process but as mentioned 

even if this was not the case the 

pathway would still easily fall below 

the 60% lifecycle threshold for 

cellulosic biofuels. If actual emissions 

from other necessary changes to the 

direct biochemical fermentation to 

hydrocarbons process represent some 

small increment in GHG emissions, the 

pathway would still likely meet the 

threshold. Therefore, we can extend the 

results to all variations of the direct 

biochemical route for renewable 

gasoline or renewable gasoline 

blendstock production which use 

natural gas, biogas or biomass for 

production energy. 

The biochemical with catalytic 

upgrading route that we evaluated 

resulted in a 65% reduction in GHG 

emissions compared to the petroleum 

baseline. However, this can be 

considered a conservative estimate. For 

instance, the biochemical fermentation 

to gasoline via carboxylic acid route 

considered did not include the potential 

for generating steam from the 

combustion of undigested biomass and 

then using this steam for process energy. 

If this had been included, natural gas 

consumption could potentially be 

decreased which would lower the 

potential GHG emissions estimated from 

the process. Therefore, the scenario 

analyzed could be considered 

conservative in estimating actual natural 

gas usage. As was the case with the 

pyrolysis route considered, we believe 

that as commercial scale cellulosic 

facilities develop, improvements will be 

made to maximize the use of all the 

biomass and waste byproducts available 

to bring the facility closer to energy selfsufficiency. These improvements help 

to increase the economic profitability 

for cellulosic facilities where fossil 

energy inputs become costly to 

purchase. The processes we analyzed 

for this rulemaking utilized a mix of 

natural gas and biomass for process 

energy, with biogas replacing natural 

gas providing improved GHG 

performance. We have not analyzed 

other fuel types (e.g., coal) and are 

therefore not approving processes that 

utilized other fuel sources at this point. 

Therefore, we are extending our results 

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62Commonly used base catalysts include sodium 

hydroxide (NaOH), potassium hydroxide (KOH) and 

sodium methoxide (NaOCH3). 

to include all variations of the 

biochemical with catalytic upgrading 

process utilizing natural gas, biogas or 

biomass for process energy. 

While actual cellulosic facilities may 

show some modifications to the process 

scenarios we have already analyzed, our 

results give a good indication of the 

range of emissions we could expect 

from processes producing renewable 

gasoline and renewable gasoline 

blendstock from cellulosic feedstock, all 

of which meet the 60% cellulosic 

biofuel threshold (assuming they are 

utilizing natural gas, biogas or biomass 

for process energy). Technology changes 

in the future are likely to increase 

efficiency to maximize profits, while 

also lowering lifecycle GHG emissions. 

Therefore, we have concluded that since 

all of the renewable gasoline or 

renewable gasoline blendstock fuel 

processing methods we have analyzed 

exceed the 60% threshold using specific 

cellulosic feedstock types, we can 

conclude that processes producing 

renewable gasoline or renewable 

gasoline blendstock that fit within the 

categories of process analyzed here and 

are produced from the same feedstock 

types and using natural gas, biogas or 

biomass for process energy use will also 

meet the 60% GHG reduction threshold. 

In addition, while other technologies 

may develop, we expect that they will 

only become commercially competitive 

if they have better yield (more gallons 

per ton of feedstock) or lower 

production cost due to lower energy 

consumption. Both of these factors 

would suggest better GHG performance. 

This would certainly be the case if such 

processes also relied upon using biogas 

and/or biomass as the primary energy 

source. Therefore based on our review 

of the existing primary cellulosic biofuel 

production processes, likely GHG 

emission improvements for existing or 

new technologies, and consideration of 

the positive GHG emissions benefits 

associated with using biogas and/or 

biomass for process energy, we are 

approving for cellulosic RIN generation 

any process for renewable gasoline and 

renewable gasoline blendstock 

production using specified cellulosic 

biomass feedstocks as long as the 

process utilizes biogas and/or biomass 

for all process energy. 

5. Summary 

Three renewable gasoline and 

renewable gasoline blendstock 

pathways were compared to baseline 

petroleum gasoline, using the same 

value for baseline gasoline as in the 

RFS2 final rule analysis. The results of 

the analysis indicate that the renewable 

gasoline and renewable gasoline 

blendstock pathways result in a GHG 

emissions reduction of 65–129% or 

better compared to the gasoline fuel it 

would replace using corn stover as a 

feedstock. Since the renewable gasoline 

and renewable gasoline blendstock 

pathways which use corn stover as a 

feedstock all exceed the 60% lifecycle 

GHG threshold requirements for 

cellulosic biofuel, and since these 

pathways capture the likely current 

technologies and since future 

technology improvements are likely to 

increase efficiency and lower GHG 

emissions, we have determined that all 

processes producing renewable gasoline 

or renewable gasoline blendstock from 

corn stover can qualify if they fall in the 

following process characterizations: 

• Catalytic pyrolysis and upgrading 

utilizing natural gas, biogas, and/or 

biomass as the only process energy 

sources. 

• Gasification and upgrading utilizing 

natural gas, biogas, and/or biomass as 

the only process energy sources. 

• Direct fermentation utilizing natural 

gas, biogas, and/or biomass as the only 

process energy sources. 

• Fermentation and upgrading 

utilizing natural gas, biogas, and/or 

biomass as the only process energy 

sources. 

• Any process utilizing biogas and/or 

biomass as the only process energy 

sources. 

As was the case for extending corn 

stover results to other feedstocks in the 

RFS2 final rule, these results are also 

reasonably extended to feedstocks with 

similar or lower GHG emissions 

profiles, including the following 

feedstocks: 

• Cellulosic biomass from crop 

residue, slash, pre-commercial 

thinnings and tree residue, annual cover 

crops; 

• Cellulosic components of separated 

yard waste; 

• Cellulosic components of separated 

food waste; and 

• Cellulosic components of separated 

MSW. 

For more information on the 

reasoning for extension to these other 

feedstocks refer to the feedstock 

production and distribution section or 

the RFS2 rulemaking (75 FR 14793– 

14795). 

Based on these results, today’s rule 

includes pathways for the generation of 

cellulosic biofuel RINs for renewable 

gasoline or renewable gasoline 

blendstock produced by catalytic 

pyrolysis and upgrading, gasification 

and upgrading, direct fermentation, 

fermentation and upgrading, all 

utilizing natural gas, biogas, and/or 

biomass as the only process energy 

sources or any process utilizing biogas 

and/or biomass as the only energy 

sources, and using corn stover as a 

feedstock or the feedstocks noted above. 

In order to qualify for RIN generation, 

the fuel must meet the other definitional 

criteria for renewable fuel (e.g., 

produced from renewable biomass, and 

used to reduce or replace 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 

Table 14, shown below, includes 

pathways for biodiesel using specified 

feedstocks and the production process 

transesterification. Transesterification is 

the most commonly used method to 

produce biodiesel (i.e., methyl esters) by 

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

62Commonly used base catalysts include sodium 

hydroxide (NaOH), potassium hydroxide (KOH) and 

sodium methoxide (NaOCH3). 

63 Van Gerpen, J., Shanks, B., Pruszko, R., 

Clements, D., Knothe, G., ‘‘Biodiesel Production 

Technology,’’ NREL/SR–510–36244, July 2004. 

64 Van Gerpen, J., ‘‘Used and Waste Oil and 

Grease for Biodiesel,’’ NC State University A&T 

State University Cooperative Extension, http://

www.extension.org/pages/Used_and_Waste_Oil_

and_Grease_for_Biodiesel. 

reacting triglycerides with methanol 

typically under the presence of a base 

catalyst, see the simplified form in 

Equation 1.62

TABLE 14—EXCERPTS OF EXISTING FUEL PATHWAYS FROM § 40 CFR 80.1426 

Fuel type Feedstock Production process requirements D-Code 

Biodiesel, and renewable diesel ....... Soy bean oil; Oil from annual 

covercrops; Algal oil; Biogenic 

waste oils/fats/greases; Non-food 

grade corn oil.

One of the following: TransEsterification Hydrotreating Excluding processes that co-process 

renewable biomass and petroleum.

4 (Biomass-Based Diesel). 

Biodiesel, and renewable diesel ....... Soy bean oil; Oil from annual 

covercrops; Algal oil; Biogenic 

waste oils/fats/greases; Non-food 

grade corn oil.

One of the following: TransEsterification Hydrotreating Includes only processes that coprocess renewable biomass and 

petroleum.

5 (Advanced Biofuel). 

While triglycerides are usually the 

main component of oils, fats, and grease 

feedstocks, there are other components 

such as free fatty acids (FFAs) that are 

typically removed prior to 

transesterification. Removal or 

conversion of FFAs is important if the 

traditional base-catalyzed 

transesterification production process is 

used since FFAs will react with base 

catalysts to produce soaps that inhibit 

the transesterification reaction. Table 15 

below gives the usual ranges for FFAs 

found in biodiesel feedstocks. 

TABLE 15—RANGES OF FFA IN

BIODIESEL FEEDSTOCKS 63 64

Biodiesel feedstock Percentage 

FFA 

Refined vegetable oils .............. <0.05 

Crude vegetable oils ................. 0.3–0.7 

Restaurant waste grease ......... 2–7 

Yellow grease ........................... <15 

Animal fat .................................. 5–30 

Brown grease ........................... >15 

Trap grease .............................. 40–100 

One of the most widely used methods 

for treating biodiesel feedstocks with 

higher FFA content is acid catalysis. 

Acid catalysis typically uses a strong 

acid such as sulfuric acid to catalyze the 

esterification of the FFAs and the 

transesterification of the triglycerides. 

The simplified form of the esterification 

process is given below in Equation 2. 

Acid esterification can be applied to 

feedstocks with FFA contents above 5%. 

Because the transesterification of 

triglycerides is slow under acid 

catalysis, a technique commonly used to 

overcome the reaction rate issue is to 

first convert the FFAs through an acid 

esterification (also known as an acid 

‘‘pretreatment’’ step), and then followup with the traditional base-catalyzed 

transesterification of triglycerides. See 

Figure 2 for a general flow diagram of 

the acid esterification and subsequent 

transesterification biodiesel process. 


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65National Biodiesel Board, Comprehensive 

Survey on Energy Use for Biodiesel Production 

(2008) http://www.biodiesel.org/news/RFS/

rfs2docs/NBB%20Energy%20Use%20Survey%20

FINAL.pdf. 

66The material inputs include methanol, sodium 

methylate, sodium hydroxide, potassium 

hydroxide, hydrochloric acid, sulfuric acid, 

phosphoric acid, and citric acid. The majority of 

material input is from methanol. 

Under the RFS2 final rule, biodiesel 

from biogenic waste oils/fats/greases 

qualifies for D-Codes 4 and 5 using a 

‘‘transesterification’’ process. This 

conclusion was based on the analysis of 

yellow grease as a feedstock in a process 

where there was an acid ‘‘pretreatment’’ 

or ‘‘esterification’’ process to treat the 

FFAs contained in the feedstock. In fact, 

one of the material inputs assumed in 

the modeling for the final RFS2 rule 

yellow grease pathway is sulfuric acid, 

which is the catalyst commonly used for 

acid esterification. However, we had not 

stipulated ‘‘esterification’’ as a qualified 

production process in Table 1 to § 40 

CFR 80.1426. We believe this ambiguity 

could unnecessarily cause confusion as 

to whether esterification can also be 

used for the production of biodiesel 

under the currently approved pathways. 

Since the biodiesel modeling 

completed for the final RFS2 rule 

actually includes esterification 

upstream of the transesterification 

process, we find it appropriate to clarify 

Table 1 to § 40 CFR 80.1426 to include 

‘‘esterification’’ as a qualified process in 

which to produce biodiesel. As the 

modeling for yellow grease met an 86% 

GHG reduction emissions level, and 

yellow grease is typically <15% FFA 

content, it is reasonable to conclude that 

esterification and subsequent 

transesterification with a yellow grease 

feedstock containing FFAs at the very 

least up to 15% can meet the GHG 

reduction threshold for biomass-based 

diesel and advanced biofuel of 50%. 

As noted in Table 15, however, there 

are feedstocks that may contain even 

higher levels of FFAs. As described 

below, EPA has evaluated the use of 

these higher FFA feedstocks to make 

biodiesel and has determined that use of 

such feedstocks also results in a 

biodiesel with lifecycle GHG emissions 

at least 50% less than that of 

conventional fuel. 

The National Biodiesel Board (NBB) 

has conducted a comprehensive survey 

of the actual energy used by commercial 

biodiesel production plants in the U.S.65

The survey depicts the amount of 

energy and incidental process materials 

such as acids used to produce a gallon 

of biodiesel. The survey data returned 

represents 37% of the surveyed 230 

NBB biodiesel members in 2008 and 

includes producers using a variety of 

virgin oils and recycled or reclaimed 

fats and oils. While there is no specific 

data on the FFA content of the 

feedstocks used, the feedstocks did 

include reclaimed greases which 

represent the feedstocks which typically 

have the highest FFA content. As the 

data is partially aggregated, we used the 

maximum surveyed electricity and 

natural gas used at the facilities and a 

high estimate of ‘‘materials used’’ based 

on a sum of industry averages for all 

process materials for calculating 

potential GHG emissions. Even though 

some of the facilities might be 

processing feedstocks with relatively 

low FFA content, we believe that using 

these maximum observed inputs for 

energy used plus a high estimate for 

process materials used will estimate the 

highest GHG emissions profile for 

biodiesel production GHG emissions. 

When combined with the feedstock 

GHG emissions impact (see discussion 

below), the results still predict a GHG 

emissions reduction comfortably 

exceeding 50% as compared to the 

petroleum fuel it displaces. Therefore, 

there is little risk in predicting that any 

facility that utilizes esterification and 

feedstock over the range of likely FFA 

content can meet the 50% biomassbased diesel and advanced biofuel 

threshold. 

According to the survey, the 

maximum electricity use for a producer 

reached as high as 3,071 Btu per gallon 

biodiesel. This is about 5 times higher 

than the industry average. The 

maximum natural gas usage for a 

producer reached as high as 12,324 Btu 

per gallon biodiesel, which is about 3.5 

times higher than the industry average. 

For ‘‘materials used’’ only an industry 

average for each material was provided 

in the survey. Therefore, as a 

conservative estimate, we totaled all the 

average material inputs to equal 0.51 kg/ 

gal biodiesel.66 We believe that this is 

conservative because not all facilities 

are likely to use each and every one of 

the process materials listed in the 

survey (e.g., we totaled all the acids 


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

used even though a facility is not likely 

to use each different acid). Thus, our 

estimate of materials used will estimate 

a level of maximum usage of materials 

at a given facility. In addition, we did 

not include a glycerin co-product credit 

when calculating emissions since the 

esterification reaction does not produce 

glycerin (see Equation 2). Using the 

same methodology as was used for the 

yellow grease modeling under RFS2, but 

using the high energy and materials use 

assumptions per the above discussion 

and omitting the glycerin co-product 

credit, we estimate the emissions from 

biodiesel processing at 23,708 gCO2eq 

per mmBtu of biodiesel. The estimated 

GHG emissions reduction for the entire 

process is ¥71%. Since the GHG 

threshold is at ¥50% for biomass-based 

diesel and advanced biofuel, we believe 

that there is a large enough margin in 

the results to reasonably conclude that 

biodiesel using esterification of 

specified feedstocks with any level of 

FFA content meets the biomass-based 

diesel and advanced biofuel 50% 

lifecycle GHG reduction threshold. 

Therefore, we are including the process 

‘‘esterification’’ as an approved 

biodiesel production process in Table 1 

to § 40 CFR 80.1426. In addition, 

consistent with the modeling conducted 

for RFS2, we interpret the RFS 

regulations as they existed prior to 

today’s rule as including a direct 

esterification process as part of the 

biodiesel pathways for which only 

‘‘trans-esterification’’ was specifically 

referenced in Table 1 to § 40 CFR 

80.1426. 

V. Additional Changes to Listing of 

Available Pathways in Table 1 of 

80.1426 

We are also finalizing two changes to 

Table 1 to 80.1426 that were proposed 

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

change adds ID letters to pathways to 

facilitate references to specific 

pathways. The second change adds 

‘‘rapeseed’’ to the existing pathway for 

renewable fuel made from canola oil. 

On September 28, 2010, EPA 

published a ‘‘Supplemental 

Determination for Renewable Fuels 

Produced Under the Final RFS2 

Program from Canola Oil’’ (FR Vol. 75, 

No. 187, pg 59622–59634). In the July 1, 

2011 NPRM (76 FR 38844) we proposed 

to clarify two aspects of the 

supplemental determination. First we 

proposed to amend the regulatory 

language in Table 1 to § 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 thus are finalizing 

it as proposed. This change will 

enhance the clarity of the regulations 

regarding the feedstocks that qualify 

under the approved canola biodiesel 

pathway. 

Second, we wish to clarify that 

although the GHG emissions of 

producing fuels from canola feedstock 

grown in the U.S. and Canada was 

specifically modeled as the most likely 

source of canola (or rapeseed) oil used 

for biodiesel produced for sale and use 

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

approved pathway cover canola/ 

rapeseed oil from other countries, and 

we interpret our regulations in that 

manner. We expect the vast majority of 

biodiesel used in the U.S. and produced 

from canola/rapeseed oil will come from 

U.S. and Canadian crops. Incidental 

amounts from crops produced in other 

nations will not impact our average 

GHG emissions for two reasons. First, 

our analyses considered world-wide 

impacts and thus considered canola/ 

rapeseed crop production in other 

countries. Second, other countries most 

likely to be exporting canola/rapeseed 

or biodiesel product from canola/ 

rapeseed are likely to be major 

producers which typically use similar 

cultivars and farming techniques. 

Therefore, GHG emissions from 

producing biodiesel with canola/ 

rapeseed grown in other countries 

should be very similar to the GHG 

emissions we modeled for Canadian and 

U.S. canola, though they could be 

slightly (and insignificantly) higher or 

lower. At any rate, even if there were 

unexpected larger differences, EPA 

believes the small amounts of feedstock 

or fuel potentially coming from other 

countries will not impact our threshold 

analysis. Therefore, EPA interprets the 

approved canola pathway as covering 

canola/rapeseed regardless of country 

origin. 

VI. Statutory and Executive Order 

Reviews 

A. Executive Order 12866: Regulatory 

Planning and Review 

This action is not a ‘‘significant 

regulatory action’’ under the terms of 

Executive Order 12866 (58 FR 51735, 

October 4, 1993) and is therefore not 

subject to review under Executive 

Orders 12866 and 13563 (76 FR 3821, 

January 21, 2011). 

B. Paperwork Reduction Act 

This action does not impose any new 

information collection burden. The 

corrections, clarifications, and 

modifications to the final RFS2 

regulations contained in this rule are 

within the scope of the information 

collection requirements submitted to the 

Office of Management and Budget 

(OMB) for the final RFS2 regulations. 

OMB has approved the information 

collection requirements contained in the 

existing regulations at 40 CFR part 80, 

subpart M under the provisions of the 

Paperwork Reduction Act, 44 U.S.C. 

3501 et seq. and has assigned OMB 

control numbers 2060– 0637 and 2060– 

0640. The OMB control numbers for 

EPA’s regulations in 40 CFR are listed 

in 40 CFR part 9. 

C. Regulatory Flexibility Act 

The Regulatory Flexibility Act (RFA) 

generally requires an agency to prepare 

a regulatory flexibility analysis of any 

rule subject to notice and comment 

rulemaking requirements under the 

Administrative Procedure Act or any 

other statute unless the agency certifies 

that the rule will not have a significant 

economic impact on a substantial 

number of small entities. Small entities 

include small businesses, small 

organizations, and small governmental 

jurisdictions. 

For purposes of assessing the impacts 

of today’s rule on small entities, small 

entity is defined as: (1) A small business 

as defined by the Small Business 

Administration’s (SBA) regulations at 13 

CFR 121.201; (2) a small governmental 

jurisdiction that is a government of a 

city, county, town, school district or 

special district with a population of less 

than 50,000; and (3) a small 

organization that is any not-for-profit 

enterprise which is independently 

owned and operated and is not 

dominant in its field. 

After considering the economic 

impacts of this action on small entities, 

I certify that this rule will not have a 

significant economic impact on a 

substantial number of small entities. 

This rule will not impose any new 

requirements on small entities. The 

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Federal Register / Vol. 77, No. 3 / Thursday, January 5, 2012 / Rules and Regulations 725 

relatively minor corrections and 

modifications this rule makes to the 

final RFS2 regulations do not impact 

small entities. 

D. Unfunded Mandates Reform Act 

This rule does not contain a Federal 

mandate that may result in expenditures 

of $100 million or more for State, local, 

and tribal governments, in the aggregate, 

or the private sector in any one year. We 

have determined that this action will 

not result in expenditures of $100 

million or more for the above parties 

and thus, this rule is not subject to the 

requirements of sections 202 or 205 of 

UMRA. 

This rule is also not subject to the 

requirements of section 203 of UMRA 

because it contains no regulatory 

requirements that might significantly or 

uniquely affect small governments. It 

only applies to gasoline, diesel, and 

renewable fuel producers, importers, 

distributors and marketers and makes 

relatively minor corrections and 

modifications to the RFS2 regulations. 

E. Executive Order 13132 (Federalism) 

This action does not have federalism 

implications. It will not have substantial 

direct effects on the States, on the 

relationship between the national 

government and the States, or on the 

distribution of power and 

responsibilities among the various 

levels of government, as specified in 

Executive Order 13132. This action only 

applies to gasoline, diesel, and 

renewable fuel producers, importers, 

distributors and marketers and makes 

relatively minor corrections and 

modifications to the RFS2 regulations. 

Thus, Executive Order 13132 does not 

apply to this action. 

F. Executive Order 13175 (Consultation 

and Coordination With Indian Tribal 

Governments) 

This rule does not have tribal 

implications, as specified in Executive 

Order 13175 (65 FR 67249, November 9, 

2000). It applies to gasoline, diesel, and 

renewable fuel producers, importers, 

distributors and marketers. This action 

makes relatively minor corrections and 

modifications to the RFS regulations, 

and does not impose any enforceable 

duties on communities of Indian tribal 

governments. Thus, Executive Order 

13175 does not apply to this action. 

G. Executive Order 13045: Protection of 

Children From Environmental Health 

Risks and Safety Risks 

EPA interprets EO 13045 (62 FR 

19885, April 23, 1997) as applying only 

to those regulatory actions that concern 

health or safety risks, such that the 

analysis required under section 5–501 of 

the EO has the potential to influence the 

regulation. This action is not subject to 

EO 13045 because it does not establish 

an environmental standard intended to 

mitigate health or safety risks. 

H. Executive Order 13211: Actions 

Concerning Regulations That 

Significantly Affect Energy Supply, 

Distribution, or Use 

This rule is not subject to Executive 

Order 13211 (66 FR 18355 (May 22, 

2001)), because it is not a significant 

regulatory action under Executive Order 

12866. 

I. National Technology Transfer and 

Advancement Act 

Section 12(d) of the National 

Technology Transfer and Advancement 

Act of 1995 (‘‘NTTAA’’), Public Law 

104–113, 12(d) (15 U.S.C. 272 note) 

directs EPA to use voluntary consensus 

standards in its regulatory activities 

unless to do so would be inconsistent 

with applicable law or otherwise 

impractical. Voluntary consensus 

standards are technical standards (e.g., 

materials specifications, test methods, 

sampling procedures, and business 

practices) that are developed or adopted 

by voluntary consensus standards 

bodies. NTTAA directs EPA to provide 

Congress, through OMB, explanations 

when the Agency decides not to use 

available and applicable voluntary 

consensus standards. 

This action does not involve technical 

standards. Therefore, EPA did not 

consider the use of any voluntary 

consensus standards. 

J. Executive Order 12898: Federal 

Actions To Address Environmental 

Justice in Minority Populations and 

Low-Income Populations 

Executive Order (EO) 12898 (59 FR 

7629 (Feb. 16, 1994)) establishes Federal 

executive policy on environmental 

justice. Its main provision directs 

Federal agencies, to the greatest extent 

practicable and permitted by law, to 

make environmental justice part of their 

mission by identifying and addressing, 

as appropriate, disproportionately high 

and adverse human health or 

environmental effects of their programs, 

policies, and activities on minority 

populations and low-income 

populations in the United States. 

EPA has determined that this rule will 

not have disproportionately high and 

adverse human health or environmental 

effects on minority or low-income 

populations because it does not affect 

the level of protection provided to 

human health or the environment. 

These amendments would not relax the 

control measures on sources regulated 

by the RFS regulations and therefore 

would not cause emissions increases 

from these sources. 

K. Congressional Review Act 

The Congressional Review Act, 5 

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

Business Regulatory Enforcement 

Fairness Act of 1996, generally provides 

that before a rule may take effect, the 

agency promulgating the rule must 

submit a rule report, which includes a 

copy of the rule, to each House of the 

Congress and to the Comptroller General 

of the United States. A major rule 

cannot take effect until 60 days after it 

is published in the Federal Register. 

EPA will submit a report containing this 

rule and other required information to 

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

Representatives, and the Comptroller 

General of the United States prior to 

publication of the rule in the Federal 

Register. This action is not a ‘‘major 

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

VII. Statutory Provisions and Legal 

Authority 

Statutory authority for the rule 

finalized today can be found in section 

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

7545. Additional support for the 

procedural and compliance related 

aspects of today’s rule, including the 

recordkeeping requirements, come from 

Sections 114, 208, and 301(a) of the 

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

7601(a). 

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

List of Subjects in 40 CFR Part 80 

Environmental protection, 

Administrative practice and procedure, 

Agriculture, Air pollution control, 

Confidential business information, 

Diesel Fuel, Energy, Forest and forest 

products, Fuel additives, Gasoline, 

Imports, Labeling, Motor vehicle 

pollution, Penalties, Petroleum, 

Reporting and recordkeeping 

requirements. 

Dated: November 30, 2011. 

Lisa P. Jackson, 

Administrator. 

For the reasons set forth in the 

preamble, 40 CFR part 80 is amended as 

follows: 

PART 80—REGULATION OF FUELS 

AND FUEL ADDITIVES 

■ 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 

addition of the following definitions of 

‘‘Renewable Gasoline’’ and ‘‘Renewable 

Gasoline Blendstock’’ in alphabetical 

order to read as follows: 

§ 80.1401 Definitions. 

* * * * * 

Renewable gasoline means renewable 

fuel made from renewable biomass that 

is composed of only hydrocarbons and 

which meets the definition of gasoline 

in § 80.2(c). 

Renewable gasoline blendstock means 

a blendstock made from renewable 

biomass that is composed of only 

hydrocarbons and which meets the 

definition of gasoline blendstock in 

§ 80.2(s). 

* * * * * 

■ 3. Section 80.1426 is amended by 

revising Table 1 in 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 oil.

One of the following: Trans-Esterification, 

Esterification Hydrotreating Excluding processes 

that co-process renewable biomass and petroleum.

4 

G Biodiesel, heating oil .. Canola/Rapeseed oil ................................................ Trans-Esterification using natural gas or biomass 

for process energy.

4 

H Biodiesel, renewable 

diesel, jet fuel and heating oil.

Soy bean oil; Oil from annual covercrops; Algal oil; 

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

corn oil Camelina oil.

One of the following: Trans-Esterification, 

Esterification Hydrotreating Includes only processes that co-process renewable biomass and 

petroleum.

5 

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

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

K Ethanol ....................... Cellulosic Biomass from crop residue, slash, precommercial thinnings and tree residue, annual 

covercrops, switchgrass, miscanthus, 

napiergrass, giant reed, and energy cane; cellulosic components of separated yard waste; cellulosic components of separated food waste; and 

cellulosic components of separated MSW.

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

L Cellulosic Diesel, jet 

fuel and heating oil.

Cellulosic Biomass from crop residue, slash, precommercial thinnings and tree residue, annual 

covercrops, switchgrass, miscanthus, 

napiergrass, giant reed and energy cane; cellulosic components of separated yard waste; cellulosic components of separated food waste; and 

cellulosic components of separated MSW.

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

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Federal Register / Vol. 77, No. 3 / Thursday, January 5, 2012 / Rules and Regulations 727 

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 

M Renewable Gasoline 

and Renewable Gasoline Blendstock.

Cellulosic Biomass from crop residue, slash, precommercial 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, Gasification and Upgrading, Direct Fermentation, Fermentation and Upgrading, 

all utilizing natural gas, biogas, and/or biomass 

as the only process energy sources. Any process utilizing biogas and/or biomass as the only 

process energy sources.

3 

N Butanol ....................... Corn starch .............................................................. Fermentation; dry mill using natural gas, biomass, 

or biogas for process energy.

6 

O Ethanol, renewable 

diesel, jet fuel, heating 

oil, and naphtha.

The non-cellulosic portions of separated food 

waste.

Any ........................................................................... 5 

P Biogas ......................... Landfills, sewage waste treatment plants, manure 

digesters.

Any ........................................................................... 5 

* * * * * 

[FR Doc. 2011–31580 Filed 1–4–12; 8:45 am] 

BILLING CODE 6560–50–P 

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